**UNITED STATES**

**SECURITIES AND EXCHANGECOMMISSION**

**Washington,D.C. 20549**

 

**FORM 10-K**

 

**ANNUAL REPORT PURSUANT TO SECTION13 or 15(d) of**

**THE SECURITIES EXCHANGE ACT OF1934**

 

**Forthe year ended December 31, 2006**

 

**CommissionFile Number 1-6702**

 

**NEXEN INC.**

**Incorporatedunder 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**

**Website - 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) ofthe Act: **None**.

 

Indicateby check mark if the registrant is a well-known seasoned issuer, as defined inRule 405 of the Securities Act.

 

Yes x No o

 

Indicateby check mark if the registrant is not required to file reports pursuant to Section13 or Section 15(d) of the Exchange Act.

 

Yes o No x

 

Indicateby check mark whether the registrant (1) has filed all reports required to befiled by Section 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months, and (2) has been subject to such filing requirements forthe past 90 days.

 

Yes x No o

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the bestof registrant’s knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-K or any amendment tothis Form 10-K. x

 

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filer, or a non-accelerated filer.

 

Large accelerated filer x Accelerated filer o Non-accelerated filer o

 

Indicateby check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Exchange Act).

 

Yes o No x

 

On June 30, 2006, theaggregate market value of the voting shares held by non-affiliates of theregistrant was approximately Cdn $16.5 billion based on the Toronto StockExchange closing price on that date. On January 31, 2007, there were262,830,108 common shares issued and outstanding.

 

 

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**TABLE OF CONTENTS**

 
| **PART I**       | ** **                                                                                                             | ** ** |
|------------------|------------------------------------------------------------------------------------------------------------------------|------------|
| Items 1 and 2.   | Business and Properties                                                                                                |       |
| Item 1A.         | Risk Factors                                                                                                           |       |
| Item 1B.         | Unresolved Staff Comments                                                                                              |       |
| Item 3.          | Legal Proceedings                                                                                                      |       |
| Item 4.          | Submission of Matters to a Vote of Security  Holders                                                                   |       |
| **PART II**      | ** **                                                                                                             | ** ** |
| Item 5.          | Market for the Registrant’s Common Equity,  Related Stockholder Matters and Issuer Purchases of Equity Securities |       |
| Item 6.          | Selected Financial Data                                                                                                |       |
| Item 7.          | Management’s Discussion and Analysis of  Financial Condition and Results of Operations                            |       |
| Item 7A.         | Quantitative and Qualitative Disclosures  About Market Risk                                                            |       |
| Item 8.          | Financial Statements and Supplementary Data                                                                            |       |
| Item 9.          | Changes in and Disagreements with  Accountants on Accounting and Financial Disclosure                                  |       |
| Item 9A.         | Controls and Procedures                                                                                                |       |
| **PART III**     | ** **                                                                                                             | ** ** |
| Items 10 and 11. | Directors, Executive Officers and Corporate  Governance, and Executive Compensation                                    |       |
| Item 12.         | Security Ownership of Certain Beneficial  Owners and Management and Related Stockholder Matters                        |       |
| Item 13.         | Certain Relationships and Related  Transactions, and Director Independence                                             |       |
| Item 14.         | Principal Accounting Fees and Services                                                                                 |       |
| **PART IV**      | ** **                                                                                                             | ** ** |
| Item 15.         | Exhibits,  Financial Statement Schedules                                                                               |       |

 

Special Note to Canadian Investors — see page 81

Unless we indicate otherwise, all dollar amounts($) are in Canadian dollars, and oil and gas volumes, reserves and relatedperformance measures are presented on a working interest before-royaltiesbasis. Where appropriate, information on an after-royalties basis is providedin tabular format. Volumes and reserves include Syncrude operations unlessotherwise stated.

 

Below is a list of terms specific to theoil 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 incommon units called barrel of oil equivalent (boe). A boe is derived byconverting six thousand cubic feet of gas to one barrel of oil (6mcf/1bbl).This conversion may be misleading, particularly if used in isolation, as the6mcf/1bbl ratio is based on an energy equivalency at the burner tip and doesnot represent the value equivalency at the well head.

 

The noon-day Canadian toUS dollar exchange rates for Cdn $1.00, as reported by the Bank of Canada,were:

 
| **(US$)** | ** ** | **December  31** | ** ** | **Average** | ** ** | **High** | ** ** | **Low** | ** ** |
|-----------|------------|------------------|------------|-------------|------------|----------|------------|---------|------------|
| 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  |       |
| 2006      |       | 0.8581           |       | 0.8818      |       | 0.9099   |       | 0.8528  |       |

 

On January 31, 2007, the noon-day exchangerate was US $0.8480 for Cdn $1.00.

 

Electronic copies of our filings with the Securities Exchange Commission(SEC) and the Ontario Securities Commission (OSC) (from November 8, 2002onward) are available, free of charge, on our website (www.nexeninc.com). Filingsprior to November 8, 2002 are available free of charge, on request, bycontacting our investor relations department at (403) 699-5931. As soon asreasonably practicable, our filings are made available on our website once theyare electronically filed with the SEC and/or the OSC. Alternatively, the SECand the OSC each maintain a website (www.sec.gov and www.sedar.com) thatcontains our reports, proxy and information statements and other publishedinformation that have been filed or furnished with the SEC and the OSC.

 

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Operations

 

We have developed specific capabilities inoil sands, coalbed methane, deep-water technology and international locations. This provides us with world-class capacity for future growth.

 

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**PART I**

 

**ITEMS 1 AND 2. BUSINESS AND PROPERTIES**

 
| **About Us**                                     |   |   |
|--------------------------------------------------|--------|--------|
| **Strategy**                                     |   |   |
| **Understanding the Oil and Gas Business**       |   |   |
| **Oil and  Gas Operations**                      |   |   |
| North  Sea—United Kingdom                   |   |   |
| Gulf of  Mexico—United States               |   |   |
| Canada                                           |   |   |
| Middle  East—Yemen                          |   |   |
| Offshore  West Africa                            |   |   |
| Other  International                             |   |   |
| **Reserves, Production and Related Information** |   |   |
| **Syncrude  Mining Operations**                  |   |   |
| **Energy Marketing**                             |   |   |
| **Chemicals**                                    |   |   |
| **Government  Regulations**                      |   |   |
| **Environmental  Regulations**                   |   |   |
| **Employees**                                    |   |   |

 

----

 
| Business and Properties | About Us |
|-------------------------|----------|

 

**About Us**

 

Nexen Inc. (Nexen, we orour) is an independent, Canadian-based, global energy company. We were formedin Canada in 1971 by the combination of the Canadian crude oil, natural gas,sulphur and chemical operations of two subsidiaries of Occidental PetroleumCorporation (Occidental). We’ve grown from producing 10,700 boe/d beforeroyalties with revenues of $26 million in 1971, to 211,700 boe/d beforeroyalties (including Syncrude production) and revenues of $3.9 billion in 2006.We achieved this growth through exploration success and strategic acquisitions.In more than 30 years of operations, we have been profitable every year, exceptone, and have been paying quarterly dividends consecutively since 1975.

 

In the 1970s, weexpanded our western Canadian assets and entered the US Gulf of Mexico. Wefinished this decade with production of approximately 11,000 boe/d beforeroyalties and revenues of $126 million.

 

In the 1980s, wecontinued to expand in western Canada by acquiring Canada-Cities Service, Ltd.in 1983. This acquisition doubled our size and included an interest in theSyncrude Joint Venture, our entry into the Athabasca oil sands. Acquisitions ofCities Offshore Production Co. in 1984 and Moore McCormack Energy, Inc. in 1988established our presence in the Gulf of Mexico. We finished this decade withproduction of approximately 68,600 boe/d before royalties and revenues of $591million.

 

In the 1990s, we had twodefining events: discovering oil on the Masila block in Yemen and acquiringWascana Energy Inc. The first of 17 fields at Masila was discovered in 1991,and Masila has produced more than 940 million barrels since start up in 1993.Our 1997 purchase of Wascana Energy Inc. almost tripled our Canadian production.In 1998, we entered Australia with an interest in the offshore Buffalo fieldand Nigeria as the operator of the Ejulebe field. Also in 1998, we discoveredUkot on Block OPL-222, offshore Nigeria, the first of several discoveries todate on the block. We finished this decade with production of approximately239,200 boe/d before royalties and revenues of $1.7 billion.

 

So far in the 21stcentury, we have made a number of discoveries, two strategic acquisitions andcompleted a non-core divestiture program. In 2000, we discovered Gunnison inthe deep-water Gulf of Mexico and Guando in Colombia. We joined with OntarioTeachers’ Pension Plan Board (Teachers) to acquire Occidental’s remaining 29%interest in us. Teachers purchased 20.2 million common shares. We repurchasedthe remaining 20 million common shares for $605 million, which would have had avalue of more than $2.6 billion at year-end 2006. We also exchanged our oil andgas operations in Ecuador for Occidental’s 15% interest in our chemical operationsand 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 ajoint venture agreement with OPTI Canada Inc. to develop, produce and upgradebitumen 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 discoveredtwo fields on Block 51 in Yemen. In 2004, we acquired properties in the UKNorth Sea, providing us with operatorship of the Buzzard discovery, theproducing Scott and Telford fields and 700,000 exploration acres.

 

**We’ve grown from producing 10,700boe/d in 1971 to 211,700 boe/d in 2006. In 2007, we expect our net productionto grow by 50%.**

 

In 2005, we soldCanadian conventional oil and gas properties producing approximately 18,300boe/d before royalties and monetized 39% of our chemical business through theinitial public offering of the Canexus Income Fund. We also made a potentiallysignificant discovery in the Gulf of Mexico at Knotty Head and commencedcommercial development of our first coalbed methane (CBM) project in the FortAssiniboine area in western Canada. In 2006, we completed our major developmentproject at Buzzard on budget and made significant construction progress at ourLong Lake project in the Athabasca oil sands. In early January 2007, Buzzardproduced first oil. With Buzzard on stream, followed by Long Lake later in theyear, we expect our production after royalties in 2007 to grow by more than50%, net of declines. Our portfolio of assets, combined with our talentedpeople and an active exploration program, are expected to provide future growthfor our company.

 

For financial reportingpurposes, we report on four main segments:

 

•      oil and gas;

•      Syncrcrude;

•      energy marketing; and

•      chemicals

 

Our oil and gasoperations are broken down geographically into the UK North Sea, US Gulf ofMexico, Canada,

 

3

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| Items 1 and 2 |   | Business and Properties |   | Strategy |
|---------------|--------|-------------------------|--------|----------|

 

Yemen and Other International(currently Colombia and offshore West Africa). Results from our Long Lakeproject are included in Canada. Syncrude is our 7.23% interest in the SyncrudeJoint Venture. Energy marketing includes our growing crude oil, natural gas,natural gas liquids, ethanol and power marketing business in North America,Europe and southeast Asia. Chemicals includes operations in North America andBrazil that manufacture, market and distribute sodium chlorate, caustic sodaand chlorine through the Canexus Limited Partnership.

 

Production, revenues,net income, capital expenditures and identifiable assets for these segmentsappear in Note 20 to the Consolidated Financial Statements and in Management’sDiscussion and Analysis of Financial Condition and Results of Operations(MD&A) in this report.

 

**Strategy**

 

Our goal is to growlong-term value for our shareholders. We define value growth as increasingreserves, production, cash flow and net income over the long term. We believein developing our competitive advantage, which generates opportunities forlong-term success in our ever-evolving industry. As conventional basins inNorth America mature, we have developed specific capabilities in oil sands,coalbed methane (CBM), deep-water technology and international locations. Theseenable us to focus on specific types of projects, as we transition toward majorprojects in established basins, exploration in less mature basins andexploitation of unconventional resources.

 

Today, we are buildingnew sustainable businesses in western Canada, the North Sea, Gulf of Mexico,and offshore West Africa, capitalizing on the following corporate strengths:

 

•                  We are successfuldeep-water explorers with significant discoveries at Knotty Head in the Gulf ofMexico and at Usan, offshore Nigeria;

 

•                  We are skilled projectmanagers with major development projects at Buzzard in the North Sea, and LongLake in Canada’s Athabasca oil sands. In 2006, Buzzard was completed on budgetand just days after the original projected start up date. At Long Lake,construction is progressing well and we expect the SAGD production operationsto be on stream by the end of the first quarter in 2007, followed by the startup of the upgrader late in the year;

 

•                  We are innovative in ourapplication of technology. Long Lake is expected to be the first oil sandsproject to use gasification technology to significantly reduce the cost ofproducing bitumen;

 

•                  We are an internationaloperator with a proven track record of successful business ventures in Yemen,the United Kingdom, Nigeria, Colombia and Australia; and

 

•      From time to time, we supplement ourgrowth with acquisitions, such as our strategic entry into the UK North Sea in2004.

 

The location and scaleof our operations often result in an extended period of time from the captureof opportunities to first production and non-linear year-over-year growth inreserves and production. Significant up-front capital investment is oftenrequired prior to realizing production and free cash flows. We fund thisinvestment by maximizing cash flow from our producing assets, issuing long-termdebt and selling non-core assets into attractive markets.

 

**We are building sustainable businesses with major projects inestablished basins, exploitation of unconventional resources and exploration.**

 

Our long-term strategyfocuses on building capacity by ensuring we have a sufficient inventory ofopportunities for future growth. With Buzzard on stream, followed by Long Lakelater this year, we expect to deliver significant production growth. In fact,in 2007 we expect our production after royalties to grow by more than 50%, netof declines. However, the growth does not stop there. Beyond 2007, we have anumber of opportunities that are expected to provide production growth andcreate shareholder value well into the next decade. These opportunities includeundeveloped discoveries at Knotty Head in the Gulf of Mexico, Usan and Ukotoffshore Nigeria, various discoveries in the UK North Sea, together withdevelopment of our CBM and additional oil sands leases in Canada.

 

In creating sustainablebusinesses, we are committed to good corporate governance and socialresponsibility. We believe that over the long term, companies that followsustainable business practices outperform those with narrower priorities. Wefoster dialogue with stakeholders about our operational opportunities andchallenges, from exploration to production to reclamation. Our goal is to helpstakeholders become engaged participants in a continuing consultation process,while balancing their multiple, and sometimes conflicting goals.

 

**Understanding The OiL and GASBUSINESS**

 

The oil and gas industryis highly competitive. With strong global demand for energy, there is intensecompetition to find and develop new sources of supply. Yet, barrels fromdifferent reservoirs around the world do not have equal value. Their valuedepends on the costs to find, develop and produce

 

4

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| Business and Properties |   | Oil & Gas Operations |
|-------------------------|--------|--------------------------|

 

the oil or gas, the fiscal terms of the hostregime and the price products command in the market based on quality andmarketing efforts. Our goal is to extract the maximum value from each barrel ofoil equivalent, so every dollar of capital we invest generates an attractivereturn.

 

Numerous factors can affect this. Changesin crude oil and natural gas prices can significantly affect our net income andcash generated from operating activities. Consequently, these prices may alsoaffect the carrying value of our oil and gas properties and how much we investin oil and gas exploration and development. We attempt to reduce these impactsby investing in projects we believe will generate positive returns atrelatively low commodity prices.

 

Realized prices for our oil and gasproducts are mainly determined by volatile global crude oil and natural gasmarkets. With many alternative customers, the loss of any one customer is notexpected to have a significant adverse effect on the price of our products orrevenues. Oil and gas producing operations are generally not seasonal. However,demand for some of our products can have a seasonal component that can impactprice. In particular, heavy oil is generally in higher demand in the summer forits use in road construction, and natural gas is generally in higher demand inthe winter for heating. We manage our operations on a country-by-country basis,reflecting differences in the regulatory and competitive environments and riskfactors associated with each country.

 

**OIL ANd GAS OPERATIONS**

 

Wehave oil and gas operations in the UK North Sea, US Gulf of Mexico, westernCanada, Yemen, offshore West Africa and Colombia. We also have operations inCanada’s Athabasca oil sands which produce synthetic crude oil. We operate mostof our production and continue to develop new growth opportunities in each areaby actively exploring and applying technology.

 

 

In this Form 10-K, we provide estimates ofremaining quantities of oil and gas reserves for our various properties. Such estimatesare internally prepared. We had 98% of our reserves assessed by independentreserves consultants. Their assessments are performed at varying levels ofproperty aggregation and we work with them to reconcile the differences on theportfolio of properties to within 10% in the aggregate. Estimates pertaining toindividual properties within the portfolio often differ by significantly morethan 10%, either positively or negatively. Refer to the section on Oil and GasAccounting – Reserves Determination on page 71 for a description of ourreserves process.

 

**North Sea—United Kingdom (UK)**

 

The UK is one of our key growth areas. In2004, we acquired a 43.2% operated interest in the Buzzard development, a 41%operated interest in the Scott field, a 54.3% operated interest in the Telfordfield, the Scott production platform, interests in several satellitediscoveries and more than 700,000 net undeveloped exploration acres for US$2.1billion. This acquisition established us as a significant regional player with concentratedassets, infrastructure and exploration and development potential for futuregrowth. It added high-margin reserves andproduction, diversified our worldwide portfolio by adding strong assets in astable jurisdiction, and complemented our other longer cycle-time projects.

 

 

5

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| Items 1 and 2 |   | Business  and Properties |   | North  Sea |
|---------------|--------|--------------------------|--------|------------|

 

Our UK strategy is focused on exploration and exploitationopportunities near existing infrastructure. We have a number of exploitationopportunities in our existing fields and smaller satellite undevelopeddiscoveries near infrastructure. Most of our unexplored acreage is nearScott/Telford, Buzzard or Ettrick which is currently being developed. As aresult, new discoveries could be tied-in relatively quickly, upon success.

 

During the year, we produced 20,200 boe/d before royalties(20,200 after royalties) in the UK, which was approximately 10% of Nexen’stotal production. At year end, the UK had proved reserves of 182 mmboe beforeroyalties (182 after royalties) representing about 17% of our total proved oiland gas and Syncrude reserves.

 

**Buzzard Development**

 

The Buzzard field is located in the Outer Moray Firth,central North Sea, about 60 miles northeast of Aberdeen, in 317 feet of water.The field was discovered in 2001 and construction was completed in 2006, withproduction commencing early January 2007. During the year, we installed theutilities and production topsides, drilled the initial development wells and completedhook-ups and project commissioning. The facilities have the capacity to processup to 200,000 bbls/d of oil and 60 mmcf/d of gas, including the removal ofhydrogen sulphide. Based upon recent drilling results, we have experienced morewell-to-well variability in the concentration of hydrogen sulphide thanpreviously seen. We expect existing equipment and processes will allow us tomanage this variability for at least the first two to three years ofproduction. As we continue to produce and acquire additional reservoirinformation, we will determine whether additional equipment will ultimately berequired. We anticipate the field will be produced through 27 production wellsand reservoir pressure will be maintained through an active water-flood program.Buzzard is one of the largest discoveries in the UK North Sea in the past tenyears.

 

**Buzzardis on stream and ramping up to estimated peak rates of 85,000 boe/d net to us.**

 

**Ettrick Development**

 

We are progressing development of the Ettrick field which isexpected to begin producing in the first half of 2008, with our share expectedto average approximately 16,000 boe/d (before and after royalties). Developmentincludes drilling three production wells tied back to a leased floatingproduction, storage and off-loading vessel (FPSO) and is approximately 30%complete. Our share of full-cycle development costs is estimated at $460million. In 2007, we plan to invest $235 million in subsea developmentincluding drilling three development wells and one water injection well.

 

 

**UK Production**

 

Buzzard began producing at the beginning of January 2007. Weexpect to reach peak gross production rates of approximately 200,000 bbls/d ofoil and approximately 30 mmcf/d of gas, with our share about 85,000 boe/d(before and after royalties) in the first half of 2007. Oil from Buzzard isexported via the Forties pipeline to the Grangemouth refinery in Scotland. Gasis exported via the Frigg system to the St. Fergus Gas Terminal in northeastScotland. In 2007, we plan to invest approximately $130 million to pre-drilland complete 11 future production and injection wells.

 

Scott and Telford are producing fields with additionalexploitation opportunities. Scott, in which we have a 41% working interest, wasdiscovered 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 in1996. In 2006, our share of Scott and Telford royalty-free productionapproximated 16,000 boe/d, of which 80% was oil.

 

Oil and gas is produced through numerous subsea wells and platform wells. 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 Gas Terminal in

 

6

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northeast Scotland. In 2005, the Scott platformunderwent a significant maintenance turnaround and facilities upgrade toimprove reliability and extend facility life. In 2006, the flare tip and flaretip supporting structure were upgraded. In 2007, we plan to investapproximately $45 million to drill, complete and tie-in three developmentwells.

 

Our 2004 UK acquisition included anon-operated interest in Farragon, a small satellite discovery, which wasbrought on stream in November 2005. In 2006, our 20% share of royalty-freeproduction from Farragon was 3,700 boe/d.

 

**Exploration and UndevelopedAssets**

 

In early 2007, wecompleted drilling operations at our Golden Eagle prospect and we encounteredhydrocarbons. A successful sidetrack was drilled to appraise the accumulationand we are currently evaluating development options. We have a number ofsmaller discoveries on operated blocks near Scott, Buzzard and third-partyfacilities as follows:

 
| **Field**    | ** ** | **Interest****(%)** | ** ** | **Operator Status** | ** ** | **Comments**                                                 |
|--------------|------------|---------------------|------------|---------------------|------------|--------------------------------------------------------------|
| Duart        |       | 50                  |       | non-operated        |       | discovery  near Scott; first oil expected in late 2007       |
| Black Horse  |       | 40                  |       | operated            |       | discovery  near Scott; evaluating development alternatives   |
| Bugle        |       | 82                  |       | operated            |       | discovery  near Scott; well planned for 2007                 |
| Dolphin      |       | 42                  |       | operated            |       | discovery  near Scott; evaluating development alternatives   |
| Golden Eagle |       | 34                  |       | operated            |       | discovery  near Ettrick; evaluating development alternatives |
| Perth        |       | 42                  |       | operated            |       | discovery  near Scott; evaluating development alternatives   |
| Polecat      |       | 40                  |       | operated            |       | discovery  near Buzzard; evaluating development alternatives |
| Selkirk      |       | 38                  |       | operated            |       | appraisal  well planned for 2007                             |
| Yeoman       |       | 50                  |       | operated            |       | discovery  near Scott; evaluating development alternatives   |

 

Development isprogressing at Duart. In 2007, we plan to drill a development well and bringthe field on stream before year-end. The other discoveries are in variousstages of evaluation.

 

During 2006, we drilledunsuccessful exploration wells at Zanzibar and Black Cat. These wellsencountered non-commercial hydrocarbons and were abandoned. In 2007, we expectto drill five exploration and appraisal wells. The offshore drilling rig marketis currently tight, however, we have secured drilling rigs for most of our 2007North Sea exploration and development program.

 

**Coalbed Methane (CBM)**

 

In 2006, we acquired an80% working interest at an emerging CBM opportunity in the UK. CBM is commonlyreferred to as an unconventional form of natural gas because it is primarily storedthrough adsorption by coal in coal deposits rather than in the pore space ofthe rock like most conventional gas. The gas is released in response to a dropin reservoir pressure. If the coal deposit is water saturated, water generallyneeds 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 frominitial development. Water-producing CBM wells in the United States generallyshow increasing gas production rates for a period of approximately one to threeyears before gas rates begin to decline.

 

During 2006, we drilledtwo exploratory wells at our UK CBM opportunity. The wells encountered all thecoal seams expected. In 2007, we plan to continue assessing the potential ofthis investment by drilling additional wells and production testing them.

 

**Fiscal Terms**

 

UK fiscal terms arefavourable. New discoveries pay no royalties and result in cash netbacks thatare higher than our company average. Scott is subject to Petroleum Revenue Tax(PRT), although no PRT is payable until available oil allowances have beenfully utilized, which isn’t expected before 2012. Once payable, PRT is leviedat 50% of cash flow after capital expenditures, operating costs and an oilallowance. PRT is applicable to fields receiving development consent prior toMarch 1993. The Buzzard, Telford and Farragon fields are not subject to PRT.PRT is deductible for corporate income tax purposes. The UK corporate incometax rate is 30% of taxable income. Income from oil and gas activities is also subjectto a supplemental charge. The UK government increased this charge from 10% to20%, effective January 1, 2006. The amount and timing of income taxes payabledepends on many factors including price, production, capital investment levelsand available tax losses.

 

 

7

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| Items 1 and 2 |   | Business and Properties |   | Gulf of Mexico |
|---------------|--------|-------------------------|--------|----------------|

 

**Gulf ofMexico—United States (US)**

 

The Gulf of Mexico is anintegral part of our growth strategy. Large discoveries, relatively high successrates, production infrastructure and attractive fiscal terms make thedeep-water Gulf of Mexico one of the world’s most prospective sources for oiland gas. The deep-water prospects generally have multiple sands and highproduction rates, factors which reduce risk and improve economics. Technologyto find, drill, and develop discoveries is rapidly progressing and becomingmore cost effective. The deep-water Gulf is relatively near infrastructure andcontinental US markets, enabling discoveries to be brought on stream in areasonable period of time.

 

Our strategy in the Gulf isto explore for new reserves, exploit our existing asset base and acquire assetswith upside potential. We focus our exploration program on three strategic playtypes:

 

•                  deep-shelf gas prospects;

•                  deep-water prospects near existinginfrastructure; and

•                  deep-water, sub-salt plays with potential tobecome new core areas.

 

These playsare relatively under-explored, hold potential for large discoveries and haveattractive fiscal terms. The shorter-cycle times for shelf gas and deep-waterprospects near infrastructure complement the longer-cycle times for deep-watersub-salt plays. Although competition in the Gulf is strong, we expect the availability ofexpiring acreage over the next few years to provide us with access toadditional exploration opportunities.

 

 

In 2006, we invested $595million on exploration and development activities in the Gulf. This resulted indiscoveries at Alaminos Canyon Block 856 (Great White West) and Ringo. In 2007,we plan to invest approximately $585 million in the Gulf to further ourstrategy.

 

**US Production**

 
| ** **    | ** ** | **2006**              | ** ** | **2005**             | ** ** | **2004**              | ** ** |
|---------------|------------|-----------------------|------------|----------------------|------------|-----------------------|------------|
| **(mboe/d)**  | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** |
| Deep-water    |       | 19.6                  |       | 17.5                 |       | 24.0                  |       | 21.5 |   | 32.1 |   | 28.7 |   |
| Shallow-water |       | 15.9                  |       | 13.2                 |       | 17.6                  |       | 14.6 |   | 22.6 |   | 18.8 |   |
| Total         |       | 35.5                  |       | 30.7                 |       | 41.6                  |       | 36.1 |   | 54.7 |   | 47.5 |   |

 

In 2006, we produced approximately 35,500boe/d before royalties (30,700 after royalties), representing approximately 17%of Nexen’s total production including Syncrude. This was less than expected dueto timing delays at Aspen and weather-related disruptions. Weather is a risk inthe Gulf of Mexico; specifically, tropical storms and hurricanes can damagefacilities, drilling rigs and surrounding infrastructure, interrupt production,and delay exploration and development programs. Storms in 2005 caused damage tothird-party infrastructure and as a result, approximately 4,000 boe/d of ourpre-storm production was shut-in for nine months of 2006. We carry property andbusiness interruption insurance to mitigate losses caused by adverse weather.During 2006, we received $80 million of insurance proceeds relating to thesestorms.

 

At year end, we had proved reserves of 73mmboe before royalties (63 after royalties) representing about 7% of Nexen’stotal proved oil and gas and Syncrude reserves. Our production and reserves inthe Gulf are primarily concentrated in two deep-water and five shallow-waterareas. We operate most of this production.

 

 

8

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**Deep-WaterProduction**

** **

The majority of ourdeep-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 feetof water. The project was developed using subsea wells tied back to theShell-operated Bullwinkle platform 16 miles away. Production began in December2002 and we achieved payout on our full investment in Aspen in January 2005.Our share of 2006 production before royalties was approximately 8,900 boe/d(8,000 after royalties). In 2006, we drilled an additional development well.This well came on stream in late December. Based on results from this well, wesee additional opportunities in the Aspen field and are currently sidetrackingthe Aspen 1 well to exploit deeper sands. We expect our 2007 production fromthe Aspen field to average between 15,000 and 20,000 boe/d.

 

**TheWrigley discovery is expected to begin producing in early 2007.**

 

Gunnison is in 3,100 feet ofwater and includes Garden Banks Blocks 667, 668 and 669. Gunnison beganproduction in December 2003 through our truss SPAR platform that can handle40,000 bbls/d of oil and 200 mmcf/d of gas. We achieved payout on Gunnison in December2005, just two years after first production. In 2006, our share of productionbefore royalties was approximately 10,600 boe/d (9,300 after royalties). OurGunnison SPAR production facility has excess capacity, leaving room for growthfrom exploration and processing of third-party volumes. In 2006, we completedthe tie-in of our 15% non-operated Dawson Deep discovery to the Gunnison SPAR.

 

**Shallow-WaterProduction**

** **

Our shelf producing assetsare offshore Louisiana, primarily in five 100%-owned field areas: Eugene Island18, Eugene Island 255/257/258/259, Eugene Island 295, Vermilion302/321/339/340, and Vermilion 76 (consisting of Blocks 65, 66 and 67). Wecontinue to exploit these assets and look for other opportunities on the shelf.Most of our 2006 shelf activities focused on development drilling at EugeneIsland 258/259 and Eugene Island 295.

 

**Explorationand Undeveloped Assets**

** **

Our exploration program inthe Gulf of Mexico continues to produce new discoveries. In 2006, we haddiscoveries at Alaminos Canyon Block 856 (Great White West) and Ringo. We arecurrently evaluating development options for both of these discoveries. Duringthe year, we also drilled a successful sidetrack well on our 2005 Knotty Headdiscovery. We are currently proceeding with facility and subsurface studies.Access to deep-water rigs remains limited and we continue to work with partnersto find a rig to complete the appraisal of the field. Our undevelopeddeep-water discoveries include:

 
| **Well**                   | ** ** | **Interest****(%)** | ** ** | **Operator Status** | ** ** | **Comments**                                                     |
|----------------------------|------------|---------------------|------------|---------------------|------------|------------------------------------------------------------------|
| Wrigley                    |       | 50                  |       | non-operated        |       | development  underway; expected to begin producing in early 2007 |
| Alaminos  Canyon Block 856 |       | 30                  |       | non-operated        |       | evaluating  development alternatives                             |
| Tobago                     |       | 10                  |       | non-operated        |       | development  approved; expected to begin producing in 2009       |
| Knotty Head                |       | 25                  |       | operated            |       | further  appraisal required                                      |
| Ringo                      |       | 50                  |       | non-operated        |       | additional  appraisal well to be drilled in 2007                 |

 

During the year, we drilled dry holes atPathfinder, West Cameron 135, West Cameron 109, Eugene Island 19 and Vermilion65. We increased our deep-water undeveloped land position by 20 blocks to over200 blocks and expect this acreage and future exploration opportunities toposition us well for continued growth. In 2007, we plan to tie-in our Wrigleydiscovery to a third-party facility. We also plan to drill nine explorationwells (four in the deep water and five on the shelf) and have drilling rigssecured for more than half of these wells. We are actively working withpartners to find rigs for the remainder. In 2005, we committed to a deep-waterdrilling contract, which provides us with access to a new-build fifthgeneration dynamically positioned semi-submersible drilling rig for two yearsover a three-and-a-half year period. We expect this new rig to be available in mid2009.

 

 

9

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| Items 1 and 2 |   | Business and Properties |   | Canada |
|---------------|--------|-------------------------|--------|--------|

 

**Fiscal Terms**

** **

In 2006, royalty rates on ourUS production averaged 16.6% for shallow-water volumes and 11.2% for deep-watervolumes. The US government has proposed to increase royalty rates from 12.5% to16.7% for new deep-water leases awarded after July 2007. We qualify for royaltyrelief at our deep-water Aspen and Gunnison fields on the first 87.5 mmboe ofproduction. However, we may be subject to royalties at Gunnison if annualcommodity prices are higher than threshold prices set by the US Department ofthe Interior’s Minerals Management Service (MMS). The oil and gas industry iscurrently litigating the enforceability of these price thresholds. In 2006,commodity prices exceeded these thresholds, and we were assessed a royalty atGunnison of 12.5% by the MMS. If the litigation is not successful, royaltiesthat we have accrued on our Gunnison production will be payable. Our Aspenfield is not subject to the minimum price threshold, however, the US governmenthas proposed legislation to include minimum threshold prices for deep-waterleases granted in 1998 and 1999. If the legislation is approved, our Aspenfield could be subject to a 12.5% government royalty on production afterOctober 1, 2006. US taxable income is subject to federal income tax of 35% andstate taxes ranging from 0% to 12%.

 

**Canada**

 

Our strategy in Canada is tobring our new growth developments into production while we maximize value fromour established operations. In 2005, we disposed of approximately 18,300 boe/dbefore royalties of production, comprising approximately 60% oil and 40% gas.The assets we retained have upside potential for continued conventionaldevelopment and enhanced recovery with advancements in extraction technology.During the year, we produced 38,000 boe/d before royalties (31,000 afterroyalties), which was approximately 18% of Nexen’s total production includingSyncrude. At year end 2006, proved reserves (including bitumen and excludingSyncrude) of 364 mmboe before royalties (319 after royalties) wereapproximately 35% of our total proved oil and gas and Syncrude reserves.

 

**InCanada, we are increasing our capacity by focusing on unconventionalresources such as oil sands, CBM and enhanced oil recovery.**

 

Our remainingCanadian conventional assets comprise heavy oil production in east-centralAlberta and west-central Saskatchewan, and natural gas near Calgary and in southern Alberta andSaskatchewan. We operate most of our producing properties and hold 1.1 millionnet acres of undeveloped land across western Canada. These assets providepredictable production volumes and earnings while we advance the followinginitiatives for future growth:

 

•      Athabascaoil sands—to produce and upgrade bitumen into synthetic crude;

•      enhancedoil recovery (EOR)—to increase recovery in our heavy oil fields; and

•      coalbedmethane (CBM)—to extract natural gas primarily from Upper Mannville coals.

 

In 2006, we invested $1,609 million inCanada; $1,416 million into these growth initiatives. In 2007, we plan toinvest approximately $1,070 million; $944 million in these initiatives.

 

 

**Athabasca Oil Sands**

 

The Athabasca oil sands in northeastAlberta is a key growth area for Nexen. Our strategy is to economically developour bitumen resource in phases to provide low-risk, stable, future growth. OurLong Lake project involves integrating steam-assisted-gravity-drainage (SAGD)bitumen production with field upgrading technology to produce a premiumsynthetic crude oil that significantly reduces our need to purchase naturalgas. We also have a 7.23% investment in the Syncrude oil sands miningoperation.

 

10

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Long Lake Project

 

In 2001, we formed a 50/50 joint venturewith OPTI Canada Inc. (OPTI) to develop the Long Lake property using SAGD forbitumen production and field upgrading using the proprietary OrCrudeTM process.OrCrudeTM is a technology to which OPTI has the exclusive Canadian license. Weacquired the exclusive right to use this technology with OPTI, withinapproximately 100 miles of Long Lake, and the right to use the technologyindependently elsewhere in the world.

 

We operate the Long Lake lease bitumenextraction process and are responsible for constructing, developing andoperating the SAGD project. OPTI is responsible for the design, constructionand operation of the upgrader. We share equally in all project reserves,production, operating and capital costs.

 

*SAGD and UpgraderIntegration*

 

SAGD involves drilling two parallelhorizontal wells, generally between 2,300 and 3,300 feet long, with about 16feet of vertical separation. Steam is injected into the shallower well, whereit heats the bitumen that then flows by gravity to the deeper producing well.The OrCrudeTM technology, using conventional distillation, solvent de-asphaltingand thermal cracking, separates the produced bitumen into partially upgradedsour crude oil and liquid asphaltenes. By coupling the OrCrudeTM process withcommercially available hydrocracking and gasification technologies, sour crudeis upgraded to light (39° API) premium synthetic sweet crude oil, and theasphaltenes are converted to a low-energy, synthetic fuel gas. This gas isavailable as a low-cost fuel source, and as a source for hydrogen required inthe hydrocracker. The gas is also to be burned in a co-generation plant toproduce steam for the SAGD operations and for electricity to be used on-siteand sold to the provincial electricity grid. The energy conversion efficiencyfor our Long Lake upgrader is about 90% compared to 75% for a typicalbitumen-fed coker, which we expect will provide us with an approximate $10/bbloperating cost advantage.

 

*Our Strategic Advantage*

 

Our SAGD and upgradingintegration enables us to overcome three main economic hurdles of SAGD bitumenproduction: 1) the high cost of natural gas; 2) the cost and availability ofdiluent; and 3) the realized price of bitumen. With synthetic gas from theasphaltenes as a fuel source, we have little need to purchase additionalnatural gas. With the upgrading facilities on site, expensive diluent is notrequired to transport the bitumen tomarket. And, by upgrading the bitumen into a highly desirable refineryfeedstock or diluent supply, the end product commands light-sweet crude oilpremium pricing.

 

 

**We expect our integrated oilsands strategy will provide us with an approximate $10/bbl operating costadvantage.**

 

*Project Milestones and Costs*

 

The Long Lake projectreceived regulatory approval in 2003 and Nexen board approval in 2004. Fieldconstruction on the SAGD and upgrader facilities began in 2004. In 2006, wesubstantially completed module and site construction of the SAGD facilities.Steam injection is expected to commence at the end of the first quarter of2007, with bitumen production expected to ramp up to peak rates over a 12 to 24month period. For the first six months of SAGD operation, we will largely beheating the reservoir. During this period, steam to oil ratios will be high butwill decline with time as bitumen production ramps up to our target rates.Depending on our actual start up date and the amount of downtime at ourfacilities, we expect bitumen production before royalties to reach between35,000 and 45,000 bbls/d (between 17,500 and 22,500 bbls/d net to our share) bythe end of 2007, with a steam-to-oil 

 

11

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ratio of between 3.5 and 4.0. We expect thesteam-to-oil ratio to average approximately 3.0 over the long-term.

 

**Long Lake is on track for startup in 2007 and expected to reach peak production of about 60,000 bbls/d (30,000bbls/d net) of premium synthetic crude by late 2008 or early 2009.**

 

Upgrader module fabrication is largelycomplete and over 95% of the modules are on site. Construction of the upgraderis approximately 80% complete and start up is scheduled for late 2007. Peakoutput of premium synthetic crude oil is expected within 6 to 18 months ofupgrader start up and we expect to exit 2007 with synthetic production rates ofbetween 28,000 and 36,000 bbls/d (between 14,000 and 18,000 bbls/d net to ourshare). Production capacity for the first phase of Long Lake is approximately60,000 bbls/d (30,000 bbls/d net to our share) of premium synthetic crude,which we expect to reach by late 2008 or early 2009. We also expect productionto be maintained over the project’s life, estimated at 40 years, by periodicallydrilling additional SAGD well-pairs.

 

In 2006, we invested $1,050million at Long Lake and expect to invest approximately $500 million in 2007.The capital cost estimate when our board sanctioned the project in February2004 was $3.4 billion ($1.7 billion net). In December 2004, we accelerated thedrilling of an additional well pad consisting of 13 well-pairs to ensurecertainty and reliability of bitumen production at the commencement of upgraderoperations at a cost of $98 million ($49 million net). In early 2006, wefurther modified the project design by adding steam generation capacity andsoot handling equipment at a cost of $360 million ($180 million net). Thesescope changes increased the estimated project cost to $3.8 billion ($1.9 billionnet). While construction progress has been significant, high activity in theoil sands is placing ongoing pressure on the costs of labour and services. Inaddition, labour productivity has been lower than anticipated, requiring alarger workforce to maintain progress. As a result, the projected costs of LongLake have increased from $3.8 billion to $4.6 billion ($1.9 billion to $2.3billion net). Although we are seeing pressure on capital costs, we expect tobenefit from a significant operating cost advantage. Combined SAGD,cogeneration and upgrading operating costs are expected to average between$12/bbl and $14/bbl, substantially lower than coking upgrading. We expectongoing capital to average between $3/bbl and $4/bbl. The capital costs ofproducing and upgrading bitumen using this technology are comparable to thosefor surface mining and coking upgrading on a barrel-of-daily production basis.

 

12

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*FuturePhases*

* *

We have approximately 240,000net acres of bitumen-prone lands in the Athabasca region and plan to acquiremore. We plan to continue developing our bitumen lands in a phased manner usingour integrated upgrading strategy. In 2005, we announced our plan to duplicateLong Lake by developing Phase 2. In 2006, we invested $119 million for futurephases and in 2007, we plan to invest approximately $170 million on landacquisition, additional drilling, seismic and engineering to develop our leasesand advance regulatory applications for these phases. Phase 2 SAGD productionis expected to be on stream by late 2011, with upgrader start up by the secondhalf of 2012, followed by additional phases every two years or three years.Each phase will leverage the knowledge and experience gained from successfullydeveloping Long Lake and subsequent projects will be similar in size anddesign. By keeping the core team in place and repeating and improving onexisting designs and implementation plans, we expect to gain efficiencies inengineering, modular fabrication and on-site construction. We also anticipateenhanced operating efficiencies as we can train and move people easily betweenthe various plants.

 

**Phase 2SAGD production is expected to be on stream by late 2011 followed by upgraderstart up in 2012.**

 

*Reserves Recognition*

* *

Under SEC rules andregulations, we are required to recognize bitumen reserves rather than theupgraded premium synthetic crude oil that we will produce and sell. Theeconomic recoverability of bitumen reserves is sensitive to natural gas prices,diluent costs and light/heavy differentials, risks that our integrated projecthas been designed to virtually eliminate. At December 31, 2006, we recognizedproved bitumen reserves of 246 mmboe before royalties (219 after royalties) forour Long Lake project, representing about 23% of Nexen’s total proved oil andgas and Syncrude reserves before royalties.

 

**Heavy Oil**

** **

Approximately 52% of ourCanadian conventional production is heavy oil. Heavy oil is characterized byhigh specific gravity or weight and high viscosity or resistance to flow.Because of these features, heavy oil is more difficult and expensive toextract, transport and refine than other types of oil. Heavy oil also receivesa lower price than light oil, as more expensive and complex refineries arerequired to refine the heavy crude into higher-value petroleum products.

 

Our heavy oil operations arein east-central Alberta and west-central Saskatchewan. To maximize heavy oilreturns, it is important to manage capital and operating costs. Our largeproduction base and existing infrastructure are advantageous to us in managingthese costs. In 2007, we plan to continue exploiting our existing fieldsthrough drilling and optimizing operations.

 

**Enhanced OilRecovery**

** **

Heavy oil reservoirs typicallyhave lower recovery factors than conventional oil reservoirs, leavingsubstantial amounts of oil in the ground. This creates an opportunity toincrease recovery factors by applying new technology. We are continuing toresearch various technologies to increase our heavy oil recoveries with severalongoing pilot projects in west-central Saskatchewan.

 

**Natural Gas**

** **

Approximately 48% of ourCanadian production is natural gas extracted primarily from shallow sweetreservoirs in southern Alberta and Saskatchewan and from sour gas reservoirsnear Calgary. In general, shallower gas targets are cheaper to drill anddevelop, but have relatively smaller reserves and lower productivity per well.Sour gas is natural gas that contains hydrogen sulfide. We have been producingsour natural gas from our Balzac field northeast of Calgary since 1961. Thissour gas is processed through our operated Balzac plant.

 

**CoalbedMethane (CBM)**

** **

In 2005, we approvedcommercial CBM developments at Corbett, Doris and Thunder in the Fort Assiniboinearea. Our CBM pilot at Corbett in the Fort Assiniboine area of central Albertahas established techniques to produce natural gas from water saturated UpperMannville coals. These coals are generally deeper than the Horseshoe Canyon “drycoal” play, which is also being commercially developed in Alberta. Weestablished commerciality of CBM production from the Upper Mannville coals in2005 by applying horizontal well technology. Commercial production rates andreduced de-watering time has enabled us to confidently develop these coals.

 

 

13

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| Items 1 and  2 |   | Business and  Properties |   | Middle East |
|----------------|--------|--------------------------|--------|-------------|

 

In 2006, we investedapproximately $237 million in exploration and development activities. We have along-term view of this business and plan to increase our CBM production to atleast 150 mmcf/d by 2011, more than doubling our current Canadian natural gasproduction. At the end of 2006, we held more than 700 net sections of land inAlberta with CBM potential, some of which overlay existing conventionalproducing lands. We have also established positions in other prospective CBMareas of Alberta. In 2007, we plan to invest $200 million to develop 98 gross(41 net) sections using single and multi-leg horizontal wells. In addition toour development at Fort Assiniboine, we will continue to evaluate otherMannville and Horseshoe Canyon CBM prospects and pursue new CBM opportunitiesin 2007.

 

**Shale Gas**

 

As part of our growthstrategy in unconventional Canadian resource plays, we acquired over 100sections of land in an emerging shale gas play in western Canada in 2006. Shalegas is natural gas produced from reservoirs composed of organic shale. The gasis stored in pore spaces, fractures or adsorbed into organic matter. Currently,the United States is the largest producer of shale gas. In 2007, we plan toinitiate a drilling and evaluation program to demonstrate the feasibility ofthis resource.

 

**Fiscal Terms**

 

In Canada, we payroyalties ranging from 15% to 40% on production from lands owned by the federaland provincial governments. Some provinces also impose taxes on production fromlands where they do not own the mineral rights. The Saskatchewan governmentassesses a resource surcharge on gross Saskatchewan resource sales that aresubject to crown royalties of 3.3%, which is reduced to 1.85% for wellscompleted after October 1, 2002.

 

Profits earned in Canadafrom resource properties are subject to federal and provincial income taxes. In2006, legislation was passed to reduce the federal corporate income tax rate onincome from Canadian oil and gas activities from 24% to 19% by 2010.

 

For our oil sandsprojects, we elected to pay royalties based on bitumen production, whichincludes a 1% royalty on gross revenue until all costs have been recovered, atwhich time the royalty changes to 25% on net revenue. With the combination oflow royalties, our expected operating cost advantage and a premium product, ouroil sands financial returns are expected to be attractive relative to other oilsands projects.

 

**Middle East—Yemen**

 

Yemen has been our mostsignificant international region since we first began production at Masila in1993. We operate the country’s largest oil project and have developed excellentrelationships with the government and local communities. Our success andreputation in Yemen opens doors elsewhere in the Middle East and around theworld.

 

**Although our Masila fields have matured, we expect to generateapproximately 20% of the total project cash flow from the remaining provedresources.**

 

Our strategy is tomaximize the value from our existing blocks, while we continue to search fornew reservoirs in deeper horizons. We have two producing blocks: Masila (Block14) and East Al Hajr (Block 51). In 2006, we produced 92,900 bbls/d of oilbefore royalties (51,800 after royalties), representing approximately 44% ofNexen’s total production and 32% of 2006 cash flow. Proved reserves of 66 mmboebefore royalties (38 after royalties) comprise approximately 6% of Nexen’stotal proved oil and gas and Syncrude reserves before royalties.

 

 

 

14

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**Masila Block (Block 14 )**

 

We have a 52% workinginterest in and operate the Masila project. Our share of 2006 production was70,300 bbls/d before royalties (35,500 after royalties). After more than 10years of growth, our Masila fields have matured, but significant value stillremains. As a result of the Production Sharing Agreement (PSA) terms thatgovern Masila production, we still expect to generate approximately 20% of thetotal project free cash flow from the remaining proved reserves recoverablebefore the PSA expires in 2011.

 

The first successfulMasila exploratory well was drilled at Sunah in 1990, with additionaldiscoveries quickly following at Heijah and Camaal. Initial production began inJuly 1993, with the first lifting of oil in August 1993. Masila Blend oilaverages 32° API at very low gas-oil ratios. Most of the oil is produced fromthe Upper Qishn formation, but we also produce from deeper formations includingthe Lower Qishn, Upper Saar, Saar, Madbi, Basal Sand and Basement formations.

 

Production is collectedat our Central Processing Facility (CPF) where water is separated forreinjection and oil is pumped to the Ash Shihr export terminal and shipped tocustomers primarily in Asia.

 

We are managing the paceof our drilling program to ensure we recover the remaining reserves in the mostefficient, cost-effective manner. In 2007, we plan to invest approximately $55million to drill 14 wells.

 

The PSA governing Masilaproduction was signed in 1987 between the Government of Yemen and the Masilajoint venture partners (Masila Partners), including Nexen. Under the PSA, wehave the right to produce oil from Masila into 2011 and to negotiate afive-year extension. Production is divided into cost recovery oil and profitoil. Cost recovery oil provides for the recovery of all exploration,development, and operating costs that are funded by the Masila Partners. Costsare 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 isprofit oil that is shared between the Masila Partners and the Government and iscalculated on a sliding scale based on production. The Masila Partners’ shareof profit oil ranges from 20% to 33%. The structure of the agreement moderatesthe impact on Masila Partners’ cash flows during periods of low prices, as werecover our costs first and then share any remaining profit oil with theGovernment. At current production, the Government is entitled to approximately73% of the profit oil, which includes a component for Yemen income taxespayable by the Masila Partners at a rate of 35%. In 2006, the Masila Partners’share of production, including recovery of past costs, was approximately 37%.

 

 

15

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**East Al Hajr Block (Block 51)**

 

Wehave an 87.5% working interest and operate Block 51. This block is governed bya PSA between the Government of Yemen and the East Al Hajr partners (EAHPartners): The Yemen Company (TYCO) (12.5% carried working interest) and Nexen(87.5% working interest). Under the PSA, TYCO has no obligation to fund capitalor operating expenditures. Our effective interest is 100% and for purposes ofaccounting and reserves recognition, we treat TYCO’s 12.5% participatinginterest as a royalty interest. We recognize both the Government’s share andTYCO’s share of profit oil under the PSA as royalties and taxes consistent withour treatment of our Masila operations. The PSA expires in 2023, and we havethe right to negotiate a five-year extension. Under the terms of the PSA, theEAH Partners pay a royalty ranging from 3% to 10% to the Government dependingon production volumes. Theremaining production is divided into cost recovery oil and profit oil. Costrecovery oil provides for the recovery of all of the project’s exploration,development and operating costs, funded solely by Nexen. Costs are recoveredfrom a maximum of 50% of production each year after royalties, as follows:

 
| **Costs**   | ** ** | **Recovery**                    |
|-------------|------------|---------------------------------|
| Operating   |       | 100% in year incurred           |
| Exploration |       | 75% per year, declining balance |
| Development |       | 75% per year, declining balance |

 

The remaining production is profit oilthat is shared between the EAH Partners and the Government on a sliding scalebased on production rates. The EAH Partners’ share of profit oil ranges from20% to 30%. The Government’s share of profit oil includes a component for Yemenincome taxes payable by the EAH Partners at a rate of 35%. In 2006, the EAHPartners’ share of Block 51 production, including recovery of past costs, wasapproximately 61%.

 

The first successful exploratory well wasdrilled at BAK-A in 2003, with BAK-B discovered shortly after. Block 51development began in 2004 and includes a CPF, gathering system and a 22-kmtieback to our Masila export pipeline. Production began in November 2004 and weachieved payout on the project in the first quarter of 2006. During the year,production averaged 22,600 bbls/d before royalties (16,300 after royalties).

 

**We achieved payout on Block 51in the first quarter of 2006.**

 

In 2006, we drilled three explorationwells on the block and two of these wells were abandoned. In 2007, we plan toinvest approximately $80 million to drill nine development wells, constructadditional facilities and continue exploring with three exploration wells.

 

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| Business  and Properties |   | Offshore  West Africa |
|--------------------------|--------|-----------------------|

 

**Offshore West Africa**

 

Offshore West Africa is a growing corearea where we already have discoveries. It offers prolific reservoirs andmultiple opportunities to invest in this oil-rich region. Our strategy here isto explore and develop our portfolio for medium- to long-term growth.

 

**Nigeria**

 

**Block OPL-222**

 

In 1998, we acquired a 20% non-operatedinterest in Block OPL-222, which includes 448,000 acres and is approximately 50miles offshore in water depths ranging from 600 to 3,500 feet. The ongoingappraisal of the block indicates significant hydrocarbon accumulations based onthe 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                                                                |

 

Appraisal of this field is complete. TheNigerian authorities have provisionally approved the preliminary Usan fielddevelopment plan. We expect the Usan development to be formally sanctioned in2007, with first production as early as 2010.

 

**Usan is expected to beproducing by 2011, adding about 30,000 bbls/d to our production.**

 

The development will include a FPSO withstorage capacity of two million barrels, capable of handling peak productionrates of 160,000 bbls/d of oil. In 2007, we plan to invest approximately $140million to progress development by completing our cost estimate. We have a 20%interest in this development program. Proved reserves of 30 mmboe beforeroyalties (25 after royalties) comprise approximately 3% of Nexen’s totalproved oil and gas and Syncrude reserves.

 

In 2006, we drilled the deep-water UkotSouth well. This well was unsuccessful and the capital costs were expensed.

 

**Block OML-115**

 

We relinquished this block during theyear.

 

**Block OML-109—Ejulebe**

 

In 2005, we sold our producing assets andterminated our contractual interest in this block.

 

 

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| Items 1 and 2 |   | Business and Properties |   | Other International |
|---------------|--------|-------------------------|--------|---------------------|

 

**Equatorial Guinea—Block K**

 

We relinquished thisblock during the year.

 

**Other International**

**Colombia**

**Boqueron Block—Guando**

 

In 2000, we made ourfirst discovery at Guando on our 20% non-operated Boqueron Block. Boqueron isin the Upper Magdalena Basin of central Colombia, approximately 45 km southwestof Bogota. Our share of 2006 production averaged 6,300 bbls/d before royalties(5,700 after royalties), about 3% of Nexen’s total production includingSyncrude.

 

Production from Guandois subject to a 5% to 25% royalty depending on daily production. In 2006,legislation was introduced to reduce the corporate income tax rate from 38.5%in 2006 to 34% in 2007, and to 33% in 2008 and future years.

 

**Exploration Blocks**

 

We have interests inthree exploration blocks in the Upper Magdalena Basin. Villarrica was acquiredin 2000, El Queso in 2003 and Boqueron Deep in 2003. In 2005, we relinquishedthe Villarrica Block and acquired the Villarrica Norte Block under improvedfiscal terms. In 2006, we drilled a well on the El Queso block which we arecurrently evaluating. We are currently participating in a well on Boqueron Deepand plan to drill a well on Villarrica Norte later in 2007. In addition, we areassessing potential drilling opportunities in other areas of the UpperMagdelena Basin.

 

**Norway**

 

As part of our growthstrategy in the North Sea, we participated in the 2006 bid round forexploration rights offshore Norway and were awarded interests in four licensesin early 2007. In 2007, we expect to invest approximately $30 million inadditional seismic and geologic studies there.

 

**Australia—Buffalo**

 

Field abandonment beganin November 2004 and was completed in 2005.

 

**Reserves, Production and RelatedInformation**

 

In addition to thetables below, we refer you to the Supplementary Data in Item 8 of this Form10-K for information on our oil and gas producing activities. Nexen has notfiled with nor included in reports to any other United States federal authorityor agency, any estimates of total proved crude oil or natural gas reservessince the beginning of the last fiscal year.

 

**Oil and Gas Acreage**

 
| ** **               | ** ** | **2006**      | ** ** |
|--------------------------|------------|---------------|------------|
| ** **               | ** ** | **Developed** | ** ** | **Undeveloped (****1)** | ** ** | **Total** | ** ** |
| **(thousands of acres)** | ** ** | **Gross**     | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Yemen (2)                |       | 50            |       | 29 |   | 756 |   | 628 |   | 806 |   | 657 |   |
| Canada                   |       | 781           |       | 578 |   | 2,081 |   | 1,095 |   | 2,862 |   | 1,673 |   |
| United  States           |       | 183           |       | 103 |   | 1,396 |   | 650 |   | 1,579 |   | 753 |   |
| United  Kingdom          |       | 83            |       | 27 |   | 1,822 |   | 1,031 |   | 1,905 |   | 1,058 |   |
| Colombia (4)             |       | 1             |       | — |   | 604 |   | 463 |   | 605 |   | 463 |   |
| Nigeria (2), (3)         |       | —        |       | — |   | 448 |   | 90 |   | 448 |   | 90 |   |
| **Total**                | ** ** | **1,098**     | ** ** | **737** | ** ** | **7,107** | ** ** | **3,957** | ** ** | **8,205** | ** ** | **4,694** | ** ** |

 

----

*Notes:*

*(1)**      **Undeveloped acreage isconsidered to be those acres on which wells have not been drilled or completedto a point that would permit production of commercial quantities of crude oiland natural gas regardless of whether or not such acreage contains provedreserves.*

*(2)**      **The acreage is coveredby production sharing contracts.*

*(3)**      **The acreage is coveredby a joint venture agreement.*

*(4)**      **The acreage is covered by anassociation contract.*

 

18

----

 
| Business and Properties |   | Operations Statistics |
|-------------------------|--------|-----------------------|

 

Producing Oil and Gas Wells

 
| ** **            | ** ** | **2006**      | ** ** |
|-----------------------|------------|---------------|------------|
| ** **            | ** ** | **Oil**       | ** ** | **Gas** | ** ** | **Total** | ** ** |
| **(number of wells)** | ** ** | **Gross (1)** | ** ** | **Net (2)** | ** ** | **Gross (1)** | ** ** | **Net (2)** | ** ** | **Gross (1)** | ** ** | **Net (2)** | ** ** |
| Yemen                 |       | 428           |       | 249 |   | — |   | — | ** ** | 428 |   | 249 |   |
| Canada                |       | 2,196         |       | 1,519 |   | 2,627 |   | 2,279 |   | 4,823 |   | 3,798 |   |
| United  States        |       | 191           |       | 91 |   | 199 |   | 138 |   | 390 |   | 229 |   |
| United  Kingdom       |       | 39            |       | 17 |   | — |   | — |   | 39 |   | 17 |   |
| Colombia              |       | 91            |       | 19 |   | — |   | — |   | 91 |   | 19 |   |
| **Total**             | ** ** | **2,945**     | ** ** | **1,895** | ** ** | **2,826** | ** ** | **2,417** | ** ** | **5,771** | ** ** | **4,312** | ** ** |

 

----

*Notes:*

*(1)*       *Gross wells are the totalnumber of wells in which we own an interest.*

*(2)*       *Net wells are the sum offractional interests owned in gross wells.*

 

Drilling Activity

 
| ** **                | ** ** | **2006**            | ** ** |
|---------------------------|------------|---------------------|------------|
| ** **                | ** ** | **Net Exploratory** | ** ** | **Net Development** | ** ** | ** ** | ** ** |
| **(number of net wells)** | ** ** | **Productive**      | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Productive** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Total** | ** ** |
| Yemen                     |       | 3.0                 |       | 5.5 |   | 8.5 |   | 36.0 |   | 1.0 |   | 37.0 |   | 45.5 |   |
| Canada                    |       | 35.4                |       | 2.2 |   | 37.6 |   | 214.3 |   | 0.7 |   | 215.0 |   | 252.6 |   |
| United  States            |       | 1.6                 |       | 2.1 |   | 3.7 |   | 8.3 |   | 2.0 |   | 10.3 |   | 14.0 |   |
| United  Kingdom           |       | 0.8                 |       | 1.7 |   | 2.5 |   | 5.5 |   | — |   | 5.5 |   | 8.0 |   |
| Colombia                  |       | —              |       | — |   | — |   | 2.0 |   | — |   | 2.0 |   | 2.0 |   |
| Nigeria                   |       | —              |       | 0.2 |   | 0.2 |   | — |   | — |   | — |   | 0.2 |   |
| **Total**                 | ** ** | **40.8**            | ** ** | **11.7** | ** ** | **52.5** | ** ** | **266.1** | ** ** | **3.7** | ** ** | **269.8** | ** ** | **322.3** | ** ** |

 
| ** **                | ** ** | **2005**            | ** ** |
|---------------------------|------------|---------------------|------------|
| ** **                | ** ** | **Net Exploratory** | ** ** | **Net Development** | ** ** | ** ** | ** ** |
| **(number of net wells)** | ** ** | **Productive**      | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Productive** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Total** | ** ** |
| Yemen                     |       | 0.5                 |       | 4.6 |   | 5.1 |   | 33.0 |   | 1.6 |   | 34.6 |   | 39.7 |   |
| Canada                    |       | 32.2                |       | 8.0 |   | 40.2 |   | 198.9 |   | 0.5 |   | 199.4 |   | 239.6 |   |
| 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 |   |
| Colombia                  |       | —              |       | — |   | — |   | 1.8 |   | — |   | 1.8 |   | 1.8 |   |
| Nigeria                   |       | 0.4                 |       | 0.2 |   | 0.6 |   | — |   | — |   | — |   | 0.6 |   |
| 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** | ** ** | ** ** | ** ** |
| **(number of net wells)** | ** ** | **Productive**      | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Productive** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Total** | ** ** |
| Yemen                     |       | —              |       | 2.0 |   | 2.0 |   | 37.3 |   | 0.5 |   | 37.8 |   | 39.8 |   |
| Canada                    |       | 13.4                |       | 1.0 |   | 14.4 |   | 202.9 |   | — |   | 202.9 |   | 217.3 |   |
| United  States            |       | 0.3                 |       | 1.8 |   | 2.1 |   | 11.0 |   | 1.0 |   | 12.0 |   | 14.1 |   |
| United  Kingdom           |       | —              |       | — |   | — |   | — |   | — |   | — |   | — |   |
| Colombia                  |       | —              |       | — |   | — |   | 7.0 |   | — |   | 7.0 |   | 7.0 |   |
| Nigeria                   |       | 0.4                 |       | 1.0 |   | 1.4 |   | — |   | — |   | — |   | 1.4 |   |
| Equatorial  Guinea        |       | —              |       | 0.5 |   | 0.5 |   | — |   | — |   | — |   | 0.5 |   |
| **Total**                 | ** ** | **14.1**            | ** ** | **6.3** | ** ** | **20.4** | ** ** | **258.2** | ** ** | **1.5** | ** ** | **259.7** | ** ** | **280.1** | ** ** |

 

Wells in Progress

 

At December 31, 2006, we weredrilling 5 wells in Yemen (3.6 net), 5 wells in Canada (5 net), 2 wells in theUnited States (1.6 net), 3 wells in the United Kingdom (1.6 net), and 1 well inColombia (0.5 net).

 

19

----

 
| Items 1and 2 | Business and Properties |   | Operations Statistics |
|--------------|-------------------------|--------|-----------------------|

 

Net Sales byProduct from Continuing Oil and Gas Operations (including Syncrude)

 
| **(Cdn$ millions)**                               | ** ** | **2006**  | ** ** | **2005**  | ** ** | **2004**  | ** ** |
|--------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Conventional  Crude Oil and Natural Gas Liquids (NGLs) |       | 2,479     |       | 2,438     |       | 1,697     |       |
| Synthetic  Crude Oil                                   |       | 446       |       | 397       |       | 321       |       |
| Natural Gas                                            |       | 553       |       | 671       |       | 534       |       |
| **Total**                                              | ** ** | **3,478** | ** ** | **3,506** | ** ** | **2,552** | ** ** |

 

Crude oil (includingsynthetic crude oil) and natural gas liquids represent approximately 84% of ouroil and gas net sales, while natural gas represents the remaining 16%.

 

Sales Prices and ProductionCosts (excluding Syncrude)

 
| ** **                         | ** ** | **Average Sales Price (1)** | ** ** | **Average Production Cost (1)** | ** ** |
|------------------------------------|------------|-----------------------------|------------|---------------------------------|------------|
| ** **                         | ** ** | **2006**                    | ** ** | **2005**                        | ** ** | **2004** | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Crude  Oil and NGLs** (Cdn$/bbl) |       |                        |       |                            |       |   |   |   |   |   |   |   |   |
| Yemen                              |       | 71.57                       |       | 62.07                           |       | 47.59 |   | 8.11 |   | 6.75 |   | 5.64 |   |
| Canada (2)                         |       | 42.79                       |       | 40.51                           |       | 36.60 |   | 15.50 |   | 14.01 |   | 11.76 |   |
| United States                      |       | 65.80                       |       | 57.63                           |       | 46.60 |   | 9.45 |   | 7.33 |   | 6.09 |   |
| United Kingdom                     |       | 71.19                       |       | 60.55                           |       | 46.81 |   | 11.28 |   | 14.90 |   | 8.26 |   |
| Australia (2)                      |       | —                      |       | —                          |       | 51.22 |   | — |   | — |   | 35.73 |   |
| Other Countries                    |       | 66.09                       |       | 59.96                           |       | 43.07 |   | 3.13 |   | 6.08 |   | 4.09 |   |
|                               |       |                        |       |                            |       |   |   |   |   |   |   |   |   |
| **Natural Gas** (Cdn$/mcf)         |       |                        |       |                            |       |   |   |   |   |   |   |   |   |
| Canada (2)                         |       | 6.49                        |       | 7.51                            |       | 5.76 |   | 1.65 |   | 0.95 |   | 0.85 |   |
| United States                      |       | 7.86                        |       | 10.56                           |       | 7.89 |   | 1.58 |   | 1.22 |   | 1.02 |   |
| United Kingdom                     |       | 7.43                        |       | 7.86                            |       | 8.28 |   | 1.88 |   | 2.48 |   | — |   |

 

----

*Notes:*

*(1)*       *Sales prices and unitproduction costs are calculated using our working interest production afterroyalties.*

*(2)*       *Includes results ofdiscontinued operations for 2005 and 2004. (See Note 14 to our ConsolidatedFinancial Statements.)*

 

**ProvedReserves including Proved Undeveloped Reserves**

 

At December 31, 2006, we had725 mmboe of proved oil and gas reserves before royalties (637 afterroyalties). This is a 55% increase over the prior year (62% after royalties).Including Syncrude, our total proved oil and gas and Syncrude reservesincreased 34% to 1,049 mmboe (39% to 911 after royalties).

 

The following table providesa summary of the changes in our proved oil and gas reserves (before royalties)excluding our Syncrude reserves. Refer to page 131 for proved reservesinformation on an after-royalties basis.

 
| ** **                | ** ** | ** ** | ** ** | **United**  | ** ** | **United** | ** ** | ** ** | ** ** | **Other**     | ** ** | ** ** | ** ** |
|---------------------------|------------|------------|------------|-------------|------------|------------|------------|------------|------------|---------------|------------|------------|------------|
| **(mmboe)**               | ** ** | **Canada** | ** ** | **Kingdom** | ** ** | **States** | ** ** | **Yemen**  | ** ** | **Countries** | ** ** | **Total**  | ** ** |
| December 31,  2005        |       | 117        |       | 145         |       | 90         |       | 105        |       | 11            |       | 468        |       |
| Extension and Discoveries |       | 11         |       | 25          |       | 7          |       | 4          |       | 30            |       | 77         |       |
| Revisions                 |       | 249        |       | 20          |       | (11        | )          | (8         | )          | 1             |       | 251        |       |
| Production                |       | (13        | )          | (8          | )          | (13        | )          | (35        | )          | (2            | )          | (71        | )          |
| **December  31, 2006**    | ** ** | **364**    | ** ** | **182**     | ** ** | **73**     | ** ** | **66**     | ** ** | **40**        | ** ** | **725**    | ** ** |

 

 

20

----

 

Extensions and discoveriescontributed 77 mmboe (67 after royalties). The majority of the increase resultsfrom new development projects at Usan, offshore West Africa, the Ettrick andDuart fields in the North Sea, Ringo in the Gulf of Mexico, and coalbed methanein Canada. Other increases relate to ongoing exploitation activities in theNorth Sea, Yemen, the Gulf of Mexico and Canada.

 

The revisions relateprimarily to our Long Lake project. Under SEC rules, we are required torecognize bitumen reserves rather than the upgraded synthetic crude oil that wewill produce and sell. As such, proved reserves recognition depends on year endoil prices, light/heavy differentials, diluent prices and natural gas prices.We initially recognized proved bitumen reserves at Long Lake in early 2004 whenwe sanctioned development of the project. The reserves were, however, writtenoff at the end of the year due to wide light/heavy differentials and highnatural gas costs. At the end of 2006, narrow light/heavy differentials and lownatural gas costs allowed us to recognize proved bitumen reserves of 246 mmboe(219 after royalties). In the North Sea, the additions reflect increases atBuzzard as a result of development drilling and an increase in the proved recoveryfactor. In Canada, the additions relate primarily to our heavy oil propertieswhere narrow light/heavy differentials increased the amount of economicallyrecoverable reserves. Negative revisions occurred on Block 51 in Yemen and theAspen field in the Gulf of Mexico as a result of lower than expected productionperformance.

 

**ProvedUndeveloped Reserves**

 

The following table providesa summary of our proved undeveloped reserves (PUDs) for our oil and gasactivities at December 31, 2006 and 2005:

 
| ** **             | ** ** | **Before Royalties** | ** ** | **After Royalties**  | ** ** |
|------------------------|------------|----------------------|------------|----------------------|------------|
| **(mmboe)**            | ** ** | **PUDs**             | ** ** | **Total Proved (1)** | ** ** | **% of Total** | ** ** | **PUDs** | ** ** | **Total Proved (1)** | ** ** | **% of Total** | ** ** |
| Canada                 |       | 216                  |       | 364                  |       | 59 | % | 188 |   | 319 |   | 59 | % |
| United  Kingdom        |       | 50                   |       | 182                  |       | 27 | % | 50 |   | 182 |   | 27 | % |
| Yemen                  |       | 9                    |       | 66                   |       | 14 | % | 5 |   | 38 |   | 13 | % |
| United  States         |       | 9                    |       | 73                   |       | 12 | % | 7 |   | 63 |   | 11 | % |
| Other  Countries       |       | 31                   |       | 40                   |       | 78 | % | 25 |   | 35 |   | 71 | % |
| **December  31, 2006** | ** ** | **315**              | ** ** | **725**              | ** ** | **43** | **%** | **275** | ** ** | **637** | ** ** | **43** | **%** |
|                   |       |                 |       |                 |       |   |   |   |   |   |   |   |   |
| Canada                 |       | 13                   |       | 117                  |       | 11 | % | 11 |   | 101 |   | 11 | % |
| United  Kingdom        |       | 128                  |       | 145                  |       | 88 | % | 128 |   | 145 |   | 88 | % |
| Yemen                  |       | 23                   |       | 105                  |       | 22 | % | 13 |   | 59 |   | 22 | % |
| United  States         |       | 15                   |       | 90                   |       | 17 | % | 13 |   | 77 |   | 17 | % |
| Other  Countries       |       | 1                    |       | 11                   |       | 5 | % | — |   | 11 |   | 5 | % |
| **December  31, 2005** | ** ** | **180**              | ** ** | **468**              | ** ** | **38** | **%** | **165** | ** ** | **393** | ** ** | **42** | **%** |

 

----

*Note:*

*(1)*       *Excludes proved reserves forour Syncrude operations of 324 mmboe (274 after royalties) in 2006 and 318mmboe (264 after royalties) in 2005.*

 

In 2006, our PUDs increasedby 135 mmboe (110 after royalties). We added 206 mmboe (179 after royalties) atLong Lake relating to proved reserves outside of the initial 81 well-pair SAGDdevelopment area. We also added PUDs from our new development projects at Usan,Ettrick, Ringo, Duart and CBM. We converted 117 mmboe (112 after royalties) ofPUDs to developed, with the majority relating to the completion of the Buzzarddevelopment project. Other small additions and conversions occurred fromongoing development activities at Canada, the United States, Yemen, the UnitedKingdom and Colombia.

 

In Canada, our PUDs increasedfrom 13 mmboe (11 after royalties) to 216 mmboe (188 after royalties).Substantially all of the increase relates to Long Lake where we added 206 mmboe(179 after royalties). These PUDs are expected to be converted to developedover the next 20 years as we drill additional wells to provide feedstock to runthe upgrader at capacity. The remaining PUDs relate to infill drilling, recompletionsor facilities enhancements on our various heavy oil and natural gas fields. Themajority of these PUDs are expected to be converted to producing reserves in2007 and 2008. Also, a small portion of the PUDs relate to our CBM properties,which are expected to be converted to producing by infill drilling and fielddevelopment planned for 2007 and 2008.

 

21

----

 
| Items 1 and  2 |   | Business and  Properties |   | Syncrude Mining |
|----------------|--------|--------------------------|--------|-----------------|

 

In the United Kingdom, ourPUDs decreased from 128 mmboe (128 after royalties) to 50 mmboe (50 afterroyalties) primarily from completing the Buzzard development, which converted80% of the related PUDs to developed. The remaining Buzzard PUDs are expectedto be converted to proved over the next few years as we drill additional wellsto keep the platform operating at capacity. PUDs were added by our Ettrickdevelopment, which we expect to convert to producing in 2008.

 

In Yemen, the PUDs are splitrelatively equally between our Masila and East Al Hajr Blocks. These reservesrelate entirely to infill drilling, which we plan to carry-out during 2007 and2008.

 

In the United States, ourPUDS decreased from ongoing development of our Gulf of Mexico deep-water andshelf properties. In 2006, additions principally relate to the Ringo and Tobagodevelopments, which are expected to be producing within the next two years.

 

In other countries, our PUDsincreased by 30 mmboe (25 after royalties), resulting from recognizing provedreserves associated with our Usan development, offshore West Africa.

 

Excluding Long Lake and Usan,we expect to convert about 80% of our PUDs to producing in 2007 and 2008. Usanwill be converted by 2011 when it is expected to come on stream. Long Lake PUDswill be converted over the next 20 years as initial SAGD wells deplete. At thesame time, we expect our ongoing exploration and development activities tocontinue to add new PUDs.

 

**Sy****NCRUDE MINING OPERATIONS**

 

We hold a 7.23% participatinginterest in Syncrude Canada Ltd. (Syncrude). This joint venture was establishedin 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 ahigh-quality, light (32° API), sweet, synthetic crude oil.

 

The Syncrude operationexploits a portion of the Athabasca oil sands deposit that contains bitumen inthe unconsolidated sands of the McMurray formation. Ore bodies are buriedbeneath 50 to 150 feet of over-burden, have bitumen grades ranging from 4 to 14percent by weight and ore bearing sand thickness of 100 to 160 feet.

 

Syncrude’s operations are oneight leases (10, 12, 17, 22, 29, 30, 31, and 34) covering 258,000 hectares, 40km north of Fort McMurray in northeast Alberta.

 

Syncrude mines oil sands atthree mines: Base, North, and Aurora North. These locations are readilyaccessible by public road. Trucks and shovels are used to collect the oil sandsin the open pit mines. The oil sands are transferred for processing using ahydro-transport system.

 

The extraction facilities,which separate bitumen from oil sands, are capable of processing more than 270million tons of oil sands per year and about 160 mmbbls of bitumen per year. Toextract bitumen, the oil sands are mixed with water to form a slurry. Air andchemicals are added to separate bitumen from the sand grains. The process atthe Base Mine uses hot water, steam, and caustic soda to create a slurry, whileat the North Mine and the Aurora North Mine, the oil sands are mixed with warmwater to produce a slurry.

 

The extracted bitumen is fedinto a vacuum distillation tower and three cokers for primary upgrading. Theresulting products are then separated into naphtha, light gas oil, and heavygas-oil streams. These streams are hydrotreated to remove sulphur and nitrogenimpurities to form light, sweet, synthetic crude oil. Sulphur and coke, whichare by-products of the process, are stockpiled for possible future sale.

 

The high quality of Syncrude’ssynthetic crude oil allows it to be sold at prices approximating WTI. In 2006,about 40% of the synthetic crude oil was sold to Edmonton area refineries, andthe remaining 60% was sold to refineries in Eastern Canada and the mid-westernUnited States.

 

Electricity is provided to Syncrudefrom two generating plants on site: a 270 MW plant and an 80 MW plant.

 

 

22

----

 
| Business and  Properties |   | Syncrude  Mining |
|--------------------------|--------|------------------|

 

Since operations started in1978, Syncrude has shipped more than 1.7 billion barrels of synthetic crude oilto Edmonton, Alberta, by Alberta Oil Sands Pipeline Ltd. The pipeline wasexpanded in 2004 to accommodate increased Syncrude production.

 

At December 31, 2006, ourtotal investment in the property, plant and equipment, including surface miningfacilities, transportation equipment, and upgrading facilities, wasapproximately $1.3 billion. Based on development plans, our share of futureexpansion and equipment replacement costs over the next 35 years is expected tobe more than $2.5 billion.

 

In 1999, the Alberta Energyand Utilities Board (AEUB) extended Syncrude’s operating license for the eightoil sands leases through to 2035. The license permits Syncrude to mine oilsands and produce synthetic crude oil from approved development areas on theoil sands leases. The leases are automatically renewable as long as oil sandsoperations 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. Therewere no known commercial operations on these leases prior to the start up ofoperations in 1978.

 

Syncrude pays a royalty tothe Province of Alberta. Subsequent to 1987, this royalty was equal to 50% ofSyncrude’s deemed net profits after deduction of capital expenditures. In 1995,the Province of Alberta announced generic royalty terms for new oil sandsprojects that provide for a royalty rate of 25% on net revenues after all costshave been recovered, subject to a minimum 1% gross royalty. In 1997, theProvince of Alberta and the Syncrude owners agreed to move to the genericroyalty terms when the total of all allowed capital costs incurred afterDecember 31, 1995 equalled $2.8 billion (gross). That total was surpassed atthe end of 2001. In 2006, we realized full recovery of allowed capital costsand, as a result, Syncrude royalties are assessed at 25% of net revenues.

 

In 1999, the AEUB approved anincrease in Syncrude’s production capacity to 465,700 bbls/d. At the end of2001, Syncrude had increased its synthetic crude oil capacity to 246,500 bbls/dwith the development of the Aurora North Mine, which involved extending miningoperations to a new location about 25 miles north of the main Syncrude site.The next expansion of Syncrude came on-stream in 2006, increasing capacity to360,000 bbls/d with the completion of the Stage 3 project. Our share of capitalspending in 2007 is expected to be $50 million.

 

In 2006, Syncrude’sproduction of marketable synthetic crude oil was 258,400 bbls/d. Nexen’s sharewas 18,700 bbls/d before royalties (16,900 after royalties).

 

The following table providessome operating statistics for Syncrude operations:

 
| ** **                                      | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| **Total Mined Volume**(1)                       |       |       |       |       |       |       |       |
| Millions of Tons                                |       | 428        |       | 353        |       | 389        |       |
| Mined Volume to Oil Sands Ratio (1)             |       | 2.2        |       | 2.1        |       | 2.1        |       |
| **Oil  Sands Processed**                        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Millions of Tons                                |       | 192        |       | 169        |       | 188        |       |
| Average Bitumen Grade (weight %)                |       | 11.3       |       | 11.1       |       | 11.1       |       |
| **Bitumen  in Mined Oil Sands**                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Millions of Tons                                |       | 22         |       | 19         |       | 21         |       |
| Average Extraction Recovery (%)                 |       | 90         |       | 89         |       | 87         |       |
| **Bitumen Production**(2)                       |       |       |       |       |       |       |       |
| Millions of Barrels                             |       | 112        |       | 94         |       | 103        |       |
| Average Upgrading Yield (%)                     |       | 85         |       | 85         |       | 86         |       |
| **Gross Synthetic Crude Oil Shipped**(3)        |       |       |       |       |       |       |       |
| Millions of Barrels                             |       | 94         |       | 78         |       | 87         |       |
| **Nexen’s  Share of Marketable Crude Oil** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Millions of Barrels Before Royalties            |       | 6.8        |       | 5.7        |       | 6.3        |       |
| Millions of Barrels After Royalties             |       | 6.2        |       | 5.6        |       | 6.1        |       |

 

----

*Notes:*

*(1)*       *Includes pre-stripping ofmine areas.*

*(2)*       *Bitumen production inbarrels is equal to bitumen in mined oil sands multiplied by the averageextraction recovery and the appropriate conversion factor.*

*(3)*       *Approximately 1.2% of theproduced synthetic crude oil is used internally, primarily for diesel thatfuels the trucks and shovels at Syncrude. The remaining synthetic crude oil issold externally.*

 

23

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| Items 1 and  2 |   | Business and  Properties |   | Energy  Marketing |
|----------------|--------|--------------------------|--------|-------------------|

 

**ENERGYMARKETING**

 

Our marketing group sellsproprietary and third-party natural gas, crude oil, natural gas liquids,ethanol and power in certain regional global markets. We have built a solidstrategic presence within various North American regional markets and extendedour presence into certain global markets as well. We focus on securing accessto transportation, storage and facilities, as well as commodities we produce oracquire. We optimize the margin on our base business by physically andfinancially trading around our access to these physical assets. We also tradefinancially for profit where we see opportunities in the market. We usefinancial and derivative contracts, including futures, forwards, swaps andoptions for hedging and trading purposes.

 

Our marketing strategy is to:

 

**•****     **obtain competitive pricing on the sale of ouroil and gas production;

 

**•****     **provide market intelligence in support of ouroil and gas operations;

 

**•****     **provide superior customer service to producersand consumers;

 

**•****     **capitalize on market opportunities throughphysical and financial trading; and

 

**•    **optimize physical assets or contracts to which we have access.

 

This strategy aligns with ourcorporate focus on extracting full value from our assets and provides us withthe market intelligence needed to deliver current and future oil and gasproduction to market at competitive pricing.

 

**North American Gas Marketing**

 

The marketing and trading ofNorth American natural gas is our marketing group’s largest revenue source. Wefocus on key regional markets where we have a strategic presence—solid customerrelationships, in-depth understanding of the market or established physicalassets. We capture regional opportunities by managing supply, transportationand storage assets for producers and end users. In addition to thefee-for-service income we realize from managing these assets, we generatefurther revenue by:

 

**•****     **capitalizing on location spreads (differencesin prices between locations) using our transportation assets;

 

**•    **capitalizing on time spreads (differences in prices between summer andwinter) using our storage assets; and

 

**•    **financial trading of location and time spreads.

 

We have offices in keyregions including Calgary, Detroit and Houston. Our Calgary office provides avariety of services, including supply, storage, and transportation managementas well as netback pool arrangements and other customer services. Our customersinclude producers and consumers in western Canada as well as consumers(including utilities) in eastern Canada, the north-eastern United States andthe US mid-continent. Our Detroit office works closely with Calgary to provideservices to our customers. Our presence in Houston has established us in theGulf Coast region where we have our own production.

 

We use our access totransportation and storage facilities to optimize returns for ourselves as wellas our customers.

 

In 2003 and 2004, we grew ourasset base by acquiring physical gas purchase and sales contracts, as well asnatural

 

**MarketingOffice Locations**

 

 

24

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| Business and  Properties |   | Energy  Marketing |
|--------------------------|--------|-------------------|

 

gas transportation capacity,on favourable terms. This gives us access to new third party gas supply until2008, pipeline capacity to 2016 and new relationships that have enabled us tonegotiate new gas purchase and sales contracts. In 2006, we continued to growour storage and transportation positions through acquisitions as well asbidding processes. Our position as a physical marketer at multiple deliverypoints in key markets gives us the flexibility to capitalize on time andlocation spreads. With pipeline capacity, we can move gas from producingregions to take advantage of price differences. At the end of 2006, we held 3.3bcf/d of pipeline capacity, primarily between western Canada and the easternUS, and we continue to expand our presence into other markets within NorthAmerica. We also use storage capacity to store typically cheaper summer gas inthe ground until the winter heating season arrives. We had access to 50 bcf ofnatural gas storage facilities at the end of the year.

 

**We use our access to transportation and storage facilities tooptimize returns, capitalizing on location and time spreads.**

 

In addition to transportationand storage assets, we hold financial contracts that enable us to captureprofits around time and location spreads. The risks we assume on thesecontracts are based on fundamental analysis and knowledge of regional markets.The risk is managed proactively by our product group teams and monitored by ourrisk group, with regular reporting to management and the board of directors.

 

**InternationalCrude Oil Marketing**

 

Our crude oil businessfocuses on marketing physical crude oil to end-use refiners. The crude oilgroup markets our own production and more than 500,000 bbls/d of third-partyfield production to refiners from producing regions where we operate. Inaddition to physical marketing, we take advantage of quality differentials andtime spreads.

 

Our North American operationsfocus on key regions supported by our offices in Calgary, Houston and Denver.In western Canada, our producer services group concentrates on the procurementof a diversified supply base, while our trading team seeks to optimize the mixfor sale to refiners. Traditionally, the Chicago and Denver areas have been keymarkets for our western Canadian crude, however, we continue to expand ourpresence into the US Gulf Coast. Our deep-water Gulf of Mexico crude oilproduction has given us the opportunity to expand our presence in that marketthrough our Houston office. At the end of 2006, we had access to 1.7 mmbbls ofstorage and over the course of the year, moved approximately 705 mbbls per day.

 

In the last two years, weacquired two North American natural gas liquid (NGL) and ethanol businessesthat focus on buying and selling NGLs as well as diesel, ethanol and naturalgasoline. These businesses acquire and move NGLs into the US midwest and GulfCoast from Canada, as well as providing denaturant for ethanol production andthe marketing of finished ethanol in the US. At the end of 2006, we had accessto 550 mbbls of storage and over the course of the year, moved approximately 25mbbls per day of product.

 

Internationally, we focus onthe 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 owncrude, we market production for our partners and third parties in the Yemenregion. By locating our international crude oil marketing office in Singapore,we are well positioned to serve both the producing region and the Asian refiningmarket. We established an office in London, United Kingdom to maximize thevalue of our North Sea production. With Buzzard crude on stream in early 2007,we expect to increase our presence in various global markets, ensuring wemaximize the value of this production.

 

Our crude oil marketing groupalso holds financial contracts intended to capture trading profits around time,quality and location spreads. Like gas marketing, the risks assumed are basedon fundamental analysis and proprietary knowledge of regional markets, and aremonitored by our risk group.

 

**NorthAmerican Power Marketing**

 

Our power marketing group isresponsible for optimizing the use of our 50% interest in a 100 MW gas-fired,combined-cycle power generation facility at Balzac, Alberta, as well as ourrecently completed 70 MW Soderglen wind power operation in southern Alberta. Wealso market power to larger commercial, industrial and municipal clients inAlberta. With the 2005 acquisition of a commercial/industrial marketing businessin Alberta, we became the largest supplier of power to the commercial andindustrial sectors in the province. Our Balzac facility began operations in2001 and Soderglen in October 2006. We expect to increase our power generationcapacity with a 170 MW co-generation facility at Long Lake in 2007. We have a50% interest in this project.

 

25

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| Items 1 and  2 |   | Business and  Properties |   | Chemicals |
|----------------|--------|--------------------------|--------|-----------|

 

**European Gasand Power Marketing**

 

In 2006, we acquired aUK-based European gas and power marketing business that focuses on UK gas andpower as well as German power. In 2007, we expect to increase our presence inboth the UK and continental Europe gas and power markets.

 

**CHEMICALS**

 

In 2005, we monetized part ofour chemicals business through an initial public offering of the Canexus IncomeFund. We have retained a 61.4% interest in our chemicals business, and wecontinue to fully consolidate chemicals in our Consolidated FinancialStatements.

 

Our chemicals businessmanufactures sodium chlorate and chlor-alkali products (chlorine, caustic sodaand muriatic acid) in Canada and Brazil. This production is sold in North andSouth America, with some sodium chlorate distributed in Asia. Our manufacturingfacilities are modern, reliable and strategically located to capitalize oncompetitive power costs or transportation infrastructure to minimize productionand delivery costs. This enables us to have reliable supplies and low costs—keyfactors for marketing bleaching chemicals.

 

Electricity is the mostsignificant operating cost in producing sodium chlorate and chlor-alkaliproducts, making up over half our cash costs. Therefore, our current facilitiesare strategically located to take advantage of economic power sources. Oursecond highest cost is transportation. The proximity of our manufacturingplants to major customers and competitive freight rates minimize ourtransportation costs. Labour is also a significant manufacturing cost.Approximately 50% of our workforce is unionized with collective agreements inplace at all of our unionized plants.

 

To grow value in ourchemicals business, we focus on reducing our costs while maintaining marketshare, building a sustainable North American customer base and capturing newoffshore opportunities.

 

 

Average Annual ProductionCapacity

 
| **(short tons)**     | ** ** | **2006**    | ** ** | **2005**    | ** ** | **2004**    | ** ** |
|----------------------|------------|-------------|------------|-------------|------------|-------------|------------|
| **Sodium  Chlorate** | ** ** | ** **  | ** ** | ** **  | ** ** | ** **  | ** ** |
| North America        |       | 446,208     |       | 446,208     |       | 446,617     |       |
| Brazil               |       | 68,563      |       | 68,563      |       | 68,563      |       |
| **Total**            | ** ** | **514,771** | ** ** | **514,771** | ** ** | **515,180** | ** ** |
| **Chlor-alkali**     | ** ** | ** **  | ** ** | ** **  | ** ** | ** **  | ** ** |
| North America        |       | 356,002     |       | 356,002     |       | 356,002     |       |
| Brazil               |       | 109,430     |       | 109,430     |       | 109,430     |       |
| **Total**            | ** ** | **465,432** | ** ** | **465,432** | ** ** | **465,432** | ** ** |

 

**NorthAmerica**

 

The North American pulp andpaper industry consumes approximately 95% of the continent’s sodium chlorate production.We market our sodium chlorate production to numerous pulp and paper mills undermulti-year contracts that contain price and volume adjustment provisions. Approximately32% of this production is sold in Canada, 61% in the US, and the rest ismarketed offshore.

 

We are the third-largestmanufacturer of sodium chlorate in North America with four Canadian facilities:Nanaimo, British Columbia; Bruderheim, Alberta; Brandon, Manitoba; andBeauharnois, Quebec.

 

26

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| Business and  Properties | Regulations |
|--------------------------|-------------|

 

In October 2004, we completedan expansion of our plant in Brandon, Manitoba increasing capacity to 260,000tonnes per year. This expansion replaced higher-cost capacity idled in 2002 atTaft, Louisiana. Brandon is the world’s largest sodium chlorate facility andhas one of the lowest cost structures in the industry, significantly enhancingour competitive position in North America. In late 2006, we began anotherexpansion of our plant in Brandon which is expected to increase capacity by32,300 tonnes per year, early in 2008.

 

Our chlor-alkali facility atNorth Vancouver, British Columbia, manufactures caustic soda, chlorine andmuriatic acid. Almost all of our caustic soda is consumed by local pulp andpaper mills, while our chlorine is sold to various customers in the polyvinylchloride, water purification and petrochemicals industries, primarily in theUnited States.

 

**Brazil**

 

We entered Brazil in 1999 byacquiring a sodium chlorate plant and a chlor-alkali plant from AracruzCellulose S.A. (Aracruz), the leading manufacturer of pulp in Brazil. Themajority of the sodium chlorate production is sold to Aracruz under a long-termsales agreement that expires in 2024. This agreement had an initial six-yeartake-or-pay component that ended in 2005. Most of the chlorine and about 20% ofthe sodium chlorate production is sold in the merchant market undershorter-term contractual arrangements. In 2002, we completed an expansion atboth facilities to meet Aracruz’s growing needs. The majority of ourelectricity needs are supplied by a long-term supply contract in Brazil.

 

**GOVERNMENTREGULATIONS**

 

Our operations are subject tovarious levels of government controls and regulations in the countries where weoperate. These laws and regulations include matters relating to land tenure,drilling, production practices, environmental protection, marketing and pricingpolicies, royalties, various taxes and levies including income tax, and foreigntrade and investment, that are subject to change from time to time. Currentlegislation is generally a matter of public record, and we are unable topredict what additional legislation or amendments may be proposed that willaffect our operations or when any such proposals, if enacted, might become effective.We participate in many industry and professional associations and monitor theprogress of proposed legislation and regulatory amendments.

 

**ENVIRONMENTALREGULATIONS**

 

Our oil and gas, Syncrude andchemical operations are subject to government laws and regulations designed toprotect and regulate the discharge of materials into the environment incountries where we operate. We believe our operations comply in all materialrespects with applicable environmental laws. To reduce our exposure, we applyindustry standards, codes and best practices to meet or exceed these laws andregulations. Occasionally, we may conduct activities in countries whereenvironmental regulatory frameworks are in various stages of evolution. Whereregulations are lacking, we observe Canadian standards where applicable, aswell as internationally accepted industry environmental management practices.

 

We have an active safety,environment and social responsibility group that ensures our worldwideoperations are conducted in a safe, ethical and socially responsible manner. Wehave developed policies for continuing compliance with environmental laws andregulations in the countries in which we operate.

 

**EnvironmentalProvisions and Expenditures**

 

The ultimate financial impactof environmental laws and regulations is not clearly known and cannot bereasonably estimated as new standards continue to evolve in the countries inwhich we operate. We estimate our future environmental costs based on pastexperience and current regulations. At December 31, 2006, $704 million ($1,770million, undiscounted) has been provided in our Consolidated FinancialStatements for asset retirement obligations. In 2006, we increased ourretirement obligations for future dismantlement and site restoration by $75 millionprimarily from the development of the Buzzard field in the North Sea.

 

In 2006, our capitalexpenditures for environmental-related matters, including environment controlfacilities, were approximately $44 million. Our operating expenditures for environmental-relatedmatters were approximately $6 million. In 2007, we estimate these expendituresto be approximately $21 million.

 

**EMPLO****y****EES**

 

We had 3,687 employees onDecember 31, 2006, of which 266 were employed under collective bargainingschemes. Information on our executive officers is presented in Item 10 of thisreport.

 

27

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| Items 1 and  2 |   | Business and  Properties |   | Risk Factors |
|----------------|--------|--------------------------|--------|--------------|

 

**ITEM 1A. RISK FACTORS**

 

**RISK FACTORS**

 

Our operations are exposed tovarious risks, some of which are common to others in our industry and some ofwhich are unique to our operations.

 

**Competitiveforces may limit our access to natural resources, and create labour andequipment shortages.**

 

The oil and gas industry ishighly competitive, particularly in the following areas:

 

•     searching for and developing new sources of crude oil and natural gasreserves;

 

•     constructing and operating crude oil and natural gas pipelines andfacilities; and

 

•     transporting and marketing crude oil, natural gas and other petroleumproducts.

 

Our competitors includenational oil companies, major integrated oil and gas companies and variousother independent oil and gas companies. The petroleum industry also competeswith other industries in supplying energy, fuel and related products tocustomers. The pulp and paper chemicals market is also highly competitive. Keysuccess factors in each of these markets are price, product quality, andlogistics and reliability of supply.

 

Competitive forces may resultin shortages of prospects to drill, shortages of labour and equipment to carryout exploration, development or operating activities, and shortages ofinfrastructure to produce and transport production. It may also result in anoversupply of crude oil and natural gas. Each of these factors could have anegative impact on costs and prices and, therefore, our financial results.

 

**Exploration,development and production risks and natural disasters could result inliability exposure or loss of production or reserves.**

 

Acquiring, developing andexploring for oil and natural gas involves many risks. These include:

 

•     encountering unexpected formations or pressures;

 

•     premature declines of reservoirs;

 

•     blow-outs, well bore collapse, equipment failures and other accidents;

 

•     craterings and sour gas releases;

 

•     uncontrollable flows of oil, natural gas or well fluids; and

 

•     environmental risks.

 

We operate two facilitiesthat are located in close proximity to populated areas, and each processesmaterials of potential harm to the local populations. At Balzac, just north ofCalgary, we operate a gas plant that has been producing sour gas for over 40years. In North Vancouver, we operate, indirectly through ownership in CanexusLimited Partnership a chlor-alkali plant that has been producing chlorine foralmost 50 years.

 

We may not be fully insuredagainst all of these risks. Losses resulting from the occurrence of these risksmay have a material impact on our financial results.

 

**Our offshoreoperations are subject to unique operating risks.**

 

Offshore operations aresubject 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 interruptproduction.

 

Our operations in the Gulf ofMexico have been suspended, from time to time, due to hurricanes or tropicalstorms. In the last five years, we have had a few instances where productionwas suspended for an extended period of time and damage to facilities wasincurred. In late August 2005, we shut-in all of our production in the Gulf ofMexico, consisting of approximately 50,000 boe/d before royalties, and ceaseddrilling operations in anticipation of Hurricane Katrina. Production wasrestored in early September for most of our fields. In late September 2005, weagain shut-in all of our production and ceased drilling operations inanticipation of Hurricane Rita. While we incurred minimal damage to most of ourfacilities, extensive damage was incurred to the third party infrastructurenecessary to accommodate our production. As a result, our 2005 annualizedproduction was reduced by approximately 6,000 boe/d. These storms also resultedin damage to rigs under contract with us, which increased our costs and delayedour drilling schedule. In 2002, our facilities at Eugene Island 295 weredamaged during Hurricane Lili. Production from this field was suspended forabout four months while temporary production facilities were put in place. Duringthis period, production volumes were reduced by approximately 2,500 boe/d.Production was restored at a reduced rate through temporary facilities forapproximately six months while installation of new permanent facilities wascompleted. It is estimated that volumes were reduced by approximately 1,800boe/d during this period. In each of these instances, there was no significantfinancial impact after business interruption and property insurance claims.

 

Our exploration anddevelopment capital programs in our offshore operations are exposed to risk ofdelay or additional

 

28

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| Business and  Properties |   | Risk Factors |
|--------------------------|--------|--------------|

 

costs by limited access todrilling rigs. Recent industry pressure in the Gulf of Mexico following stormdamage sustained in the 2005 hurricane season has reduced the availability ofdrilling rigs. Our profitability and success at finding reserves may be reducedby extended delays and/or higher costs of obtaining drilling rigs.

 

**Withoutreserve additions, our reserves and production will decline over time and werequire capital to produce remaining reserves.**

 

Our future crude oil andnatural gas reserves and production, and therefore our operating cash flows andresults of operations, are highly dependent upon our success in exploiting ourcurrent reserve base and acquiring or discovering additional reserves. Withoutreserve additions through exploration, development or acquisitions, ourreserves and production will decline over time as reserves are produced. Thebusiness of exploring for, developing or acquiring reserves is capitalintensive. To the extent cash flows from operations are insufficient andexternal sources of capital become limited or unavailable, our ability to makethe necessary capital investments to maintain and expand our oil and naturalgas reserves will be impaired.

 

Over the past three years, weexperienced net negative revisions of 19 million boe to our proved reserves(before royalties). This includes net negative revisions of 25 million boe,representing about 2% of worldwide proved reserves (including Syncrude),related to technical revisions primarily on our producing properties, partiallyoffset by 6 million boe of net positive economic revisions related to changesin year-end prices and costs. In Yemen, negative revisions of 27 million boeoccurred largely in 2004 and resulted primarily from lower-than-expectedproduction performance, drilling results and updated geological mapping. In theUnited States, negative revisions of 29 million boe occurred largely in 2005and 2006 and resulted primarily from lower-than-expected production performanceat our deep-water Aspen property and at various properties on the shelf. Thesenegative revisions were somewhat offset by positive revisions of 37 million boein our Buzzard field due to updated geological mapping.

 

Under SEC rules, we mustrecognize our oil sands as bitumen reserves rather than the upgraded premiumsynthetic crude oil that we expect to produce from Long Lake. As a result, weexpect price-related revisions, both positive and negative, to occur in thefuture as the economic producibility of our bitumen and heavy oil reserves aresensitive to year-end prices. In particular, since we recognize our oil sandsas bitumen reserves and they are related to one project, all or none of thereserves will likely be considered economic depending on the year-end pricesfor bitumen, diluent and natural gas, even though the Long Lake integratedproject has virtually no exposure to these factors.

 

**Our provedreserves include undeveloped properties that require additional capital tobring them on-stream.**

 

Under SEC rules, thedefinition of proved undeveloped reserves includes reserves that are expectedto be recovered from new wells on undrilled acreage or from existing wellswhere a relatively major expenditure is still required before such wells maybegin production. Such reserves may be recognized when plans are in place tomake the required investments to convert these undeveloped reserves toproducing. Circumstances such as a sustained decline in commodity prices orpoorer than expected results from initial activities could cause a change inthe investment or development plans which could result in a material change inour reserves estimates.

 

During the past three years,our total proved undeveloped reserves before royalties have increased from 124mmboe to 315 mmboe (87 mmboe to 275 mmboe after royalties). As a result, ourproved undeveloped reserves have increased from 23% to 43% of our provedreserves excluding Syncrude (22% to 43% after royalties). Proved undevelopedreserves increased primarily at our Long Lake oil sands project and variousother worldwide development projects, partially offset by the completion of theBuzzard development and ongoing development activities elsewhere.

 

**Our heavyoil production is more expensive and yields lower prices than light oil andgas.**

 

Heavy oil is characterized byhigh specific gravity or weight and high viscosity or resistance to flow.Because of these features, heavy oil is more difficult and expensive toextract, transport and refine than other types of oil. Heavy oil also yields alower price relative to light oil and gas, as a smaller percentage ofhigh-value petroleum products can be refined from heavy oil. As a result, ourheavy oil operations are exposed to the following risks:

 

•     additional costs may be incurred to purchase diluent to transport heavyoil;

 

•     there could be a shortfall in the supply of diluent which may cause itsprice to increase; and

 

•      themarket for heavy oil is more limited than for light oil making it moresusceptible to supply and demand fundamentals which may cause the price todecline.

 

29

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Any one or combination ofthese factors could cause some of our heavy oil properties to become uneconomicto produce and/or result in negative reserve revisions.

 

**Our LongLake project faces additional risks compared to conventional oil and gasproduction.**

 

Our Long Lake project isplanned as a fully integrated production, upgrading and co-generation facility.We intend to use Steam Assisted Gravity Drainage (SAGD) technology to recoverbitumen from oil sands. As designed, the bitumen will be partially upgradedusing the proprietary OrCrudeTM process, followed by conventional hydrocrackingto produce a sweet, premium synthetic crude oil. The OrCrudeTM process alsoyields liquid asphaltines that will be gasified into a syngas. This syngas willbe used as a fuel source for the SAGD process, a source of hydrogen for use inthe upgrading process, and to generate electricity through a co-generationfacility.

 

We have a 50% workinginterest 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 operatingcosts to produce and upgrade bitumen, the payout period for the project islonger and the economic return is lower than a conventional light oil projectwith an equal volume of reserves.

 

In addition to the risksassociated with heavy oil production stated above, risks associated with ourLong Lake oil sands project include the following:

 

**UncertainTimeline and Cost of the Project**

 

The Long Lake project iscurrently in the construction stage. There is a risk that actual costs toconstruct and develop may be higher than expected or that the project may notbe completed on time or at all due to many factors, including:

 

•      constructionperformance falling below expected levels of output or efficiency;

 

•      labourdisputes, disruptions or declines in productivity;

 

•      increasesin materials or labour costs;

 

•      inabilityto attract sufficient numbers of qualified workers;

 

•      designerrors;

 

•      contractoror operator errors;

 

•      non-performanceby third-party contractors;

 

•      changesin project scope;

 

•      delaysin obtaining, or conditions imposed by, regulatory approvals;

 

•      breakdownor failure of equipment or processes;

 

•      violationof permit requirements;

 

•      catastrophicevents such as fires, earthquakes, storms or explosions; and

 

•      disruptionin the supply of energy.

 

The capitalcost 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 wellpad consisting of 13 well-pairs to increase certainty and reliability ofbitumen production at the commencement of upgrader operations at a cost of $98million (gross). In early 2006, we further modified the project design byadding steam generation capacity and soot handling equipment at a cost of $360million (gross). These scope changes increased the estimated project cost to$3.8 billion. High activity in the oil sands region is placing ongoing pressureon the costs of labour and services. In addition, labour productivity has beenlower than anticipated, requiring a larger workforce to maintain progress.After a review of all trends, the projected cost of Long Lake has beenincreased to $4.6 billion (gross).

 

**Applicationof Relatively New SAGD Bitumen Recovery Process**

 

SAGD has been used in westernCanada to increase recoveries from conventional heavy oil reservoirs for over adecade. However, application of SAGD to the in-situ recovery of bitumen fromoil sands is relatively new. Some of the SAGD oil sands applications to datehave been pilot projects, however several commercial SAGD projects have been insteady state operation for over five years.

 

Our estimates for performanceand recoverable volumes for the Long Lake project are based primarily on ourthree well-pair SAGD pilot and industry performance from SAGD operations inlike reservoirs in the McMurray formation in the Athabasca oil sands. Usingthis data, our assumptions included average well-pair productivity of 900bbls/d of bitumen and a long-term steam-to-oil ratio of 3.0. There can be noassurance that our SAGD operation will produce bitumen at the expected levelsor steam-to-oil ratio. If the assumed production rates or steam-to-oil ratioare not achieved, we might have to drill additional wells to maintain optimalproduction levels, construct additional steam generating capacity, purchasenatural gas for additional steam generation, and/or make short-term bitumenpurchases. These could have a significant adverse impact on the futureactivities and economic return of the Long Lake project.

 

**Applicationof New Bitumen Upgrading Process**

 

The proprietary OrCrudeTMprocess we are using to upgrade raw bitumen to synthetic crude will be thefirst commercial application of the process although we have operated

 

30

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it in a 500 bbl/ddemonstration plant. There can be no assurance that the commercial upgraderbeing constructed at Long Lake will achieve the same or similar results as thedemonstration plant or the results which are forecast. If we are unable toupgrade the bitumen for any reason we may decide to sell it as bitumen withoutupgrading it, which would expose us to the following risks:

 

•     the market for bitumen is limited;

 

•     additional costs would be incurred to purchase diluent for blending andtransporting bitumen;

 

•     there could be a shortfall in the supply of diluent which may cause itsprice to increase;

 

•     the market price for bitumen is relatively low reflecting its qualitydifferential;

 

•     the market price for bitumen fluctuates over the course of the year; and

 

•     additional costs would be incurred to purchase natural gas for use ingenerating steam for the SAGD process since we would not be producing syngasfrom the upgrading process.

 

These factors could have asignificant adverse impact on the future activities and economic returns of theLong Lake project.

 

If any of these factorsarise, our operating costs would increase and our revenues would decrease fromthose we have assumed. This would cause a material decrease in expectedearnings from the project and the project may not be profitable under theseconditions.

 

**Dependenceon OPTI Canada Inc.**

 

We are undertaking the LongLake project jointly with OPTI Canada Inc. (OPTI) pursuant to a joint ventureagreement governing the construction, ownership and joint operation of theproject. The agreement provides for the creation of a management committee thatis responsible for the supervision and direction of the management andoperation of the project, the supervision and control of the operators and allother matters relating to the development of the project. If our interest inany element of the project falls below 25%, OPTI may be able to make decisionsrespecting that element without our input, which may adversely affect ouroperations.

 

**Dependenceupon Proprietary Technology**

 

The success of the projectand our investment depends to a significant extent on the proprietarytechnology of OPTI and proprietary technology of third parties that has been,or is required to be, licensed by OPTI. OPTI currently relies on intellectualproperty rights and other contractual or proprietary rights, including (withoutlimitation) copyright, trademark laws, trade secrets, confidentialityprocedures, contractual provisions, licenses and patents, to secure the rightsto utilize its proprietary technology and the proprietary technology of thirdparties. OPTI may have to engage in litigation in order to protect the validityof its patents or other intellectual property rights, or to determine thevalidity or scope of the patents or proprietary rights of third parties. Thiskind of litigation can be time-consuming and expensive, regardless of whetheror not OPTI is successful. The process of seeking patent protection can itselfbe long and expensive, and there can be no assurance that any currently pendingor future patent applications of OPTI or such third parties will actuallyresult in issued patents, or that, even if patents are issued, they will be ofsufficient scope or strength to provide meaningful protection or any commercialadvantage to OPTI. Furthermore, others may develop technologies that aresimilar or superior to the technology of OPTI or such third parties or designaround the patents owned by OPTI and/or such third parties. There is also arisk that OPTI may not be able to enter into licensing arrangements with thirdparties for the additional technologies required for the possible furtherexpansion of the Long Lake upgrader.

 

**OperationalHazards**

 

The operation of the projectwill be subject to the customary hazards of recovering, transporting andprocessing hydrocarbons, such as fires, explosions, gaseous leaks, migration ofharmful substances, blowouts and oil spills. A casualty occurrence might resultin the loss of equipment or life, as well as injury or property damage. We maynot carry insurance with respect to all potential casualty occurrences anddisruptions. It cannot be assured that our insurance will be sufficient tocover any such casualty occurrences or disruptions. The project could beinterrupted by natural disasters or other events beyond our control. Losses andliabilities arising from uninsured or under-insured events could have amaterial adverse effect on the project and on our business, financial conditionand results of operations.

 

Recovering bitumen from oilsands and upgrading the recovered bitumen into synthetic crude oil and otherproducts involve particular risks and uncertainties. The project is susceptibleto loss of production, slowdowns or restrictions on its ability to producehigher value products due to the interdependence of its component systems.Severe climatic conditions can cause reduced production and in some situationsresult in higher costs. SAGD bitumen recovery facilities and development

 

31

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and expansion of productioncan entail significant capital outlays. The costs associated with syntheticcrude oil production are largely fixed and, as a result, operating costs perunit are largely dependent on levels of production.

 

The Long Lake SAGD operationand upgrader will process large volumes of hydrocarbons at high pressure andtemperatures and will handle large volumes of high-pressure steam. Equipmentfailures could result in damage to the project’s facilities and liability tothird parties against which we may not be able to fully insure or may elect notto insure because of high premium costs or for other reasons.

 

Certain components of theLong Lake project will produce sour gas, which is gas containing hydrogensulphide. Sour gas is a colourless, corrosive gas that is toxic at relativelylow levels to plants and animals, including humans. The project will includeintegrated facilities for handling and treating the sour gas, including the useof gas sweetening units, sulphur recovery systems and emergency flaringsystems. Failures or leaks from these systems or other exposure to sour gasproduced as part of the project could result in damage to other equipment,liability to third parties, adverse effect to humans, animals and theenvironment, or the shut down of operations.

 

The Long Lake project willproduce carbon dioxide emissions. Carbon dioxide is a greenhouse gas that willbe regulated by the Kyoto Protocol, which may come into effect in Canada. Riskfactors relating to environmental regulation are provided separately herein.

 

**AboriginalClaims**

 

Aboriginal peoples haveclaimed 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 regionalmunicipality of Wood Buffalo (which includes the city of Fort McMurray,Alberta) claiming, among other things, aboriginal title to large areas of landssurrounding Fort McMurray, including the lands on which the project and most ofthe other oil sands operations in Alberta are located. Such claims, ifsuccessful, could have a significant adverse effect on the project and on us.

 

**Competition**

 

The Canadian andinternational petroleum industry is highly competitive in all aspects,including the exploration for, and the development of, new sources of supply,the acquisition of petroleum interests and the distribution and marketing ofpetroleum products. The Long Lake project competes with other producers ofsynthetic crude oil blends and other producers of conventional crude oil. Someof the conventional producers have lower operating costs than the project isanticipated to have. The petroleum industry also competes with other industriesin supplying energy, fuel and related products to consumers.

 

A number of companies, otherthan OPTI and us, have announced plans to enter the oil sands business andbegin production of synthetic crude oil, or expand existing operations.Expansion of existing operations and development of new projects couldmaterially increase the supply of synthetic crude oil and other competing crudeoil products in the marketplace. Depending on the levels of future demand,increased supplies could have a negative impact on prices.

 

**Some of ourproduction is concentrated in a few producing assets.**

 

A significant portion of ourproduction is generated from highly productive individual wells or centralproduction facilities. Examples include:

 

•     central processing facilities, oil pipelines, and export terminal at ourtwo Yemen operations;

 

•     Gunnison SPAR production platform in the Gulf of Mexico;

 

•     highly productive Aspen wells tied-in to a third-party processingfacility in the Gulf of Mexico;

 

•     upgrading facilities at Syncrude in the Athabasca oil sands; and

 

•     Scott and Buzzard production platforms in the North Sea.

 

As significant production isgenerated from each of these assets, any single event causing an interruptionto any one of these operations could result in the loss of production.

 

**We may notachieve commercial production rates in our coalbed methane operations.**

 

Coalbed methane (CBM) iscommonly referred to as an unconventional form of natural gas because it isprimarily stored through adsorption by the coal itself rather than in the porespace of the rock like most conventional gas. The gas is released in responseto a drop in pressure in the coal. If the coal is water saturated, watergenerally needs to be extracted to reduce the pressure and allow gas productionto occur. CBM wells typically have lower producing rates and reserves per wellthan conventional gas wells, although this varies by area. Regulatory approvalis required to drill more than one well per section. As a result, the timing ofdrilling programs and land development can be uncertain.

 

32

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The Mannville coals in theFort Assiniboine region of Alberta are generally deeper than other commercialCBM projects in the Horseshoe Canyon and are water saturated. A significantperiod of time may be required to sufficiently dewater the coals to determineif commercial production is feasible. As a result, we may have to investsignificant capital in CBM assets before they achieve commercial rates ofproduction. The wells may never achieve commercial rates of production as thereare no other commercially proven Mannville CBM projects in operation.

 

CBM projects in some areas ofthe United States have had negative public reaction due to certain waterdisposal practices. In Canada, as in the United States, water disposalpractices are regulated to ensure public safety and water conservation.Nevertheless, negative public perception around CBM production could impede ouraccess to the resource.

 

**We havesignificant upfront commitments related to our current development projects.**

 

We have significantcommitments in connection with various development activities currentlyunderway. At Long Lake, we essentially completed module and site constructionof the SAGD facilities in 2006 and steam injection is expected to commence atthe end of first quarter of 2007. With respect to the Long Lake upgrader,module fabrication is largely complete and over 95% of the modules are on site.Construction of the upgrader is approximately 80% complete and start up isscheduled for late 2007. At Long Lake, we are exposed to the possibility ofcost overruns and/or delays in the commencement of commercial production, whichmay be significant. Specific risk factors relating to our Long Lake oil sandsproject are provided separately.

 

**We operatein countries with political and economic risk.**

 

We operate in numerouscountries, some of which may be considered politically and economicallyunstable. Our operations and related assets are subject to the risks of actionsby governmental authorities, insurgent groups or terrorists which may havematerial adverse financial consequences. For instance, on September 15, 2006our oil export terminal in Yemen was assaulted by two explosive laden vehicles.One worker was killed and two others received minor injuries. The ability ofthe terminal to receive and export oil was not affected and operations arecontinuing as normal. There can be no assurance that we will be successful inprotecting ourselves against these risks and the related financialconsequences.

 

**We may beaffected by changes in government rules and regulations.**

 

Our operations are subject tovarious levels of government controls and regulations in the countries where weoperate. These laws and regulations include matters relating to land tenure,drilling, production practices, environmental protection, marketing and pricingpolicies, royalties, various taxes and levies including income tax, and foreigntrade and investment, that are subject to change from time to time. For example,the US government has proposed increases to the royalty rates for newdeep-water Gulf of Mexico leases and has proposed amendments to deep-waterleases issued in 1998 and 1999. Current legislation is generally a matter ofpublic record, and we are unable to predict what additional legislation oramendments may be proposed that will affect our operations or when any suchproposals, if enacted, might become effective. Changes in governmentregulations could have an adverse effect on our results of operations andfinancial condition.

 

**Ouroperations are exposed to environmental liabilities.**

 

Environmental liabilitiesinherent in the oil and gas and chemicals industries are becoming increasinglysensitive as related laws and regulations become more stringent worldwide. Manyof these laws and regulations require us to remove or remedy the effect of ouractivities on the environment at present and former operating sites, includingdismantling production facilities and remediating damage caused by the disposalor release of specified substances. This could have an adverse financialconsequence.

 

Certain operations requirethe use of fresh and saline water. We currently use sub-surface sources ofwater for these operations. Additional costs may be incurred if allocationlimits are placed on our saline water usage, if our sub-surface fresh waterneeds exceed allocated amounts or if existing subsurface fresh waterallocations are reduced.

 

**Ouroperations could be subject to changes in regulations related to climatechange.**

 

The Kyoto Protocol came intoforce on February 16, 2005. Canada ratified the Kyoto Protocol in December2002. In 1997, Canada committed to an emission reduction of 6% below 1990levels during the First Commitment period (2008 to 2012). Since that time, theCanadian federal government and various provincial governments have grappledwith the issue of climate change and a number of proposals have come and gone.Bill C-30 (Canada’s Clean Air Act) has been sent to

 

33

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| Items 1 and  2 |   | Business and  Properties |   | Legal  Proceedings |
|----------------|--------|--------------------------|--------|--------------------|

 

a special parliamentarycommittee that intends to report back to parliament by the end of March 2007.This Bill contains proposals to deal with criteria air contaminants (CACs) andgreenhouse gases (GHGs) and outlines proposed changes to the CanadianEnvironmental Protection Act 1999, the Energy Efficiency Act and the MotorVehicle Fuel Conservation Standards Act. The proposals seek to applyintensity-based targets for GHGs and absolute caps on CACs in the period up to2020—2025, ultimately leading to absolute caps on GHGs. It is unclear if andwhen Bill C-30 will become law.

 

Any required reductions inthe GHGs emitted for our operations could result in increases in our capital oroperating expense, or reduced operating rates, especially those related to theLong Lake project, which could have an adverse effect on our results ofoperations and financial condition.

 

**Our energymarketing operations expose us to the risk of trading losses and liquidityconstraints.**

 

Our trading operations exposeus to the risk of financial losses from various sources. The markets in whichwe trade are susceptible to significant changes, which could expose us to therisk of material financial losses. Significant changes in the commodities andfinancial markets could require us to provide additional liquidity to supportour marketing operations. Adverse credit related events such as a downgrade ofour credit rating to non-investment grade could require additional collateralto be placed with counter-parties. Any significant loss of liquidity may resultin delays and/or cancellation of our development plans.

 

**Use ofmarine transportation may expose us to the risk of financial loss andreputational damage.**

 

From time to time, we maychoose to charter marine vessels for the transportation of crude oil. This mayexpose us to the risk of financial loss and reputational damage in the event ofoil spills.

 

**ITEM 1B. UNRESOLVED STAFF COMMENTS**

 

There are no unresolved staffcomments with the SEC that have been outstanding for more than 180 days beforeDecember 31, 2006.

 

**ITEM 3. LEGAL PROCEE****d****INGS**

 

There are a number oflawsuits and claims pending against Nexen, the ultimate results of which cannotbe ascertained at this time. Management is of the opinion that any amountsassessed against us would not have a material adverse effect on ourconsolidated financial position or results of operations. We believe we havemade adequate provisions for such lawsuits and claims.

 

Certain of our US oil and gasoperations have received, over the years, notices and demands from the USEnvironmental Protection Agency (EPA), state environmental agencies, andcertain third parties with respect to certain sites seeking to require investigationand remediation under federal or state environmental statutes. In addition,notices, demands, and lawsuits have been received for certain sites related tohistorical operations and activities in the US for which, although noassurances can be made, we believe that certain assumption and indemnificationagreements protect our US operations from any present or future materialliabilities that may arise from these particular sites.

 

In June 2003, a subsidiary ofOccidental Petroleum Corporation (Occidental) initiated an arbitration againstus at the International Court of Arbitration in the International Chamber ofCommerce (ICC Court) regarding an Area of Mutual Interest agreement relating tocertain portions of Block 51 in the Republic of Yemen. In April 2006, the ICCCourt concluded that we breached this agreement and as a result, Occidental wasentitled to monetary damages. In late 2006, we agreed to settle the arbitrationwith Occidental for US$135 million. This amount was accrued and included in otherexpenses in our Consolidated Statement of Income during 2006. No furtheramounts are expected to be payable under the settlement.

 

On September 5, 2005, therewas a gas release on the Scott Platform in the North Sea. No-one was harmed asa result of the incident, but Nexen was fined £400,000 under the UK Health andSafety at Work Act, 1974 and the Offshore Installation (Prevention of Fire andExplosion, and Emergency Response) Regulations, 1995.

 

**ITEM 4. SUBMISSION OF MATTERS TO AVOTE OF SECURIT****y h****OL****d****ERS**

 

No matters were submitted toa vote of Nexen’s security holders during the fourth quarter of 2006.

 

34

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| Business and  Properties |   | Market Data |
|--------------------------|--------|-------------|

 

**PART II**

 

**ITEM 5. MARKET FOR ThE REGISTRANT’S COMMON EqUITy, RELATEd STOCKhOLdER****M****ATTERS ANdISSUER PURChASES OF EqUITy SECURITIES**

 

Nexen’s common shares aretraded on the Toronto Stock Exchange (TSX) and the New York Stock Exchange(NYSE) under the symbol NXY.

 

On December 31, 2006, therewere 1,454 registered holders of common shares and 262,513,206 common sharesoutstanding. The number of registered holders of common shares is calculatedexcluding individual participants in securities positions listings. During theyear, we made no purchases of our own equity securities.

 

Trading Range of Nexen’sCommon Shares

 
| ** **     | ** ** | **TSX****(Cdn$)** | ** ** | **NYSE****(US$)** | ** ** |
|----------------|------------|-------------------|------------|-------------------|------------|
| **($/share)**  | ** ** | **High**          | ** ** | **Low**           | ** ** | **High** | ** ** | **Low** | ** ** |
| **2006**       | ** ** | ** **        | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** |
| First Quarter  |       | 68.10             |       | 54.34             |       | 59.94 |   | 46.98 |   |
| Second Quarter |       | 69.50             |       | 50.82             |       | 61.68 |   | 45.63 |   |
| Third Quarter  |       | 71.22             |       | 52.13             |       | 63.65 |   | 46.70 |   |
| Fourth Quarter |       | 65.79             |       | 52.91             |       | 58.37 |   | 46.90 |   |
| **2005**       | ** ** | ** **        | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** |
| First Quarter  |       | 35.50             |       | 23.55             |       | 29.18 |   | 19.44 |   |
| Second Quarter |       | 39.85             |       | 29.53             |       | 32.32 |   | 23.28 |   |
| Third Quarter  |       | 60.67             |       | 40.25             |       | 51.73 |   | 31.95 |   |
| Fourth Quarter |       | 59.54             |       | 43.77             |       | 51.69 |   | 36.80 |   |

 

Quarterly Dividends Declaredon Common Shares

 
| ** **    | ** ** | **First**   | ** ** | **Second**  | ** ** | **Third**   | ** ** | **Fourth**  | ** ** |
|---------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|
| **($/share)** | ** ** | **Quarter** | ** ** | **Quarter** | ** ** | **Quarter** | ** ** | **Quarter** | ** ** |
| 2006          |       | 0.05        |       | 0.05        |       | 0.05        |       | 0.05        |       |
| 2005          |       | 0.05        |       | 0.05        |       | 0.05        |       | 0.05        |       |

 

Payment date for dividendswas the first day of the next quarter. All dividends paid to holders of commonshares in 2006 have been designated as “eligible dividends” for Canadian taxpurposes.

 

The Income Tax Act of Canadarequires us to deduct a withholding tax from all dividends remitted tonon-residents. According to the Canada-US Tax Treaty, we have deducted awithholding tax of 15% on dividends paid to residents of the United States,except in the case of a company that owns at least 10% of the voting stock,where the withholding tax is 5%.

 

The Investment Canada Actrequires that a “non-Canadian”, as defined, file notice with Investment Canadaand obtain government approval prior to acquiring control of a Canadianbusiness, as defined. Otherwise, there are no limitations, either under thelaws of Canada or in Nexen’s charter on the right of a non-Canadian to hold orvote Nexen’s securities.

 

On February 3, 2000, at aSpecial Meeting of Shareholders, a Shareholder Rights Plan was approved. On May2, 2002, at the Annual General and Special Meeting of Shareholders, an Amendedand Restated Shareholder Rights Plan (Plan) was approved. According to thePlan, a right is attached to each present and future outstanding common share,entitling the holder to acquire additional common shares during the term of theright. Prior to the separation date, the rights are not separable from thecommon shares, and no separate certificates are issued. The separation datewould typically occur at the time of an unsolicited takeover bid, but our boardcan defer the separation date.

 

Rights created under thePlan, which can only be exercised when a person acquires 20% or more of ourcommon shares (a Flip-In Event), entitle each shareholder, other than the 20%buyer, to acquire additional common shares at one-half of the market price atthe time of exercise. The Plan must be reapproved by shareholders on or beforeour annual general meeting in 2008 to remain effective past that date. A copyof the Plan is available on our website at www.nexeninc.com.

 

35

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| Item 6 |   | Selected  Financial Data |   | US GAAP  Summary Data |
|--------|--------|--------------------------|--------|-----------------------|

 

**ITEM 6. SELECTED FINANCIAL DATA**

 

Five-Year Summary of SelectedFinancial Data in Accordance with US GAAP

 
| **Cdn$ millions, except per share  amounts**                       | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** | **2003**   | ** ** | **2002**   | ** ** |
|-------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|
|                                                                    |       |       |       |       |       |       |       |       |       |       |       |
| **Oil  & Gas and Syncrude Production**                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Production Before Royalties (mboe/d) (2)                                |       | 212        |       | 242        |       | 250        |       | 269        |       | 269        |       |
| Production After Royalties (mboe/d) (2)                                 |       | 156        |       | 173        |       | 174        |       | 185        |       | 176        |       |
|                                                                    |       |       |       |       |       |       |       |       |       |       |       |
| **Results  of Operations**                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenue                                                                 |       |       |       |       |       |       |       |       |       |       |       |
| Oil & Gas and Syncrude (1)                                          |       | 3,656      |       | 3,535      |       | 2,573      |       | 2,261      |       | 1,966      |       |
| Marketing                                                               |       | 1,373      |       | 864        |       | 625        |       | 586        |       | 496        |       |
| Chemicals                                                               |       | 413        |       | 413        |       | 383        |       | 377        |       | 369        |       |
| Other                                                                   |       | (47        | )          | (193       | )          | 59         |       | 31         |       | 8          |       |
| Total Revenue                                                           |       | 5,395      |       | 4,619      |       | 3,640      |       | 3,255      |       | 2,839      |       |
|                                                                    |       |       |       |       |       |       |       |       |       |       |       |
| Net Income from Continuing Operations                                   |       | 579        |       | 658        |       | 705        |       | 419        |       | 270        |       |
| Basic Earnings per Common Share from Continuing  Operations ($/share)   |       | 2.21       |       | 2.52       |       | 2.74       |       | 1.69       |       | 1.10       |       |
| Diluted Earnings per Common Share from  Continuing Operations ($/share) |       | 2.15       |       | 2.47       |       | 2.71       |       | 1.68       |       | 1.09       |       |
| Net Income                                                              |       | 579        |       | 1,110      |       | 788        |       | 420        |       | 352        |       |
| Basic Earnings per Common Share ($/share)                               |       | 2.21       |       | 4.26       |       | 3.06       |       | 1.70       |       | 1.44       |       |
| Diluted Earnings per Common Share ($/share)                             |       | 2.15       |       | 4.17       |       | 3.03       |       | 1.68       |       | 1.42       |       |
|                                                                    |       |       |       |       |       |       |       |       |       |       |       |
| **Financial  Position**                                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Total Assets (2)                                                        |       | 17,079     |       | 14,493     |       | 12,339     |       | 7,703      |       | 6,764      |       |
| Long-Term Debt (3)                                                      |       | 4,618      |       | 3,630      |       | 4,214      |       | 2,470      |       | 2,575      |       |
| Shareholders’ Equity                                               |       | 4,614      |       | 3,961      |       | 2,892      |       | 2,131      |       | 1,812      |       |
| Capital Investment, including Acquisitions                              |       | 3,408      |       | 2,638      |       | 4,264      |       | 1,432      |       | 1,545      |       |
| Dividends per Common Share ($/share) (4)                      |       | 0.20       |       | 0.20       |       | 0.20       |       | 0.163      |       | 0.15       |       |
| Common Shares Outstanding (thousands)                                   |       | 262,513    |       | 261,141    |       | 258,399    |       | 251,212    |       | 245,932    |       |

 

----

*Notes:*

*(1)*       *During 2003, we soldnon-core conventional light oil assets in southeast Saskatchewan in Canadaproducing 9,000 bbls/d. In late 2004, we concluded production from our Buffalofield, offshore Australia, as anticipated. In the third quarter of 2005, wesold Canadian conventional oil and gas properties in Saskatchewan, BritishColumbia and Alberta producing 18,300 bbls/d. The results of these operationshave been shown as discontinued operations.*

*(2)*       *In 2003, production increasedfrom our deep-water Aspen development in the Gulf of Mexico in the UnitedStates. In 2004, production declined from our maturing assets in Yemen atMasila, in Canada and in the United States on the Gulf of Mexico Shelf. In late2004, we acquired North Sea assets and began production from Block 51 in Yemen.In 2005, we sold producing properties in Canada and suffered hurricane-relateddowntime in the Gulf of Mexico. A full year’s production from the North Sea andBlock 51 in Yemen offset declines caused by these events. In 2006, declines inYemen at Masila reduced production volumes.*

*(3)*       *In December 2004, we drewUS$1.5 billion on unsecured acquisition credit facilities to finance thepurchase of North Sea assets. The remainder of the purchase price was fundedfrom cash on hand. The acquisition credit facility was repaid in 2005 with proceedsfrom the issuance of US $1.04 billion in senior notes in the first quarter andfrom our asset disposition program in the third quarter. Our long-term debtincreased in 2006 as a result of our investment in capital projects, primarilyat Buzzard and Long Lake.*

*(4)*       *Quarterly dividends wereincreased to 5¢ per share in the fourth quarter of 2003.*

 

36

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MD&A

 

Our 2006 accomplishmentsposition us for anexciting 2007 as we plan to ramp up productionat Buzzard, bring Long Lake on stream, evaluateour recent discoveries and continue exploring.

 

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**ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS**

 

The following should be readin conjunction with the Consolidated Financial Statements included in thisreport. The Consolidated Financial Statements have been prepared in accordancewith generally accepted accounting principles (GAAP) in Canada. The impact ofsignificant differences between Canadian and United States (US) accountingprinciples on the financial statements is disclosed in Note 21 to theConsolidated Financial Statements. The date of this discussion is February 9,2007.

 

Unless otherwise noted,tabular amounts are in millions of Canadian dollars. Our discussion andanalysis of our oil and gas activities include our Syncrude activities sincethe product produced from Syncrude competes in the oil and gas market. Oil andgas volumes, reserves and related performance measures are presented on aworking interest before-royalties basis. We measure our performance in thismanner consistent with other Canadian oil and gas companies. Where appropriate,we have provided information on an after-royalty basis in tabular format.

 

Note: Canadian investorsshould read the Special Note to Canadian Investors on page 81 which highlightsdifferences between our reserve estimates and related disclosures that areotherwise required by Canadian regulatory authorities.

 
| **Executive Summary**                                           |       |       |
|-----------------------------------------------------------------|------------|------------|
| **Capital  Investment**                                         |       |       |
| **Financial Results**                                           | ** ** | ** ** |
| Year-to-Year Change in Net Income                               |       |       |
| Oil & Gas and Syncrude                                      |       |       |
| Production                                                      |       |       |
| Commodity Prices                                                |       |       |
| Operating Expenses                                              |       |       |
| Depreciation, Depletion,  Amortization and Impairment           |       |       |
| Exploration Expense                                             |       |       |
| Oil & Gas and  Syncrude Netbacks                            |       |       |
| Energy Marketing                                                |       |       |
| Chemicals                                                       |       |       |
| Corporate Expenses                                              |       |       |
| **Outlook  for 2007**                                           |       |       |
| **Liquidity and  Capital Resources**                            |       |       |
| **Critical Accounting  Estimates**                              |       |       |
| **New Accounting  Pronouncements**                              |       |       |
| **Quantitative  and Qualitative Disclosures about Market Risk** |       |       |

 

----

 
| Management’s Discussion & Analysis |   | Executive Summary |
|---------------------------------------------|--------|-------------------|

 

**EXECUTIVESUMMARY**

 
| **(Cdn$ millions)**                                   | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net Income                                                 |       | 601      |       | 1,140    |       | 793      |       |
| Earnings per Common Share, Basic ($/share)                 |       | 2.29     |       | 4.38     |       | 3.08     |       |
| Cash Flow from Operating Activities                        |       | 2,374    |       | 2,143    |       | 1,606    |       |
| Production before Royalties (mboe/d) (1)                   |       | 212      |       | 242      |       | 250      |       |
| Production after Royalties (mboe/d)                        |       | 156      |       | 173      |       | 174      |       |
| Capital Investment, including Acquisitions                 |       | 3,408    |       | 2,638    |       | 4,264    |       |
| Net Debt (2)                                               |       | 4,730    |       | 3,639    |       | 4,285    |       |
| Average Foreign Exchange Rate (Canadian to US dollar)      |       | 0.88     |       | 0.83     |       | 0.77     |       |
| Proved Oil and Gas Reserves before  Royalties (mmboe)  (3) |       | 725      |       | 468      |       | 542      |       |
| Proved Oil and Gas Reserves after Royalties (mmboe) (3)    |       | 637      |       | 393      |       | 451      |       |
| Proved Syncrude Reserves before Royalties (mmboe) (3)      |       | 324      |       | 318      |       | 301      |       |
| Proved Syncrude Reserves after Royalties (mmboe) (3)       |       | 274      |       | 264      |       | 255      |       |

 

----

*Notes:*

*(1)*       *Production before royaltiesreflects our working interest before royalties and includes production ofsynthetic crude oil from Syncrude. We have presented our working interestbefore royalties as we measure our performance on this basis consistent withother Canadian oil and gas companies.*

*(2)*       *Long-term debt andshort-term borrowings less cash and cash equivalents.*

*(3)*       *Includes developed andundeveloped proved reserves as at December 31.*

 

Strong commodity prices andrecord results from our energy marketing group contributed to net income andcash flow from operating activities. WTI reached new trading highs during theyear and our realized oil and gas price was $62.92/ boe, 9% above 2005. Themarketing group contributed record results, generating value from the optimizationof storage and transportation capacity, as well as financially trading pricedifferences caused by location, product quality and time. At the beginning ofthe year, the UK government increased the supplementary tax on oil and gasactivities in the North Sea. As a result, we recorded $277 million of futureincome tax expense. Our 2006 income also included $151 million of expense inconnection with our Block 51 arbitration. Last year, our net income includedgains of $225 million from the sale of Canadian oil and gas properties and again of $193 million on the sale of a portion of our interest in our chemicalsbusiness.

 

Our combined oil & gasand Syncrude production was lower than 2005 levels as we continue to transitionfrom maturing production in Yemen and Canada to new higher-return production in2007, primarily in the North Sea and the Gulf of Mexico. The 2005 sale ofCanadian conventional oil and gas assets reduced our 2006 volumes by 10,700 boe/dbefore royalties (8,100 boe/d after royalties) as compared to last year. Asexpected, our Masila assets continued to mature and production declined 16,800boe/d (7,600 boe/d after royalties). Our ongoing investment in Masila is tomaximize the recovery of the remaining reserves before our licence expires in2011. With Buzzard on stream in early January 2007, our 2007 net production isexpected to grow 50% to average between 230,000 boe/d and 260,000 boe/d, afterroyalties, and between 275,000 boe/d and 305,000 boe/d, before royalties.

 

In 2006, our largest annualcapital program was focused on our major development projects at Buzzard and atLong Lake. Development of Buzzard in the North Sea was completed during theyear and the field began producing on January 7, 2007. Peak production rates of85,000 boe/d, net to us, are expected by mid 2007. At Long Lake, we investedover $1 billion on the SAGD component of the project and on construction of theupgrader. We expect steam injection to begin at the end of the first quarter of2007, with upgrader start up scheduled for late 2007. At its peak, we expectour share of synthetic crude oil from phase 1 of Long Lake to be 30,000 bbls/d.At Syncrude, the Stage 3 expansion was brought on stream in 2006, adding 8,000bbls/d of production capacity. Late in the year, we completed an additionaldevelopment well at Aspen in the Gulf of Mexico, and we expect 2007 Aspenproduction to average between 15,000 and 20,000 boe/d.

 

 

39

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| Item 7 |   | Management’s Discussion & Analysis |   | Executive Summary |
|--------|--------|---------------------------------------------|--------|-------------------|

 

Our 2006 exploration programwas focused on drilling 20 wells, primarily in the Gulf of Mexico and the NorthSea. We had successful results from Alaminos Canyon Block 856 (Great WhiteWest) and Ringo in the Gulf of Mexico, and Golden Eagle in the North Sea.

 

Our net debt increased from2005 as a result of our investment in capital projects, primarily at Buzzardand Long Lake. We drew upon our committed term credit facilities during theyear as our capital spending exceeded our cash flow by approximately $1billion.

 

Throughout 2006, the Canadiandollar continued to strengthen relative to the US dollar. Our sales revenue isdenominated in or referenced to US dollars. As a result, our revenues declineas the US dollar weakens. On the other hand, our US-dollar capital spending andoperating costs are lower when translated to Canadian dollars. Overall, theweaker US dollar reduced our 2006 cash flow from operating activities and netincome by $223 million and $98 million, respectively.

 

During 2006, our proved oiland gas and Syncrude reserves additions replaced more than 400% of our oil andgas and Syncrude production (500% after royalties) as shown in the followingtable:

 
| ** **                                | ** ** | **Before**    | ** ** | **After**     | ** ** |
|-------------------------------------------|------------|---------------|------------|---------------|------------|
| **(mmboe)**                               | ** ** | **Royalties** | ** ** | **Royalties** | ** ** |
| **Production**                            |       |          |       |          |       |
| Oil and Gas                               |       | 71            |       | 51            |       |
| Syncrude                                  |       | 7             |       | 6             |       |
| **Total**                                 | ** ** | **78**        | ** ** | **57**        | ** ** |
|                                      |       |          |       |          |       |
| **Extensions, Discoveries and Revisions** |       |          |       |          |       |
| Oil and Gas                               |       | 328           |       | 295           |       |
| Syncrude                                  |       | 13            |       | 16            |       |
| **Total**                                 | ** ** | **341**       | ** ** | **311**       | ** ** |

 

The majority of our 2006additions came from our development projects at Long Lake in the Athabasca oilsands, Ettrick in the North Sea and Usan, offshore West Africa. We included 246mmboe of bitumen (219 after royalties) at Long Lake as a result of strongyear-end bitumen prices and lower natural gas costs. The Ettrick developmentwas sanctioned during the year, contributing 18 mmboe of proved reserves (18after royalties). At Usan, offshore West Africa, we added 30 mmboe of provedreserves (25 after royalties). Reserves were also added from ongoing activitiesin Canada, the Gulf of Mexico and the North Sea.

 

**CAPITALINVESTMENT**

 
| **(Cdn$ millions)**                  | ** ** | **Estimated 2007** | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|-------------------------------------------|------------|-------------------------|------------|-----------|------------|-----------|------------|
| Major Development                         |       | 1,000                   |       | 1,849     |       | 1,550     |       |
| Early Stage Development                   |       | 400                     |       | 123       |       | 54        |       |
| New Growth Exploration                    |       | 700                     |       | 491       |       | 456       |       |
| Core Asset Development                    |       | 700                     |       | 748       |       | 524       |       |
| Total Oil & Gas and Syncrude          |       | 2,800                   |       | 3,211     |       | 2,584     |       |
| Marketing, Corporate, Chemicals and Other |       | 100                     |       | 197       |       | 54        |       |
| **Total Capital**                         | ** ** | **2,900**               | ** ** | **3,408** | ** ** | **2,638** | ** ** |

 

40

----

 
| Management’s Discussion & Analysis |   | Capital Investment |
|---------------------------------------------|--------|--------------------|

 

Our strategy and capital programs are focused on growing long-term valuefor our shareholders. To maximize value, we invest in:

 

**•****           **core assets for short-term production and freecash flow to fund capital programs and repay debt;

 

**•****           **development projects that convert ourdiscoveries into new production and cash flow; and

 

**•****           **exploration projects for longer-term growth.

 

As conventional basins inNorth America mature, we have been transitioning our operations toward lessmature basins and unconventional resources. Our key focus areas include theNorth Sea, Athabasca oil sands, Canadian coalbed methane, Gulf of Mexico,offshore West Africa and the Middle East—areas we believe have attractivefiscal terms and significant remaining opportunity, and where we have somecompetitive advantage.

 

In 2006, we invested morethan $3.4 billion in capital expenditures, mostly in multi-year developmentprojects and long cycle-time exploration. In 2007, we plan to invest $2.8billion in our oil and gas and Syncrude assets. About 34% of this is focused onmulti-year development projects, 28% on core assets to sustain production andprovide cash flow, and 24% on drilling high-impact exploration wells andbuilding our acreage position. The rest will be spent on early stagedevelopment activities.

 

**2006 Investment Program**

 
| ** **                     | ** ** | **Major**       | ** ** | **Early Stage** | ** ** | **New Growth** | ** ** | **Core Asset** | ** ** | ** ** | ** ** |
|--------------------------------|------------|-----------------|------------|----------------------|------------|---------------------|------------|---------------------|------------|------------|------------|
| **(Cdn$ millions)**       | ** ** | **Development** | ** ** | **Development**      | ** ** | **Exploration**     | ** ** | **Development**     | ** ** | **Total**  | ** ** |
| Oil and Gas                    |       |            |       |                 |       |                |       |                |       |       |       |
| Synthetic (mainly Long Lake)   |       | 1,050           |       | 74                   |       | 45                  |       | —              |       | 1,169      |       |
| United Kingdom                 |       | 552             |       | 14                   |       | 62                  |       | 31                  |       | 659        |       |
| Yemen                          |       | —          |       | —               |       | 37                  |       | 145                 |       | 182        |       |
| United States                  |       | 31              |       | —               |       | 177                 |       | 387                 |       | 595        |       |
| Canada                         |       | 167             |       | 15                   |       | 118                 |       | 140                 |       | 440        |       |
| Other Countries                |       | —          |       | 20                   |       | 52                  |       | 8                   |       | 80         |       |
| Syncrude                       |       | 49              |       | —               |       | —              |       | 37                  |       | 86         |       |
| ** **                     | ** ** | **1,849**       | ** ** | **123**              | ** ** | **491**             | ** ** | **748**             | ** ** | **3,211**  | ** ** |
| Marketing, Corporate and Other |       | —          |       | —               |       | —              |       | 197                 |       | 197        |       |
| **Total Capital**              | ** ** | **1,849**       | ** ** | **123**              | ** ** | **491**             | ** ** | **945**             | ** ** | **3,408**  | ** ** |
|                           |       |            |       |                 |       |                |       |                |       |       |       |
| As a % of Total Capital        |       | 54              | %          | 4                    | %          | 14                  | %          | 28                  | %          | 100        | %          |

 

**2007 Estimated Capital**

 
| ** **                     | ** ** | **Major**       | ** ** | **Early Stage** | ** ** | **New Growth** | ** ** | **Core Asset** | ** ** | ** ** | ** ** |
|--------------------------------|------------|-----------------|------------|----------------------|------------|---------------------|------------|---------------------|------------|------------|------------|
| **(Cdn$ millions)**       | ** ** | **Development** | ** ** | **Development**      | ** ** | **Exploration**     | ** ** | **Development**     | ** ** | **Total**  | ** ** |
| Oil and Gas                    |       |            |       |                 |       |                |       |                |       |       |       |
| Synthetic (mainly Long Lake)   |       | 500             |       | 170                  |       | —              |       | —              |       | 670        |       |
| United Kingdom                 |       | 300             |       | —               |       | 125                 |       | 200                 |       | 625        |       |
| Yemen                          |       | —          |       | —               |       | 50                  |       | 100                 |       | 150        |       |
| United States                  |       | —          |       | 60                   |       | 325                 |       | 200                 |       | 585        |       |
| Canada                         |       | 200             |       | —               |       | 50                  |       | 150                 |       | 400        |       |
| Other Countries                |       | —          |       | 170                  |       | 150                 |       | —              |       | 320        |       |
| Syncrude                       |       | —          |       | —               |       | —              |       | 50                  |       | 50         |       |
| ** **                     | ** ** | **1,000**       | ** ** | **400**              | ** ** | **700**             | ** ** | **700**             | ** ** | **2,800**  | ** ** |
| Marketing, Corporate and Other |       | —          |       | —               |       | —              |       | 100                 |       | 100        |       |
| **Total Capital**              | ** ** | **1,000**       | ** ** | **400**              | ** ** | **700**             | ** ** | **800**             | ** ** | **2,900**  | ** ** |
|                           |       |            |       |                 |       |                |       |                |       |       |       |
| As a % of Total Capital        |       | 34              | %          | 14                   | %          | 24                  | %          | 28                  | %          | 100        | %          |

 

41

----

 
| Item 7 |   | Management’s Discussion & Analysis |   | Capital Investment |
|--------|--------|---------------------------------------------|--------|--------------------|

 

 

**Major and Early Stage development Projects**

 

Approximately 58% of our 2006capital was directed towards early stage and major development projectsincluding Buzzard, Long Lake, Syncrude Stage 3 and CBM.

 

**Synthetic**

 

In 2006, we investedapproximately $1.2 billion to develop our insitu oil sands resource. Thisincluded approximately $1.1 billion invested at our first phase of Long Lake.The SAGD facilities are in the final stages of commissioning and start up andwe expect steam injection to commence at the end of the first quarter of 2007,with bitumen production rates ramping up to peak rates over a 12 to 24 monthperiod. Upgrader module fabrication is largely complete and over 95% of themodules are on site. Construction of the upgrader is approximately 80% completeand start up is scheduled for late 2007. Production capacity for the firstphase of Long Lake is approximately 60,000 bbls/d (30,000 bbls/d net to us) ofpremium synthetic crude which we expect to reach by late 2008 or early 2009.

 

**We have anumber of major development projects at various stages of completion.**

 

We are planning to increasesynthetic crude oil production to 240,000 bbls/d (120,000 bbl/s net to us) overthe next decade. We plan to sequentially develop our oil sands leases withadditional 60,000 bbls/d (30,000 bbls/d net to us) phases using the sametechnology and design as Long Lake phase 1. We are currently progressing phase2 development. We have completed seismic and core hole drilling programs and wehave ordered several major vessels.

 

**United Kingdom**

 

At Buzzard, we installed theutilities and production topsides, drilled the initial development wells andcompleted hook-ups and project commissioning. Buzzard came on stream in earlyJanuary 2007 and production is ramping up. The facilities have the capacity toprocess up to 200,000 bbls/d of oil and 60 mmcf/d of gas, including the removalof hydrogen sulphide. Based upon recent drilling results, we have experiencedmore well-to-well variability in the concentration of hydrogen sulphide thanpreviously seen. We expect existing equipment and processes will allow us tomanage this variability for at least the first two or three years ofproduction. As we continue to produce and acquire reservoir information, wewill determine whether additional equipment will ultimately be required. Wehave a 43.2% interest in Buzzard and operate the project.

 

Elsewhere in the North Sea,we are progressing the development of the Ettrick field. Production at Ettrickis expected to commence in the first half of 2008, with our share reachingapproximately 16,000 boe/d. Development is approximately 30% complete andincludes drilling three production wells tied back to a floating production,storage and off-loading vessel. We have an 80% interest in Ettrick.

 

**Canada**

 

In Canada, we are developingthe first commercial CBM project from Mannville coals in the Fort Assiniboinearea of Alberta. In 2006, we invested $237 million in exploration anddevelopment activities on our CBM lands, of which $181 million was associatedwith development. We plan to increase our CBM production to at least 150 mmcf/dby 2011.

 

During the year, we acquiredover 100 sections of land in an emerging shale gas play in western Canada. Weplan to initiate a drilling and evaluation program in 2007 to demonstrate thefeasibility of this opportunity.

 

42

----

 

**Other Countries**

 

On Block OPL-222, offshoreWest Africa, Nigerian authorities have provisionally approved the Usan FieldDevelopment Plan. Basic engineering of the facilities is complete and tenderingof contracts for all major components is proceeding. The development planincludes a floating production, storage and off-loading vessel with storagecapacity of two million barrels, capable of handling peak production rates of160,000 bbls/d of oil. We expect the Usan development to be formally sanctionedin 2007, with first production as early as 2010. We have a 20% interest in theexploration and development of this block.

** **

**Syncrude**

 

At Syncrude, we completed theStage 3 expansion during the year. Start up was initially delayed by theemission of odours from the flue gas desulphurizer plant but modifications toeliminate the odours were completed and the expansion started up in lateAugust. The Stage 3 expansion increases our production capacity by 8,000bbls/d.

 

**New Growth Exploration**

 

We invested approximately 14%of our 2006 capital in new growth exploration, including seismic dataacquisition. We had exploration success in the Gulf of Mexico at AlaminosCanyon Block 856 (Great White West) and Ringo, and at Golden Eagle in the UKNorth Sea.

 

At Alaminos Canyon 856, weare evaluating development options following a two-well exploration drillingprogram earlier in the year. This block is located approximately 240 milessouth of Houston and is immediately west of the Great White discovery. We havea 30% interest in this discovery.

 

At Ringo, we are evaluating asub-sea tie-back to nearby facilities, which could be on stream in late 2008.We have a 50% interest in this discovery.

 

We recently completeddrilling operations at our Golden Eagle prospect in the UK North Sea. Thediscovery well was drilled to a depth of approximately 7,500 feet andencountered hydrocarbons. A successful sidetrack well was drilled to appraisethe accumulation and we are currently evaluating development options. We have a34% operated interest in Golden Eagle.

 

**Ourexploration program continues to deliver results with new finds in the Gulf ofMexico and North Sea.**

 

In 2006, we participated inthe Norwegian exploration bid round and were recently awarded four licenses.The licenses are in water depths from 1,000 to 1,300 feet and are locatedbetween 30 and 100 miles offshore Norway, situated close to existinginfrastructure. In 2007, we plan to invest in additional seismic and geologicalstudies in this region.

 

**Core Asset Development**

 

We direct our capitalinvestment in our maturing assets to extract maximum value over the remaininglife of the assets. In the Gulf of Mexico, we began producing from anadditional development well at Aspen in late December. Based on results fromthis well, we see further opportunities in the Aspen field and are currentlysidetracking one of our existing Aspen wells to exploit deeper sands. We have a100% interest in Aspen.

 

During the year, we commencedpower production from our Soderglen 70 megawatt wind farm in southern Alberta.The wind farm comprises 47 wind towers, each with a 1.5 megawatt turbine. Wehave a 50% interest in this project.

 

43

----

 
| Item 7 |   | Management’s Discussion & Analysis |   | Net Income Analysis |
|--------|--------|---------------------------------------------|--------|---------------------|

 

**FINANCIAL RESULTS**

**year-to-year Change in Net Income**

 
| **(Cdn$ millions)**                                             | ** ** | **2006 vs 2005** | ** ** | **2005 vs 2004** | ** ** |
|----------------------------------------------------------------------|------------|----------------------------|------------|----------------------------|------------|
| **Net Income for 2005 and 2004 (1)**                                 | ** ** | **1,140**                  | ** ** | **793**                    | ** ** |
|                                                                 |       |                       |       |                       |       |
| Favourable (unfavourable) variances: (2)                             |       |                       |       |                       |       |
|                                                                 |       |                       |       |                       |       |
| Production Volumes, After Royalties                                  |       |                       |       |                       |       |
| Crude Oil                                                            |       | (245                       | )          | 39                         |       |
| Natural Gas                                                          |       | (55                        | )          | (55                        | )          |
| Change in Crude Oil Inventory                                        |       | (74                        | )          | 4                          |       |
| Total Volume Variance                                                |       | (374                       | )          | (12                        | )          |
|                                                                 |       |                       |       |                       |       |
| Realized Commodity Prices                                            |       |                       |       |                       |       |
| Crude Oil                                                            |       | 325                        |       | 648                        |       |
| Natural Gas                                                          |       | (133                       | )          | 165                        |       |
| Total Price Variance                                                 |       | 192                        |       | 813                        |       |
|                                                                 |       |                       |       |                       |       |
| Oil and Gas Operating Expense                                        |       |                       |       |                       |       |
| Conventional                                                         |       | 13                         |       | (64                        | )          |
| Syncrude                                                             |       | (35                        | )          | (27                        | )          |
| Total Operating Expense Variance                                     |       | (22                        | )          | (91                        | )          |
|                                                                 |       |                       |       |                       |       |
| Depreciation, Depletion, Amortization and  Impairment                |       |                       |       |                       |       |
| Oil & Gas and Syncrude                                           |       | (48                        | )          | (308                       | )          |
| Other                                                                |       | 4                          |       | (19                        | )          |
| Total Depreciation, Depletion, Amortization  and Impairment Variance |       | (44                        | )          | (327                       | )          |
|                                                                 |       |                       |       |                       |       |
| Exploration Expense                                                  |       | (111                       | )          | (5                         | )          |
|                                                                 |       |                       |       |                       |       |
| Energy Marketing Contribution                                        |       | 336                        |       | 49                         |       |
|                                                                 |       |                       |       |                       |       |
| Chemicals Contribution                                               |       | (12                        | )          | 31                         |       |
|                                                                 |       |                       |       |                       |       |
| General and Administrative Expense                                   |       | 254                        |       | (510                       | )          |
|                                                                 |       |                       |       |                       |       |
| Interest Expense                                                     |       | 44                         |       | 46                         |       |
|                                                                 |       |                       |       |                       |       |
| Current Income Taxes                                                 |       | (29                        | )          | (91                        | )          |
| Future Income Taxes                                                  |       | (549                       | )          | 353                        |       |
|                                                                 |       |                       |       |                       |       |
| Other                                                                |       |                       |       |                       |       |
| Block 51 Arbitration                                                 |       | (151                       | )          | —                     |       |
| Business Interruption Insurance Proceeds                             |       | 152                        |       | (8                         | )          |
| Gains from Divestiture Programs                                      |       | (418                       | )          | 418                        |       |
| Increase (Decrease) in Fair Value of Crude  Oil Put Options          |       | 185                        |       | (252                       | )          |
| Other                                                                |       | 8                          |       | (67                        | )          |
|                                                                 |       |                       |       |                       |       |
| **Net Income for 2006 and 2005 (1)**                                 | ** ** | **601**                    | ** ** | **1,140**                  | ** ** |

 

----

*Note:*

*(1)*       *2005 and 2004 includesresults of discontinued operations (see Note 14 to our Consolidated FinancialStatements).*

*(2)*       *All amounts are presentedbefore provision for income taxes.*

 

Significant variances in net income are explained in the sections thatfollow.

 

44

----

 
| Management’s Discussion & Analysis |   | Production |
|---------------------------------------------|--------|------------|

 

**OIL & GAS AND SYNCRUDE**

**Production**

 
| ** **                     | ** ** | **2006**          | ** ** | **2005**      | ** ** | **2004**          | ** ** |
|--------------------------------|------------|-------------------|------------|---------------|------------|-------------------|------------|
| ** **                     | ** ** | **Before**        | ** ** | **After**     | ** ** | **Before**        | ** ** | **After** | ** ** | **Before** | ** ** | **After** | ** ** |
| ** **                     | ** ** | **Royalties (1)** | ** ** | **Royalties** | ** ** | **Royalties (1)** | ** ** | **Royalties** | ** ** | **Royalties (1)** | ** ** | **Royalties** | ** ** |
| **Oil and  Liquids** (mbbls/d) |       |              |       |          |       |              |       |   |   |   |   |   |   |
| Yemen                          |       | 92.9              |       | 51.8          |       | 112.7             |       | 60.6 |   | 107.3 |   | 53.5 |   |
| Canada (2)                     |       | 20.0              |       | 15.8          |       | 29.2              |       | 22.6 |   | 36.2 |   | 28.2 |   |
| United States                  |       | 17.0              |       | 15.0          |       | 22.2              |       | 19.6 |   | 30.0 |   | 26.5 |   |
| United Kingdom                 |       | 16.9              |       | 16.9          |       | 12.6              |       | 12.6 |   | 1.5 |   | 1.5 |   |
| Australia (3)                  |       | —            |       | —        |       | —            |       | — |   | 2.7 |   | 2.5 |   |
| Other Countries                |       | 6.3               |       | 5.7           |       | 5.6               |       | 5.1 |   | 5.3 |   | 4.7 |   |
| Syncrude (mbbls/d)  (4)        |       | 18.7              |       | 16.9          |       | 15.5              |       | 15.3 |   | 17.2 |   | 16.6 |   |
|                           |       | 171.8             |       | 122.1         |       | 197.8             |       | 135.8 |   | 200.2 |   | 133.5 |   |
| **Natural  Gas** (mmcf/d)      |       |              |       |          |       |              |       |   |   |   |   |   |   |
| Canada (2)                     |       | 108               |       | 91            |       | 124               |       | 101 |   | 146 |   | 115 |   |
| United States                  |       | 111               |       | 94            |       | 116               |       | 99 |   | 148 |   | 126 |   |
| United Kingdom                 |       | 20                |       | 20            |       | 23                |       | 23 |   | 3 |   | 3 |   |
|                           |       | 239               |       | 205           |       | 263               |       | 223 |   | 297 |   | 244 |   |
|                           |       |              |       |          |       |              |       |   |   |   |   |   |   |
| **Total******(mboe/d)          | ** ** | **212**           | ** ** | **156**       | ** ** | **242**           | ** ** | **173** | ** ** | **250** | ** ** | **174** | ** ** |

 

----

*Notes:*

*(1)*       *We have presented productionvolumes before royalties as we measure our performance on this basis consistentwith other Canadian oil and gas companies.*

*(2)*       *Includes the followingproduction from discontinued operations. See Note 14 to our ConsolidatedFinancial Statements.*

 
| ** **                | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------|------------|----------|------------|----------|------------|----------|------------|
| Before  Royalties         |       |     |       |     |       |     |       |
| Oil and Liquids (mbbls/d) |       | —   |       | 6.7      |       | 11.7     |       |
| Natural Gas (mmcf/d)      |       | —   |       | 24       |       | 47       |       |
| After  Royalties          |       | —   |       |     |       |     |       |
| Oil and Liquids (mbbls/d) |       | —   |       | 5.3      |       | 9.0      |       |
| Natural Gas (mmcf/d)      |       | —   |       | 17       |       | 33       |       |

 

*(3)*       *Comprises production from discontinued operations. SeeNote 14 to our Consolidated Financial Statements.*

*(4)*       *Considered a mining operation for US reportingpurposes.*

 

**2006 vs 2005—Lower production decreased net income by$374 million**

 

Production before royaltiesdecreased 12% from 2005, while production after royalties decreased 10%. Our2006 production excludes volumes from our Canadian oil and gas properties thatwere sold in the third quarter of 2005. Removing the impact of these propertydispositions, production before and after royalties declined 8% and 5%,respectively.

 

The following tablesummarizes our production changes year over year:

 
| ** **                             | ** ** | **Before**    | ** ** | **After**     | ** ** |
|----------------------------------------|------------|---------------|------------|---------------|------------|
| **(mboe/d)**                           | ** ** | **Royalties** | ** ** | **Royalties** | ** ** |
| 2005  Production                       |       | 242           |       | 173           |       |
| Canada—Disposition  of Properties |       | (11           | )          | (8            | )          |
|                                   |       | 231           |       | 165           |       |
| Production  changes                    |       |          |       |          |       |
| Yemen                                  |       | (20           | )          | (9            | )          |
| Canada                                 |       | (1            | )          | (1            | )          |
| United States                          |       | (6            | )          | (5            | )          |
| United Kingdom                         |       | 4             |       | 4             |       |
| Colombia                               |       | 1             |       | 1             |       |
| Syncrude                               |       | 3             |       | 1             |       |
| **2006  Production**                   | ** ** | **212**       | ** ** | **156**       | ** ** |

 

45

----

 
| Item 7 |   | Management’s Discussion & Analysis |   | Production |
|--------|--------|---------------------------------------------|--------|------------|

 

In 2007, we expect to growour annual production rate after royalties approximately 50% compared to 2006to between 230,000 and 260,000 boe/d after royalties (275,000 and 305,000 boe/dbefore royalties). Increases are expected to come from Buzzard in the North Sea(which commenced production January 7, 2007), from the Gulf of Mexico and afull year of production from the Stage 3 expansion at Syncrude. Also, steaminjection at Long Lake is expected to begin at the end of the first quarter in2007, with bitumen production ramping up until the upgrader is scheduled tocommence synthetic crude oil production late in 2007. Anticipated fielddeclines in Yemen will partially offset these expected increases.

 

**Our production after royalties is expected to growapproximately 50% in 2007, with incremental volumes from Buzzard, the Gulf ofMexico, Syncrude Stage 3 and Long Lake.**

 

Production volumes discussedin this section represent our working interest before royalties.

 

**Yemen**

 

Yemen production decreased18% from 2005. Production from Masila decreased 19% reflecting the maturity ofthe field and the impact of a reduced development drilling program. In 2006, wedrilled 28 development wells, eight fewer than in 2005. Strong initial ratesfrom new wells, combined with well optimizations, helped to minimize expectedproduction declines. Base declines at Masila are expected to continue as wemaximize recovery of the remaining reserves on the block prior to expiry of ourlicense in 2011. We plan to drill 14 development wells and continue our welloptimization program in 2007.

 

On Block 51, production fromthe East Al Hajr field declined 12%. In the first quarter of 2006, wecommissioned the permanent central processing facilities on the block. Lowerthan expected initial rates on new wells and higher than anticipated declinerates contributed to the decrease from 2005. During the year, we drilled 24development wells and nine development wells are planned for 2007.

 

We expect our share of totalproduction from Yemen to average between 60,000 and 75,000 bbls/d in 2007.

 

**Canada**

 

Production in Canadadecreased 24% from the previous year, primarily as a result of the sale ofconventional oil and gas properties in Alberta, British Columbia andSaskatchewan. Removing the effect of the dispositions, production decreased 3% from2005. Natural field declines of 7,600 boe/d were offset by capital investmentin our heavy oil and natural gas assets, contributing 5,500 boe/d in newproduction. Gas production is increasing at our coalbed methane projects inAlberta as existing wells continue to de-water and we bring more wells onstream. In 2007, we expect to drill 165 infill wells, continue optimizationactivities on our conventional assets and work on developing new technologiesto increase recoveries on our heavy oil properties.

 

We expect 2007 production toaverage between 45,000 and 50,000 boe/d in Canada with the commencement ofproduction of premium synthetic crude oil at Long Lake and additional coalbedmethane volumes.

 

**United States**

 

Gulf of Mexico productiondeclined 14%, or about 6,000 boe/d from 2005. Lower production from Aspen dueto natural declines contributed approximately 5,400 boe/d of the decrease. Anadditional Aspen development well was brought on stream in December 2006. Thiswell was expected to come on stream earlier in the year but damage to thedrilling rig from a work-boat accident delayed completion of the well. We arecurrently side-tracking one of the wells and expect it to be on stream by mid2007. In 2007, we expect production from the Aspen field to average between15,000 and 20,000 boe/d. Gunnison production remained strong, accounting for30% of our production from the Gulf of Mexico. Development of the Dawson Deepdiscovery was completed and tied-back to our Gunnison SPAR in July. The Wrigleydevelopment was delayed by the tight rig market in the Gulf, but completion isprogressing and the development is expected to come on stream in the first halfof 2007, with production rates anticipated of 3,200 boe/d.

 

46

----

 

The effects of HurricanesKatrina and Rita continued to be felt in 2006 as we slowly restored productionfrom fields shut-in due to damage received in 2005. Production from Vermilion321 was restored in September 2006. At year end, Vermilion 340 remains shut-infrom damage to the sub-surface pipeline system. This production was restored inearly 2007 (400 boe/d). During the year, we received $80 million of businessinterruption insurance proceeds related to the 2005 hurricanes.

 

In 2007, we expect productionto average between 45,000 and 55,000 boe/d in the Gulf of Mexico.

 

**United Kingdom**

 

Production in the UKincreased 23%, or 3,800 boe/d from 2005, primarily as a result of less downtimeon the Scott platform and new production from our non-operated Farragon field.In 2005, our production was reduced by two generator failures on the Scottplatform. During 2006, we received $74 million in business interruptionproceeds related to these failures. Our 2006 production was lower than weexpected as planned maintenance work on the Scott platform flare tip tooklonger than anticipated and operating capacity was reduced by maintenanceactivities on the SAGE export pipeline.

 

**With Buzzardon stream, we expect UK production to average between 90,000 and 100,00 boe/din 2007.**

 

Final commissioning of thefacilities at Buzzard was delayed by inclement weather in the North Sea late inthe year. Buzzard began production on January 7, 2007. The delay has no impacton our ramp-up plans and peak production of 85,000 boe/d is expected to beachieved in the second quarter of 2007.

 

In 2007, we plan to drill andcomplete eight production and three injection wells at Buzzard and threedevelopment wells in the Scott/Telford area. We expect our total yearproduction from our North Sea assets to average between 90,000 and 100,000boe/d in 2007. This compares to the 19,000 boe/d these assets produced when wepurchased them in late 2004.

 

**Other Countries**

 

Production from the Guandofield in Colombia was consistent with 2005. We maintained production rates fromtwo infill drilling programs, bringing 15 additional wells on stream during theyear. We expect to maintain production rates in Colombia in 2007.

 

**Syncrude**

 

At Syncrude, productionincreased 21% from 2005, but was lower than expected. The start-up of the Stage3 expansion was delayed by emission of odours from the flue gas desulphurizerplant. Production from the Stage 3 expansion began in early May and wasapproaching design capacity rates prior to shutting in as a result of theodours. Modifications to eliminate the problem were completed during the summerand the facilities were restarted in late August. Late in the year, aturnaround on coker 8-2 reduced production by approximately 6,000 bbls/d. Theturnaround was completed early in 2007.

 

Strong realized prices onproduction have enabled us to fully recover capital costs at Syncrude includingcosts associated with the Stage 3 expansion. Consequently, our Syncrude royaltyin 2006 increased from a 1% gross revenue royalty to a 25% net revenue royalty.As a result of the increased royalty rate, we receive lower net productionrelative to our working interest production volumes.

 

In 2007, we expect ourtotal-year production from Syncrude to average between 20,000 and 25,000 bbls/d.

 

**2005 vs 2004—Lower production decreased net income by$12 million**

 

Production before royaltiesdeclined 3% during 2005, while production after royalties remained consistentwith 2004 levels. New royalty-free production from the UK North Sea partiallyoffset the sale of higher-royalty production from Canada. We sold Canadianproduction during 2005 to reduce debt that financed our acquisition of offshoreoil and gas assets in the North Sea. Production was lower as a result ofhurricane activity in the Gulf of Mexico in the second half of 2005. Removingthe impact of the Canadian asset sales and the lost volumes attributable toHurricanes Katrina and Rita, our 2005 production before royalties would haveincreased 3% from 2004.

 

47

----

 
| Item 7 |   | Management’s Discussion & Analysis |   | Commodity Prices |
|--------|--------|---------------------------------------------|--------|------------------|

 

**CommodityPrices**

 
| ** **                                                     | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|----------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| **Crude  Oil**                                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| West Texas Intermediate (WTI) (US$/bbl)                        |       | 66.22      |       | 56.58      |       | 41.40      |       |
|                                                           |       |       |       |       |       |       |       |
| Differentials (1) (US$/bbl)                                    |       |       |       |       |       |       |       |
| Heavy Oil - LLK                                                |       | 21.79      |       | 20.82      |       | 13.53      |       |
| MARS                                                           |       | 7.34       |       | 6.59       |       | 6.15       |       |
| Masila                                                         |       | 3.00       |       | 5.71       |       | 4.84       |       |
| Dated Brent                                                    |       | 1.08       |       | 2.20       |       | —     |       |
|                                                           |       |       |       |       |       |       |       |
| Producing Assets (Cdn$/bbl)                                    |       |       |       |       |       |       |       |
| Yemen                                                          |       | 71.57      |       | 62.07      |       | 47.59      |       |
| Canada                                                         |       | 42.79      |       | 40.51      |       | 36.60      |       |
| United States                                                  |       | 65.80      |       | 57.63      |       | 46.60      |       |
| United Kingdom                                                 |       | 71.19      |       | 60.55      |       | 46.81      |       |
| Australia                                                      |       | —     |       | —     |       | 51.22      |       |
| Other Countries                                                |       | 66.09      |       | 59.96      |       | 43.07      |       |
| Syncrude                                                       |       | 72.32      |       | 71.00      |       | 52.80      |       |
|                                                           |       |       |       |       |       |       |       |
| Corporate Average (Cdn$/bbl)                                   |       | 67.50      |       | 58.98      |       | 45.90      |       |
|                                                           |       |       |       |       |       |       |       |
| **Natural  Gas**                                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| New York Mercantile Exchange (US$/mmbtu)                       |       | 6.99       |       | 8.99       |       | 6.19       |       |
| AECO (Cdn$/mcf)                                                |       | 6.62       |       | 8.04       |       | 6.44       |       |
|                                                           |       |       |       |       |       |       |       |
| Producing Assets (Cdn$/mcf)                                    |       |       |       |       |       |       |       |
| Canada                                                         |       | 6.49       |       | 7.51       |       | 5.76       |       |
| United States                                                  |       | 7.86       |       | 10.56      |       | 7.89       |       |
| United Kingdom                                                 |       | 7.43       |       | 7.86       |       | 8.28       |       |
|                                                           |       |       |       |       |       |       |       |
| Corporate Average (Cdn$/mcf)                                   |       | 7.18       |       | 8.89       |       | 6.85       |       |
|                                                           |       |       |       |       |       |       |       |
| **Nexen’s  Average Realized Oil and Gas Price**(Cdn$/boe) | ** ** | **62.92**  | ** ** | **57.97**  | ** ** | **44.94**  | ** ** |
|                                                           |       |       |       |       |       |       |       |
| Average  Foreign Exchange Rate–Canadian to US Dollar      |       | 0.8818     |       | 0.8253     |       | 0.7683     |       |

 

----

*Note:*

*(1)*       *These differentials are adiscount to WTI.*

 

**2006 vs 2005—Higher realized prices increased netincome $192 million**

 

Average WTI was 17% higherfrom the prior year, increasing our average realized crude oil price 14% to$67.50/bbl. Our realized natural gas price fell 19% from 2005, while NYMEXdecreased 22% in the same period. The full impact of the increase in WTI wasnot reflected in our higher realized crude oil price as the Canadian dollarstrengthened relative to the US dollar. The impact of the weaker US dollar wasoffset by narrower crude oil differentials. The weaker US dollar reduced netsales by approximately $250 million, and reduced our realized crude oil andnatural gas prices by approximately $4.85/bbl and $0.50/mcf, respectively ascompared to 2005.

 

48

----

 
| Management’s Discussion & Analysis |   | Commodity Prices |
|---------------------------------------------|--------|------------------|

 

**Crude Oil Reference Prices**

 

Crude oil prices remainedstrong for most of 2006, with WTI reaching new highs in July before finishingthe year at US$61.05/bbl, roughly where it began. WTI traded at an average ofUS$66.22/bbl for the year, with a trading range of between US$54.86/bbl andUS$78.40/bbl, where it peaked on July 14. The steady decline in crude pricesfrom August to the end of the year was largely driven by warm weather, aboveaverage crude oil inventories, concerns over the US economy, the perceivedreduction of geopolitical tensions in the Middle East and institution-led selloffs in the crude oil markets.

 

Weather has become anincreasingly significant factor in the pricing of crude oil. In North America,a mild 2005/2006 winter followed by an uneventful hurricane season in the Gulfof Mexico and a forecast for a warmer than normal 2006/2007 winter season dueto the warming effect of El Nino have put downward pressure on prices. Theresulting reduced demand has helped push crude oil inventories to levels higherthan the five-year average. In addition, concerns over a slowdown in the USeconomy due to the weakening of the US housing market have depressed crude oilprices further.

 

**WTI reachedrecord highs during 2006, increasing our realized crude oil prices.**

 

Geopolitical events were adominant theme through the first eight months of the year. Tensions in theMiddle East as a result of Iran’s uranium enrichment program, on-going violencein Iraq, fighting between Israel and Hezbollah militants in Lebanon, supplyoutages in Nigeria caused by continued violence and the nationalization of Venezuela’senergy industry contributed to increased prices and greater market volatility.Towards the end of the year, however, geopolitical tensions have beendiscounted by the market following an end to the conflict in Lebanon and doubtsthe US will move against Iran.

 

A number of oil and gasproducers have put option price protection programs in place at WTI strikeprices ranging from US$45 to US$60/bbl. With falling crude oil prices, theseprograms get closer to being “in the money”. This caused a sell-off in the crudeoil markets by various institutions that wrote these options as they attemptedto manage their option exposures. This sell-off contributed to the downwardpressure on crude prices.

 

 

To mitigate the bearishsentiments for crude oil, OPEC has shown a commitment to its US$50 — $55/bblbasket price by agreeing to reduce production by 1.2 million barrels a day fromNovember 1 and by a further 500,000 barrels a day from February 1, 2007. On thedemand side, global oil demand growth remains moderate and is expected to riseby 1.5 million barrels per day in 2007 to 86 million barrels a day. This growthcomes mainly from China and India. We expect this demand increase and thecommitment from OPEC to lower production to stabilize crude oil prices in thenear term.

 

Since the beginning of 2007,WTI has dropped to a low of US$49.90/bbl, but has since rebounded toapproximately US$59/bbl in early February.

 

**Crude Oil Differentials**

 

In Canada, heavy crude oildifferentials averaged US$21.79/bbl (33% of WTI) for the year, compared to$20.82/bbl (37% of WTI) in 2005. Differentials narrowed in the summer, asdemand increased for heavy blends relative to light blends. This reflectednormal seasonal narrowing as we headed into the summer asphalt season.Typically, heavy crude oil differentials widen going into the fourth quarterbut this year, they maintained their summer levels following the late-yearfalloff in WTI. In addition, heavy crude oil differentials are tighter thanusual this winter since OPEC cuts tend to be heavy barrels. This increases thevalue of heavy barrels relative to lighter barrels.

 

49

----

 

The US Gulf Coast Marsdifferential widened, averaging US$7.34/bbl in 2006 as compared to US$6.59/bblin 2005. This was primarily due to higher WTI prices, temporary declines indemand due to refinery maintenance schedules and increased competition fromCanadian heavy crude down the Spearhead pipeline into Cushing, Oklahoma and thePegasus pipeline into Nederland, Texas. Late in the year, Mars differentialsnarrowed in response to falling WTI prices and OPEC production quota cuts.

 

The Yemen Masila differentialnarrowed substantially relative to WTI during 2006, averaging US$3.00/bblcompared to US$5.71/bbl last year. This largely reflects the impact of strongerBrent pricing since Masila crude is priced off Brent, coupled with continuedstrong Asian demand.

 

**TheBrent/WTI differential strengthened during 2006, creating strong crude oilpricing for our North Sea barrels.**

 

The Brent/WTI differentialstrengthened during 2006 averaging US$1.08/bbl as compared to US$2.20/bbl in2005, resulting in a solid crude oil price for our North Sea barrels. Thespread between WTI and Brent broke away from historical norms where WTI usuallytrades at a premium of US$1.50/bbl to US$2.00/bbl. Several times during theyear, WTI traded at a discount to Brent. This was caused by weak US demandduring a heavier than usual maintenance season, coupled with high US crudeinventory levels as production from the US Gulf Coast came back on streamfollowing damage caused by Hurricanes Katrina and Rita in 2005. On-goingproduction outages in Nigeria also helped to push Brent up relative to theNorth American WTI benchmark. Near the end of the year, Brent gained moreupside support due to the production quota cut from OPEC. OPEC cuts have a moreimmediate impact on Brent relative to WTI given the shorter transit time ofBrent to world markets.

 

**Natural Gas Reference Prices**

 

Natural gas prices averagedUS$6.99/mmbtu, 22% below 2005 levels. NYMEX reached record price and volatilitylevels in late 2005, driven mainly by the impact of hurricanes Katrina and Ritaand speculation around the 2005/2006 North American winter season. In 2006, themildest January temperatures on record were experienced in several key NorthAmerican natural gas consuming regions which resulted in a weakening of NYMEX.This created a significant gas storage overhang. Prices remained softthroughout the year reflecting high storage levels, an uneventful hurricaneseason and a mild 2006/2007 winter prediction due to the warming effect of ElNino. Lack of sustained cold temperatures heading into 2007 will discouragestorage withdrawals, which puts further downward pressure on prices.

 

**2005 vs 2004—Higher realized prices added $813 millionto net income**

 

Crude oil prices remainedstrong in 2005 reaching new highs and new levels of volatility. While globaldemand was moderate and supply levels adequate, the stability and security oflong-term supply remained a concern, along with tightening refining capacityworldwide.

 

Natural gas prices reachedrecord highs and experienced increased volatility. Prices early in the yearwere propped up by strong oil prices. The disruptions caused by the hurricanespushed North American gas prices to new highs. The volatility did not end withthe hurricane activity, but continued into the winter, as markets speculated onthe impact of a cold or mild winter on tight supply. Prices peaked on December13, 2005 with NYMEX gas settling at US$15.38/mmbtu.

 

The full benefit of higherbenchmark prices wasn’t reflected in our realized prices because of the weakerUS dollar in 2005. All of our oil sales and most of our gas sales aredenominated in, or referenced to, US dollars. As a result, the weaker US dollardecreased net sales for the year by approximately $270 million, and reduced ourrealized crude oil and natural gas prices by approximately $4.40/bbl and$0.65/mcf, respectively, compared to 2004.

 

 

50

----

 
| Management’s Discussion & Analysis |   | Operating Expenses |
|---------------------------------------------|--------|--------------------|

 

**Operating Expenses**

 
| ** **                    | ** ** | **2006**          | ** ** | **2005**      | ** ** | **2004**          | ** ** |
|-------------------------------|------------|-------------------|------------|---------------|------------|-------------------|------------|
| ** **                    | ** ** | **Before**        | ** ** | **After**     | ** ** | **Before**        | ** ** | **After** | ** ** | **Before** | ** ** | **After** | ** ** |
| **(Cdn$/boe)**                | ** ** | **Royalties (1)** | ** ** | **Royalties** | ** ** | **Royalties (1)** | ** ** | **Royalties** | ** ** | **Royalties (1)** | ** ** | **Royalties** | ** ** |
| **Conventional  Oil and Gas** | ** ** | ** **        | ** ** | ** **    | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Yemen                         |       | 4.45              |       | 8.11          |       | 3.63              |       | 6.75 |   | 2.80 |   | 5.64 |   |
| Canada                        |       | 10.31             |       | 12.73         |       | 8.21              |       | 10.34 |   | 7.12 |   | 8.98 |   |
| United States                 |       | 8.17              |       | 9.45          |       | 6.35              |       | 7.33 |   | 5.30 |   | 6.12 |   |
| United Kingdom                |       | 11.28             |       | 11.28         |       | 14.90             |       | 14.90 |   | 8.26 |   | 8.26 |   |
| Australia                     |       | —            |       | —        |       | —            |       | — |   | 32.94 |   | 35.73 |   |
| Other Countries               |       | 2.87              |       | 3.13          |       | 5.55              |       | 6.08 |   | 3.76 |   | 4.09 |   |
| Average Conventional          |       | 6.95              |       | 9.69          |       | 6.03              |       | 8.70 |   | 5.13 |   | 7.59 |   |
|                          |       |              |       |          |       |              |       |   |   |   |   |   |   |
| **Synthetic  Crude Oil**      | ** ** | ** **        | ** ** | ** **    | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Syncrude                      |       | 27.53             |       | 30.43         |       | 26.95             |       | 27.22 |   | 19.89 |   | 20.61 |   |
| **Average  Oil and Gas**      |       | 8.77              |       | 11.96         |       | 7.36              |       | 10.34 |   | 6.15 |   | 8.83 |   |

 

----

*Note:*

*(1)*       *Operating expenses per boeare our total oil and gas operating costs divided by our working interestproduction before royalties. We use production before royalties to monitor ourperformance consistent with other Canadian oil and gas companies.*

 

**2006 vs 2005—Higher operating expenses decreased netincome by $22 million**

 

In Yemen, operating costs ona per-unit basis are increasing as fixed costs from our central processingfacilities, combined with increased water handling costs, are spread over lowerproduction volumes. At Masila, lower production and increased service rigactivity required to minimize production declines, combined with the costsassociated with the replacement of a single point mooring system used to loadoil onto tankers, increased our corporate average by $0.20/boe. Block 51operating costs increased our corporate average by $0.22/boe, reflecting highermanpower costs, increased water handling costs at the new facilities,maintenance costs associated with equipment repairs and power outages, andincreased fuel consumption and fuel prices. We expect Yemen operating costs perbarrel to continue to increase as our production declines.

 

Following the sale ofCanadian conventional oil and gas properties in 2005, we have proportionatelyhigher production from our heavy oil properties, which have higher operatingcosts compared to the lighter oil production we sold. Canadian operating costsincreased our corporate average by $0.18/boe. We are focused on increasingrecovery rates from our heavy oil properties by developing new technologies.

 

Operating costs in the Gulfof Mexico increased from last year due to industry cost pressures caused by thestrong commodity price environment and the 2005 hurricane season. Lowerproduction volumes and workovers on our shelf properties at the start of theyear increased our corporate average by $0.39/boe.

 

With the sale of Canadianproduction in 2005, barrels from the North Sea are contributing a higherpercentage of our total production. As the North Sea has higher operating coststhan our average cost per barrel, the change in production mix has increasedour corporate average by $0.32/boe. This was offset by lower operating costsrelative to 2005, as operating expenses last year included repair costs relatedto turbine failures. This reduced our corporate average by $0.26/boe. We expectour North Sea operating costs to decrease on a per-unit basis in 2007, withincreased low-operating cost production expected from Buzzard.

 

**We expect 2007 operating costs to decrease on aper-unit basis with increased low-operating cost production from Buzzard.**

 

Syncrude increased our corporateaverage operating costs by $0.72/boe as a result of maintenance activities andthe turnaround of a coker during the first quarter of 2006, combined with costsrelated to start-up of the Stage 3 expansion.

 

The stronger Canadian dollardecreased our US-dollar denominated operating costs, reducing our corporateaverage by $0.38/boe, compared to 2005.

 

51

----

 
| Item 7 |   | Management’s Discussion & Analysis |   | Operating Expenses |
|--------|--------|---------------------------------------------|--------|--------------------|

 

**2005 vs 2004—Higher operating expenses decreased netincome by $91 million**

 

In 2005, higher operatingcosts reflect the change in our profile as more of our production came fromhigher-cost areas such as the North Sea and from Canadian heavy oil followingthe Canadian property sales completed that year. Operating costs werenegatively impacted by storm-related costs and maintenance activities. Inaddition, high levels of industry activity and higher energy costs, driven byrecord commodity prices, increased our operating costs.

 

Our operations at Masila inYemen reflect the maturing asset base and have higher operating costs, mainlyfrom increased service rig activity to minimize production declines. Thesehigher costs added $0.09/boe to our corporate average. Block 51 operating costswere higher than Masila, reflecting the use of temporary production facilities.Higher operating costs from Block 51 increased our corporate average by$0.53/boe.

 

Industry cost pressures andthe sale of conventional production increased our Canadian unit operating costsin 2005. Although we sold high-cost production relative to our corporateaverage, we expect our overall Canadian operating costs to increase as we haveproportionately higher production from our heavy oil properties. Theseproperties have higher operating costs compared to the lighter oil productionthat was sold. 

 

In the Gulf of Mexico, lowervolumes of higher-cost barrels at Aspen, along with $12 million of Aspen-1intervention costs expensed in 2004, decreased our corporate average by$0.10/boe. Workovers on our shelf properties, coupled with lower production andproperty damage costs not covered by insurance, increased our corporate averageby $0.05/boe from 2004.

 

Higher-cost North Seaproduction increased our corporate average unit costs by $1.14/boe. Our NorthSea operating costs were higher than anticipated as a result of maintenance andrepair work caused by generator failures in the second quarter and majormaintenance turnaround and facilities upgrading at the Scott platform in thethird quarter.

 

Our Australian operationsceased in late 2004 and the exclusion of these high-cost, late-life barrelsreduced our corporate average by $0.57/boe. US-dollar denominated operatingcosts were lower when translated to Canadian dollars as a result of the weak USdollar. Our corporate average was reduced by $0.30/boe as a result.

 

Syncrude operating costs perboe were 35% higher than in 2004. Turnaround and maintenance costs accountedfor half of the increase, as we completed major turnarounds on various upgradingunits during the year. In addition, high levels of industry activity in the oilsands have put upward pressure on costs. When combined with higher energy costsrequired in the upgrading process, our corporate average increased by$0.34/boe.

 

**Depreciation,Depletion, Amortization and Impairment (DD&A)**

 
| ** **                    | ** ** | **2006**          | ** ** | **2005**      | ** ** | **2004**          | ** ** |
|-------------------------------|------------|-------------------|------------|---------------|------------|-------------------|------------|
| ** **                    | ** ** | **Before**        | ** ** | **After**     | ** ** | **Before**        | ** ** | **After** | ** ** | **Before** | ** ** | **After** | ** ** |
| **(Cdn$/boe)**                | ** ** | **Royalties (1)** | ** ** | **Royalties** | ** ** | **Royalties (1)** | ** ** | **Royalties** | ** ** | **Royalties (1)** | ** ** | **Royalties** | ** ** |
| **Conventional  Oil and Gas** | ** ** | ** **        | ** ** | ** **    | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Yemen                         |       | 9.67              |       | 17.61         |       | 8.56              |       | 15.93 |   | 4.35 |   | 8.77 |   |
| Canada                        |       | 11.22             |       | 13.84         |       | 9.26              |       | 11.67 |   | 9.02 |   | 11.37 |   |
| United States (2)             |       | 16.28             |       | 18.84         |       | 15.39             |       | 17.77 |   | 12.93 |   | 14.93 |   |
| United Kingdom                |       | 30.22             |       | 30.22         |       | 33.25             |       | 33.25 |   | 22.44 |   | 22.44 |   |
| Australia                     |       | —            |       | —        |       | —            |       | — |   | 5.82 |   | 6.31 |   |
| Other Countries               |       | 4.30              |       | 4.69          |       | 6.20              |       | 6.79 |   | 9.90 |   | 10.77 |   |
| Average Conventional          |       | 13.12             |       | 18.30         |       | 11.78             |       | 17.00 |   | 7.87 |   | 11.64 |   |
|                          |       |              |       |          |       |              |       |   |   |   |   |   |   |
| **Synthetic  Crude Oil**      | ** ** | ** **        | ** ** | ** **    | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Syncrude                      |       | 4.81              |       | 5.32          |       | 3.08              |       | 3.12 |   | 2.75 |   | 2.85 |   |
| **Average  Oil and Gas**      |       | 12.38             |       | 16.88         |       | 11.23             |       | 15.77 |   | 7.52 |   | 10.80 |   |

 

----

*Notes:*

*(1)*       *DD&A per boe is our DD&A for oil and gasoperations divided by our working interest production before royalties. We useproduction before royalties to monitor our performance consistent with otherCanadian oil and gas companies.*

*(2)*       *DD&A per boe excludes the impairment chargedescribed in Note 6 of our Consolidated Financial Statements.*

 

52

----

 
| Management’s Discussion & Analysis |   | DD&A |
|---------------------------------------------|--------|----------|

 

**2006 vs 2005—Higher oil and gas DD&A decreased netincome by $48 million**

 

Our 2006 DD&A expenseincludes $93 million ($1.21/boe) of impairment expense primarily related to twonatural gas producing properties in the Gulf of Mexico. The impairment wascaused by disappointing development programs and negative year-end reserverevisions. The carrying values of the impaired properties have been reduced totheir estimated fair value. In addition, our 2006 DD&A expense includes $15million (2005 - $58 million) relating to the write down of a portion of ourpurchase price allocation to unproved properties purchased in the North Sea asa result of unsuccessful exploration activities. Our 2006 average depletionrate excluding impairment charges is $12.38/boe, 10% above our 2005 average.

 

In Yemen, we began depletingthe permanent production facilities on Block 51 during the year. Strong crudeoil prices allowed us to continue to maximize the recovery of the costs we paidon behalf of the government. This increased our corporate average by $0.64/boe.

 

**The strongCanadian dollar reduced our corporate dd&A rate by $0.72/boe from 2005.**

 

The increased Canadiandepletion rate reflects the depletion of costs associated with our coalbedmethane projects in central Alberta. Our corporate average is higher by$0.35/boe as a result. We expect our depletion rate for our coalbed methaneprojects to decline as the wells de-water and we are able to recognizeadditional reserves. Depletion rates for our deep-water assets in the Gulf ofMexico increased our average by $0.28/boe primarily as a result of reserve revisionslate in 2005.

 

Our depletion rate for ourNorth Sea assets is higher than our average, primarily from the allocation ofthe purchase price we paid for these assets in 2004. Our corporate average isincreasing as the North Sea becomes a larger proportion of our total productionand from lower production in Canada following the sale of conventional oil andgas assets in 2005. This change increased our corporate average by $0.42/boe.We expect our corporate average will continue to increase in 2007 as we beginto deplete Buzzard.

 

The Stage 3 expansion atSyncrude began producing during the year and we started depleting these assetsin 2006. This increased our corporate average by $0.23/boe.

 

The strong Canadian dollarreduced our DD&A expense relative to 2005 as the depletion of ourinternational and US assets is denominated in US dollars. This lowered ourcorporate average by $0.72/boe from last year.

 

**2005 vs 2004—Higher oil and gas DD&A decreased netincome by $308 million**

 

Strong production volumes,new production from our North Sea assets and additional capital cost recoveryfrom 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 aresult of unsuccessful exploration activities.

 

Block 51 production in Yemenincreased our corporate unit depletion by $2.21/boe from 2004 as a result ofcarried interest accounting for the recovery of Block 51 capital costs. Strongproduction and higher realized oil prices have resulted in faster recovery ofcapital costs we paid on behalf of the government.

 

Our Canadian depletion rateper unit has increased slightly compared with 2004. Reserve revisions at theend of 2004 increased our 2005 heavy oil depletion rate. This increase wassomewhat offset when we stopped depleting our Canadian assets held for sale inthe second quarter, but continued to recognize related production. Thedisposition of these assets in the third quarter changed our asset mix andreduced our average annual corporate depletion rate by $0.23/boe.

 

Depletion rates in the Gulfof Mexico increased following reserve revisions in late 2004. Reduced volumes offsetthe increase in rates with minimal impact on our overall unit rate.

 

53

----

 
| Item 7 |   | Management’s Discussion & Analysis |   | Exploration Expense |
|--------|--------|---------------------------------------------|--------|---------------------|

 

North Sea depletion increasedour corporate average by $2.37/boe in 2005. The depletable carrying costs ofour Scott, Telford and Farragon fields include an allocation of the purchaseprice 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 tounproved properties subject to unsuccessful exploration activities.

 

The strengthening Canadiandollar offset these increases as the depletion of our international and USassets is denominated in US dollars. This lowered our corporate average by$0.70/boe compared with 2004.

 

**ExplorationExpense****(1)**

 
| **(Cdn$ millions)**                                | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Seismic                                                 |       | 128      |       | 53       |       | 73       |       |
| Unsuccessful  Drilling                                  |       | 169      |       | 143      |       | 125      |       |
| Other                                                   |       | 65       |       | 55       |       | 48       |       |
| **Total  Exploration Expense**                          | ** ** | **362**  | ** ** | **251**  | ** ** | **246**  | ** ** |
|                                                    |       |     |       |     |       |     |       |
| New Growth  Exploration                                 |       | 491      |       | 456      |       | 266      |       |
| Geological  and Geophysical Costs                       |       | 128      |       | 53       |       | 73       |       |
| **Total  Exploration Expenditures**                     | ** ** | **619**  | ** ** | **509**  | ** ** | **339**  | ** ** |
|                                                    |       |     |       |     |       |     |       |
| Exploration  Expense as a % of Exploration Expenditures |       | 58       | %          | 49       | %          | 73       | %          |

 

----

*Note:*

*(1)*       *2005 and 2004 includes exploration expense from discontinuedoperations. See Note 14 to our Consolidated Financial Statements.*

* *

**2006 vs 2005—Higherexploration expense reduced net income by $111 million**

** **

Our 2006 explorationactivities were focused on drilling 20 wells, mostly in the Gulf of Mexico andthe North Sea, and acquiring seismic data. We were successful at Great WhiteWest and Ringo in the Gulf of Mexico. In early 2007, we completed drillingoperations at our Golden Eagle prospect on License P928 in the UK North Sea.The discovery well was drilled to a depth of approximately 7,500 feel andencountered hydrocarbons. A successful sidetrack well was drilled to appraisethe accumulation and we are currently evaluating development options.

 

 

Our unsuccessful drillingresults were primarily in the Gulf of Mexico, where we expensed $135 million indry hole costs. Early in the year, we expensed $49 million for the Pathfinderwell, which found non-commercial quantities of hydrocarbons, after reaching atotal depth of 31,196 feet. Unsuccessful wells on the shelf in the Gulf ofMexico include West Cameron 135 and 109 ($23 million and $14 million respectively)and Vermilion 65 ($15 million). During the year, we also expensed $29 millionof capitalized costs related to Big Bend as it was determined that developmentwas uneconomic and the block was relinquished. In the North Sea, dry hole costsincluded unsuccessful exploratory wells at Zanzibar ($10 million) and Black Cat($7 million). Exploration expense also includes costs relating to Ukot South,offshore Nigeria, which encountered wet sands and was plugged and abandoned,and costs relating to three unsuccessful wells on Block 51 in Yemen.

 

54

----

 
| Management’s Discussion & Analysis |   | Exploration Expense |
|---------------------------------------------|--------|---------------------|

 

Our geological andgeophysical costs include $128 million of seismic data acquired during the yearof which half relates to the Gulf of Mexico. The balance was spent on datarelating to Canada, Norway, the North Sea, Nigeria and other internationaltargets.

 

We continue to focus on largeunconventional resource opportunities in Canada. In 2006, we acquiredapproximately 100 sections of prospective shale gas acreage in northeastBritish Columbia for $50 million, which we intend to evaluate in 2007.

 

**We continue to grow our unconventional resource in Canada. In2006, we acquired a sizeable shale gas land position in northeast BC.**

** **

In 2007, we plan to investapproximately $700 million to drill up to 19 exploration wells and acquireseismic data and access to new exploratory acreage. In the Gulf of Mexico wehave four deep-water and five shelf-gas prospects planned, while we anticipatedrilling five exploration wells in the North Sea. We expect to drill threeexploration wells on Block 51 in Yemen, one deep-water exploration welloffshore West Africa and one exploration well in Colombia.

 

**2005 vs 2004—Higherexploration expense reduced net income by $5 million**

** **

Our 2005 exploration programwas active, as we spent more than $500 million on 20 high-potential explorationwells in our key basins. In the Gulf of Mexico, Knotty Head, drilled to a depthof 34,189 feet, encountered hydrocarbons in multiple zones.

 

Our 2005 exploration expenseincludes costs associated with unsuccessful wells in the Gulf of Mexico, NorthSea, offshore West Africa and Yemen. In the Gulf of Mexico, we expensed $44million for the Vrede well. Vrede, a sub-salt prospect drilled to a total depthof 32,600 feet, encountered non-commercial quantities of hydrocarbons and wastemporarily abandoned. We also wrote off costs relating to our Castleton dryhole together with trailing costs related to the 2004 Crested Butte, Wind Riverand Fawkes wells. These wells, with the exception of Wind River, were locatedin the deep water.

 

In the North Sea, explorationexpense includes costs relating to Black Horse, Polecat, Bennachie and Saracen.The Black Horse and Polecat wells encountered hydrocarbons, but insufficient towarrant stand-alone development. We will continue to evaluate these reservoirsin combination with other potential development projects that may be sanctionedin the future. Bennachie was abandoned after encountering no reservoir sands inthe target zone. Saracen was written off earlier in 2005 as an unsuccessfulexploratory well.

 

Internationally, we expensedcosts related to four unsuccessful wells on Block 51 in Yemen and we abandonedour deep-water Efere well in Nigeria, as well as our K-2 well on Block K inEquatorial Guinea.

 

55

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| Item 7 |   | Management’s Discussion & Analysis |   | Netbacks |
|--------|--------|---------------------------------------------|--------|----------|

 

**OIL &GAS AND SYNCRUDE NETBACKS**

** **

Netbacks are the cash margins,before general and administrative expenses, we receive for every equivalentbarrel sold. The following table lists the sales prices, per-unit costs andnetbacks for our producing assets, calculated using our working interestproduction before and after royalties.

 

**BeforeRoyalties**

 
| ** **            | ** ** | **2006**  | ** ** |
|-----------------------|------------|-----------|------------|
| **($/boe)**           | ** ** | **Yemen** | ** ** | **Canada** | ** ** | **US** | ** ** | **UK** | ** ** | **Other** | ** ** | **Syncrude** | ** ** | **Total** | ** ** |
| Sales                 |       | 71.57     |       | 40.98 |   | 56.12 |   | 66.81 |   | 66.09 |   | 72.32 |   | 62.92 |   |
| Royalties  and Other  |       | (32.32    | )          | (7.80 | ) | (7.53 | ) | — |   | (5.51 | ) | (6.93 | ) | (17.68 | ) |
| Operating  Expenses   |       | (4.45     | )          | (10.31 | ) | (8.17 | ) | (11.28 | ) | (2.87 | ) | (27.53 | ) | (8.77 | ) |
| In-country  Taxes (1) |       | (8.45     | )          | — |   | — |   | — |   | — |   | — |   | (3.72 | ) |
|                  |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Cash  Netback**     | ** ** | **26.35** | ** ** | **22.87** | ** ** | **40.42** | ** ** | **55.53** | ** ** | **57.71** | ** ** | **37.86** | ** ** | **32.75** | ** ** |

 
| ** **            | ** ** | **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 (1) |       | (7.17     | )          | — |   | — |   | — |   | — |   | — |   | (3.34 | ) |
|                  |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Cash  Netback**     | ** ** | **22.56** | ** ** | **25.46** | ** ** | **45.85** | ** ** | **42.93** | ** ** | **49.18** | ** ** | **43.34** | ** ** | **30.57** | ** ** |

 
| ** **            | ** ** | **2004**      | ** ** |
|-----------------------|------------|---------------|------------|
| **($/boe)**           | ** ** | **Australia** | ** ** | **Yemen** | ** ** | **Canada** | ** ** | **US** | ** ** | **UK** | ** ** | **Other** | ** ** | **Syncrude** | ** ** | **Total** | ** ** |
| Sales                 |       | 51.22         |       | 47.59 |   | 35.76 |   | 46.94 |   | 47.45 |   | 43.07 |   | 52.80 |   | 44.94 |   |
| Royalties  and Other  |       | (4.00         | )          | (23.98 | ) | (7.40 | ) | (6.29 | ) | — |   | (3.49 | ) | (1.84 | ) | (13.65 | ) |
| Operating  Expenses   |       | (32.94        | )          | (2.80 | ) | (7.12 | ) | (5.30 | ) | (8.26 | ) | (3.76 | ) | (19.89 | ) | (6.15 | ) |
| In-country  Taxes (1) |       | —        |       | (5.82 | ) | — |   | — |   | — |   | — |   | — |   | (2.48 | ) |
|                  |       |          |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Cash  Netback**     | ** ** | **14.28**     | ** ** | **14.99** | ** ** | **21.24** | ** ** | **35.35** | ** ** | **39.19** | ** ** | **35.82** | ** ** | **31.07** | ** ** | **22.66** | ** ** |

 

**AfterRoyalties**

 
| ** **            | ** ** | **2006**  | ** ** |
|-----------------------|------------|-----------|------------|
| **($/boe)**           | ** ** | **Yemen** | ** ** | **Canada** | ** ** | **US** | ** ** | **UK** | ** ** | **Other** | ** ** | **Syncrude** | ** ** | **Total** | ** ** |
| Sales                 |       | 71.57     |       | 40.98 |   | 56.12 |   | 66.81 |   | 66.09 |   | 72.32 |   | 62.92 |   |
| Operating  Expenses   |       | (8.11     | )          | (12.73 | ) | (9.45 | ) | (11.28 | ) | (3.13 | ) | (30.43 | ) | (11.96 | ) |
| In-country  Taxes (1) |       | (15.40    | )          | — |   | — |   | — |   | — |   | — |   | (5.07 | ) |
|                  |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Cash  Netback**     | ** ** | **48.06** | ** ** | **28.25** | ** ** | **46.67** | ** ** | **55.53** | ** ** | **62.96** | ** ** | **41.89** | ** ** | **45.89** | ** ** |

 
| ** **            | ** ** | **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 (1) |       | (13.35    | )          | — |   | — |   | — |   | — |   | — |   | (4.69 | ) |
|                  |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Cash  Netback**     | ** ** | **41.97** | ** ** | **32.08** | ** ** | **52.93** | ** ** | **42.93** | ** ** | **53.88** | ** ** | **43.78** | ** ** | **42.94** | ** ** |

 
| ** **            | ** ** | **2004**      | ** ** |
|-----------------------|------------|---------------|------------|
| **($/boe)**           | ** ** | **Australia** | ** ** | **Yemen** | ** ** | **Canada** | ** ** | **US** | ** ** | **UK** | ** ** | **Other** | ** ** | **Syncrude** | ** ** | **Total** | ** ** |
| Sales                 |       | 51.22         |       | 47.59 |   | 35.76 |   | 46.94 |   | 47.45 |   | 43.07 |   | 52.80 |   | 44.94 |   |
| Operating  Expenses   |       | (35.73        | )          | (5.64 | ) | (8.98 | ) | (6.12 | ) | (8.26 | ) | (4.09 | ) | (20.61 | ) | (8.83 | ) |
| In-country  Taxes (1) |       | —        |       | (11.72 | ) | — |   | — |   | — |   | — |   | — |   | (3.57 | ) |
|                  |       |          |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Cash  Netback**     | ** ** | **15.49**     | ** ** | **30.23** | ** ** | **26.78** | ** ** | **40.82** | ** ** | **39.19** | ** ** | **38.98** | ** ** | **32.19** | ** ** | **32.54** | ** ** |

 

----

Note:

(1)    Comprises income taxes payable in Yemen that are included inthe Government’s share of profit oil.

 

56

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| Management’s Discussion & Analysis |   | Energy Marketing |
|---------------------------------------------|--------|------------------|

 

**ENERGY MARKETING**

 
| **(Cdn$ millions)**                                                             | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|--------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Physical Sales (1)                                                                   |       | 40,920     |       | 37,873     |       | 28,554     |       |
| Physical Purchases (1)                                                               |       | (39,925    | )          | (36,988    | )          | (28,074    | )          |
| Net Financial Transactions (1)                                                       |       | 314        |       | (38        | )          | 128        |       |
| Net Revenue                                                                          |       | 1,309      |       | 847        |       | 608        |       |
| Transportation Expense                                                               |       | (789       | )          | (641       | )          | (451       | )          |
| Other                                                                                |       | 20         |       | (2         | )          | (2         | )          |
| **Net  Marketing Revenue**                                                           | ** ** | **540**    | ** ** | **204**    | ** ** | **155**    | ** ** |
|                                                                                 |       |       |       |       |       |       |       |
| **Contribution  to Net Marketing Revenue by Product Type:**                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| North American Natural Gas                                                           |       | 390        |       | 117        |       | 93         |       |
| International Crude Oil                                                              |       | 114        |       | 70         |       | 52         |       |
| North American Power                                                                 |       | 16         |       | 8          |       | 4          |       |
| Other                                                                                |       | 20         |       | 9          |       | 6          |       |
| **Net  Marketing Revenue**                                                           | ** ** | **540**    | ** ** | **204**    | ** ** | **155**    | ** ** |
| Depreciation, Depletion, Amortization and  Impairment                                |       | (12        | )          | (11        | )          | (10        | )          |
| General and Administrative                                                           |       | (112       | )          | (89        | )          | (58        | )          |
|                                                                                 |       |       |       |       |       |       |       |
| **Marketing Contribution to Income from  Continuing Operations before Income Taxes** | ** ** | **416**    | ** ** | **104**    | ** ** | **87**     | ** ** |
|                                                                                 |       |       |       |       |       |       |       |
| **Natural  Gas**                                                                     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Physical Sales Volumes (2) (bcf/d)                                                   |       | 5.4        |       | 4.9        |       | 4.9        |       |
| Transportation Capacity (bcf/d)                                                      |       | 3.3        |       | 4.0        |       | 3.5        |       |
| Storage Capacity (bcf)                                                               |       | 50         |       | 30         |       | 27         |       |
| **Crude  Oil**                                                                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Physical Sales Volumes (2) (mbbls/d)                                                 |       | 705        |       | 510        |       | 465        |       |
| Storage Capacity (mbbls)                                                             |       | 1,749      |       | 580        |       | 408        |       |
| **Power**                                                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Physical Sales Volumes Power (2) – (MW/d)                                       |       | 4,388      |       | 2,548      |       | 1,191      |       |
| Generation Capacity (MW/hr)                                                          |       | 87         |       | 53         |       | 53         |       |
|                                                                                 |       |       |       |       |       |       |       |
| **Value-at-Risk**                                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Year End                                                                             |       | 26         |       | 24         |       | 21         |       |
| High                                                                                 |       | 33         |       | 28         |       | 42         |       |
| Low                                                                                  |       | 17         |       | 11         |       | 17         |       |
| Average                                                                              |       | 23         |       | 21         |       | 29         |       |

 

----

*Notes:*

*(1)*       *Marketing’s physical sales, physical purchases and netfinancial transactions are reported net on the Consolidated Statement of Incomeas marketing and other.*

*(2)*       *Excludes intra-segment transactions.*

* *

**2006 vs 2005—Netmarketing revenue increased net income by $336 million**

** **

Marketing had record resultsin 2006, with all groups achieving new highs or starting new businesses. Thelargest contribution continues to come from our North American natural gasmarketing group where we capitalized on our asset-based trading strategy. Timeand location spread trading generated most of our gas gains but we were alsosuccessful in generating revenues through the optimization of ourtransportation and storage capacity. Volatility within the North American gasmarkets created market inefficiencies for us to capitalize on. North Americangas prices started 2006 at US$10.63/mcf and closed the year at US$6.30/mcf.Storage overhang and speculation around weather and possible hurricanes causedsignificant changes in prices during the year. We also took advantage ofopportunities late in the year to add to our storage capacity. 

 

57

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| Item 7 |   | Management’s Discussion & Analysis |   | Energy Marketing |
|--------|--------|---------------------------------------------|--------|------------------|

 

 

Our crude oil marketing groupalso generated record results by successfully taking advantage of crudequality, location and time spreads. The group generated physical and financialtrading gains by taking advantage of the contango (rising forward month prices)in the crude oil forward curve. In addition, we captured profits around qualityspreads by diverting crude oil, or by blending to enhance the crude quality,and attract higher prices. While our strategies remained largely the same in2006, we executed more transactions and added more capacity, particularlystorage, during the year. With our newly established marine transportationcapabilities, this group is well positioned to start marketing our Buzzardproduction in 2007.

 

Our power marketing group isthe largest supplier of power to the commercial and industrial sector inAlberta and net revenue contributions exceeded expectations.

 

**Our power marketing group is the largest supplier of power tothe commercial and industrial sector in Alberta.**

** **

We continued our expansioninto new markets during the year with acquisitions in the North American NGLtrading business and a UK acquisition which positioned us in the UK and Europeangas and power markets.

 

Results from our marketinggroup vary between periods and historical results are not necessarilyindicative of future results. Marketing results depend on a variety of factorssuch as market volatility, changes in time and location spreads, the manner inwhich we use our storage and transportation assets and the change in value ofthe financial instruments we use to hedge these assets.

 

**2005 vs 2004—Netmarketing revenue increased net income by $49 million**

** **

Marketing delivered strongresults in 2005, with net revenue of $204 million. Our gas marketing group grewtheir net revenue to $117 million. We achieved these results through ourcontinued focus on an asset-based trading strategy, using our transportationand storage capacity to take advantage of seasonal and locational pricingdifferences and market inefficiencies.

 

While 2005 was a profitableyear, it was also volatile with hurricane activity in the Gulf of Mexicodisrupting gas supply and infrastructure. This volatility caused us torecognize losses in the third quarter on financial contracts hedging ourphysical assets. However, we were able to recognize gains on our physicalassets in the fourth quarter as we used our transportation capacity and soldgas from storage. This allowed us to recoup our third quarter losses andrecognize $175 million of net revenue in the fourth quarter. We also generatedprofits from financial contracts that captured time and location spreads.

 

Our crude oil marketing groupcontributed $70 million of net revenue in 2005, an increase of 35% over 2004.Similar to prior years, we continued to capitalize on forward prices, as wellas differences in crude qualities. In particular, in 2005, we took advantage ofcontango by successfully pricing our purchases lower than our sales, and byfinancially trading calendar spreads. We also captured profits around qualityspreads by diverting crude oil, or by blending to enhance the crude quality,and attract higher prices.

 

**Compositionof Net Marketing Revenue**

 
| **(Cdn$ millions)**         | ** ** | **2006** | ** ** | **2005** | ** ** |
|----------------------------------|------------|----------|------------|----------|------------|
| Trading  Activities              |       | 520      |       | 195      |       |
| Non-Trading  Activities          |       | 20       |       | 9        |       |
| **Total  Net Marketing Revenue** | ** ** | **540**  | ** ** | **204**  | ** ** |

 

58

----

 

**TradingActivities**

** **

In marketing, we enter intocontracts to purchase and sell crude oil and natural gas. We also use financialand derivative contracts, including futures, forwards, swaps and options forhedging and trading purposes. We account for all derivative contracts notdesignated as hedges for accounting purposes using mark-to-market accountingand record the net gain or loss from their revaluation in marketing and otherincome. The fair value of these instruments is included with accounts receivableor payable. They are classified as long-term or short-term based on theiranticipated settlement date.

 

We value derivative tradingcontracts daily using:

 

•            actively quoted markets such as the New YorkMercantile Exchange and the International Petroleum Exchange; and

 

•            other external sources such as the Natural GasExchange, independent price publications and over-the-counter broker quotes.

 

Fair Value of DerivativeContracts

 

At December 31, 2006, thefair value of our derivative contracts not designated as hedges totalled $360million (2005—$169 million). Below is a breakdown of this fair value byvaluation method and contract maturity.

 
| ** **                                  | ** ** | **Maturity**    | ** ** |
|---------------------------------------------|------------|-----------------|------------|
| **(Cdn$ millions)**                    | ** ** | **< 1 year** | ** ** | **1-3 years** | ** ** | **4-5 years** | ** ** | **> 5 years** | ** ** | **Total** | ** ** |
| Prices                                      |       |            |       |   |   |   |   |   |   |   |   |
| Actively Quoted Markets                     |       | 190             |       | (26 | ) | (21 | ) | — |   | 143 |   |
| From Other External Sources                 |       | 216             |       | (6 | ) | 13 |   | (6 | ) | 217 |   |
| Based on Models and Other Valuation Methods |       | —          |       | — |   | — |   | — |   | — |   |
| **Total**                                   | ** ** | **406**         | ** ** | **(32** | **)** | **(8** | **)** | **(6** | **)** | **360** | ** ** |

 

Changes in Fair Value ofDerivative Contracts

 
| **(Cdn$ millions)**                                                           | ** ** | **Total** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------|------------|
| Fair Value  at December 31, 2005                                                   |       | 169       |       |
| Change in Fair Value of Contracts                                                  |       | 576       |       |
| Net Losses (Gains) on Contracts Closed                                             |       | (385      | )          |
| Changes in Valuation Techniques and  Assumptions (1)                               |       | —    |       |
| **Fair  Value at December 31, 2006**                                               | ** ** | **360**   | ** ** |
|                                                                               |       |      |       |
| Unrecognized  Gains on Hedges of Future Sale of Gas Inventory at December 31, 2006 |       | 25        |       |
| **Total  Outstanding at December 31, 2006**                                        | ** ** | **385**   | ** ** |

 

----

*Note:*

*(1)*       *Our valuation methodology has been applied consistentlyyear-over-year.*

* *

As a physical energymarketer, we match the contract months of our derivative contracts with the contractmonths of our physical sales and purchases. As a result, the fair value of ourderivative contracts as at December 31, 2006 includes amounts with no ongoingcommodity price or foreign currency exchange risk. Excluding these amounts, thefair value of our derivative contracts at December 31, 2006 was $102 million.

 

The fair values of ourderivative contracts will be realized over time as the related contractssettle. Until then, the value of certain contracts will vary with forwardcommodity prices and price differentials. While forward prices vary, the valueof the contracts only varies to the extent they are economically exposed orunprotected. As most of our unrealized value is not economically exposed, weexpect to realize the majority of this fair value.

 

59

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More than 113% of the unrealized fairvalue relates to contracts that settle within 12 months. Contract maturitiesvary from a single day up to 12 years. Those maturing beyond one year primarilyrelate to North American natural gas positions. The relatively short maturityof our contracts, the high quality of our valuations from quoted markets andexternal sources and the limited economic exposure combine to lower ourportfolio risk.

 

As part of ourgas marketing strategy, we hold physical transportation and storage capacitycontracts that allow us to take advantage of pricing differences betweenlocations (i.e. west vs. east) and time periods (i.e. summer vs. winter). Thesecapacity contracts have market value, similar to financial commodity contracts,as future margins realized depend on future prices and, more importantly,pricing differences. The market value of these capacity contracts variesdepending on the change in future prices and pricing relationships. Weroutinely hedge the economic value of our capacity contracts using varioustypes of derivative contracts, thereby limiting volatility in our economicresults. Accounting rules, however, increase volatility in our reported resultssince they require us to recognize the change in fair value of derivativecontracts hedging our capacity contracts, but do not allow us to recognize thechange in fair value of the capacity contracts themselves until the contractsare used. As a result, when prices or pricing relationships change, we may berequired to include gains or losses in our reported results in differentperiods even though our underlying economic results may be largely unchanged.At the end of 2006, unrecognized future commitments related to ourtransportation and storage capacity contracts was a loss of $81 million. Thisamount has been included in our contractual obligations, commitments andguarantees in the MD&A.

 

We have designated certain derivativecontracts as accounting cash flow hedges of the future sale of our gas instorage. Mark-to-market gains and losses on these designated contracts areexcluded from income until the underlying inventory is sold. At December 31,2006, we had $25 million of unrecognized gains on these derivative contracts.These contracts have been valued from actively quoted markets and will settlewithin 12 months. In late 2006, we de-designated certain futures contracts thathad been designated as cash flow hedges of future sales of our natural gas instorage. Gains of $65 million on the futures contracts have been deferred andare expected to be recognized in net income in the first quarter of 2007.

 

Non-Trading Activities

 

We enter into fee-for-service contractsrelated to transportation and storage of third-party oil and gas. We also earnincome from our power generation facilities at Balzac and Soderglen. We earned$20 million from our non-trading activities in 2006 (2005—$9 million).

 

**CHEMICALS**

 
| **(Cdn$ millions)**                                                         | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net Sales                                                                        |       | 407      |       | 398      |       | 378      |       |
| Sales Volumes (thousand short tons)                                              |       |     |       |     |       |     |       |
| Sodium Chlorate                                                                  |       | 487      |       | 493      |       | 506      |       |
| Chlor-alkali                                                                     |       | 451      |       | 450      |       | 403      |       |
| Operating  Profit (1)                                                            |       | 124      |       | 136      |       | 105      |       |
| Operating  Margin (2)                                                            |       | 30       | %          | 34       | %          | 28       | %          |
| Chemicals  Contribution to Income from Continuing Operations Before Income Taxes |       | 44       |       | 37       |       | 40       |       |
| Capacity  Utilization                                                            |       | 95       | %          | 96       | %          | 95       | %          |

 

----

*Notes:*

*(1)**      **Total revenues lessoperating costs, transportation and other.*

*(2)**      **Operatingprofit divided by net sales.*

 

60

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**2006 vs 2005—Lower chemicals operating profit decreased net income by $12 million**

** **

Our investment in ourchemicals business is held through our 61.4% interest in the Canexus LimitedPartnership. While North American prices for sodium chlorate remained strong throughout2006, sales volumes fell slightly from last year as a result of pulp millclosures. Chlor-alkali volumes and prices in North America remained steady.US-dollar denominated North American sales were reduced $12 million from thestronger Canadian dollar during 2006. Sales and operations from the Brazilplant remained solid as a result of strong demand from Aracruz Cellulose, ourprimary customer, and from the merchant market.

 

**During theyear, Canexus began an expansion of the Brandon, Manitoba plant, which benefitsfrom low electricity rates.**

** **

Late in the year, Canexuscommenced an expansion of the Brandon, Manitoba plant to increase capacity by12% by early 2008. The Brandon plant benefits from low electricity rates in theprovince of Manitoba, where the electricity market is based on hydroelectricpower and is regulated.

 

**2005 vs 2004—Higherchemicals 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 IncomeFund through an initial public offering (IPO), which raised net proceeds of$301 million. Canexus Limited Partnership, also raised US$167 million ($200million) of bank debt. Canexus Limited Partnership used the proceeds fromCanexus Income Fund’s IPO and the bank debt, together with the issuance of 50.5million exchangeable units of the Canexus Limited Partnership to Nexen, topurchase our chemicals operations. We have retained a 61.4% interest in thechemicals operations through our investment in Canexus Limited Partnership, andwe 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 thechemicals business. Sodium chlorate volumes decreased compared with 2004 as aresult of our decision in early 2005 to forego low-margin business consistentwith our restructuring effort and the closure of our Amherstburg, Ontarioplant. Sales and operations from the Brazil plant remained strong as a resultof continued strong demand from Aracruz Cellulose, our primary customer inBrazil, and an expanded presence in the merchant market.

 

The weaker US dollar putpressure on our US-dollar denominated sales, reducing net sales by $13 million.During 2005, we purchased US-dollar foreign currency call options to mitigateour exposure to the weakening dollar. We generated $4 million of income as aresult of these call options.

 

Our chemicals contributionwas reduced by $12 million for an impairment charge relating to our chemicalsplant in Amherstburg, which was closed in the third quarter of 2005.

 

**CORPORATE EXPENSES**

**General and Administrative (G&A)**

 
| **(Cdn$ millions)**                                            | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| General and  Administrative Expense before Stock-Based Compensation |       | 345      |       | 302      |       | 206      |       |
| Stock-Based  Compensation (1)                                       |       | 210      |       | 507      |       | 93       |       |
| **Total  General and Administrative Expense**                       | ** ** | **555**  | ** ** | **809**  | ** ** | **299**  | ** ** |

 

----

*Note:*

*(1)*       *Includes tandem option plan, stock options for our US-basedemployees and stock appreciation rights plan.*

 

61

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**2006 vs 2005—Lowercosts increased net income by $254 million**

** **

Our G&A expense beforestock-based compensation increased 14% primarily from additional costs toexpand our marketing operations into new markets. Acquisitions during the yearenabled us to increase our NGL business in North America and to expand ourEuropean trading operations. Our G&A expense also includes higher variablecompensation stemming from our marketing group’s strong performance in 2006.

 

**TotalG&A expense decreased 31% in 2006 from lower stock-based compensationcosts.**

** **

Changes in our share pricecreates volatility in our net income as we account for stock-based compensationusing the intrinsic-value method. This method uses our share price at the endof the reporting period to determine our stock-based compensation expense andrelated obligations. In 2006, our share price increased 16% from $55.42 to$64.20, creating over $2.3 billion of shareholder value. The expense representsapproximately 9% of the increase in shareholder value. Cash payments toemployees for our stock-based compensation programs were $119 million in 2006,a 61% increase over 2005.

 

**2005 vs 2004—Highercosts reduced net income by $510 million**

** **

Our stock-based compensationexpense in 2005 reflects the significant increase in the price of our commonshares. Our share price increased 128% from $24.35 to $55.42, adding more than$8 billion of shareholder value. Notwithstanding this increase in our shareprice, cash payments to employees under our stock-based compensation programsonly amounted to $74 million.

 

Our growing internationalpresence and the expansion of our businesses increased our G&A costs duringthe year. Costs reflect more employees, additional travel, and highercompliance and governance costs, combined with increased variable incentivecompensation stemming from our record results. We also incurred additionalcosts related to our disposition activities and the integration of our NorthSea operations acquired in late 2004.

 

**Interest**

 
| **(Cdn$ millions)**  | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest                  |       | 294      |       | 275      |       | 194      |       |
| Less: Capitalized         |       | (241     | )          | (178     | )          | (51      | )          |
| **Net  Interest Expense** | ** ** | **53**   | ** ** | **97**   | ** ** | **143**  | ** ** |
|                      |       |     |       |     |       |     |       |
| Effective  Rate           |       | 6.3      | %          | 6.4      | %          | 6.6      | %          |

 

**2006 vs 2005—Lowernet interest expense increased net income by $44 million**

** **

Our financing costs haveincreased $19 million from 2005. Additional borrowings to finance our 2006capital program increased financing costs by approximately $28 million. Thiswas partially offset however, by the stronger Canadian dollar which decreasedour US-dollar denominated interest by $16 million. The Canexus debt,consolidated with our results, increased our interest expense by $7 million.

 

The amount of interest wecapitalized on our major development projects grew by $63 million, primarilyfrom increased investment in the North Sea Buzzard project, at Long Lake andthe Stage 3 expansion at Syncrude prior to its start-up. We expect interestcapitalized on projects to decrease in 2007 as we ceased capitalizing intereston the Syncrude expansion in August 2006 and on Buzzard in January 2007. Weexpect to continue to capitalize interest on our Long Lake project prior to itscompletion in 2007. Our net interest expense is expected to increase once theseprojects are completed.

 

**2005 vs 2004—Lowernet interest expense increased net income by $46 million**

** **

We acquired our North Seaassets in late 2004. We partially financed this acquisition with US$1 billionof new long-term debt, increasing our interest costs by $87 million in 2005.Interest expense also increased $3 million relating to the Canexus debtconsolidated with our results. However, the stronger Canadian dollar loweredour US-dollar denominated interest by $12 million. During the last two years,we have taken advantage of declining interest rates by replacing ourhigher-cost preferred securities with new long-term debt at lower rates.

 

62

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| Management’s Discussion & Analysis |   | Corporate Expenses |
|---------------------------------------------|--------|--------------------|

 

**Income Taxes**

 
| **(Cdn$ millions)**                                     | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Current                                                      |       | 368      |       | 339      |       | 248      |       |
| Future                                                       |       | 315      |       | (234     | )          | 119      |       |
| **Total  Provision for Income Taxes**                        | ** ** | **683**  | ** ** | **105**  | ** ** | **367**  | ** ** |
|                                                         |       |     |       |     |       |     |       |
| Disclosed  as:                                               |       |     |       |     |       |     |       |
|                                                         |       |     |       |     |       |     |       |
| Provision  for Income Taxes—Continuing Operations       |       | 683      |       | 234      |       | 317      |       |
| Provision  for Income Taxes—Discontinued Operations (1) |       | —   |       | (129     | )          | 50       |       |
| **Total  Provision for Income Taxes**                        | ** ** | **683**  | ** ** | **105**  | ** ** | **367**  | ** ** |
|                                                         |       |     |       |     |       |     |       |
| Effective  Rate                                              |       | 53       | %          | 8        | %          | 32       | %          |

 

----

*Note:*

*(1)*       *See Note 14 to ourConsolidated Financial Statements.*

* *

**2006 vs 2005—Effectivetax rate increases from 8% to 53%**

** **

In early 2006, the UKgovernment substantively enacted increases to the supplementary tax rate on ourNorth Sea oil and gas activities from 10% to 20%, effective January 1, 2006.This increased our future income tax liabilities, resulting in a charge of $277million during the first quarter. During the second quarter, federal andcertain provincial governments in Canada reduced corporate income tax rates.These rate reductions lowered our future income tax liabilities by $32 million.Our effective tax rate excluding the effect of these tax rate changes was 33%.

 

**In 2006, an increase in the UK supplemental tax rate on oil& gas activities resulted in a future income tax expense of $277 million.**

** **

Current income taxes includecash taxes in Yemen of $286 million (2005 - $296 million; 2004 - $227 million).Our current income tax provision also includes federal and state taxes in theUS, cash taxes in Colombia and capital taxes in Canada.

 

**2005 vs 2004—Effectivetax rate decreases from 32% to 8%**

** **

The recovery of future taxespayable of $234 million is attributable to the disposition of our oil and gasproducing properties in Canada and the sale of our chemicals business to theCanexus Limited Partnership. As a result of the dispositions, we revalued ourfuture income tax liabilities for the change in the underlying book and taxvalues. This revaluation resulted in the reduction of our future income taxliabilities. In addition, the disposition gains were taxed at lower capital gainstax rates. Removing the tax impact of the dispositions, the effective tax ratefor our continuing operations was 32%.

 

63

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| Item 7 |   | Management’s Discussion & Analysis |   | Outlook for 2007 |
|--------|--------|---------------------------------------------|--------|------------------|

 

**Other**

 
| **(Cdn$ millions)**                                                       | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Block 51  Arbitration                                                          |       | (151     | )          | —   |       | —   |       |
| Business  Interruption Insurance Proceeds                                      |       | 154      |       | 2        |       | 10       |       |
| Gain on  Dilution of Interest in Chemicals Business                            |       | —   |       | 193      |       | —   |       |
| Gain on  Disposition of Oil and Gas Assets included as Discontinued Operations |       | —   |       | 225      |       | —   |       |
| Increase  (Decrease) in Fair Value of Crude Oil Put Options                    |       | (11      | )          | (196     | )          | 56       |       |

 

During the year, a court ofarbitration concluded that we breached an Area of Mutual Interest agreementwith Occidental Petroleum Corporation (Occidental). As a result, Occidental wasentitled to monetary damages. In late 2006, we agreed to settle the arbitrationby agreeing to pay Occidental US$135 million as monetary damages. No furtheramounts are expected to be payable under the settlement.

 

In 2006, we received $154million of business interruption insurance proceeds related to productionlosses caused by Gulf of Mexico hurricanes in 2005 and by generator failures inour UK operations in 2005.

 

As a result of the sale ofour chemicals business to the Canexus Limited Partnership in 2005, we recordeda gain on the dilution of our interest from 100% to 61.4% of $193 million. Ourgain on the 2005 sale of Canadian oil and gas properties in Alberta, BritishColumbia and Saskatchewan was $225 million.

 

Following our North Seaacquisition in late 2004, we purchased put options on 60,000 bbls/d of oilproduction for 2005 and 2006 to ensure base cash flow in those years while weinvest in our major development projects. These options created an averagefloor price for this production of US$43.17/bbl in 2005 and US$38.17/bbl in2006. Accounting rules require that these options be recorded at fair valuethroughout their term. As a result, changes in forward crude oil prices causegains 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 valueof these options to $200 million. During 2005, a significant increase inforward crude prices reduced the value of these options by $196 million. StrongWTI prices in 2006 reduced the market value of these remaining options to niland we expensed $4 million in 2006 as a result.

 

During 2006, we purchased putoptions on approximately 105,000 bbls/d of our 2007 crude oil production. Theseoptions establish a WTI floor price of US$50/bbl on these volumes, are settledannually and provide a base level of price protection without limiting ourupside to higher prices. The put options were purchased for $26 million and arecarried at fair value. We recorded a loss of $7 million during the year for thedecrease in fair value.

 

**OUTLOOK FOR2007**

** **

In 2007, we plan to invest$2.9 billion in capital projects. Approximately 34% of this capital will beinvested in development projects, which include Long Lake, coalbed methane inCanada, Ettrick in the North Sea, and Wrigley and Tobago in the Gulf of Mexico.We are also directing 14% of our 2007 capital to early-stage developmentprojects expected to contribute production and cash flow growth beyond 2007.These include Knotty Head, Alaminos Canyon Block 856 (Great White West) andRingo in the Gulf of Mexico, additional phases of oil sands in the Athabascaregion and Block 222, offshore West Africa. We have allocated 24% of ourcapital to exploration opportunities in our growth areas. The remaining 28% ofthe 2007 capital will be invested to exploit potential in our existingproducing assets and in other corporate assets.

 

Details of our 2007 capitalinvestment program are included in the Capital Investment section of theMD&A.

 

**DailyProduction**

** **

We expect to grow annualproduction rates after royalties approximately 50% compared to 2006 to between230,000 and 260,000 boe/d (275,000 and 305,000 boe/d before royalties). OurBuzzard development came on stream early January 2007 and we expect to achievepeak rates of 85,000 boe/d during the second quarter of 2007. Othercontributions to our expected growth in 2007 are from the Gulf of Mexico, afull year of production from the Stage 3 expansion at Syncrude and bitumenproduction from Long Lake. Our annual production for 2007 is expected to be:

 

64

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| Management’s Discussion & Analysis |   | Liquidity |
|---------------------------------------------|--------|-----------|

 

**2007Estimated Production**

 
| ** **           | ** ** | **2007 Estimated Production** | ** ** | **2006 Production** | ** ** |
|----------------------|------------|-------------------------------|------------|---------------------|------------|
| ** **           | ** ** | **Before**                    | ** ** | **After**           | ** ** | **Before** | ** ** | **After** | ** ** |
| **(mboe/d)**         | ** ** | **Royalties**                 | ** ** | **Royalties**       | ** ** | **Royalties** | ** ** | **Royalties** | ** ** |
| United  States       |       | 45 - 55                       |       | 38 - 48             |       | 36 |   | 31 |   |
| United  Kingdom      |       | 90 - 100                      |       | 90 - 100            |       | 20 |   | 20 |   |
| Yemen                |       | 60 - 75                       |       | 35 - 45             |       | 93 |   | 52 |   |
| Canada               |       | 45 -50                        |       | 38 - 42             |       | 38 |   | 31 |   |
| Syncrude             |       | 20 -25                        |       | 18 - 20             |       | 19 |   | 17 |   |
| Other  International |       | 6 -7                          |       | 5 - 6               |       | 6 |   | 5 |   |
| **Total**            | ** ** | **275 - 305**                 | ** ** | **230 - 260**       | ** ** | **212** | ** ** | **156** | ** ** |

 

**Cash Flowand Sensitivities**

** **

We expect to generate morethan $3.3 billion in cash flow from operating activities in 2007 (before siterestoration and geological and geophysical expenditures), assuming thefollowing:

 
| WTI (US$/bbl)                                          |   | 50.00 |   |
|--------------------------------------------------------|--------|-------|--------|
| NYMEX  Natural Gas  (US$/mmbtu)                        |   | 6.00  |   |
| Oil &  Gas and Syncrude Operating Costs (Cdn$/boe) |   | 8.00  |   |
| US to  Canadian Dollar Exchange Rate                   |   | 0.88  |   |

 

Changes in commodity pricesand exchange rates impact our annual cash flow from operating activities asfollows:

 
| **(Cdn$ millions)**                    | ** ** | ** ** | ** ** |
|---------------------------------------------|------------|------------|------------|
| WTI—US$1/bbl  Change above US$50       |       | 73         |       |
| WTI—US$1/bbl  Change below US$50       |       | 42         |       |
| NYMEX  Natural Gas—US $1.00/mcf Change |       | 66         |       |
| Exchange  Rate—$0.01 Change            |       | 35         |       |

 

**LIQUIDITY AND CAPITAL RESOURCES**

**Capital Structure**

 
| **(Cdn$ millions)**           | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|------------------------------------|------------|-----------|------------|-----------|------------|
| **Net Debt  (1)**                  |       |      |       |      |       |
| Bank Debt                          |       | 1,410     |       | 171       |       |
| Public Senior Notes                |       | 2,885     |       | 2,980     |       |
| Senior Debt                        |       | 4,295     |       | 3,151     |       |
| Subordinated Debt                  |       | 536       |       | 536       |       |
| Total Debt                         |       | 4,831     |       | 3,687     |       |
| Less: Cash and Cash Equivalents    |       | (101      | )          | (48       | )          |
| **Total  Net debt**                | ** ** | **4,730** | ** ** | **3,639** | ** ** |
|                               |       |      |       |      |       |
| **Shareholders’  Equity (2)** | ** ** | **4,636** | ** ** | **3,996** | ** ** |

 

----

*Notes:*

*(1)*       *Includes all of our debt andis calculated as long-term debt and short-term borrowings less cash and cashequivalents.*

*(2)*       *At January 31, 2007, therewere 262,830,108 common shares and US$460 million of unsecured subordinatedsecurities outstanding. These subordinated securities may be redeemed byissuing common shares at our option after November 8, 2008. The number ofshares issuable depends on the common share price on the redemption date.*

 

65

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| Item 7 |   | Management’s Discussion & Analysis |   | Liquidity |
|--------|--------|---------------------------------------------|--------|-----------|

 

**Net debt**

** **

We use net debt as a keyindicator of our leverage and to monitor the strength of our balance sheet. Netdebt is directly related to our operating cash flows, capital investmentactivities and disposition programs. We ended the year with net debt of $4.7billion, an increase of $1.1 billion from 2005. In 2006, we invested over $3.4billion in capital projects, with more than 50% of this at Long Lake andBuzzard. These major projects did not contribute to cash flow in 2006 but willstart to contribute in 2007 and beyond. We financed our 2006 capital programwith cash flow from operating activities and borrowed US$925 million under ourterm credit facilities.

 

The year-over-year change inour net debt results from:

 
| **(Cdn$ millions)**                                 | ** ** | **2006**  | ** ** | **2005** | ** ** |
|----------------------------------------------------------|------------|-----------|------------|----------|------------|
| Capital  Investment                                      |       | 3,408     |       | 2,638    |       |
| Cash Flow  from Operating Activities                     |       | (2,374    | )          | (2,143   | )          |
| Excess of Capital Investment over Cash Flow              |       | 1,034     |       | 495      |       |
| Net Proceeds  on Disposition of Assets                   |       | (27       | )          | (911     | )          |
| Net Proceeds  from Canexus Initial Public Offering       |       | —    |       | (301     | )          |
| Dividends on  Common Shares                              |       | 52        |       | 52       |       |
| Issue of  Common Shares                                  |       | (48       | )          | (58      | )          |
| Foreign  Exchange Translation of US-dollar Debt and Cash |       | 31        |       | (113     | )          |
| Other                                                    |       | 49        |       | 190      |       |
| **Increase  (Decrease) in Net Debt**                     | ** ** | **1,091** | ** ** | **(646** | **)**      |

 

The change in our net debthas increased our leverage levels as reflected in following ratios:

 
| **(times)**                                      | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net Debt to  Cash Flow from Operating Activities |       | 2.0      |       | 1.7      |       | 2.7      |       |
| Interest  Coverage (1)                           |       | 9.6      |       | 9.7      |       | 11.9     |       |

 

----

*Note:*

*(1)*       *Earnings before interest,taxes, DD&A and exploration expense divided by interest expense (beforecapitalized interest).*

* *

Our business strategy isfocused on value-based growth through full-cycle exploration and development,supplemented by strategic acquisitions when appropriate. We have leveraged ourbalance sheet in the past to accomplish our growth strategy, as most of ourprojects have long-cycle times, requiring significant amounts of capital to beinvested prior to generating cash flows. Historically, we have been successfulwith this strategy as we used leverage to: 

 

•            develop the Masila project in Yemen in 1993; 

•            acquire Wascana in 1997; 

•            repurchase 20 million common shares in 2000;

•            acquire the remaining interest in Aspen in2003;

•            acquire the Buzzard project and other keyassets in the North Sea in 2004;

•            build our first phase of Long Lake, scheduledto be on stream in late 2007; and

•            fund remaining development capital.

 

Each time, we exceeded ourinternal net debt to cash flow target band; however, we successfully broughtour leverage down through asset sales and incremental cash flows. In 2006, weagain increased our leverage levels as a result of capital expenditures on ourmajor development projects at Buzzard and Long Lake. In 2007, we anticipatereducing our net debt to cash flow from operating activities ratio using cashflows from our Buzzard operations, as well as our Long Lake project, expectedto come on stream in 2007.

 

66

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**Change in Working Capital**

 
| **(Cdn$ millions)**                  | ** ** | **2006** | ** ** | **2005** | ** ** | **Increase/  (Decrease)** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|---------------------------|------------|
| Cash and  Cash Equivalents                |       | 101      |       | 48       |       | 53                        |       |
| Restricted  Cash and Margin Deposits      |       | 197      |       | 70       |       | 127                       |       |
| Accounts  Receivable                      |       | 2,951    |       | 3,151    |       | (200                      | )          |
| Inventories  and Supplies                 |       | 786      |       | 504      |       | 282                       |       |
| Future  Income Tax Assets                 |       | 479      |       | —   |       | 479                       |       |
| Accounts Payable  and Accrued Liabilities |       | (3,879   | )          | (3,727   | )          | (152                      | )          |
| Other                                     |       | (1       | )          | (17      | )          | 16                        |       |
| **Total**                                 | ** ** | **634**  | ** ** | **29**   | ** ** | **605**                   | ** ** |

 

Lower natural gas prices reduced our yearend accruals for our marketing accounts receivable and accounts payable. Thishas been offset by higher prices in crude oil markets. We expanded our crudeoil physical and financial trading activities to capture market gains. Thisexpanded activity increased our marketing accounts receivable and accountspayable. We took advantage of lower natural gas prices and expanded our gasstorage inventories by 27 bcf during the year. Volatile gas markets alsoincreased the value of our derivative contract assets and liabilities.

 

Our accounts payable and accruedliabilities have increased since 2005 from higher accrued stock-basedcompensation obligations as a result of our strong share price, higher accrualsrelated to our capital investment programs and our accrual related to the Block51 settlement. We have reclassed $479 million of future income tax assets tocurrent assets. This represents tax loss carry-forward balances in our UKoperations that we expect to use in the next twelve months now that Buzzard ison stream.

 

**Liquidity**

 

We generally rely onoperating cash flows to fund capital requirements and provide liquidity. Webuild 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 developmentprojects and the volatility of commodity prices, it is not unusual in any givenyear for capital expenditures to exceed our cash flow. In addition, we requireliquidity for our energy marketing business. Accordingly, we maintainsignificant committed credit facilities. At December 31, 2006, we had committedterm credit facilities of $3.6 billion that are available until 2011. At yearend, $1,078 million was drawn on these facilities and $294 million of thesefacilities were utilized to support letters of credit. We also had $632 millionof uncommitted, unsecured credit facilities, of which $158 million was drawn atyear end and $252 million was utilized to support letters of credit.

 

From time to time, we accessthe capital markets to meet our financing needs. We also use various financialinstruments to minimize our exposure to fluctuations in commodity prices andforeign exchange. For example, we purchased WTI put options for 2007 tomitigate cash flow volatility. Overall, we manage our capital structure tomaintain flexibility so we can fund our capital programs throughout the highsand lows of the price cycles inherent in the oil and gas business.

 

The following table shows howwe finance our business activities. When our operating cash flows exceed ourinvestment requirements, we generally pay down debt. We borrow or issue equityto fund investment requirements that exceed our operating cash flow.

 
| **(Cdn$ millions)**             | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003**  | ** ** | **2002** | ** ** |
|--------------------------------------|------------|----------|------------|----------|------------|----------|------------|-----------|------------|----------|------------|
| Cash Flow  from Operating Activities |       | 2,374    |       | 2,143    |       | 1,606    |       | 1,405     |       | 1,250    |       |
| Cash Flow  from Investing Activities |       | (3,388   | )          | (1,864   | )          | (4,013   | )          | (1,219    | )          | (1,569   | )          |
| Surplus  (Deficiency)                |       | (1,014   | )          | 279      |       | (2,407   | )          | 186       |       | (319     | )          |
|                                 |       |     |       |     |       |     |       |      |       |     |       |
| Cash Flow  from Financing Activities |       | 1,081    |       | (274     | )          | 1,426    |       | 1,006     |       | 329      |       |
| ** **                           | ** ** | **67**   | ** ** | **5**    | ** ** | **(981** | **)**      | **1,192** | ** ** | **10**   |       |

 

67

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In 2002, we began to investsignificantly in two deep-water Gulf of Mexico projects (Aspen and Gunnison),our Syncrude expansion and our Long Lake project. We accessed public debtmarkets in 2002 to fund these investments. In 2003, Aspen contributedsignificantly to our cash flow and in late 2003, we pre-funded debt repaymentsby raising more than $1 billion in senior and subordinated debt. We used thesefunds in 2004 to repay higher-cost debt, and coupled with acquisition creditfacilities, acquired the North Sea assets. In 2005, we used our cash flow andthe proceeds from asset dispositions to fund our capital program and repaydebt. In 2006, we borrowed approximately $1 billion under our committed termcredit facilities and used our cash flow from operating activities to fund ourcapital program.

 

Our marketing business alsorequires liquidity to support its asset-based trading strategy. We requireliquidity for working capital, cash or credit lines to fund collateralrequirements and to absorb unexpected market or credit losses. The commercialagreements our marketing business enters into often include financial assuranceprovisions that allow Nexen and our counterparties to effectively manage creditrisk. These agreements typically require posting of collateral when adversecredit-related events occur, such as a reduction in credit ratings. Inevaluating our liquidity requirements, we consider the current requirements ofour marketing business as well as additional collateral or other payments thatcould be required in the event of reductions in our credit ratings.

 

**FutureLiquidity**

** **

Our future liquidity isprimarily dependent on cash flows generated from our operations, existingcommitted credit facilities and our ability to access debt and equity markets.Assuming WTI of US$50/bbl, we expect our 2007 cash flow to exceed our capitalinvestment program and dividend requirements by more than $300 million. In July2007, we are required to repay $150 million of medium term notes that becomedue, however, we plan to fund this with our term credit facilities.

 

Our cash flow is sensitive tochanges in commodity prices and exchange rates. For 2007, we expect cash flowof approximately $3.3 billion (before remediation and geological andgeophysical expenditures) assuming:

 
| WTI (US$/bbl)                        |   | 50.00 |   |
|--------------------------------------|--------|-------|--------|
| NYMEX  Natural Gas (US$/mmbtu)       |   | 6.00  |   |
| US to  Canadian Dollar Exchange Rate |   | 0.88  |   |

 

Changes in commodity pricesand exchange rates will impact our cash flow and borrowing requirements. Theimpact of a variance in any one of the above assumptions on our cash flow isdescribed in the Outlook for 2007 section on page 64.

 

**For 2007, we expect cash flow of approximately $3.3 billion.**

** **

We are in the midst of anumber of development projects that require capital to bring them on stream. Weanticipate that we will spend an additional $500 million in 2007 to bring thefirst phase of Long Lake on stream. In addition, we expect to spend $200million in 2007 on furthering our coalbed methane projects in central Albertaand $235 million to complete the Ettrick development in the North Sea by mid2008.

 

While these developmentprojects lack exploration risk, they are subject to other risks includinghigher than anticipated capital costs or delayed start-up. We maintain undrawncommitted credit facilities to manage this risk. In addition to our operatingcash flows and our undrawn committed credit facilities, we have a US$1.5billion shelf prospectus available in the US and Canada.

 

At December 31, 2006, theaverage term to maturity of our long-term debt was 16.6 years. We have thefollowing short and long-term debt maturities during the next five years:

 
| **(Cdn$ millions)**           | ** ** | **2007** | ** ** | **2008** | ** ** | **2009**   | ** ** | **2010** | ** ** | **2011**  | ** ** |
|------------------------------------|------------|----------|------------|----------|------------|------------|------------|----------|------------|-----------|------------|
| Uncommitted  Credit Facilities     |       | 158      |       | —   |       | —     |       | —   |       | —    |       |
| Term Credit  Facilities (1)        |       | —   |       | —   |       | —     |       | —   |       | 1,078     |       |
| Canexus LP  Term Credit Facilities |       | —   |       | —   |       | —     |       | 174      |       | —    |       |
| Debentures                         |       | —   |       | —   |       | —     |       | —   |       | —    |       |
| Medium Term  Notes                 |       | 150      |       | 125      |       | —     |       | —   |       | —    |       |
| **Total**                          | ** ** | **308**  | ** ** | **125**  | ** ** | **—** | ** ** | **174**  | ** ** | **1,078** | ** ** |

 

----

*Note:*

*(1)**      **$3.6 billion available until 2011.*

 

68

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| Management’s Discussion & Analysis |   | Contractual Obligations |
|---------------------------------------------|--------|-------------------------|

 

With our expected cash flowstreams, commodity price and hedging strategies, current levels of liquidity,and access to debt and equity markets, we expect to be able to fund our plannedcapital programs, dividend requirements and debt repayments, or meet otherobligations that may arise from our oil and gas, chemicals and marketingoperations.

 

In 2006 we declared commonshare dividends of $0.20 per share (2005—$0.20, 2004—$0.20). We expect to declarecommon share dividends of $0.20 per share in 2007.

 

**ContractualObligations, Commitments and Guarantees**

 

We assume various contractualobligations and commitments in the normal course of our operations andfinancing activities. We have considered these obligations and commitments inassessing our cash requirements, as noted in the above discussion of futureliquidity. They include:

 
| ** **                                     | ** ** | **Payments** | ** ** |
|------------------------------------------------|------------|--------------|------------|
| **(Cdn$ millions)**                       | ** ** | **Total**    | ** ** | **<1 year** | ** ** | **1-3 years** | ** ** | **4-5 years** | ** ** | **>5 years** | ** ** |
| Short-Term  and Long-Term Debt                 |       | 4,831        |       | 308 |   | 125 |   | 1,252 |   | 3,146 |   |
| Interest on  Long-Term Debt                    |       | 4,859        |       | 215 |   | 406 |   | 403 |   | 3,835 |   |
| Operating  Leases (1)                          |       | 752          |       | 44 |   | 236 |   | 240 |   | 232 |   |
| Capital  Leases                                |       | 119          |       | 5 |   | 10 |   | 10 |   | 94 |   |
| Energy  Commodity Contract Liabilities         |       | 524          |       | 325 |   | 191 |   | 8 |   | — |   |
| Transportation  and Storage Commitments (1)    |       | 927          |       | 424 |   | 262 |   | 123 |   | 118 |   |
| Work  Commitments and Purchase Obligations (2) |       | 1,460        |       | 663 |   | 419 |   | 218 |   | 160 |   |
| Asset  Retirement Obligations                  |       | 1,770        |       | 21 |   | 42 |   | 34 |   | 1,673 |   |
| **Total**                                      | ** ** | **15,242**   | ** ** | **2,005** | ** ** | **1,691** | ** ** | **2,288** | ** ** | **9,258** | ** ** |

 

----

*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 canbe financial or non-financial. Financial obligations are known future cashpayments that we must make under existing contracts, such as debt and leasearrangements. Non-financial obligations are contractual obligations to performspecified activities such as work commitments. Commercial commitments arecontingent obligations that become payable only if certain pre-defined eventsoccur.

 

•      Short-termand long-term debt amounts are included on our December 31, 2006 ConsolidatedBalance Sheet.

 

•      Operatingleases include the minimum lease payment obligations associated with leases foroffice space, rail cars, vehicles and our processing agreement that allows ourAspen production to flow through Shell’s processing facilities at theBullwinkle platform. The terms of the processing agreement give Shell an annualoption to take payment in cash or in kind. For 2007, Shell has elected to takepayment in kind, so the 2007 obligation has been excluded from this table.Instead, it is shown as a royalty and excluded from reserves and production.

 

•      Capitalleases include pipeline commitments primarily related to future production atLong Lake.

 

•      Energycommodity contract liabilities include the purchase and sale of physical quantitiesof oil and natural gas, and financial derivatives used to manage our exposureto commodity prices. For contracts where the price is based on an index, theamount is based on forward market prices at December 31, 2006. For certaincontracts, we may net settle.

 

•      Workcommitments include non-discretionary capital spending related to drilling,seismic, construction of facilities and other development commitments in ourinternational operations, and includes Long Lake ($157 million) and the Ettrickdevelopment in the North Sea ($233 million). The timing of certain payments isdifficult to determine with certainty. The table has been prepared using ourbest estimates; the remainder of our 2007 capital investment is discretionary.

 

•      Wealso have included work commitments relating to drilling rigs, which have beencontracted to work for us in the North Sea and Gulf of Mexico, totalling $414million over the next five years.

 

69

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| Item 7 |   | Management’s Discussion & Analysis |   | Contractual Obligations |
|--------|--------|---------------------------------------------|--------|-------------------------|

 

**•****                 **We have $1,770 million of undiscounted assetretirement obligations after inflation. As of December 31, 2006, the discountedvalue ($704 million) of these estimated obligations has been provided for inour Consolidated Financial Statements (including $21 million of currentliabilities). The timing of any payments is difficult to determine withcertainty, and the table has been prepared using our best estimates.

 

**•****                 **We have unfunded obligations under our definedbenefit pension plans of $122 million (Nexen—$67 million; Canexus—$8 million;Syncrude—$47 million). Our obligations for Nexen and Canexus include $54million that is unfunded as a result of statutory limitations. Theseobligations are backed by irrevocable letters of credit.

 

**•****                 **We have excluded obligations on our tandemoption and stock appreciation rights programs as the amount and timing of cashpayments are indeterminable.

 

**•****                 **We have excluded our normal purchasearrangements as they are discretionary and are reflected in our expected cashflow from operating activities and our expected capital expenditures for 2007.

 

**•****                 **We have excluded our future income taxliabilities as the amount and timing of any cash payments for income taxes arebased primarily on taxable income for each fiscal year in the variousjurisdictions in which we operate.

 

From time to time, we enterinto contracts that require us to indemnify parties against possible claims,particularly when these contracts relate to the sale of assets. On occasion, weprovide indemnifications to the purchaser. Generally, a maximum obligation isnot stated; therefore, the overall maximum amount cannot be reasonablyestimated. We have not made any significant payments related to theseindemnifications. We believe these matters would not have a material adverseeffect on our liquidity, financial condition or results of operations.

 

**CreditRatings**

 

Currently, our senior debt israted Baa2 by Moody’s Investor Service, Inc. (Moody’s), BBB by Dominion BondRating Service (DBRS) and BBB- by Standard & Poor’s (S&P). In addition,Moody’s and DBRS currently rate our outlook as stable while S&P has apositive outlook. Our strong financial results, ample liquidity and financialflexibility continue to support our credit ratings.

 

**FinancialAssurance Provisions in Commercial Contracts**

 

The commercial agreements ourmarketing group enters into often include financial assurance provisions thatallow Nexen and our counterparties to effectively manage credit risk. Theagreements normally require posting of collateral when adverse credit-relatedevents occur such as a reduction in credit ratings. Based on the contracts inplace and commodity prices at December 31, 2006, we could be required to postcollateral of up to $1,149 million if we were downgraded to non-investmentgrade. These obligations are already reflected on our balance sheet. Theposting of collateral merely accelerates the payment of such amounts. Just aswe may be required to post collateral in the event of a downgrade belowinvestment grade, we have similar provisions in many of our contracts thatallow us to demand certain counterparties post collateral for amounts owing tous if they are downgraded to non-investment grade.

 

**Off-BalanceSheet Arrangements**

 

We have no off-balance sheetarrangements that would have a material adverse effect on our liquidity,consolidated financial position or results of operations. We use operatingleases in the normal course of business as disclosed in ContractualObligations, Commitments and Guarantees on page 69 and in Note 15 to theConsolidated Financial Statements in Item 8, which is incorporated herein byreference. At December 31, 2006, we had outstanding letters of credit amountingto $294 million and $252 million supported by our committed term creditfacilities and our uncommitted credit facilities, respectively.

 

**Contingencies**

 

We have no contingencies thatwould have a material adverse effect on our liquidity, consolidated financialposition or results of operations. See Note 15 to the Consolidated FinancialStatements in Item 8, which is incorporated herein Moody’s by reference for adiscussion of our contingencies.

 

70

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| Management’s Discussion & Analysis |   | Critical Accounting Estimates |
|---------------------------------------------|--------|-------------------------------|

 

**CRITICALACCOUNTING ESTIMATES**

 

We make estimates andassumptions that affect the reported amounts of our assets and liabilities andthe disclosure of contingent assets and liabilities at the date of theConsolidated Financial Statements and our revenues and expenses during thereporting period. Our management reviews these estimates, including thoserelated to accruals, litigation, environmental and asset retirementobligations, income taxes, derivative contract assets and liabilities and the determinationof proved reserves on an ongoing basis. Changes in facts and circumstances mayresult in revised estimates and actual results may differ from these estimates.Our critical accounting estimates are discussed below.

 

**Oil and GasAccounting—Reserves Determination**

 

We follow the successfulefforts method of accounting for our oil and gas activities, as described inNote 1 to our Consolidated Financial Statements. Successful efforts accountingdepends on the estimated reserves we believe are recoverable from our oil andgas properties.

 

The process of estimatingreserves is complex. It requires significant judgements and decisions based onavailable geological, geophysical, engineering and economic data. To estimatethe economically recoverable oil and natural gas reserves and related futurenet cash flows, we incorporate many factors and assumptions including:

 

•                  expected reservoir characteristics based ongeological, geophysical and engineering assessments;

 

•                  future production rates based on historicalperformance and expected future operating and investment activities;

 

•                  future oil and gas prices and qualitydifferentials;

 

•                  assumed effects of regulation by governmentalagencies; and

 

•                  future development and operating costs.

 

We believe these factors andassumptions are reasonable based on the information available to us at the timewe prepare our estimates. However, these estimates may change substantially asadditional data from ongoing development activities and production performancebecomes available and as economic conditions impacting oil and gas prices andcosts change.

 

Management is responsible forestimating the quantities of proved oil and natural gas reserves and forpreparing related disclosures. Estimates and related disclosures are preparedin accordance with SEC requirements, generally accepted industry practices inthe US and the standards of the Canadian Oil and Gas Evaluation Handbookmodified to reflect SEC requirements.

 

Reserve estimates for eachproperty are internally prepared at least annually by the property’s reservoirengineer. They are reviewed by engineers familiar with the property and bydivisional management. An Executive Reserves Committee, including our CEO, CFOand board-appointed internal qualified reserves evaluator, meet with divisionalreserves personnel to review the estimates and any changes from previousestimates.

 

The internal qualifiedreserves evaluator assesses whether our reserves estimates and the *Standardized Measure of Discounted Future Net Cash Flowsand Changes Therein*, included in the Supplementary FinancialInformation, have been prepared in accordance with our reserve standards. Hisopinion stating that the reserves information has, in all material respects,been prepared according to our reserves standards is included in an exhibit tothis Form 10-K.

 

Our reserves are based oninternal estimates. To increase our confidence in our estimates, we have atleast 80% of our oil and gas and Syncrude reserves assessed (i.e., eitherevaluated or audited) annually by independent qualified reserves consultants.Given that reserve estimates are based on numerous assumptions, interpretationsand judgements, differences frequently arise between the estimates prepared bydifferent qualified estimators. When the initial estimate on the portfolio ofproperties differs by greater than 10%, we work with the independent reservesconsultant to reconcile the difference to within 10%. Estimates pertaining toindividual properties within the portfolio often differ by significantly morethan 10%, either positively or negatively. We do not attempt to resolve eachproperty to within 10% as it would be time and cost prohibitive given thenumber of wells in which we have an interest.

 

71

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| Item 7 |   | Management’s Discussion & Analysis |   | Critical Accounting Estimates |
|--------|--------|---------------------------------------------|--------|-------------------------------|

 

At December 31, 2006, we had98% of our oil and gas and Syncrude reserves before royalties (98% afterroyalties) assessed by independent engineers. DeGolyer and MacNaughtonperformed evaluations of our proved reserves for each of the Masila Block(Yemen), Block 51 (Yemen), Usan (Nigeria) and our United Kingdom properties.McDaniel & Associates Consultants Ltd. (McDaniel) prepared one evaluationcomprising a portion of our Canadian conventional, coalbed methane and LongLake properties. An evaluation is a process whereby a qualified reservesevaluator prepares their estimate of the remaining quantities of oil and gasreserves by assessing and interpreting all available data on a reservoir toallow them to assess whether our estimates are reasonable. McDaniel performedan audit of our Syncrude interest. Ryder Scott Company audited a portion of ourUS Gulf of Mexico shelf properties. William M. Cobb & Associates, Inc. auditedour US Gulf of Mexico deep-water properties. An audit is a process whereby anindependent qualified reserves auditor reviews our estimates, supporting workpapers and other data as they feel is necessary to prepare their estimate ofremaining quantities of oil and gas reserves to allow them to assess whetherour estimates are reasonable.

 

The board of directors hasestablished a Reserves Review Committee (Reserves Committee) to assist theboard and the Audit and Conduct Review Committee to oversee the annual reviewof our oil and gas reserves and related disclosures. The Reserves Committee iscomprised of three or more directors, the majority of whom are independent, andeach being familiar with estimating oil and gas reserves. The ReservesCommittee 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 witheach of the internal qualified reserves evaluator and independent reservesconsultants, independent of management, to review the scope of their work,whether they have had access to sufficient information, the nature andsatisfactory resolution of any material differences of opinion, and in the caseof the independent reserves consultants, their independence.

 

The Reserves Committee hasreviewed Nexen’s procedures for preparing the reserves estimates and relateddisclosures. It has reviewed the information with management, and met with theinternal qualified reserves evaluator and the independent qualified reservesconsultants. As a result of this, the Reserves Committee is satisfied that theinternally-estimated reserves are reliable and free of material misstatement.Based on the recommendation of the Reserves Committee, the board has approvedthe reserves estimates and related disclosures in the Form 10-K.

 

Reserves estimates arecritical to many of our accounting estimates, including:

 

**•****                 **Determining whether or not an exploratory wellhas found economically producible reserves. If successful, we capitalize thecosts of the well, and if not, we expense the costs immediately. In 2006, $169million of our total $289 million spent on exploration drilling was expensed.If none of our exploration drilling had been successful, our net income wouldhave decreased by $120 million.

 

**•****                 **Calculating our unit-of-production depletionrates. Both proved and proved developed reserves estimates are used todetermine rates that are applied to each unit-of-production in calculating ourdepletion expense. Proved reserves are used where a property is acquired andproved developed reserves are used where a property is drilled and developed.In 2006, oil and gas depletion of $741 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 havechanged by approximately $74 million, assuming no other changes to our reservesprofiles.

 

**•****                 **Assessing, when necessary, our oil and gasassets for impairment. Estimated future undiscounted cash flows are determinedusing 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 loancovenants directly linked to reserves, it would take a significant decrease inour proved reserves to limit our ability to borrow money under our term creditfacilities, as previously described in the Liquidity section of the MD&A.

 

**Property,Plant and Equipment—Impairment**

 

We evaluate our long-livedassets (oil and gas properties, Syncrude and chemicals) for impairment if anadverse event or change occurs. Among other things, this might include fallingoil and gas prices, a significant negative revision to our reserves estimates,changes in operating and capital costs, or significant or adverse politicalchanges. If one of these occurs, we assess estimated undiscounted future cashflows for affected properties

 

72

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to determine if they areimpaired. If the undiscounted future cash flows for a property are less thanthe carrying amount of that property, we calculate its fair value using adiscounted cash flow approach. The property is then written down to its fairvalue. We assessed our oil and gas assets for impairment at the end of 2006 andrecorded an impairment charge of $93 million, primarily related to two naturalgas producing properties in the Gulf of Mexico.

 

Cash flow estimates for ourimpairment assessments require assumptions about two primary elements—futureprices and reserves. Our estimates of future prices require significantjudgements about highly uncertain future events. Historically, oil and gasprices have exhibited significant volatility—over the last five years, pricesfor WTI and NYMEX gas have ranged from US$18/bbl to US$79/bbl and US$2/mmbtu toUS$16/mmbtu, respectively. Our forecasts for oil and gas revenues are based onprices derived from a consensus of future price forecasts amongst industryanalysts and our own assessments. Our estimates of future cash flows generallyassume our long-term price forecast and forecast operating and developmentcosts. Given the significant assumptions required and the possibility thatactual conditions will differ, we consider the assessment of impairment to be acritical accounting estimate. A change in these estimates would impact allexcept our chemicals and energy marketing businesses.

 

It is difficult to determineand assess the impact of a decrease in our proved reserves on our impairmenttests. The relationship between the reserves estimate and the estimatedundiscounted cash flows, and the nature of the property-by-property impairmenttest, is complex. As a result, we are unable to provide a reasonablesensitivity analysis of the impact that a reserves estimate decrease would haveon our assessment of impairment.

 

**AssetRetirement Obligations**

 

We are required to remove orremedy the effect of our activities on the environment at our present andformer operating sites by dismantling and removing production facilities andremediating any damage caused. Estimating our future asset retirementobligations requires us to make estimates and judgments with respect toactivities that will occur many years into the future. In addition, theultimate financial impact of environmental laws and regulations is not alwaysclearly known and cannot be reasonably estimated as standards evolve in thecountries in which we operate.

 

We record asset retirementobligations in our consolidated financial statements by discounting the presentvalue of the estimated retirement obligations associated with our oil and gaswells and facilities, Syncrude assets and chemical plants. In arriving atamounts recorded, numerous assumptions and judgments are made with respect toultimate settlement amounts, inflation factors, credit-adjusted discount rates,timing of settlement and expected changes in legal, regulatory, environmentaland political environments. The asset retirement obligations we have recordedresult in an increase to the carrying cost of our property, plant andequipment. The obligations are accreted with the passage of time. A change inany one of our assumptions could impact our asset retirement obligations, thecarrying value of our property, plant and equipment and our net income.

 

It is difficult to determinethe impact of a change in any one of our assumptions. As a result, we areunable to provide a reasonable sensitivity analysis of the impact a change inour assumptions would have on our financial results.

 

**BusinessCombination—Purchase Price Allocation**

 

During the fourth quarter of2004, we acquired a company operating and exploring oil and gas propertieslocated in the North Sea. We accounted for this acquisition using the purchasemethod of accounting. Under this method, we were required to record on ourConsolidated Balance Sheet the estimated fair values of the acquired company’sassets and liabilities at the acquisition date. The excess of the purchaseprice over the fair values of the tangible and intangible net assets acquiredwas recorded as goodwill.

 

We made various assumptionsin determining the fair values of the acquired company’s assets andliabilities. The most significant assumptions and judgments relate to theestimation of the fair value of the oil and gas properties. To determine thefair value of these properties, we estimated (a) oil and gas reserves inaccordance with our reserve standards, (b) additional reserves potential and(c) future prices of oil and gas.

 

Our reserve estimates werebased on the work performed by our engineers and outside consultants. Thejudgments associated with these estimated reserves are described earlier in ourcritical accounting estimates discussion entitled “Oil and GasAccounting—Reserves Determination”. Our estimates of future prices were basedon prices derived from a consensus of future price forecasts amongst industryanalysts and our own assessments. The judgments associated with these estimatesare described earlier in our critical accounting estimates discussion entitled “Oiland Gas Accounting—Impairment”.

 

73

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| Item 7 |   | Management’s Discussion & Analysis |   | New Accounting Pronouncements |
|--------|--------|---------------------------------------------|--------|-------------------------------|

 

We applied our estimatedfuture prices to the estimated reserves quantities acquired, and we estimatedfuture operating and development costs, to arrive at estimated future netrevenues for the properties acquired. For proved properties, we discounted thefuture net revenues using after-tax discount rates. The same principles wereapplied in arriving at the fair value of unproved properties acquired. Theseunproved properties generally represent the value of the probable and possible reserves.Because of their very nature, probable and possible reserve estimates are moreimprecise than those of proved reserves. To compensate for the inherent risk ofestimating and valuing unproved reserves, an appropriate risk-weighting factorwas applied to the discounted future net revenues of the probable and possiblereserves in each particular instance.

 

If the fair value allocatedto oil and gas properties acquired had been decreased by $50 million, futureincome tax liabilities would have decreased by $20 million and goodwill wouldhave increased by $30 million.

 

**FutureIncome Taxes**

 

We follow the liabilitymethod of accounting for income taxes whereby future income tax assets andliabilities are recognized based on temporary differences in reported amountsfor financial statement and tax purposes. We carry on business in severalcountries and as a result, we are subject to income taxes in numerousjurisdictions. The determination of our income tax provision is inherentlycomplex and we are required to interpret continually changing regulations andmake certain judgments. While income tax filings are subject to audits andreassessments, we believe we have made adequate provision for all income taxobligations. However, changes in facts and circumstances as a result of incometax audits, reassessments, jurisprudence and any new legislation may result inan increase or decrease in our provision for income taxes.

 

**NEWACCOUNTING PRONOUNCEMENTS**

** **

**CanadianPronouncements**

 

In an effort to harmonizeCanadian GAAP with US GAAP, the Canadian Accounting Standards Board (AcSB) hasissued sections:

 

**•****                 **1530, *ComprehensiveIncome;*

 

**•****                 **3855, *FinancialInstruments—Recognition and Measurement;*and

 

**•****                 **3865, *Hedges.*

 

Under these new standards,all financial assets should be measured at fair value with the exception ofloans, receivables and investments that are intended to be held to maturity andcertain equity investments, which should be measured at cost. Similarly, allfinancial liabilities should be measured at fair value when they are held fortrading or they are derivatives.

 

Gains and losses on financialinstruments measured at fair value will be recognized in the income statementin the periods they arise with the exception of gains and losses arising from:

 

•                  financial assets held for sale, for whichunrealized gains and losses are deferred in other comprehensive income untilsold or impaired; and

 

•                  certain financial instruments that qualify forhedge accounting.

 

Sections 3855 and 3865 makeuse of “other comprehensive income”. Other comprehensive income comprisesrevenues, expenses, gains and losses that are recognized in comprehensiveincome, but are excluded from net income. Unrealized gains and losses onqualifying hedging instruments, translation of self-sustaining foreignoperations, and unrealized gains or losses on financial instruments availablefor sale will be included in other comprehensive income and reclassified to netincome when realized. Comprehensive income and its components will be arequired disclosure under the new standard.

 

These new standards areeffective for fiscal years beginning on or after October 1, 2006 and earlyadoption is permitted. Adoption of these standards as at December 31, 2006would have the following impact on our Consolidated Financial Statements:

 
| ** **                                          | ** ** | **Increase/**  | ** ** |
|-----------------------------------------------------|------------|----------------|------------|
| **(Cdn$ millions)**                            | ** ** | **(Decrease)** | ** ** |
| Accounts  Receivable                                |       | 25             |       |
| Future  Income Tax Liabilities                      |       | 7              |       |
| Cumulative  Foreign Currency Translation Adjustment |       | 161            |       |
| Accumulated  Other Comprehensive Income             |       | (143           | )          |

 

74

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In March 2006, the CICA’sEmerging Issues Committee (EIC) issued Abstract 160, *Stripping Costs Incurred in the Production Phase of a Mining Operation*(EIC-160). EIC-160 outlines accounting for overburden and mine waste materialsremoved in the process of accessing mineral deposits according to the benefitreceived by the entity. Generally, stripping costs should be accounted for asvariable production costs and included in the costs of inventory produced inthe period the stripping costs are incurred. If it can be shown that thestripping was for betterment of the mineral property, stripping costs should becapitalized. The standard outlines the requirement for amortization ofcapitalized stripping costs as well as a reconciliation of stripping costsincurred in the production phase. EIC-160 is effective for fiscal yearsbeginning on or after July 1, 2006. We do not expect the adoption of EIC-160will have any material impact on our results of operations or financial position.

 

In July 2006, the EIC issuedAbstract 162, *Stock-Based Compensation forEmployees Eligible to Retire Before the Vesting Date* (EIC-162).EIC-162 provides that if an employee is eligible to retire on the grant date ofa stock-based award, related compensation expense is recognized in full at thatdate as there is no ongoing service requirement to earn the award. In addition,if the employee becomes eligible to retire during the vesting period, relatedcompensation expense is recognized over the period from the grant date to theretirement eligibility date on a graded vesting basis. EIC-162 is effective forinterim and annual periods ending on or after December 31, 2006. We adoptedEIC-162 on a retroactive basis in the fourth quarter of 2006. For the year endedDecember 31, 2006, the impact of adopting EIC-162 decreased general andadministrative expense by $9 million, increased provision for future incometaxes by $3 million, increased net income $6 million, and increased basic anddiluted earnings per share by $0.02/share. For the year ended December 31,2005, the impact of adopting EIC-162 increased general and administrativeexpense by $17 million, decreased provision for future income taxes by $5million, reduced net income by $12 million, and reduced basic and dilutedearnings per share by $0.05/share. The impact on the year ended December 31,2004 was immaterial.

 

In December 2006, the AcSBissued two new Sections in relation to financial instruments: Section 3862, *Financial Instruments – Disclosures*, andSection 3863, *Financial Instruments –Presentation*. Both sections will become effective for annual andinterim periods beginning on or after October 1, 2007 and will requireincreased disclosure of financial instruments.

 

In December 2006, the AcSBissued Section 1535, *Capital Disclosures*,requiring disclosure of information about an entity’s managing capital. Thestandard is effective for annual periods beginning on or after October 1, 2007.

 

**USPronouncements**

 

On January 1, 2006, weadopted FASB Statement 123 (revised), *Share-BasedPayment* (Statement 123(R)) using the modified-prospective approachand graded-vesting amortization. Under Statement 123(R), our tandem options andstock appreciation rights are considered liability-based stock compensation plans.Under the modified-prospective approach, no amounts are restated in priorperiods. Upon adoption of Statement 123(R), we recorded a cumulative effect ofa change in accounting principle of $2 million. This amount was recorded ingeneral and administrative expenses during the first quarter of 2006 in our USGAAP Consolidated Statement of Income.

 

Prior to the adoption ofStatement 123(R), we accounted for our liability-based stock compensation plansin accordance with FASB Interpretation 28, *Accountingfor Stock Appreciation Rights and Other Variable Stock Option or Award Plans*(the intrinsic-value method). Accordingly, obligations were accrued on agraded-vesting basis and represented the difference between the market value ofour common shares and the exercise price of underlying options and rights.Under Statement 123(R), obligations for liability-based stock compensationplans are measured at their fair value, and are re-measured at fair value ineach subsequent reporting period.

 

Consistent with Statement123(R), we account for any stock options that do not include a cash feature(equity-based stock compensation plans), using the fair-value method.

 

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The impact of adoptingStatement 123(R) on our results for the year ended December 31, 2006 is asfollows:

 
| ** **                                                          | ** ** | **Prior to**    | ** ** | **After**       | ** ** | ** **     | ** ** |
|---------------------------------------------------------------------|------------|-----------------|------------|-----------------|------------|----------------|------------|
| ** **                                                          | ** ** | **Adoption of** | ** ** | **Adoption of** | ** ** | **Increase/**  | ** ** |
| **(Cdn$ millions, except per  share amounts)**                 | ** ** | **FAS 123(R)**  | ** ** | **FAS 123(R)**  | ** ** | **(Decrease)** | ** ** |
| Income from  Continuing Operations before Income Taxes—US GAAP |       | 1,306           |       | 1,264           |       | (42            | )          |
| Net  Income—US GAAP                                            |       | 608             |       | 579             |       | (29            | )          |
| Basic  Earnings per Common Share—US GAAP ($/share)             |       | 2.32            |       | 2.21            |       | (0.11          | )          |
| Diluted  Earnings per Common Share—US GAAP ($/share)           |       | 2.26            |       | 2.15            |       | (0.11          | )          |

 

We recognize stock-basedcompensation expense for our retired and retirement-eligible employees over anaccelerated graded vesting period in accordance with the provisions ofStatement 123(R) for stock-based awards granted to employees after December 31,2005. For stock-based awards granted prior to the adoption of Statement 123(R),stock-based compensation expense for our retired and retirement-eligibleemployees is recognized over a graded vesting period. If we applied theaccelerated vesting provisions of Statement 123(R) to stock-based awardsgranted to our retired and retirement-eligible employees prior to the adoptionof Statement 123(R), there would be no material change to our stock-basedcompensation expense for the three years ended December 31, 2006.

 

In February 2006, the FASBissued Statement 155, *Accounting for CertainHybrid Instruments*, which amends Statement 133, *Accounting for Derivative Instruments and HedgingActivities*, and Statement 140, *Accountingfor Transfers and Servicing of Financial Assets and Extinguishments of Liabilities*.Statement 155 permits fair value re-measurement of hybrid financial instrumentsthat contain an embedded derivative that otherwise would require bifurcationfrom its host contract in accordance with Statement 133. Statement 155 alsoclarifies and amends certain other provisions of Statement 133 and Statement140. This statement is effective for all financial instruments acquired orissued in fiscal years beginning after September 15, 2006. We do not expect theadoption of this statement will have a material impact on our results ofoperations or financial position.

 

In July 2006, FASB issued FIN48 *Accounting for Uncertainty in IncomeTaxes* with respect to FAS 109 *Accountingfor Income Taxes* regarding accounting for and disclosure of uncertaintax positions. FIN 48 seeks to reduce the diversity in practice associated withcertain aspects of the recognition and measurement related to accounting forincome taxes and is effective for fiscal years beginning after December 15,2006. Adoption of this standard is expected to increase our future income taxliabilities by no more than $30 million and decrease our retained earnings by acorresponding amount.

 

In September 2006, FASBissued Statement 157, *Fair ValueMeasurements*. Statement 157 defines fair value, establishes aframework for measuring fair value under US generally accepted accountingprinciples and expands disclosures about fair value measurements. Thisstatement is effective for fiscal years beginning after November 15, 2007. Wedo not expect the adoption of this statement will have a material impact on ourresults of operations or financial position.

 

In September 2006, FASBissued Statement 158, *Employers’ Accountingfor Defined Benefit Pension and Other Postretirement Plans*.Statement 158 requires an employer to recognize the over-funded or under-fundedstatus of a defined benefit post-retirement plan on the balance sheet as anasset or liability and to recognize changes in funded status throughcomprehensive income. This statement also requires measurement of the fundedstatus of a plan as of the balance sheet date. The recognition and disclosuresunder Statement 158 are required for fiscal years ending after December 15,2006 while the new measurement date is effective for fiscal years ending afterDecember 15, 2008. We adopted the recognition and disclosure provisions atDecember 31, 2006 in our US GAAP presentation. We do not expect the adoption ofthe change in measurement date in 2008 to have a material impact on our resultsof operations or financial position.

 

76

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| Management’s Discussion & Analysis |   | Market Risks |
|---------------------------------------------|--------|--------------|

 

**ITEM 7A. QUANTITATIVE ANdqUALITATIVE dISCLOSURES ABOUT MARKET RISK**

 

We are exposed to normalmarket risks inherent in the oil and gas, Syncrude, energy marketing andchemicals businesses, including commodity price risk, foreign-currency raterisk, interest rate risk and credit risk. We recognize these risks and manageour operations to minimize our exposures to the extent practical.

 

**NON-TRAdING**

** **

**CommodityPrice Risk**

 

Commodity price risk relatedto conventional and synthetic crude oil prices is our most significant marketrisk exposure. Crude oil and natural gas are commodities which are sensitive tonumerous worldwide factors, many of which are beyond our control, and aregenerally sold at contract or posted prices. Changes in world crude oil andnatural gas prices may significantly affect our results of operations and cashgenerated from operating activities. Consequently, such prices also may affectthe value of our oil and gas properties and our level of spending for oil andgas exploration and development.

 

Our crude oil prices arebased on various reference prices, primarily the WTI crude oil reference priceand other prices which generally track the movement in WTI. Adjustments aremade to the reference prices to reflect quality differentials andtransportation. WTI and other international reference prices are affected bynumerous and complex worldwide factors such as supply and demand fundamentals,economic outlooks, production quotas set by the Organization of PetroleumExporting Countries and political events. Quality differentials are affected bylocal supply and demand factors.

 

To a lesser extent we arealso exposed to natural gas price movements. Natural gas prices are generallyinfluenced by oil prices and North American supply and demand, and to a lesserextent local market conditions.

 

In 2006, WTI averagedUS$66.22/bbl reaching a high of US$78.40/bbl and a low of US$54.86/bbl. NYMEXnatural gas prices averaged US$6.99/mmbtu in 2006, reaching a high ofUS$11.00/mmbtu and a low of US$4.05/mmbtu. Our sensitivities to commodityprices and the expected impact on our 2007 cash flow from operating activitiesand net income are as follows:

 
| **(Cdn$ millions)**                   | ** ** | **Cash Flow** | ** ** | **Net Income** | ** ** |
|--------------------------------------------|------------|---------------|------------|----------------|------------|
| WTI—US$1/bbl  Change above US$50      |       | 73            |       | 46             |       |
| WTI—US$1/bbl  Change below US$50      |       | 42            |       | 26             |       |
| NYMEX  Natural Gas—US$1.00/mcf Change |       | 66            |       | 56             |       |

 

These sensitivities tochanges in benchmark prices for crude oil and natural gas are based on ourestimated 2007 production levels for crude oil and natural gas and assume aCanadian/US dollar exchange rate of $0.88. Our estimated crude oil and naturalgas production range for 2007 is between 275,000 and 305,000 boe/d beforeroyalties, of which natural gas represents approximately 18%.

 

The majority of our oil andgas production is sold under short-term contracts, exposing us to short-termprice movements. Other energy contracts we enter into also expose us tocommodity 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 2006, we purchased WTI putoptions to manage the commodity price risk exposure on a portion of our oilproduction in 2007, by establishing an annual average WTI floor price ofUS$50/bbl on 105,000 bbls/d of production.

 

**ForeignCurrency Risk**

 

A substantial portion of ouractivities are transacted in or referenced to US dollars including:

 

•                  sales of crude oil, natural gas and certainchemicals products;

 

•                  capital spending and expenses for our oil andgas, Syncrude and chemicals operations; and

 

•                  short-term and long-term borrowings.

 

The Canadian/US dollarexchange rate averaged $0.88 in 2006 with a high of $0.91 and a low of $0.85.

 

77

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| Item 7 |   | Management’s Discussion & Analysis |   | Market Risks |
|--------|--------|---------------------------------------------|--------|--------------|

 

Our sensitivities to the USdollar and the expected impact of a one cent change on our 2007 cash flow fromoperating activities, net income, capital expenditures and long-term debt areas follows:

 
| ** **                             | ** ** | ** **    | ** ** | ** **     | ** ** | **Capital**      | ** ** | **Long-Term** | ** ** |
|----------------------------------------|------------|---------------|------------|----------------|------------|------------------|------------|---------------|------------|
| **(Cdn$ millions)**               | ** ** | **Cash Flow** | ** ** | **Net Income** | ** ** | **Expenditures** | ** ** | **Debt**      | ** ** |
| $0.01 Change  in US to Canadian Dollar |       | 35            |       | 12             |       | 19               |       | 31            |       |

 

Our sensitivities to changesin the Canadian/US dollar exchange rate are calculated based on projectedrevenues, expenses, capital expenditures and US-dollar denominated long-termdebt for 2007. These estimates are based on a WTI price for crude oil of US$50/bbl,a NYMEX natural gas price of US$6/mmbtu, operating costs of $8/boe and aCanadian/US dollar exchange rate of $0.88.

 

We manage our exposure tofluctuations between the US and Canadian dollar by matching our expected netcash flows and borrowings in the same currency. Net revenue from our foreignoperations and our US-dollar borrowings are generally used to fund US-dollarcapital expenditures and debt repayments. We maintain revolving Canadian andUS-dollar borrowing facilities that can be used or repaid depending on expectednet cash flows. We designate our US-dollar borrowings as a hedge against ourUS-dollar net investment in foreign operations.

 

Our chemicals operations areexposed to changes in the US-dollar exchange rate as a portion of their salesare denominated in US-dollars. Canexus periodically purchases US-dollar calloptions to reduce this exposure. Under outstanding option contracts at December31, 2006, Canexus had the right to sell US$5 million monthly and purchaseCanadian dollars at an exchange rate of US$0.85 to January 10, 2007 and has theright to sell US$5 million monthly and purchase Canadian dollars at an exchangerate of US$0.87 for the period January 10, 2007 to July 11, 2007.

 

We do not have any materialexposure to highly inflationary foreign currencies.

 

**InterestRate Risk**

 

We are exposed tofluctuations in interest rates on our floating-rate debt. To minimize ourexposure to interest rate fluctuations, we occasionally use derivativeinstruments.

 

Our sensitivity to interestrates and the expected impact of a 1% change in interest rates on our 2007 cashflow from operating activities and net income is as follows:

 

 
| **(Cdn$ millions)**                | ** ** | **Cash Flow** | ** ** | **Net Income** | ** ** |
|-----------------------------------------|------------|---------------|------------|----------------|------------|
| Interest  Rates—1% change in rates |       | 9             |       | 6              |       |

 

Our sensitivity to changes ininterest rates is based on 2007 estimated average floating rate debt of $900million and a Canadian/US dollar exchange rate of $0.88.

 

Our floating rate debtexposes us to changes in interest payments as interest rates fluctuate. Tomanage this exposure, we maintain a combination of fixed and floating rateborrowings and facilities. At December 31, 2006, fixed-rate borrowingscomprised 73% (2005—95%) of our long-term debt at an effective average rate of6.3% (2005—6.3%). During the year, we periodically drew on our committed,unsecured, term credit facilities and at December 31, 2006, floating-rate debtcomprised 27% (2005—5%) of our long-term debt at an effective average rate of5.7% (2005—4.4%) reaching a high of 6.4% and a low of 4.25% during 2006.

 

We had no interest rate swapsoutstanding in 2006 or 2005.

 

78

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**TRAdING**

 

**CommodityPrice Risk**

 

Our marketing operation isinvolved in the marketing and trading of crude oil, natural gas, natural gasliquids and power through the use of physical purchase and sales contracts, aswell as financial commodity contracts. These activities expose us to commodityprice risk, as well as foreign currency risk and volatility within thesemarkets. The marketing group actively manages this risk by utilizingenergy-related futures, forwards, swaps and options, as well as currency swapsor forwards. The marketing operation also tries to take advantage of volatilitywithin commodity markets and can establish net open commodity positions to takeadvantage of existing market conditions.

 

Volatility within our variousmarkets can vary and changes over time. While this volatility gives usopportunities, it can also cause our results to vary significantly betweenperiods. We attempt to manage associated risk and take on positions based onsolid market intelligence, however, it is possible that we could incurfinancial loss.

 

Open positions exist wherenot all contracted purchases and sales terms have been matched. These net openpositions allow us to generate income, but also expose us to risk of loss dueto fluctuating market prices (market risk sensitivities in our portfolio). Openpositions and derivative instruments expose us to other risks, including creditrisk and liquidity risk. The inability to close out options, futures andforward positions could have an adverse impact on our ability to use derivativeinstruments to effectively hedge our portfolio and/ or generate income fromtrading activities.

 

We control the level of marketrisk through daily monitoring of our energy-trading portfolio relative to:

 

•                  prescribed limits for Value-at-Risk (VaR);

 

•                  nominal size of commodity positions;

 

•                  stop loss limits; and

 

•                  stress testing.

 

VaR is a statistical estimatethat is reliable when normal market conditions prevail. Our VaR calculationestimates the maximum probable loss, given a 95% confidence level, that wewould incur if we were to unwind our outstanding positions over a two-dayperiod. We estimate VaR using the Variance-Covariance method based onhistorical commodity price volatility and correlation inputs. Our estimate isbased upon the following key assumptions:

 

•                  changes in commodity prices are eithernormally or “T” (for natural gas since May 2006) distributed;

 

•                  price volatility remains stable; and

 

•                  price correlation relationships remain stable.

 

If a severe market shockoccurred, the key assumptions underlying our VaR estimate could be exceeded andthe potential loss could be greater than our estimate. In May 2006, themethodology for estimating the input parameters for the VaR calculation fornatural gas was revised to improve performance and stability under a range ofnormal and low probability market conditions. The new methodology produces VaRresults substantially similar to the prior method with no material changes.

 

Stress testing complementsour VaR estimate. It is used to quantify potential unexpected losses from lowprobability market movements. Credit VaR is reported separately from commodityVaR, and ranged between $4 and $5 million in 2006.

 

79

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| Item 7 |   | Management’s Discussion & Analysis |   | Forward-Looking Statements |
|--------|--------|---------------------------------------------|--------|----------------------------|

 

Our year end, annual high,annual low and annual average VaR amounts are as follows:

 
| **(Cdn$ millions)** | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|--------------------------|------------|------------|------------|------------|------------|------------|------------|
| **Value at  Risk**       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Year End                 |       | 26         |       | 24         |       | 21         |       |
| High                     |       | 33         |       | 28         |       | 42         |       |
| Low                      |       | 17         |       | 11         |       | 17         |       |
| Average                  |       | 23         |       | 21         |       | 29         |       |

 

Our board of directors hasapproved formal risk management policies for our energy trading activities.Market and credit risks are monitored daily by a risk group that operatesindependently and ensures compliance with our risk management policies. TheFinance Committee of the board of directors and our Risk Management Committeemonitor our exposure to the above risks and review the results of our energytrading activities regularly.

 

**CREdIT RISK**

 

Credit risk affects both ourtrading and non-trading activities and is the risk of loss if counterparties donot fulfill their contractual obligations. Most of our credit exposures arewith counterparties in the energy industry, including energy traders, and aresubject to normal industry credit risk. We take the following measures toreduce this risk:

 

•                  we assess the financial strength of ourcounterparties through a rigorous credit process;

 

•                  we limit the total exposure extended toindividual counterparties, and may require collateral from some counterparties;

 

•                  we routinely monitor credit risk exposures,including sector, geographic and corporate concentrations of credit, and reportthese to our Risk Management Committee and the Finance Committee of the board;

 

•                  we set credit limits based on rating agencycredit ratings and internal assessments based on company and industry analysis;

 

•                  we review counterparty credit limitsregularly; and

 

•                  we use standard agreements that allow for thenetting of exposures associated with a single counterparty.

 

We believe these measuresminimize our overall credit risk. However, there can be no assurance that theseprocesses will protect us against all losses from non-performance. At December31, 2006:

 

**•****                 **over 98% of our credit exposures wereinvestment grade; and

 

•                  only 2 counterparties individually made upmore than 5% of our credit exposure. Both were investment grade.

 

80

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| Management’s Discussion & Analysis |   | Special Note to Canadian Investors |
|---------------------------------------------|--------|------------------------------------|

 

**SPECIAL NOTE REGARdING FORWARd-LOOKING STATEMENTS**

 

Certain statements in thisreport, including those appearing in *Items 1and 2—Business and Properties* and *Item7—Management’s Discussion and Analysis of Financial Condition and Results ofOperations*, are forward-looking statements(1). Forward-lookingstatements are generally identifiable by terms such as *anticipate, believe, intend, plan, expect, estimate,budget, outlook* or other similar words, and include statementsrelating to future production associated with our Coalbed Methane, Long Lake,and West Africa projects and future capital investment plans.

 

These statements are subjectto known and unknown risks and uncertainties and other factors which may causeactual results, levels of activity and achievements to differ materially fromthose expressed or implied by such statements. These risks, uncertainties andother factors include, among others:

 

•                  market prices for oil, natural gas andchemicals products;

 

•                  our ability to explore, develop, produce andtransport crude oil and natural gas to markets;

 

•                  the results of exploration and developmentdrilling and related activities;

 

•                  volatility in energy trading markets;

 

•                  foreign-currency exchange rates;

 

•                  economic conditions in the countries andregions in which we carry on business;

 

•                  governmental actions that increase taxes orroyalties, change environmental and other laws and regulations;

 

•                  renegotiations of contracts;

 

•                  results of litigations, arbitration orregulatory proceedings; and

 

•                  political uncertainty, including actions byinsurgent or other armed groups or other conflict, including conflict betweenstates.

 

The above items and theirpossible impact are discussed more fully in the section, titled *Risk Factors* in Item 1A and *Quantitative and Qualitative Disclosures about MarketRisk*in Item 7A.

 

The impact of any one risk,uncertainty or factor on a particular forward-looking statement is notdeterminable with certainty as these are interdependent and and management’s futurecourse of action depends upon our assessment of all information available atthat time. Any statements regarding the following are forward-lookingstatements:

 

•                  future crude oil, natural gas or chemicalsprices;

 

•                  future production levels;

 

•                  future cost recovery oil revenues from ouroperations in Yemen;

 

•                  future capital expenditures and theirallocation to exploration and development activities;

 

•                  future asset dispositions;

 

•                  future sources of funding for our capitalprogram;

 

**•****                 **possible commerciality, development plans orcapacity expansions;

 

•                  future ability to execute dispositions ofassets or businesses;

 

•                  future debt levels;

 

•                  future cash flows and their uses;

 

•                  future drilling of new wells;

 

•                  ultimate recoverability of reserves;

 

•                  expected finding and development costs;

 

•                  expected operating costs;

 

•                  future demand for chemicals products;

 

•                  future expenditures and future allowancesrelating to environmental matters; and

 

•                  dates by which certain areas will be developedor will come on stream.

 

We believe that anyforward-looking statements made are reasonable based on information availableto us on the date such statements were made. However, no assurance can be givenas to future results, levels of activity and achievements. Except to the extentrequired by law, we undertake no obligation to update publicly or revise anyforward-looking statements contained in this report. All subsequent forward-lookingstatements, whether written or oral, attributable to us or persons acting onour behalf are expressly qualified in their entirety by these cautionarystatements.

 

----

*Note:*
| *(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.* |
|-------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

**SPECIAL NOTETO CANADIAN INVESTORS**

 

Nexen is an SEC registrantand a Form 10-K and related forms filer. Therefore, our reserves estimates andsecurities regulatory disclosures follow SEC requirements. In 2003, Canadianregulatory authorities adopted *NationalInstrument 51-101—Standards of Disclosure for Oil and Gas Activities*(NI 51-101) which prescribes that Canadian companies follow certain standardsfor the preparation and disclosure of reserves

 

81

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and related information. Wehave been granted the following exemptions permitting us to:

 

•                  substitute our SEC disclosures for much of theannual disclosure required by NI 51-101;

 

•                  prepare our reserves estimates and relateddisclosures in accordance with SEC requirements, generally accepted industrypractices in the US, and the standards of the *CanadianOil and Gas Evaluation Handbook* (COGE Handbook) modified to reflectSEC requirements;

 

•                  dispense with the requirement to have ourreserves estimates and the *StandardizedMeasure of Discounted Future Net Cash Flows and Changes Therein*,included in the Supplementary Financial Information, evaluated or audited byindependent qualified reserves evaluators; and

 

•                  not disclose certain prescribed informationpertaining to prospects if such disclosures would result in the contraventionof a legal obligation, would likely be detrimental to our competitive interestsor the information does not exist.

 

As a result of theseexemptions, Canadian investors should note the following fundamentaldifferences in reserves estimates and related disclosures contained in the Form10-K:

 

**•****     **SEC registrants apply SEC reserves definitionsand prepare their reserves estimates in accordance with SEC requirements andgenerally accepted industry practices in the US whereas NI 51-101 requiresadherence to the definitions and standards promulgated by the COGE Handbook; **  **

 

•      theSEC mandates disclosure of proved reserves and the *Standardized Measure of Discounted Future Net Cash Flows and ChangesTherein* calculated using year-end constant prices and costs onlywhereas NI 51-101 also requires disclosure of reserves and related future netrevenues using forecast prices; **  **

 

**•****     **the SEC mandates disclosure of proved andproved developed reserves by geographic region only whereas NI 51-101 requiresdisclosure of more reserve categories and product types;

 

•                  the SEC does not prescribe the nature of theinformation required in connection with proved undeveloped reserves and futuredevelopment costs whereas NI 51-101 requires certain detailed informationregarding proved undeveloped reserves, related development plans and futuredevelopment costs;

 

•                  the SEC does notrequire disclosure of finding and development (F&D) costs per boe of provedreserves additions whereas NI 51-101 requires that various F&D costs per boebe disclosed. NI 51-101 requires that F&D costs be calculated by dividingthe aggregate of exploration and development costs incurred in the current yearand the change in estimated future development costs relating to provedreserves by the additions to proved reserves in the current year. However, thiswill generally not reflect full cycle finding and development costs related toreserve additions for the year;

 

•                  the SEC leavesthe engagement of independent qualified reserves evaluators to the discretionof a company’s board  of directors whereas NI 51-101 requiresissuers to engage such evaluators and to file their reports; **  **

** **

**•****     **the SEC does not consider the upgradingcomponent of our integrated oil sands project at Long Lake as an oil and gasactivity, and therefore permits recognition of bitumen reserves only. NI 51-101specifically includes such activity as an oil and gas activity and recognizessynthetic oil as a product type, and therefore permits recognition of syntheticreserves. At year end, we have recognized 246 million barrels before royaltiesof proved bitumen reserves (219 million barrels after royalties) under SECrequirements, whereas under NI 51-101 we would have recognized 200 millionbarrels before royalties of proved synthetic reserves (185 million barrels afterroyalties); and **  **

** **

**•****     **the SEC considers our Syncrude operation as amining activity rather than an oil and gas activity, and therefore does notpermit related reserves to be included with oil and gas reserves. NI 51-101specifically includes such activity as an oil and gas activity and recognizessynthetic oil as a product type, and therefore permits them to be included withoil and gas reserves. We have provided a separate table showing our share ofthe Syncrude proved reserves as well as the additional disclosures relating tomining activities required by SEC requirements.

 

The foregoing is a generaldescription of the principal differences only.

 

NI 51-101 requires that wemake the following disclosures: 

 

•      weuse oil equivalents (boe) to express quantities of natural gas and crude oil ina common unit. A conversion ratio of 6 mcf of natural gas to 1 barrel of oil isused. Boe may be misleading, particularly if used in isolation. The conversionratio is based on an energy equivalency conversion method primarily applicableat the burner tip and does not represent a value equivalency at the wellhead.

 

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FinancialStatements

 

Strongcommodity prices and recordresults from our marketing group resultedin solid financial results for 2006. Cash flowfrom operating activities was a record$2.4 billion, while net income was $601 million.

 

----

 

**ITEM 8. FINANCIAL STATEMENTS ANdSUPPLEMENTARy dATA**

 
| **Report of Management**                                          |       |       |
|-------------------------------------------------------------------|------------|------------|
| **Report of Independent  Registered Chartered Accountants**       |       |       |
| **Consolidated  Financial Statements**                            | ** ** | ** ** |
| Consolidated Statement of Income                                  |       |       |
| Consolidated Balance Sheet                                        |       |       |
| Consolidated Statement of  Cash Flows                             |       |       |
| Consolidated Statement of  Shareholders’ Equity              |       |       |
| Notes To Consolidated  Financial Statements                       |       |       |
|                                                              |       |       |
| **Supplementary Data  (Unaudited)**                               | ** ** | ** ** |
| Quarterly  Financial Data In Accordance with Canadian and US GAAP |       |       |
| Oil And Gas  Producing Activities and Syncrude Operations         |       |       |

 

----

 
| Financial Statements and Supplementary Data |   | Report of Management |
|---------------------------------------------|--------|----------------------|

 

**REPORT OF MANAGEMENT**

 

February 9, 2007

 

To the Shareholders of NexenInc.:

 

We are responsible for thepreparation and fair presentation of the consolidated financial statements, aswell as the financial reporting process that gives rise to such consolidatedfinancial statements. This responsibility requires us to make significantaccounting judgments and estimates. For example, we are required to chooseaccounting principles and methods that are appropriate to the company’scircumstances, and we are required to make estimates and assumptions thataffect amounts reported. Fulfilling this responsibility requires thepreparation and presentation of our consolidated financial statements inaccordance with generally accepted accounting principles in Canada with areconciliation to generally accepted accounting principles in the US. 

 

We also have responsibilityfor the preparation and fair presentation of other financial information inthis report and to ensure the consistency of this information with thefinancial statements.

 

We are responsible for thedevelopment and implementation of internal controls over the financialreporting process. These controls are designed to provide reasonable assurancethat relevant and reliable financial information is produced. To gather andcontrol financial data, we have established accounting and reporting systemssupported by internal controls over financial reporting and an internal auditprogram. We believe that our internal controls over financial reporting providereasonable assurance that our assets are safeguarded against loss fromunauthorized use or disposition, that receipts and expenditures of the companyare made only in accordance with authorization of management and directors ofthe company, and that our records are reliable for preparing our consolidatedfinancial statements and other financial information in accordance withapplicable generally accepted accounting principles and in accordance withapplicable securities rules and regulations. All internal control systems, nomatter how well designed, have inherent limitations. Therefore, even thosesystems determined to be effective can provide only reasonable assurance withrespect to financial statement preparation and presentation. 

 

We have establisheddisclosure controls and procedures, internal controls over financial reportingand corporate-wide policies to ensure that Nexen’s consolidated financialposition, results of operations and cash flows are presented fairly. Ourdisclosure controls and procedures are designed to ensure timely disclosure andcommunication of all material information required by regulators. We oversee,with assistance from our Disclosure Review Committee, these controls andprocedures and all required regulatory disclosures.

 

To ensure the integrity ofour financial statements, we carefully select and train qualified personnel. Wealso ensure our organizational structure provides appropriate delegation ofauthority and division of responsibilities. Our policies and procedures arecommunicated throughout the organization and include a written ethics andintegrity policy that applies to all employees, including the chief executiveofficer, chief financial officer and chief accounting officer or controller. 

 

Our board of directors isresponsible for reviewing and approving the consolidated financial statementsand for overseeing management’s performance of its financial reportingresponsibilities. Their financial statement related responsibilities arefulfilled mainly through the Audit and Conduct Review Committee (the AuditCommittee) with assistance from the Reserves Review Committee regarding theannual review of our crude oil and natural gas reserves and the FinanceCommittee regarding the assessment and mitigation of risk. The Audit Committeeis composed entirely of independent directors and includes four directors withfinancial expertise. The Audit Committee meets regularly with management, theinternal auditors and the independent registered Chartered Accountants toreview accounting policies, financial reporting and internal control issues andto ensure each party is properly discharging its responsibilities. The AuditCommittee is responsible for the appointment and compensation of theindependent registered Chartered Accountants and also considers theirindependence, reviews their fees and (subject to applicable securities laws),pre-approves their retention for any permitted non-audit services and their feefor such services. The internal auditors and independent registered CharteredAccountants have full and unlimited access to the Audit Committee, with orwithout the presence of management.

 
| (signed)  “Charles W. Fischer” |   | (signed) “Marvin F.  Romanow”               |
|------------------------------------------|--------|-------------------------------------------------------|
| President  and Chief Executive Officer   |   | Executive Vice President  and Chief Financial Officer |

 

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| Item 8 |   | Financial Statements and Supplementary Data | Report of Auditors |
|--------|--------|---------------------------------------------|--------------------|

 

**REPORT OF INdEPENdENT REGISTEREd ChARTEREd ACCOUNTANTS**

 

To the Board of Directors andShareholders of Nexen Inc.:

 

We have audited theaccompanying consolidated balance sheets of Nexen Inc. and subsidiaries (the “Company”)as of December 31, 2006 and 2005 and the consolidated statements of income,cash flows and shareholders’ equity for each of the three years in the periodended December 31, 2006. These financial statements are the responsibility ofthe Company’s management.  Ourresponsibility is to express an opinion on these financial statements based onour audits.

 

We conducted our audits inaccordance with Canadian generally accepted auditing standards and the standardsof the Public Company Accounting Oversight Board (United States). Thesestandards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation.We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, suchconsolidated financial statements present fairly, in all material respects, thefinancial position of Nexen Inc. and subsidiaries as of December 31, 2006 and2005 and the results of their operations and their cash flows for each of thethree years in the period ended December 31, 2006 in conformity with Canadiangenerally accepted accounting principles.

 

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the effectiveness of the Company’s internal control overfinancial reporting as of December 31, 2006, based on the criteria establishedin Internal Control—Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission and our report dated February 9, 2007expressed an unqualified opinion on management’s assessment of the effectivenessof the Company’s internal control over financial reporting and an unqualifiedopinion on the effectiveness of the Company’s internal control over financialreporting.

 
| Calgary,  Canada  |   | (signed) “Deloitte &  Touche LLP” |
|-------------------|--------|-------------------------------------------------|
| February  9, 2007 |   | Independent Registered  Chartered Accountants   |

 

**COMMENTS By INdEPENdENT REGISTEREd ChARTEREd ACCOUNTANTS ONCANAdA-UNITEd STATES OF AMERICA REPORTING dIFFERENCE**

 

The standards of the PublicCompany Accounting Oversight Board (United States) require the addition of anexplanatory paragraph when there are changes in accounting principles that havea material effect on the comparability of the Company’s financial statements,such as the change described in Note 1(u) to the consolidated financialstatements. Our report to the board of directors and shareholders on theconsolidated financial statements of the Company dated February 9, 2007, isexpressed in accordance with Canadian reporting standards which do not requirea reference to such changes in accounting principles in the auditors’ reportwhen the change is properly accounted for and adequately disclosed in thefinancial statements.

 
| Calgary,  Canada  |   | (signed) “Deloitte &  Touche LLP” |
|-------------------|--------|-------------------------------------------------|
| February  9, 2007 |   | Independent Registered  Chartered Accountants   |

 

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| Financial Statements and Supplementary Data |   | Financial Statements |
|---------------------------------------------|--------|----------------------|

 

**NExEN INC.**

 

**CONSOLIdATEd STATEMENT OFINCOME**

** **

**FOR ThE ThREE yEARS ENdEd dECEMBER31, 2006**

 
| **Cdn$ millions, except per share  amounts**                       | ** ** | **2006**   | ** ** | **2005**      | ** ** | **2004**      | ** ** |
|-------------------------------------------------------------------------|------------|------------|------------|---------------|------------|---------------|------------|
| ** **                                                              | ** ** | ** ** | ** ** | **Note 1(u)** | ** ** | **Note 1(u)** | ** ** |
| Revenues and  Other Income                                              |       |       |       |          |       |          |       |
| Net Sales                                                               |       | 3,936      |       | 3,932         |       | 2,944         |       |
| Marketing and Other (Note 17)                                           |       | 1,450      |       | 702           |       | 713           |       |
| Gain on Dilution of Interest in Chemicals  Business (Note 2)            |       | —     |       | 193           |       | —        |       |
|                                                                    |       | 5,386      |       | 4,827         |       | 3,657         |       |
| Expenses                                                                |       |       |       |          |       |          |       |
| Operating                                                               |       | 955        |       | 893           |       | 722           |       |
| Depreciation, Depletion, Amortization and  Impairment (Note  6)         |       | 1,124      |       | 1,052         |       | 674           |       |
| Transportation and Other                                                |       | 1,041      |       | 796           |       | 549           |       |
| General and Administrative                                              |       | 555        |       | 809           |       | 299           |       |
| Exploration                                                             |       | 362        |       | 250           |       | 243           |       |
| Interest (Note 8)                                                       |       | 53         |       | 97            |       | 143           |       |
|                                                                    |       | 4,090      |       | 3,897         |       | 2,630         |       |
|                                                                    |       |       |       |          |       |          |       |
| Income from  Continuing Operations before Income Taxes                  |       | 1,296      |       | 930           |       | 1,027         |       |
|                                                                    |       |       |       |          |       |          |       |
| Provision  for Income Taxes (Note  18)                                  |       |       |       |          |       |          |       |
| Current                                                                 |       | 368        |       | 339           |       | 248           |       |
| Future                                                                  |       | 315        |       | (105          | )          | 69            |       |
|                                                                    |       | 683        |       | 234           |       | 317           |       |
|                                                                    |       |       |       |          |       |          |       |
| Net Income  from Continuing Operations before Non-Controlling Interests |       | 613        |       | 696           |       | 710           |       |
| Net Income Attributable to Non-Controlling  Interests                   |       | 12         |       | 8             |       | —        |       |
|                                                                    |       |       |       |          |       |          |       |
| Net Income  from Continuing Operations                                  |       | 601        |       | 688           |       | 710           |       |
| Net Income from Discontinued Operations (Note 14)                       |       | —     |       | 452           |       | 83            |       |
|                                                                    |       |       |       |          |       |          |       |
| **Net  Income**                                                         | ** ** | **601**    | ** ** | **1,140**     | ** ** | **793**       | ** ** |
|                                                                    |       |       |       |          |       |          |       |
| **Earnings  Per Common Share from Continuing Operations**($/share)      |       |       |       |          |       |          |       |
| Basic (Note 13)                                                         |       | 2.29       |       | 2.64          |       | 2.76          |       |
| Diluted (Note 13)                                                       |       | 2.24       |       | 2.58          |       | 2.72          |       |
|                                                                    |       |       |       |          |       |          |       |
| **Earnings  Per Common Share**($/share)                                 |       |       |       |          |       |          |       |
| Basic (Note 13)                                                         |       | 2.29       |       | 4.38          |       | 3.08          |       |
| Diluted (Note 13)                                                       |       | 2.24       |       | 4.28          |       | 3.04          |       |

 

*Seeaccompanying notes to Consolidated Financial Statements.*

 

87

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**NExEN INC.**

 

**CONSOLIdATEd BALANCE ShEET**

** **

**dECEMBER 31, 2006 ANd 2005**

 
| **Cdn$ millions, except share  amounts**               | ** **                    | **2006**   | ** ** | **2005**      | ** ** |
|-------------------------------------------------------------|-------------------------------|------------|------------|---------------|------------|
| ** **                                                  | ** **                    | ** ** | ** ** | **Note 1(u)** | ** ** |
| **ASSETS**                                                  | ** **                    | ** ** | ** ** | ** **    | ** ** |
| Current Assets                                              |                          |       |       |          |       |
| Cash and Cash Equivalents                                   |                          | 101        |       | 48            |       |
| Restricted Cash and Margin Deposits                         |                          | 197        |       | 70            |       |
| Accounts Receivable (Note 4)                                |                          | 2,951      |       | 3,151         |       |
| Inventories and Supplies (Note 5)                           |                          | 786        |       | 504           |       |
| Future Income Tax Assets (Note 18)                          |                          | 479        |       | —        |       |
| Other                                                       |                          | 67         |       | 51            |       |
| Total Current Assets                                        |                          | 4,581      |       | 3,824         |       |
|                                                        |                          |       |       |          |       |
| Property, Plant and Equipment (Note 6)                      |                          | 11,739     |       | 9,594         |       |
| Goodwill                                                    |                          | 377        |       | 364           |       |
| Future Income Tax Assets (Note 18)                          |                          | 141        |       | 410           |       |
| Deferred Charges and Other Assets (Note 10)                 |                          | 318        |       | 398           |       |
|                                                        |                          |       |       |          |       |
| **TOTAL  ASSETS**                                           | ** **                    | **17,156** | ** ** | **14,590**    | ** ** |
|                                                        |                          |       |       |          |       |
| **LIABILITIES  AND SHAREHOLDERS’ EQUITY**              | ** **                    | ** ** | ** ** | ** **    | ** ** |
| Current Liabilities                                         |                          |       |       |          |       |
| Short-Term Borrowings (Note 8)                              |                          | 158        |       | —        |       |
| Accounts Payable and Accrued Liabilities                    |                          | 3,879      |       | 3,727         |       |
| Accrued Interest Payable                                    |                          | 55         |       | 55            |       |
| Dividends Payable                                           |                          | 13         |       | 13            |       |
| Total Current Liabilities                                   |                          | 4,105      |       | 3,795         |       |
|                                                        |                          |       |       |          |       |
| Long-Term Debt (Note 8)                                     |                          | 4,673      |       | 3,687         |       |
| Future Income Tax Liabilities (Note 18)                     |                          | 2,468      |       | 1,955         |       |
| Asset Retirement Obligations (Note 9)                       |                          | 683        |       | 590           |       |
| Deferred Credits and Other Liabilities (Note 11)            |                          | 516        |       | 479           |       |
| Non-Controlling Interests (Note 2)                          |                          | 75         |       | 88            |       |
| Shareholders’ Equity (Note 12)                         |                          |       |       |          |       |
| Common Shares, no par value                                 |                          |       |       |          |       |
| Authorized:                                                 | Unlimited                     |       |       |          |       |   |
| Outstanding:                                                | 2006—262,513,206  shares |       |       |          |       |   |
|                                                        | 2005—261,140,571 shares  |       | 821        |          | 732        |   |
| Contributed Surplus                                         |                          | 4          |       | 2             |       |
| Retained Earnings                                           |                          | 3,972      |       | 3,423         |       |
| Cumulative Foreign Currency Translation Adjustment          |                          | (161       | )          | (161          | )          |
| Total Shareholders’ Equity                             |                          | 4,636      |       | 3,996         |       |
| Commitments, Contingencies and Guarantees (Notes 15 and 18) |                          |       |       |          |       |
| **TOTAL LIABILITIES ANd ShAREhOLdERS’ EqUITy**         | ** **                    | **17,156** | ** ** | **14,590**    | ** ** |

 

*Seeaccompanying notes to Consolidated Financial Statements.*

 
| Approved on behalf of the  Board:        |   |                                        |
|------------------------------------------|--------|---------------------------------------------|
|                                     |   |                                        |
| (signed) “Charles W.  Fischer” |   | (signed) “Thomas C. O’Neill” |
| Director                                 |   | Director                                    |

 

88

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**NExEN INC.**

 

**CONSOLIdATEd STATEMENT OFCASh FLOWS**

** **

**FOR ThE ThREE yEARS ENdEd dECEMBER31, 2006**

 
| **Cdn$ millions**                                                 | ** ** | **2006**   | ** ** | **2005**      | ** ** | **2004**      | ** ** |
|------------------------------------------------------------------------|------------|------------|------------|---------------|------------|---------------|------------|
| ** **                                                             | ** ** | ** ** | ** ** | **Note 1(u)** | ** ** | **Note 1(u)** | ** ** |
| **Operating  Activities**                                              | ** ** | ** ** | ** ** | ** **    | ** ** | ** **    | ** ** |
| Net Income from Continuing Operations                                  |       | 601        |       | 688           |       | 710           |       |
| Net Income from Discontinued Operations                                |       | —     |       | 452           |       | 83            |       |
| Charges and Credits to Income not Involving  Cash (Note 19)            |       | 1,629      |       | 1,081         |       | 906           |       |
| Exploration Expense                                                    |       | 362        |       | 250           |       | 243           |       |
| Changes in Non-Cash Working Capital (Note 19)                          |       | (177       | )          | (195          | )          | (122          | )          |
| Other                                                                  |       | (41        | )          | (133          | )          | (214          | )          |
|                                                                   |       | 2,374      |       | 2,143         |       | 1,606         |       |
|                                                                   |       |       |       |          |       |          |       |
| **Financing  Activities**                                              | ** ** | ** ** | ** ** | ** **    | ** ** | ** **    | ** ** |
| Proceeds from Long-Term Notes and  Debentures (Note  8)                |       | —     |       | 1,253         |       | 1,779         |       |
| Repayment of Long-Term Notes and Debentures  (Note 8)                  |       | (93        | )          | (1,818        | )          | (300          | )          |
| Proceeds from (Repayment of) Term Credit  Facilities, Net              |       | 1,044      |       | (66           | )          | 83            |       |
| Proceeds from (Repayment of) Short-Term  Borrowings, Net               |       | 160        |       | (99           | )          | 101           |       |
| Redemption of Preferred Securities                                     |       | —     |       | —        |       | (289          | )          |
| Dividends on Common Shares                                             |       | (52        | )          | (52           | )          | (52           | )          |
| Issue of Common Shares and Exercise of  Options for Shares             |       | 48         |       | 58            |       | 124           |       |
| Net Proceeds from Canexus Initial Public  Offering (Note 2)            |       | —     |       | 301           |       | —        |       |
| Proceeds from Term Credit Facilities of  Canexus, Net (Notes  2 and 8) |       | 2          |       | 176           |       | —        |       |
| Other                                                                  |       | (28        | )          | (27           | )          | (20           | )          |
|                                                                   |       | 1,081      |       | (274          | )          | 1,426         |       |
|                                                                   |       |       |       |          |       |          |       |
| **Investing  Activities**                                              | ** ** | ** ** | ** ** | ** **    | ** ** | ** **    | ** ** |
| Business Acquisitions, Net of Cash Acquired  (Note 3)                  |       | (78        | )          | —        |       | (2,583        | )          |
| Capital Expenditures                                                   |       |       |       |          |       |          |       |
| Exploration and Development                                            |       | (3,198     | )          | (2,564        | )          | (1,582        | )          |
| Proved Property Acquisitions                                           |       | (13        | )          | (20           | )          | (4            | )          |
| Chemicals, Corporate and Other                                         |       | (119       | )          | (54           | )          | (95           | )          |
| Proceeds on Disposition of Assets                                      |       | 27         |       | 911           |       | 34            |       |
| Changes in Non-Cash Working Capital (Note 19)                          |       | 134        |       | (54           | )          | 244           |       |
| Changes in Restricted Cash and Margin  Deposits                        |       | (127       | )          | (70           | )          | —        |       |
| Other                                                                  |       | (14        | )          | (13           | )          | (27           | )          |
|                                                                   |       | (3,388     | )          | (1,864        | )          | (4,013        | )          |
|                                                                   |       |       |       |          |       |          |       |
| Effect of  Exchange Rate Changes on Cash and Cash Equivalents          |       | (14        | )          | (30           | )          | (33           | )          |
|                                                                   |       |       |       |          |       |          |       |
| Increase  (Decrease) in Cash and Cash Equivalents                      |       | 53         |       | (25           | )          | (1,014        | )          |
|                                                                   |       |       |       |          |       |          |       |
| Cash and  Cash Equivalents—Beginning of Year                      |       | 48         |       | 73            |       | 1,087         |       |
|                                                                   |       |       |       |          |       |          |       |
| **Cash and  Cash Equivalents—End of Year**                        | ** ** | **101**    | ** ** | **48**        | ** ** | **73**        | ** ** |

 

*Seeaccompanying notes to Consolidated Financial Statements.*

 

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**NEXEN INC.**

 

**CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY**

 

**FOR THE THREE YEARS ENDED DECEMBER 31, 2006**

 
| **Cdn$ millions**                                              | ** ** | **2006**   | ** ** | **2005**      | ** ** | **2004**      | ** ** |
|---------------------------------------------------------------------|------------|------------|------------|---------------|------------|---------------|------------|
| ** **                                                          | ** ** | ** ** | ** ** | **Note 1(u)** | ** ** | **Note 1(u)** | ** ** |
| **Common  Shares**(Note  12)                                        |       |       |       |          |       |          |       |
| Balance at Beginning of Year                                        |       | 732        |       | 637           |       | 513           |       |
| Issue of Common Shares                                              |       | 32         |       | 29            |       | 31            |       |
| Proceeds from Options Exercised for Shares                          |       | 16         |       | 29            |       | 93            |       |
| Accrued Liability Relating to Options  Exercised                    |       | 41         |       | 37            |       | —        |       |
| **Balance at End of Year**                                          | ** ** | **821**    | ** ** | **732**       | ** ** | **637**       | ** ** |
|                                                                |       |       |       |          |       |          |       |
| **Contributed  Surplus**                                            | ** ** | ** ** | ** ** | ** **    | ** ** | ** **    | ** ** |
| Balance at Beginning of Year                                        |       | 2          |       | —        |       | 1             |       |
| Stock-Based Compensation Expense (Note 12)                          |       | 2          |       | 2             |       | 2             |       |
| Modification of Stock Option Plan to Tandem  Option Plan (Note  12) |       | —     |       | —        |       | (3            | )          |
| **Balance at End of Year**                                          | ** ** | **4**      | ** ** | **2**         | ** ** | **—**    | ** ** |
|                                                                |       |       |       |          |       |          |       |
| **Retained  Earnings**                                              | ** ** | ** ** | ** ** | ** **    | ** ** | ** **    | ** ** |
| Balance at Beginning of Year                                        |       | 3,423      |       | 2,335         |       | 1,594         |       |
| Net Income                                                          |       | 601        |       | 1,140         |       | 793           |       |
| Dividends on Common Shares                                          |       | (52        | )          | (52           | )          | (52           | )          |
| **Balance at End of Year**                                          | ** ** | **3,972**  | ** ** | **3,423**     | ** ** | **2,335**     | ** ** |
|                                                                |       |       |       |          |       |          |       |
| **Cumulative  Foreign Currency Translation Adjustment**             | ** ** | ** ** | ** ** | ** **    | ** ** | ** **    | ** ** |
| Balance at Beginning of Year                                        |       | (161       | )          | (105          | )          | (33           | )          |
| Translation Adjustment, Net of Income Taxes                         |       | —     |       | (56           | )          | (72           | )          |
| **Balance at End of Year**                                          | ** ** | **(161**   | **)**      | **(161**      | **)**      | **(105**      | **)**      |

 

*Seeaccompanying notes to Consolidated Financial Statements.*

 

90

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| Financial Statements and Supplementary Data |   | Notes to Financial Statements |
|---------------------------------------------|--------|-------------------------------|

 

**NExEN INC.**

 

**NOTES TO CONSOLIdATEdFINANCIAL STATEMENTS**

 

Cdn$ millions, except asnoted

 

**1.**               **ACCOUNTING POLICIES**

 

Our Consolidated FinancialStatements are prepared in accordance with Canadian Generally AcceptedAccounting Principles (GAAP). The impact of significant differences betweenCanadian and United States (US) GAAP on the Consolidated Financial Statementsis disclosed in Note 21.

 

**(a) Use ofestimates**

 

We make estimates andassumptions that affect the reported amounts of assets and liabilities anddisclosure of contingent assets and liabilities at the date of the ConsolidatedFinancial 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,derivative contract assets and liabilities and the determination of provedreserves on an ongoing basis. Changes in facts and circumstances may result inrevised estimates, and actual results may differ from these estimates.

 

**(b)Principles of consolidation**

 

The Consolidated FinancialStatements 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 intercompany accountsand transactions have been eliminated. On August 18, 2005, we sold ourchemicals operations to Canexus LP, but retained control of these operationsthrough our 61.4% interest in Canexus LP. All of the assets, liabilities andresults of operations of Canexus LP and its subsidiaries have been included inour consolidated financial statements. The non-Nexen ownership interests inCanexus LP and its subsidiaries are shown as non-controlling interests. Weproportionately consolidate our undivided interests in our oil and gasexploration, development and production activities conducted under jointventure arrangements. We also proportionately consolidate our 7.23% undividedinterest in the Syncrude joint venture, which is considered a mining activityunder US regulations. While the joint ventures under which these activities arecarried out do not comprise distinct legal entities, they are operatingentities, the significant operating policies of which are, by contractual arrangement,jointly controlled by all working interest parties.

 

**(c) Accountsreceivable**

 

Accounts receivable arerecorded based on our revenue recognition policy (see Note 1(j)). Our allowancefor doubtful accounts provides for specific doubtful receivables.

 

**(d)Inventories and supplies**

 

Inventories and supplies forour oil and gas, marketing and chemicals operations are stated at the lower ofcost and net realizable value. Cost is determined on the first-in, first-outmethod or average basis. Inventory costs include expenditures and other costs,including depreciation, depletion and amortization, directly or indirectlyincurred in bringing the inventory to its existing condition.

 

**(e)Property, plant and equipment (PP&E)**

 

Property, plant and equipmentis recorded at cost and includes only recoverable costs that directly result inan identifiable future benefit. Unrecoverable costs, maintenance and turnaroundcosts are expensed as incurred. Improvements that increase capacity or extendthe useful lives of the related assets are capitalized to PP&E.

 

We follow successful effortsaccounting for our oil and gas business. All property acquisition costs areinitially capitalized to PP&E as unproved property costs. Once provedreserves are discovered, the acquisition costs are reclassified to provedproperty

 

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acquisition costs.Exploration drilling costs are capitalized pending evaluation as to whethersufficient quantities of reserves have been found to justify commercialproduction. If commercial quantities of reserves are not found, explorationdrilling costs are expensed. All exploratory wells are evaluated for commercialviability on a regular basis following completion of drilling. Explorationdrilling costs remain capitalized when a well has found a sufficient quantityof reserves to justify its completion as a producing well and sufficientprogress is being made to assess the reserves and the economic and operatingviability of the well. All other exploration costs, including geological andgeophysical and annual lease rentals, are expensed to earnings as incurred. Alldevelopment costs are capitalized as proved property costs. General andadministrative costs that directly relate to acquisition, exploration and developmentactivities are capitalized to PP&E.

 

PP&E for our Syncrudeoperation is recorded at cost and includes only recoverable costs that directlyresult in an identifiable future benefit. Unrecoverable costs, maintenance andturnaround costs are expensed as incurred. Improvements that increase capacityor extend the useful lives of the related assets are capitalized to PP&E.

 

We engage in research anddevelopment activities to develop or improve processes and techniques toextract oil and gas. Research involves investigating new knowledge. Developmentinvolves translating that knowledge into a new technology or process. Researchcosts are expensed as incurred. Development costs are deferred once technicalfeasibility is established, and we intend to proceed with development. We deferthese costs in PP&E until the commencement of commercial operations orproduction. Otherwise, development costs are expensed as incurred. Developmentcosts include pre-operating revenues and costs.

 

**(f) Depreciation,depletion, amortization and impairment (dd&A)**

 

Under successful effortsaccounting, we deplete oil and gas capitalized costs using theunit-of-production method. Development and exploration drilling and equippingcosts are depleted over remaining proved developed reserves and proved propertyacquisition costs over remaining proved reserves. Depletion is considered acost of inventory when the oil and gas is produced. When this inventory issold, the depletion is charged to DD&A expense.

 

Our Syncrude PP&E isdepleted using the unit-of-production method. Capitalized costs are depletedover proved and probable reserves within developed areas of interest.

 

We depreciate other plant andequipment costs, including our chemicals facilities, using the straight-linemethod based on the estimated useful lives of the assets, which range from 3years to 30 years. Unproved property costs and major projects that are underconstruction or development are not depreciated, depleted or amortized.

 

We evaluate the carryingvalue of our PP&E whenever events or conditions occur that indicate thatthe carrying value of properties on our balance sheet may not be recoverablefrom future cash flows. These events or conditions occur periodically. Ifcarrying value exceeds the sum of undiscounted future cash flows, the property’svalue is impaired. The property is then assigned a fair value equal to itsestimated total future cash flows, discounted for the time value of money, andwe expense the excess carrying value to depreciation, depletion, amortizationand impairment. Our cash flow estimates require assumptions about futurecommodity prices, operating costs and other factors. Actual results can differfrom these estimates.

 

In assessing the carryingvalues of our unproved properties, we take into account our future plans forthese properties, the remaining terms of the leases and any other factors thatmay be indicators of potential impairment.

 

**(g) Carriedinterest**

 

We conduct certaininternational operations jointly with foreign governments in accordance withproduction sharing agreements pursuant to which proved reserves are recognizedusing the economic interest method. Under these agreements, we pay both ourshare and the government’s share of operating and capital costs. We recover thegovernment’s share of these costs from future revenues or production overseveral years. The government’s share of operating costs are recorded inoperating expense when incurred and capital costs are recorded in PP&E andexpensed to DD&A in the year recovered. All recoveries are recorded asrevenue in the year of recovery.

 

92

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**(h) Assetretirement obligations**

 

We provide for future assetretirement obligations on our resource properties, facilities, productionplatforms, pipelines and chemicals facilities based on estimates established bycurrent legislation and industry practices. The asset retirement obligation isinitially measured at fair value and capitalized to PP&E as an assetretirement cost. The asset retirement obligation accretes until the time theretirement obligation is expected to settle, while the asset retirement cost isamortized over the useful life of the underlying PP&E. We periodicallyreview our estimates for changes in expected amounts or timing of cash flows.

 

The amortization of the assetretirement cost and the accretion of the asset retirement obligation areincluded in depreciation, depletion, amortization and impairment. Actualretirement costs are recorded against the obligation when incurred. Anydifference between the recorded asset retirement obligation and the actualretirement costs incurred is recorded as a gain or loss in the period ofsettlement.

 

**(i) Goodwill**

 

Goodwill is recorded at costand is not amortized. We test goodwill for impairment annually based onestimated future cash flows of the reporting unit to which the goodwill isattributable. In addition, we test goodwill for impairment whenever an event orcircumstance occurs that may reduce the fair value of a reporting unit belowits carrying amount. If our goodwill is impaired, we write it down to itsimplied fair value, based on the fair value of the assets and liabilities ofthe underlying reporting unit. Our goodwill is attributable to our marketingand UK reporting units.

 

**(j) Revenuerecognition**

 

**Crude Oiland Natural Gas**

 

Revenue from the productionof 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 crudeoil and natural gas reaches the end of the pipeline. For our otherinternational operations, our customers take title when the crude oil is loadedonto the tanker. When we produce or sell more or less oil or natural gas thanour share, production overlifts and underlifts occur. We record overlifts asliabilities and underlifts as assets. We settle these over time as liftings areequalized or in cash when production ends.

 

Revenue represents Nexen’sshare and is recorded net of royalty payments to governments and other mineralinterest owners. For our international operations, all government interests,except for income taxes, are considered royalty payments. Our revenue alsoincludes the recovery of costs paid on behalf of foreign governments ininternational locations. See Note 1(g).

 

**Chemicals**

 

Revenue from our chemicalsoperations is only recognized when our products are delivered to our customers.Delivery only takes place when we have a sales contract in place specifyingdelivery volumes and sales prices. We assess customer credit worthiness beforeentering into sales contracts to minimize collection risk.

 

**Marketing**

 

Substantially all of thephysical purchase and sales contracts entered into by our marketing operationare considered to be derivative instruments. Accordingly, financial andphysical commodity contracts (collectively derivative instruments) held by ourmarketing operation are stated at fair value on the balance sheet unless therequirements for hedge accounting are met (see Note 1(n)). We record any changein fair value as a gain or loss in marketing and other.

 

Any margin realized by ourmarketing operation on the sale of our proprietary oil and gas production isincluded in marketing and other. Sales of our proprietary production arerecorded at monthly market-based prices and intercompany profits and lossesbetween segments are eliminated. We assess customer credit worthiness beforeentering into contracts and provide for netting terms to minimize collectionrisk. Amounts are recorded on a net basis where we have the legal right ofoffset.

 

93

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**(k) Incometaxes**

 

We follow the liabilitymethod of accounting for income taxes (see Note 18). This method recognizesincome tax assets and liabilities at current rates, based on temporarydifferences in reported amounts for financial statement and tax purposes. Theeffect of a change in income tax rates on future income tax assets and futureincome tax liabilities is recognized in income when substantively enacted.

 

We do not provide for foreignwithholding taxes on the undistributed earnings of our foreign subsidiaries, aswe intend to invest such earnings indefinitely in foreign operations.

 

**(l) Foreigncurrency translation**

 

Our foreign operations, whichare considered financially and operationally independent, are translated fromtheir functional currency into Canadian dollars as follows: 

 

**•****     **assets and liabilities using exchange rates atthe balance sheet dates; and

 

**•****     **revenues and expenses using average exchangerates throughout the year.

 

Gains and losses resultingfrom this translation are included in the cumulative foreign currencytranslation adjustment in shareholders’ equity. Monetary balances denominatedin a currency other than a functional currency are translated into thefunctional currency using exchange rates at the balance sheet dates. Gains andlosses 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 againstour net investment in US-dollar based self-sustaining foreign operations. Gainsand losses resulting from the translation of the designated US-dollar debt areincluded in the cumulative foreign currency translation adjustment inshareholders’ equity. If our US-dollar debt, net of income taxes, exceeds ourUS-dollar investment in foreign operations, then the gains or lossesattributable to such excess are included in marketing and other in theConsolidated Statement of Income.

 

**(m)Capitalized interest**

 

We capitalize interest onmajor development projects until the project is substantially complete usingthe weighted-average interest rate on all of our borrowings. Capitalizedinterest cannot exceed the actual interest incurred.

 

**(n)  Derivative instruments**

 

**Non-TradingActivities**

 

We use derivative instrumentssuch as physical purchase and sales contracts, forwards, futures, swaps andoptions for non-trading purposes to manage fluctuations in commodity prices,foreign currency exchange rates and interest rates (see Note 7). We recordthese instruments at fair value at the balance sheet date and record any changein fair value as a net gain or loss in marketing and other during the period ofchange unless the requirements for hedge accounting are met. Hedge accountingis used when there is a high degree of correlation between price movements inthe derivative instruments and the items designated as being hedged. Nexenformally documents all hedges and the risk management objectives at theinception of the hedge. We recognize gains and losses on the derivativeinstruments designated as hedges in the same period as the gains or losses onthe hedged items are recognized. If effective correlation ceases, hedgeaccounting is terminated, and future changes in the market value of thederivative instrument are included as gains or losses in marketing and other inthe period of change.

 

**TradingActivities**

 

Our marketing operation usesderivative instruments for marketing and trading crude oil and natural gasincluding:

** **

•      commoditycontracts settled with physical delivery;

** **

•      exchange-tradedfutures and options; and

** **

•      non-exchangetraded forwards, swaps and options.

 

We record these instrumentsat fair value at the balance sheet date and record changes in fair value as netgains or losses in marketing and other during the period of change. The fairvalue of these instruments is recorded as accounts receivable or

 

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payable if we anticipatesettling the instruments within a year of the balance sheet date. If weanticipate settling the instruments beyond 12 months, we record them asdeferred charges and other assets or deferred credits and other liabilities.

 

**(o) Employeefuture benefits**

 

The cost of pension benefitsearned by employees in our defined benefit pension plans is actuariallydetermined using the projected-benefit method prorated on service and our bestestimate of the plans’ investment performance, salary escalations and retirementages of employees. To calculate the plans’ expected returns, assets aremeasured at fair value. Past service costs arising from plan amendments, andnet actuarial gains and losses that exceed 10% of the greater of the accruedbenefit obligation and the fair value of plan assets, are expensed in equalamounts over the expected average remaining service life of the employee group.We measure the plan assets and the accrued benefit obligation on October 31each year.

 

**(p)Stock-based compensation**

 

In 2003, we adopted thefair-value method of accounting for stock options granted to employees anddirectors. We recorded stock-based compensation expense in the ConsolidatedStatement of Income as general and administrative expenses for all optionsgranted on or after January 1, 2003, with a corresponding increase tocontributed surplus. Compensation expense for options granted was based onestimated fair values at the time of grant and we recognized the expense overthe vesting period of the option.

 

In May 2004, we modified ourstock option plan to a tandem option plan by including a cash feature. Thetandem options give the holders a right to either purchase common shares at theexercise price or to receive cash payments equal to the excess of the marketvalue of the common shares over the exercise price. As a result of themodification, we record obligations for the tandem options using theintrinsic-value method of accounting and recognize compensation expense.Obligations are accrued on a graded vesting basis and represent the differencebetween the market value of our common shares and the exercise price of theoptions. The obligations are revalued each reporting period based on the changein the market value of our common shares and the number of graded vestedoptions outstanding. We reduce the liability when the options are surrenderedfor cash. When the options are exercised for stock, the recorded liabilityamount is transferred to share capital.

 

Stock options awarded to ourUS employees between December 1, 2004 and December 1, 2005 do not include acash feature and are not accounted for as tandem options. Instead, we accountfor these options using the fair-value method. Compensation expense is based onestimated fair values at the time of grant and is recognized over the vestingperiod of the options. The expense is included as general and administrativeexpense with a corresponding increase to contributed surplus. Stock optionsawarded to our US employees after December 1, 2005 are accounted for as tandemoptions.

 

We provide stock appreciationrights to employees as described in Note 12, and we account for these on thesame basis as our tandem options. Obligations are accrued as compensationexpense over the graded vesting period of the stock appreciation rights.

 

**(q) Cash andcash equivalents**

 

Cash and cash equivalentsinclude short-term, highly liquid investments that mature within three monthsof their purchase. They are recorded at cost, which approximates market value.

 

**(r)Restricted cash and margin deposits**

 

Restricted cash includesmargin deposits relating to our exchange-traded derivative contracts and othercash balances subject to regulatory restrictions.

 

**(s) Leases**

 

We classify leases enteredinto as either capital or operating leases. Leases that transfer substantiallyall of the benefits and risks of ownership to us are accounted for as capitalleases and the related assets are included with PP&E. These assets aredepreciated on the same basis as other PP&E. Rental payments underoperating leases are expensed as incurred.

 

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**(t)Transportation**

 

We pay to transport the crudeoil, natural gas and chemicals products that we market, and then bill ourcustomers for the transportation. This transportation is presented in ourConsolidated Financial Statements as a cost to us and is recorded astransportation and other. Our marketing operation has received cash payments inexchange for assuming certain transportation obligations from third parties.These cash payments have been recorded as deferred liabilities and arerecognized in net income as the transportation is used.

 

**(u) Changesin accounting principles**

 

**Stock-BasedCompensation for Employees Eligible to Retire Before the Vesting Date**

 

In the fourth quarter of2006, we retroactively adopted EIC-162, *Stock-BasedCompensation for Employees Eligible to Retire Before the Vesting Date*(EIC-162). EIC-162 provides that if an employee is eligible to retire on thegrant date of a stock-based award, related compensation expense is recognizedin full at that date as there is no ongoing service requirement to earn theaward. In addition, if an employee becomes eligible to retire during thevesting period, related compensation expense is recognized over the period fromthe grant date to the retirement eligibility date on a graded vesting basis.Prior to the adoption of EIC-162, we did not consider the retirement dates ofour employees in the determination of our stock-based compensation expense.EIC-162 is effective for interim and annual periods ending on or after December31, 2006 and is to be adopted on a retroactive basis. For the year endedDecember 31, 2006, the impact of adopting EIC-162 decreased general andadministrative expense by $9 million, increased provision for future incometaxes by $3 million, increased net income by $6 million, and increased basicand diluted earnings per share by $0.02/share. For the year ended December 31,2005, the impact of adopting EIC-162 increased general and administrativeexpense by $17 million, decreased provision for future income taxes by $5million, reduced net income by $12 million, and reduced basic and dilutedearnings per share by $0.05/share. The impact on the year ended December 31,2004 was immaterial.

 

**2.**               **CANExUS INCOME FUNd**

 

In June 2005, our board ofdirectors approved a plan to monetize our chemicals operations through thecreation of an income trust and the issuance of trust units in an initialpublic offering. This initial public offering closed on August 18, 2005, withCanexus Income Fund (Canexus) issuing 30 million units at a price of $10 perunit for gross proceeds of $300 million ($284 million, net of underwriters’commissions).

 

Concurrent with the closingof the offering, Canexus acquired a 36.5% interest in Canexus Limited Partnership(Canexus LP) using the net proceeds from the initial public offering. CanexusLP acquired Nexen’s chemicals business for approximately $1 billion, comprisedof the net proceeds from Canexus’ initial public offering and $200 million(US$167 million) of bank debt, plus the issuance of 52.3 million exchangeablelimited partnership units (Exchangeable LP Units) of Canexus LP. At that time,the Exchangeable LP Units held by Nexen represented a 63.5% interest in CanexusLP.

 

The Exchangeable LP Unitsheld by Nexen are exchangeable on a one-for-one basis for trust units ofCanexus. As a result, the Exchangeable LP Units owned by Nexen wereexchangeable into 52.3 million trust units which represented 63.5% of theoutstanding trust units of Canexus assuming exchange of the Exchangeable LPUnits.

 

On September 16, 2005, theunderwriters of the initial public offering exercised a portion of theirover-allotment option to purchase 1.75 million trust units at $10 per unit forgross proceeds of $18 million ($17 million, net of underwriters’ commissions). Asa result, Nexen exchanged 1.75 million of its Exchangeable LP Units for $17million in net proceeds. After this exchange, Nexen has a 61.4% interest inCanexus LP represented by 50.5 million Exchangeable LP Units. The initialpublic offering, together with the exercise of the over-allotment, resulted intotal net proceeds to Nexen of $301 million.

 

These transactions dilutedour interest in our chemicals operations. As a result of this dilution, werecorded a gain of $193 million during the third quarter of 2005.

 

We have the right to nominatea majority of the members of the board of Canexus Limited, the corporation withresponsibility for the strategic management and operational decisions ofCanexus and Canexus LP. Nexen currently has nominated two representatives tothe 10-member board of Canexus Limited. Since we have retained effectivecontrol of our chemicals business, the

 

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results, assets andliabilities of this business have been included in these financial statements.The non-Nexen ownership interests in our chemicals business are shown asnon-controlling interests.

 

During the year $28 million(2005 - $10 million) of distributions were paid to non-Nexen ownershipinterests.

 

**3.**               **BUSINESS ACqUISITIONS**

 

In 2006, we completed minorbusiness acquisitions related to our marketing group for $78 million, net ofcash acquired. These acquisitions were accounted for using the purchase methodof accounting. The assets and liabilities purchased were primarily workingcapital and we recorded goodwill of $12 million as a result of theacquisitions.

 

On December 1, 2004, weacquired 100% of the issued and outstanding share capital of EnCana (UK)Limited (EnCana UK) from EnCana Corporation (EnCana) for cash consideration ofUS$2.1 billion, subject to certain adjustments. EnCana UK held all of EnCana’soffshore oil and gas assets in the North Sea. We acquired EnCana UK toestablish a strategic presence in the North Sea by acquiring operatorship ofthe Buzzard field development and operatorship of the producing Scott andTelford fields. The acquisition also gave us access to interests in severalsatellite discoveries and more than 700,000 net undeveloped exploration acres.In addition, we acquired the management and technical teams that found and aredeveloping the Buzzard discovery. Goodwill paid was attributable to theestablished North Sea presence acquired and the knowledge and businessrelationships acquired through the management team and employees of EnCana UK.

 

The acquisition has beenaccounted for using the purchase method, and the results of EnCana UK have beenconsolidated with the results of Nexen from December 1, 2004. The followingtable shows the allocation of the purchase price based on the estimated fairvalues 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 formaresults for the year ended December 31, 2004 are shown below as if theacquisition had occurred on January 1, 2004. Pro forma results are notnecessarily indicative of actual results or future performance.

 
| ** **                                        | ** ** | **2004** | ** ** |
|---------------------------------------------------|------------|----------|------------|
| Revenues                                          |       | 4,258    |       |
| Net Income                                        |       | 841      |       |
| Earnings Per  Common Share—Basic ($/share)   |       | 3.27     |       |
| Earnings Per  Common Share—Diluted ($/share) |       | 3.23     |       |

 

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**4.**               **ACCOUNTS RECEIVABLE**

 
| ** **                          | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|-------------------------------------|------------|-----------|------------|-----------|------------|
| Trade                               |       |      |       |      |       |
| Marketing                           |       | 2,226     |       | 2,400     |       |
| Oil and Gas                         |       | 600       |       | 614       |       |
| Chemicals and Other                 |       | 58        |       | 48        |       |
|                                |       | 2,884     |       | 3,062     |       |
| Non-Trade                           |       | 80        |       | 96        |       |
|                                |       | 2,964     |       | 3,158     |       |
| Allowance  for Doubtful Receivables |       | (13       | )          | (7        | )          |
|                                |       |      |       |      |       |
| **Total  Accounts Receivable**      | ** ** | **2,951** | ** ** | **3,151** | ** ** |

 

**5.**               **INVENTORIES ANd SUPPLIES**

 
| ** **                          | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|
| Finished  Products                  |       |     |       |     |       |
| Marketing                           |       | 609      |       | 320      |       |
| Oil and Gas                         |       | 21       |       | 11       |       |
| Chemicals and Other                 |       | 14       |       | 15       |       |
|                                |       | 644      |       | 346      |       |
| Work in  Process                    |       | 5        |       | 6        |       |
| Field  Supplies                     |       | 137      |       | 152      |       |
|                                |       |     |       |     |       |
| **Total  Inventories and Supplies** | ** ** | **786**  | ** ** | **504**  | ** ** |

 

**6.**               **PROPERTy, PLANT ANd EqUIPMENT**

 
| ** **                  | ** ** | **2006**   | ** ** | **2005**        | ** ** |
|-----------------------------|------------|------------|------------|-----------------|------------|
| ** **                  | ** ** | ** ** | ** ** | **Accumulated** | ** ** | **Net Book** | ** ** | ** ** | ** ** | **Accumulated** | ** ** | **Net Book** | ** ** |
| ** **                  | ** ** | **Cost**   | ** ** | **DD&A**    | ** ** | **Value** | ** ** | **Cost** | ** ** | **DD&A** | ** ** | **Value** | ** ** |
| Oil and Gas                 |       |       |       |            |       |   |   |   |   |   |   |   |   |
| Yemen                       |       | 779        |       | 599             |       | 180 |   | 833 |   | 546 |   | 287 |   |
| Yemen—Carried Interest |       | 1,625      |       | 1,529           |       | 96 |   | 1,410 |   | 1,295 |   | 115 |   |
| Canada                      |       | 5,216      |       | 1,448           |       | 3,768 |   | 3,631 |   | 1,311 |   | 2,320 |   |
| United States               |       | 2,889      |       | 1,445           |       | 1,444 |   | 2,437 |   | 1,159 |   | 1,278 |   |
| United Kingdom              |       | 4,710      |       | 432             |       | 4,278 |   | 4,013 |   | 216 |   | 3,797 |   |
| Other Countries             |       | 249        |       | 78              |       | 171 |   | 249 |   | 119 |   | 130 |   |
|                        |       | 15,468     |       | 5,531           |       | 9,937 |   | 12,573 |   | 4,646 |   | 7,927 |   |
| Marketing                   |       | 226        |       | 47              |       | 179 |   | 177 |   | 72 |   | 105 |   |
| Syncrude                    |       | 1,304      |       | 179             |       | 1,125 |   | 1,240 |   | 171 |   | 1,069 |   |
| Chemicals                   |       | 854        |       | 494             |       | 360 |   | 827 |   | 456 |   | 371 |   |
| Corporate  and Other        |       | 286        |       | 148             |       | 138 |   | 245 |   | 123 |   | 122 |   |
|                        |       |       |       |            |       |   |   |   |   |   |   |   |   |
| **Total  PP&E**         | ** ** | **18,138** | ** ** | **6,399**       | ** ** | **11,739** | ** ** | **15,062** | ** ** | **5,468** | ** ** | **9,594** | ** ** |

 

The above table includescapitalized costs of $6,708 million (2005—$5,211 million) relating to unprovedproperties and projects under construction or development. These costs are notbeing depreciated, depleted or amortized. These costs include $2,399 millionrelated to our Buzzard project in the North Sea that began operations inJanuary 2007.

 

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Our Syncrude operations are considered a mining operation for USreporting purposes. PP&E at December 31, 2006 and 2005 includes mineralrights of $6 million.

 

**Depreciation,Depletion, Amortization and Impairment (DD&A)**

 

Our 2006 DD&A expenseincludes $93 million of impairment expense, primarily related to two naturalgas producing properties in the Gulf of Mexico. The impairment was caused byunsuccessful development programs and negative year-end reserve revisions. Thecarrying values of the impaired properties have been reduced to their estimatedfair value. In addition, our 2006 DD&A expense includes $15 million (2005 -$58 million) relating to the write down of a portion of our purchase priceallocation to unproved properties purchased in the North Sea as a result ofunsuccessful exploration activities.

 

**Research andDevelopment**

 

We incurred $53 million (2005—$54million) in connection with research and development activities related todeveloping new technologies for increasing oil recoveries. Research costs of$50 million (2005—$44 million) were included in other expense onthe Consolidated Statement of Income. The development costs have been deferredand are included in PP&E.

 
| ** **                                     | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------------|------------|----------|------------|----------|------------|
| Development  Costs Deferred, Beginning of Year |       | 25       |       | 15       |       |
| Deferred in the Year                           |       | 3        |       | 10       |       |
| Amortized in the Year                          |       | —   |       | —   |       |
| **Development  Costs deferred, End of year**   | ** ** | **28**   | ** ** | **25**   | ** ** |

 

**SuspendedWell Costs**

 

The following table shows thechanges in capitalized exploratory well costs during the years ended December31, 2006 and 2005, and does not include amounts that were initially capitalizedand subsequently expensed in the same period.

 
| ** **                                                                                    | ** ** | **2006** | ** ** | **2005** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Balance at  Beginning of Year                                                                 |       | 252      |       | 116      |       |
| Additions to Capitalized Exploratory Well  Costs Pending the Determination of Proved Reserves |       | 129      |       | 174      |       |
| Capitalized Exploratory Well Costs Charged  to Expense                                        |       | (70      | )          | (27      | )          |
| Transfers to Wells, Facilities and  Equipment Based on Determination of Proved Reserves       |       | (84      | )          | (3       | )          |
| Effects of Foreign Exchange                                                                   |       | (1       | )          | (8       | )          |
| **Balance  at End of year**                                                                   | ** ** | **226**  | ** ** | **252**  | ** ** |

 

The following table providesan aging of capitalized exploratory well costs based on the date drilling wascompleted and shows the number of projects for which exploratory well costshave been capitalized for a period greater than one year after the completionof drilling.

 
| ** **                                                                                           | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Capitalized for a Period of One Year or  Less                                                        |       | 179      |       | 165      |       |
| Capitalized for a Period of Greater than  One Year                                                   |       | 47       |       | 87       |       |
| **Balance  at End of year**                                                                          | ** ** | **226**  | ** ** | **252**  | ** ** |
|                                                                                                 |       |     |       |     |       |
| Number of  Projects that have Exploratory Well Costs Capitalized for a Period Greater  than One Year |       | 4        |       | 3        |       |

 

As at December 31, 2006, wehave exploratory costs that have been capitalized for more than one yearrelating to our interest in an exploratory block, offshore Nigeria ($14million), our interest in an exploratory block in the Gulf of Mexico ($16million), our coalbed methane exploratory activities in Canada ($10 million)and an exploratory block in the North Sea ($7 million). Our

 

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capitalized costs in Nigeriainclude capital spending for four successful wells. Development plans arecurrently being prepared for this area. We have capitalized costs related tosuccessful wells drilled in the Gulf of Mexico and the North Sea. In Canada, wehave capitalized exploratory costs relating to our coalbed methane projects. Weare assessing all of these wells and projects, and we are working with ourpartners to prepare development plans.

 

**7. DERIVATIVEINSTRUMENTS AND FINANCIAL RISK MANAGEMENT**

 

**(a) Carryingvalue and estimated fair value of derivative and financial instruments**

 

The carrying values, fairvalues and unrecognized gains or losses on our outstanding derivatives andlong-term financial assets and liabilities at December 31 are:

 
| ** **                            | ** ** | **2006**     | ** ** | **2005**       | ** ** |
|---------------------------------------|------------|--------------|------------|----------------|------------|
| ** **                            | ** ** | **Carrying** | ** ** | ** **     | ** ** | **Unrecognized** | ** ** | **Carrying** | ** ** | ** ** | ** ** | **Unrecognized** | ** ** |
| ** **                            | ** ** | **Value**    | ** ** | **Fair Value** | ** ** | **Gain (Loss)** | ** ** | **Value** | ** ** | **Fair Value** | ** ** | **Gain (Loss)** | ** ** |
| **Commodity  Price Risk**             | ** ** | ** **   | ** ** | ** **     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Non-Trading Activities                |       |         |       |           |       |   |   |   |   |   |   |   |   |
| Crude Oil Put Options                 |       | 19           |       | 19             |       | — |   | 4 |   | 4 |   | — |   |
| Fixed-Price Natural Gas Contracts     |       | (96          | )          | (96            | )          | — |   | (175 | ) | (175 | ) | — |   |
| Natural Gas Swaps                     |       | (8           | )          | (8             | )          | — |   | 29 |   | 29 |   | — |   |
|                                  |       |         |       |           |       |   |   |   |   |   |   |   |   |
| Trading Activities                    |       |         |       |           |       |   |   |   |   |   |   |   |   |
| Crude Oil and Natural Gas             |       | 372          |       | 372            |       | — |   | 161 |   | 161 |   | — |   |
| Future Sale of Gas Inventory          |       | —       |       | 25             |       | 25 |   | — |   | (35 | ) | (35 | ) |
|                                  |       |         |       |           |       |   |   |   |   |   |   |   |   |
| **Foreign  Currency Risk**            | ** ** | ** **   | ** ** | ** **     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Non-Trading Activities                |       | —       |       | —         |       | — |   | 14 |   | 14 |   | — |   |
| Trading Activities                    |       | (12          | )          | (12            | )          | — |   | 8 |   | 8 |   | — |   |
| **Total Derivatives**                 | ** ** | **275**      | ** ** | **300**        | ** ** | **25** | ** ** | **41** | ** ** | **6** | ** ** | **(35** | **)** |
|                                  |       |         |       |           |       |   |   |   |   |   |   |   |   |
| **Financial  Assets and Liabilities** | ** ** | ** **   | ** ** | ** **     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Long-Term Debt                        |       | (4,673       | )          | (4,728         | )          | (55 | ) | (3,687 | ) | (3,863 | ) | (176 | ) |

 

The estimated fair value ofall derivative instruments is based on quoted market prices and, if not available,on estimates from third-party brokers or dealers. The carrying value of cashand cash equivalents, restricted cash, margin deposits, amounts receivable andshort-term obligations approximates their fair value because the instrumentsare near maturity.

 

**(b)Commodity price risk management**

 

**Non-TradingActivities**

 

We generally sell our crudeoil and natural gas under short-term market-based contracts.

 

**Crude oil put options**

 

In 2006, we purchased WTIcrude oil put options to provide a base level of price protection withoutlimiting our upside to higher prices. These options establish an annual averageWTI floor price of US$50/bbl in 2007 on 105,000 bbls/d at a cost of $26million. In 2004, we purchased WTI crude oil put options to manage thecommodity price risk exposure of a portion of our oil production in 2006 and2005. These options established an annual average WTI floor price of US$38/bblin 2006 and US$43/bbl in 2005 at a cost of $144 million. The 2006 and 2005 WTIcrude oil put options were not used and have expired. The 2007

 

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WTI crude oil put options arestated at fair value and are included in deferred charges and other assets asthey settle beyond 12 months from December 31, 2006. Any change in fair valueis included in marketing and other on the Consolidated Statement of Income.

 
| ** **                 | ** ** | **Notional** | ** ** | ** ** | ** ** | **Average**     | ** ** | ** **               | ** ** |
|----------------------------|------------|--------------|------------|------------|------------|-----------------|------------|--------------------------|------------|
| ** **                 | ** ** | **Volumes**  | ** ** | **Term**   | ** ** | **Price (WTI)** | ** ** | **Fair Value**           | ** ** |
| ** **                 | ** ** | **(bbls/d)** | ** ** | ** ** | ** ** | **(US$/bbl)**   | ** ** | **(Cdn$ millions)** | ** ** |
| WTI Crude  Oil Put Options |       | 105,000      |       | 2007       |       | 50              | ** ** | **19**                   | ** ** |

 

**Fixed price natural gas contractsand natural gas swaps**

 

In July and August 2005, wesold certain Canadian oil and gas properties, and we retained fixed-pricenatural gas sales contracts that were previously associated with thoseproperties (see Note 14). Since these contracts are no longer used in thenormal course of our oil and gas operations, they have been included in ourConsolidated Balance Sheet at fair value. Any change in fair value is includedin marketing and other in the Consolidated Statement of Income.

 
| ** **                         | ** ** | **Notional** | ** ** | ** **     | ** ** | ** **     | ** ** | ** **               | ** ** |
|------------------------------------|------------|--------------|------------|----------------|------------|----------------|------------|--------------------------|------------|
| ** **                         | ** ** | **Volumes**  | ** ** | **Term**       | ** ** | **Price**      | ** ** | **Fair Value**           | ** ** |
| ** **                         | ** ** | **(Gj/d)**   | ** ** | ** **     | ** ** | **($/Gj)**     | ** ** | **(Cdn$ millions)** | ** ** |
| Fixed-Price  Natural Gas Contracts |       | 15,514       |       | 2007           |       | 2.46           |       | (22                      | )          |
|                               |       | 15,514       |       | 2008—2010 |       | 2.56—2.77 |       | (74                      | )          |
|                               | ** ** | ** **   | ** ** | ** **     | ** ** | ** **     | ** ** | **(96**                  | **)**      |

 

Following the sale of theCanadian oil and gas properties, we entered into natural gas swaps toeconomically hedge our exposure to the fixed-price natural gas contracts. Anychange in fair value is included in marketing and other in the ConsolidatedStatement of Income.

 
| ** **         | ** ** | **Notional** | ** ** | ** **     | ** ** | ** ** | ** ** | ** **               | ** ** |
|--------------------|------------|--------------|------------|----------------|------------|------------|------------|--------------------------|------------|
| ** **         | ** ** | **Volumes**  | ** ** | **Term**       | ** ** | **Price**  | ** ** | **Fair Value**           | ** ** |
| ** **         | ** ** | **(Gj/d)**   | ** ** | ** **     | ** ** | **($/Gj)** | ** ** | **(Cdn$ millions)** | ** ** |
| Natural Gas  Swaps |       | 15,514       |       | 2007           |       | 7.60       |       | (6                       | )          |
|               |       | 15,514       |       | 2008—2010 |       | 7.60       |       | (2                       | )          |
|               | ** ** | ** **   | ** ** | ** **     | ** ** | ** ** | ** ** | **(8**                   | **)**      |

 

**TradingActivities**

 

**Crude oil and natural gas**

 

We enter into physicalpurchase and sales contracts as well as financial commodity contracts toenhance our price realizations and lock-in our margins. The physical andfinancial commodity contracts (derivative contracts) are stated at marketvalue. The $372 million fair value of the commodity contracts at December 31,2006 is included in the Consolidated Balance Sheet and any change in fair valueis included in marketing and other in the Consolidated Statement of Income.

 

**Future sale of gas inventory**

 

We have certain NYMEX futurescontracts and swaps in place, which effectively lock-in our margins on thefuture sale of our natural gas inventory in storage. We have designated, inwriting, some of these derivative contracts as cash flow hedges of the

 

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future sale of our storageinventory. As a result, gains and losses on these designated futures contractsand swaps are recognized in net income when the inventory in storage is sold.The principal terms of these outstanding contracts and the unrecognized gainsat December 31, 2006 are:

 
| ** **                 | ** ** | **Hedged**  | ** ** | ** **   | ** ** | **Average**   | ** ** | **Unrecognized**         | ** ** |
|----------------------------|------------|-------------|------------|--------------|------------|---------------|------------|--------------------------|------------|
| ** **                 | ** ** | **Volumes** | ** ** | **Month**    | ** ** | **Price**     | ** ** | **Gain**                 | ** ** |
| ** **                 | ** ** | **(mmbtu)** | ** ** | ** **   | ** ** | **(US$/mcf)** | ** ** | **(Cdn$ millions)** | ** ** |
| NYMEX  Natural Gas Futures |       | 5,580,000   |       | January 2007 |       | 10.73         | ** ** | **25**                   | ** ** |

 

In late 2006, we de-designatedcertain futures contracts that had been designated as cash flow hedges offuture sales of our natural gas in storage. These contracts were de-designatedsince it became uncertain that the future sales of natural gas would occurwithin the designated time frame. As it is reasonably possible that the futuresales may take place as designated at the inception of the hedgingrelationship, gains of $65 million on the futures contracts have been deferredand will be recognized in net income in 2007 in the originally designated timeframe.

 

**(c) Foreigncurrency exchange rate risk management**

 

**Non-TradingActivities**

** **

**US dollar call options—Canexus**

 

The operations of Canexus areexposed to changes in the US-dollar exchange rate as a portion of its sales aredenominated in US dollars. Canexus periodically purchases US-dollar calloptions to reduce this exposure to fluctuations in the Canadian-US dollarexchange rate. Under outstanding option contracts at December 31, 2006, CanexusLP had the right to sell US$5 million monthly and purchase Canadian dollars atan exchange rate of US$0.85 for the period August 16, 2006 to January 10, 2007and has the right to sell US$5 million monthly and purchase Canadian dollars atan exchange rate of US$0.87 for the period January 10, 2007 to July 11, 2007.The fair value of these contracts at December 31, 2006 was immaterial andchanges in fair value are included in marketing and other in the ConsolidatedStatement of Income.

 

**Foreign currency swap**

 

We occasionally use derivativeinstruments to effectively convert cash flows from Canadian to US dollars andvice versa. During the year, we held a foreign currency derivative instrumentthat obligated us and the counterparty to exchange principal and interestamounts. In November 2006, we paid US$37 million and received Cdn$50 million tosettle the foreign currency swap (see Note 8). The change in fair value wasincluded in marketing and other in the Consolidated Statement of Income.

 

**Other**

 

The foreign exchange gains orlosses related to our designated debt are included in the cumulative foreigncurrency translation adjustment in shareholders’ equity. Our net investment inself-sustaining foreign operations and our designated US-dollar debt atDecember 31 are as follows:

 
| **(US$ millions)**                               | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------------------------------|------------|----------|------------|----------|------------|
| Net  Investment in Self-Sustaining Foreign Operations |       | 4,534    |       | 4,357    |       |
| US-Dollar  Debt                                       |       | 3,761    |       | 2,700    |       |

 

We also have small exposuresto currencies other than the US dollar. A portion of our United Kingdomoperating expenses, capital spending and future asset retirement expendituresis denominated in British pounds and Euros. We do not have any materialexposure to highly inflationary foreign currencies.

 

102

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**TradingActivities**

 

Our sales and purchases ofcrude oil and natural gas are generally transacted in or referenced to the USdollar, as are most of the financial commodity contracts used by our marketinggroup. However, we pay for many of our purchases in Canadian dollars. We enter intoUS-dollar forward contracts and swaps to manage this exposure. Losses of $12million on our US-dollar forward contracts and swaps at December 31, 2006 areincluded in the Consolidated Balance Sheet, and any change in fair value isincluded in marketing and other in the Consolidated Statement of Income.

 

**(d) Totalcarrying value of derivative contracts related to trading activities**

 

Amounts related to derivativeinstruments held by our marketing operation are equal to fair value as we usemark-to-market accounting, and are as follows at December 31:

 
| ** **                                           | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------------------|------------|----------|------------|----------|------------|
| Accounts  Receivable                                 |       | 731      |       | 382      |       |
| Deferred  Charges and Other Assets (1) (Note 10)     |       | 153      |       | 232      |       |
| **Total Derivative  Contract Assets**                | ** ** | **884**  | ** ** | **614**  | ** ** |
|                                                 |       |     |       |     |       |
| Accounts  Payable and Accrued Liabilities            |       | 325      |       | 321      |       |
| Deferred  Credits and Other Liabilities (1)(Note 11) |       | 199      |       | 124      |       |
| **Total Derivative  Contract Liabilities**           | ** ** | **524**  | ** ** | **445**  | ** ** |
|                                                 |       |     |       |     |       |
| **Total Derivative  Contract Net Assets**(2)         | ** ** | **360**  | ** ** | **169**  | ** ** |

 

----

*Notes:*

*(1)*       *These derivative instrumentssettle beyond 12 months and are considered non-current.*

*(2)*       *Comprised of $372 million(2005**—**$161 million) related tocommodity contracts and losses of $12 million (2005**—**$8 million) related toUS-dollar forward contracts and swaps.*

 

As a physical energymarketer, we match the contract months of our derivative instruments with thecontract months of our physical sales and purchases. As a result, ourdisclosure with respect to derivative instruments includes amounts with noongoing commodity price or foreign currency risk as at December 31, 2006.Excluding such amounts, derivative contracts included in accounts receivable atDecember 31, 2006 amounted to $460 million (December 31, 2005 - $382 million)and derivative contracts included in accounts payable and accrued liabilitiesamounted to $312 million (December 31, 2005 - $290 million).

 

Our exchange-tradedderivative contracts are subject to margin deposit requirements. We arerequired to advance cash to counterparties in order to satisfy theserequirements. We have margin deposits of $197 million (December 31, 2005—nil),which have been included in restricted cash and margin deposits on ourConsolidated Balance Sheet at December 31, 2006.

 

**(e) Interestrate risk management**

 

We use fixed and floatingrate debt to finance our operations. The floating rate debt exposes us tochanges in interest payments as interest rates fluctuate. To manage thisexposure, we maintain a combination of fixed and floating rate borrowings andfacilities. At December 31, 2006, fixed-rate borrowings comprised 73% (2005—95%)of our long-term debt at an effective average rate of 6.3% (2005—6.3%).During the year, we periodically drew on our floating-rate, unsecured,committed term credit facilities. We had no interest rate swaps outstanding in2006 or 2005.

 

**(f) Creditrisk management**

 

A substantial portion of ouraccounts receivable are with counterparties in the energy industry and aresubject to normal industry credit risk. This concentration of risk within theenergy industry is reduced because of our broad base of domestic andinternational counterparties. We assess the financial strength of ourcounterparties, including those involved in marketing and other commodityarrangements, and we limit the total exposure to individual counterparties. Aswell, a number of our contracts contain provisions that allow us to demand theposting of collateral in the event downgrades to non-investment grade creditratings occur. Credit risk,

 

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including credit concentrations,is routinely reported to our Risk Management Committee. We also use standardagreements that allow for the netting of exposures associated with a singlecounterparty. We believe this minimizes our overall credit risk.

 

**8.**               **LONG-TERM DEBT AND SHORT-TERMBORROWINGS**

 
| ** **                                              | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|---------------------------------------------------------|------------|-----------|------------|-----------|------------|
| Canexus LP  Term Credit Facilities (US$149 million) (a) |       | 174       |       | 171       |       |
| Term Credit  Facilities (US$925 million) (b)            |       | 1,078     |       | —    |       |
| Debentures,  due 2006 (c)                               |       | —    |       | 93        |       |
| Medium-Term  Notes, due 2007 (d)                        |       | 150       |       | 150       |       |
| Medium-Term  Notes, due 2008 (e)                        |       | 125       |       | 125       |       |
| Notes, due  2013 (US$500 million) (f)                   |       | 583       |       | 583       |       |
| Notes, due  2015 (US$250 million) (g)                   |       | 291       |       | 292       |       |
| Notes, due  2028 (US$200 million) (h)                   |       | 233       |       | 233       |       |
| Notes, due  2032 (US$500 million) (i)                   |       | 583       |       | 583       |       |
| Notes, due  2035 (US$790 million) (j)                   |       | 920       |       | 921       |       |
| Subordinated  Debentures, due 2043 (US$460 million) (k) |       | 536       |       | 536       |       |
| **Total**                                               | ** ** | **4,673** | ** ** | **3,687** | ** ** |

 

**(a) CanexusLP term credit facilities**

 

Canexus LP has $350 millionof committed, secured term credit facilities, which are available until 2010.At December 31, 2006, $174 million (US$149 million) was drawn on thesefacilities (December 31, 2005—$171 million). Borrowings are available asCanadian bankers’ acceptances, LIBOR-based loans, Canadian prime rate loans orUS-dollar base rate loans. Interest is payable monthly at floating rates. Theterm credit facilities are secured by a floating charge debenture over all ofCanexus LP’s assets and by certain guarantees, security interests andsubordination agreements provided by certain affiliates of Canexus LP (which donot include Nexen). During 2006, the weighted-average interest rate on theCanexus LP term credit facilities was 5.9% (2005—4.8%).

 

**(b) Termcredit facilities**

 

We have committed, unsecured,term credit facilities of $3.6 billion, which are available until 2011. AtDecember 31, 2006, $1,078 million (US$925 million) was drawn on thesefacilities (December 31, 2005—nil). Borrowings are available as Canadianbankers’ acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollarbase rate loans or British pound call-rate loans. Interest is payable monthlyat floating rates. During 2006, the weighted-average interest rate was 5.7%(2005—4.4%). At December 31, 2006, $294 million ofthese facilities were utilized to support outstanding letters of credit(December 31, 2005—$250 million).

 

**(c) Debentures,due 2006**

 

During November 1996, weissued $100 million of unsecured 10 year redeemable debentures. Interest waspayable semiannually at a rate of 6.85%. In December 1996, $50 million of thisobligation was effectively converted through a foreign currency swap with aCanadian chartered bank to a US$37 million liability bearing interest at 6.75%for the term of the debentures. In November 2006, we repaid the outstandingdebentures of $100 million and realized a gain of $7 million on the foreigncurrency swap.

 

**(d)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 ofthe notes at any time. The redemption price will be the greater of par and anamount that provides the same yield as a Government of Canada Bond having aterm to maturity equal to the remaining

 

104

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term of the notes plus0.125%. Amounts due July 2007 have not been included in current liabilities aswe expect to refinance this amount with our term credit facilities.

 

**(e)Medium-term notes, due 2008**

 

During October 1997, weissued $125 million of notes. Interest is payable semi-annually at a rate of6.3%, and the principal is to be repaid in June 2008. We may redeem part or allof the notes at any time. The redemption price will be the greater of par andan amount that provides the same yield as a Government of Canada Bond having aterm to maturity equal to the remaining term of the notes plus 0.125%.

 

**(f) Notes,due 2013**

 

During November 2003, weissued 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 allof the notes at any time. The redemption price will be the greater of par andan amount that provides the same yield as a US Treasury security having a termto maturity equal to the remaining term of the notes plus 0.2%.

 

**(g) Notes,due 2015**

 

During March 2005, we issuedUS$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 ofthe notes at any time. The redemption price will be the greater of par and anamount that provides the same yield as a US Treasury security having a term tomaturity equal to the remaining term of the notes plus 0.15%.

 

**(h) Notes,due 2028**

 

During April 1998, we issuedUS$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 thenotes any time. The redemption price will be the greater of par and an amountthat provides the same yield as a US Treasury security having a term tomaturity equal to the remaining term of the notes plus 0.25%.

 

**(i) Notes,due 2032**

 

During March 2002, we issuedUS$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 ofthe notes at any time. The redemption price will be the greater of par and anamount that provides the same yield as a US Treasury security having a term tomaturity equal to the remaining term of the notes plus 0.375%.

 

**(j) Notes,due 2035**

 

During March 2005, we issuedUS$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 thenotes at any time. The redemption price will be the greater of par and anamount that provides the same yield as a US Treasury security having a term tomaturity equal to the remaining term of the notes plus 0.2%.

 

**(k)Subordinated debentures, due 2043**

 

During November 2003, weissued US$460 million of unsecured subordinated debentures. Interest is payablequarterly at a rate of 7.35%, and the principal is to be repaid in November2043. We may redeem part or all of the debentures at any time on or afterNovember 8, 2008. The redemption price is equal to the par value of theprincipal 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.

 

105

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**(l)Long-term debt repayments**

 
| 2007                       |       | 150       |       |
|----------------------------|------------|-----------|------------|
| 2008                       |       | 125       |       |
| 2009                       |       | —    |       |
| 2010                       |       | 174       |       |
| 2011                       |       | 1,078     |       |
| Thereafter                 |       | 3,146     |       |
| **Total Debt  Repayments** | ** ** | **4,673** | ** ** |

 

**(m) Debtcovenants**

 

Some of our debt instrumentscontain covenants with respect to certain financial ratios and our ability togrant security. At December 31, 2006, we were in compliance with all covenants.

 

**(n)Short-term borrowings**

 

Nexen has uncommitted,unsecured credit facilities of approximately $632 million. At December 31, 2006,$158 million (US$136 million) was drawn under these facilities (December 31,2005—nil). We have also utilized $252 million ofthese facilities to support outstanding letters of credit at December 31, 2006(2005—$468 million). Interest is payable at floatingrates. During 2006, the weighted-average interest rate on our short-termborrowings was 5.5% (2005—3.6%).

 

**(o) Interestexpense**

 
| ** **                  | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------|------------|----------|------------|----------|------------|----------|------------|
| Long-Term  Debt             |       | 275      |       | 260      |       | 182      |       |
| Other                       |       | 19       |       | 15       |       | 12       |       |
| Total                       |       | 294      |       | 275      |       | 194      |       |
| Less: Capitalized           |       | (241     | )          | (178     | )          | (51      | )          |
| **Total  Interest Expense** | ** ** | **53**   | ** ** | **97**   | ** ** | **143**  | ** ** |

 

Capitalized interest relatesto 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 amountsof the asset retirement obligations associated with our PP&E are asfollows:

 
| ** **                                       | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------------------------------|------------|----------|------------|----------|------------|
| Balance at  Beginning of Year                    |       | 611      |       | 468      |       |
| Obligations Assumed with Development  Activities |       | 75       |       | 72       |       |
| Obligations Discharged with Disposed  Properties |       | (1       | )          | (37      | )          |
| Expenditures Made on Asset Retirements           |       | (44      | )          | (34      | )          |
| Accretion                                        |       | 37       |       | 26       |       |
| Revisions to Estimates                           |       | (10      | )          | 138      |       |
| Effects of Foreign Exchange                      |       | 36       |       | (22      | )          |
| **Balance  at End of year**(1),(2)               | ** ** | **704**  | ** ** | **611**  | ** ** |

 

----

*Notes:*

*(1)*       *Obligations due within 12months of $21 million (2005**—**$21 million) have been included in accounts payable andaccrued liabilities.*

*(2)*       *Obligations relating to ouroil and gas activities amount to $658 million (2005—$564 million) and obligationsrelating to our chemicals business amount to $46 million (2005**—**$47 million).*

 

106

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Our total estimatedundiscounted asset retirement obligations amount to $1,770 million. We havediscounted the total estimated asset retirement obligations using aweighted-average, credit-adjusted risk-free rate of 5.7%. Approximately $97million included in our asset retirement obligations will be settled over thenext five years. The remaining obligations settle beyond five years and will befunded by future cash flows from our operations.

 

We own interests in assetsfor which the fair value of the asset retirement obligations cannot bereasonably determined because the assets currently have an indeterminate lifeand we cannot determine when remediation activities would take place. Theseassets include our interest in Syncrude’s upgrader and sulphure pile. Theestimated future recoverable reserves at Syncrude are significant and given thelong life of this asset, we are unable to determine when asset retirementactivities would take place. Furthermore, the Syncrude plant can continue torun indefinitely with ongoing maintenance activities. The retirementobligations for these assets will be recorded in the first year in which thelives of the assets are determinable.

 

**10. DEFERREDCHARGES AND OTHER ASSETS**

 
| ** **                                          | ** ** | **2006** | ** ** | **2005** | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|
| Long-Term  Marketing Derivative Contracts (Note 7d) |       | 153      |       | 232      |       |
| Deferred  Financing Costs                           |       | 59       |       | 63       |       |
| Asset  Retirement Remediation Fund                  |       | 13       |       | 14       |       |
| Crude Oil  Put Options (Note  7a)                   |       | 19       |       | 4        |       |
| Other                                               |       | 74       |       | 85       |       |
| **Total**                                           | ** ** | **318**  | ** ** | **398**  | ** ** |

 

**11. DEFERREDCREDITS AND OTHER LIABILITIES**

 
| ** **                                          | ** ** | **2006** | ** ** | **2005** | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|
| Fixed-Price  Natural Gas Contracts (Note 7b)        |       | 74       |       | 128      |       |
| Long-Term  Marketing Derivative Contracts (Note 7d) |       | 199      |       | 124      |       |
| Deferred  Transportation Revenue                    |       | 89       |       | 87       |       |
| Stock-Based  Compensation Liability                 |       | 6        |       | 53       |       |
| Defined  Benefit Pension Obligations (Note 16)      |       | 48       |       | 39       |       |
| Capital  Lease Obligations                          |       | 48       |       | 9        |       |
| Other                                               |       | 52       |       | 39       |       |
| **Total**                                           | ** ** | **516**  | ** ** | **479**  | ** ** |

 

**12.SHAREHOLDERS’ EQUITY**

** **

**(a) Authorizedcapital**

 

Authorized share capitalconsists of an unlimited number of common shares of no par value, and anunlimited number of Class A preferred shares of no par value, issuable inseries.

 

107

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**(b) Issuedcommon shares and dividends**

 
| **(thousands of shares)**                             | ** ** | **2006**    | ** ** | **2005**    | ** ** | **2004**    | ** ** |
|-------------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|
| Beginning of  Year                                    |       | 261,141     |       | 258,399     |       | 251,212     |       |
| Issue of  Common Shares for Cash                      |       |        |       |        |       |        |       |
| Exercise of Tandem Options                            |       | 846         |       | 1,823       |       | 5,902       |       |
| Dividend Reinvestment Plan                            |       | 276         |       | 605         |       | 895         |       |
| Employee Flow-through Shares                          |       | 250         |       | 314         |       | 390         |       |
| **End of  Year**                                      | ** ** | **262,513** | ** ** | **261,141** | ** ** | **258,399** | ** ** |
|                                                  |       |        |       |        |       |        |       |
| **Dividends  Declared per Common Share****($/share)** | ** ** | **0.20**    | ** ** | **0.20**    | ** ** | **0.20**    | ** ** |
|                                                  |       |        |       |        |       |        |       |
| **Cash  Consideration****(Cdn$millions)**             |       |        |       |        |       |        |       |
| Exercise of Tandem Options                            |       | 16          |       | 29          |       | 93          |       |
| Dividend Reinvestment Plan                            |       | 16          |       | 20          |       | 21          |       |
| Employee Flow-through Shares                          |       | 16          |       | 9           |       | 10          |       |
|                                                  | ** ** | **48**      | ** ** | **58**      | ** ** | **124**     | ** ** |

 

At December 31, 2006, therewere 498,831 common shares (2005—774,915; 2004—1,379,874)reserved for issuance under the Dividend Reinvestment Plan.

 

**(c) Tandemoptions**

 

In May 2004, our shareholdersapproved the modification of our stock option plan to a tandem option plan byincluding a cash feature. The tandem options give the holders a right to eitherpurchase common shares at the exercise price or to receive cash payments equalto the excess of the market value of the common shares over the exercise price.

 

Similar to our stockappreciation rights, we use the intrinsic-value method to recognizecompensation expense associated with our tandem options. Obligations areaccrued on a graded-vesting basis and represent the difference between themarket value of our common shares and the exercise price of the options. Theobligations are revalued each reporting period based on the change in themarket value of our common shares and the number of graded-vested optionsoutstanding.

 

Upon modification of thestock option plan, we were required to recognize an obligation for our tandemoptions. This obligation represented the difference between the market value ofour common shares and the weighted-average exercise price of the options. As aresult, we recognized an obligation of $85 million for the graded-vestedportion of the options outstanding on June 30, 2004. In the second quarter of2004, a one-time, non-cash charge of $82 million was included in general andadministrative expense, net of $3 million previously expensed in respect of ouroriginal stock options.

 

Following the introduction ofthe *American Job Creation Act of 2004*in the US, stock options awarded to our US employees between December 1, 2004and December 1, 2005 did not include a tandem option cash feature. We use thefair-value method to recognize compensation expense associated with theseoptions. The expense is recognized over the vesting period of the options witha corresponding increase to contributed surplus. This resulted in compensationexpense in 2006 of $2 million (2005—$2 million; 2004—$0.1million), which was included in general and administrative expense. In 2005, UStax regulations were modified and as a result, tandem options have been issuedto our US employees after December 1, 2005. These options are expensed usingthe intrinsic-method described above.

 

108

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We have granted options topurchase common shares to directors, officers and employees. Each optionpermits the holder to purchase one Nexen common share at the stated exerciseprice. Options granted prior to February 2001 vest over four years and areexercisable on a cumulative basis over 10 years. Options granted after February2001 vest over three years and are exercisable on a cumulative basis over fiveyears. At the time of grant, the exercise price equals the market price. Thefollowing options have been granted:

 
| ** **                                                        | ** ** | **2006**        | ** ** | **2005**           | ** ** | **2004**        | ** ** |
|-------------------------------------------------------------------|------------|-----------------|------------|--------------------|------------|-----------------|------------|
| ** **                                                        | ** ** | ** **      | ** ** | **Weighted**       | ** ** | ** **      | ** ** | **Weighted** | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **                                                        | ** ** | ** **      | ** ** | **Average**        | ** ** | ** **      | ** ** | **Average** | ** ** | ** ** | ** ** | **Average** | ** ** |
| ** **                                                        | ** ** | **Options**     | ** ** | **Exercise Price** | ** ** | **Options**     | ** ** | **Exercise Price** | ** ** | **Options** | ** ** | **Exercise Price** | ** ** |
| ** **                                                        | ** ** | **(thousands)** | ** ** | **($/option)**     | ** ** | **(thousands)** | ** ** | **($/option)** | ** ** | **(thousands)** | ** ** | **($/option)** | ** ** |
| Balance at  Beginning of Year                                     |       | 15,315          |       | 28                 |       | 16,276          |       | 20 |   | 18,406 |   | 17 |   |
| Granted                                                           |       | 2,400           |       | 63                 |       | 3,392           |       | 55 |   | 4,224 |   | 25 |   |
| Exercised for Stock                                               |       | (846            | )          | 18                 |       | (1,823          | )          | 16 |   | (5,902 | ) | 15 |   |
| Surrendered for Cash                                              |       | (1,522          | )          | 18                 |       | (2,089          | )          | 17 |   | (289 | ) | 17 |   |
| Forfeited                                                         |       | (105            | )          | 38                 |       | (441            | )          | 22 |   | (163 | ) | 17 |   |
| **Balance  at End of year**                                       | ** ** | **15,242**      | ** ** | **35**             | ** ** | **15,315**      | ** ** | **28** | ** ** | **16,276** | ** ** | **20** | ** ** |
|                                                              |       |            |       |               |       |            |       |   |   |   |   |   |   |
| Options  Exercisable at End of Year                               |       | 9,345           |       | 24                 |       | 8,131           |       | 19 |   | 8,455 |   | 17 |   |
| Common Shares Reserved for Issuance Under  the Tandem Option Plan |       | 16,235          |       |               |       | 17,290          |       |   |   | 19,172 |   |   |   |

 

The range of exercise pricesof options outstanding and exercisable at December 31, 2006 is as follows:

 
| ** **         | ** ** | **Outstanding Options** | ** ** | **Exercisable Options** | ** ** |
|--------------------|------------|-------------------------|------------|-------------------------|------------|
| ** **         | ** ** | ** **              | ** ** | ** **              | ** ** | **Weighted** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **         | ** ** | ** **              | ** ** | **Weighted**            | ** ** | **Average** | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **         | ** ** | **Number of**           | ** ** | **Average**             | ** ** | **Years** | ** ** | **Number of** | ** ** | **Average** | ** ** |
| ** **         | ** ** | **Options**             | ** ** | **Exercise Price**      | ** ** | **to Expiry** | ** ** | **Options** | ** ** | **Exercise Price** | ** ** |
| ** **         | ** ** | **(thousands)**         | ** ** | **($/option)**          | ** ** | **(years)** | ** ** | **(thousands)** | ** ** | **($/option)** | ** ** |
| $5.00 to  $9.99    |       | 178                     |       | 9                       |       | 2 |   | 178 |   | 9 |   |
| $10.00 to  $14.99  |       | 788                     |       | 14                      |       | 2 |   | 788 |   | 14 |   |
| $15.00 to  $19.99  |       | 3,032                   |       | 18                      |       | 3 |   | 3,032 |   | 18 |   |
| $20.00 to  $24.99  |       | 2,792                   |       | 23                      |       | 2 |   | 2,462 |   | 22 |   |
| $25.00 to  $29.99  |       | 2,768                   |       | 25                      |       | 3 |   | 1,778 |   | 25 |   |
| $30.00 to  $34.99  |       | 14                      |       | 31                      |       | 3 |   | 2 |   | 31 |   |
| $35.00 to  $39.99  |       | —                  |       | —                  |       | — |   | — |   | — |   |
| $40.00 to  $44.99  |       | 2                       |       | 40                      |       | 4 |   | 1 |   | 40 |   |
| $45.00 to  $49.99  |       | 13                      |       | 47                      |       | 4 |   | 5 |   | 47 |   |
| $50.00 to  $54.99  |       | 3,254                   |       | 55                      |       | 4 |   | 1,099 |   | 54 |   |
| $55.00 to  $59.99  |       | 12                      |       | 57                      |       | 4 |   | — |   | — |   |
| $60.00 to  $64.99  |       | 2,383                   |       | 63                      |       | 5 |   | — |   | — |   |
| $65.00 to  $69.99  |       | 3                       |       | 66                      |       | 4 |   | — |   | — |   |
| $70.00 to  $74.99  |       | 3                       |       | 71                      |       | 5 |   | — |   | — |   |
| **Total  Options** | ** ** | **15,242**              | ** ** | ** **              | ** ** | ** ** | ** ** | **9,345** | ** ** | ** ** | ** ** |

 

109

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**(d) Stockappreciation rights**

 

Under our stock appreciationrights (StARs) plan established in 2001, employees are entitled to cashpayments equal to the excess of the market price of the common shares over theexercise price of the right. The vesting period and other terms of the plan aresimilar to the tandem option plan. The total rights granted and outstanding atany time cannot exceed 10% of total outstanding common shares. At the time ofgrant, the exercise price equals the market price. The following stockappreciation rights have been granted:

 
| ** **                        | ** ** | **2006**        | ** ** | **2005**           | ** ** | **2004**        | ** ** |
|-----------------------------------|------------|-----------------|------------|--------------------|------------|-----------------|------------|
| ** **                        | ** ** | ** **      | ** ** | **Weighted**       | ** ** | ** **      | ** ** | **Weighted** | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **                        | ** ** | ** **      | ** ** | **Average**        | ** ** | ** **      | ** ** | **Average** | ** ** | ** ** | ** ** | **Average** | ** ** |
| ** **                        | ** ** | **StARs**       | ** ** | **Exercise Price** | ** ** | **StARs**       | ** ** | **Exercise Price** | ** ** | **StARs** | ** ** | **Exercise Price** | ** ** |
| ** **                        | ** ** | **(thousands)** | ** ** | **($/StAR)**       | ** ** | **(thousands)** | ** ** | **($/StAR)** | ** ** | **(thousands)** | ** ** | **($/StAR)** | ** ** |
| Balance at  Beginning of Year     |       | 5,964           |       | 30                 |       | 6,436           |       | 22 |   | 4,809 |   | 18 |   |
| Granted                           |       | 2,254           |       | 63                 |       | 1,443           |       | 55 |   | 2,609 |   | 25 |   |
| Exercised for Cash                |       | (1,082          | )          | 21                 |       | (1,455          | )          | 19 |   | (867 | ) | 16 |   |
| Forfeited                         |       | (191            | )          | 38                 |       | (460            | )          | 23 |   | (115 | ) | 18 |   |
| **Balance  at End of year**       | ** ** | **6,945**       | ** ** | **42**             | ** ** | **5,964**       | ** ** | **30** | ** ** | **6,436** | ** ** | **22** | ** ** |
|                              |       |            |       |               |       |            |       |   |   |   |   |   |   |
| StARs  Exercisable at End of Year |       | 3,076           |       | 27                 |       | 2,426           |       | 21 |   | 2,021 |   | 17 |   |

 

The range of exercise pricesof StARs outstanding and exercisable at December 31, 2006 is as follows:

 
| ** **        | ** ** | **Outstanding StARs** | ** ** | **Exercisable StARs** | ** ** |
|-------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **        | ** ** | ** **            | ** ** | ** **            | ** ** | **Weighted** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **        | ** ** | ** **            | ** ** | **Weighted**          | ** ** | **Average** | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **        | ** ** | **Number of**         | ** ** | **Average**           | ** ** | **Years to** | ** ** | **Number of** | ** ** | **Average** | ** ** |
| ** **        | ** ** | **StARs**             | ** ** | **Exercise Price**    | ** ** | **Expiry** | ** ** | **StARs** | ** ** | **Exercise Price** | ** ** |
| ** **        | ** ** | **(thousands)**       | ** ** | **($/StAR)**          | ** ** | **(years)** | ** ** | **(thousands)** | ** ** | **($/StAR)** | ** ** |
| $15.00 to  $19.99 |       | 513                   |       | 17                    |       | 1 |   | 513 |   | 17 |   |
| $20.00 to  $24.99 |       | 991                   |       | 22                    |       | 2 |   | 985 |   | 22 |   |
| $25.00 to  $29.99 |       | 1,859                 |       | 25                    |       | 3 |   | 1,138 |   | 25 |   |
| $30.00 to  $34.99 |       | 18                    |       | 33                    |       | 3 |   | 6 |   | 33 |   |
| $35.00 to  $39.99 |       | 9                     |       | 37                    |       | 4 |   | 1 |   | 37 |   |
| $40.00 to  $44.99 |       | 8                     |       | 41                    |       | 4 |   | 3 |   | 41 |   |
| $45.00 to  $49.99 |       | 38                    |       | 48                    |       | 4 |   | 12 |   | 48 |   |
| $50.00 to  $54.99 |       | 1,256                 |       | 55                    |       | 4 |   | 418 |   | 55 |   |
| $55.00 to $59.99  |       | 29                    |       | 57                    |       | 4 |   | — |   | — |   |
| $60.00 to  $64.99 |       | 2,213                 |       | 63                    |       | 5 |   | — |   | — |   |
| $65.00 to  $69.99 |       | 11                    |       | 66                    |       | 4 |   | — |   | — |   |
| **Total  StARs**  | ** ** | **6,945**             | ** ** | ** **            | ** ** | ** ** | ** ** | **3,076** | ** ** | ** ** | ** ** |

 

**13. EARNINGSPER COMMON SHARE**

 

We calculate basic earningsper common share from continuing operations using net income from continuingoperations divided by the weighted-average number of common shares outstanding.We calculate basic earnings per common share using net income and theweighted-average number of common shares outstanding. We calculate dilutedearnings per common share from continuing operations and diluted earnings percommon share in the same manner as basic, except we use the weighted-averagenumber of diluted common shares outstanding in the denominator.

 

110

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| **(millions of shares)**                                          | ** ** | **2006**  | ** ** | **2005**  | ** ** | **2004**  | ** ** |
|-------------------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Weighted-Average  Number of Common Shares Outstanding             |       | 262.1     |       | 260.4     |       | 257.3     |       |
| Shares  Issuable Pursuant to Stock Options                        |       | 13.9      |       | 13.4      |       | 13.1      |       |
| Shares to be  Purchased from Proceeds of Stock Options            |       | (7.1      | )          | (7.4      | )          | (9.8      | )          |
| **Weighted-Average  Number of diluted Common Shares Outstanding** | ** ** | **268.9** | ** ** | **266.4** | ** ** | **260.6** | ** ** |

 

In calculating theweighted-average number of diluted common shares outstanding for the year endedDecember 31, 2006, we excluded 211,283 options (2005—280,708;2004—348,200), because their exercise price wasgreater than the annual average common share market price in those periods.During the last three years, outstanding stock options were the only potentialdilutive instruments.

 

**14. DISCONTINUEDOPERATIONS**

 

In the third quarter of 2005,we sold certain Canadian conventional oil and gas properties in southeastSaskatchewan, northwest Saskatchewan, northeast British Columbia and theAlberta foothills. The results of operations of these properties have beenpresented as discontinued operations. The sales closed in the third quarter of2005 with net proceeds of $900 million after closing adjustments, and werealized gains of $225 million. These gains are net of losses attributable topipeline contracts and fixed-price gas sales contracts associated with theseproperties that we have retained, but no longer use in connection with our oiland gas business.

 

During the fourth quarter of2004, we concluded production from our Buffalo field, offshore Australia. Theresults of our operations in Australia have been presented as discontinuedoperations, as we have no plans to continue operations in the country.Remediation and abandonment activities have been completed, and no gain or losswas recognized.

 

The results of operationsfrom these properties in Australia and Canada are detailed below and shown asdiscontinued operations in our Consolidated Statement of Income.

 
| ** **                                            | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                            | ** ** | **Canada** | ** ** | **Canada** | ** ** | **Australia** | ** ** | **Total** | ** ** |
| Revenues and  Other Income                            |       |       |       |       |       |   |   |   |   |
| Net Sales                                             |       | 154        |       | 232        |       | 75 |   | 307 |   |
| Marketing and Other                                   |       | —     |       | 1          |       | — |   | 1 |   |
| Gain on Disposition of Assets                         |       | 225        |       | —     |       | — |   | — |   |
|                                                  |       | 379        |       | 233        |       | 75 |   | 308 |   |
| Expenses                                              |       |       |       |       |       |   |   |   |   |
| Operating                                             |       | 27         |       | 40         |       | 53 |   | 93 |   |
| Depreciation, Depletion, Amortization and  Impairment |       | 28         |       | 70         |       | 9 |   | 79 |   |
| Exploration Expense                                   |       | 1          |       | 3          |       | — |   | 3 |   |
| Income  before Income Taxes                           |       | 323        |       | 120        |       | 13 |   | 133 |   |
| Provision for Future Income Taxes                     |       | (129       | )          | 50         |       | — |   | 50 |   |
| **Net  Income from Discontinued Operations**          | ** ** | **452**    | ** ** | **70**     | ** ** | **13** | ** ** | **83** | ** ** |
|                                                  |       |       |       |       |       |   |   |   |   |
| **Earnings  per Common Share**($/share)               |       |       |       |       |       |   |   |   |   |
| Basic (Note 13)                                       |       | 1.74       |       | 0.27       |       | 0.05 |   | 0.32 |   |
| Diluted (Note 13)                                     |       | 1.70       |       | 0.27       |       | 0.05 |   | 0.32 |   |

 

There were no assets andliabilities related to discontinued operations as at December 31, 2006.

 

111

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**15.COMMITMENTS, CONTINGENCIES AND GUARANTEES**

 
| ** **                              | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** |
|-----------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|
| Operating  Leases                       |       | 44       |       | 109      |       | 127      |       | 123      |       | 117      |       | 232            |       |
| Transportation  and Storage Commitments |       | 424      |       | 165      |       | 97       |       | 70       |       | 53       |       | 118            |       |
|                                    | ** ** | **468**  | ** ** | **274**  | ** ** | **224**  | ** ** | **193**  | ** ** | **170**  | ** ** | **350**        | ** ** |

 

In June 2003, a subsidiary ofOccidental Petroleum Corporation (Occidental) initiated an arbitration againstus at the International Court of Arbitration of the International Chamber ofCommerce (ICC Court) regarding an Area of Mutual Interest agreement relating tocertain portions of Block 51 in the Republic of Yemen. In April 2006, the ICCCourt concluded that we breached this agreement and as a result, Occidental wasentitled to monetary damages. In late 2006, we agreed to settle the arbitrationwith Occidental for US$135 million. No further amounts are expected to bepayable under the settlement. This amount was accrued and included in otherexpenses in our Consolidated Statement of Income during 2006.

 

We have a number of lawsuitsand claims pending including income tax reassessments (see Note 18), for whichwe currently cannot determine the ultimate result. We record costs as they areincurred or become determinable. We believe the resolution of these matters wouldnot have a material adverse effect on our liquidity, consolidated financialposition or results of operations.

 

During 2006, total rentalexpense was $49 million (2005—$47 million; 2004—$45million).

 

From time to time, we enterinto certain types of contracts that require us to indemnify parties againstpossible third-party claims, particularly when these contracts relate todivestiture transactions. On occasion, we may provide routine indemnifications.The terms of such obligations vary, and generally, a maximum is not explicitlystated. Because the obligations in these agreements are often not explicitlystated, the overall maximum amount of the obligations cannot be reasonablyestimated. Historically, we have not been obligated to make significant paymentsfor these obligations. We believe that payments, if any, related to suchmatters, would not have a material adverse effect on our liquidity, financialcondition or results of operations.

 

**16. PENSION ANDOTHER POST-RETIREMENT BENEFITS**

 

Nexen and Canexus havecontributory and non-contributory defined benefit and defined contributionpension plans, which together cover substantially all employees. Syncrude has adefined benefit plan for its employees, and we disclose only our proportionateshare of this plan. Under the defined benefit plans, we provide benefits toretirees based on their length of service and final average earnings. Benefitspaid out of Nexen’s defined benefit plan are indexed to 75% of the annual rateof inflation less 1%, to a maximum increase of 5%. On the establishment ofCanexus in 2005, the portion of the projected benefit obligation and fair valueof plan assets relating to Canexus employees was transferred to Canexus fromNexen.

 

112

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**(a) Defined benefit pension plans**

 

The cost of pension benefitsearned by employees is determined using the projected-benefit method proratedon employment services and is expensed as services are rendered. We fund theseplans according to federal and provincial government regulations bycontributing to trust funds administered by an independent trustee. These fundsare invested primarily in equities and bonds.

 
| ** **                                          | ** ** | **2006**   | ** ** | **2005**    | ** ** |
|-----------------------------------------------------|------------|------------|------------|-------------|------------|
| ** **                                          | ** ** | **Nexen**  | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** | **Nexen** | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** |
| **Change  in Projected Benefit Obligation (PBO)**   | ** ** | ** ** | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Beginning of Year                                   |       | 223        |       | 49          |       | 109 |   | 217 |   | — |   | 91 |   |
| Service Cost                                        |       | 16         |       | 3           |       | 5 |   | 15 |   | 1 |   | 4 |   |
| Interest Cost                                       |       | 12         |       | 3           |       | 5 |   | 12 |   | 1 |   | 5 |   |
| Plan Participants’ Contributions               |       | 3          |       | 1           |       | 1 |   | 3 |   | — |   | 1 |   |
| Actuarial Loss/(Gain)                               |       | 9          |       | 2           |       | — |   | 33 |   | (2 | ) | 11 |   |
| Benefits Paid                                       |       | (11        | )          | —      |       | (4 | ) | (8 | ) | — |   | (3 | ) |
| Transfer to Canexus                                 |       | —     |       | —      |       | — |   | (49 | ) | 49 |   | — |   |
| **End of  Year**(1)                                 | ** ** | **252**    | ** ** | **58**      | ** ** | **116** | ** ** | **223** | ** ** | **49** | ** ** | **109** | ** ** |
| **Change  in Fair Value of Plan Assets**            | ** ** | ** ** | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Beginning of Year                                   |       | 146        |       | 40          |       | 58 |   | 171 |   | — |   | 50 |   |
| Actual Return on Plan Assets                        |       | 23         |       | 6           |       | 8 |   | 18 |   | — |   | 6 |   |
| Employer’s Contribution                        |       | 24         |       | 3           |       | 5 |   | 2 |   | — |   | 4 |   |
| Plan Participants’ Contributions               |       | 3          |       | 1           |       | 1 |   | 3 |   | — |   | 1 |   |
| Benefits Paid                                       |       | (11        | )          | —      |       | (3 | ) | (8 | ) | — |   | (3 | ) |
| Transfer to Canexus                                 |       | —     |       | —      |       | — |   | (40 | ) | 40 |   | — |   |
| **End of  Year**                                    | ** ** | **185**    | ** ** | **50**      | ** ** | **69** | ** ** | **146** | ** ** | **40** | ** ** | **58** | ** ** |
| **Reconciliation  of Funded Status**                | ** ** | ** ** | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Funded Status (2)                                   |       | (67        | )          | (8          | )          | (47 | ) | (77 | ) | (9 | ) | (51 | ) |
| Unamortized Transitional Obligation                 |       | —     |       | —      |       | — |   | 1 |   | — |   | — |   |
| Unamortized Prior Service Costs                     |       | 3          |       | —      |       | — |   | 3 |   | — |   | — |   |
| Unamortized Net Actuarial Loss                      |       | 39         |       | 7           |       | 32 |   | 44 |   | 9 |   | 38 |   |
| **Pension  Liability**                              | ** ** | **(25**    | **)**      | **(1**      | **)**      | **(15** | **)** | **(29** | **)** | **—** | ** ** | **(13** | **)** |
| **Pension  Liability Recognized**                   | ** ** | ** ** | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Deferred Charges and Other Assets                   |       | 10         |       | —      |       | — |   | — |   | — |   | — |   |
| Accounts Payable and Accrued Liabilities            |       | (1         | )          | —      |       | (2 | ) | (1 | ) | — |   | (2 | ) |
| Other Deferred Credits and Liabilities (Note 11)    |       | (34        | )          | (1          | )          | (13 | ) | (28 | ) | — |   | (11 | ) |
| **Pension  Liability**                              | ** ** | **(25**    | **)**      | **(1**      | **)**      | **(15** | **)** | **(29** | **)** | **—** | ** ** | **(13** | **)** |
|                                                |       |       |       |        |       |   |   |   |   |   |   |   |   |
| Assumptions (%)                                     |       |       |       |        |       |   |   |   |   |   |   |   |   |
| Accrued Benefit Obligation at December 31           |       |       |       |        |       |   |   |   |   |   |   |   |   |
| Discount Rate                                       |       | 5.00       |       | 5.00        |       | 5.00 |   | 5.25 |   | 5.25 |   | 5.00 |   |
| Long-Term Rate of Employee Compensation Increase    |       | 4.00       |       | 4.00        |       | 4.00 |   | 4.00 |   | 4.00 |   | 4.00 |   |
| Benefit Cost for Year Ended December 31 (3)         |       |       |       |        |       |   |   |   |   |   |   |   |   |
| Discount Rate                                       |       | 5.25       |       | 5.25        |       | 5.00 |   | 5.00 |   | 5.00 |   | 5.00 |   |
| Long-Term Rate of Employee Compensation Increase    |       | 4.00       |       | 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 |   | 6.50 |   | 8.50 |   |

 

----

*Notes:*

*(1)*  *The accumulated benefitobligations (the projected benefit obligation excluding future salaryincreases) of the Nexen and Canexus plans were $180 million and $44 million atDecember 31, 2006, respectively (2005—$161 million and $36 million,respectively). Nexen’s supplemental pension plan’s accumulated benefitobligation was $35 million at December 31, 2006 (2005—$29 million). Nexen’sshare of Syncrude’s employee pension plan’s accumulated benefit obligation was$89 million at December 31, 2006 (2005—$82 million).*

*(2)*  *Includes unfundedobligations for supplemental benefits to the extent that the benefit is limitedby statutory guidelines. At December 31, 2006, the PBO for Nexen’s supplementalbenefits was $53 million (2005—$43 million) and $1 million for Canexus (2005—$1million).*

*(3)*  *The assumptions have beenused to calculate the recognized expense for Nexen and Canexus. There were nochanges to the assumptions between the measurement date and December 31, 2006.Syncrude’s measurement date was December 31, 2006.*

*(4)*  *The long-term annual rate ofreturn on plan assets assumption is based on a mix of historical market returnsfor debt and equity securities.*

 

113

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Net Pension Expense Recognized Under Our Defined Benefit Pension Plans

 
| ** **                                                                                    | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| **Nexen**                                                                                     |       |     |       |     |       |     |       |
| Cost of Benefits Earned by Employees                                                          |       | 16       |       | 15       |       | 8        |       |
| Interest Cost on Benefits Earned                                                              |       | 12       |       | 12       |       | 12       |       |
| Actual Return on Plan Assets                                                                  |       | (23      | )          | (18      | )          | (16      | )          |
| Actuarial Losses                                                                              |       | 9        |       | 33       |       | 10       |       |
| Pension Expense Before Adjustments for the  Long-Term Nature of Employee Future Benefit Costs |       | 14       |       | 42       |       | 14       |       |
| Difference Between Actual and Expected  Return on Plan Assets                                 |       | 12       |       | 8        |       | 5        |       |
| Difference Between Actual and Recognized  Actuarial Losses                                    |       | (7       | )          | (32      | )          | (10      | )          |
| Difference Between Actual and Recognized  Past Service Costs                                  |       | 1        |       | —   |       | 1        |       |
| **Net Pension Expense**                                                                       |       | 20       |       | 18       |       | 10       |       |
| ** **                                                                                    |       |     |       |     |       |     |       |
| **Canexus**                                                                                   |       |     |       |     |       |     |       |
| Cost of Benefits Earned by Employees                                                          |       | 3        |       | 1        |       | —   |       |
| Interest Cost on Benefits Earned                                                              |       | 3        |       | 1        |       | —   |       |
| Actual Return on Plan Assets                                                                  |       | (6       | )          | —   |       | —   |       |
| Actuarial (Gains)/Losses                                                                      |       | 2        |       | (2       | )          | —   |       |
| Pension Expense Before Adjustments for the  Long-Term Nature of Employee Future Benefit Costs |       | 2        |       | —   |       | —   |       |
| Difference Between Actual and Expected  Return on Plan Assets                                 |       | 3        |       | (1       | )          | —   |       |
| Difference Between Actual and Recognized  Actuarial Gains                                     |       | (2       | )          | 2        |       | —   |       |
| Difference Between Actual and Recognized  Past Service Costs                                  |       | —   |       | —   |       | —   |       |
| **Net Pension Expense**                                                                       |       | 3        |       | 1        |       | —   |       |
| ** **                                                                                    |       |     |       |     |       |     |       |
| **Syncrude**                                                                                  |       |     |       |     |       |     |       |
| Cost of Benefits Earned by Employees                                                          |       | 5        |       | 4        |       | 3        |       |
| Interest Cost on Benefits Earned                                                              |       | 5        |       | 5        |       | 5        |       |
| Actual Return on Plan Assets                                                                  |       | (8       | )          | (6       | )          | (5       | )          |
| Actuarial Losses                                                                              |       | —   |       | 11       |       | 7        |       |
| Pension Expense Before Adjustments for the  Long-Term Nature of Employee Future Benefit Costs |       | 2        |       | 14       |       | 10       |       |
| Difference Between Actual and Expected  Return on Plan Assets                                 |       | 3        |       | 2        |       | 1        |       |
| Difference Between Actual and Recognized  Actuarial Losses                                    |       | 2        |       | (8       | )          | (6       | )          |
| Difference Between Actual and Recognized  Past Service Costs                                  |       | —   |       | —   |       | —   |       |
| **Net Pension Expense**                                                                       |       | 7        |       | 8        |       | 5        |       |
| ** **                                                                                    |       |     |       |     |       |     |       |
| **Total  Net Pension Expense**                                                                | ** ** | **30**   | ** ** | **27**   | ** ** | **15**   | ** ** |

 

**(b) Plan asset allocation atDecember 31**

 

Our investment goal forthe assets in our defined benefit pension plans is to preserve capital and earna long-term rate of return on assets, net of all management expenses, in excessof the inflation rate. Investment funds are managed by external fund managersbased on policies approved by the Board of Directors and Pension Committees ofNexen and Canexus. Nexen’s and Canexus’ investment strategy is to diversifyplan assets between debt and equity securities of Canadian and non-Canadiancorporations that are traded on recognized stock exchanges. Allowable andprohibited investment types are also prescribed in Nexen’s investment policies.

 

114

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Syncrude’s pension plan is governed and administered separately fromours. Syncrude’s investment assets are subject to similar investment goals,policies and strategies.

 
| **(%)**           | ** ** | **Expected 2007** | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|-------------------|------------|-------------------|------------|------------|------------|------------|------------|
| **Nexen**         |       |              |       |       |       |       |       |
| Equity Securities |       | 65                |       | 60         |       | 60         |       |
| Debt Securities   |       | 35                |       | 40         |       | 40         |       |
| Real Estate       |       | —            |       | —     |       | —     |       |
| Other             |       | —            |       | —     |       | —     |       |
| **Total**         | ** ** | **100**           | ** ** | **100**    | ** ** | **100**    | ** ** |
| ** **        | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Canexus**       |       |              |       |       |       |       |       |
| Equity Securities |       | 50                |       | 60         |       | 60         |       |
| Debt Securities   |       | 50                |       | 40         |       | 40         |       |
| Real Estate       |       | —            |       | —     |       | —     |       |
| Other             |       | —            |       | —     |       | —     |       |
| **Total**         | ** ** | **100**           | ** ** | **100**    | ** ** | **100**    | ** ** |
| ** **        | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Syncrude**      |       |              |       |       |       |       |       |
| Equity Securities |       | 70                |       | 70         |       | 70         |       |
| Debt Securities   |       | 30                |       | 30         |       | 30         |       |
| Real Estate       |       | —            |       | —     |       | —     |       |
| Other             |       | —            |       | —     |       | —     |       |
| **Total**         | ** ** | **100**           | ** ** | **100**    | ** ** | **100**    | ** ** |

 

**(c) Defined contributionpension plans**

 

Under these plans, pension benefits arebased on plan contributions. During 2006, Canadian pension expense for theseplans was $4 million (2005—$4 million; 2004—$4million). During 2006, US pension expense for these plans was $4 million (2005—$4million; 2004—$3 million).

 

**(d) Post-retirementbenefits**

 

Nexen provides certain post-retirementbenefits, including group life and supplemental health insurance, to eligibleemployees and their dependents. These costs are fully accrued as compensationin the period employees work; however, these future obligations are not funded.The present value of Nexen employees’ future post retirement benefits atDecember 31, 2006 was $6 million (2005—$4 million) and $2 million for Canexus(2005—$2 million).

 

**(e) Employer fundingcontributions and benefit payments**

 

Canadian regulators have prescribedfunding requirements for our defined benefit plans. Our funding contributionsover the last three years have met these requirements and also included additionaldiscretionary contributions permitted by law. For our defined contributionplans, we make contributions on behalf of our employees and no furtherobligation exists. Our funding contributions for the defined benefit plans are:

 
| **Defined Benefit Contributions** | ** ** | **Expected 2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|-----------------------------------|------------|-------------------|------------|----------|------------|----------|------------|
| Nexen                             |       | 11                |       | 24       |       | 2        |       |
| Canexus                           |       | 2                 |       | 3        |       | —   |       |
| Syncrude                          |       | 5                 |       | 5        |       | 4        |       |
| **Total  Funding Contributions**  | ** ** | **18**            | ** ** | **32**   | ** ** | **6**    | ** ** |

 

 

115

----

 

Our most recent fundingvaluation was prepared as of June 30, 2006. Our next funding valuation isrequired by June 30, 2009. Canexus’ most recent funding valuation was preparedas of August 18, 2005, and their next funding valuation is required by December31, 2007. Syncrude’s most recent funding valuation was prepared as of December31, 2006, and their next funding valuation is December 31, 2008.

 

Our total benefit payments in2006 were $11 million for Nexen (2005—$8 million). Our share ofSyncrude’s total benefit payments in 2006 was $4 million (2005—$3million). Our estimated future payments are as follows:

 
| ** **     | ** ** | **Defined Benefit** | ** ** | **Other**   | ** ** |
|----------------|------------|---------------------|------------|-------------|------------|
| ** **     | ** ** | **Nexen**           | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** | **Nexen** | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** |
| 2007           |       | 9                   |       | 1           |       | 3 |   | 1 |   | — |   | — |   |
| 2008           |       | 9                   |       | 1           |       | 3 |   | 2 |   | — |   | — |   |
| 2009           |       | 10                  |       | 1           |       | 4 |   | 2 |   | — |   | — |   |
| 2010           |       | 11                  |       | 1           |       | 4 |   | 2 |   | — |   | — |   |
| 2011           |       | 11                  |       | 2           |       | 4 |   | 2 |   | — |   | — |   |
| 2012—2016 |       | 71                  |       | 15          |       | 29 |   | 18 |   | — |   | 1 |   |

 

**17. MARKETING AND OTHER**

 
| ** **                                     | ** ** | **2006**  | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------------------|------------|-----------|------------|----------|------------|----------|------------|
| Marketing  Revenue, Net                        |       | 1,309     |       | 847      |       | 608      |       |
| Business  Interruption Insurance Proceeds (1)  |       | 154       |       | 2        |       | 10       |       |
| Change in  Fair Value of Crude Oil Put Options |       | (11       | )          | (196     | )          | 56       |       |
| Interest                                       |       | 36        |       | 29       |       | 12       |       |
| Foreign  Exchange Losses                       |       | (72       | )          | (19      | )          | (13      | )          |
| Gains on  Disposition of Assets (2)            |       | 4         |       | 4        |       | 24       |       |
| Other                                          |       | 30        |       | 35       |       | 16       |       |
| **Total  Marketing and Other**                 | ** ** | **1,450** | ** ** | **702**  | ** ** | **713**  | ** ** |

 

----

*Notes:*

*(1)**      **In 2006, we receivedbusiness interruption insurance proceeds related to production losses caused byGulf of Mexico hurricanes in 2005 and by generator failures in our UKoperations in 2005.*

*(2)**      **Gains on disposition ofassets resulted from the sale of minor oil and gas assets in our Canadianoperations in 2006 and 2004 and from the sale of our Ejulebe assets, offshoreNigeria in 2005.*

 

**18. INCOME TAXES**

 

**(a) Temporarydifferences**

 
| ** **                          | ** ** | **2006**                       | ** ** | **2005**                            | ** ** |
|-------------------------------------|------------|--------------------------------|------------|-------------------------------------|------------|
| ** **                          | ** ** | **Future  Income Tax  Assets** | ** ** | **Future  Income Tax  Liabilities** | ** ** | **Future  Income Tax  Assets** | ** ** | **Future  Income Tax  Liabilities** | ** ** |
| Property,  Plant and Equipment, Net |       | 26                             |       | 2,420                               |       | 31 |   | 1,780 |   |
| Tax Losses  Carried Forward         |       | 594                            |       | —                              |       | 370 |   | — |   |
| Deferred  Income                    |       | —                         |       | 48                                  |       | — |   | 175 |   |
| Recoverable  Taxes                  |       | —                         |       | —                              |       | 9 |   | — |   |
| **Total**(1)                        | ** ** | **620**                        | ** ** | **2,468**                           | ** ** | **410** | ** ** | **1,955** | ** ** |

 

----

*Note:*

*(1)**      **2006 includes future income taxassets of $479 million that we expect to realize in the following twelve monthshave been included in current assets.*

 

116

----

 

**(b) Canadian and foreign incometaxes**

 
| ** **                                                 | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| **Income  from Continuing Operations before Income Taxes** |       |     |       |     |       |     |       |
| Canadian                                                   |       | (352     | )          | (396     | )          | 24       |       |
| Foreign                                                    |       | 1,648    |       | 1,326    |       | 1,003    |       |
|                                                       |       | 1,296    |       | 930      |       | 1,027    |       |
| **Provision  for Income Taxes**                            |       |     |       |     |       |     |       |
| Current                                                    |       |     |       |     |       |     |       |
| Canadian                                                   |       | 14       |       | 1        |       | 6        |       |
| Foreign                                                    |       | 354      |       | 338      |       | 242      |       |
|                                                       |       | 368      |       | 339      |       | 248      |       |
| Future                                                     |       |     |       |     |       |     |       |
| Canadian                                                   |       | (96      | )          | (206     | )          | (3       | )          |
| Foreign                                                    |       | 411      |       | 101      |       | 72       |       |
|                                                       |       | 315      |       | (105     | )          | 69       |       |
| **Total  Provision for Income Taxes**                      | ** ** | **683**  | ** ** | **234**  | ** ** | **317**  | ** ** |

 

The Canadian and foreign components of theprovision for income taxes are based on the jurisdiction in which income istaxed. Foreign taxes relate mainly to Yemen, Colombia, the United Kingdom andthe United States and include Yemen cash taxes of $286 million (2005—$296million; 2004—$227 million).

 

**(c) Reconciliation of effectivetax rate to the Canadian statutory tax rate**

 
| ** **                                                          | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Income  before Income Taxes From Continuing Operations              |       | 1,296    |       | 930      |       | 1,027    |       |
|                                                                |       |     |       |     |       |     |       |
| Provision  for Income Taxes Computed at the Canadian Statutory Rate |       | 401      |       | 318      |       | 354      |       |
| Add (Deduct)  the Tax Effect of:                                    |       |     |       |     |       |     |       |
| Royalties, Rentals and Similar Payments to  Provincial Governments  |       | 15       |       | 24       |       | 20       |       |
| Resource Allowance and Provincial Tax  Rebates                      |       | (15      | )          | (24      | )          | (29      | )          |
| Lower Foreign Tax Rates                                             |       | (9       | )          | (40      | )          | (22      | )          |
| Additional Canadian Tax on Canadian  Resource Income                |       | 10       |       | 6        |       | 7        |       |
| Lower Tax Rates on Capital Gains                                    |       | (3       | )          | (54      | )          | —   |       |
| Federal and Provincial Capital Tax                                  |       | 13       |       | 5        |       | 6        |       |
| Effect of Changes in Tax Rates                                      |       | 245      |       | —   |       | (15      | )          |
| Non-Deductible Expenses and Other                                   |       | 26       |       | (1       | )          | (4       | )          |
| **Provision  for Income Taxes**                                     | ** ** | **683**  | ** ** | **234**  | ** ** | **317**  | ** ** |

 

During the first quarter of 2006, werecorded a future income tax expense of $277 million related to an increase inthe supplemental tax rate on oil and gas activities in the United Kingdom.Legislation was introduced to the United Kingdom parliament during the firstquarter to increase the supplemental tax rate from 10% to 20%, effectiveJanuary 1, 2006.

 

In 2006 and 2004, the federal and someprovincial governments in Canada reduced statutory income tax rates. Thisreduced our liability and provision for future income taxes by $32 million and$15 million in 2006 and 2004, respectively.

 

117

----

 

**(d) Available unused tax lossesand tax contingencies**

 

At December 31, 2006 and2005, we had unused tax losses totalling $1,258 million and $965 million,respectively, mostly from our UK operations. The majority of these losses haveno expiry date.

 

Nexen’s income tax filingsare subject to audit by taxation authorities. There are audits in progress anditems under review, some of which may increase our tax liability. In addition,we have filed notices of objection with respect to certain issues. While theresults of these items cannot be ascertained at this time, we believe we havean adequate provision for income taxes based on available information.

 

At the time of acquisition,Wascana, a predecessor company, had outstanding taxation issues in dispute fromprior taxation years. Wascana disagreed with issues raised and has filednotices of objection. The value of the tax pools acquired at the time ofacquisition reflected our evaluation of the potential impact of these issues.

 

**19. CASH FLOWS**

 

**(a)Charges and credits to income not involving cash**

 
| ** **                                                  | ** ** | **2006**  | ** ** | **2005**  | ** ** | **2004** | ** ** |
|-------------------------------------------------------------|------------|-----------|------------|-----------|------------|----------|------------|
| Depreciation,  Depletion, Amortization and Impairment       |       | 1,124     |       | 1,052     |       | 674      |       |
| Stock-Based  Compensation                                   |       | 101       |       | 428       |       | 74       |       |
| Gains on  Disposition of Assets                             |       | (4        | )          | (4        | )          | (24      | )          |
| Provision  for Future Income Taxes                          |       | 315       |       | (105      | )          | 69       |       |
| Change in  Fair Value of Crude Oil Put Options              |       | 11        |       | 196       |       | (56      | )          |
| Non-Cash  Items included in Discontinued Operations         |       | —    |       | (325      | )          | 132      |       |
| Unamortized  Issue Costs on Preferred Securities Redemption |       | —    |       | —    |       | 11       |       |
| Gain on  Dilution of Interest in Chemicals Business         |       | —    |       | (193      | )          | —   |       |
| Net Income  Attributable to Non-Controlling Interests       |       | 12        |       | 8         |       | —   |       |
| Other                                                       |       | 70        |       | 24        |       | 26       |       |
| **Total**                                                   | ** ** | **1,629** | ** ** | **1,081** | ** ** | **906**  | ** ** |

 

**(b) Changes in non-cash workingcapital**

 
| ** **                                | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Accounts  Receivable                      |       | 345      |       | (1,078   | )          | (454     | )          |
| Inventories  and Supplies                 |       | (302     | )          | (163     | )          | (106     | )          |
| Other  Current Assets                     |       | (14      | )          | (10      | )          | 44       |       |
| Accounts  Payable and Accrued Liabilities |       | (72      | )          | 982      |       | 650      |       |
| Other                                     |       | —   |       | 20       |       | (12      | )          |
| **Total**                                 | ** ** | **(43**  | **)**      | **(249** | **)**      | **122**  | ** ** |
|                                      |       |     |       |     |       |     |       |
| Relating to:                              |       |     |       |     |       |     |       |
| Operating Activities                      |       | (177     | )          | (195     | )          | (122     | )          |
| Investing Activities                      |       | 134      |       | (54      | )          | 244      |       |
| **Total**                                 | ** ** | **(43**  | **)**      | **(249** | **)**      | **122**  | ** ** |

 

 

118

----

 

**(c) Other cash flow information**

 
| ** **         | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest  Paid     |       | 278      |       | 237      |       | 190      |       |
| Income Taxes  Paid |       | 398      |       | 325      |       | 249      |       |

 

In 2004, other operatingactivity cash outflows include $144 million for the purchase of crude oil putoptions.

 

**20. OPERATING SEGMENTS ANDRELATED INFORMATION**

 

Nexen has the followingoperating segments in various industries and geographic locations:

 

**Oil and Gas:**We explore for, developand produce crude oil, natural gas and related products around the world. Wemanage our operations to reflect differences in the regulatory environments andrisk factors for each country. Our core operations are onshore in Yemen andCanada, and offshore in the US Gulf of Mexico and the UK North Sea. Our otheroperations are primarily in West Africa and Colombia.

 

**EnergyMarketing:**Ourmarketing group sells our crude oil and natural gas, markets third-party crudeoil and natural gas and engages in energy trading, including electricitygeneration.

 

**Syncrude:**We own 7.23% of the Syncrude Joint Venture,which develops and produces synthetic crude oil from mining bitumen in the oilsands in northern Alberta.

 

**Chemicals:**Through our investment in Canexus LP, we manufacture,market and distribute industrial chemicals, principally sodium chlorate,chlorine, acid and caustic soda. We produce sodium chlorate at four facilitiesin Canada and one in Brazil. We produce chlorine, caustic soda and muriaticacid at chlor-alkali facilities in Canada and Brazil.

 

The accounting policies ofour operating segments are the same as those described in Note 1. Net income ofour operating segments excludes interest income, interest expense, unallocatedcorporate expenses and foreign exchange gains and losses with the exception ofChemicals. Identifiable assets are those used in the operations of thesegments.

 

119

----

 

**2006 Operating and GeographicSegments**

 
| ** **                                                    | ** ** | **Oil and  Gas** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **                   | ** ** | ** **            | ** ** |
|---------------------------------------------------------------|------------|------------------|------------|------------|------------|------------|------------|------------|------------|------------------------------|------------|-----------------------|------------|
| **(Cdn$ millions)**                                      | ** ** | **Yemen**        | ** ** | **Canada** | ** ** | **US**     | ** ** | **UK**     | ** ** | **Other  Countries (1****)** | ** ** | **Energy  Marketing** | ** ** | **Syncrude** | ** ** | **Chemicals** | ** ** | **Corporate  and Other** | ** ** | **Total** | ** ** |
| Net Sales (2)                                                 |       | 1,328            |       | 459        |       | 629        |       | 477        |       | 139                          |       | 51                    |       | 446 |   | 407 | (3)  | — |   | 3,936 |   |
| Marketing and Other                                           |       | 8                |       | 7          |       | 81         | (4)        | 85         | (5)        | 1                            |       | 1,309                 |       | — |   | 6 |   | (47 | )(6) | 1,450 |   |
|                                                          |       | 1,336            |       | 466        |       | 710        |       | 562        |       | 140                          |       | 1,360                 |       | 446 |   | 413 |   | (47 | ) | 5,386 |   |
| Less: Expenses                                                |       |             |       |       |       |       |       |       |       |                         |       |                  |       |   |   |   |   |   |   |   |   |
| Operating                                                     |       | 151              |       | 143        |       | 106        |       | 80         |       | 8                            |       | 31                    |       | 187 |   | 249 |   | — |   | 955 |   |
| Depreciation,  Depletion, Amortization and Impairment (7)     |       | 327              |       | 162        |       | 296        |       | 216        |       | 10                           |       | 12                    |       | 33 |   | 40 |   | 28 |   | 1,124 |   |
| Transportation  and Other                                     |       | 6                |       | 33         |       | —     |       | —     |       | 1                            |       | 789                   |       | 18 |   | 40 |   | 154 | (8) | 1,041 |   |
| General and  Administrative (9)                               |       | 17               |       | 80         |       | 58         |       | 14         |       | 44                           |       | 112                   |       | 1 |   | 29 |   | 200 |   | 555 |   |
| Exploration                                                   |       | 4                |       | 26         |       | 214        |       | 46         |       | 72                           | (10)       | —                |       | — |   | — |   | — |   | 362 |   |
| Interest                                                      |       | —           |       | —     |       | —     |       | —     |       | —                       |       | —                |       | — |   | 11 |   | 42 |   | 53 |   |
| Income (Loss)  from Continuing Operations before Income Taxes |       | 831              |       | 22         |       | 36         |       | 206        |       | 5                            |       | 416                   |       | 207 |   | 44 |   | (471 | ) | 1,296 |   |
| Less: Provision  for (Recovery of) Income Taxes (11)          |       | 289              |       | 7          |       | 13         |       | 378        | (12)       | 1                            |       | 151                   |       | 66 |   | 15 |   | (237 | ) | 683 |   |
| Net Income (Loss)  from Continuing Operations                 |       | 542              |       | 15         |       | 23         |       | (172       | )          | 4                            |       | 265                   |       | 141 |   | 29 |   | (234 | ) | 613 |   |
| Less: Non-Controlling Interests                               |       | —           |       | —     |       | —     |       | —     |       | —                       |       | —                |       | — |   | 12 |   | — |   | 12 |   |
| **Net Income (Loss)**                                         | ** ** | **542**          | ** ** | **15**     | ** ** | **23**     | ** ** | **(172**   | **)**      | **4**                        | ** ** | **265**               | ** ** | **141** | ** ** | **17** | ** ** | **(234** | **)** | **601** | ** ** |
| ** **                                                    | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **                   | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Identifiable Assets**                                       | ** ** | **464**          | ** ** | **3,923**  | ** ** | **1,620**  | ** ** | **5,490**  | ** ** | **245**                      | ** ** | **3,528**             | (13)       | **1,186** | ** ** | **459** | ** ** | **241** | ** ** | **17,156** | ** ** |
|                                                          |       |             |       |       |       |       |       |       |       |                         |       |                  |       |   |   |   |   |   |   |   |   |
| Capital Expenditures                                          |       |             |       |       |       |       |       |       |       |                         |       |                  |       |   |   |   |   |   |   |   |   |
| Development and  Other                                        |       | 145              |       | 1,434      |       | 418        |       | 596        |       | 28                           |       | 47                    |       | 86 |   | 27 |   | 45 |   | 2,826 |   |
| Exploration                                                   |       | 37               |       | 163        |       | 177        |       | 62         |       | 52                           |       | —                |       | — |   | — |   | — |   | 491 |   |
| Proved Property  Acquisitions                                 |       | —           |       | 12         |       | —     |       | 1          |       | —                       |       | —                |       | — |   | — |   | — |   | 13 |   |
| **Total Capital Expenditures**                                | ** ** | **182**          | ** ** | **1,609**  | ** ** | **595**    | ** ** | **659**    | ** ** | **80**                       | ** ** | **47**                | ** ** | **86** | ** ** | **27** | ** ** | **45** | ** ** | **3,330** | ** ** |
| ** **                                                    | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **                   | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Property, Plant  and Equipment                                |       |             |       |       |       |       |       |       |       |                         |       |                  |       |   |   |   |   |   |   |   |   |
| Cost                                                          |       | 2,404            |       | 5,216      |       | 2,889      |       | 4,710      |       | 249                          |       | 226                   |       | 1,304 |   | 854 |   | 286 |   | 18,138 |   |
| Less: Accumulated  DD&A                                   |       | 2,128            |       | 1,448      |       | 1,445      |       | 432        |       | 78                           |       | 47                    |       | 179 |   | 494 |   | 148 |   | 6,399 |   |
| **Net Book Value**(2)                                         | ** ** | **276**          | ** ** | **3,768**  | ** ** | **1,444**  | ** ** | **4,278**  | ** ** | **171**                      | ** ** | **179**               | ** ** | **1,125** | ** ** | **360** | ** ** | **138** | ** ** | **11,739** | ** ** |
| ** **                                                    | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **                   | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Goodwill**                                                  | ** ** | **—**       | ** ** | **—** | ** ** | **—** | ** ** | **325**    | ** ** | **—**                   | ** ** | **52**                | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **377** | ** ** |

 

----

*Notes:*
| *(1)* | *Includes results of operations  from producing activities in Colombia.* |
|-------|--------------------------------------------------------------------------|

 
| *(2)*    | *Net sales made from all  segments originating in Canada:* | *1,095*         |
|----------|------------------------------------------------------------|-----------------|
|     | *PP&E located in Canada:*                              | * *        | *5,483* |
| *(3)*    | *Net sales for our chemicals  operations include:*         |            |
| * * | * *                                                   |            |
| * * | * *                                                   | *Canada*        | *139* |
| * * | * *                                                   | *United States* | *185* |
| * * | * *                                                   | *Brazil*        | *83* |
| * * | * *                                                   | *Total*         | *407* |
|          |                                                            |                 |  |  |

 

*(4**)**                **Includes $80 million ofbusiness interruption insurance proceeds related to production losses caused byGulf of Mexico hurricanes in 2005.*

*(5**)**                **Includes $74 million ofbusiness interruption insurance proceeds for generator failures in 2005.*

*(6**)**                **Includes interest incomeof $36 million, foreign exchange losses of $72 million and decrease in the fairvalue of crude oil put options of $11 million.*

*(7**)**                **Includes an impairmentcharge of $93 million, primarily relating to two natural gas properties in theGulf of Mexico.*

*(8**)**                **Includes $151 million(US$135 million) accrual with respect to the Block 51 arbitration settlement(see Note 15).*

*(9**)**                **Includes stock-basedcompensation expense of $210 million.*

*(10**)**         **Includes explorationactivities primarily in Nigeria, Norway and Colombia.*

*(11**)**         **The provision for(recovery of) income taxes for foreign locations is based on in-country taxeson foreign income. For oil and gas locations with no operating activities, theprovision is based on the tax jurisdiction of the entity performing theactivity.*

*(*12*)*            *Includes future income tax expense of $277 millionrelated to an increase in the supplemental tax rate on oil and gas activitiesin the United Kingdom (see Note 18).*

*(**13)**         **Approximately 80% of Marketing’sidentifiable assets are accounts receivable and inventories.*

 

120

----

 

**2005 Operating and GeographicSegments**

 
| ** **                                                    | ** ** | **Oil and  Gas** | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** **                    | ** ** | ** **            | ** ** |
|---------------------------------------------------------------|------------|------------------|------------|--------------------|------------|------------|------------|------------|------------|-------------------------------|------------|-----------------------|------------|
| **(Cdn$ millions)**                                      | ** ** | **Yemen**        | ** ** | **Canada (****1)** | ** ** | **US**     | ** ** | **UK**     | ** ** | **Other   Countries (****2)** | ** ** | **Energy  Marketing** | ** ** | **Syncrude** | ** ** | **Chemicals** | ** ** | **Corporate  and Other** | ** ** | **Total** | ** ** |
| Net Sales (3)                                                 |       | 1,377            |       | 455                |       | 792        |       | 366        |       | 119                           |       | 28                    |       | 397 |   | 398 | (4) | — |   | 3,932 |   |
| Marketing and Other                                           |       | 8                |       | 3                  |       | 2          |       | 16         |       | 4                             |       | 847                   |       | — |   | 15 |   | (193 | )(5) | 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 | (6) | 22 |   | 1,052 |   |
| Transportation  and Other                                     |       | 6                |       | 23                 |       | 1          |       | —     |       | 2                             |       | 641                   |       | 21 |   | 40 |   | 62 |   | 796 |   |
| General and  Administrative (7)                               |       | 42               |       | 107                |       | 88         |       | 8          |       | 101                           |       | 89                    |       | 1 |   | 45 |   | 328 |   | 809 |   |
| Exploration                                                   |       | 12               |       | 23                 |       | 100        |       | 51         |       | 64                            | (8)        | —                |       | — |   | — |   | — |   | 250 |   |
| Interest                                                      |       | —           |       | —             |       | —     |       | —     |       | —                        |       | —                |       | — |   | 3 |   | 94 |   | 97 |   |
| Income (Loss)  from Continuing Operations before Income Taxes |       | 821              |       | 44                 |       | 275        |       | 18         |       | (69                           | )          | 104                   |       | 206 |   | 230 |   | (699 | ) | 930 |   |
| Less: Provision  for (Recovery of) Income Taxes (9)           |       | 285              |       | 13                 |       | 98         |       | 7          |       | (13                           | )          | 41                    |       | 60 |   | 15 |   | (272 | ) | 234 |   |
| Net Income (Loss)  from Continuing Operations                 |       | 536              |       | 31                 |       | 177        |       | 11         |       | (56                           | )          | 63                    |       | 146 |   | 215 |   | (427 | ) | 696 |   |
| Less: Non-Controlling Interests                               |       | —           |       | —             |       | —     |       | —     |       | —                        |       | —                |       | — |   | 8 |   | — |   | 8 |   |
| Add: Net Income from  Discontinued Operations                 |       | —           |       | 452                |       | —     |       | —     |       | —                        |       | —                |       | — |   | — |   | — |   | 452 |   |
| **Net Income (Loss)**                                         | ** ** | **536**          | ** ** | **483**            | ** ** | **177**    | ** ** | **11**     | ** ** | **(56**                       | **)**      | **63**                | ** ** | **146** | ** ** | **207** | ** ** | **(427** | **)** | **1,140** | ** ** |
| ** **                                                    | ** ** | ** **       | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** **                    | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Identifiable Assets**                                       | ** ** | **635**          | ** ** | **2,449**          | ** ** | **1,433**  | ** ** | **4,775**  | ** ** | **183**                       | ** ** | **3,165**             | (10)       | **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**(3)                                         | ** ** | **402**          | ** ** | **2,320**          | ** ** | **1,278**  | ** ** | **3,797**  | ** ** | **130**                       | ** ** | **105**               | ** ** | **1,069** | ** ** | **371** | ** ** | **122** | ** ** | **9,594** | ** ** |
| ** **                                                    | ** ** | ** **       | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** **                    | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Goodwill**                                                  | ** ** | **—**       | ** ** | **—**         | ** ** | **—** | ** ** | **325**    | ** ** | **—**                    | ** ** | **39**                | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **364** | ** ** |

 

----

*Notes:*
| *(1)* | *During the third quarter of  2005, we concluded the sale of Canadian conventional oil and gas properties.  The results of these properties are shown as discontinued operations (see  Note 14).* |
|-------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Includes results of  operations from producing activities in Nigeria and Colombia.*                                                                                                              |

 
| *(3)*    | *Net sales made from all  segments originating in Canada:* | *1,014*         |
|----------|------------------------------------------------------------|-----------------|
| * * | *PP&E located in Canada:*                              | *3,899*         |
| *(4)*    | *Net sales for our chemicals  operations include:*         |            |
| * * | * *                                                   |            |
| * * | * *                                                   | *Canada*        | *132* |
| * * | * *                                                   | *United States* | *198* |
| * * | * *                                                   | *Brazil*        | *68* |
| * * | * *                                                   | *Total*         | *398* |

* *

*(5**)**                **Includes interest incomeof $29 million, foreign exchange losses of $19 million, decrease in the fairvalue of crude oil put options of $196 million and decrease in the fair valueof foreign currency call options of $7 million.*

*(6**)**                **Includes impairmentcharge of $12 million related to the closure of our sodium chlorate plant inAmherstburg, Ontario.*

*(7**)**                **Includes stock-basedcompensation expense of $507 million.*

*(8**)**                **Includes explorationactivities primarily in Nigeria, Colombia and Equatorial Guinea.*

*(9**)**                **The provision for(recovery of) income taxes for foreign locations is based on in-country taxeson foreign income. For oil and gas locations with no operating activities, theprovision is based on the tax jurisdiction of the entity performing theactivity.*

*(**10)**         **Approximately 86% of Marketing’sidentifiable assets are accounts receivable and inventories.*

 

121

----

 

**2004 Operating and GeographicSegments**

 
| ** **                                                    | ** ** | **Oil and  Gas** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **            | ** ** |
|---------------------------------------------------------------|------------|------------------|------------|------------|------------|------------|------------|----------------|------------|-------------------------------|------------|-----------------------|------------|
| **(Cdn$ millions)**                                      | ** ** | **Yemen**        | ** ** | **Canada** | ** ** | **US**     | ** ** | **UK (****1)** | ** ** | **Other   Countries (****2)** | ** ** | **Energy  Marketing** | ** ** | **Syncrude** | ** ** | **Chemicals** | ** ** | **Corporate    and Other** | ** ** | **Total** | ** ** |
| Net Sales (3)                                                 |       | 921              |       | 390        |       | 811        |       | 36             |       | 73                            |       | 14                    |       | 321 |   | 378 | (4) | — |   | 2,944 |   |
| Marketing and Other                                           |       | 5                |       | 27         |       | 11         |       | —         |       | 2                             |       | 608                   |       | — |   | 5 |   | 55 | (5) | 713 |   |
|                                                          |       | 926              |       | 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                            | (6)        | —                |       | — |   | — |   | — |   | 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 (7)           |       | 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 (8)             |       | —           |       | 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**             | (9)        | **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**(3)                                         | ** ** | **488**          | ** ** | **1,408**  | (10)       | **1,212**  | ** ** | **3,483**      | ** ** | **127**                       | ** ** | **93**                | ** ** | **875** | ** ** | **406** | ** ** | **111** | ** ** | **8,203** | ** ** |
| ** **                                                    | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Goodwill**                                                  | ** ** | **—**       | ** ** | **—** | ** ** | **—** | ** ** | **339**        | ** ** | **—**                    | ** ** | **36**                | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **375** | ** ** |

 

----

*Notes:*
| *(1)* | *On December 1, 2004, we  acquired EnCana (UK) Limited (see Note 3).*                            |
|-------|--------------------------------------------------------------------------------------------------|
| *(2)* | *Includes results of  operations from producing activities in Nigeria, Colombia, and Australia.* |

 
| *(3)*    | *Net sales made from all  segments originating in Canada:* | *1,242*         |
|----------|------------------------------------------------------------|-----------------|
| * * | *PP&E located in Canada:*                              | *3,198*         |
| *(4)*    | *Net sales for our chemicals  operations include:*         |            |
| * * | * *                                                   |            |
| * * | * *                                                   | *Canada*        | *135* |
| * * | * *                                                   | *United States* | *184* |
| * * | * *                                                   | *Brazil*        | *59* |
| * * | * *                                                   | *Total*         | *378* |

 

*(5)**                 **Includes interest incomeof $12 million, foreign exchange losses of $13 million and unrealizedmark-to-market gains on crude oil put options of $56 million.*

*(6)**                 **Includes explorationactivities primarily in Nigeria and Colombia.*

*(7)**                 **The provision for(recovery of) income taxes for foreign locations is based on in-country taxeson foreign income. For oil and gas locations with no operating activities, theprovision is based on the tax jurisdiction of the entity performing theactivity.*

*(8)**                 **In the fourth quarter of2004, we concluded production activities in Australia. During the third quarterof 2005, we concluded the sale of certain Canadian conventional oil and gasproperties. The combined results of these dispositions are shown asdiscontinued operations (see Note 14).*

*(9)**                 **Approximately 81% ofMarketing’s identifiable assets are accounts receivable and inventories.*

*(10)**          **Excludes PP&E costs of $860million and accumulated DD&A of $420 million relating to the Canadianproperties disposed of during 2005 (see Note 14).*

 

122

----

 

**21.****                              ****DIFFERENCES BETWEEN CANADIAN ANDUS GENERALLY ACCEPTED ACCOUNTING PRINCIPLES**

 

The Consolidated FinancialStatements have been prepared in accordance with Canadian GAAP. US GAAPConsolidated Financial Statements and summaries of differences from CanadianGAAP are as follows:

 

**Consolidated Statement ofIncome—US GAAP**

**For the Three****Y****ears ended****D****ecember 31, 2006**

 
| **(Cdn$ millions, except per share amounts)**                      | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Revenues and  Other Income                                              |       |       |       |       |       |       |       |
| Net Sales                                                               |       | 3,936      |       | 3,932      |       | 2,944      |       |
| Marketing and Other (ii); (x); (xi)                                     |       | 1,459      |       | 687        |       | 696        |       |
| Gain on Dilution of Interest in Chemicals  Business                     |       | —     |       | 193        |       | —     |       |
|                                                                    |       | 5,395      |       | 4,812      |       | 3,640      |       |
| Expenses                                                                |       |       |       |       |       |       |       |
| Operating (iv)                                                          |       | 958        |       | 903        |       | 731        |       |
| Depreciation, Depletion, Amortization and  Impairment (i)               |       | 1,124      |       | 1,081      |       | 716        |       |
| Transportation and Other (x)                                            |       | 1,037      |       | 792        |       | 524        |       |
| General and Administrative (viii); (ix)                                 |       | 597        |       | 792        |       | 263        |       |
| Exploration                                                             |       | 362        |       | 250        |       | 243        |       |
| Interest                                                                |       | 53         |       | 97         |       | 143        |       |
|                                                                    |       | 4,131      |       | 3,915      |       | 2,620      |       |
|                                                                    |       |       |       |       |       |       |       |
| Income from  Continuing Operations before Income Taxes                  |       | 1,264      |       | 897        |       | 1,020      |       |
|                                                                    |       |       |       |       |       |       |       |
| Provision  for Income Taxes                                             |       |       |       |       |       |       |       |
| Current                                                                 |       | 368        |       | 339        |       | 248        |       |
| Deferred (ii) – (xi)                                               |       | 305        |       | (108       | )          | 67         |       |
|                                                                    |       | 673        |       | 231        |       | 315        |       |
|                                                                    |       |       |       |       |       |       |       |
| Net Income  from Continuing Operations before Non-Controlling Interests |       | 591        |       | 666        |       | 705        |       |
| Net Income Attributable to Non-Controlling  Interests                   |       | 12         |       | 8          |       | —     |       |
| Net Income from  Continuing Operations                                  |       | 579        |       | 658        |       | 705        |       |
| Net Income from Discontinued Operations                                 |       | —     |       | 452        |       | 83         |       |
|                                                                    |       |       |       |       |       |       |       |
| **Net  Income—US GAAP**(1)                                         | ** ** | **579**    | ** ** | **1,110**  | ** ** | **788**    | ** ** |
| ** **                                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Earnings  Per Common Share**($/share)                                 |       |       |       |       |       |       |       |
| Basic (Note 13)                                                         |       |       |       |       |       |       |       |
| Net Income from Continuing Operations                                   |       | 2.21       |       | 2.52       |       | 2.74       |       |
| Net Income from Discontinued Operations                                 |       | —     |       | 1.74       |       | 0.32       |       |
|                                                                    |       | 2.21       |       | 4.26       |       | 3.06       |       |
|                                                                    |       |       |       |       |       |       |       |
| Diluted (Note 13)                                                       |       |       |       |       |       |       |       |
| Net Income from Continuing Operations                                   |       | 2.15       |       | 2.47       |       | 2.71       |       |
| Net Income from Discontinued Operations                                 |       | —     |       | 1.70       |       | 0.32       |       |
| ** **                                                              | ** ** | **2.15**   | ** ** | **4.17**   | ** ** | **3.03**   |       |

 

----

*Note:*

*(1)**      **Reconciliation of Canadian and USGAAP Net Income*

 
| **(Cdn$ millions)**                                  | ** ** | **2006** | ** ** | **2005**  | ** ** | **2004** | ** ** |
|-----------------------------------------------------------|------------|----------|------------|-----------|------------|----------|------------|
| Net  Income—Canadian GAAP                            |       | 601      |       | 1,140     |       | 793      |       |
| Impact of US Principles, Net of Income  Taxes:            |       |     |       |      |       |     |       |
| Depreciation, Depletion, Amortization and  Impairment (i) |       | —   |       | (29       | )          | (42      | )          |
| Stock-Based Compensation (viii); (ix)                     |       | (29      | )          | 12        |       | 36       |       |
| Other (ii); (iv); (xi)                                    |       | 7        |       | (13       | )          | 1        |       |
| **Net  Income—US GAAP**                              | ** ** | **579**  | ** ** | **1,110** | ** ** | **788**  | ** ** |

 

 

123

----

 

**ConsolidatedBalance Sheet—US GAAP**

**December 31,2006 and 2005**

 
| **(Cdn$ millions, except share amounts)**                                                                                   | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| **ASSETS**                                                                                                                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Current Assets                                                                                                                   |       |       |       |       |       |
| Cash and Cash Equivalents                                                                                                        |       | 101        |       | 48         |       |
| Restricted Cash and Margin Deposits                                                                                              |       | 197        |       | 70         |       |
| Accounts Receivable (ii)                                                                                                         |       | 2,976      |       | 3,151      |       |
| Inventories and Supplies                                                                                                         |       | 786        |       | 504        |       |
| Deferred Income Tax Assets                                                                                                       |       | 479        |       | —     |       |
| Other                                                                                                                            |       | 67         |       | 51         |       |
| Total Current Assets                                                                                                             |       | 4,606      |       | 3,824      |       |
|                                                                                                                             |       |       |       |       |       |
| Property,  Plant and Equipment                                                                                                   |       |       |       |       |       |
| Net of Accumulated Depreciation, Depletion,  Amortization and   Impairment of $6,792 (December 31, 2005—$5,861) (iv); (vii) |       | 11,692     |       | 9,550      |       |
| Goodwill                                                                                                                         |       | 377        |       | 364        |       |
| Deferred Income Tax Assets                                                                                                       |       | 141        |       | 410        |       |
| Deferred Charges and Other Assets (v); (vi)                                                                                      |       | 263        |       | 345        |       |
|                                                                                                                             |       |       |       |       |       |
| **TOTAL  ASSETS**                                                                                                                | ** ** | **17,079** | ** ** | **14,493** | ** ** |
|                                                                                                                             |       |       |       |       |       |
| **LIABILITIES  AND SHAREHOLDERS’ EQUITY**                                                                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Current Liabilities                                                                                                              |       |       |       |       |       |
| Short-Term Borrowings                                                                                                            |       | 158        |       | —     |       |
| Accounts Payable and Accrued Liabilities  (ii); (ix)                                                                             |       | 3,839      |       | 3,745      |       |
| Accrued Interest Payable                                                                                                         |       | 55         |       | 55         |       |
| Dividends Payable                                                                                                                |       | 13         |       | 13         |       |
| Total Current Liabilities                                                                                                        |       | 4,065      |       | 3,813      |       |
|                                                                                                                             |       |       |       |       |       |
| Long-Term Debt (v)                                                                                                               |       | 4,618      |       | 3,630      |       |
| Deferred Income Tax Liabilities (i) – (xi)                                                                                  |       | 2,427      |       | 1,906      |       |
| Asset Retirement Obligations                                                                                                     |       | 683        |       | 590        |       |
| Deferred Credits and Other Liabilities (vi)                                                                                      |       | 597        |       | 505        |       |
| Non-Controlling Interests                                                                                                        |       | 75         |       | 88         |       |
| Shareholders’ Equity                                                                                                        |       |       |       |       |       |
| Common Shares, no par value                                                                                                      |       |       |       |       |       |
| Authorized:    Unlimited                                                                                          |       |       |       |       |       |
| Outstanding:  2006—262,513,206 shares                                                                                  |       |       |       |       |       |
|                 2005—261,140,571 shares               |       | 821        |       | 732        |       |
| Contributed Surplus                                                                                                              |       | 4          |       | 2          |       |
| Retained Earnings (i) – (xi)                                                                                                |       | 3,945      |       | 3,418      |       |
| Accumulated Other Comprehensive Income  (ii); (iii); (vi)                                                                        |       | (156       | )          | (191       | )          |
| Total Shareholders’ Equity                                                                                                  |       | 4,614      |       | 3,961      |       |
| Commitments, Contingencies and Guarantees                                                                                        |       |       |       |       |       |
| **TOTAL  LIABILITIES AND SHAREHOLDERS’ EQUITY**                                                                             | ** ** | **17,079** | ** ** | **14,493** | ** ** |

 

124

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**ConsolidatedStatement of Comprehensive Income—US GAAP**

**For theThree Years ended December 31, 2006**

 
| **(Cdn$ millions)**                          | ** ** | **2006** | ** ** | **2005**  | ** ** | **2004** | ** ** |
|---------------------------------------------------|------------|----------|------------|-----------|------------|----------|------------|
| Net  Income—US GAAP                          |       | 579      |       | 1,110     |       | 788      |       |
| Other Comprehensive Income, Net of Income  Taxes: |       |     |       |      |       |     |       |
| Translation Adjustment (iii)                      |       | —   |       | (56       | )          | (72      | )          |
| Unrealized Mark-to-Market Gain (Loss) (ii)        |       | 77       |       | (20       | )          | 11       |       |
| Minimum Unfunded Pension Liability (vi)           |       | 5        |       | (10       | )          | (1       | )          |
| Adoption of FASB Statement 158 (vi)               |       | (47      | )          | —    |       | —   |       |
| **Comprehensive  Income**                         | ** ** | **614**  | ** ** | **1,024** | ** ** | **726**  | ** ** |

 

**ConsolidatedStatement of Accumulated Other Comprehensive Income—US GAAP**

**December 31,2006 and 2005**

 
| **(Cdn$ millions)**                             | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------------------|------------|----------|------------|----------|------------|
| Translation  Adjustment (iii)                        |       | (161     | )          | (161     | )          |
| Unrealized  Mark-to-Market Gains (Losses) (ii)       |       | 61       |       | (16      | )          |
| Minimum  Pension Liability Adjustment (vi)           |       | —   |       | (14      | )          |
| Unamortized  Defined Benefit Pension Plan Costs (vi) |       | (56      | )          | —   |       |
| **Accumulated  Other Comprehensive Income (AOCI)**   | ** ** | **(156** | **)**      | **(191** | **)**      |

 

----

**Notes to theConsolidated US GAAP Financial Statements:**

 

(i)                  Under US GAAP, the liability method ofaccounting for income taxes was adopted in 1993. In Canada, the liabilitymethod was adopted in 2000. In 1997, we acquired certain oil and gas assets andthe amount paid for these assets differed from the tax basis acquired. Under USprinciples, this difference was recorded as a deferred tax liability with anincrease to PP&E rather than a charge to retained earnings. As a result,additional depreciation, depletion, amortization and impairment of $29 millionwas included in net income during 2005 (2004—$42 million). Thedifference was fully amortized during 2005.

 

(ii)               Under US GAAP, all derivative instruments arerecognized on the balance sheet as either an asset or a liability measured atfair value. Changes in the fair value of derivatives are recognized in earningsunless specific hedge criteria are met.

 

**Cash flow hedges**

 

Changesin the fair value of derivatives that are designated as cash flow hedges arerecognized in net income in the same period as the hedged item. Any fair valuechange in a derivative before that period is recognized on the balance sheet.The effective portion of that change is recognized in other comprehensiveincome with any ineffectiveness recognized in net income.

 

*Future sale of oil and gas production:* At December 31, 2003, accounts payableincludes a $3 million loss on forward contracts we used to hedge commodityprice risk on the future sale of a portion of our production from the Aspenfield. These contracts expired in March 2004. Losses ($2 million, net of incometaxes), that were deferred in accumulated other comprehensive income (AOCI) atDecember 31, 2003, were recognized in net sales in 2004. 

 

*Future sale of gas inventory:* At December 31, 2003, accounts payableincludes $11 million of losses on futures and basis swap contracts we used tohedge commodity price risk on the future sale of our gas inventory. Losses of$8 million ($5 million, net of income taxes), related to the effective portionand deferred in AOCI at December 31, 2003, were recognized in marketing andother in 2004. Additionally, losses of $3 million ($2 million, net of incometaxes), related to the ineffective portion, were recognized in marketing andother under US GAAP in 2003. Under Canadian GAAP, the ineffective portion wasrecognized in net income in 2004.

 

AtDecember 31, 2004, accounts receivable includes $6 million of gains on futurescontracts and swaps we used to hedge commodity price risk on the future sale ofour gas inventory. Gains of $6 million ($4 million net of income taxes),related to the effective portion and deferred in AOCI at December 31, 2004,were recognized in marketing and other in 2005.

 

125

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AtDecember 31, 2005, accounts payable includes losses of $35 million on futurescontracts and swaps we used to hedge commodity price risk on the future sale ofour gas inventory. Losses of $24 million ($16 million, net of income taxes),related to the effective portion and deferred in AOCI at December 31, 2005,were recognized in marketing and other in 2006. The ineffective portion of thelosses of $11 million ($7 million, net of income taxes) was recognized in USGAAP net income in 2005. Under Canadian GAAP, the ineffective portion wasrecognized in marketing and other in 2006.

 

AtDecember 31, 2006, accounts receivable includes gains of $25 million on futurescontracts and swaps we used to hedge commodity price risk on the future sale ofour gas inventory. Gains of $23 million ($16 million, net of income taxes),related to the effective portion, have been deferred in AOCI until theunderlying gas inventory is sold. These gains will be reclassified to marketingand other as the contracts settle over the next 12 months. The ineffectiveportion of the gains of $2 million ($2 million, net of taxes) was recognized inmarketing and other in 2006. 

 

Alsoincluded in AOCI at December 31, 2006 are gains of $65 million ($45 million,net of income taxes) related to de-designated cash flow hedges as described inNote 7(b). These gains will be reclassified to marketing and other over thenext 12 months. Under Canadian GAAP, these deferred gains are included inaccounts payable and accrued liabilities.

 

**Fair value hedges**

 

Boththe derivative instrument and the underlying commitment are recognized on thebalance sheet at their fair value. The change in fair value of both arereflected in net income. At December 31, 2006, we had no fair value hedges inplace.

 

(iii)            Under US GAAP, exchange gains and lossesarising from the translation of our net investment in self-sustaining foreignoperations are included in comprehensive income. Additionally, exchange gainsand losses, net of income taxes, from the translation of our US-dollar long-termdebt designated as a hedge of our foreign net investment are included incomprehensive income. Cumulative amounts are included in AOCI in theConsolidated Balance Sheet— US GAAP.

 

(iv)           Under Canadian GAAP, we defer certain development costs and all pre-operatingrevenues and costs to PP&E. Under US GAAP, these costs have been includedin operating expenses. As a result:

 

•                       operating expenses include pre-operating costsof $3 million ($2 million, net of income taxes) (2005— $10million ($6 million net of income taxes); 2004— $9 million ($6 million,net of income taxes)); and

•                       PP&E is lower under US GAAP by $28 million(December 31, 2005—$25 million).

 

(v)              Under US GAAP, discounts on long-term debt areclassified as a reduction of long-term debt rather than as deferred charges andother assets. Discounts of $55 million (December 31, 2005—$57 million) havebeen included in long-term debt.

 

(vi)           On December 31, 2006, we adopted FASB Statement No. 158 *Employer’s Accounting for Defined Benefit**Pension and Other Postretirement Plans* asdescribed under changes in accounting policy—US GAAP. At year-end, the unfundedamount of our defined benefit pension plans was $81 million. This amount hasbeen included in deferred credits and other liabilities and $56 million, net ofincome taxes, has been included in AOCI. Prior to the adoption of FAS 158 onDecember 31, 2006, we included our minimum unfunded pension liability indeferred credits and other liabilities and in AOCI. At December 31, 2005, $26million was included in deferred credits and other liabilities, $4 million wasincluded in deferred charges and other assets and $14 million, net of incometaxes was included in AOCI. During the year, our minimum unfunded pensionliability decreased by $5 million, net of income taxes (2005 – increased by $10million, net of income taxes; 2004 – increased by $1 million, net of incometaxes).

 

(vii)        On January 1, 2003, we adopted FASB Statement No. 143, *Accounting for Asset Retirement Obligations*(FAS143) for US GAAP reporting purposes. We adopted the equivalent Canadianstandard for asset retirement obligations on January 1, 2004. These standardsare consistent, except for the adoption date, which resulted in our PP&Eunder US GAAP being lower by $19 million.

 

(viii)     As described in Note 12(c), our existing stock option plan was modifiedto a tandem option plan in 2004 to include a cash feature. Prior to themodification of our stock option plan, we accounted for stock options using thefair-value method. Following the addition of the cash feature, we account forstock options using the intrinsic-value method. As a result of the planmodification, we recognized an obligation of $85 million for our tandem optionsunder both Canadian and US GAAP. This resulted in a one-time, non-cash expenseto net income for Canadian GAAP purposes of $54 million, net of tax, in thesecond quarter of 2004. For US GAAP purposes, $36 million of this expense wasrecognized as a reduction of US GAAP retained earnings

 

126

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and $18 million wasrecognized as an expense to our second quarter 2004 US GAAP net income. Thereduction of US GAAP retained earnings was made in respect of stock optionsgranted prior to the adoption of FAS 123 on January 1, 2003.

 

(ix)             Under Canadian principles, we recordobligations for liability-based stock compensation plans using theintrinsic-value method of accounting. Under US principles, effective January 1,2006 obligations for liability-based stock compensation plans are recordedusing the fair-value method of accounting. In addition, under Canadianprinciples as disclosed in Note 1(u), we retroactively adopted EIC–162 whichrequires the accelerated recognition of stock-based compensation expense forall stock-based awards made to our retired and retirement-eligible employees.However, under US GAAP, the accelerated recognition of stock-based compensationexpense for such employees is only required in respect of stock-based awardsgranted on or after January 1, 2006. As a result:

 

**•****                      **general and administrative expense is higherby $42 million ($29 million, net of income taxes) for the year ended December31, 2006 (2005—lower by $17 million ($12 million, net of income taxes));

•                       accounts payable and accrued liabilities arehigher by $25 million at December 31, 2006 (2005—lower by $17 million); and

•                       the impact for 2004 is not material.

 

(x)                Under US GAAP, gains and losses on thedisposition of assets are included with transportation and other expense. Gainsin 2006 of $4 million, 2005 of $4 million, and 2004 of $24 million were reclassified from marketing and other to transportationand other. 

 

(xi)    In May 2003, the FASB issued Statement No.150, *Accounting for Certain Instruments withCharacteristics of Both Liabilities and Equity* that requires certainfinancial instruments, including our preferred securities, to be valued at fairvalue with changes in fair value recognized through net income. The $4 millionincrease in fair value from January 1, 2004 to February 9, 2004 (redemptiondate of preferred securities) was included in net income for the year endedDecember 31, 2004.

 

**Changes inAccounting Policies—US GAAP**

 

**Stock-BasedCompensation**

 

On January 1, 2006, weadopted FASB Statement 123 (revised), *Share-BasedPayment* (Statement 123(R)) using the modified prospective approachand graded vesting amortization. Under Statement 123(R), our tandem options andstock appreciation rights (StARs) are considered liability-based stockcompensation plans. Under the modified prospective approach, no amounts arerestated in prior periods. Upon adoption of Statement 123(R), we recorded acumulative effect of a change in accounting principle of $2 million. Thisamount was recorded in general and administrative expenses in our US GAAPConsolidated Statement of Income in 2006.

 

Prior to the adoption ofStatement 123(R), we accounted for our liability-based stock compensation plansin accordance with FASB Interpretation 28, *Accountingfor Stock Appreciation Rights and Other Variable Stock Option or Award Plans*(the intrinsic-value method). Accordingly, obligations were accrued on a gradedvesting basis and represented the difference between the market value of ourcommon shares and the exercise price of underlying options and rights. UnderStatement 123(R), obligations for liability-based stock compensation plans aremeasured at their fair value, and are remeasured at fair value in eachsubsequent reporting period. 

 

Consistent with Statement123(R), we account for any stock options that do not include a cash feature(equity-based stock compensation plans), using the fair-value method.

 

The impact of adoptingStatement 123(R) on our results for the year ended December 31, 2006 is asfollows:

 
| ** **                                                           | ** ** | **Prior to**    | ** ** | **After**       | ** ** | ** **     | ** ** |
|----------------------------------------------------------------------|------------|-----------------|------------|-----------------|------------|----------------|------------|
| ** **                                                           | ** ** | **Adoption of** | ** ** | **Adoption of** | ** ** | **Increase/**  | ** ** |
| **(Cdn$ millions)**                                             | ** ** | **FAS 123(R)**  | ** ** | **FAS 123(R)**  | ** ** | **(Decrease)** | ** ** |
| Income from  Continuing Operations before Income Taxes —US GAAP |       | 1,306           |       | 1,264           |       | (42            | )          |
| Net  Income—US GAAP                                             |       | 608             |       | 579             |       | (29            | )          |
| Basic  Earnings per Common Share—US GAAP ($/share)              |       | 2.32            |       | 2.21            |       | (0.11          | )          |
| Diluted  Earnings per Common Share—US GAAP ($/share)            |       | 2.26            |       | 2.15            |       | (0.11          | )          |

 

127

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*Assumptions*

 

We use the GeneralizedBlack-Scholes option pricing model to estimate the fair value of ourstock-based compensation, with the following assumptions:

 
| Expected Annual Dividends per Common Share ($/share)                   |   | 0.20            |   |
|------------------------------------------------------------------------|--------|-----------------|--------|
| Expected  Volatility                                                   |   | 40              | %      |
| Risk-Free  Interest Rate                                               |   | 4.3% — 4.4 | %      |
| Weighted-Average  Expected Life of Compensation Instruments (in years) |   | 2.8 — 3.0  |   |

 

These assumptions are basedon multiple factors, including historical exercise patterns of employees inrelatively homogenous groups with respect to exercise and post-vestingemployment termination behaviors, expected future exercising patterns for thosesame homogenous groups, the implied volatility of our stock price, our expectedfuture dividend levels and the interest rate for Government of Canada bonds.Our valuation methodology and assumptions are consistent with those previouslyused under FAS 123.

 

*Stock Options*

 
| ** **                                             | ** ** | ** **      | ** ** | ** **         | ** ** | **Weighted**       | ** ** | ** **               | ** ** | ** **     | ** ** |
|--------------------------------------------------------|------------|-----------------|------------|--------------------|------------|--------------------|------------|--------------------------|------------|----------------|------------|
| ** **                                             | ** ** | ** **      | ** ** | **Weighted**       | ** ** | **Average**        | ** ** | ** **               | ** ** | **Weighted**   | ** ** |
| ** **                                             | ** ** | ** **      | ** ** | **Average**        | ** ** | **Remaining**      | ** ** | **Aggregate**            | ** ** | **Average**    | ** ** |
| ** **                                             | ** ** | **Number**      | ** ** | **Exercise Price** | ** ** | **Term to Expiry** | ** ** | **Intrinsic Value**      | ** ** | **Fair Value** | ** ** |
| ** **                                             | ** ** | **(thousands)** | ** ** | **($/option)**     | ** ** | **(years)**        | ** ** | **(Cdn$ millions)** | ** ** | **($/option)** | ** ** |
| Outstanding  at December 31, 2006                      |       | 15,242          |       | 35                 |       | 3.2                |       | 450                      |       | 33             |       |
| Outstanding at December 31, 2006 and  Expected to Vest |       | 15,156          |       | 35                 |       | 3.2                |       | 445                      |       | 34             |       |
| Exercisable  at December 31, 2006                      |       | 9,345           |       | 24                 |       | 2.6                |       | 373                      |       | 39             |       |

 

The total intrinsic value ofstock options exercised during the year ended December 31, 2006 was $109million (2005 — $83 million; 2004 – $60 million). As at December 31, 2006, wehad $77 million of unrecognized compensation expense related to stock optionswhich we expect to recognize over a weighted-average period of 1.5 years.

 

*StockAppreciation Rights*

 
| ** **                                             | ** ** | ** **      | ** ** | ** **         | ** ** | **Weighted**       | ** ** | ** **               | ** ** | ** **     | ** ** |
|--------------------------------------------------------|------------|-----------------|------------|--------------------|------------|--------------------|------------|--------------------------|------------|----------------|------------|
| ** **                                             | ** ** | ** **      | ** ** | **Weighted**       | ** ** | **Average**        | ** ** | ** **               | ** ** | **Weighted**   | ** ** |
| ** **                                             | ** ** | ** **      | ** ** | **Average**        | ** ** | **Remaining**      | ** ** | **Aggregate**            | ** ** | **Average**    | ** ** |
| ** **                                             | ** ** | **Number**      | ** ** | **Exercise Price** | ** ** | **Term to Expiry** | ** ** | **Intrinsic Value**      | ** ** | **Fair Value** | ** ** |
| ** **                                             | ** ** | **(thousands)** | ** ** | **($/right)**      | ** ** | **(years)**        | ** ** | **(Cdn$ millions)** | ** ** | **($/right)**  | ** ** |
| Outstanding  at December 31, 2006                      |       | 6,945           |       | 42                 |       | 3.5                |       | 154                      |       | 29             |       |
| Outstanding at December 31, 2006 and  Expected to Vest |       | 6,759           |       | 42                 |       | 3.5                |       | 151                      |       | 30             |       |
| Exercisable  at December 31, 2006                      |       | 3,076           |       | 27                 |       | 2.6                |       | 115                      |       | 38             |       |

 

The total intrinsic value ofstock appreciation rights exercised during the year ended December 31, 2006 was$46 million (2005—$34 million; 2004—$7 million). As at December 31, 2006, wehad $54 million of unrecognized compensation expense related to stock appreciationrights which we expect to recognize over a weighted-average period of 1.6years.

 

*Stock-BasedCompensation Expense and Payments*

 

For the year ended December31, 2006, stock-based compensation expense of $252 million (2005—$490 million;2004—$57 million) was included in general and administrative expense in theConsolidated Statement of Income—US GAAP.

 

For the year ended December31, 2006, cash proceeds of $16 million were received related to the exercise ofstock options (2005—$29 million; 2004—$93 million).

 

128

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For the year ended December 31, 2006, cash of$119 million (2005—$74 million; 2004—$10 million) was paid upon the exercise ofstock options and stock appreciation rights. The income tax benefit recordedfrom the exercise of stock options and stock appreciation rights was $37million (2005—$24 million; 2004—$3 million) for the period.

 

*Stock Based CompensationExpense for Retired and Retirement Eligible Employees*

 

We recognize stock-based compensation expensefor our retired and retirement-eligible employees over an accelerated gradedvesting period in accordance with the provisions of Statement 123(R) forstock-based awards granted to employees on or after January 1, 2006. Forstock-based awards granted prior to the adoption of Statement 123(R),stock-based compensation expense for our retired and retirement-eligibleemployees is recognized over a graded vesting period. If we applied theaccelerated graded vesting provisions of Statement 123(R) to stock-based awardsgranted to our retired and retirement-eligible employees prior to the adoptionof Statement 123(R), our stock-based compensation expense would decrease by $10million for the year ended December 31, 2006 (2005—increase by $19 million;2004—increase by $2 million).

 

**Pension and OtherPost-Retirement Benefits**

 

On December 31, 2006, we adopted FASB Statement158, *Employers’ Accounting for DefinedBenefit Pension and Other Postretirement Plans*(Statement 158),which requires, among other things, the recognition of the over-funded andunder-funded status of a defined benefit plan on the balance sheet as an assetor liability. The initial impact of the standard due to unrecognized priorservice costs or credits and net actuarial gains or losses as well assubsequent changes in the funded status is recognized as a component of AOCI inshareholders’ equity. Additional minimum pension liabilities and relatedintangible assets are also de-recognized upon adoption of Statement 158.

 

The impact of adopting Statement 158 at December31, 2006 reduced deferred charges and other assets by $4 million, reduceddeferred future income tax liabilities by $22 million, increased deferredcredits and other liabilities by $65 million and decreased AOCI by $47 million.The impact considered the additional minimum pension liability at December 31,2006 prior to the adoption of Statement 158.

 

**New Accounting Pronouncements**

 

In February 2006, the FASB issued Statement 155,*Accounting for Certain Hybrid Instruments*,which amends Statement 133,*****Accounting for Derivative Instruments and HedgingActivities*, and Statement 140, *Accountingfor Transfers and Servicing of Financial Assets and Extinguishments ofLiabilities*. Statement 155 permits fair value re-measurement for anyhybrid financial instrument that contains an embedded derivative that otherwisewould require bifurcation from its host contract in accordance with Statement133. Statement 155 also clarifies other provisions of Statement 133 andStatement 140. This statement is effective for all financial instrumentsacquired or issued in fiscal years beginning after September 15, 2006. We donot expect adoption of this statement will have a material impact on ourresults of operations or financial position.

 

In July 2006, FASB issued FIN 48 *Accounting for Uncertainty in Income Taxes*with respect to FAS 109 *Accounting forIncome Taxes* regarding accounting for and disclosure of uncertaintax positions. This guidance seeks to reduce the diversity in practiceassociated with certain aspects of the recognition and measurement related to accountingfor income taxes. This interpretation is effective for fiscal years beginningafter December 15, 2006. Adoption of this standard is expected to increase ourfuture income tax liabilities by no more than $30 million and decrease ourretained earnings by a corresponding amount.

 

In September 2006, FASB issuedStatement 157, *Fair Value Measurements.*Statement 157 defines fair value, establishes a framework for measuring fairvalue under US generally accepted accounting principles and expands disclosuresabout fair value measurements. This statement is effective for fiscal yearsbeginning after November 15, 2007. We do not expect the adoption of thisstatement will have a material impact on our results of operations or financialposition.

 

129

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| Item 8 | Financial Statements and Supplementary Data | Quarterly Data |
|--------|---------------------------------------------|----------------|

 

**SUPPLEMENTARY DATA(UNAUDITED)**

 

**Quarterly Financial Datain Accordance with Canadian and US GAAP**

 
| ** **                                                                         | ** ** | **Quarter Ended** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------|------------|
| ** **                                                                         | ** ** | **March 31**      | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| **(Cdn$ millions)**                                                           | ** ** | **2006**          | ** ** | **2005** | ** ** | **2006** | ** ** | **2005** | ** ** | **2006** | ** ** | **2005** | ** ** | **2006** | ** ** | **2005** | ** ** |
| Net Sales  (1)                                                                     |       | 980               |       | 856 |   | 1,039 |   | 909 |   | 997 |   | 1,094 |   | 920 |   | 1,073 |   |
|                                                                               |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Income (Loss) from Continuing Operations before  Income Taxes is Comprised of: (4) |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Oil and Gas (1),(2)                                                                |       | 196               |       | 247 |   | 476 |   | 193 |   | 372 |   | 330 |   | 56 |   | 319 |   |
| Energy Marketing                                                                   |       | 166               |       | 30 |   | 69 |   | 54 |   | 42 |   | (162 | ) | 139 |   | 182 |   |
| Syncrude                                                                           |       | 20                |       | 19 |   | 59 |   | 59 |   | 77 |   | 78 |   | 51 |   | 50 |   |
| Chemicals (3)                                                                      |       | 12                |       | 7 |   | 22 |   | (2 | ) | 10 |   | 215 |   | — |   | 10 |   |
| Corporate and Other                                                                |       | (66               | )          | (286 | ) | (92 | ) | (55 | ) | (171 | ) | (230 | ) | (142 | ) | (128 | ) |
|                                                                               | ** ** | **328**           | ** ** | **17** | ** ** | **534** | ** ** | **249** | ** ** | **330** | ** ** | **231** | ** ** | **104** | ** ** | **433** | ** ** |
|                                                                               |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Net Income (Loss) from Continuing Operations—Canadian  GAAP** (4)           | ** ** | **(83**           | **)**      | **13** | ** ** | **408** | ** ** | **167** | ** ** | **199** | ** ** | **205** | ** ** | **77** | ** ** | **303** | ** ** |
| US GAAP  Adjustments                                                               |       | 282               |       | (5 | ) | (11 | ) | (9 | ) | (283 | ) | (9 | ) | (10 | ) | (7 | ) |
| **Net Income (Loss) from Continuing Operations—US  GAAP**                     | ** ** | **199**           | ** ** | **8** | ** ** | **397** | ** ** | **158** | ** ** | **(84** | **)** | **196** | ** ** | **67** | ** ** | **296** | ** ** |
|                                                                               |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Net Income (Loss)—Canadian GAAP**(4)                                        | ** ** | **(83**           | **)**      | **31** | ** ** | **408** | ** ** | **197** | ** ** | **199** | ** ** | **609** | ** ** | **77** | ** ** | **303** | ** ** |
| US GAAP  Adjustments                                                               |       | 282               |       | (5 | ) | (11 | ) | (9 | ) | (283 | ) | (9 | ) | (10 | ) | (7 | ) |
| **Net  Income (Loss)—US GAAP**                                                | ** ** | **199**           | ** ** | **26** | ** ** | **397** | ** ** | **188** | ** ** | **(84** | **)** | **600** | ** ** | **67** | ** ** | **296** | ** ** |
|                                                                               |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Earnings (Loss) per Common Share from  Continuing Operations**($/share)          | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Canadian GAAP—Basic                                                           |       | (0.32             | )          | 0.06 |   | 1.56 |   | 0.64 |   | 0.76 |   | 0.79 |   | 0.29 |   | 1.16 |   |
| Canadian GAAP—Diluted                                                         |       | (0.32             | )          | 0.06 |   | 1.53 |   | 0.63 |   | 0.74 |   | 0.77 |   | 0.29 |   | 1.13 |   |
| US GAAP—Basic                                                                 |       | 0.76              |       | 0.03 |   | 1.52 |   | 0.61 |   | (0.33 | ) | 0.75 |   | 0.26 |   | 1.13 |   |
| US GAAP—Diluted                                                               |       | 0.74              |       | 0.03 |   | 1.48 |   | 0.60 |   | (0.33 | ) | 0.73 |   | 0.25 |   | 1.11 |   |
|                                                                               |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Earnings (Loss) per Common****Share**($/share)                                   | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Canadian GAAP—Basic                                                           |       | (0.32             | )          | 0.13 |   | 1.56 |   | 0.76 |   | 0.76 |   | 2.34 |   | 0.29 |   | 1.16 |   |
| Canadian GAAP—Diluted                                                         |       | (0.32             | )          | 0.13 |   | 1.53 |   | 0.75 |   | 0.74 |   | 2.28 |   | 0.29 |   | 1.13 |   |
| US GAAP—Basic                                                                 |       | 0.76              |       | 0.10 |   | 1.52 |   | 0.72 |   | (0.33 | ) | 2.31 |   | 0.26 |   | 1.13 |   |
| US GAAP—Diluted                                                               |       | 0.74              |       | 0.10 |   | 1.48 |   | 0.71 |   | (0.33 | ) | 2.25 |   | 0.25 |   | 1.11 |   |
|                                                                               |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Dividends  Declared**(5)                                                         |       | 0.05              |       | 0.05 |   | 0.05 |   | 0.05 |   | 0.05 |   | 0.05 |   | 0.05 |   | 0.05 |   |
|                                                                               |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Common  Share Prices**($/share)                                                  |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Toronto Stock Exchange—High                                                   |       | 68.10             |       | 35.50 |   | 69.50 |   | 39.85 |   | 71.22 |   | 60.67 |   | 65.79 |   | 59.54 |   |
| Toronto Stock Exchange—Low                                                    |       | 54.34             |       | 23.55 |   | 50.82 |   | 29.53 |   | 52.13 |   | 40.25 |   | 52.91 |   | 43.77 |   |
| New York Stock Exchange—High (US$)                                            |       | 59.94             |       | 29.18 |   | 61.68 |   | 32.32 |   | 63.65 |   | 51.73 |   | 58.37 |   | 51.69 |   |
| New York Stock Exchange—Low (US$)                                             |       | 46.98             |       | 19.44 |   | 45.63 |   | 23.28 |   | 46.70 |   | 31.95 |   | 46.90 |   | 36.80 |   |

 

----

*Notes:*

*(1)**      **Excludes results of Canadian conventional oil and gasproperties sold in the third quarter of 2005 in southeast Saskatchewan,northwest Saskatchewan, northeast British Columbia and the Alberta foothills.These results are shown as discontinued operations (see Note 14 to theConsolidated Financial Statements).*

*(2)**      **The fourth quarter of 2006 includes an impairment charge of$93 million, primarily relating to two natural gas properties in the Gulf ofMexico.*

*(3)**      **Chemicals operating profit includes a dilution gain of $193million in the third quarter of 2005 as the result of the Canexus initialpublic offering.*

*(4)**      **Includes the impact of changes in accounting policies asdescribed in Note 1(u) to the Consolidated Financial Statements.*

*(5)**      **In February 2007, the Board of Directors declared aquarterly dividend of $0.05 per common share, payable April 1, 2007, toshareholders of record on March 10, 2007.*

*(6)**      **At December 31, 2006, there were 1,454 registered holders ofcommon shares and 262,513,206 common shares outstanding.*

 

130

----

 
| Financial Statements and Supplementary Data | FAS 69 Reserves |
|---------------------------------------------|-----------------|

 

**OIL AND GAS PRODUCINGACTIVITIES AND SYNCRUDE OPERATIONS (UNAUDITED)**

 

The following oil and gas information isprovided 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 itproduces a crude oil product similar to our oil and gas activities even thoughthese operations are considered mining activities under SEC regulations.

 

**A.****           ****Reserve Quantity Information**

 

Our net proved reserves and changes in thosereserves for our conventional operations (excluding Syncrude) are disclosed below.The net proved reserves represent management’s best estimate of proved oil andnatural gas reserves after royalties. Reserve estimates for each property areprepared internally each year, and at least 80% of the reserves (includingSyncrude) have been assessed by independent qualified reserves consultants.

 

Estimates of crude oil and natural gas provedreserves are determined through analysis of geological and engineering data,and demonstrate reasonable certainty that they are recoverable from known reservoirsunder economic and operating conditions that existed at year end. See CriticalAccounting Estimates in Item 7 for a description of our reserves estimationprocess.

 
| **Conventional oil and bitumen are in  mmbbls and natural gas is in bcf** | ** ** | **Total**  | ** ** | **Yemen  (1)** | ** ** | **Canada** | ** ** | **United  States** | ** ** | **United  Kingdom** | ** **           | **Other  Countries (3)** | ** ** |
|---------------------------------------------------------------------------|------------|------------|------------|----------------|------------|------------|------------|--------------------|------------|---------------------|----------------------|-------------------------------|------------|
| ** **                                                                | **Oil**    | ** ** | **Gas**    | ** **     | **Oil**    | ** ** | **Oil**    | ** **         | **Gas**    | ** **          | **Bitumen (2)** | ** **                    | **Oil**    | ** ** | **Gas** | ** ** | **Oil** | ** ** | **Gas** | ** ** | **Oil** | ** ** |
| **Proved developed and Undeveloped Reserves** (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** | ** ** |
| ** **                                                                | ** ** | ** ** | ** ** | ** **     | ** ** | ** ** | ** ** | ** **         | ** ** | ** **          | ** **           | ** **                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Extensions and Discoveries                                                |       | 52         |       | 89             |       | 1          |       | 1                  |       | 54                  |                 | —                        |       | 2 |   | 26 |   | 23 |   | 9 |   | 25 |   |
| Purchases of Reserves in Place                                            |       | —     |       | 1              |       | —     |       | —             |       | 1                   |                 | —                        |       | — |   | — |   | — |   | — |   | — |   |
| Sales of Reserves in Place                                                |       | —     |       | —         |       | —     |       | —             |       | —              |                 | —                        |       | — |   | — |   | — |   | — |   | — |   |
| Revisions of Previous Estimates                                           |       | 231        |       | (16            | )          | (3         | )          | 3                  |       | (13                 | )                    | 219                           |       | (8 | ) | (12 | ) | 19 |   | 9 |   | 1 |   |
| Production                                                                |       | (38        | )          | (74            | )          | (19        | )          | (6                 | )          | (33                 | )                    | —                        |       | (5 | ) | (34 | ) | (6 | ) | (7 | ) | (2 | ) |
| **December 31, 2006**                                                     | ** ** | **549**    | ** ** | **532**        | ** ** | **38**     | ** ** | **48**             | ** ** | **314**             | ** **           | **219**                       | ** ** | **30** | ** ** | **195** | ** ** | **179** | ** ** | **23** | ** ** | **35** | ** ** |
| ** **                                                                | ** ** | ** ** | ** ** | ** **     | ** ** | ** ** | ** ** | ** **         | ** ** | ** **          | ** **           | ** **                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Proved developed Reserves**(5)                                          |       |       |       |           |       |       |       |               |       |                |                 |                          |       |   |   |   |   |   |   |   |   |   |   |
| 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** | ** ** |
| **December 31, 2006**                                                     | ** ** | **286**    | ** ** | **460**        | ** ** | **33**     | ** ** | **44**             | ** ** | **287**             | ** **           | **40**                        | ** ** | **28** | ** ** | **161** | ** ** | **131** | ** ** | **12** | ** ** | **10** | ** ** |

 

----

*Notes:*

*(1)**      **Under the terms of the Masila and the Block 51 productionsharing 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 ourpartners. Remaining production is profit oil, which is shared between thepartners and the Government of Yemen based on production rates, with thepartners’ share ranging from 20% to 33%. The Government’s share of profit oilrepresents its royalty interest and an amount for income taxes payable inYemen. Yemen’s net proved reserves have been determined using the economicinterest method and include our share of future cost recovery and profit oilafter the Government’s royalty interest, but before reserves relating to incometaxes payable. Under this method, reported reserves will increase as oil pricesdecrease (and vice versa) as the barrels necessary to achieve cost recoverychange with prevailing oil prices. Production includes volumes used for fuel.*

*(2)**      **Represents bitumen reserves from the insitu recovery ofCanadian oil sands, rather than upgraded synthetic crude oil reserves to besold.*

*(3)**      **Represents reserves in Nigeria and Colombia.*

*(4)  Proved oil and gas reserves are the estimatedquantities of natural gas, crude oil, condensate and natural gas liquids thatgeological and engineering data demonstrate with reasonable certainty can berecovered in future years from known reservoirs under existing economic andoperating conditions. Reserves are considered “proved” if they can be producedeconomically, as demonstrated by either actual production or conclusiveformation test.*

*(5)**      **Proved developed oil and gas reserves are expected to berecovered through existing wells with existing equipment and operating methods.*

 

131

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Our net proved reserves and changes in thosereserves for our Syncrude operations are disclosed below. Additionaldisclosures required by SEC Industry Guide 7 are on pages 22 and 23. The netproved reserves represent management’s best estimate of proved syntheticreserves after royalties.

 

Estimates of Syncrude’s synthetic crude oilreserves are based on detailed geological and engineering assessments of thebitumen volume in-place, the mining plan, historical extraction recovery andupgrading yield factors, installed plant operating capacity and operatingapproval limits. The in-place volume, depth and grade are established throughextensive and closely spaced core drilling. In accordance with the approvedmining plan, there are an estimated 1,780 million tons of economicallyextractable oil sands in the Base and North Mines, with an average bitumengrade of 10.6 weight percent. The Aurora North Mine contains an estimated 4,810million tons of economically extractable oil sands at an average bitumen gradeof 11.2 weight percent. Aurora South Lease 31 contains measured economicallyextractable oil sands of 4,309 million tons at an average bitumen grade of 10.8weight percent.

 
| ** **                     | ** ** | **Synthetic Crude Oil**                | ** ** |
|--------------------------------|------------|----------------------------------------|------------|
| **(millions of barrels)**      | ** ** | **Base Mine  and North  Mine (****1)** | ** ** | **Aurora (****2)** | ** ** | **Total** | ** ** |
| **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 |   |
| Production                     |       | (3                                     | )          | (3 | ) | (6 | ) |
| **December  31, 2005**         | ** ** | **47**                                 | ** ** | **217** | ** ** | **264** | ** ** |
| ** **                     | ** ** | ** **                             | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revision of Previous Estimates |       | 1                                      |       | 4 |   | 5 |   |
| Extensions and Discoveries     | ** ** | **—**                             |       | 11 |   | 11 |   |
| Production                     |       | (3                                     | )          | (3 | ) | (6 | ) |
| **December  31, 2006**         | ** ** | **45**                                 | ** ** | **229** | ** ** | **274** | ** ** |

 

----

*Notes:*

*(1)**      **Leases 17 and 22*

*(2)**      **Leases 10, 12, 31 and 34.*

 

132

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**B.    Capitalized Costs (excluding Syncrude operations)**

 
| **(Cdn$ millions)**    | ** ** | **Proved  Properties** | ** ** | **Unproved  Properties** | ** ** | **Accumulated  DD&A** | ** ** | **Capitalized**

**Costs** | ** ** |
|-----------------------------|------------|------------------------|------------|--------------------------|------------|---------------------------|------------|----------------------------|------------|
| **December  31, 2006**      |       |                   |       |                     |       |                      |       |                       |       |
| ** **                  |       |                   |       |                     |       |                      |       |                       |       |
| Yemen                       |       | 2,404                  |       | —                   |       | (2,128                    | )          | 276                        |       |
| Canada                      |       | 3,787                  |       | 227                      |       | (1,467                    | )          | 2,547                      |       |
| United States               |       | 2,768                  |       | 121                      |       | (1,445                    | )          | 1,444                      |       |
| United Kingdom              |       | 4,325                  |       | 385                      |       | (432                      | )          | 4,278                      |       |
| Other Countries             |       | 99                     |       | 150                      |       | (78                       | )          | 171                        |       |
| **Total Capitalized Costs** | ** ** | **13,383**             | ** ** | **883**                  | ** ** | **(5,550**                | **)**      | **8,716**                  | ** ** |
| **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**      |       |                   |       |                     |       |                      |       |                       |       |
| ** **                  |       |                   |       |                     |       |                      |       |                       |       |
| Yemen                       |       | 2,022                  |       | 16                       |       | (1,550                    | )          | 488                        |       |
| Canada                      |       | 3,732                  |       | 136                      |       | (2,025                    | )          | 1,843                      |       |
| 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**                  | ** ** |

 

**C.    Costs Incurred (excluding Syncrude operations)**

 
| ** **                        | ** ** | ** **             | ** ** | **Oil and Gas** | ** ** |
|-----------------------------------|------------|------------------------|------------|-----------------|------------|
| **(Cdn$ millions)**          | ** ** | **Total  Oil and Gas** | ** ** | **Yemen**       | ** ** | **Canada** | ** ** | **United  States** | ** ** | **United  Kingdom** | ** ** | **Other** | ** ** |
| **Year  Ended December 31, 2006** |       |                   |       |            |       |   |   |   |   |   |   |   |   |
| Property Acquisition Costs        |       |                   |       |            |       |   |   |   |   |   |   |   |   |
| Proved                            |       | 13                     |       | —          |       | 12 |   | — |   | 1 |   | — |   |
| Unproved                          |       | 125                    |       | —          |       | 105 |   | 19 |   | 1 |   | — |   |
| Exploration Costs                 |       | 514                    |       | 37              |       | 74 |   | 242 |   | 71 |   | 90 |   |
| Development Costs                 |       | 2,051                  |       | 145             |       | 884 |   | 399 |   | 595 |   | 28 |   |
| Asset Retirement Costs            |       | 69                     |       | 4               |       | 5 |   | 4 |   | 56 |   | — |   |
| **Total  Costs Incurred**         | ** ** | **2,772**              | ** ** | **186**         | ** ** | **1,080** | ** ** | **664** | ** ** | **724** | ** ** | **118** | ** ** |
| **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** | ** ** |

 

 

133

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**D.    Results of Operations for Producing Activities (excludingSyncrude operations)**

 
| ** **                                            | ** ** | ** **              | ** ** | **Oil and Gas** | ** ** |
|-------------------------------------------------------|------------|-------------------------|------------|-----------------|------------|
| **(Cdn$ millions)**                              | ** ** | **Total   Oil and Gas** | ** ** | **Yemen**       | ** ** | **Canada (****1)** | ** ** | **United   States** | ** ** | **United   Kingdom** | ** ** | **Other   Countries (****1)** | ** ** |
| **Year  Ended December 31, 2006**                     |       |                    |       |            |       |   |   |   |   |   |   |   |   |
| Net Sales                                             |       | 3,032                   |       | 1,328           |       | 459 |   | 629 |   | 477 |   | 139 |   |
| Production Costs                                      |       | 491                     |       | 151             |       | 146 |   | 106 |   | 80 |   | 8 |   |
| Exploration Expense                                   |       | 362                     |       | 4               |       | 26 |   | 214 |   | 46 |   | 72 |   |
| Depreciation, Depletion, Amortization and  Impairment |       | 1,011                   |       | 327             |       | 162 |   | 296 |   | 216 |   | 10 |   |
| Other Expenses (Income)                               |       | 71                      |       | 15              |       | 106 |   | (23 | ) | (71 | ) | 44 |   |
|                                                  |       | 1,097                   |       | 831             |       | 19 |   | 36 |   | 206 |   | 5 |   |
| Income Tax Provision                                  |       | 687                     |       | 289             |       | 6 |   | 13 |   | 378 |   | 1 |   |
| **Results  of Operations**                            | ** ** | **410**                 | ** ** | **542**         | ** ** | **13** | ** ** | **23** | ** ** | **(172** | **)** | **4** | ** ** |
| **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                                        |       | 106                     |       | 4               |       | 38 |   | 19 |   | — |   | 45 |   |
|                                                  |       | 1,037                   |       | 637             |       | 167 |   | 290 |   | 9 |   | (66 | ) |
| Income Tax Provision                                  |       | 406                     |       | 222             |       | 75 |   | 104 |   | 4 |   | 1 |   |
| **Results  of Operations**                            | ** ** | **631**                 | ** ** | **415**         | ** ** | **92** | ** ** | **186** | ** ** | **5** | ** ** | **(67** | **)** |

 

----

*Note:*

*(1)  2005 and 2004 include results of discontinuedoperations (see Note 14).*

 

134

----

 

**E.     Standardized Measure of Discounted Future Net Cash Flows andChanges Therein (excluding Syncrude operations)**

 

The following disclosure is based on estimatesof net proved reserves (excluding Syncrude) and the period during which theyare expected to be produced. Future cash inflows are computed by applyingyear-end prices to our after royalty share of estimated annual futureproduction from proved oil and gas reserves (excluding Syncrude operations).Future development and production costs to be incurred in producing and furtherdeveloping the proved reserves are based on year-end cost indicators. Futureincome taxes are computed by applying year-end statutory tax rates. These ratesreflect allowable deductions and tax credits, and are applied to the estimatedpre-tax future net cash flows.

 

Discounted future net cash flows are calculatedusing 10% mid-period discount factors. The calculations assume the continuationof existing economic, operating and contractual conditions. However, sucharbitrary assumptions have not proved to be the case in the past. Otherassumptions could give rise to substantially different results.

 

We believe this information does not in any wayreflect the current economic value of our oil and gas producing properties orthe present value of their estimated future cash flows as:

 

•      noeconomic value is attributed to probable and possible reserves;

 

•      useof a 10% discount rate is arbitrary; and

 

•      priceschange constantly from year-end levels.

 

135

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| **(Cdn$ millions)**                              | ** ** | **Total** | ** ** | **Yemen** | ** ** | **Canada** | ** ** | **United  States** | ** ** | **United   Kingdom** | ** ** | **Other   Countries** | ** ** |
|-------------------------------------------------------|------------|-----------|------------|-----------|------------|------------|------------|--------------------|------------|----------------------|------------|-----------------------|------------|
| **December  31, 2006**                                |       |      |       |      |       |       |       |               |       |                 |       |                  |       |
| Future Cash Inflows                                   |       | 32,247    |       | 2,330     |       | 12,678     |       | 3,151              |       | 11,437               |       | 2,651                 |       |
| Future Production Costs                               |       | 9,523     |       | 606       |       | 5,615      |       | 791                |       | 2,236                |       | 275                   |       |
| Future Development Costs                              |       | 3,190     |       | 115       |       | 1,156      |       | 332                |       | 891                  |       | 696                   |       |
| Future Dismantlement and Site Restoration  Costs, Net |       | 1,006     |       | 11        |       | 289        |       | 197                |       | 471                  |       | 38                    |       |
| Future Income Tax                                     |       | 5,204     |       | 489       |       | 753        |       | 450                |       | 3,308                |       | 204                   |       |
| Future Net Cash Flows                                 |       | 13,324    |       | 1,109     |       | 4,865      |       | 1,381              |       | 4,531                |       | 1,438                 |       |
| 10% Discount Factor                                   |       | 4,951     |       | 106       |       | 2,484      |       | 321                |       | 970                  |       | 1,070                 |       |
| **Standardized  Measure**                             | ** ** | **8,373** | ** ** | **1,003** | ** ** | **2,381**  | ** ** | **1,060**          | ** ** | **3,561**            | ** ** | **368**               | ** ** |
|                                                  |       |      |       |      |       |       |       |               |       |                 |       |                  |       |
| **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**               | ** ** |

 

**Changes in the StandardizedMeasure of Discounted Future Net Cash Flows**

 

The following are the principal sources ofchange in the standardized measure of discounted future net cash flows:

 
| **(Cdn$ millions)**                                                                  | ** ** | **2006**  | ** ** | **2005**  | ** ** | **2004**  | ** ** |
|-------------------------------------------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Beginning of  Year                                                                        |       | 8,042     |       | 6,290     |       | 5,517     |       |
| Sales and Transfers of Oil and Gas  Produced, Net of Production Costs                     |       | (2,291    | )          | (2,028    | )          | (1,674    | )          |
| Net Changes in Prices and Production Costs  Related to Future Production                  |       | (1,065    | )          | 3,302     |       | 142       |       |
| Extensions, Discoveries and Improved  Recovery, Less Related Costs (1)                    |       | 695       |       | 977       |       | (71       | )          |
| Changes in Estimated Future Development and  Dismantlement Costs                          |       | (692      | )          | (135      | )          | (122      | )          |
| Previous Estimated Future Development and  Dismantlement Costs Incurred During the Period |       | 1,048     |       | 638       |       | 604       |       |
| Revisions of Previous Quantity Estimates                                                  |       | 1,936     |       | 478       |       | (223      | )          |
| Accretion of Discount                                                                     |       | 1,117     |       | 799       |       | 692       |       |
| Purchases of Reserves in Place                                                            |       | 2         |       | 15        |       | 1,764     |       |
| Sales of Reserves in Place                                                                |       | (2        | )          | (882      | )          | (20       | )          |
| Net Change in Income Taxes                                                                |       | (417      | )          | (1,412    | )          | (319      | )          |
| **End of  Year**                                                                          | ** ** | **8,373** | ** ** | **8,042** | ** ** | **6,290** | ** ** |

 

----

*Note:*

*(1)  2004 includes approximately $230 million ofnegative discounted future net cash flows relating to bitumen reserves based onyear-end assumptions.*

 

136

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| Financial Statements and Supplementary Data | Controls and Reserves |
|---------------------------------------------|-----------------------|

 

**ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTSON ACCOUNTING AND FINANCIAL DISCLOSURE**

 

There were no disagreements with accountants onaccounting and financial disclosure.

 

**ITEM 9A. CONTROLS AND PROCEDURES**

 

**EVALUATION OF DISCLOSURECONTROLS AND PROCEDURES**

 

Our Chief Executive Officer and Chief FinancialOfficer have evaluated the effectiveness of our disclosure controls andprocedures (as defined in Exchange Act Rules 13a-15(e) and 15-d-15(e)) as ofthe end of the period covered by this report. They concluded that, as of theend of the period covered by this report, our disclosure controls andprocedures were adequate and effective in ensuring that material informationrelating to the Company and its consolidated subsidiaries would be made knownto them by others within those entities, particularly during the period inwhich this report was being prepared. Management recognizes that any controlsand procedures, no matter how well designed and operated, can provide onlyreasonable assurance of achieving the desired control objectives, and inreaching a reasonable level of assurance, management necessarily is required toapply its judgement in evaluating the cost-benefit relationship of possiblecontrols and procedures.

 

**MANAGEMENT’S REPORT ON INTERNALCONTROL OVER FINANCIAL REPORTING**

 

Our management is responsible for establishingand maintaining adequate internal control over financial reporting (as definedin Exchange Act Rules 13a-15(f)). Under the supervision and with theparticipation of our management, including our principal executive officer(CEO) and principal financial officer (CFO), we conducted an evaluation of theeffectiveness of our internal control over financial reporting based on theInternal Control-Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission. Based on our evaluation, we concludedthat our internal control over financial reporting is effective as of December31, 2006. We have documented this assessment and made this assessment availableto our independent registered Chartered Accountants. We recognize that allinternal control systems, no matter how well designed, have inherentlimitations. Therefore, even those systems determined to be effective canprovide only reasonable assurance with respect to financial statementpreparation and presentation.

 

Our management’s assessment of the effectivenessof our internal control over financial reporting as of December 31, 2006, hasbeen audited by Deloitte & Touche LLP, independent registered CharteredAccountants, as stated in their report which is on page 138 of this Form 10-K. Deloitte& Touche LLP also audited our Consolidated Financial Statements as statedin their report which is on page 86 of this Form 10-K.

 

**CHANGES IN INTERNAL CONTROLS**

 

We have continually had in place systemsrelative to internal control over financial reporting. In 2006, we implementedour existing Systems, Applications, and Products in Data Processing (SAP) intoour UK operations and, in keeping pace with growth in our US operations, weimplemented additional inventory tracking and procure to pay process controls.The conversion of data and the implementation and operation of SAP has beencontinually monitored and reviewed.

 

We have evaluated these changes and confirm thatthere have been no other changes in our internal control over financialreporting during the fourth quarter of 2006 that have materially affected, orare reasonably likely to materially affect, our internal control over financialreporting. Based on these evaluations, there were no material weaknesses inthese internal controls requiring corrective action. As a result, no suchcorrective action was taken.

 

137

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| Item 8 | Financial Statements and Supplementary Data | Auditors’ Report on Internal  Controls |
|--------|---------------------------------------------|---------------------------------------------|

 

**REPORT OF INDEPENDENTREGISTERED CHARTERED ACCOUNTANTS**

Tothe Board of Directors and Shareholders of Nexen Inc.:

 

We have audited management’s assessment,included in the accompanying Management’s Report on Internal Control overFinancial Reporting, that Nexen Inc. and subsidiaries (the “Company”) maintainedeffective internal control over financial reporting as of December 31, 2006,based on criteria established in Internal Control—Integrated Framework issuedby the Committee of Sponsoring Organizations of the Treadway Commission. TheCompany’s management is responsible for maintaining effective internal controlover financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting. Our responsibility is to express anopinion on management’s assessment and an opinion on the effectiveness of theCompany’s internal control over financial reporting based on our audit.

 

We conducted our audit in accordance with thestandards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonableassurance about whether effective internal control over financial reporting wasmaintained in all material respects. Our audit included obtaining anunderstanding of internal control over financial reporting, evaluatingmanagement’s assessment, testing and evaluating the design and operatingeffectiveness of internal control, and performing such other procedures as weconsidered necessary in the circumstances. We believe that our audit provides areasonable basis for our opinions.

 

A company’s internal control over financialreporting is a process designed by, or under the supervision of, the company’sprincipal executive and principal financial officers, or persons performingsimilar functions, and effected by the company’s board of directors,management, and other personnel to provide reasonable assurance regarding thereliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accountingprinciples. A company’s internal control over financial reporting includesthose policies and procedures that (1) pertain to the maintenance of recordsthat, in reasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (2) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, andthat receipts and expenditures of the company are being made only in accordancewith authorizations of management and directors of the company; and (3) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’s assets that could have amaterial effect on the financial statements.

 

Because of the inherent limitations of internalcontrol over financial reporting, including the possibility of collusion orimproper management override of controls, material misstatements due to erroror fraud may not be prevented or detected on a timely basis. Also, projectionsof any evaluation of the effectiveness of the internal control over financialreporting to future periods are subject to the risk that the controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

 

In our opinion, management’s assessment that theCompany maintained effective internal control over financial reporting as ofDecember 31, 2006, is fairly stated, in all material respects, based on thecriteria established in Internal Control—Integrated Framework issued by theCommittee of Sponsoring Organizations of the Treadway Commission. Also, in ouropinion, the Company maintained, in all material respects, effective internalcontrol over financial reporting as of December 31, 2006, based on criteriaestablished in Internal Control—Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission.

 

We have also audited, in accordance withCanadian generally accepted auditing standards and the standards of the PublicCompany Accounting Oversight Board (United States), the consolidated financialstatements of the Company as of and for the year ended December 31, 2006, andour report dated February 9, 2007, expressed an unqualified opinion on thosefinancial statements and included a separate report on Canada-United States ofAmerica reporting differences.

 
| Calgary,  Canada  | (signed)  “Deloitte & Touche LLP” |
|-------------------|-------------------------------------------------|
| February  9, 2007 | Independent  Registered Chartered Accountants   |

 

 

138

----

 

 
|   | Corporate Governance                                                                      |
|--------|-------------------------------------------------------------------------------------------|
|   |
|   |                                                                                      |
|   | Governance is a two way street. Our board  and                                            |
|   |     management are  committed to transparent,                         |
|   |     meaningful  disclosure and to feedback from                       |
|   |         stakeholders  for continuous improvement. |
|        |                                                                                           |  |

** **

 

----

 

**PARTS III AND IV**

 

**ITEMS 10 TO 15.**

 
| Directors                                                                  |   |   |
|----------------------------------------------------------------------------|--------|--------|
| Directors  Compensation                                                    |   |   |
| Compensation Committee Report                                              |   |   |
| Compensation Committee Interlocks and Insider Participation                |   |   |
| Compensation  Disclosure                                                   |   |   |
| Executive Officers                                                         |   |   |
| Summary Compensation Table                                                 |   |   |
| Change in Control Agreements                                               |   |   |
| Share Performance Graph                                                    |   |   |
| Corporate Governance                                                       |   |   |
| Governance Committee Report                                                |   |   |
| Security Ownership of Certain Beneficial  Owners and Management            |   |   |
| Certain Relationships and Related  Transactions, and Director Independence |   |   |
| Principal Accounting Fees and Services                                     |   |   |
| Exhibits, Financial Statement Schedules                                    |   |   |
| Certifications                                                             |   |   |

 

 

----

 
| Corporate Governance | Directors |
|----------------------|-----------|

 

**PART III**

**ITEMS 10AND 11. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATEGOVERNANCE, AND EXECUTIVE COMPENSATION**

 

**Directors**

** **

According to our Articles, Nexen must have between three and 15directors. On July 5 2006, the board determined that, until changed, there willbe 12 directors.

 

Our By-Laws provide that directors will be elected at the annualgeneral meeting of shareowners (AGM) each year and will hold office until theirsuccessors are elected. All of our current directors were elected at the lastAGM with the exception of A. Anne McLellan PC, who was appointed on July 5,2006.

 

This table shows our directors’ principal occupations or employmentduring the past five years and any other directorships they held in publiccompanies as at February 15, 2007. The following directors are managementnominees for election to the board.

 
| **Name****(Age)**                       | ** ** | **Principal  Occupation**                                                                                                                                                                                                                                                                                                                          | ** ** | **Other  Directorships**                                                                     | ** ** | **Nexen    Director Since** |
|-----------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------|------------|-----------------------------|
| Charles  W. Fischer (56)                |       | President  and Chief Executive Officer (CEO) of Nexen.                                                                                                                                                                                                                                                                                             |       |                                                                                         |       | 2000                        |
| Dennis  G. Flanagan  (1), (2), (3) (67) |       | Retired  oil executive.                                                                                                                                                                                                                                                                                                                            |       | Canexus  Income Fund (Chair)  NAL Oil & Gas Trust                                        |       | 2000                        |
| David  A.  Hentschel (4)(73)            |       | Retired  oil executive.  Formerly: Oil and gas consultant.                                                                                                                                                                                                                                                                                         |       | Cimarex  Energy Co.                                                                          |       | 1985                        |
| S.  Barry Jackson (1)(54)               |       | Retired  oil executive.  Formerly: Chair of Resolute Energy Inc. and Chair of Deer Creek Energy  Limited.                                                                                                                                                                                                                                          |       | Cordero  Energy Inc.  TransCanada Corporation (Chair)  TransCanada PipeLines Limited (Chair) |       | 2001                        |
| Kevin  J.  Jenkins (1), (2)(50)         |       | Managing  Director of TriWest Capital Partners  Formerly: President and CEO of The Westaim Corporation.                                                                                                                                                                                                                                            |       |                                                                                         |       | 1996                        |
| A. Anne McLellan,  P.C. (1)(56)         |       | Counsel  at Bennett Jones LLP, Barristers and Solicitors and Distinguished Scholar in  Residence at the University of Alberta in the Institute for United States  Policy Studies  Formerly: Liberal Member of Parliament for Edmonton Centre, Deputy Prime  Minister, Minister of Public Safety and Emergency Preparedness and Minister  of Health |       | Agrium  Inc.  Cameco Corporation                                                             |       | 2006                        |
| Eric  P. Newell, O.C. (62)              |       | Retired  Chair and CEO of Syncrude Canada Ltd.                                                                                                                                                                                                                                                                                                     |       | Canfor  Corporation                                                                          |       | 2004                        |
| Thomas  C.  O’Neill (1), (2)(61)   |       | Retired  Chair of PwC Consulting.  Formerly: CEO of PwC Consulting. Prior to that,   COO of PricewaterhouseCoopers LLP, Global.                                                                                                                                                                                                                    |       | Adecco  S.A.  BCE Inc.  Loblaw Companies Limited                                             |       | 2002                        |
| Francis  M. Saville,  Q.C. (1)(68)      |       | Chair  of Nexen.  Counsel to Fraser Milner Casgrain LLP, Barristers and Solicitors.  Formerly: Senior Partner and Vice Chair of Fraser   Milner Casgrain LLP, Barristers and Solicitors.                                                                                                                                                           |       |                                                                                         |       | 1994                        |
| Richard  M. Thomson, O.C. (1), (2)(73)  |       | Retired  banking executive.                                                                                                                                                                                                                                                                                                                        |       | The  Thomson Corporation                                                                     |       | 1997                        |
| John  M. Willson (1) (67)               |       | Retired  mining executive.                                                                                                                                                                                                                                                                                                                         |       | Aber  Diamond Corporation  Finning International Inc.  Pan American Silver Corporation       |       | 1996                        |
| Victor  J.  Zaleschuk (5) (63)          |       | Retired  oil executive.                                                                                                                                                                                                                                                                                                                            |       | Agrium  Inc.  Cameco Corporation (Chair)                                                     |       | 1997                        |

 

----

*Notes:*

*(1)** **All members of the Audit and Conduct Review (Audit),Corporate Governance and Nominating (Governance) and Compensation and HumanResources (Compensation) Committees are independent. All members of the AuditCommittee are independent under additional regulations for audit committeemembers.*

*(2)** **Financial Experts on Nexen’s Audit Committee.*

*(3)** **Mr. Flanagan was a director of Elek-Tek Inc., a US publiccomputer retailing company, that was subject to bankruptcy proceedings in 1998.*

*(4)** **Mr. Hentschel was Chair and CEO of Occidental Oil and GasCorporation from 1997 to 1999 and President and CEO of Nexen from 1995 to 1997.*

*(5)** **Mr. Zaleschuk was President and CEO of Nexen from 1997 to2001.*

 

141

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| Items 10 to 15 | Corporate Governance | Board Committees |
|----------------|----------------------|------------------|

 

**Independence and Board Committees**

 

The board affirmed director independence in reference to ourcategorical standards, which are available at www.nexeninc.com, in place since2003 and most recently confirmed on February 15, 2007. Our categoricalstandards meet or exceed the requirements set out in SEC rules and regulations,the *Sarbanes-Oxley Act of 2002*(Sarbanes-Oxley), the NYSE rules, *NationalPolicy 58-201 — Corporate Governance Guidelines*, *Multilateral Instrument 52-110 — Audit Committees,*and applicable provisions of *NationalInstrument 51-101 — Standards of Disclosure for Oil and Gas Activities*.

 

Mr. Fischer is not independent as he is President and CEO.

 

Mr. Saville, a director, was a senior partner of Fraser Milner CasgrainLLP (FMC), Barristers and Solicitors, Calgary, Alberta until the end of January2004. Since February 1, 2004, he has been counsel with the firm. FMC providedlegal services to us during each of the last five years. Mr. Saville neithersolicits nor participates in those services and does not receive any portion ofthe fees we pay to FMC. He is an independent director pursuant to ourcategorical standards.

 

Ms. McLellan, a director, has been counsel with Bennett Jones LLP (BJ),Barristers and Solicitors, Edmonton, Alberta, since June 27, 2006. BJ providedlegal services to us during each of the last five years. Ms. McLellan neithersolicits nor participates in those services and does not receive any portion ofthe fees we pay to BJ. She is an independent director pursuant to ourcategorical standards.

 
| ** **                                      | ** ** | **Committees  (Number of Members)** | ** ** |
|-------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                      | ** ** | **Audit****(1), (2)****(6)**        | ** ** | **Compensation  (****1), (3)****(7)** | ** ** | **Governance  (****1)****(7)** | ** ** | **Finance (7)** | ** ** | **Reserves  (4)********(7)** | ** ** | **SESR (7)** | ** ** |
| **Independent Outside Directors**               |       |                                |       |   |   |   |   |   |   |   |   |   |   |
| Dennis G. Flanagan (5)                          |       | ü                              |       |   |   | ü |   | ü |   | ü |   |   |   |
| David A. Hentschel                              |       |                                |       |   |   |   |   | ü |   | ü |   | ü |   |
| S. Barry Jackson                                |       | ü                              |       | ü |   |   |   |   |   | ü |   | Chair |   |
| Kevin J. Jenkins (5)                            |       | ü                              |       | Chair |   | ü |   |   |   |   |   | ü |   |
| A. Anne McLellan, P.C.                          |       |                                |       | ü |   | ü |   | ü |   |   |   | ü |   |
| Eric P. Newell, O.C.                            |       |                                |       |   |   |   |   | ü |   | ü |   | ü |   |
| Thomas C. O’Neill (5), (6)                 |       | Chair                               |       | ü |   | ü |   |   |   | ü |   |   |   |
| Francis M. Saville, Q.C.                        |       |                                |       | ü |   | ü |   | ü |   |   |   | ü |   |
| Richard M. Thomson, O.C. (5)                    |       | ü                              |       | ü |   | Chair |   | ü |   |   |   |   |   |
| John M. Willson                                 |       | ü                              |       | ü |   | ü |   |   |   | Chair |   |   |   |
| Victor J. Zaleschuk                             |       |                                |       |   |   |   |   | Chair |   | ü |   | ü |   |
| **Management Director — Not  Independent** | ** ** | ** **                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Charles W. Fischer                              |       |                                |       |   |   |   |   |   |   |   |   |   |   |

 

----

*Notes:*

*(1)** **All members of the Audit and Conduct Review (Audit),Corporate Governance and Nominating (Governance) and Compensation and HumanResources (Compensation) Committees are independent. All members of the AuditCommittee are independent under additional regulations for audit committeemembers.*

*(2)** **Experience of the members of the Audit Committee thatindicates an understanding of the accounting principles we use to prepare ourfinancial statements is shown in their biographies on page 143.*

*(3)** **Composition of the Compensation Committee has changed sinceJanuary 1, 2006. See page 146 for details.*

*(4)** **A majority of the Reserves Review (Reserves) Committee areindependent.*

*(5)** **Audit committee financial expert under US regulatoryrequirements.*

*(6)** **The board has considered the circumstances of Mr. O’Neill’sservice on four public company audit committees including Nexen’s. Mr. O’Neillis retired and holds neither a full nor a part-time employee position. His onlycommitments are to the boards and committees on which he serves. Mr. O’Neillhas been a chartered accountant for more than 30 years, having joined the auditfirm of Price Waterhouse (now part of PricewaterhouseCoopers LLP) in 1967.Accordingly, the board has determined that service as an audit committee memberon three other public companies does not impair Mr. O’Neill’s ability to serveon our Audit Committee.*

 

142

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**AuditCommittee Financial Expert Experience**

 
| **Name**     | ** ** | **Experience**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
|--------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Flanagan     |       | Dennis Flanagan, 67, is a retired oil  executive. He worked in the oil and gas industry for more than 40 years with  Ranger Oil Limited (Ranger) and ELAN Energy Inc. (ELAN), most recently as  Executive Chair of ELAN until it was bought by Ranger in 1997. He was  involved in all phases of exploration and development in Canada, the US and  the UK sector of the North Sea.  Mr. Flanagan completed the Registered Industrial and Cost Accountant program,  the predecessor to the Certified Management Accountant program, in 1967. He  worked in various accounting and management positions at Ranger, including  the position of chief financial officer.  Dennis is the Chair of Canexus Income Fund (Canexus), an affiliate controlled  by Nexen, and a director of NAL Oil & Gas Trust. He is also founding  Chair of STARS (Shock Trauma Air Rescue) Foundation.                                                                                                                                                                         |
|         |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| Jenkins      |       | Kevin Jenkins, 50, is Managing Director  of TriWest Capital Partners, an independent private equity firm. He was  President, CEO and a director of The Westaim Corporation from 1996 to 2003,  with businesses including technology investments, production of coin blanks,  aerospace coatings and surface engineered products. From 1985 to 1996 he held  senior executive positions with Canadian Airlines International Ltd.  (Canadian). He was elected to serve on Canadian’s board of directors in 1987,  appointed President in 1991 and appointed President and CEO in 1994.  Mr. Jenkins has a Bachelors Degree in Law from the University of Alberta and  a Masters of Business Administration from Harvard Business School. He has  worked in management positions with increasing level of responsibility  including assistant treasurer, vice president finance, executive vice  president and chief financial officer, and president and CEO.  Kevin is Chair of Young Life of Canada and a member of the board of World  Vision Canada. |
|         |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| O’Neill |       | Tom O’Neill, 61, is the retired Chair  of PwC Consulting. He was formerly CEO of PwC Consulting, COO of  PricewaterhouseCoopers LLP, Global, CEO of PricewaterhouseCoopers LLP, Canada  and Chair and CEO of Price Waterhouse Canada. He worked in Brussels in 1975  to broaden his international experience and from 1975 to 1985 was client  service partner for numerous multi nationals, specializing in dual Canadian  and US listed companies.  Mr. O’Neill has a Bachelor of Commerce Degree from Queen’s University. He  received his Chartered Accountant designation in 1970 and was made a Fellow  (FCA) of the Institute of Chartered Accountants of Ontario in 1988. He also  has an Honourary Doctorate of Law from Queen’s University.  Tom is a director of BCE Inc., Loblaw Companies Limited, Adecco S.A., and  Ontario Teachers’ Pension Plan Board. He is also Vice Chair of the Board of  Governors of Queen’s University and a director of St. Michael’s Hospital.                                  |
|         |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| Thomson      |       | Dick Thomson, 73, is a retired banking  executive. He was with the Toronto Dominion Bank, one of Canada’s largest  banks, since 1957, as President from 1972 to 1978 and as Chair from 1978  until his retirement in 1998.  Mr. Thomson holds a Masters of Business Administration from Harvard Business  School and a Bachelor of Arts and Science in Engineering from the University  of Toronto. He is an Officer of the Order of Canada.  Dick is a director of The Thomson Corporation. He is also a member of the  board of the Multiple Sclerosis Scientific Research Foundation.                                                                                                                                                                                                                                                                                                                                                                                                                                                                |

 

**Directors’ and Officers’Liability Insurance**

 

We maintain a directors’and officers’ liability insurance policy. The policy provides coverage forcosts incurred to defend and settle claims against directors and officers ofNexen to an annual limit of US$130 million with a US$12.5 million deductibleper occurrence. The cost of coverage for 2006 was approximately US$0.9 million.Directors and officers do not pay any portion of the premiums and no indemnityclaims were made or became payable in 2006.

 

**Directors’ and Officers’Fiduciary Insurance**

 

We also maintain afiduciary liability insurance policy. The policy provides coverage for costsincurred to defend and settle claims against Nexen, our directors, officers andemployees for breach of fiduciary duty in connection with company sponsoredplans, such as pension and savings plans. This policy has an annual limit ofUS$25 million with a US$2.5 million deductible for an indemnifiable occurrenceand no deductible for a non-indemnifiable occurrence. The cost of coverage for2006 was approximately US$30,000. Directors and officers do not pay any portionof the premiums and no claims were made or became payable in 2006.

 

 

143

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**Loansto Directors**

 

As set out in thecorporate governance policy, we do not make loans to our directors. There areno loans outstanding from Nexen to any of our directors.

 

**DIRECTOR COMPENSATION**

 

Director compensationincludes annual retainers, meeting fees and equity-based incentive compensationin the form of deferred share units (DSUs). The compensation is intended toprovide an appropriate level of remuneration considering the responsibilities,time requirements and accountability of their roles. All elements of directorcompensation are reviewed annually for competitiveness against a peer group ofoil and gas companies by management, and then the board.

 

In 2003, the boardadopted a policy stating that non-executive directors would no longer begranted stock options. We do not provide our directors with any form ofnon-equity incentive or pension compensation. 

 

There are currently twodirectors, Mr. Hentschel and Mr. Zaleschuk, both former CEO’s of Nexen, who areretirees in the Nexen pension plan. The pension benefit provided to thesedirectors is for previous service as employees. 

 

A DSU plan was approvedfor the non-executive directors in 2001, as an appropriate form of equity-basedcompensation intended to provide a competitive long-term incentive aligned withshareowner interests. 

 

In December 2006, alldirector compensation was reviewed and confirmed at the then-current levels.

** **

**DirectorSummary Compensation Table**

 
| **Name**     | ** ** | **Total  Fees Earned (****1)** | ** **    | **DSU   Awards (****2)** | ** ** | **All Other   Compensation (****3)** | ** ** | **Total   Compensation** | ** **  |
|--------------|------------|--------------------------------|---------------|--------------------------|------------|--------------------------------------|------------|--------------------------|-------------|
| Fischer (4)  |       | *—*                       |          | *—*                 |       | *—*                             |       | *—*                 |        |
| Flanagan (5) |       | 116,667                        |          | 132,720                  |       | 115,331                              |       | 364,718                  |        |
| Hentschel    |       | 101,633                        |          | 132,720                  |       | 2,726                                |       | 237,079                  |        |
| Jackson      |       | 116,600                        |          | 132,720                  |       | 2,953                                |       | 252,273                  |        |
| Jenkins      |       | 120,200                        |          | 132,720                  |       | 4,411                                |       | 257,331                  |        |
| McLellan     |       | 62,850                         |          | 132,720                  |       | 259                                  |       | 195,829                  |        |
| Newell       |       | 91,400                         |          | 132,720                  |       | 4,291                                |       | 228,411                  |        |
| O’Neill |       | 132,800                        |          | 132,720                  |       | 4,018                                |       | 269,538                  |        |
| Saville      |       | 263,100                        |          | 202,240                  |       | 3,116                                |       | 468,456                  |        |
| Thomson      |       | 120,200                        |          | 132,720                  |       | 5,946                                |       | 258,866                  |        |
| Willson      |       | 116,600                        |          | 132,720                  |       | 4,308                                |       | 253,628                  |        |
| Zaleschuk    |       | 103,367                        |          | 132,720                  |       | 2,819                                |       | 238,906                  |        |
| **Total**    | ** ** | **$**                          | **1,345,417** | ** **               | **$**      | **1,529,440**                        | ** ** | **$**                    | **150,178** | ** ** | **$** | **3,025,035** | ** ** |
|              |            |                                |               |                          |            |                                      |            |                          |             |  |  |  |  |

 

----

*Notes:*

*(1)** **Includes all retainers and meetings fees, including feespaid in the form of DSUs.*

*(2)** **The value of DSUs granted on December 4, 2006, based on theclosing market price of Nexen common shares on the TSX on December 1, 2006 of$63.20.*

*(3)** **The total value of perquisites provided to each director isless than both $50,000 or 10% of total fees, and is not included in thiscolumn. Amounts reflect life insurance premiums paid by Nexen, reinvesteddividends earned in 2006 valued at the closing market price of Nexen commonshares on the TSX on the payment dates, and Canexus fees as set out in note 5.*

*(4)** **As an executive officer of Nexen, Mr. Fischer is not paiddirector fees.*

*(5)** **Mr. Flanagan is the Board Chair of Canexus, and was paidfees of $59,000 in 2006, received deferred trust units of**Canexus valued at $48,770 and distributions on histrust units of $4,806. This amount is included in “All Other Compensation”.*

 

144

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| Corporate Governance | Compensation Committee Report |
|----------------------|-------------------------------|

** **

**Director Fees**

 

Annual board andcommittee retainers are paid quarterly, in advance, and are pro-rated forpartial service, if appropriate. Nexen also reimburses directors forout-of-pocket travel expenses. Directors are paid meeting fees for attendingmeetings either in person or by telephone conference call. From January 1,2006, non-executive directors are paid:

 
| Annual Board Chair Retainer (1)                         |   | $      | 150,000 |   |
|---------------------------------------------------------|--------|--------|---------|--------|
| Annual Board Retainer                                   |   | 28,100 |    |
| Annual Committee Retainer (per committee)               |   | 9,100  |    |
| Annual Committee Additional Chair Retainer              |   | 5,300  |    |
| Annual Audit Committee Additional Chair Retainer (2)    |   | 14,400 |    |
| Board and Committee Meeting Fees (per meeting attended) |   | 1,800  |    |

 

----

*Notes:*

*(1)** **The total annual retainer paid to the Board Chair is$178,100 and includes the Annual Board Chair Retainer and the Annual BoardRetainer.*

*(2)** **The total annual retainer paid to the Chair of the AuditCommittee for his service on that committee is $28,800 and includes the AnnualCommittee Retainer, the Annual Committee Additional Chair Retainer and theAnnual Audit Committee Additional Chair Retainer.*

**2006 Retainers and Fees**

 
| ** **   | ** ** | **Annual  Board   Retainer** | ** **  | **Annual   Committee Retainers** | ** ** | **Annual   Committee   Chair   Retainer** | ** ** | **Board  Meeting  Fees** | ** ** | **Committee  Meeting  Fees** | ** ** | **Total Fees  Earned** | ** ** | **Total Fees Credited in  DSUs** | ** **  | **Total Fees Earned in Cash** | ** ** |
|--------------|------------|------------------------------|-------------|----------------------------------|------------|-------------------------------------------|------------|--------------------------|------------|------------------------------|------------|------------------------|------------|----------------------------------|-------------|-------------------------------|------------|
| Fischer (1)  |       | *—*                     |        | *—*                         |       | *—*                                  |       | *—*                 |       | *—*                     |       | *—*               |       | *—*                         |        | *—*                      |       |
| Flanagan     |       | 28,100                       |        | 36,400                           |       | 1,767                                     |       | 14,400                   |       | 36,000                       |       | 116,667                |       | *—*                         |        | 116,667                       |       |
| Hentschel    |       | 28,100                       |        | 30,333                           |       | *—*                                  |       | 14,400                   |       | 28,800                       |       | 101,633                |       | *—*                         |        | 101,633                       |       |
| Jackson      |       | 28,100                       |        | 36,400                           |       | 5,300                                     |       | 14,400                   |       | 32,400                       |       | 116,600                |       | 116,600                          |        | *—*                      |       |
| Jenkins      |       | 28,100                       |        | 36,400                           |       | 5,300                                     |       | 14,400                   |       | 36,000                       |       | 120,200                |       | *—*                         |        | 120,200                       |       |
| McLellan (2) |       | 14,050                       |        | 18,200                           |       | *—*                                  |       | 9,000                    |       | 21,600                       |       | 62,850                 |       | 62,850                           |        | *—*                      |       |
| Newell       |       | 28,100                       |        | 27,300                           |       | *—*                                  |       | 12,600                   |       | 23,400                       |       | 91,400                 |       | 91,400                           |        | *—*                      |       |
| O’Neill |       | 28,100                       |        | 36,400                           |       | 19,700                                    |       | 12,600                   |       | 36,000                       |       | 132,800                |       | *—*                         |        | 132,800                       |       |
| Saville      |       | 178,100                      |        | 36,400                           |       | *—*                                  |       | 14,400                   |       | 34,200                       |       | 263,100                |       | *—*                         |        | 263,100                       |       |
| Thomson      |       | 28,100                       |        | 36,400                           |       | 5,300                                     |       | 14,400                   |       | 36,000                       |       | 120,200                |       | 120,200                          |        | *—*                      |       |
| Willson      |       | 28,100                       |        | 36,400                           |       | 5,300                                     |       | 14,400                   |       | 32,400                       |       | 116,600                |       | *—*                         |        | 116,600                       |       |
| Zaleschuk    |       | 28,100                       |        | 30,334                           |       | 3,533                                     |       | 14,400                   |       | 27,000                       |       | 103,367                |       | 28,100                           |        | 75,267                        |       |
| **Total**    | ** ** | **$**                        | **445,050** | ** **                       | **$**      | **360,967**                               | ** ** | **$**                    | **46,200** | ** **                   | **$**      | **149,400**            | ** ** | **$**                            | **343,800** | ** **                    | **$**      | **1,345,417** | ** ** | **$** | **419,150** | ** ** | **$** | **926,267** | ** ** |
|              |            |                              |             |                                  |            |                                           |            |                          |            |                              |            |                        |            |                                  |             |                               |            |  |  |  |  |  |  |  |  |

 

----

*Notes:*

*(1)** **As an executive officer of Nexen, Mr. Fischer is not paiddirector fees.*

*(2)** **Ms. McLellan is taking all fees in Deferred Share Units(DSUs) until her share ownership requirement is met.*

**Share OwnershipGuideline**

 

Theboard believes it is important that directors demonstrate their commitment toNexen’s growth through share ownership. The board-approved guideline sets outthat directors are expected to own or control at least 6,000 shares (DSUs counttowards share ownership) to be accumulated over three years. Specificarrangements may be made when a qualified candidate might be prevented fromserving by this guideline. The guideline is reviewed from time to time.Ownership can be achieved by purchasing common shares, participating in ourdividend reinvestment plan or directing retainer fees into DSUs.

 

All directors, exceptMs. McLellan, meet the guideline. Ms. McLellan has until July 5, 2009 to meetthis guideline. She is taking 100% of her fees in DSUs until she meets therequirement and currently has 4,341 DSUs that count toward her requirement.

 

145

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**Deferred ShareUnits**

** **

In 2001, a DSU plan was approved as analternative form of compensation for non-executive directors. Under the plan,eligible directors may elect annually to receive all or part of their fees inDSUs, rather than in cash. A DSU is a bookkeeping entry that tracks the valueof one Nexen common share. When cash dividends are paid on Nexen common shares,eligible directors are credited with additional DSUs. The number of DSUs iscalculated by dividing the total amount of the dividends that would have beenpaid if the DSUs in the director’s account were common shares by the fair marketvalue of a common share on the payment date. DSUs accumulate over a director’sterm of service and are not paid out until the director leaves the board,providing them with an ongoing stake in Nexen during the term of service. Whenthe director leaves the board, payments may be made in cash or in Nexen commonshares purchased on the open market, at Nexen’s option. 

 

Grants of DSUs have been used since 2003 asequity-based compensation in place of stock option grants, which werediscontinued for non-executive directors in 2003.

 

**Deferred ShareUnits Granted in 2006**

** **
| ** **                    | ** ** | **Grant Date** | ** ** | **DSUs** | ** ** | **Base Price (****1)** | ** ** | **Value of DSUs (****2)** | ** ** |
|-------------------------------|------------|----------------|------------|----------|------------|------------------------|------------|---------------------------|------------|
|                          |       |           |       | **(#)**  |       | **($)**                |       | **($)**                   |       |
| Board Chair                   |       | Dec 4, 2006    |       | 3,200    |       | 63.20                  |       | 202,240                   |       |
| Other Non-Executive Directors |       | Dec 4, 2006    |       | 2,100    |       | 63.20                  |       | 132,720                   |       |

 

----

*Notes:*

*(1)** **Theclosing market price of Nexen common shares on the TSX on December 1, 2006.*

*(2)** **Thenumber of DSUs times the base price.*

** **

**TOPs Exercisedor Exchanged and Awards Vested during 2006**

 

All exercise or exchange activity in 2006occurred within five months of the expiry date of the options. There are novesting provisions and, accordingly, no value realized on vesting under the DSUplan. 

 
| ** ** | ** ** | **TOPs Awards**             | ** ** | **Stock Awards**           | ** ** |
|------------|------------|-----------------------------|------------|----------------------------|------------|
| **Name**   | ** ** | **Exercised or  Exchanged** | ** ** | **Value Realized (****1)** | ** ** | **Shares Acquired  on Vesting** | ** ** | **Value Realized** | ** ** |
| ** ** | ** ** | **(#)**                     | ** ** | **($)**                    | ** ** | **(#)** | ** ** | **($)** | ** ** |
| Hentschel  |       | 13,000                      |       | 579,215                    |       | *—* |   | *—* |   |
| Jackson    |       | 13,000                      |       | 566,345                    |       | *—* |   | *—* |   |
| Thomson    |       | 19,600                      |       | 1,044,974                  |       | *—* |   | *—* |   |
| Zaleschuk  |       | 24,000                      |       | 1,255,740                  |       | *—* |   | *—* |   |

 

----

*Note:*

*(1)** **Equalsmarket price at the time of the exercise or exchange, minus the exercise price,as defined in the Tandem Option (TOPs) plan.*

** **

**COMPENSATION COMMITTEE REPORT**

 

The Compensation Committee assists theboard in overseeing key compensation and human resources policies, CEO andexecutive management compensation, and executive management succession anddevelopment. The Committee reports to the board, as set out in its mandate, andthe board or independent directors give final approval to compensation matters.

**Changes to Committee Membership in 2006**

 

Messrs. Jenkins and O’Neill joined theCommittee and Messrs. Hentschel and Zaleschuk left the Committee on April 27,2006. That same date, Mr. Jenkins was appointed Committee Chair to replace Mr.Willson. Ms. McLellan joined the Committee onJuly 5, 2006.

 

146

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**Key Activities in 2006**

 

•      Recommendedprograms for employee, executive and CEO compensation, including base salary,annual cash incentive and long-term incentive programs (TOPs and STARs);

•      Oversawpayments and grants made under Nexen’s annual cash incentive, TOPs and STARsplans; 

•      Recommendedto the board salaries, bonuses and grants of TOPs to executive officers;

•      EvaluatedCEO performance on short-term and long-term corporate goals and objectives, andrecommended his compensation, which was approved by the independent directorsof the board; 

•      Reviewedthe CEO’s position description; and

•      Recommendedcompensation programs in the form of retention or recognition awards for keybusiness initiatives. 

** **

**Independent Consultant**

 

The Committee engagedMercer Human Resource Consulting (Mercer) to provide a report of confidentialmarket data on the CEO’s compensation, and a technical analysis of the marketdata in light of our compensation plans and practices. The report includescompetitive compensation data from a list of peer companies, which isrecommended by the independent consultant and approved by the Committee. Thedecisions of the Committee are their responsibility and may reflect factors otherthan the information and recommendations provided by Mercer. 

 

Mercer also providedlimited general employee compensation consulting services to Nexen in 2006.Specifically, Mercer provided administrative services to management related tointernational pension arrangements. We also participated in compensationsurveys in Canada and international locations and purchased some of thepublished results. Management would obtain Committee approval before retainingMercer for compensation consulting work.

**Fees Billed byIndependent Consultant**

 
| **Type of Fee**                                                  | ** ** | **Billed in 2006** | ** ** | **Percentage of Total Fees  billed in 2006** | ** ** |
|------------------------------------------------------------------|------------|--------------------|------------|----------------------------------------------|------------|
| For independent assessment of CEO compensation for the Committee |       | 37,780             |       | 92                                           | %          |
| For administrative services provided to management               |       | 3,470              |       | 8                                            | %          |
| Total Annual Fees                                                |       | $                  | 41,250     |                                         | 100        | % |
|                                                                  |            |                    |            |                                              |            |  |

 

**External Recognition and Verification**

 

Nexenwas recognized for our human resource practices during 2006, including thefollowing:

•      Namedone of the 50 Best Employers in Canada by Hewitt Associates Inc.; and

•      Namedone of Alberta’s Top 25 Employers by Mediacorp Canada Inc.

**Committee Approval**

 

The Committee hasreviewed and discussed the compensation disclosure included in this document,including the information on pages 144 through 164, and has recommended to theboard that it be included in the Form 10-K.

**Submitted on behalf ofthe Compensation Committee:**

 
|   | Kevin Jenkins, Chair |   | Francis Saville |
|--------|----------------------|--------|-----------------|
|   | Barry Jackson        |   | Dick Thomson    |
|   | Anne McLellan        |   | John Willson    |
|   | Tom O’Neill     |   |            |

 

147

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| Items 10 to 15 | Corporate Governance | Summary Compensation |
|----------------|----------------------|----------------------|

 

**COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION**

 

The members of theCompensation Committee are set out on page 142. Mr. Saville had a relationshiprequiring disclosure, the details of which are set out under “CertainRelationships and Related Transactions, and Director Independence” on page 170.There are no Compensation Committee interlocks during 2006.

** **

**COMPENSATION DISCLOSURE**

 

We are committed to bestpractices in corporate governance, disclosure and transparency. This discussionof compensation practices at Nexen is intended to provide a clear understandingof our compensation objectives and programs. For 2006, we are providingcompensation disclosure that will comply with the requirements of the CanadianSecurities Administrators. As a foreign private issuer in the US, we are notrequired to disclose compensation in accordance with the SEC rules issued in2006. We have, however, complied with the spirit of those rules where possible,without compromising required Canadian disclosure.

 

**ExecutiveCompensation Philosophy**

 

Nexen’s policies andpractices for executive compensation are linked to its strategic businessobjectives, including increasing shareowner returns. Within that framework, theoverall philosophy is to compensate executives based on performance, at a levelcompetitive with our peers, and in a manner designed to attract and retain atalented leadership team focused on managing Nexen’s operations, finances andassets.

 

Our compensationprograms are designed to meet performance and competitiveness objectives. Toensure pay-for-performance, rewards are directly linked to planned performancefor Nexen and its divisions. Individual performance and contribution areconsidered in determining awards. Measures are aligned with financial andnon-financial goals and shareowner interests. 

 

We use independentcompensation surveys to benchmark the competitiveness of our compensationpractices to peers, primarily major Canadian oil and gas companies and, whererelevant, marketing companies. The peer group includes energy companies withwhom we compete for talent. Nexen’s programs provide responsiveness to changesin the market. We also aim for simplicity in our compensation programs to supportcommunication and employee understanding of the value of the variouscomponents. Programs provided for the executives are generally consistent withthose provided to all employees in the same location. Where certain programs,such as perquisites, are only provided to executives or senior management, itis reflective of competitive practice and particular business needs andobjectives.

 

In determining basesalary, annual cash and long term incentives for executive officers, theCompensation Committee considers individual’s performance and recommendationsfrom the CEO and CFO for their respective direct reports, in the context ofmarket data provided by management. The Committee recommends all payments andgrants for executive officers to the board or independent directors forapproval.

** **

**ExecutiveCompensation Objectives**

 

Our compensationprograms include three components: base salary, annual cash incentive andlong-term incentive. We assess total compensation and consider thecompetitiveness of each component, both individually and in the aggregate. Theoverall goal is to provide total compensation for experienced, top-performingemployees between the 50th and 75th percentile as compared to peer companies.Nexen’s position is compared against the peer group annually.

** **

**KeyElements of Compensation**

 
| **Component** | ** ** | **Type of Compensation** | ** ** | **Element**           | ** ** | **Form**       | ** ** | **Performance Period** |
|---------------|------------|--------------------------|------------|-----------------------|------------|----------------|------------|------------------------|
| Fixed         |       | Annual                   |       | Base Salary           |       | Cash           |       | 1 Year                 |
| Variable      |       | Annual                   |       | Annual Cash Incentive |       | Cash           |       | 1 Year                 |
| Variable      |       | Long-Term                |       | Long-Term Incentive   |       | TOPs and STARs |       | Greater than 1 Year    |

 

148

----

 

**Pay Mix**

 

Nexen’s compensationprograms are designed to meet both performance and competitiveness objectives,rather than a fixed pay-mix target. As a result, actual pay levels will varyfrom year to year. In general, the target mix between the compensation elementsis designed to provide the majority of compensation to the executive officersin the form of at-risk pay to ensure alignment with shareowners. The annual cashincentive program is designed to reward delivery of results against pre-definedmeasures within a short time frame. Long-term incentives reward the sustainedperformance of Nexen as seen in share price appreciation. The actual mixbetween the compensation elements varies, depending on the ability of theexecutive to influence short-term and long-term business results, the level andlocation of the executive, and competitive local market practices. The level ofcompensation is determined considering the competitive position of each elementof compensation on its own, as well as the aggregate of all elements, relativeto competitive market data.

 

**TargetWeightings for Compensation Elements**

 
| ** **   | ** ** | ** **      | ** ** | **At-Risk Compensation (****1)** | ** ** |
|--------------|------------|-----------------|------------|----------------------------------|------------|
| **Position** | ** ** | **Base Salary** | ** ** | **Annual Cash  Incentive**       | ** ** | **Long-Term  Incentive** | ** ** |
| CEO          |       | 20              | %          | 15                               | %          | 65 | % |
| CFO          |       | 25              | %          | 20                               | %          | 55 | % |
| Senior VPs   |       | 30              | %          | 20                               | %          | 50 | % |

* *

----

*Note:*

*(1)** **Reported as a percentage of total compensation, excludingbenefits, pension and prerequisites.*

** **

**BaseSalaries**

 

Nexen maintains aframework of job levels based on internal comparability and external marketdata to determine base salaries. Base salaries are determined within thatframework, considering the individual’s current and sustained performance,skills and potential. Base salaries are reviewed annually against competitivedata from our peer group.

** **

**AnnualCash Incentives**

 

Annual incentivesprovide cash compensation that is at risk and dependent upon the achievement ofspecific business and operating objectives within a one-year period. Individualawards are intended to reflect a combination of overall Nexen and individualperformance, along with market competitiveness. Annual incentive awards aretypically within a range of 0% to 200% of targeted amounts. 

** **

**2006Annual Incentive Targets (1)**

 
| **Position** | ** ** | **Minimum** | ** ** | **Target (****2)** | ** ** | **Maximum (****3)** | ** ** |
|--------------|------------|-------------|------------|--------------------|------------|---------------------|------------|
| CEO          |       | 0           | %          | 75                 | %          | 150                 | %          |
| CFO          |       | 0           | %          | 60                 | %          | 120                 | %          |
| Senior VPs   |       | 0           | %          | 60                 | %          | 120                 | %          |

 

----

*Notes:*

*(1)** **Reported as a percentage of base salary.*

*(2)** **Approved by the board effective January 1, 2006.*

*(3)** **Target at 200%.*

 

The board, at therecommendation of the Compensation Committee, determines the total cashavailable for annual cash incentives after reviewing Nexen’s annual financialand non-financial incentive measures. The measures in the following balancedscorecard are commonly used metrics in our industry, and are assessed by theCommittee in the context of our overall performance and performance relative topeers. The Committee may increase or decrease the total cash available forthese awards based on their assessment.

 

149

----

 

**2006Annual Incentive Measures (Balanced Scorecard)**

 
| **Financial  Performance Measures (50%)**              |       |                              |       |                      |
|--------------------------------------------------------|------------|-----------------------------------|------------|---------------------------|
| ** **                                             |       |                              |       |                      |
| **Measure**                                            | ** ** | **Actual Results**                | ** ** | **Results versus Target** |
| •      Cash  flow (25%)  |       | Cash flow was $2,669 million |       | Exceeded Target           |
| •      Net  income (25%) |       | Net Income was $601 million  |       | Below Target              |

 
| **Key  Qualitative and Quantitative Performance Measures (50%)**                                                                                                                                                                                                                                                                                                                                                       |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **                                                                                                                                                                                                                                                                                                                                                                                                             |
| **Measure**                                                                                                                                                                                                                                                                                                                                                                                                            | ** ** | **Results versus Target** |
| ** **                                                                                                                                                                                                                                                                                                                                                                                                             | ** ** | ** ** |
| **Overall  Business Measures**                                                                                                                                                                                                                                                                                                                                                                                         |   |   |
| •      Annual  stock performance

•      Annual  relative stock performance

•      Employee  recordable injury index rate

•      Gross  corporation G&A

•      Net  G&A                                                                               |   | The board, at the  recommendation of the Compensation Committee, determined that:

•      three  of the measures exceeded target, including our annual stock performance with  a return of 16% versus a target of 12%; and

•      two  were below target. |
|                                                                                                                                                                                                                                                                                                                                                                                                                   |   |   |
| **Growth and Investment Measures**                                                                                                                                                                                                                                                                                                                                                                                     |   |   |
| •      Realized  oil equivalent price

•      Exploration  and development project portfolio: Risked

•      Reserve  replacement costs: Proved

•      FD&A  costs: Proved

•      Recycle  ratio

•      Reserve  life index |   | The board, at the  recommendation of the Compensation Committee, determined that:

•      three  of the measures exceeded target, including reserve life index of 13.2 years  versus a target of 12.3 years; and

•      three  were below target. |
|                                                                                                                                                                                                                                                                                                                                                                                                                   |   |   |
| **Operational Measures**                                                                                                                                                                                                                                                                                                                                                                                               |   |   |
| •      Production  volumes

•      Operating  costs per unit

•      Net  oil and gas G&A

•      Net  oil and gas G&A per unit

•      Product  netback

•      Major  environmental incidents                            |   | The board, at the  recommendation of the Compensation Committee, determined that:

•      two  of the measures exceeded target, including operating costs of $8.77 per boe  versus a target of $8.86 per boe;

•      one  measure, major environmental incidents of zero, met target; and

•      three  were below target, including production volumes of 212 thousand boe per day  versus a target of 234 thousand boe per day. |

 

The total cash availablefor annual incentives is distributed to employees, including executives, on thebasis of individual performance. Eligibility for awards is defined byindividual target award levels that increase in relation to jobresponsibilities so that the ratio of at-risk versus fixed compensation isgreater for higher levels of employees. The program is reviewed annually toensure we continue to attract, motivate, reward and retain the high-performingand high-potential employees needed to achieve our business objectives, whiledemonstrating long-term fiscal responsibility to shareowners. Consistent withindustry practice, we have a profit sharing arrangement as the annual incentiveprogram for our marketing group. None of the named executive officersparticipate in the profit sharing arrangement. The Compensation Committeerecommends the program for all employees, including executives, to the boardfor approval. 

 

If, as a result ofmisconduct, the incentive measures above were restated in a way that decreasedthe awards, the CEO and CFO would reimburse Nexen proportionately as requiredby law.

** **

**ShareOwnership Guidelines**

 

All officers, exceptAssistant Secretaries, are required to demonstrate their commitment to Nexenthrough share ownership

 

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under the following board-approved guidelines.The period to accumulate shares is five years from date of appointment, andshare ownership includes the net value of exercisable options or TOPs,flow-through shares, shares purchased and held within the Nexen employeesavings plan and any other personal holdings. All executives hold the requirednumber of shares directly or through the net value of their exercisable optionsor TOPs. See page 159 for the current share ownership equity at risk as amultiple of salary of each named executive officer. The guidelines are reviewedfrom time to time.

 
| **Position**              | ** ** | **Required Share Ownership** |   |
|---------------------------|------------|------------------------------|--------|
| CEO                       |       | Three  times annual salary   |   |
| CFO                       |       | Two  times annual salary     |   |
| Other Executive  Officers |       | One  times annual salary     |   |

 

**Long Term Incentives**

 

The board believesemployees should have a stake in Nexen’s future and their interests should bealigned with those of share- owners. Those officers and employees whose actionscan most directly impact business results, participate in Nexen’s long-termincentive program (the TOPs and STARs plans). These plans are Nexen’s onlyequity-based compensation for executives. In addition, we encourage employeepurchases of Nexen shares in their savings plan by matching contributions up tospecified limits.

 

Both the TOPs and STARsplans are intended to provide employees with long-term incentive for continuedhigh performance, commitment to Nexen and, more importantly, alignment with theinterests of our shareowners. As Nexen’s share price rises, grants increase invalue. As equity-based plans, the value realized by employees is directlyrelated to changes in Nexen’s share price and shareowner interests. If Nexen’sshare price falls below the exercise price of a grant, the grant will cease tohave value until the share price rises above that level.

 

Effective July 1, 2004,the shareowners approved modifying Nexen’s stock option plan to a TOPs plan,which allows employees to exchange their TOPs for a cash payment, equal to thedifference between the pre-defined exercise price and the closing market priceon that day instead of exercising them for shares. No shares are issued whenemployees exchange their TOPs for a cash payment, which prevents furthershareowner dilution over time, and provides a Canadian income tax deduction toNexen. The TOPs plan provides employees with the option to buy Nexen shares ata set exercise price at some future date, subject to vesting and expiry terms.These shares may be held or sold at any time. TOPs do not provide employeeswith the right to vote the shares that are subject to the plan. The TOPs planis Nexen’s only equity-based compensation arrangement for the purposes ofdisclosure requirements.

 

Under the TOPs plan, theboard, on the recommendation of the Compensation Committee, may grant TOPs toNexen officers and employees. Options granted before February 2001 have a termof ten years; 20% of the grant vested after six months and then 20% vested eachyear for four years on the anniversary of the grant. In February 2001, theboard approved an amendment providing that each option granted has a term offive years and vests one-third each year over three years. 

 

Generally, if a changeof control event occurs (as defined in the TOPs plan), all issued but unvestedoptions will vest. 

 

The STARs plan,introduced in 2001, provides a cash payment to participants equal to theappreciation in Nexen’s share price between the date the STARs are granted andthe date they are exercised. For employees below mid-level department managers,STARs are typically granted instead of TOPs. The STARs grants have a five-yearterm and vest one-third in each of the first three years on the anniversarydate of the grant. 

 

The long-term incentiveprogram is reviewed annually for competitiveness with our peer group. Marketinformation on options and other forms of long-term incentives, along with thedilutive impact of the program on shareowners, are considered to determine thenumber of TOPs and STARs granted. Market information is also used to determinethe form of long-term incentives and the extent to which employees at differentlevels participate in the program. Management and the Compensation Committeehave considered alternative long-term incentive programs used by our peers,including full-value plans such as DSUs, restricted share units andperformance-based stock options. At this time, the current long-term incentiveprogram has been determined to best meet Nexen’s objectives, consideringcompetitive position, retention value, tax effectiveness for our employees andNexen,

 

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shareowner interests, and dilution levels.

** **

**GrantDate and Exercise Price**

 

Grants are providedunder the TOPs and STARs plans to employees, including executives, during theannual grant process and at the time of hiring key positions. Since 1998, theannual grants have occurred at the December board meeting. Nexen does notspringload grants - that is, grants are not intentionally timed to occurimmediately prior to the release of material information. Grants for new hiresmay be approved by the CEO and typically occur shortly after the hire date.Under the plans, the exercise price is the closing market price of Nexen’scommon shares on the relevant stock exchange (TSX for Canadian-based employeesor NYSE for US-based employees) on the day before the grant is approved.Accordingly, back-dating is not allowed. The exercise price of existing TOPs orSTARs may not be reduced except for automatic adjustments under the plans,(i.e., share splits) or in accordance with TSX rules.

** **

**Grantsin the Last Three Years**

 

The focus in 2006 was onproviding awards to employees in recognition of high performance, futurepotential within Nexen and retention risk.

 
| **Year**  | ** ** | **Granted to  Executive Officers** | ** ** | **Granted  to Employees** | ** ** | **Percentage of Employees  Receiving Grants** | ** ** | **Total Number  Granted** | ** ** |
|-----------|------------|------------------------------------|------------|---------------------------|------------|-----------------------------------------------|------------|---------------------------|------------|
| **TOPs**  |       |                               |       |                      |       |                                          |       |                      |       |
| 2006      |       | 740,000                            |       | 1,660,500                 |       | 7                                             | %          | 2,400,500                 |       |
| 2005      |       | 592,000                            |       | 2,799,500                 |       | 20                                            | %          | 3,391,500                 |       |
| 2004 (1)  |       | 1,022,000                          |       | 3,202,400                 |       | 11                                            | %          | 4,224,400                 |       |
| **STARs** |       |                               |       |                      |       |                                          |       |                      |       |
| 2006      |       | *—*                           |       | 2,254,300                 |       | 51                                            | %          | 2,254,300                 |       |
| 2005      |       | *—*                           |       | 1,443,050                 |       | 39                                            | %          | 1,443,050                 |       |
| 2004 (1)  |       | *—*                           |       | 2,608,900                 |       | 34                                            | %          | 2,608,900                 |       |

 

----

*Note:*

*(1) Numbers of TOPs andSTARs granted have been adjusted to account for Nexen’s two-for-one share splitin May 2005.*

** **

**Benefitand Pension Plans**

 

Nexen provides a varietyof benefit and pension plans to support the health and well-being of itsemployees, and to encourage retirement savings. The plans are reviewed fromtime to time to ensure they remain competitive and continue to meet ourobjectives. Market survey data is reviewed to ensure the plans provide benefitsbetween the 50th and 75th percentile of plans within our peer group ofcompanies. Executives participate in the same plans provided to all otheremployees at the same location.

 

Disclosure in thisdocument is specific to the Canadian and US plans in which the named executiveofficers participate. Nexen provides a variety of other benefit and pensionplans outside of Canada and the US that reflect local market practices.

** **

**Healthand Welfare Benefits**

 

Nexen employees areprovided benefit plans designed to protect their health and that of their dependents,and to cover them in the event of disability or death. Under the North Americanflexible benefits plan, employees choose the level of coverage that best fitstheir needs. Those who select enhanced coverage levels are required tocontribute to the cost of that coverage.

 

152

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**EmployeeSavings Plan**

 

Nexen employees have theopportunity to save for short- or long-term needs in the employee savings plan.Through payroll deductions, all eligible Canadian employees may contribute anypercentage of their base salary to purchase Nexen common shares, mutual fundunits or a combination of both. Nexen matches employee contributions up to 6%of base salary. The extent of matching is based on the investment option chosenand the employee’s length of participation in the plan. All Nexen contributionsare invested in our common shares purchased on the open market and vestimmediately. Canadian employee and employer contributions may be allocated toregistered or non-registered accounts. Employees may vote the Nexen commonshares they hold in their employee savings plan.

 

The employee savingsplan in the US is intended to qualify under Section 401(a) and 501(a) of theInternal Revenue Code. Nexen matches employee contributions up to 6% ofeligible compensation. Nexen’s matching contribution is provided in cash, whichvests immediately.

** **

**DefinedBenefit Pension Plan (Canada)**

 

Under this registeredplan, participants contribute 3% of their regular gross earnings, up to a planmaximum. On retirement, participants are entitled to receive a benefit equal to1.8% (1.7% for years prior to 2005) of their average earnings for the 36highest-paid consecutive months during the ten years before retirement,multiplied by the number of years of credited service. The plan is integratedwith the Canada Pension Plan (CPP) to provide a maximum offset of one-half ofthe prevailing CPP benefit. 

 

Pension benefits earnedprior to January 1, 1993, may be indexed at the discretion of management’spension committee, considering increases in the consumer price index. Pensionbenefits earned after December 31, 1992, are indexed annually at an amountbetween 0% and 5% and equal to the greater of:

 

•      75%of the increase in the Canadian consumer price index, less 1%; and

•      25%of the increase in the Canadian consumer price index.

 

Effective January 1,2005, the plan was amended to permit participants to periodically switchbetween the defined benefit pension plan and defined contribution pension planat different stages in their career. In addition, the defined benefit plan’saccrual formula increased from 1.7% to 1.8% for participation after January 1,2005 as stated above. Plan participants have an opportunity to further increasetheir defined benefit accrual formula on a go-forward basis, from 1.8% to 2%.Employees who choose this option must contribute an additional 2% ofpensionable earnings up to an allowable maximum under the Canadian Income TaxAct. The maximum employee contribution allowed under Nexen’s plan in 2006 was$10,200.

** **

**ExecutiveBenefit Plan (Canada)**

 

The executive benefitplan provides supplemental retirement benefits for Canadian participants whohave earned a retirement benefit in excess of the statutory limits. Thissupplemental benefit provides employees with the opportunity to accrue apension that is aligned with their final earnings level and also ensurescompetitiveness within our market. Benefits that accrue under this plan aresimilar to the underlying registered pension plan formula for the definedbenefit pension plan, which provides for benefits of 1.7% for credited serviceprior to 2005 and 1.8% or 2% for credited service after that. For executiveofficers, annual cash incentive payments during the last three years of participationin this plan are included for benefit accrual purposes. For annual cashincentives, the pension benefit is accrued on the lesser of target bonus oractual bonus paid, averaged over the final three years of participation. In2006, all Canadian executive officers participated in the defined benefitpension plan.

 

The pension expense for this plan is determined and recognizedannually. Benefits payable for the year are paid from the cash flows generatedby Nexen’s general operating revenues and reduce the related pension liability.As liabilities under this plan are not funded outside of Nexen, a level ofprotection is provided to participants through a letter of credit. The letterof credit basically makes participants secured creditors up to the aggregatevalue of the letter of credit. This is separate from the protection of benefitsin the registered defined benefit pension plan, which is funded by a pensiontrust. The cost of servicing the letter of credit for the executive benefitplan for all executive officers and employee participants in 2006 was $465,178.

 

153

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At December 31, 2006, as indicated in the notesto our Consolidated Financial Statements, Nexen’s supplemental pension plan’saccumulated benefit obligation (the projected benefit obligation, excludingfuture salary increases) for the executive benefit plan was $35 million and theprojected benefit obligation was $53 million. The projected benefit obligationis an estimate based on contractual entitlements that may change over time. Themethod used to determine this estimate will not be identical to the method usedby other issuers and, as a result, the figures may not be directly comparableacross companies. The key assumptions used for the projected benefit obligationwere: a discount rate of 5% per year; long-term compensation rate increases of4% per year; and, an expected average remaining service life of ten years.

 

Effective January 1, 2005, the executive benefitplan was amended to provide a supplemental pension allocation for definedcontribution pension plan participants who are affected by annual statutorycontribution limits. In 2006, the supplemental allocation for eligibleparticipants was $29,979 and the supplemental allocation for eligibleparticipants is estimated to be $35,000 in 2007.

 

**Defined Contribution PensionPlan (US)**

 

Under this qualified retirement plan, Nexenprovides participants with a contribution of 6% of eligible compensation up tothe social security wage base and 11.5% of eligible compensation that exceedsthe social security taxable wage base. For 2006, the maximum amount ofcontributions permitted by legislation to the qualified defined contributionplans was US$20,119 per participant. Employees are not permitted tocontribute to the plan. Investment decisions are made by the employee from avariety of mutual funds. The contributions vest after two years of service.This plan is intended to be an Employee Retirement Income Security Act (ERISA)404(c) plan. In 2006, there was one named executive officer participating inthis US plan.

 

**Non-Qualified Restoration Plan(US)**

 

This plan is an unfunded and non-qualifieddeferred compensation arrangement that provides deferred compensation benefitsto a select group of management or senior employees. The returns in this planreflect the returns on the investments selected by the employee in the definedcontribution pension plan (US). The plan is established and maintained by Nexenfor the purpose of providing retirement benefits in excess of applicablelegislative limits and is intended to comply fully with Section 409A of theInternal Revenue Code.

 

**Loans to Officers**

 

As set out in the corporate governance policy,Nexen does not make loans to its officers. There are no loans outstanding fromNexen to any of its officers.

 

154

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| Corporate  Governance |   | Executive  Officers |
|-----------------------|--------|---------------------|

 

**Executive Officers**

 

The board determines the term of office for eachexecutive officer. Below are Nexen’s officers, including prior offices andnon-executive positions for officers who have held their current executive positionswith Nexen for less than five years. Start dates are indicated for officerpositions with Nexen.

 
| **Officer**** ****(Age)** | ** ** | **Current and Past Position(s) with Nexen**                                                                                   | ** ** | **Effective Date of  Current Position** | ** ** | **Executive Officer  Since** | ** ** |
|--------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------|------------|------------------------------|------------|
| Charles  W. Fischer (56)       |       | President  and CEO and a director                                                                                                                      |       | June 1, 2001                                           |       | 1994                         |       |
| Marvin  F. Romanow (51)        |       | Executive  VP and CFO                                                                                                                                  |       | June 1, 2001                                           |       | 1997                         |       |
| Laurence  Murphy (55)          |       | Senior  VP, International Oil and Gas                                                                                                                  |       | January 1, 1999                                        |       | 1998                         |       |
| John  B. McWilliams, Q.C. (59) |       | Senior  VP, General Counsel and Secretary                                                                                                              |       | May 11, 1993                                           |       | 1987                         |       |
| Douglas  B. Otten (64)         |       | Senior  VP, US Oil and Gas                                                                                                                             |       | May 12, 1998                                           |       | 1990                         |       |
| Roger  D. Thomas (54)          |       | Senior  VP, Canadian Oil and Gas                                                                                                                       |       | February 19, 1999                                      |       | 1998                         |       |
| Nancy  F. Foster (47)          |       | Senior  VP, Human Resources and Corporate Services

Formerly:  VP, Human Resources and Corporate Services                                              |       | February 15, 2007                                      |       | 2000                         |       |
| Gary  H. Nieuwenburg (48)      |       | VP,  Synthetic Crude 

Formerly:  VP, Corporate Planning and Business Development since February 16, 2001                                              |       | July 11, 2002                                          |       | 2001                         |       |
| Kevin  J. Reinhart (48)        |       | VP,  Corporate Planning and Business Development

Formerly:  Treasurer since October 20, 1998                                                          |       | July 11, 2002                                          |       | 1994                         |       |
| Una  M. Power (1) (42)         |       | Treasurer

Formerly:  Controller and Director, Corporate Insurance since May 2, 2002; Controller  and Director, Risk Management since December 1, 1998 |       | July 11, 2002                                          |       | 1998                         |       |
| Michael  J. Harris (43)        |       | Controller

Formerly:  Manager, Corporate Finance—Treasury since December 1, 2000                                                            |       | December 10, 2002                                      |       | 2002                         |       |

 

----

*Note:*

*(1)**   **Ms. Power concurrently maintained her position as Controlleruntil December 10, 2002.*

 

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| Items  10 to 15 |   | Corporate  Governance |   | Executive  Officer Compensation |
|-----------------|--------|-----------------------|--------|---------------------------------|

 

**SUMMARY COMPENSATIONTABLE**

 

The compensation for the CEO, CFO and the nextthree highest paid officers is provided. The determination of the next threehighest paid officers is based on the sum of salary, special bonus andnon-equity cash incentive compensation.

 
| ** **             | ** ** | ** ** | ** ** | **Annual** | ** ** | **Long-Term**  | ** ** | **Other**             | ** ** | ** **      | ** ** |
|------------------------|------------|------------|------------|------------|------------|----------------|------------|-----------------------|------------|-----------------|------------|
| ** **             | ** ** | ** ** | ** ** | ** ** | ** ** | ** **     | ** ** | **Non-Equity  Cash**  | ** ** | ** **      | ** ** | ** ** | ** ** | **Changes  in** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Name and**           | ** ** | ** ** | ** ** | ** ** | ** ** | **Special**    | ** ** | **Incentive**         | ** ** | **TOPs**        | ** ** | **TOPs** | ** ** | **Pension** | ** ** | **All  Other** | ** ** | **Total** | ** ** |
| **Principal Position** | ** ** | **Year**   | ** ** | **Salary** | ** ** | **Bonus  (1)** | ** ** | **Compensation  (2)** | ** ** | **Awards  (3)** | ** ** | **Awards  (3)** | ** ** | **Obligations  (4)** | ** ** | **Compensation  (5)** | ** ** | **Compensation** | ** ** |
| ** **             | ** ** | ** ** | ** ** | **($)**    | ** ** | **($)**        | ** ** | **($)**               | ** ** | **(#)**         | ** ** | **($)** | ** ** | **($)** | ** ** | **($)** | ** ** | **($)** | ** ** |
| Fischer, President     |       | 2006       |       | 1,150,000  |       | 500,000        |       | 1,300,000             |       | 275,000         |       | 5,010,654 |   | 1,673,800 |   | 101,721 |   | 9,736,175 |   |
| and CEO                |       | 2005       |       | 975,000    |       | 300,000        |       | 1,500,000             |       | 200,000         |       | 3,110,490 |   | 879,300 |   | 91,464 |   | 6,856,254 |   |
|                   |       | 2004       |       | 847,917    |       | 450,000        |       | 900,000               |       | 300,000         |       | 1,983,930 |   | 1,430,000 |   | 84,109 |   | 5,695,956 |   |
|                   |       |       |       |       |       |           |       |                  |       |            |       |   |   |   |   |   |   |   |   |
| Romanow (6),           |       | 2006       |       | 528,000    |       | —         |       | 402,000               |       | 80,000          |       | 1,457,645 |   | 534,800 |   | 111,973 |   | 3,034,418 |   |
| Executive VP           |       | 2005       |       | 486,000    |       | 175,000        |       | 590,000               |       | 62,000          |       | 964,252 |   | 176,300 |   | 83,457 |   | 2,475,009 |   |
| and CFO                |       | 2004       |       | 462,500    |       | 200,000        |       | 350,000               |       | 114,000         |       | 753,893 |   | 346,000 |   | 47,569 |   | 2,159,962 |   |
|                   |       |       |       |       |       |           |       |                  |       |            |       |   |   |   |   |   |   |   |   |
| Otten, (7) Senior VP,  |       | 2006       |       | 439,716    |       | —         |       | 326,938               |       | 55,000          |       | 990,017 |   | — |   | 100,303 |   | 1,856,974 |   |
| US Oil and Gas         |       | 2005       |       | 423,489    |       | —         |       | 430,154               |       | 50,000          |       | 815,163 |   | — |   | 95,461 |   | 1,764,267 |   |
|                   |       | 2004       |       | 438,005    |       | —         |       | 227,763               |       | 80,000          |       | 572,827 |   | — |   | 111,291 |   | 1,349,886 |   |
|                   |       |       |       |       |       |           |       |                  |       |            |       |   |   |   |   |   |   |   |   |
| Murphy, Senior VP,     |       | 2006       |       | 455,000    |       | 300,000        |       | 342,000               |       | 65,000          |       | 1,184,336 |   | 580,800 |   | 47,611 |   | 2,909,747 |   |
| International          |       | 2005       |       | 405,000    |       | —         |       | 410,000               |       | 50,000          |       | 777,623 |   | 141,300 |   | 38,339 |   | 1,772,262 |   |
| Oil and Gas            |       | 2004       |       | 385,500    |       | 300,000        |       | 205,000               |       | 80,000          |       | 529,048 |   | 104,000 |   | 43,620 |   | 1,567,168 |   |
|                   |       |       |       |       |       |           |       |                  |       |            |       |   |   |   |   |   |   |   |   |
| Thomas, Senior VP,     |       | 2006       |       | 445,000    |       | —         |       | 336,000               |       | 65,000          |       | 1,184,336 |   | 735,800 |   | 46,986 |   | 2,748,122 |   |
| Canadian Oil           |       | 2005       |       | 394,250    |       | 200,000        |       | 400,000               |       | 50,000          |       | 777,623 |   | 167,300 |   | 44,673 |   | 1,983,846 |   |
| and Gas                |       | 2004       |       | 373,250    |       | —         |       | 200,000               |       | 80,000          |       | 529,048 |   | 87,000 |   | 37,191 |   | 1,226,489 |   |

 

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*Notes:*

*(1)**   **Special discretionary award(s) earned in the year shown. For2006, the board approved a special bonus for Mr. Fischer and Mr. Murphy for thesuccess of Buzzard.*

*(2)**   **Reflects the value of awards earned in each year under Nexen’sannual cash incentive program. The awards are paid to the executives in thefollowing calendar year.*

*(3)**   **Reflects the fair market value under the Black-Scholespricing model of TOPs granted in the year as described in the TOPs Tables onpage 158.*

*(4)**   **Represents the employer service cost, plus changes incompensation in excess of actuarial assumptions, less required membercontributions to the plan.*

*(5)**   **The total value of perquisites provided to each namedexecutive officer is less than both $50,000 or 10% of their total annual salaryplus bonus and is not included in this column. Reflects Nexen’s contributionsto the employee savings plan, defined contribution pension plan (US), carallowance and life insurance premiums paid by Nexen.*

*(6)**   **Mr. Romanow is a director of Canexus and was paid fees of$34,000 and received deferred trust units of Canexus valued at $24,000 anddistributions on his trust units of**$2,571 in 2006. In 2005, he was paid fees of$13,875, received deferred trust units valued at $20,000 and distributions onhis trust units of $659. These amounts are included in “All Other Compensation”and more detail is on page 163.*

*(7)**   **Nexen contributed to a qualified defined contributionpension plan and a restoration plan with Nexen Petroleum U.S.A. Inc. for Mr.Otten.*

 

**Non-Equity Cash IncentiveCompensation and Special Bonus**

 

The summary compensation table above shows theawards for each year, determined under that year’s annual cash incentiveprogram. Payment of the awards is made early the following year. Prior to 2006,Nexen reported this award as bonus in the year paid rather than the yearearned. Values in the table have been updated to reflect the change inpresentation. Special bonuses include discretionary cash awards approved by theboard for successful delivery of key business objectives, such as acquisitionsand divestitures.

 

**Changes in Pension Obligations**

 

The summary compensation table shows theyear-over-year change in pension obligations. The value reflects the employerservice cost plus any changes in obligations resulting from compensationincreases over actuarial assumptions. Actual compensation changes may vary fromthe assumed rate of compensation increase and will vary among each executiveofficer from year to year. These values differ from pension benefit valuesreported on page 163, which disclose estimated values of annual pensionbenefits earned to date, as well as at age 60 (the earliest unreducedretirement age). These values also differ from the termination values reportedunder the change of control agreements on page 164, which disclose the value ofadditional lump sum pension benefits which will be provided in the event of achange of control.

 

156

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**President and CEO Compensation**

 

Competitive compensation information for ourPresident and CEO is determined based on assessments conducted by anindependent compensation consulting firm that compares similar positions in oiland gas companies. Target total direct compensation (base salary plus annualcash and long term incentives) is competitive within the range of our oil andgas peer group. CEO compensation is approved by the independent directors ofthe board.

 

**President and CEO 2006 Goals**

 

Mr. Fischer’s responsibility is to providedirection and leadership in setting and achieving goals, which will createvalue for Nexen’s shareowners in the short- and long-terms. Mr. Fischer’sannual cash incentive award for 2006 performance was based on the corporateresults described on page 150, which were used to determine the total cashavailable for the awards. Individual cash incentive awards are determined fromthe available pool and distributed to individuals based on specific goalsestablished for the year. Based on the board assessment of Mr. Fischer’sachievement of objectives in 2006, he was awarded an annual cash incentive of$1,300,000, which was his target bonus times 144%. More specifically, Mr.Fischer’s goals in 2006 were to:

 

•    develop and implement corporate strategy,balancing short-term growth while positioning Nexen for sustainable growth;

•    achieve capital, operating, and generaland administrative cost performance targets set out in the annual operatingplan (AOP);

•    achieve targets for operating cash flow,earnings, production levels and reserve replacement set out in the AOP;

•    maintain financial flexibility andliquidity to support business strategies;

•    achieve top-quartile performance insafety, environmental performance and social responsibility;

•    provide for corporate managementsuccession and development;

•    ensure Nexen adheres to the higheststandards of integrity; and

•    demonstrate personal commitment tocommunity and industry leadership.

 

**CEO Three-Year Look-Back**

 

The table below outlines the three-year historyof compensation paid to Mr. Fischer. The pension service cost from prior yearshas been updated to reflect the best practice method of reporting the change inpension obligation related to service and earnings increases in that year. Thecalculation of these numbers in prior years applied a different method thatreported the change in pension obligation related to service and earningsincreases and non-compensation assumption changes. The values reportedpreviously for 2005 and 2004 were $724,000 and $1,341,000, respectively.

 
| **CASH**                                      | ** ** | **Total**      | ** ** | **2006**      | ** ** | **2005**      | ** ** | **2004**      | ** ** |
|-----------------------------------------------|------------|----------------|------------|---------------|------------|---------------|------------|---------------|------------|
| Base Salary                                   |       | 2,972,917      |       | 1,150,000     |       | 975,000       |       | 847,917       |       |
| Annual Cash  Incentive (1)                    |       | 4,950,000      |       | 1,800,000     |       | 1,800,000     |       | 1,350,000     |       |
| **EQUITY**                                    | ** ** | ** **     | ** ** | ** **    | ** ** | ** **    | ** ** | ** **    | ** ** |
| Value of  TOPs (2)                            |       | 10,105,074     |       | 5,010,654     |       | 3,110,490     |       | 1,983,930     |       |
| Total Direct  Compensation                    |       | 18,027,991     |       | 7,960,654     |       | 5,885,490     |       | 4,181,847     |       |
| All Other  Compensation (3)                   |       | 277,294        |       | 101,721       |       | 91,464        |       | 84,109        |       |
| Annual  Change in Pension Obligation (4)      |       | 3,983,100      |       | 1,673,800     |       | 879,300       |       | 1,430,000     |       |
| **Total**                                     | ** ** | **22,288,385** | ** ** | **9,736,175** | ** ** | **6,856,254** | ** ** | **5,695,956** | ** ** |
|                                          |       |           |       |          |       |          |       |          |       |
| Annual  Average                               |       | 7,429,462      |       |          |       |          |       |          |       |
| Year-End  Market Capitalization (in billions) |       |           |       | 17            |       | 14            |       | 6             |       |
| Market  Capitalization grew by a factor of:   |       | 283            | %          |          |       |          |       |          |       |

 

----

*Notes:*

*(1)**   **Includes special bonuses of $500,000 in 2006 for the successof Buzzard, $300,000 in 2005 for successful divestitures and $450,000 in 2004for successful completion of**the UK North Sea acquisition.*

*(2)**   **Estimated fair value of TOPs using the Black-Scholes pricingmodel valued on the grant date.*

*(3)**   **Reflects Nexen’s contributions to the employee savings plan,car allowance and life insurance premiums paid by Nexen.*

*(4)**   **Represents the employer service cost, plus changes incompensation in excess of actuarial assumptions, less required membercontributions to the plan.*

 

157

----

 

In addition to the information on the previouspage, in 2006 the Compensation Committee reviewed a broader analysis of totalCEO pay and shareowner value created from the date Mr. Fischer became CEO. Thisanalysis included a compensation tally sheet outlining a dollar value to eachcompensation component including: salary, annual cash incentives, awards,benefits, pension (including annual increases to liabilities) and potentialpayments on change of control. The Committee reviewed total compensation paidto Mr. Fischer since his appointment to the CEO position relative to growth inshareowner value (market capitalization) and that growth relative to ourindustry peers. All of these factors are considered in determining CEOcompensation.

 

**TOPs Tables**

 

Nexen uses the Black-Scholes pricing model,which is a generally accepted method of measurement for this type of long-termincentive, to value TOPs grants. The actual value realized on exercises may behigher or lower than this value depending on the Nexen share price at the timeof exercise.

 

In the following tables, grant prices andnumbers granted have been adjusted to account for the May 2005 share split.

 

**TOPs Granted in 2006**

 
| ** ** | ** ** | ** **     | ** ** | ** **  | ** ** | ** **       | ** ** | ** **       | ** ** | ** **  | ** **  | ** **       | ** ** | **Potential Realizable Value at**    | ** ** |
|------------|------------|----------------|------------|-------------|------------|------------------|------------|------------------|------------|-------------|-------------|------------------|------------|--------------------------------------|------------|
| ** ** | ** ** | ** **     | ** ** | ** **  | ** ** | **% of Total**   | ** ** | ** **       | ** ** | ** **  | ** **  | ** **       | ** ** | **Assumed Annual Rates of Share**    | ** ** |
| ** ** | ** ** | ** **     | ** ** | **TOPs**    | ** ** | **TOPs Granted** | ** ** | **Exercise**     | ** ** | **Expiry**  | ** **  | **TOPs**         | ** ** | **Price Appreciation for TOPs Term** | ** ** |
| **Name**   | ** ** | **Grant Date** | ** ** | **Granted** | ** ** | **to Employees** | ** ** | **Price****(1)** | ** ** | **Date**    | ** **  | **Value****(2)** | ** ** | **5%**                               | ** ** | **10%** | ** ** |
| ** ** | ** ** | ** **     | ** ** | **(#)**     | ** ** | ** **       | ** ** | **($)**          | ** ** | ** **  | ** **  | **($)**          | ** ** | **($)**                              | ** ** | **($)** | ** ** |
| Fischer    |       | Dec 4, 2006    |       | 275,000     |       | 5.9              |       | 63.20            |       | Dec 3, 2011 |        | 5,010,654        |       | 4,801,774                            |       | 10,610,664 |   |
| Romanow    |       | Dec 4, 2006    |       | 80,000      |       | 1.7              |       | 63.20            |       | Dec 3, 2011 |        | 1,457,645        |       | 1,396,880                            |       | 3,086,739 |   |
| Otten      |       | Dec 4, 2006    |       | 55,000      |       | 1.2              |       | US$              | 55.00      |        | Dec 3, 2011 |             | 990,017    |                                 | 984,746    |   | 2,096,479 |   |
| Murphy     |       | Dec 4, 2006    |       | 65,000      |       | 1.4              |       | 63.20            |       | Dec 3, 2011 |        | 1,184,336        |       | 1,134,965                            |       | 2,507,975 |   |
| Thomas     |       | Dec 4, 2006    |       | 65,000      |       | 1.4              |       | 63.20            |       | Dec 3, 2011 |        | 1,184,336        |       | 1,134,965                            |       | 2,507,975 |   |
|            |            |                |            |             |            |                  |            |                  |            |             |             |                  |            |                                      |            |  |  |  |

 

----

*Notes:*

*(1)**   **The closing market price of Nexen common shares on the TSXor NYSE on December 1, 2006.*

*(2)**   **Estimated fair value of the TOPs as at December 4, 2006using the Black-Scholes pricing model.*

 

 

158

----

 

**TOPs Exercised or Exchanged andAwards Vested in 2006**

 
| ** ** | ** ** | **TOPs Awards**             | ** ** | **Stock Awards (****1)**   | ** ** |
|------------|------------|-----------------------------|------------|----------------------------|------------|
| **Name**   | ** ** | **Exercised or  Exchanged** | ** ** | **Value Realized (****2)** | ** ** | **Shares Acquired  on Vesting** | ** ** | **Value Realized** | ** ** |
|       |       | **(#)**                     | ** ** | **($)**                    | ** ** | **(#)** | ** ** | **($)** |   |
| Fischer    |       | 150,000                     |       | 7,220,550                  |       | — |   | — |   |
| Romanow    |       | 180,000                     |       | 7,750,800                  |       | — |   | — |   |
| Otten      |       | 84,312                      |       | 3,813,976                  |       | — |   | — |   |
| Murphy     |       | 49,580                      |       | 2,415,041                  |       | — |   | — |   |
| Thomas     |       | 90,000                      |       | 4,637,950                  |       | — |   | — |   |

 

----

*Notes:*

*(1)**   **Nexen does not provide stock awards to its named executiveofficers.*

*(2)**   **Market price at the time of the exercise or exchange, minusthe exercise price, as defined in the TOPs plan.*

 

**Equity Ownership and Changes in2006**

 

Executive officers meet the share ownershipguidelines described on page 151. Mr. Fischer is required to hold three timeshis annual salary, Mr. Romanow is required to hold two times his annual salaryand the other executive officers are required to hold one time annual salary.

 
| ** ** | ** ** | **Dec 31, 2005** | ** ** | **Dec 31, 2006** | ** ** | **Net Change** | ** ** | **Equity at Risk** | ** ** |
|------------|------------|------------------|------------|------------------|------------|----------------|------------|--------------------|------------|
| **Name**   | ** ** | **Shares**       | ** ** | **TOPs (****1)** | ** ** | **Shares**     | ** ** | **TOPs (****1)**   | ** ** | **Shares** | ** ** | **TOPs (****2)** | ** ** | **Value****($)****(****3)** | ** ** | **Multiple of Salary (****4)** | ** ** |
| Fischer    |       | 74,141           |       | 1,146,000        |       | 83,258         |       | 1,229,000          |       | 9,117 |   | 83,000 |   | 59,947,769 |   | 52 |   |
| Romanow    |       | 46,121           |       | 492,460          |       | 25,937         |       | 407,460            |       | (20,184 | ) | (85,000 | ) | 18,837,026 |   | 36 |   |
| Otten      |       | 55,873           |       | 246,636          |       | 35,036         |       | 230,144            |       | (20,837 | ) | (16,492 | ) | 11,678,697 |   | 27 |   |
| Murphy     |       | 48,261           |       | 99,880           |       | 55,828         |       | 118,120            |       | 7,567 |   | 18,240 |   | 7,953,430 |   | 17 |   |
| Thomas     |       | 1,426            |       | 160,080          |       | 4,286          |       | 134,600            |       | 2,860 |   | (25,480 | ) | 5,233,475 |   | 12 |   |

 

----

*Notes:*

*(1)**   **Total TOPs granted, vested and unexercised.*

*(2)**   **Reflects the number of TOPs that vested, minus the numberexercised or exchanged during 2006, as also set out on page 160.*

*(3)**   **Equity at risk is the market value of common shares andvested TOPs using the closing price of Nexen shares on the TSX on December 31,2006 of $64.20.*

*(4)**   **Reflects the equity at risk divided by the named executiveofficer’s 2006 salary amount on page 156.*

 

 

159

----

 

**TOPs Holdings and Value ofIn-the-Money TOPs**

 
| ** ** | ** ** | ** **        | ** ** | ** **       | ** ** | ** **               | ** ** | ** **           | ** ** | **Vested  and Unvested   TOPs at Dec 31, 2006 (****1), (4)** | ** ** | **Vested  TOPs   at Dec 31, 2006 (4)** | ** ** |
|------------|------------|-------------------|------------|------------------|------------|--------------------------|------------|----------------------|------------|--------------------------------------------------------------|------------|----------------------------------------|------------|
| **Name**   | ** ** | **Date  Granted** | ** ** | **Expiry  Date** | ** ** | **Grant  Price (****2)** | ** ** | **Granted  (****2)** | ** ** | **Number**                                                   | ** ** | **Value (****3)**                      | ** ** | **Number** | ** ** | **Value (****3)** | ** ** |
| ** ** | ** ** | ** **        | ** ** | ** **       | ** ** | **($)**                  | ** ** | **(#)**              | ** ** | **(#)**                                                      | ** ** | **($)**                                | ** ** | **(#)** | ** ** | **($)** | ** ** |
| Fischer    |       | Feb 21, 1997      |       | Feb 20, 2007     |       | 11.900                   |       | 60,000               |       | 60,000                                                       |       | 3,138,000                              |       | 60,000 |   | 3,138,000 |   |
|       |       | May 14, 1997      |       | May 13, 2007     |       | 14.000                   |       | 40,000               |       | 40,000                                                       |       | 2,008,000                              |       | 40,000 |   | 2,008,000 |   |
|       |       | Feb 27, 1998      |       | Feb 26, 2008     |       | 14.150                   |       | 80,000               |       | 80,000                                                       |       | 4,004,000                              |       | 80,000 |   | 4,004,000 |   |
|       |       | Dec 15, 1998      |       | Dec 14, 2008     |       | 8.925                    |       | 100,000              |       | 100,000                                                      |       | 5,527,500                              |       | 100,000 |   | 5,527,500 |   |
|       |       | Dec 14, 1999      |       | Dec 13, 2009     |       | 13.625                   |       | 140,000              |       | 140,000                                                      |       | 7,080,500                              |       | 140,000 |   | 7,080,500 |   |
|       |       | Dec 12, 2000      |       | Dec 11, 2010     |       | 18.050                   |       | 140,000              |       | 140,000                                                      |       | 6,461,000                              |       | 140,000 |   | 6,461,000 |   |
|       |       | Dec 10, 2002      |       | Dec 9, 2007      |       | 16.965                   |       | 200,000              |       | 200,000                                                      |       | 9,447,000                              |       | 200,000 |   | 9,447,000 |   |
|       |       | Dec 9, 2003       |       | Dec 8, 2008      |       | 21.750                   |       | 200,000              |       | 200,000                                                      |       | 8,490,000                              |       | 200,000 |   | 8,490,000 |   |
|       |       | Dec 7, 2004       |       | Dec 6, 2009      |       | 25.435                   |       | 300,000              |       | 300,000                                                      |       | 11,629,500                             |       | 201,000 |   | 7,791,765 |   |
|       |       | Dec 6, 2005       |       | Dec 5, 2010      |       | 54.570                   |       | 200,000              |       | 200,000                                                      |       | 1,926,000                              |       | 68,000 |   | 654,840 |   |
|       |       | Dec 4, 2006       |       | Dec 3, 2011      |       | 63.200                   |       | 275,000              |       | 275,000                                                      |       | 275,000                                |       | — |   | — |   |
| **Total**  | ** ** | ** **        | ** ** | ** **       | ** ** | ** **               | ** ** | **1,735,000**        | ** ** | **1,735,000**                                                | ** ** | **59,986,500**                         | ** ** | **1,229,000** | ** ** | **54,602,605** | ** ** |
| ** ** | ** ** | ** **        | ** ** | ** **       | ** ** | ** **               | ** ** | ** **           | ** ** | ** **                                                   | ** ** | ** **                             | ** ** | ** ** | ** ** | ** ** | ** ** |
| Romanow    |       | Dec 12, 2000      |       | Dec 11, 2010     |       | 18.050                   |       | 100,000              |       | 100,000                                                      |       | 4,615,000                              |       | 100,000 |   | 4,615,000 |   |
|       |       | Dec 10, 2002      |       | Dec 9, 2007      |       | 16.965                   |       | 100,000              |       | 100,000                                                      |       | 4,723,500                              |       | 100,000 |   | 4,723,500 |   |
|       |       | Dec 9, 2003       |       | Dec 8, 2008      |       | 21.750                   |       | 110,000              |       | 110,000                                                      |       | 4,669,500                              |       | 110,000 |   | 4,669,500 |   |
|       |       | Dec 7, 2004       |       | Dec 6, 2009      |       | 25.435                   |       | 114,000              |       | 114,000                                                      |       | 4,419,210                              |       | 76,380 |   | 2,960,871 |   |
|       |       | Dec 6, 2005       |       | Dec 5, 2010      |       | 54.570                   |       | 62,000               |       | 62,000                                                       |       | 597,060                                |       | 21,080 |   | 203,000 |   |
|       |       | Dec 4, 2006       |       | Dec 3, 2011      |       | 63.200                   |       | 80,000               |       | 80,000                                                       |       | 80,000                                 |       | — |   | — |   |
| **Total**  | ** ** | ** **        | ** ** | ** **       | ** ** | ** **               | ** ** | **566,000**          | ** ** | **566,000**                                                  | ** ** | **19,104,270**                         | ** ** | **407,460** | ** ** | **17,171,871** | ** ** |
| ** ** | ** ** | ** **        | ** ** | ** **       | ** ** | ** **               | ** ** | ** **           | ** ** | ** **                                                   | ** ** | ** **                             | ** ** | ** ** | ** ** | ** ** | ** ** |
| Otten      |       | Dec 12, 2000      |       | Dec 11, 2010     |       | 18.050                   |       | 80,000               |       | 71,580                                                       |       | 3,303,417                              |       | 71,580 |   | 3,303,417 |   |
|       |       | Dec 10, 2002      |       | Dec 9, 2007      |       | US$                      | 10.945     |                 | 70,000     |                                                         | 13,964     |                                   | 698,357    |   | 13,964 |   | 698,357 |   |
|       |       | Dec 9, 2003       |       | Dec 8, 2008      |       | US$                      | 16.690     |                 | 74,000     |                                                         | 74,000     |                                   | 3,218,224  |   | 74,000 |   | 3,218,224 |   |
|       |       | Dec 7, 2004       |       | Dec 6, 2009      |       | US$                      | 21.160     |                 | 80,000     |                                                         | 80,000     |                                   | 3,073,213  |   | 53,600 |   | 2,059,053 |   |
|       |       | Dec 6, 2005       |       | Dec 5, 2010      |       | US$                      | 47.210     |                 | 50,000     |                                                         | 50,000     |                                   | 442,160    |   | 17,000 |   | 150,335 |   |
|       |       | Dec 4, 2006       |       | Dec 3, 2011      |       | US$                      | 55.000     |                 | 55,000     |                                                         | 55,000     |                                   | —     |   | — |   | — |   |
| **Total**  | ** ** | ** **        | ** ** | ** **       | ** ** | ** **               | ** ** | **409,000**          | ** ** | **344,544**                                                  | ** ** | **10,735,371**                         | ** ** | **230,144** | ** ** | **9,429,386** | ** ** |
| ** ** | ** ** | ** **        | ** ** | ** **       | ** ** | ** **               | ** ** | ** **           | ** ** | ** **                                                   | ** ** | ** **                             | ** ** | ** ** | ** ** | ** ** | ** ** |
| Murphy     |       | Dec 10, 2002      |       | Dec 9, 2007      |       | 16.965                   |       | 70,000               |       | 23,100                                                       |       | 1,091,129                              |       | 23,100 |   | 1,091,129 |   |
|       |       | Dec 9, 2003       |       | Dec 8, 2008      |       | 21.750                   |       | 74,000               |       | 24,420                                                       |       | 1,036,629                              |       | 24,420 |   | 1,036,629 |   |
|       |       | Dec 7, 2004       |       | Dec 6, 2009      |       | 25.435                   |       | 80,000               |       | 80,000                                                       |       | 3,101,200                              |       | 53,600 |   | 2,077,804 |   |
|       |       | Dec 6, 2005       |       | Dec 5, 2010      |       | 54.570                   |       | 50,000               |       | 50,000                                                       |       | 481,500                                |       | 17,000 |   | 163,710 |   |
|       |       | Dec 4, 2006       |       | Dec 3, 2011      |       | 63.200                   |       | 65,000               |       | 65,000                                                       |       | 65,000                                 |       | — |   | — |   |
| **Total**  | ** ** | ** **        | ** ** | ** **       | ** ** | ** **               | ** ** | **339,000**          | ** ** | **242,520**                                                  | ** ** | **5,775,458**                          | ** ** | **118,120** | ** ** | **4,369,272** | ** ** |
| ** ** | ** ** | ** **        | ** ** | ** **       | ** ** | ** **               | ** ** | ** **           | ** ** | ** **                                                   | ** ** | ** **                             | ** ** | ** ** | ** ** | ** ** | ** ** |
| Thomas     |       | Dec 9, 2003       |       | Dec 8, 2008      |       | 21.750                   |       | 64,000               |       | 64,000                                                       |       | 2,716,800                              |       | 64,000 |   | 2,716,800 |   |
|       |       | Dec 7, 2004       |       | Dec 6, 2009      |       | 25.435                   |       | 80,000               |       | 80,000                                                       |       | 3,101,200                              |       | 53,600 |   | 2,077,804 |   |
|       |       | Dec 6, 2005       |       | Dec 5, 2010      |       | 54.570                   |       | 50,000               |       | 50,000                                                       |       | 481,500                                |       | 17,000 |   | 163,710 |   |
|       |       | Dec 4, 2006       |       | Dec 3, 2011      |       | 63.200                   |       | 65,000               |       | 65,000                                                       |       | 65,000                                 |       | — |   | — |   |
| **Total**  | ** ** | ** **        | ** ** | ** **       | ** ** | ** **               | ** ** | **259,000**          | ** ** | **259,000**                                                  | ** ** | **6,364,500**                          | ** ** | **134,600** | ** ** | **4,958,314** | ** ** |
|            |            |                   |            |                  |            |                          |            |                      |            |                                                              |            |                                        |            |  |  |  |  |  |  |  |  |  |

 

----

*Notes:*

*(1)**   **Excludes grants that have been fully exercised.*

*(2)**   **Grant prices and numbers of TOPs granted have been adjustedto account for share splits.*

*(3)**   **The difference between the market value of Nexen commonshares at year end (TSX—$64.20; NYSE—US $55.00) and the grant price of TOPs,times the number of TOPs.*

*(4)**   **The number and value of unvested TOPs can be determined bysubtracting the vested TOPs from the vested and unvested TOPs above. The valueof unvested TOPs can be confirmed on page 164 in the Change of Control table.*

* *

160

----

 

**Pension Plan Tables**

 

All named executive officers, except Mr. Otten,are members of Nexen’s registered defined benefit pension plan and executivebenefit plan. Mr. Otten is employed in the US and is a member of a qualifieddefined contribution pension plan and a non-qualified restoration plan,described on page 154.

 

**Estimated Pension Benefit(Canada)**

 

When determining the estimated value of futurepension benefits for an executive officer, both tables below need to bereferenced. For example, a pension estimate based on 35 years of creditedservice would require the first table for actual credited service up to andincluding December 31, 2004, and the second table for credited service on andafter January 1, 2005. When estimating future pension benefits, the finalaverage earnings outlined in the “Pension Value Earned in 2006 (Canada)” tableon page 162 should be used in both tables. The final average earnings willdiffer from the three-year average of base salary and cash incentive paymentsreported in the summary compensation table on page 156 due to the timing ofbase salary increases and because final average earnings include the lesser oftarget bonus and actual bonus paid.

 

This table shows the estimated annual pension aretiring executive officer would receive for credited service to and includingDecember 31, 2004. The annual benefit is based on a pension accrualformula of 1.7% of final average earnings, less a plan CPP offset. It includesbenefits from both the defined benefit pension plan and the executive benefitplan and assumes a retirement age of 60, the earliest age at which theindividual receives full retirement benefits. The normal benefits paid fromthese plans are joint life and survivor benefits with a five-year guarantee.The benefit is payable for the participant’s lifetime and provides the spousewith a survivor benefit of 66 2/3% of the monthly payment. The five-yearguarantee means that if the participant dies before receiving 60 monthlypayments, the surviving spouse receives the balance of those 60 monthlypayments and then receives the reduced survivor pension of 66 2/3%.

 
| ** **                                        | ** ** | **Years of Credited Service through Dec 31, 2004** | ** ** |
|---------------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|
| **Final Average Earnings ****($)** | ** ** | **5**                                                                                 | ** ** | **10** | ** ** | **15** | ** ** | **20** | ** ** | **25** | ** ** |
| 400,000                                           |       |                                                                                  | 33,276     |   | 66,552 |   | 99,828 |   | 133,104 |   | 166,380 |   |
| 600,000                                           |       |                                                                                  | 50,276     |   | 100,552 |   | 150,828 |   | 201,104 |   | 251,380 |   |
| 800,000                                           |       |                                                                                  | 67,276     |   | 134,552 |   | 201,828 |   | 269,104 |   | 336,380 |   |
| 1,000,000                                         |       |                                                                                  | 84,276     |   | 168,552 |   | 252,828 |   | 337,104 |   | 421,380 |   |
| 1,200,000                                         |       |                                                                                  | 101,276    |   | 202,552 |   | 303,828 |   | 405,104 |   | 506,380 |   |
| 1,400,000                                         |       |                                                                                  | 118,276    |   | 236,552 |   | 354,828 |   | 473,104 |   | 591,380 |   |
| 1,600,000                                         |       |                                                                                  | 135,276    |   | 270,552 |   | 405,828 |   | 541,104 |   | 676,380 |   |
| 1,800,000                                         |       |                                                                                  | 152,276    |   | 304,552 |   | 456,828 |   | 609,104 |   | 761,380 |   |
| 2,000,000                                         |       |                                                                                  | 169,276    |   | 338,552 |   | 507,828 |   | 677,104 |   | 846,380 |   |
| 2,200,000                                         |       |                                                                                  | 186,276    |   | 372,552 |   | 558,828 |   | 745,104 |   | 931,380 |   |
| 2,400,000                                         |       |                                                                                  | 203,276    |   | 406,552 |   | 609,828 |   | 813,104 |   | 1,016,380 |   |

 

161

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This table shows the estimated annual pensionbenefit a retiring executive officer would receive for credited service earnedon and after January 1, 2005, based on a pension benefit accrual formula of 2%of final average earnings, less a plan CPP offset. It includes benefits fromboth the defined benefit plan and executive benefit plan and assumes aretirement age of 60, the earliest age at which the individual receives fullretirement benefits.

 
| ** **                                        | ** ** | **Years of Credited Service from Jan 1, 2005** | ** ** |
|---------------------------------------------------|------------|-----------------------------------------------------------------------------------|------------|
| **Final Average Earnings ****($)** | ** ** | **2**                                                                             | ** ** | **5** | ** ** | **10** | ** ** | **15** | ** ** | **20** | ** ** | **25** | ** ** |
| 400,000                                           |       |                                                                              | 15,710     |   | 39,276 |   | 78,552 |   | 117,828 |   | 157,104 |   | 196,380 |   |
| 600,000                                           |       |                                                                              | 23,710     |   | 59,276 |   | 118,552 |   | 177,828 |   | 237,104 |   | 296,380 |   |
| 800,000                                           |       |                                                                              | 31,710     |   | 79,276 |   | 158,552 |   | 237,828 |   | 317,104 |   | 396,380 |   |
| 1,000,000                                         |       |                                                                              | 39,710     |   | 99,276 |   | 198,552 |   | 297,828 |   | 397,104 |   | 496,380 |   |
| 1,200,000                                         |       |                                                                              | 47,710     |   | 119,276 |   | 238,552 |   | 357,828 |   | 477,104 |   | 596,380 |   |
| 1,400,000                                         |       |                                                                              | 55,710     |   | 139,276 |   | 278,552 |   | 417,828 |   | 557,104 |   | 696,380 |   |
| 1,600,000                                         |       |                                                                              | 63,710     |   | 159,276 |   | 318,552 |   | 477,828 |   | 637,104 |   | 796,380 |   |
| 1,800,000                                         |       |                                                                              | 71,710     |   | 179,276 |   | 358,552 |   | 537,828 |   | 717,104 |   | 896,380 |   |
| 2,000,000                                         |       |                                                                              | 79,710     |   | 199,276 |   | 398,552 |   | 597,828 |   | 797,104 |   | 996,380 |   |
| 2,200,000                                         |       |                                                                              | 87,710     |   | 219,276 |   | 438,552 |   | 657,828 |   | 877,104 |   | 1,096,380 |   |
| 2,400,000                                         |       |                                                                              | 95,710     |   | 239,276 |   | 478,552 |   | 717,828 |   | 957,104 |   | 1,196,380 |   |

 

**Pension Value Earned in 2006(Canada)**

 

Additional past service credits or acceleratedservice credits must be approved by the board. No accelerated service creditswere authorized in 2006. Additional past service credits authorized by theboard for the named executive officers who participate in the Canadian definedbenefit pension plan and the executive benefit plan are noted below. Finalaverage earnings for each named executive officer is his:

 

•    average base salary for the 36 highestpaid consecutive months during the ten years before retirement;

•    plus annual cash incentive payments at thelesser of target bonus or actual bonus paid, averaged over the final threeyears of participation.

 
| **Name**                   | ** ** | **Years of Credited Service** | ** ** | **Final  Average  Earnings (****1)** | ** ** | **Accrued Annual  Pension Benefit (****1)** | ** ** | **Estimated Annual  Pension Benefit  at Age 60 (****2)** | ** ** | **Benefit Payments  During the Last  Fiscal Year (****3)** | ** ** |
|----------------------------|------------|----------------------------------------------|------------|-------------------------------------------|------------|------------------------------------------------------------|------------|------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|
| **Up to**             | ** ** | **From**                                     | ** ** | ** **                                |
| **Dec 31, 2004** | ** ** | **Jan 1, 2005**                    | ** ** | **Total**                                 |
| ** **                 | ** ** | **(#)**                                      | ** ** | **(#)**                                   | ** ** | **(#)**                                                    | ** ** | **($)**                                                                      | ** ** | **($)**                                                                             | ** ** | **($)** | ** ** | **($)** | ** ** |
| Fischer                    |       | 20.58                                        | (4)        | 2.00                                      |       | 22.58                                                      |       | 1,628,472                                                                    |       | 631,698                                                                             |       | 951,321 |   | — |   |
| Romanow(5)                 |       | 17.50                                        | (4)        | 2.00                                      |       | 19.50                                                      |       | 743,267                                                                      |       | 278,977                                                                             |       | 476,898 |   | — |   |
| Murphy                     |       | 18.67                                        |       | 2.00                                      |       | 20.67                                                      |       | 585,100                                                                      |       | 206,087                                                                             |       | 310,285 |   | — |   |
| Thomas                     |       | 24.50                                        | (4)        | 2.00                                      |       | 26.50                                                      |       | 569,367                                                                      |       | 256,079                                                                             |       | 392,713 |   | — |   |

 

----

*Notes:*

*(1)**   **All information as of December 31, 2006.*

*(2)**   **Earliest age at which an individual receives full retirementbenefits.*

*(3)**   **There were no benefit payments made to the named executiveofficers in 2006.*

*(4)**   **Ten years of additional past service credits were granted toeach of Messrs. Fischer, Romanow and Thomas by the board in 2001.*

*(5)**   **Mr. Romanow joined the defined benefit pension planfollowing 7.25 year in the defined contribution pension plan. The pensionablebonus provision recognizes a pension benefit for Mr. Romanow based on hiscombined 26.75 years of service, while the base salary provision recognizes apension benefit for his 19.5 years of defined benefit pension plan service only.The value of the pension benefit resulting from the additional 7.25 years isreflected in the pension benefit values above.*

 

162

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**Pension Benefit ObligationIncrease in 2006 (Canada)**

 

Reported values use actuarial assumptions andmethods consistent with those used in the calculation of pension liabilitiesand the related annual expense as disclosed in our financial statements. As theassumptions reflect our best estimate of future events, they may not be directlycomparable to similar pension liability values disclosed by other companies.

 
| **Name**  | ** ** | **Obligation at  Dec 31, 2005** | ** ** | **Changes Related to  Current Service  Cost and Earnings  Increases (****1)** | ** ** | **Changes Related to  Financing Costs and  Non-Compensation  Assumption  Changes (****2)** | ** ** | **Change in Obligation  since Dec 31, 2005** | ** ** | **Obligation at  Dec 31, 2006** | ** ** |
|-----------|------------|------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|------------------------------------------------|------------|
| Fischer   |       | 8,687,000                                      |       | 1,673,800                                                                                                   |       | 797,000                                                                                                             |       | 2,470,800                                                             |       | 11,157,800                                     |       |
| Romanow   |       | 3,464,000                                      |       | 534,800                                                                                                     |       | 298,000                                                                                                             |       | 832,800                                                               |       | 4,296,800                                      |       |
| Murphy    |       | 2,502,000                                      |       | 580,800                                                                                                     |       | 205,000                                                                                                             |       | 785,800                                                               |       | 3,287,800                                      |       |
| Thomas    |       | 3,209,000                                      |       | 735,800                                                                                                     |       | 251,000                                                                                                             |       | 986,800                                                               |       | 4,195,800                                      |       |
| **Total** | ** ** | **17,862,000**                                 | ** ** | **3,525,200**                                                                                               | ** ** | **1,551,000**                                                                                                       | ** ** | **5,076,200**                                                         | ** ** | **22,938,200**                                 | ** ** |

 

----

*Notes:*

*(1)**   **Includes the 2006 employer service cost, plus changes incompensation in excess of actuarial assumptions, less required membercontributions to the pension plan.*

*(2)**   **Reflects the impact of interest on prior year’s obligations,changes in discount rates used to measure the obligations, the impact ofassumption changes and experience gains and losses other than those related tocompensation.*

 

**Pension Value Earned in 2006(US)**

 

Mr. Otten is the only named executive officerwho is a member of this US pension plan. He has not made any withdrawals in2006.

 
| **Name** | ** ** | **Contributions under the Defined  Contribution Pension Plan** | ** ** | **Contributions under the  Non-Qualified Restoration Plan** | ** ** | **Total Pension Compensation** | ** ** |
|----------|------------|-----------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|------------------------------------------|------------|
| Otten    |       | 22,839                                                                                  |       | 44,888                                                                          |       | 67,727                                   |       |

 

**All Other Compensation Table**

 

The total value of perquisites provided to anyone executive officer was less than both $50,000 or 10% of the named executiveofficer’s total annual salary plus bonus in 2006 and, accordingly, is notdisclosed. The car allowance, which provides direct monetary value to theexecutive, is reported.

 
| **Name** | ** ** | **Car  Allowance** | ** ** | **Life Insurance  Premiums** | ** ** | **Savings Plan  Contributions** | ** ** | **Amounts Paid  by Canexus** | ** ** | **US Pension  Contributions** | ** ** | **Total All Other  Compensation** | ** ** |
|----------|------------|--------------------|------------|-----------------------------------|------------|--------------------------------------|------------|----------------------------------------|------------|------------------------------------|------------|---------------------------------------------|------------|
| Fischer  |       | 31,200             |       | 1,521                             |       | 69,000                               |       | —                                 |       | —                             |       | 101,721                                     |       |
| Romanow  |       | 19,200             |       | 522                               |       | 31,680                               |       | 60,571                                 |       | —                             |       | 111,973                                     |       |
| Otten    |       | 16,347             |       | 2,670                             |       | 13,559                               |       | —                                 |       | 67,727                             |       | 100,303                                     |       |
| Murphy   |       | 19,200             |       | 1,111                             |       | 27,300                               |       | —                                 |       | —                             |       | 47,611                                      |       |
| Thomas   |       | 19,200             |       | 1,086                             |       | 26,700                               |       | —                                 |       | —                             |       | 46,986                                      |       |

 

----

*Note:*

*(1)**   **Includes fees of $34,000, deferred trust units of Canexusvalued at $24,000 and distributions on his trust units of $2,571.*

 

**CHANGE OF CONTROLAGREEMENTS**

 

Nexen has entered into change of controlagreements with Messrs. Fischer, Romanow, Otten, Murphy, Thomas and other keyexecutives. The agreements were effective October 1999, amended in December2000 and amended and restated in December 2001. The agreements recognize thatthese executives are critical to Nexen’s ongoing business. They recognize theneed to retain the executives, protect them from employment interruption causedby a change in control and treat them in a fair and 

 

163

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equitablemanner. Consistent with industry standards for executives in similarcircumstances, there are no restrictions on future employment or non-competeclauses in the agreements. Each year, the Committee reviews the estimatedpayments on change of control including the termination value of pensionbenefits due under the registered pension and executive benefit plans.

 

Under these agreements, a change of controlincludes any acquisition of common shares or other securities that carry theright to cast more than 35% of the votes attached to all issued common sharesand generally, any event, transaction or arrangement that results in a personor group exercising effective control of Nexen.

 

If the named executives terminate following achange in control, they are entitled to receive salary, target bonus andbenefits for a specified severance period. For Mr. Fischer and Mr. Romanow, theseverance period is 36 months if they are terminated. Both of them may alsovoluntarily terminate their employment within 12 months following a change ofcontrol with severance periods of 36 and 30 months, respectively. For Messrs.Otten, Murphy and Thomas, the severance period is 30 months, only if they areterminated following a change of control.

 

The table below outlines the estimatedincremental payments had a change of control occurred on December 31, 2006. Thecost of base salary, bonus and benefits represents the value of thosecompensation elements for the duration of the severance period. Under the termsof the agreement, bonus is paid at target for the severance period. A benefitsuplift, equal to 13% of base salary, is provided in lieu of medical, dental andlife insurance coverage. In addition, the agreement provides a payment forother employee benefits, which includes such items as car allowance and savingsplan contributions during the severance period and an allowance for financialcounselling and career transition services.

 

The pension value reported is the incrementalvalue of pension resulting from the recognition of salary and target bonus overthe severance period, as well as a tax gross-up on the resulting lump sumpayout. These additional pension benefits do not include the terminationbenefits payable from the underlying registered pension plan and executivebenefit plan that would occur in the event of a termination or retirement nottriggered by a change of control. Regular termination values, calculated as atDecember 31, 2006, are set out in the footnotes to the following table. Thetable does not include TOPs currently vested and unexercised as described onpage 160.

 

**Estimated Incremental Paymenton Change of Control (****1)**

 
| **Name**    | ** ** | **Severance  Period**       | ** ** | **Base Salary** | ** ** | **Bonus  Target Value** | ** ** | **Benefits  Uplift** | ** ** | **Other  Employee  Benefits** | ** ** | **Additional  Lump Sum  Value of  Pension (****2)** | ** ** | **Accelerated  TOPs Value (****3)** | ** ** | **Total  Incremental  Payment** | ** ** |
|-------------|------------|-----------------------------|------------|----------------------|------------|------------------------------|------------|----------------------|------------|-------------------------------|------------|--------------------------------------------------------------------|------------|-----------------------------------------------|------------|---------------------------------|------------|
| ** **  | ** ** | **(# of months)** | ** ** | **($)**              | ** ** | **($)**                      | ** ** | **($)**              | ** ** | **($)**                       | ** ** | **($)**                                                            | ** ** | **($)**                                       | ** ** | **($)**                         | ** ** |
| Fischer (4) |       | 36                          |       | 3,600,000            |       | 2,700,000                    |       | 468,000              |       | 347,500                       |       | 9,426,000                                                          |       | 5,383,895                                     |       | 21,925,395                      |       |
| Romanow     |       | 36                          |       | 1,620,000            |       | 972,000                      |       | 210,600              |       | 192,700                       |       | 3,563,000                                                          |       | 1,932,399                                     |       | 8,490,699                       |       |
| Otten (5)   |       | 30                          |       | 1,135,200            |       | 567,600                      |       | 147,576              |       | 165,626                       |       | 181,119                                                            |       | 1,305,985                                     |       | 3,503,106                       |       |
| Murphy      |       | 30                          |       | 1,175,000            |       | 587,500                      |       | 152,750              |       | 156,400                       |       | 2,410,000                                                          |       | 1,406,186                                     |       | 5,887,836                       |       |
| Thomas      |       | 30                          |       | 1,150,000            |       | 575,000                      |       | 149,500              |       | 154,900                       |       | 3,095,000                                                          |       | 1,406,186                                     |       | 6,530,586                       |       |
| **Total**   | ** ** | ** **                  | ** ** | **8,680,200**        | ** ** | **5,402,100**                | ** ** | **1,128,426**        | ** ** | **1,017,126**                 | ** ** | **18,675,119**                                                     | ** ** | **11,434,651**                                | ** ** | **46,337,622**                  |       |

 

----

*Notes:*

*(1)**   **Assumes a triggering event occurred on December 31, 2006.*

*(2)**   **Does not include regular termination pension values forMessrs. Fischer ($9,850,000), Romanow ($3,108,000), Murphy ($3,013,000) andThomas ($3,188,000). The values in this note include the pension benefitpayable under the registered pension plan funded from the pension trust and arepayable monthly if the named executive officer is 55 or older.*

*(3)**   **Value of TOPs that automatically vest on a change ofcontrol, based on the number of TOPs with accelerated vesting, times theclosing price of Nexen common shares on the TSX on December 31, 2006 of $64.20,less the exercise price.*

*(4)**   **For Mr. Fischer only, the additional lump sum value ofpension includes an incremental cost for an early retirement reduction that iswaived under the agreement.*

*(5)**   **Mr. Otten is a member of the Defined Contribution PensionPlan (US) and the Non-Qualified Restoration Plan.*

 

 

164

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| Corporate  Governance |   | Share  Performance |
|-----------------------|--------|--------------------|

 

**SHARE PERFORMANCE GRAPH**

 

The following graph shows five years of changein the value of $100 invested in our common shares, compared to the S&P/TSXComposite Index, the S&P/TSX Energy Sector Index and the S&P/TSX Oil& Gas Exploration & Production Index as at December 31, 2006. Ourcommon shares are included in each of these indices.

 

**Total Return Index Values****(1)**

 

 
| ** **                                                          | ** ** | **2001/12** | ** ** | **2002/12** | ** ** | **2003/12** | ** ** | **2004/12** | ** ** | **2005/12** | ** ** | **2006/12** | ** ** |
|---------------------------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|
|  Nexen Inc.                                                    |       | 100.00      |       | 111.08      |       | 153.52      |       | 160.59      |       | 367.13      |       | 426.65      |       |
|  S&P/TSX Energy Sector Index                               |       | 100.00      |       | 113.74      |       | 142.14      |       | 185.19      |       | 302.67      |       | 321.00      |       |
|  S&P/TSX Oil & Gas Exploration &  Production Index |       | 100.00      |       | 116.17      |       | 139.58      |       | 196.35      |       | 340.96      |       | 345.47      |       |
|  S&P/TSX Composite Index                                   |       | 100.00      |       | 87.56       |       | 110.96      |       | 127.03      |       | 157.68      |       | 184.89      |       |

 

----

*Note:*

*(1)**   **Assuming an investment of $100 and the reinvestment ofdividends.*

 

**CORPORATE GOVERNANCE**

 

Nexen’s board takes its duties andresponsibilities for good corporate governance seriously. Nexen supports andconducts business according to the rules of the Toronto Stock Exchange (TSX),NYSE, *National Policy 58-201—CorporateGovernance Guidelines*and *MultilateralInstrument 52-110—Audit Committees*. Except as noted below withregard to DSUs, Nexen’s corporate governance practices comply with the corporategovernance practices followed by domestic companies under NYSE listingstandards.

 

Nexen has a DSU plan for non-executive directorsas described on page 146. For this plan, Nexen follows the TSX rules which,unlike the NYSE rules, exempt plans from shareowner approval where the commonshares issued under the plan are purchased on the open market rather thanissuing new shares.

 

On February 26, 2007, our CEO certified to theNYSE that he was unaware of any violation by Nexen of the NYSE’s corporate governancelisting standards. Nexen also provided the required Annual Written Affirmationto the NYSE on February 26, 2007. Nexen also filed an Interim WrittenAffirmation on April 28, 2006. As well, our CEO and CFO have certified thequality of Nexen’s public disclosure to the SEC.

 

All Committee Mandates, including those for theAudit, Compensation and Governance Committees, and our corporate governancepolicy and categorical standards are available at www.nexeninc.com, and weintend to provide disclosure in this manner. Shareowners wishing to receive acopy of these documents may contact the Governance Office by telephone at403.699.4926, by facsimile at 403.699.7062 or by email atgovernance@nexeninc.com.

 

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| Items 10 to  15 |   | Corporate  Governance |   | Governance  Committee Report |
|-----------------|--------|-----------------------|--------|------------------------------|

 

**GOVERNANCE COMMITTEEREPORT**

 

The Governance Committee assists the board inoverseeing implementation of our corporate governance programs, recommendingnominees for director appointments and evaluating the board, its committees andall individual directors and chairs, to ensure Nexen is implementingbest-in-class corporate governance practices.

 

**Principles and Systems for theManagement of Corporate Governance**

 

Nexen’s board and management are committed tobest practices in corporate governance as evidenced by the Committee’s annualactivities and its commitment to continuous improvement.

 

**Key Activities in 2006**

 

•    Recommended changes to membership on thecommittees;

•    Recommended the appointment of A. AnneMcLellan, P.C. to the board;

•    Recommended the adoption of a modifiedmajority vote by-law for the election of directors;

•    Recommended revisions to the corporategovernance policy and external communications policy;

•    Recommended revised mandates or positiondescriptions for the board, individual directors, all board committees, thechairs, CEO, CFO and Secretary; and

•    Consulted with Dr. Richard Leblanc,Assistant Professor of Corporate Governance, York University, on the board’sperformance evaluations.

 

**Identifying QualifiedCandidates for Board and Committee Appointments**

 

The Committee reviews the make up of the boardand committee appointments of all directors annually and makes recommendationsto the board. The Committee considers the independence tests set out in ourcategorical standards, together with the skills and preferences of thedirectors, in making its recommendations. The board is comprised of 12directors, which is large enough to permit a diversity of views and staff thecommittees, without being so large as to detract from efficiency andeffectiveness. A skills matrix that sets out the various areas of expertisedetermined to be essential to ensure appropriate strategic direction andoversight is completed by all directors annually and reviewed by the Committee.The Committee’s review of board experience indicates that the current skillsmix is appropriate. The skills matrix is also used to assist with boardrecruitment. Character and behavioural qualities, including credibility,integrity and communication skills are also taken into account when recruitingnew directors.

 

The Committee maintains an evergreen list ofpotential board directors comprised of people who the Committee recommends tobe asked to join the board when they are available and whose skills wouldcomplement the board.

 

The Committee will consider any nominee forelection as a director recommended by a shareowner. See page 168 forcommunicating with the board.

 

In 2006, the composition of committees wasrevised, in part, to allow for committee chair rotation and to addressshareowner concerns with former Nexen CEOs on independent committees. Inaddition to the changes to the Compensation Committee, noted in their report,the following changes were made:

 

•    Mr. Flanagan left as the Reserves Chair;

•    Mr. Hentschel left Audit and Compensation,and joined Finance;

•    Mr. Jenkins left as Finance Chair andjoined Compensation as its Chair;

•    Mr. O’Neill moved from SESR toCompensation;

•    Mr. Willson left Finance and SESR, andcame off as Compensation Chair; he joined Audit and Governance and becameReserves Chair; and

•    Mr. Zaleschuk left Compensation andGovernance, joined SESR, and became Finance Chair.

 

166

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**Performance Evaluations**

 

The Committee conducts an annual six-partperformance evaluation review during the period from October through Januarydesigned to enable the board and individual directors to examine theireffectiveness and establish goals for continuous improvement. The effectivenesscriteria incorporate current best practices and Nexen’s current governancedocuments.

 

**External Recognition andVerification**

 

Nexen was recognized for its governance practicesduring 2006, including the following:

 

•    Named sixth on the list of the Top 25Boards in Canada by Canadian Business Magazine;

•    Acknowledged by the Canadian Coalition forGood Governance for seven best practices and two innovations in shareownercommunication and two best practices in compensation disclosure;

•    Had an average 2006 global rating of 9.9out of 10 and have a current rating of 10 from GovernanceMetrics Internationalfor governance practices and disclosure; and

•    John McWilliams, Q.C., received theCanadian General Counsel Award for Corporate Governance.

 

**Committee Approval**

 

The Committee has reviewed and discussed thegovernance disclosure included in this document and has recommended to theboard that it be included in the Form 10-K.

 

**Submitted on behalf of theGovernance Committee:**

 
| Dick Thomson, Chair |   |
|---------------------|--------|
| Dennis Flanagan     |   |
| Kevin Jenkins       |   |
| Anne McLellan       |   |
| Tom O’Neill    |   |
| Francis Saville     |   |
| John Willson        |   |

 

**Ethics Policy**

 

Under our ethics policy, all directors, officersand employees must demonstrate a commitment to ethical business practices andbehaviour in all business relationships, both within and outside of Nexen.Employees are not permitted to commit an unethical, dishonest or illegal act orto instruct other employees to do so. Our ethics policy has been adopted as acode of ethics for our principal executive officer, principal financial officerand principal accounting officer or controller.

 

Any waivers of, or changes to the ethics policymust be board approved and disclosed. There have been no waivers sinceJanuary 1, 2006, or ever. The ethics policy was amended on February 14,2007. We made minor revisions to the integrity-related policies section,re-wrote the prevention of improper payments policy description, and addedsubsections for the gifts and entertainment and information technologyacceptable use policies. Our ethics policy provides for an external integrityhotline, since February 1, 2005.

 

Nexen’s ethics policy is available atwww.nexeninc.com and we intend to disclose any waivers of or changes to thispolicy online. Our ethics policy and any future amendments to it are filed onSEDAR at www.sedar.com. To request a copy of the policy, contact the GovernanceOffice by calling 403.699.4926, faxing 403.699.7062 or emailinggovernance@nexeninc.com.

 

167

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**Reporting Concerns**

 

Please direct any concerns about Nexen’sfinancial statements, accounting practices or internal controls to either: (i)management or the Chair of the Audit Committee as set out in the ethics policy;or, (ii) EthicsPoint, as set out below.

 

Employees, customers, suppliers, partners,shareowners and other external stakeholders who have a concern, are encouragedto raise it with our Integrity Resource Centre:

 
| By mail:           | Nexen Inc.  801 - 7th Avenue SW  Calgary, Alberta, Canada  T2P 3P7  Attention: Integrity Resource Centre |
|--------------------|------------------------------------------------------------------------------------------------------------------------------|
| By email:          | integrity@nexeninc.com                                                                                                       |
| By telephone: | 403.699.4727                                                                                                                 |

 

You may also report concerns through ourintegrity hotline – a secure reporting system, which is owned and managed byEthicsPoint, an independent third-party service provider. To find out moreabout our integrity hotline and for toll free numbers for other countries,access our web site at www.nexeninc.com and click on the “Integrity Hotline”link at the top of the page or access the hotline directly:

 
| Online:                 | www.ethicspoint.com             |
|-------------------------|---------------------------------|
| By toll-free telephone: | 1.866.384.4277  (North America) |

 

**Communicating with the Board**

 

Shareowners may write to the board or any memberor members of the board in care of the following address:

 
| By mail:  | Nexen Inc.  801 - 7th Avenue SW  Calgary, Alberta, CanadaT2P 3P7   Attention: John B. McWilliams, Q.C.  Senior Vice President, General Counsel and Secretary |
|-----------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| By email: | board@nexeninc.com                                                                                                                                                               |

 

We receive a number of inquiries on a largerange of subjects every day. The board has consulted with management to developa process to assist in managing inquiries directed to the board or its members.

 

Letters and emails addressed to the board, anyof its members or the independent directors, as a group, are reviewed todetermine if a response from the board is appropriate. While the board overseesmanagement, it does not participate in our day-to-day functions and operationsand is not normally in the best position to respond to inquiries on thosematters. Those inquiries will be directed to the appropriate personnel forresponse. The board has instructed the Secretary to review all correspondenceand, in his discretion, not forward items that are:

 

•    not relevant to Nexen’s operations,policies or philosophies;

•    commercial in nature; or

•    not appropriate for consideration by theboard.

 

All inquiries will receive a response from theboard or management. The Secretary maintains a log of all correspondence sentto board members. Directors may review the log at any time and request copiesof any correspondence received.

 

**Audit Committee**

 

See page 171 for a full report on the AuditCommittee.

 

168

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**ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS  AND MANAGEMENT AND RELATED STOCKHOLDERMATTERS**

 

**SECURITY OWNERSHIP OFCERTAIN BENEFICIAL OWNERS**

 

Nexen’s common shares are the only class ofvoting securities. Based on information known to Nexen, the following tableshows each person or group who beneficially owns (pursuant to SEC Regulations)more than 5% of Nexen’s voting securities at December 31, 2006.

 
| **Name and Address of Beneficial Owner**                                          | ** ** | **# of Shares  Beneficially Owned** | ** ** | **% of Shares** | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------|------------|---------------------------|------------|
| Ontario Teachers’  Pension Plan Board (1)  5650 Yonge Street  Toronto, Ontario, Canada, M2M 4H5       |       | 30,088,836                                         |       | 11.5                      | %          |
|                                                                                                       |       |                                               |       |                      |       |
| Jarislowsky,  Fraser Limited (2)Suite 2005, 1010 Sherbrooke Street West  Montreal, Quebec, Canada, H3A 2R7 |       | 29,363,678                                         |       | 11.19                     | %          |
|                                                                                                       |       |                                               |       |                      |       |
| Capital  Research and Management Company (3)333 South Hope Street  Los Angeles, California, USA, 90071     |       | 13,697,880                                         |       | 5.2                       | %          |

 

----

*Notes:*

*(1)**   **The beneficial owner has sole voting and power to dispose ofall shares.*

*(2)**   **The beneficial owner has sole voting power over 24,054,458shares, shared voting power over 5,309,220 shares and sole power to dispose ofall shares.*

*(3)**   **The beneficial owner has sole voting power over 5,187,360shares, sole power to dispose of all shares and disclaims beneficial ownershippursuant to Rule 13d-4.*

 

**SECURITY OWNERSHIP OFMANAGEMENT**

 

At February 15, 2007, the following directors,certain executive officers, and all directors and executive officers as a groupbeneficially owned the following Nexen common shares:

 
| **Name of Beneficial Owner**                   | ** ** | **Number of Shares (****1)** | ** ** | **Exercisable TOPs (****2)** | ** ** |
|---------------------------------------------------------------|------------|---------------------------------------------|------------|----------------------------------------|------------|
| Charles W. Fischer                                            |       | 83,581                                      |       | 1,169,000                              |       |
| Dennis G. Flanagan                                            |       | 12,002                                      |       | 13,630                                 |       |
| David A. Hentschel                                            |       | 11,380                                      |       | 61,000                                 |       |
| S. Barry Jackson                                              |       | 25,000                                      |       | 11,000                                 |       |
| Kevin J. Jenkins                                              |       | 6,166                                       |       | 41,000                                 |       |
| A. Anne McLellan, P.C.                                        |       | —                                      |       | —                                 |       |
| Eric P. Newell, O.C.                                          |       | 6,000                                       |       | —                                 |       |
| Thomas C. O’Neill                                        |       | 8,000                                       |       | 11,000                                 |       |
| Francis M. Saville, Q.C.                                      |       | 20,800                                      |       | 39,132                                 |       |
| Richard M. Thomson, O.C.                                      |       | 46,002                                      |       | 91,600                                 |       |
| John M. Willson                                               |       | 14,002                                      |       | 3,666                                  |       |
| Victor J. Zaleschuk                                           |       | 31,451                                      |       | 120,000                                |       |
| Laurence Murphy                                               |       | 55,946                                      |       | 118,120                                |       |
| Douglas B. Otten                                              |       | 35,036                                      |       | 230,144                                |       |
| Marvin F. Romanow                                             |       | 26,068                                      |       | 407,460                                |       |
| Roger D. Thomas                                               |       | 4,395                                       |       | 134,600                                |       |
| All directors and executive officers as a  group (22 persons) |       | 487,944                                     |       | 2,940,372                              |       |

 

----

*Notes:*

*(1)**   **The number of shares held and TOPs exercisable by eachbeneficial owner represents less than 1% of the shares outstanding.*

*(2)**   **Includes all TOPs exercisable within 60 days of February 15,2007. All TOPs held by non-executive directors are vested.*

 

 

169

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| Items 10 to  15 |   | Corporate  Governance |   | Certain  Relationships and Related Transactions |
|-----------------|--------|-----------------------|--------|-------------------------------------------------|

 

Under the terms of our TOPs Plan, the board maygrant options to officers and employees and, when previously allowed for, todirectors. Nexen does not receive any consideration when options are granted.

 
| **Plan Category**                                 | ** ** | **Number of Securities to  be Issued on Exercise of  Outstanding Options** | ** ** | **Weighted-Average  Exercise Price of   Outstanding Options** | ** **    | **Number of Securities  Remaining  Available for Future  Issuance under Equity  Compensation Plans** | ** **     |
|--------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------|---------------|-----------------------------------------------------------------------------------------------------------------------------------------|----------------|
| Equity compensation plans approved by  shareowners     |       | 15,242,292                                                                                                         |       | $                                                                                 | 35/option     |                                                                                                                                    | 16,235,167     |   |
| Equity compensation plans not approved by  shareowners |       | —                                                                                                             |       | —                                                                            |          | —                                                                                                                                  |           |
| **Total**                                              | ** ** | **15,242,292**                                                                                                     | ** ** | **$**                                                                             | **35/option** | ** **                                                                                                                              | **16,235,167** | ** ** |

 

**ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE**

 

As a Canadian foreign private issuer, Nexenprovides the disclosure required under Item 7.B. of Form 20-F dealing with “relatedparty transactions.” Nexen did not have any related party transactions in 2006as defined under that standard. Certain other transactions described below,involving Nexen and certain of our directors were entered into in 2006. Thesetransactions are not, related party transactions.

 

Mr. Saville, a director, was a senior partner ofFraser Milner Casgrain (FMC), Barristers and Solicitors, Calgary, Alberta,until the end of January 2004. Since then, he has been counsel with FMC. FMCprovided legal services to Nexen during each of the last five years. Mr.Saville neither solicits nor participates in the services rendered to Nexen anddoes not receive any portion or percentage of the fees paid by Nexen to FMC. Inaddition, Mr. Saville is considered to be an independent director pursuant toour Categorical Standards.

 

Ms. McLellan, a director, is counsel of BennettJones (BJ), Barristers and Solicitors, Edmonton, Alberta. BJ provided legalservices to Nexen during each of the last five years. Ms. McLellan neithersolicits nor participates in the services rendered to Nexen and does notreceive any portion or percentage of the fees paid by Nexen to BJ. In addition,Ms. McLellan is considered to be an independent director pursuant to ourCategorical Standards.

 

Mr. Flanagan’s son is Senior Vice President,Engineering of TriAxion Resources Ltd. (TriAxion). In 2006, TriAxion acquired acompany that was party to a commodity contract and a hedge contract with awholly-owned subsidiary of Nexen. The commodity contract was later replacedwith two new contracts dated effective June 1, 2006. No payments were made in2006 under one of those contracts. For the other, however, Nexen paidapproximately $4.5 million to TriAxion between July and December 2006 forproducts purchased at market price. Accordingly, Mr. Flanagan will nottechnically be independent as of July 1, 2007. Mr. Flanagan was not aware thatthe company acquired by TriAxion held contracts with Nexen. The board hasdetermined that Mr. Flanagan’s intellectual independence was in no way impairedby this transaction.

 

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| Corporate  Governance |   | Principal  Accounting Fees and Services |
|-----------------------|--------|-----------------------------------------|

 

**ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES**

 

**AUDIT COMMITTEE REPORT**

 

The Audit Committee is directly responsible forappointing (subject to shareowner approval), compensating and overseeing the independentregistered Chartered Accountants (independent auditors). The independentauditors are accountable to and report directly to the Committee, andunderstand that they must maintain an open and transparent relationship withthe Committee, as representatives of the shareowners.

 

The Committee assists the board in overseeinginternal accounting and financial reporting controls, internal and externalaudit processes, and implementation of the ethics policy.

 

Management is responsible for our internalcontrols and financial reporting process. The independent auditors areresponsible for performing and reporting on an independent audit of ourconsolidated financial statements according to generally accepted auditingstandards. The independent auditors also perform and report on an independentaudit of our internal control over financial reporting according to thestandards of the US Public Company Accounting Oversight Board. The Committee’sresponsibility is to monitor and oversee these processes.

 

**Key Activities for 2006**

 

•    Met separately with management and theindependent auditors to review the December 31, 2006 consolidated financialstatements;

•    Discussed with the independent auditorsmatters required by Canadian regulators under Section 5751 of the GeneralAssurance and Auditing Standards of the Canadian Institute of CharteredAccountants “Communications with Those having Oversight Responsibility for theFinancial Reporting Process” and by US regulators under the Statement onAuditing Standards No. 61 “Communication with Audit Committees” issued by theAmerican Institute of Certified Public Accountants;

•    Received written disclosures from theindependent auditors required by the SEC according to the IndependenceStandards Board Standard No. 1 “Independence Discussions with Audit Committees”;

•    Based on the reviews and discussionsreferred to above, recommended to the board that the audited financialstatements be included in Nexen’s annual report on Form 10-K;

•    Discussed with the independent auditorsthat firm’s independence;

•    Oversaw the progress of Section 404Sarbanes-Oxley compliance activities undertaken by management and theindependent auditors to report on the effectiveness of internal control overfinancial reporting as at December 31, 2006; and

•    Recommended changes to the ethics policy.

 

**Audit Partner Rotation**

 

In compliance with applicable law, the leadaudit partner of our independent auditors is replaced every five years.

 

**Section 404 of Sarbanes-Oxley**

 

Nexen is a voluntary filer of Form 10-K in theUS and, due to this, has been required to comply with the requirements ofSection 404 of Sarbanes-Oxley since December 31, 2004. During 2006, managementevaluated the effectiveness of our internal control over financial reportingand concluded that it was effective as of December 31, 2006. This assessmentwas documented and audited by the independent auditors as part of theintegrated audit of the consolidated financial statements. Their report isincluded in our Form 10-K.

 

**Auditor Engagement**

 

Before Deloitte & Touche LLP is engaged byNexen or its subsidiaries to render audit or non-audit services, the engagementis approved by the Committee. All audit-related, tax and other servicesprovided by Deloitte & Touche LLP since May 6, 2003, have been approved bythe Committee.

 

 

171

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**Fees Billed by IndependentAuditors**

 
| **Type of Fee**                                                                                                 | ** ** | **Billed in  2005** | ** **    | **Billed in  2006** | ** ** | **Percentage  of Total  Fees Billed  in 2006** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------|------------|--------------------------|---------------|--------------------------|------------|---------------------------------------------------------------|------------|
| Audit Fees                                                                                                                |       |                     |          |                     |       |                                                          |       |
| For the integrated audit of Nexen’s  consolidated financial statements included in our annual report on Form 10-K    | ** ** | 2,075,500                | (1)           | 2,332,500                | (2)        |                                                          |       |
| For the integrated audit of the  consolidated financial statements of Canexus (3)                                         | ** ** | **—**               |          | 302,900                  | (4)        |                                                          |       |
| For the first, second and third quarter  reviews of Nexen’s consolidated financial statements included in Form 10-Qs |       | 69,000                   |          | 72,000                   |       |                                                          |       |
| For the first, second and third quarter  reviews of the consolidated financial statements of Canexus (3)                  |       | —                   |          | 45,000                   |       |                                                          |       |
| For comfort letters and submissions to  commissions                                                                       |       | 149,000                  |          | 2,500                    |       |                                                          |       |
| **Total Audit Fees**                                                                                                      | ** ** | **2,293,500**            | ** **    | **2,754,900**            | ** ** | **76**                                                        | **%**      |
| ** **                                                                                                                | ** ** | ** **               | ** **    | ** **               | ** ** | ** **                                                    | ** ** |
| Audit-Related Fees — Nexen and Canexus (3)                                                                           |       |                     |          |                     |       |                                                          |       |
| For the annual audits and quarterly reviews  of subsidiary financial statements and employee benefit plans                |       | 466,500                  |          | 719,500                  |       |                                                          |       |
| For audit-related work in connection with  acquisitions and divestitures                                                  |       | 391,000                  |          | —                   |       |                                                          |       |
| **Total Audit-Related Fees**                                                                                              | ** ** | **857,500**              |          | **719,500**              | ** ** | **20**                                                        | **%**      |
| ** **                                                                                                                | ** ** | ** **               |          |                     | ** ** | ** **                                                    | ** ** |
| Tax Fees — Nexen and Canexus (3)                                                                                     |       |                     |          |                     |       |                                                          |       |
| For tax return preparation assistance and  tax-related consultation                                                       |       | 234,000                  |          | 84,300                   |       |                                                          |       |
| **Total Tax Fees**                                                                                                        | ** ** | **234,000**              |          | **84,300**               | ** ** | **2**                                                         | **%**      |
| ** **                                                                                                                | ** ** | ** **               |          |                     | ** ** | ** **                                                    | ** ** |
| **All Other Fees**                                                                                                        | ** ** | **66,000**               | **(5)**       | **86,000**               | **(5)**    | **2**                                                         | **%**      |
| **Total Annual Fees**                                                                                                     | ** ** | **$**                    | **3,451,000** | ** **               | **$**      | **3,644,700**                                                 | ** ** | **100** | **%** |
|                                                                                                                           |            |                          |               |                          |            |                                                               |            |  |  |

 

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*Notes:*

*(1)**          Consisting of $885,500to complete the 2004 audit and $1,190,000 to commence the 2005 audit.*

*(2)**          Consisting of $1,032,500to complete the 2005 audit and $1,300,000 to commence the 2006 audit.*

*(3)**          Includes fees for CanexusIncome Fund, Canexus Limited Partnership and its subsidiaries.*

*(4)**          Consisting of $105,000for the 2005 audit and $197,900 to commence the 2006 audit.*

*(5)**          Annual renewal fees foran upstream information database used in our UK office.*

 

**Committee Approval**

 

The Committee is of the view that the provisionof services by Deloitte & Touche LLP described in “All Other Fees” above iscompatible with maintaining that firm’s independence.

 

Based on the Committee’s discussions withmanagement and the independent auditors, and its review of the representationsof management and the independent auditors, the Committee recommended that theboard include the audited consolidated financial statements in Nexen’s annualreport on Form 10-K for the year ended December 31, 2006.

 

**Submitted on behalf of theAudit Committee:**

 
| Tom O’Neill, Chair |   |
|-------------------------|--------|
| Dennis Flanagan         |   |
| Barry Jackson           |   |
| Kevin Jenkins           |   |
| Dick Thomson            |   |
| John Willson            |   |

 

172

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| Corporate  Governance |   | Exhibits |
|-----------------------|--------|----------|

 

**PART IV**

 

**ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES**

 

**FINANCIAL STATEMENTS ANDSCHEDULES**

 

We refer you to the index to FinancialStatements and Supplementary Data in Item 8 of this report where thesedocuments are listed.

 

Schedules and separate financial statements ofsubsidiaries are omitted because they are not required or applicable, or therequired information is shown in the Consolidated Financial Statements ornotes.

 

**EXHIBITS**

 

Exhibits filed as part of this report are listedbelow. Certain exhibits have been previously filed with the Commission and areincorporated in this Form 10-K by reference. Instruments defining the rights ofholders of debt securities that do not exceed 10% of Nexen’s consolidatedassets have not been included. A copy of such instruments will be furnished tothe Commission upon request.

 

2.2           Agreement for the Sale and Purchase ofEnCana (U.K.) Limited, between EnCana (U.K.) Holdings Limited and Nexen EnergyHoldings International Limited dated October 28, 2004 (filed as Exhibit 2.1 toForm 8-K dated October 29, 2004).

 

3.9           By-Law No. 2 of the Registrant enactedDecember 9, 2003, being a by-law relating generally to the transaction of thebusiness and affairs of the Registrant (filed as Exhibit 3.9 to Form 10-K forthe year ended December 31, 2003).

 

3.14         Restated Certificate and Articles ofIncorporation of the Registrant dated May 20, 2005 (filed as Exhibit 3.12 toForm 10-Q for the quarterly period ended June 30, 2005).

 

3.15         By-Law No. 3 of the Registrant enactedDecember 4, 2006, being a by-law relating generally to the transaction of thebusiness and affairs of the Registrant (filed as Exhibit 3.15 to Form 8-K datedDecember 5, 2006).

 

4.29         Acquisition Agreement between theRegistrant, Occidental Petroleum Corporation and Ontario Teachers’ Pension PlanBoard, dated March 1, 2000 (filed as Exhibit 4.29 to Form 10-K for the yearended December 31, 1999).

 

4.42         Trust Indenture dated April 28, 1998between the Registrant and CIBC Mellon Trust Company providing for the issue ofdebt securities from time to time (filed as Exhibit 4.42 to Form 10-K for theyear ended December 31, 2003).

 

4.43         First Supplemental Indenture dated April28, 1998 to the Trust Indenture dated April 28, 1998 between the Registrant andCIBC Mellon Trust Company pertaining to the issuance of US$200 million, 7.40%notes due 2028 (filed as Exhibit 4.43 to Form 10-K for the year ended December31, 2003).

 

4.46         Third Supplemental Indenture dated March11, 2002 to the Trust Indenture dated April 28, 1998 between the Registrant andCIBC Mellon Trust Company pertaining to the issuance of $500 million, 7.85%notes due 2032 (filed as Exhibit 4.46 to Form 10-K for the year ended December31, 2003).

 

4.47         Subordinated Debt Indenture dated November4, 2003 between the Registrant and Deutsche Bank Trust Company Americas,pertaining to the issue of subordinated notes from time to time (filed asExhibit 4.47 to Form 10-K for the year ended December 31, 2003).

 

4.48         Officer’s Certificate dated November 4,2003 pursuant to the Subordinated Debt Indenture dated November 4, 2003 betweenthe Registrant and Deutsche Bank Trust Company Americas, pertaining to theissuance of US$460 million, 7.35% subordinated notes due 2043 (filed as Exhibit4.48 to Form 10-K for the year ended December 31, 2003).

 

4.51         Fourth Supplemental Indenture datedNovember 20, 2003 to the Trust Indenture dated April 28, 1998, between theRegistrant and CIBC Mellon Trust Company pertaining to the issuance of US$500million, 5.05% notes due 2013 (filed as Exhibit 4.51 to Form 10-K for the yearended December 31, 2003).

 

 

173

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4.53         Fifth Supplemental Indenture dated March10, 2005 to the Trust Indenture dated April 28, 1998, between the Registrantand CIBC Mellon Trust Company pertaining to the issuance of US$250 million,5.20% notes due 2015 and the issuance of US$790 million, 5.875% notes due 2035(filed as Exhibit 10.1 to Form 8-K dated March 11, 2005).

 

4.54         Amended and Restated Shareholder RightsPlan Agreement dated April 27, 2005 between the Registrant and CIBC MellonTrust Company, as Rights Agent, which includes the Form of Rights Certificateas Exhibit A (filed as Exhibit 4.54 to Form 10-K for the year endedDecember 31, 2005).

 

10.40       Amended and Restated Change of Control Agreementswith Executive Officers dated during December, 2001 (filed as Exhibit 10.41 toForm 10-K for the year ended December 31, 2001).

 

10.41       Indemnification Agreements made betweenthe Registrant and its directors and officers during 2002 (filed as Exhibit10.41 to Form 10-K for the year ended December 31, 2002).

 

10.42       Indemnification Agreement made between theRegistrant and one of its directors, Eric P. Newell, as of January 5, 2004(filed as Exhibit 10.42 to Form 10-K for the year ended December 31, 2003).

 

10.43       Credit Agreement dated as of July 22, 2005between the Registrant and the Toronto Dominion Bank, as Agent, and the Lenders(filed as Exhibit 10.1 to Form 8-K dated July 28, 2005).

 

10.44       Guarantee dated as of July 22, 2005 asSchedule K to the Credit Agreement (filed as Exhibit 10.2 to Form 8-K datedJuly 28, 2005).

 

10.45       Termination of Employment and SpecialSeparation Agreement between the Registrant and Mr. Sugalski dated January 28,2005 (filed as Exhibit 10.1 to Form 8-K/A dated August 18, 2005).

 

10.46       Indemnification Agreement made between theRegistrant and one of its directors, A. Anne McLellan P.C., as of July 5, 2006(filed as Exhibit 10.2 to Form 8-K dated July 20, 2006).

 

10.47       Second Amending Agreement dated July 14,2006 to the Credit Agreement, dated as of July 22, 2005, between the Registrantand the Toronto-Dominion Bank, as Agent, and the Lenders (filed as Exhibit 10.1to Form 8-K dated July 20, 2006).

 

11.1*       Statement regarding the Computation of PerShare Earnings for the three years ended December 31, 2006.

 

16.1         Letter re change in certifying accountant(filed as Exhibit 16.1 to Form 8-K filed July 17, 2002).

 

21.1*       Subsidiaries of the Registrant.

 

23.1*       Consent of Independent RegisteredChartered Accountants.

 

23.2*       Consent of William M. Cobb &Associates, Inc.

 

23.3*       Consent of Ryder Scott Company, L.P.

 

23.4*       Consent of McDaniel & AssociatesConsultants Ltd.

 

23.5*       Consent of DeGolyer and MacNaughton.

 

31.1*       Certification of Chief Executive Officerpursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

31.2*       Certification of Chief Financial Officerpursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

32.1*       Certification of periodic report by ChiefExecutive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant toSection 906 of the Sarbanes-Oxley Act of 2002.

 

32.2*       Certification of periodic report by ChiefFinancial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant toSection 906 of the Sarbanes-Oxley Act of 2002.

 

99.1*       Opinion of Internal Qualified ReservesEvaluator on National Instrument 51-101 Form F2 as required by certain Canadiansecurities regulatory authorities.

 

----

****             **Filedwith this Form 10-K.*

 

174

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**SIGNATURES**

 

Pursuant to the requirements of Section 13 or15(d) of the Securities Exchange Act of 1934, the Company has duly caused thisreport to be signed on its behalf by the undersigned, thereunto dulyauthorized, on February 26, 2007.

 
|   | NEXEN  INC.                                 |
|--------|---------------------------------------------|
|   |
|   | By:                                         | /s/ Charles  W. Fischer |   |
|   | Charles  W. Fischer                         |
|   | President,  Chief Executive Officer         |
|   | and  Director (Principal Executive Officer) |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the registrant and inthe capacities indicated on February 26, 2007.

 
| /s/ Dennis  G. Flanagan           |                                                  | /s/ Charles  W. Fischer                     |   |
|-----------------------------------|-------------------------------------------------------|---------------------------------------------|--------|
| Dennis G.  Flanagan, Director     | Charles W.  Fischer                                   |
|                              | President,  Chief Executive Officer                   |
| /s/ David A.  Hentschel           |                                                  | and Director  (Principal Executive Officer) |
| David A.  Hentschel, Director     |                                                  |
|                              |                                                  |
| /s/ S. Barry  Jackson             |                                                  | /s/ Marvin  F. Romanow                      |   |
| S. Barry  Jackson, Director       | Marvin F.  Romanow                                    |
|                              | Executive  Vice President and Chief Financial Officer |
| /s/ Kevin J.  Jenkins             |                                                  | (Principal  Financial Officer)              |
| Kevin J.  Jenkins, Director       |                                                  |
|                              |                                                  |
| /s/ A. Anne  McLellan             |                                                  | /s/ Michael  J. Harris                      |   |
| A. Anne  McLellan, Director       | Michael J.  Harris                                    |
|                              | Controller                                            |
| /s/ Eric P.  Newell               |                                                  | (Principal  Accounting Officer)             |
| Eric P.  Newell, Director         |                                                  |
|                              |                                                  |
| /s/ Thomas  C. O’Neill       |                                                  | /s/ John B.  McWilliams                     |   |
| Thomas C.  O’Neill, Director | John B.  McWilliams                                   |
|                              | Senior Vice  President, General Counsel               |
| /s/ Francis  M. Saville           |                                                  | and  Secretary                              |
| Francis M.  Saville, Director     |                                                  |
|                              |                                                  |
| /s/ Richard  M. Thomson           |                                                  | /s/ Kevin J.  Reinhart                      |   |
| Richard M.  Thomson, Director     | Kevin J. Reinhart                                     |
|                              | Vice  President, Corporate Planning                   |
| /s/ John M.  Willson              |                                                  | and Business  Development                   |
| John M.  Willson, Director        |                                                  |
|                              |                                                  |
| /s/ Victor  J. Zaleschuk          |                                                  |                                        |
| Victor J.  Zaleschuk, Director    |                                                  |
|                                   |                                                       |                                             |        |  |  |  |  |  |  |  |  |

 

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