** **

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-K**

 

**ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) of**

**THE SECURITIES EXCHANGE ACT OF 1934**

 

**For the year ended December 31, 2007**

** **

**Commission File Number 1-6702**

 

**NEXEN INC.**

Incorporated under the Laws of Canada

 

 

**98-6000202**

(I.R.S. Employer Identification No.)

 

**801 – 7th Avenue S.W.**

**Calgary, Alberta, Canada T2P 3P7**

**Telephone - (403) 699-4000**

**Web site - www.nexeninc.com**

 

**Securities registered pursuant to Section 12(b) of the Act:**

 

| **Title**                          | ** ** | **Exchange  Registered On**  |
|------------------------------------|------------|------------------------------|
|                               |       |                         |
| Common shares, no par  value       |       | The New York Stock  Exchange |
|                               |       | The Toronto Stock Exchange   |
|                               |       |                         |
| Subordinated Securities,  due 2043 |       | The New York Stock  Exchange |
|                               |       | The Toronto Stock Exchange   |

 

Securities registered pursuant to Section 12(g) of the Act: **None.**

 

Indicate by check mark ifthe registrant is a well-known seasoned issuer, as defined in Rule 405 ofthe Securities Act.

 

Yes  x     No

 

Indicate by check mark ifthe registrant is not required to file reports pursuant to Section 13 or Section 15(d) ofthe Exchange Act.

 

Yes  o     Nox

 

Indicate by check markwhether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months, and (2) has been subject to such filing requirements for the past90 days.

 

Yes  x     Noo

 

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment to this Form 10-K.x

 

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer.

 

Large accelerated filer  x  Acceleratedfiler  o  Non-accelerated filer  o

 

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2 of theExchange Act).

 

Yes  o    No  x

 

On June 30, 2007, theaggregate market value of the voting shares held by non-affiliates of theregistrant was approximately Cdn $17 billion based on the Toronto StockExchange closing price on that date. On January 31, 2008, there were528,502,991 common shares issued and outstanding.

 

 

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**TABLE OF CONTENTS**

 
| **PART I**                                        |                                                                                                                    |   |
|--------------------------------------------------------|-------------------------------------------------------------------------------------------------------------------------|--------|
| Items 1 and 2.                                         | Business and Properties                                                                                                 | 2      |
| Item 1A.                                               | Risk Factors                                                                                                            | 27     |
| Item 1B.                                               | Unresolved  Staff Comments                                                                                              | 34     |
| Item 3.                                                | Legal Proceedings                                                                                                       | 34     |
| Item 4.                                                | Submission  of Matters to a Vote of Security Holders                                                                    | 34     |
| **PART II**                                       |                                                                                                                    |   |
| Item 5.                                                | Market for  the Registrant’s Common Equity, Related Stockholder Matters and Issuer  Purchases of Equity Securities | 35     |
| Item 6.                                                | Selected Financial  Data                                                                                                | 36     |
| Item 7.                                                | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                             | 38     |
| Item 7A.                                               | Quantitative  and Qualitative Disclosures About Market Risk                                                             | 72     |
| Item 8.                                                | Financial  Statements and Supplementary Data                                                                            | 78     |
| Item 9.                                                | Changes in  and Disagreements with Accountants on Accounting and Financial Disclosure                                   | 125    |
| Item 9A.                                               | Controls and  Procedures                                                                                                | 125    |
| **PART III**                                      |                                                                                                                    |   |
| Items 10 and  11.                                      | Directors,  Executive Officers and Corporate Governance, and Executive Compensation                                     | 128    |
| Item 12.                                               | Security  Ownership of Certain Beneficial Owners and Management and Related Stockholder  Matters                        | 154    |
| Item 13.                                               | Certain  Relationships and Related Transactions, and Director Independence                                              | 155    |
| Item 14.                                               | Principal  Accounting Fees and Services                                                                                 | 155    |
| **PART IV**                                       |                                                                                                                    |   |
| Item 15.                                               | Exhibits,  Financial Statement Schedules                                                                                | 157    |
|                                                   |                                                                                                                    |   |
| Special Note to Canadian  Investors — see page 76 |                                                                                                                    |
|                                                        |                                                                                                                         |        |  |  |

Unless we indicateotherwise, all dollar amounts ($) are in Canadian dollars, and oil and gasvolumes, reserves and related performance measures are presented on a workinginterest before-royalties basis. Where appropriate, information on anafter-royalties basis is provided in tabular format. Volumes and reservesinclude Syncrude operations unless otherwise stated.

 

Belowis a list of terms specific to the oil and gas industry. They are usedthroughout 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                  |

 

Inthis 10-K, we refer to oil and gas in common units called barrel of oilequivalent (boe). A boe is derived by converting six thousand cubic feet of gasto one barrel of oil (6mcf/1bbl). This conversion may be misleading,particularly if used in isolation, as the 6mcf/1bbl ratio is based on an energyequivalency at the burner tip and does not represent the value equivalency atthe well head.

 

Thenoon-day Canadian to US dollar exchange rates for Cdn $1.00, as reported by theBank of Canada, were:

 
| **(US$ )** | ** ** | **December 31** | ** ** | **Average** | ** ** | **High** | ** ** | **Low** | ** ** |
|-----------------|------------|----------------------|------------|-------------|------------|----------|------------|---------|------------|
| 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  |       |
| 2007            |       | 1.0120               |       | 0.9304      |       | 1.0905   |       | 0.8437  |       |

 

OnJanuary 31, 2008, the noon-day exchange rate was US $0.9978 for Cdn $1.00.

 

Electroniccopies of our filings with the Securities Exchange Commission (SEC) and theOntario Securities Commission (OSC) (from November 8, 2002 onward) areavailable, free of charge, on our website (www.nexeninc.com). Filings prior to November 8,2002 are available free of charge, on request, by contacting our investorrelations department at 403.699.5931. As soon as reasonably practicable, ourfilings are made available on our website once they are electronically filedwith the SEC and/or the OSC. Alternatively, the SEC and the OSC each maintain awebsite (www.sec.gov and www.sedar.com) that contains our reports, proxy andinformation statements and other published information that have been filed orfurnished with the SEC and the OSC

 

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global

 

operations

 

In 2007, we added value bybringing Buzzard on stream.Our Long Lake oil sandsproject is next, expectedon stream mid 2008.

 

1

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**PART I**

 

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

 
| About  Us                                     | 3  |
|-----------------------------------------------|----|
| Strategy                                      | 4  |
| Understanding the Oil and  Gas Business       | 4  |
| Oil and Gas Operations                        | 5  |
| North Sea—United Kingdom                 | 5  |
| Gulf of Mexico—United States             | 7  |
| Canada                                        | 9  |
| Middle East—Yemen                        | 13 |
| Offshore West Africa                          | 15 |
| Other International                           | 16 |
| Reserves,  Production and Related Information | 16 |
| Syncrude Mining  Operations                   | 22 |
| Energy Marketing                              | 24 |
| Chemicals                                     | 26 |
| Government Regulations                        | 27 |
| Environmental  Regulations                    | 27 |
| Employees                                     | 27 |

 

2

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Items 1 and 2         Business andProperties     About Us

 

**ABOUT US**

 

Nexen Inc. (Nexen, we or our) is anindependent, Canadian-based, global energy company. We were formed in Canada in1971 when Occidental Petroleum Corporation (Occidental) combined their Canadiancrude oil, natural gas, sulphur and chemical operations into one company. We’vegrown from producing 10,700 boe/d before royalties with revenues of $26 millionin 1971, to producing 253,600 boe/d before royalties (including Syncrudeproduction) and revenues of $5.6 billion in 2007. We achieved this growththrough exploration success and strategic acquisitions. Operating for more than35 years, we have been profitable every year, except one, and have been payingquarterly dividends consecutively since 1975.

 

In the 1970s, we expanded ourwestern Canadian assets and entered the US Gulf of Mexico. We finished thisdecade with production of approximately 11,000 boe/d before royalties andrevenues of $126 million.

 

**Buzzard produced first oil earlyin the year and we made significant construction and commissioning progress atLong Lake.**

 

In the 1980s, we continued toexpand in western Canada and the Gulf of Mexico through acquisitions. AcquiringCanada-Cities Services in 1983 doubled our size and included an interest in theSyncrude Joint Venture, our entry into the Athabasca oil sands. We finishedthis decade with production of approximately 68,600 boe/d before royalties andrevenues of $591 million.

 

In the 1990s, we had two definingevents: discovering oil on the Masila block in Yemen and acquiring WascanaEnergy Inc. The first of 17 fields at Masila was discovered in 1991. Sincestart up in 1993, Masila has produced almost a billion barrels of crude oil.Our 1997 purchase of Wascana Energy Inc. almost tripled our Canadianproduction. In 1998, we entered Australia with an interest in the offshoreBuffalo field and Nigeria as the operator of the Ejulebe field. Also in 1998,we discovered Ukot on Block OPL-222, offshore Nigeria. We finished this decadewith production of approximately 239,200 boe/d before royalties and revenues of$1.7 billion.

 

So far in the 21st century, we havemade a number of discoveries, two strategic acquisitions and completed non-coreasset divestiture programs. In 2000, we discovered Gunnison in the deep-waterGulf of Mexico and Guando in Colombia. We joined with Ontario Teachers’ PensionPlan Board (Teachers) to acquire Occidental’s remaining 29% interest in us.Teachers purchased 20.2 million common shares. We repurchased the remaining 20million common shares for $605 million, which would have had a value of almost$2.6 billion at the end of 2007. We also exchanged our oil and gas operationsin Ecuador for Occidental’s 15% interest in our chemical operations and wechanged our name from Canadian Occidental Petroleum Ltd. to Nexen Inc. In 2001,we discovered Aspen in the deep-water Gulf of Mexico and signed a joint ventureagreement with OPTI Canada Inc. to develop, produce and upgrade bitumen at LongLake in the Athabasca oil sands. In 2002, we discovered Usan, the seconddiscovery on OPL-222, offshore Nigeria. In late 2003, we discovered two fieldson Block 51 in Yemen.

 

In 2004 , we acquired properties in the UK North Sea , providing us withoperatorship of the Buzzard discovery, the producing Scott and Telford fields and 700,000 exploration acres. In 2005, we completed non-core assetdivestiture programs by selling Canadianconventional oil and gas properties producing approximately 18,300 boe/d beforeroyalties and by monetizing 39% of ourchemical business through the initial public offering of the CanexusIncome Fund. We also made a potentiallysignificant discovery in the Gulf of Mexicoat Knotty Head and commenced commercial development of our first coalbed methane (CBM) project in the Fort Assiniboine area in western Canada. In 2006, wecompleted major development projectsat Buzzard in the North Sea and the Syncrude Stage 3 expansion in the Athabascaoil sands. In 2007, Buzzard producedfirst oil early in the year and we madesignificant construction and commissioning progress at our Long Lake Project. At Long Lake, SAGD steaminjection began in the second half of2007 and the upgrader is scheduledto start up in mid 2008. We also significantly added to our inventory of exploration prospects during the yearby securing new Gulf of Mexicodeepwater leases, obtaining exploration licences offshore Norway and acquiringadditional shale gas opportunities in Canada. Our portfolio of assets,combined with talented people and an activeexploration program, are expected to provide future growth for our company.

 

For financial reporting purposes, we report on four main segments:

 

·      oil and gas;

·      Syncrude;

·      energy marketing; and

·      chemicals.

 

Our oil andgas operations are broken down geographically into the UK North Sea, US Gulf ofMexico, Canada, Yemen and Other International (currentlyColombia, offshore West Africa and Norway).Results from our Long Lake Project areincluded in Canada. Syncrude is our 7.23% interest in the Syncrude Joint Venture. Energy marketingincludes our growing crude oil,natural gas, natural gas liquids, ethanol and power marketing business in NorthAmerica, Europe and Asia.

 

3

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Items 1 and 2         Business and Properties     Strategy

 

Chemicalsincludes operations in North America and Brazil that manufacture, market anddistribute sodium chlorate, caustic soda and chlorine through the Canexus LimitedPartnership.

 

Production,revenues, net income, capital expenditures and identifiable assets forthese segments appear in Note 20 to the Consolidated Financial Statements and inManagement’s Discussionand Analysis of Financial Condition and Results of Operations (MD&A)in this report.

 

**STRATEGY**

 

Our goalis to grow long-term value for our shareholders responsibly. Key driversto growing value include increasing reserves, production, cash flow and net income on acost-effectivebasis over the long term. We believe in developing a competitive advantagewhere possible, to assist in generating opportunities for long-term success in ourever-evolving industry. Asconventional basins in North America mature, we have developed specificcapabilities in oil sands, CBM, deep-watertechnology and international experience. These skills enable us to focus on specific types of projects, as we transition toward major projects in establishedbasins, exploration in less maturebasins and exploitation of unconventional resources.

 

Today,we are building new sustainable businesses in western Canada, the North Sea,Gulf of Mexico, and offshore West Africa, capitalizing on the followingcorporate strengths:

 

·      Wehave access to resource in our key areas that creates future opportunities. OurLong Lake Project is developing only 10% of our oil sands leases in theAthabasca oil sands and we hold unexplored acreage in the Gulf of Mexico, theNorth Sea, western Canada and elsewhere;

 

·      Weare successful explorers with significant discoveries at Knotty Head andVicksburg in the Gulf of Mexico, Golden Eagle in the UK North Sea and at Usan,offshore Nigeria;

 

·      Weare skilled project managers with major development projects, proven bybringing Buzzard on stream in early 2007;

 

·      Weare innovative in our application of technology. Long Lake is expected to bethe first oil sands project to use gasification technology to significantlyreduce the cost of producing bitumen and we are advancing new techniques forunconventional production of CBM and enhanced heavy oil recovery in westernCanada;

 

·      Weare an international operator with a proven track record of successful businessventures in Yemen, the United Kingdom, Nigeria, Colombia and Australia; and

 

·      Fromtime to time, we supplement our growth with acquisitions, such as our strategicentry into the UK North Sea in 2004.

 

Thelocation and scale of our operations often result in: 1) an extended period oftime from the capture of opportunities to first production and 2) non-linear,year-over-year growth in reserves and production. Significant up-front capitalinvestment is often required prior to realizing production and free cash flows.We fund this investment by maximizing cash flow from our producing assets,issuing long-term debt and/or equity and selling non-core assets intoattractive markets.

 

Ourlong-term strategy is to build capacity by ensuring we have a sufficientinventory of opportunities for future growth. We have a number of opportunitiesexpected to provide production growth and create shareholder value well intothe next decade. They include undeveloped discoveries at Knotty Head andVicksburg in the Gulf of Mexico, Usan and Ukot offshore Nigeria, variousdiscoveries in the UK North Sea, together with development of CBM, shale gasand additional oil sands leases in Canada.

 

**Our goal is to grow long-term value responsibly for our shareholders bybuilding sustainable businesses in western Canada, the North Sea, Gulf of Mexico,and offshore West Africa.**

 

Increating sustainable businesses, we are committed to good corporate governancepractices and social responsibility. We believe that over the long term,companies that follow sustainable business practices outperform those withnarrower priorities. We foster dialogue with stakeholders about our operationalopportunities and challenges, from exploration to production to reclamation.Our goal is to help stakeholders become engaged participants in a continuingconsultation process, while balancing multiple, and sometimes conflictinggoals.

 

**UNDERSTANDING THE OIL AND GAS BUSINESS**

 

Theoil and gas industry is highly competitive. With strong global demand forenergy, there is intense competition to find and develop new sources of supply.Yet, barrels from different reservoirs around the world do not have equalvalue. Their value depends on the costs to find, develop and produce the oil orgas, the fiscal terms of the host regime and the price products command in themarket based on quality and marketing efforts. Our goal is to extract themaximum value from each barrel of oil equivalent, so every dollar of capital weinvest generates an attractive return.

 

Numerousfactors can affect this. Changes in crude oil and natural gas prices cansignificantly affect our net income and cash generated from operatingactivities. Consequently, these prices may also affect the carrying value ofour oil and gas properties and how much we invest in oil and gas explorationand development. We attempt to reduce these impacts by investing in projects webelieve will generate positive returns at relatively low commodity prices.

 

4

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Items1 and 2         Business and Properties     Oil and Gas Operations

 

 

Theprices we receive for our oil and gas products are mainly determined byvolatile global crude oil and natural gas markets. With many alternativecustomers, the loss of any one customer is not expected to have a significantlyadverse effect on the price of our products or revenues. Oil and gas producingoperations are generally not seasonal. However, demand for some of our productscan fluctuate season to season, which impacts price. In particular, heavy oilis generally in higher demand in the summer for its use in road construction,and natural gas is generally in higher demand in the winter for heating. Wemanage our operations on a country-by-country basis, reflecting differences inthe regulatory and competitive environments and risk factors associated witheach country.

 

**OIL AND GAS OPERATIONS**

 

Wehave oil and gas operations in the UK North Sea, US Gulf of Mexico, westernCanada, Yemen, Colombia, offshore West Africa and Norway. We also haveoperations in Canada’s Athabasca oil sands which produce synthetic crude oil.We operate most of our production and continue to develop new growthopportunities in each area by actively exploring and applying technology.

 

Inthis Form 10-K, we provide estimates of remaining quantities of proved oiland gas reserves for our various properties. Such estimates are internallyprepared. We had 98% of our oil and gas reserves before royalties (98% afterroyalties) and 100% of our Syncrude reserves before royalties (100% afterroyalties) assessed (either evaluated or audited as described on page 21)by independent reserves consultants. Their assessments are performed at varyinglevels of property aggregation, and we work with them to reconcile thedifferences on the portfolio of properties to within 10% in the aggregate.Estimates pertaining to individual properties within the portfolio may differby more than 10%, either positively or negatively; however, we believe suchdifferences are not material relative to our total proved reserves. Refer tothe section on Critical Accounting Estimates—Oil and Gas Accounting—ReservesDetermination on page 68 for a description of our reserves process, and tothe section on Reserves, Production and Related Information on page 16 fora description of the nature and scope of the independent assessments performedand the results thereof.

 

**NORTH SEA—UNITED KINGDOM (UK)**

 

TheUK North Sea is a key producing area. In 2004, we acquired a 43.2% operatedinterest in the Buzzard development, a 41% operated interest in the Scottfield, a 54.3% operated interest in the Telford field, the Scott productionplatform, interests in several satellite discoveries and more than 700,000 netundeveloped exploration acres for US$2.1 billion. This acquisition establishedus as a significant regional player with concentrated assets, infrastructureand exploration and development potential for future growth. It addedhigh-margin reserves and production, diversified our worldwide portfolio byadding strong assets in a stable jurisdiction, and complemented our otherlonger cycle-time projects.

 

OurUK strategy is to grow and sustain our existing North Sea production andcapture new production hubs with exploration and exploitation opportunitiesnear existing infrastructure. We

 

5

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Items1 and 2         Business and Properties     North Sea

 

 

havea number of exploitation opportunities in our existing fields and smallerundeveloped discoveries near infrastructure. Most of our unexplored acreage isnear Scott/Telford, Buzzard or Ettrick. As a result, new discoveries can betied-in quickly.

 

Duringthe year, we produced 84,000 boe/d before royalties (84,000 after royalties) inthe UK, which was approximately one-third of our total production. At year end,our UK proved oil and gas reserves of 207 mmboe before royalties (207 afterroyalties) represented about 20% of our total proved oil and gas and Syncrudereserves.

 

Buzzard

 

Buzzardis the largest discovery in the UK North Sea in the past ten years. It wasdiscovered in 2001 and began producing January 7, 2007. Development ofthis discovery was on time and on budget.

 

TheBuzzard field is located about 60 miles northeast of Aberdeen in the OuterMoray Firth, central North Sea, in 317 feet of water. The facilities canprocess at least 200,000 bbls/d of oil and 60 mmcf/d of gas. Developmentdrilling has resulted in more well-to-well variability in the concentration ofhydrogen sulphide than originally expected. To address this, we plan toconstruct a fourth platform with production sweetening facilities to handlehigher levels of hydrogen sulphide. We believe existing equipment and processescan manage current hydrogen sulphide levels and maintain current productiondeliverability until the additional equipment is commissioned in 2010.

** **

**During the year, we produced 84,000 boe/d in the UK, which wasapproximately one-third of our total production.**

 

Oilfrom Buzzard is exported via the Forties pipeline to the Grangemouth refineryin Scotland. Gas is exported via the Frigg system to the St. Fergus GasTerminal in northeast Scotland.

 

Weexpect to produce Buzzard through 27 production wells and maintain reservoirpressure through an active water-flood program. In 2008, we plan to invest $255million to drill five production wells, two sidetracks, one water injector andprogress work on the fourth platform.

 

Scott/Telford

 

Scottand Telford are producing fields with additional exploitation opportunities andboth tie back to the Scott platform. Scott was discovered in 1987 and beganproducing in September 1993, while Telford was discovered in 1991 and cameon stream in 1996. In 2007, we increased our interests in these fields and atthe end of the year, we have a 41.9% working interest in the Scott platform andfield, and a 71.75% working interest in Telford. In 2007, our share of productionfrom these fields was approximately 16,500 boe/d. The production isroyalty-free, around 90% oil and produced through numerous subsea wells. Oil isdelivered to the Grangemouth refinery in Scotland via the Forties pipeline,while gas is exported via the SAGE pipeline to the St. Fergus Gas Terminal innortheast Scotland. In recent years, the Scott platform underwent a significantmaintenance turnaround and facilities upgrade to improve reliability and extendfacility life.

 

Ettrick

 

Weare progressing development of the Ettrick field and we expect it on stream mid2008. Our share of production is expected to average approximately 20,000 boe/dat peak rates. Development includes three subsea production wells and one waterinjector tied back to a leased floating production, storage and off-loadingvessel (FPSO). The FPSO is designed to handle 30,000 bbls/d of oil, 35 mmcf/dof gas and to re-inject 55,000 bbls/d of water. Our share of full-cycledevelopment costs is estimated at $460 million. In 2008, we expect our share ofEttrick production to average approximately 9,000 boe/d. We operate Ettrickwith an 80% working interest.

 

Other

 

Our2004 UK acquisition included a non-operated interest in Farragon, a smallsatellite discovery, which was brought on stream in late 2005. In 2007, thenon-operated Duart field was brought on stream and began producing oil from asingle well tied back to the Tartan platform. Our share of production fromthese non-operated properties was 3,300 boe/d before royalties (3,300 afterroyalties) in 2007.

 

6

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Explorationand Undeveloped Assets

 

In2007, we discovered hydrocarbons at Golden Eagle and then drilled a successfulsidetrack to appraise the accumulation. We are currently evaluating developmentoptions and expect to sanction development in 2008. In 2007, we also drilled asuccessful exploration well at Kildare, and plan to follow up the discoverywith an appraisal well. We also completed appraisal of the Selkirk prospect withfavourable results. We have a number of discoveries on operated blocks nearScott, Buzzard and third-party facilities as follows:

 
| **Field**    | ** ** | **Interest (%)** | ** ** | **Operator Status** | ** ** | **Comments**                                                | ** ** |
|--------------|------------|-----------------------|------------|--------------------------|------------|-------------------------------------------------------------|------------|
| Black Horse  |       | 60                    |       | operated                 |       | discovery near Scott; evaluating development alternatives   |       |
| Bugle        |       | 41                    |       | operated                 |       | discovery near Scott; appraisal well underway               |       |
| Dolphin      |       | 42                    |       | operated                 |       | discovery near Scott; evaluating development alternatives   |       |
| Golden Eagle |       | 34                    |       | operated                 |       | discovery near Ettrick; evaluating development alternatives |       |
| Kildare      |       | 50                    |       | operated                 |       | discovery near Scott; appraisal well planned for 2008       |       |
| Perth        |       | 42                    |       | operated                 |       | discovery near Scott; evaluating development alternatives   |       |
| Polecat      |       | 40                    |       | operated                 |       | discovery near Buzzard; evaluating appraisal options        |       |
| Selkirk      |       | 38                    |       | operated                 |       | discovery near Buzzard; evaluating development alternatives |       |
| Yeoman       |       | 50                    |       | operated                 |       | discovery near Scott; evaluating development alternatives   |       |

 

In2007, we drilled unsuccessful exploration wells at Guinea, Dee and Stag. The threewells encountered non-commercial quantities of hydrocarbons and were abandoned.In 2008, we expect to drill six exploration and two appraisal wells. We havesecured drilling rigs for all of our 2008 North Sea exploration and developmentprogram.

 

Wehave also begun assessing emerging CBM opportunities in the UK. In 2006, weacquired an 80% working interest in one opportunity and have drilled twosuccessful exploration wells so far. Both encountered coal seams as expectedand are being monitored through ongoing production testing. In another CBMopportunity, we drilled two unsuccessful exploration wells in 2007. We plan tocontinue assessing CBM potential in the UK with additional exploratory wells in2008.

 

FiscalTerms

 

UKfiscal terms are favourable. New discoveries pay no royalties and result incash netbacks that are higher than our company average. Scott is subject toPetroleum Revenue Tax (PRT), although no PRT is payable until available oilallowances have been fully utilized, which isn’t expected before 2010. Oncepayable, PRT is levied at 50% of cash flow after capital expenditures,operating costs and an oil allowance. PRT is applicable to fields receivingdevelopment consent prior to March 1993. Buzzard, Ettrick, Farragon, Duartand Telford are not subject to PRT. PRT is deductible for corporate income taxpurposes. The UK corporate income tax rate on oil and gas activities is 30% oftaxable income and is also subject to a 20% supplemental charge. The amount andtiming of income taxes payable depends on many factors including price,production, capital investment levels and available tax losses.

 

**Gulf of Mexico—United States (US)**

 

TheGulf of Mexico is an integral part of our growth strategy. Large discoveries,relatively high success rates, expanding production infrastructure andattractive fiscal terms make the deep-water Gulf of Mexico one of the world’smost prospective sources for oil and gas. While costs of deep-water explorationare high relative to other basins, deep-water prospects generally have multiplesands and high production rates—factors which reduce risk and improveeconomics. Technology to find, drill, and develop discoveries is rapidlyprogressing and becoming more cost effective. The deep-water Gulf is nearinfrastructure and continental US markets, so discoveries can be brought onstream in reasonable time.

 

**We are evaluating development options for Vicksburg, South Marsh Island257 and Mississippi Canyon 72 and look forward to developing Longhorn in 2008.**

 

Ourstrategy in the Gulf is to explore for new reserves, exploit our existing assetbase and acquire assets with upside potential. We focus our exploration programon three strategic play types:

 
| · | deep-water  prospects near existing infrastructure;                                                      |
|--------|----------------------------------------------------------------------------------------------------------|
| · | deep-water,  Miocene and Lower Tertiary sub-salt plays with the potential to become new  core areas; and |
| · | deep-water,  Norphlet targets in the eastern Gulf of Mexico.                                             |

 

Theseplays are relatively under-explored, hold potential for large discoveries andhave attractive fiscal terms. The relatively shorter cycle-times for deep-waterprospects near

 

7

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Items1 and 2         Business and Properties     Gulf of Mexico

 

infrastructurecomplement the longer cycle-times for deep-water sub-salt and Norphlet plays.Although competition in the Gulf is strong, we have built a large inventory ofdeep-water acreage and are now the eighth largest leaseholder in thedeep-water.

 

In2007, we invested $793 million on exploration, development and acquisitions inthe Gulf. This resulted in three discoveries at Desoto Canyon Block 353(Vicksburg), South Marsh Island 257 and Mississippi Canyon 72 as well as asuccessful appraisal well at Longhorn. Additionally, we acquired threeproducing deep-water fields and enhanced our deep-water acreage position.However, some of our development drilling in 2007 did not meet expectations. In2008, we plan to invest approximately $390 million in the Gulf to further ourgrowth strategies. This includes development of our Longhorn discovery,drilling of proved undeveloped reserves, exploration drilling and landacquisition.

 

 

Explorationand Undeveloped Assets

 

Givenour drilling success in 2007, we are evaluating development options for ourdiscoveries at Vicksburg, South Marsh Island 257 and Mississippi Canyon 72 andlook forward to developing the Longhorn discovery in 2008. Our undevelopeddeep-water discoveries include:

 
| **Well**               | ** ** | **Interest (%)** | ** ** | **Operator Status** | ** ** | **Comments**                          | ** ** |
|------------------------|------------|-----------------------|------------|--------------------------|------------|---------------------------------------|------------|
| Longhorn               |       | 25                    |       | non-operated             |       | sanctioned; production expected 2009  |       |
| Tobago                 |       | 10                    |       | non-operated             |       | sanctioned; production expected 2009  |       |
| Knotty Head            |       | 25                    |       | operated                 |       | discovery; further appraisal required |       |
| Vicksburg              |       | 25                    |       | non-operated             |       | discovery; further appraisal required |       |
| South Marsh Island 257 |       | 35                    |       | non-operated             |       | discovery; production expected 2008   |       |
| Mississippi Canyon 72  |       | 33                    |       | non-operated             |       | discovery; production expected 2008   |       |

 

Duringthe year, we drilled ten exploratory dry holes on the shelf. We also convertedour interests in Anduin and Great White West to overriding royalty interests toaccelerate monetization of the reserves with no further capital investment. Weacquired deep-water acreage during the year and hold approximately 200 blocksand expect this acreage and future exploration opportunities to position uswell for continued growth. In 2008, we plan to drill seven exploration andappraisal wells and have secured drilling rigs for more than half of the wells.Access to deep-water rigs remains limited. To explore our inventory andevaluate existing discoveries, we have secured two new-builddynamically-positioned fifth-generation semi-submersible drilling rigs. We willhave access to each rig for at least two years. We expect the first rig to beavailable mid 2009, followed by the second rig in 2010.

 

**US Production**

 
| ** **   | ** ** | **2007**      | ** ** | **2006**      | ** ** | **2005**      | ** ** |
|--------------|------------|---------------|------------|---------------|------------|---------------|------------|
| ** **   | ** ** | **Before**    | ** ** | **After**     | ** ** | **Before**    | ** ** | **After** | ** ** | **Before** | ** ** | **After** | ** ** |
| **(mboe/d)** | ** ** | **Royalties** | ** ** | **Royalties** | ** ** | **Royalties** | ** ** | **Royalties** | ** ** | **Royalties** | ** ** | **Royalties** | ** ** |
| Deep-water   |       | 19.4          |       | 17.4          |       | 19.6          |       | 17.5 |   | 24.0 |   | 21.5 |   |
| Shelf        |       | 13.8          |       | 11.5          |       | 15.9          |       | 13.2 |   | 17.6 |   | 14.6 |   |
| **Total**    | ** ** | **33.2**      | ** ** | **28.9**      | ** ** | **35.5**      | ** ** | **30.7** | ** ** | **41.6** | ** ** | **36.1** | ** ** |

 

Atyear end, proved reserves of 62 mmboe before royalties (53 after royalties) inthe Gulf of Mexico represented about 6% of our total proved oil and gas andSyncrude reserves. Our Gulf production and reserves are primarily concentratedin four deep-water and five shallow-water (shelf) areas. We operate most ofthis production.

 

8

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Item 1 and 2           Business and Properties     Canada

 

Deep-water

 

Most of our deep-water production comes fromour 100%-operated Aspen field and our 30% non-operated Gunnison field. Theremaining comes from our 50% non-operated Wrigley field and three 100%-operatedproperties purchased in 2007.

 

Aspen is on Green Canyon Block 243 in 3,150feet of water. The project was developed using subsea wells tied back to theShell-operated Bullwinkle platform 16 miles away and began producing inDecember 2002. Our share of 2007 production before royalties was approximately10,400 boe/d (9,500 after royalties).

 

Gunnison is in 3,100 feet of water andincludes Garden Banks Blocks 667, 668 and 669. Gunnison began production inDecember 2003 through our truss SPAR platform that can handle 40,000 bbls/d ofoil and 200 mmcf/d of gas. Our Gunnison SPAR facility has excess capacity,leaving room for growth from regional exploration and processing of third-partyvolumes. We achieved payout on Gunnison in December 2005, just two years afterfirst production. In 2007, our share of production before royalties wasapproximately 7,000 boe/d (6,200 after royalties).

 

Wrigley is on Mississippi Canyon Block 506 in3,300 feet of water. The project consists of a single subsea well tied back tothe Shell-operated Cognac platform 17 miles away. Wrigley began gas productionin July 2007 and our share before royalties in 2007 was approximately 1,100boe/d (1,000 after royalties).

 

The three new deep-water fields acquired in2007 are on Garden Banks Block 205, Green Canyon 137 and Green Canyon 6/50—allin water depths between 700 and 1,100 feet. In 2008, we plan to drill adevelopment well at Green Canyon 6/50.

 

Shelf

 

Our shelf producing assets are offshoreLouisiana, primarily in five 100%-owned field areas: Eugene Island 18, Eugene Island255/257/258/259, Eugene Island 295, Vermilion 302/321/339/340, and Vermilion 76(consisting of Blocks 65, 66 and 67). We continue to exploit these assets andlook for other shelf opportunities. Most of our 2007 shelf activities focusedon development drilling at Eugene Island 258/259, Eugene Island 295 andVermillion 340.

 

Fiscal Terms

 

In 2007, royalty rates on our US productionaveraged 16.5% for shelf volumes and 10.6% for deep-water volumes. The US governmenthas increased royalty rates from 12.5% to 16.7% for new deep-water leasesawarded after July 2007. We qualify for royalty relief at our deep-water Aspenand Gunnison fields on the first 87.5 mmboe of production. However, we may be subjectto royalties at Gunnison if annual commodity prices are higher than thresholdprices set by the US Department of the Interior’s Minerals Management Service(MMS). The oil and gas industry is currently litigating the enforceability ofthese price thresholds. In October 2007, a US District Court ruled that theprice thresholds were unenforceable. The MMS has since appealed this ruling anda decision is expected by the end of 2008. In 2007, commodity prices exceededthese thresholds and we were assessed a royalty at Gunnison of 12.5% by the MMS.If the litigation is not successful, royalties that we have accrued on ourGunnison production will be payable. Our Aspen field is not subject to theminimum price threshold. Although several bills were recently proposedburdening leases awarded in 1998 and 1999 with royalties or severance taxes, nosuch legislation was passed by US Congress.

 

US taxable income is subject to federalincome tax of 35% and state taxes ranging from 0% to 12%.

 

**Canada**

** **

Our strategy in Canada is two fold: 1) developunconventional resource opportunities (oil sands, CBM and shale gas) and 2)maximize value from our established operations through continued conventionaldevelopment and enhanced recovery methods. In 2007, we produced 36,800 boe/dbefore royalties (29,700 after royalties) in Canada, which was approximately 14%of our total production including Syncrude. At year end 2007, Canadian provedreserves (including bitumen and excluding Syncrude) of 386 mmboe beforeroyalties (334 after royalties) were approximately 36% of our total proved oiland gas and Syncrude reserves.

 

Our Canadian conventional assets includeheavy oil production in east-central Alberta and west-central Saskatchewan,

 

 

9

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and natural gas near Calgary and in southernAlberta and Saskatchewan. We operate most of our producing properties and holdalmost one million net acres of undeveloped land across western Canada. Theseassets provide predictable production volumes and earnings while we advance thefollowing initiatives for future growth:

 

·                  Athabasca oil sands—to produce and upgradebitumen into synthetic crude;

·                  enhanced oil recovery (EOR)—to increaserecovery in our heavy oil fields;

·                  coalbed methane (CBM)—to extract natural gasprimarily from Upper Mannville and Horseshoe Canyon coals; and

·                  shale gas—to evaluate natural gas fromorganic shales.

 

In 2007, we invested $1,505 million inCanada; $1,380 million into these growth initiatives. With the expectedcompletion of Long Lake Phase 1 in the Athabasca oil sands, we plan to reduce ourcapital investment in 2008 to approximately $770 million. Our 2008 capitalprograms will focus on completing Phase 1 and work towards sanctioning Phase 2at Long Lake, advance our CBM strategies and evaluate the potential of shalegas.

 

Athabasca Oil Sands

 

The Athabasca oil sands in northeast Albertais a key growth area for Nexen. Our strategy is to economically develop our bitumenresource in phases to provide low-risk, stable, future growth. Our Long LakeProject involves integrating steam-assisted-gravity-drainage (SAGD) bitumenproduction with field upgrading technology to produce a premium synthetic crudeand synthetic gas, which significantly reduces our need

 

 

to purchase natural gas for operations. Wealso have a 7.23% investment in the Syncrude oil sands mining operation.

 

Long Lake Project

 

In 2001, we formed a 50/50 joint venture withOPTI Canada Inc. (OPTI) to develop the Long Lake lease using SAGD for bitumenproduction and proprietary OrCrudeTM technology for our first stage ofupgrading. OPTI has the exclusive Canadian license for the OrCrudeTM technology.We acquired the exclusive right to use this technology with OPTI within approximately100 miles of Long Lake, and the right to use the technology independentlyelsewhere in the world.

 

We operate the Long Lake bitumen extractionprocess and are responsible for constructing, developing and operating the SAGDproject. OPTI is responsible for designing, constructing and operating theupgrader. We share equally in all project reserves, production, operating andcapital costs.

 

*SAGD and Upgrader Integration*

* *

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 the asphaltenesare converted to a low-energy, synthetic fuel gas. This gas is available as alow-cost fuel for generating steam and as a source of hydrogen for thehydrocracking process. The gas will also be burned in a cogeneration plant toproduce electricity to be used on-site and sold to the provincial electricity grid.The energy conversion efficiency for our Long Lake upgrader is about 90%compared to 75% for a typical bitumen-fed coker, which we expect will provideus with an approximate $10/bbl operating cost advantage.

 

*Our Strategic Advantage*

 

Our integrated SAGD and upgrading processaddresses three main economic hurdles of SAGD bitumen production: 1) the highcost of natural gas; 2) the cost and availability of diluent; and 3) therealized price of bitumen. With synthetic gas from the asphaltenes as fuel, weneed to purchase very little additional natural gas. With the upgradingfacilities on site, expensive diluent is not required to transport the bitumento market. And, by upgrading the bitumen into a highly desirable refineryfeedstock or diluent supply, the end product commands light-sweet crude oilpremium pricing.

 

10

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*Project Milestones and Costs*

* *

The Long Lake Project received regulatory approvalin 2003 and Nexen board approval in 2004. Field construction of the SAGD andupgrader facilities began in 2004. In 2006, we substantially completed moduleand site construction of the SAGD facilities. In 2007, we began injecting steamin all 10 well pads. The first six months of steam injection largely involves heatingthe reservoir, followed up by a ramp-up of bitumen production to peak ratesover 12 to 24 months. At the start of production, steam-to-oil ratios will behigh but will decline as bitumen production ramps up to our target rates.Depending on start up issues and any related facility down time, we expectbitumen production before royalties to reach between 35,000 and 45,000 bbls/d(between 17,500 and 22,500 bbls/d net to our share) by the end of 2008, with asteam-to-oil ratio of between 3.5 and 4.0. We expect the steam-to-oil ratio to averageapproximately 3.0 over the long-term.

 

Upgrader module fabrication is complete andall modules are on site. Construction of the upgrader is approximately 97% completeand start up is scheduled for mid 2008. Peak output of premium synthetic crudeoil is expected within 12 to 18 months of upgrader start up and we expect toexit 2008 with synthetic production rates between 30,000 and 40,000 bbls/d(between 15,000 and 20,000 bbls/d net to our share). Production capacity forthe first phase of Long Lake is approximately 60,000 bbls/d (30,000 bbls/d netto our share) of premium synthetic crude, which we expect to reach in 2009. Weexpect to maintain production over the project’s life, estimated at 40 years,by periodically drilling additional SAGD well pairs.

 

**In2008, we will bring on Long Lake and expect bitumen production to reach between35,000 and 45,000 bbls/d (17,500 and 22,500 bbls/d net to us).**

** **

In 2007, we invested $1,025 million at LongLake Phase 1. Long Lake’s total capital costs have increased since project sanctioningdue to design enhancements and industry cost pressures. When our boardsanctioned the project in February 2004, capital costs were estimated at $3.4billion ($1.7 billion net). In December 2004, we accelerated the drilling of anadditional well pad consisting of 13 well-pairs to ensure reliability ofbitumen production at the commencement of upgrader operations at a cost of $98million ($49 million net). In early 2006, we further modified the project designby adding steam generation capacity and soot handling equipment at a cost of$360 million ($180 million net). These scope changes increased the estimatedproject cost to $3.8 billion ($1.9 billion net). Since then, high activity inthe oil sands has placed ongoing cost pressures on labour and services. Aswell, lower than anticipated labour productivity has required a largerworkforce to maintain progress. As a result, the projected costs of Long Lakehave increased from $3.8 billion to between $5.8 billion and $6.1 billion (between$2.9 billion and $3.05 billion net to us). Despite capital cost increases, westill expect to achieve good economic returns which benefit from a significantoperating cost advantage. Combined SAGD, cogeneration and upgrading operatingcosts are expected to average about $17/bbl,

 

11

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substantially lower than coking or other upgradingprocesses. We expect ongoing capital to average between $3/bbl and $4/bbl. Thefull-cycle capital costs of producing and upgrading bitumen using this technologyare comparable to those for surface mining and coking upgrading on abarrel-of-daily production basis.

 

*Future Phases*

* *

We have approximately 249,000 net acres ofbitumen-prone lands in the Athabasca region, with plans to acquire more. We planto continue developing our bitumen lands in phases using our integratedupgrading strategy. In 2005, we announced our plan to duplicate Long Lake bydeveloping Phase 2. In 2007, we invested $114 million on land acquisition,additional drilling, seismic and engineering to develop our leases and advanceregulatory applications for these phases.

 

During 2007, the Alberta government proposedincreases to oil sands royalty rates and implemented climate changelegislation. The federal government also announced climate change proposals;however, legislation has not been drafted. Due to this regulatory uncertainty,we are delaying certain planned expenditures on Phase 2. Phase 2 will befollowed by additional phases every three or four years. Each phase willleverage the knowledge and experience gained from successfully developing LongLake and subsequent projects will be similar in size and design. By keeping thecore team in place and repeating and improving on existing designs andimplementation plans, we expect to gain efficiencies in engineering, modularfabrication and on-site construction. We also anticipate enhanced operating efficienciesas we can train and move people easily between the various plants.

 

*Reserves Recognition*

* *

Under SEC rules and regulations, we arerequired to recognize bitumen reserves rather than the upgraded premiumsynthetic crude oil that we expect to produce and sell. The economic recoverabilityof bitumen reserves is sensitive to natural gas prices, diluent costs andlight/heavy differentials, risks that our integrated project has been designedto virtually eliminate. At December 31, 2007, we recognized proved bitumenreserves of 268 mmboe before royalties (234 after royalties) for our Long LakeProject, representing about 25% of our total proved oil and gas and Syncrudereserves before royalties.

 

Heavy Oil

 

Approximately 45% of our Canadianconventional production is heavy oil. Heavy oil is characterized by highspecific gravity or weight and high viscosity or resistance to flow. Therefore,heavy oil is more difficult and expensive to extract, transport and refine thanother types of oil. Heavy oil also receives a lower price than light oil, asmore expensive and complex refineries are required to refine heavy crude intohigher-value petroleum products.

 

To maximize heavy oil returns, it isimportant to manage capital and operating costs. Our large production base and existinginfrastructure are advantageous in managing these costs. In 2008, we plan tocontinue exploiting our existing fields through drilling and optimizingoperations.

 

Heavy oil reservoirs typically have lowerrecovery factors than conventional oil reservoirs, leaving substantial amounts ofoil in the ground. This creates an opportunity to increase recovery factors byapplying new technology. We are continuing to research various technologies toincrease our heavy oil recoveries with several ongoing pilot projects in west-centralSaskatchewan.

 

Natural Gas

 

Approximately 40% of our Canadian productionis natural gas extracted primarily from shallow sweet reservoirs in southern Albertaand Saskatchewan and from sour gas reservoirs near Calgary. In general,shallower gas targets are cheaper to drill and develop, but have relativelysmaller reserves and lower productivity per well. Sour gas is natural gas thatcontains hydrogen sulfide. Our Balzac field, northeast of Calgary, has beenproducing sour natural gas since 1961. This sour gas is processed through ouroperated Balzac plant.

 

**At theend of 2007, we held more than 725 net sections of land in Alberta with CBMpotential.**

** **

Coalbed Methane (CBM)

 

Approximately 15% of our Canadian productionis from our commercial CBM developments at Corbett, Doris and Thunder in theFort Assiniboine area of central Alberta. We began commercial development inthe Upper Mannville coals in 2005 by applying horizontal well technology toincrease gas production rates and reduce de-watering time from water-saturated coal.Upper Mannville coals are generally deeper than the Horseshoe Canyon “dry coal”play, which is also being commercially developed in Alberta.

 

We have a long-term view of this business andplan to increase our CBM production by progressively developing opportunities onour extensive land base. At the end of 2007, we held more than 725 net sectionsof land in Alberta with CBM potential, some of which overlay existingconventional producing lands. In 2007, we invested approximately $170 millionin exploration and development activities. For 2008, we have slowed our pace ofprogram spending until we gain clarity on the impact of Alberta royaltychanges. In 2008, we plan to tie-in Upper Mannville development wells drilledin 2007 for production and commence development of our Horseshoe Canyon lands.

 

12

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Item 1 and 2           Business and Properties     Yemen

 

Shale Gas

 

As part of our growth strategy inunconventional Canadian resource plays, we acquired approximately 190 netsections of land in an emerging Devonian shale gas play in north easternBritish Columbia. Shale gas is natural gas produced from reservoirs composed oforganic shale. The gas is stored in pore spaces, fractures or absorbed intoorganic matter. Currently, the United States is the largest producer of shale gas.In 2008, we plan to continue our evaluation program to demonstrate thefeasibility of this resource.

 

Fiscal Terms

 

In Canada, we pay two types of royalties tofederal and provincial governments on production from lands where they own thepetroleum and natural gas rights. The first type is a gross royalty (GrossRoyalty) system whereby we pay royalties ranging from 5% to 40% depending upondrilling date, production rate and product sales price. The second type ofroyalty (NPI) applies to our oil sands projects, which includes a 1% royalty ongross revenue prior to the recovery of capital costs. After achieving payout onthese costs, the royalty converts to the greater of 1% of gross revenues or 25%of net profits.

 

During 2007, the Alberta government announceda new royalty framework effective January 1, 2009 that includes proposed increasesto Alberta’s royalty rates, although it has yet to be passed into legislation.Under the new framework, the upper limit of the Gross Royalty system isexpected to increase to 50%, depending on production rate and product salesprice. The new framework will also increase the royalty rates for the NPIroyalty system that applies to oil sands projects. The new royalty rates foroil sands projects will range from 1% to 9% of gross revenue for projects thatare pre-payout of capital costs, and from 25% to 40% of net profit for projectsthat are post-payout. These royalty rates will vary depending on WTI (US$55/bblto US$120/bbl).

 

In addition to royalties, some provincesimpose taxes on production from lands where they do not own the mineral rights.The Saskatchewan government assesses a resource surcharge on gross Saskatchewanresource sales that are subject to crown royalties, ranging from 1.75% to 3.3%.In 2008, the rates will reduce slightly to 1.7% and 3.0%. In Alberta, we aresubject to a freehold mineral tax of approximately 4%.

 

Profits earned in Canada from resourceproperties are subject to federal and provincial income taxes. In late 2007,the federal government reduced the federal corporate income tax rate from 22%in 2007 to 15% by 2012. Provincial income tax rates vary from approximately 10%to 16%.

 

 

**MiddleEast – Yemen**

** **

Yemen has been a significant internationalregion since we first began production at Masila in 1993. We operate the country’slargest oil project and have developed excellent relationships with thegovernment and local communities. 

 

Our strategy in Yemen is to maximize thevalue from our existing blocks, while we continue to search for new reservoirs indeeper horizons. We have two producing blocks: Masila (Block 14) and East AlHajr (Block 51). In 2007, we produced 71,600 bbls/d of oil before royalties(39,800 after royalties), representing approximately 28% of Nexen’s total production.Proved reserves of 41 mmboe before royalties (23 after royalties) compriseapproximately 4% of Nexen’s total proved oil and gas and Syncrude reservesbefore royalties (3% after royalties).

 

Masila Block (Block 14)

 

We operate the Masila Project with a 52%working interest. Our share of 2007 production was 57,000 bbls/d before royalties(29,900 after royalties). After more than 10 years of growth, our Masila fieldshave matured, but significant value still remains. As a result of theProduction Sharing Agreement (PSA) terms that govern Masila production, westill expect to generate approximately 22% of total project free cash flow fromthe remaining proved reserves recoverable before the PSA expires in 2011.

 

13

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Item 1 and 2           Business and Properties     Middle East

 

 

The first successful Masila exploratory wellwas drilled at Sunah in 1990, with additional discoveries quickly following atHeijah and Camaal. Initial production began in July 1993, with the first liftingof oil in August 1993. Masila Blend oil averages 32° API at very low gas-oilratios. Most of the oil is produced from the Upper Qishn formation, but we alsoproduce from deeper formations including the Lower Qishn, Upper Saar, Saar,Madbi, Basal Sand and Basement formations. Production is collected at our CentralProcessing Facility (CPF) where water is separated for reinjection and oil ispumped to the Ash Shihr export terminal on the Indian Ocean and shipped tocustomers, primarily in Asia.

 

We are managing the pace of our drillingprogram to ensure we recover the remaining reserves in the most efficient, cost-effectivemanner. In 2008, we plan to drill ten development wells and sidetracks.

 

The Masila PSA was signed in 1987 between theGovernment of Yemen and the Masila joint venture partners (Masila Partners),including Nexen. Under the PSA, we have the right to produce oil from Masilainto 2011 and to negotiate a five-year extension. Production is divided intocost recovery oil and profit oil. Cost recovery oil provides for the recovery ofall exploration, development, and operating costs that are funded by the MasilaPartners. Costs are recovered from a maximum of 40% of production each year, asfollows:

 
| **Costs**   | ** ** | **Recovery**               |
|-------------|------------|----------------------------|
| Operating   |       | 100% in year incurred      |
| Exploration |       | 25% per year for 4 years   |
| Development |       | 16.7% per year for 6 years |

 

The remaining production is profit oil thatis shared between the Masila Partners and the Government and is calculated on asliding scale based on production. The Masila Partners’ share of

 

 

profit oil ranges from 20% to 33%. Thestructure of the agreement moderates the impact on the Masila Partners’ cashflows during periods of low prices, as we recover our costs first and thenshare any remaining profit oil with the Government. The Government’s share ofprofit oil includes a component for Yemen income taxes payable by the MasilaPartners at a rate of 35%. In 2007, the Masila Partners’ share of production,including recovery of past costs, was approximately 39%.

 

East Al Hajr Block (Block 51)

 

We operate Block 51, which is also governedby a PSA between the Government of Yemen and the East Al Hajr partners (EAH Partners):The Yemen Company (TYCO) (12.5% carried working interest) and Nexen (87.5%working interest). Under the PSA, TYCO has no obligation to fund capital oroperating expenditures. Our effective interest is 100% and for purposes of accountingand reserves recognition, we treat TYCO’s 12.5% participating interest as aroyalty interest. We recognize both the Government’s share and TYCO’s share ofprofit oil under the PSA as royalties and taxes consistent with our treatmentof our Masila operations. The PSA expires in 2023, and we have the right tonegotiate a five-year extension. Under the PSA, the EAH Partners pay a royaltyranging from 3% to 10% to the Government depending on production volumes. Theremaining production is divided into cost recovery oil and profit oil. Cost recoveryoil provides for the recovery of all of the project’s exploration, developmentand operating costs, funded solely by Nexen. Costs are recovered from a maximumof 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 |

 

14

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Items 1 and 2         Businessand Properties     Offshore West Africa

 

The remaining production is profit oil that is shared between the EAHPartners and the Government on a sliding scale based on production rates. TheEAH Partners’ share of profit oil ranges from 20% to 30%. The Government’sshare of profit oil includes a component for Yemen income taxes payable by theEAH Partners at a rate of 35%. In 2007, the EAH Partners’ share of Block 51production, including recovery of past costs, was approximately 54%.

 

The first successful exploratory well was drilled at BAK-A in 2003,with BAK-B discovered shortly after. Block 51 development began in 2004 andincludes a CPF, gathering system and a 22-km tieback to our Masila exportpipeline. Production began in November 2004. During 2007, production averaged 14,600bbls/d before royalties (9,900 after royalties).

 

**Offshore West Africa**

** **

Offshore West Africa is a core area where wealready have discoveries. It offers prolific reservoirs and multipleopportunities to invest in this oil-rich region. Our strategy here is toexplore and develop our portfolio for medium- to long-term growth.

 

 

Nigeria

 

In 1998, we acquired a 20% non-operatedinterest in Block OPL-222 which covers 448,000 acres approximately 50 miles offshorein water depths ranging from 600 to 3,500 feet. Based on the drilling resultsoutlined below, significant hydrocarbons exist on these blocks.

 
| **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 the Usan field is complete andthe field development continues to move forward. We expect the project to advanceto the execution phase shortly and this will facilitate the award of the majordeep-water facilities contracts. The project will have the ability to processan average of 180,000 bbls/d of oil during the initial production plateau periodthrough a new FPSO with a two million barrel storage capacity. We have a 20%interest in exploration and development on this block. In 2008, we plan toinvest approximately $165 million to progress development and award the major deep-waterfacilities contracts. At year-end 2007, proved reserves of 30 mmboe beforeroyalties (25 after royalties) comprise approximately 3% of our total provedoil and gas and Syncrude reserves.

 

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Item 1 and 2           Business and Properties     Other International

 

**OtherInternational**

** **

Colombia

 

Boqueron Block – Guando

 

In 2000, we made our first discovery atGuando on our 20% non-operated Boqueron Block. Boqueron is in the Upper MagdalenaBasin of central Colombia, approximately 45 km southwest of Bogota. Our workinginterest in Guando will decrease to 10% once the field has produced 60 million barrelsof oil, which is expected to occur in early 2009. Our share of 2007 productionaveraged 6,200 bbls/d before royalties (5,700 after royalties), about 2% ofNexen’s total production including Syncrude.

 

Production from Guando is subject to aroyalty between 5% and 25% depending on daily production, and in 2007 averaged 8%.Colombian taxable income is subject to federal income tax of 34% in 2007 and33% in 2008 and future years.

 

Exploration

 

We have interests in three exploration blocksin the Upper Magdalena Basin: EI Queso acquired in 2003, Villarrica Norte Blockin 2005 and EI Guadual in 2007. In 2007, we drilled two unsuccessful wells;Guaini-1 and Atalea-1. We hold five technical evaluation agreements that eachprovide approximately one year to evaluate potential prospects. We are alsoidentifying other growth opportunities in Colombia.

 

Norway

 

As part of our growth strategy in the NorthSea, we participated in the 2006 bid round for exploration rights offshoreNorway and were awarded interests in six licences covering nine blocks in early2007. In 2008, we expect to invest approximately $40 million in additionalseismic and geologic studies. In early 2008, we were awarded interests in threeadditional licences.

 

Norwegian oil and gas activities are subjectto a general corporate income tax rate of 28% plus an additional 50% special petroleumtax. A tax refund of 78% is received on tax losses arising from qualifyingexploration expenses in Norway.

 

**ReserVes,produCtIon and reLated InformatIon**

** **

In addition to the tables below, we refer youto the Supplementary Data in Item 8 of this Form 10-K for information on ouroil and gas producing activities. Nexen has not filed with nor included inreports to any other United States federal authority or agency, any estimatesof total proved crude oil or natural gas reserves since the beginning of thelast fiscal year.

 

Net Sales by Product from Continuing Oil andGas Operations (including Syncrude)

 
| **(Cdn$ millions)**                               | ** ** | **2007**  | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|--------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Conventional Crude Oil and Natural Gas  Liquids (NGLs) |       | 4,077     |       | 2,479     |       | 2,438     |       |
| Synthetic Crude Oil                                    |       | 545       |       | 446       |       | 397       |       |
| Natural Gas                                            |       | 499       |       | 553       |       | 671       |       |
| **Total**                                              | ** ** | **5,121** | ** ** | **3,478** | ** ** | **3,506** | ** ** |

 

Crude oil (including synthetic crude oil) and natural gas liquidsrepresent approximately 90% of our oil and gas net sales, while natural gasrepresents the remaining 10%.

 

16

----

 

Item 1 and 2           Businessand Properties     Operations Statistics

 

Sales Prices and Production Costs (excluding Syncrude)

 
| ** **                    | ** ** | **Average Sales Price (1)** | ** ** | **Average Production Cost (1)** | ** ** |
|-------------------------------|------------|--------------------------------------------|------------|------------------------------------------------|------------|
| ** **                    | ** ** | **2007**                                   | ** ** | **2006**                                       | ** ** | **2005** | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
| Crude Oil and NGLs (Cdn$/bbl) |       |                                       |       |                                           |       |   |   |   |   |   |   |   |   |
| Yemen                         |       | 76.29                                      |       | 71.57                                          |       | 62.07 |   | 12.00 |   | 8.11 |   | 6.75 |   |
| Canada (2)                    |       | 44.07                                      |       | 42.79                                          |       | 40.51 |   | 18.67 |   | 15.50 |   | 14.01 |   |
| United States                 |       | 69.83                                      |       | 65.80                                          |       | 57.63 |   | 9.69 |   | 9.45 |   | 7.33 |   |
| United Kingdom                |       | 76.30                                      |       | 71.19                                          |       | 60.55 |   | 6.94 |   | 11.28 |   | 14.90 |   |
| Other Countries               |       | 71.29                                      |       | 66.09                                          |       | 59.96 |   | 3.76 |   | 3.13 |   | 6.08 |   |
| Natural Gas (Cdn$/mcf)        |       |                                       |       |                                           |       |   |   |   |   |   |   |   |   |
| Canada (2)                    |       | 6.32                                       |       | 6.49                                           |       | 7.51 |   | 2.28 |   | 1.65 |   | 0.95 |   |
| United States                 |       | 7.80                                       |       | 7.86                                           |       | 10.56 |   | 1.61 |   | 1.58 |   | 1.22 |   |
| United Kingdom                |       | 4.71                                       |       | 7.43                                           |       | 7.86 |   | 1.16 |   | 1.88 |   | 2.48 |   |

 

----

*Notes:*

| *(1)* | *Sales prices and  unit production costs are calculated using our working interest production  after royalties.* |
|-------|------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Includes results of  discontinued operations for 2005 (See Note 14 to our Consolidated Financial  Statements).* |

 

Oil and Gas Acreage

 
| ** **               | ** ** | **Developed** | ** ** | **Undeveloped 1** | ** ** | **Total** | ** ** |
|--------------------------|------------|---------------|------------|------------------------|------------|-----------|------------|
| **(thousands of acres)** | ** ** | **Gross**     | ** ** | **Net**                | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Yemen (2)                |       | 50            |       | 29                     |       | 756       |       | 628 |   | 806 |   | 657 |   |
| Canada                   |       | 797           |       | 610                    |       | 1,871     |       | 980 |   | 2,668 |   | 1,590 |   |
| United States            |       | 206           |       | 122                    |       | 1,123     |       | 562 |   | 1,329 |   | 684 |   |
| United Kingdom           |       | 202           |       | 83                     |       | 1,290     |       | 846 |   | 1,492 |   | 929 |   |
| Colombia (4)             |       | 1             |       | —                 |       | 607       |       | 372 |   | 608 |   | 372 |   |
| Nigeria (2), (3)         |       | —        |       | —                 |       | 448       |       | 90 |   | 448 |   | 90 |   |
| Norway                   |       | —        |       | —                 |       | 280       |       | 134 |   | 280 |   | 134 |   |
| **Total**                | ** ** | **1,256**     | ** ** | **844**                | ** ** | **6,375** | ** ** | **3,612** | ** ** | **7,631** | ** ** | **4,456 (5** | **)** |

 

----

*Notes:*

| *(1)* | *Undeveloped acreage is considered to be those  acres on which wells have not been drilled or completed to a point that would  permit production of commercial quantities of crude oil and natural gas  regardless of whether or not such acreage contains proved reserves.* |
|-------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *The acreage is covered by production sharing  contracts.*                                                                                                                                                                                                                   |
| *(3)* | *The acreage is covered by a joint venture  agreement.*                                                                                                                                                                                                                      |
| *(4)* | *The acreage is covered by an association  contract.*                                                                                                                                                                                                                        |
| *(5)* | *Approximately 20% of our net oil and gas acreage  is scheduled to expire within three years if production is not established or  we take no other action to extend the terms. We plan to continue the terms of  many of these licences.*                                    |

 

Producing Oil and Gas Wells

 
| ** **                      | ** ** | **Oil**            | ** ** | **Gas**          | ** ** | **Total**          | ** ** |
|---------------------------------|------------|--------------------|------------|------------------|------------|--------------------|------------|
| **(number of wells)** | ** ** | **Gross (1)** | ** ** | **Net (2)** | ** ** | **Gross (1)** | ** ** | **Net (2)** | ** ** | **Gross (1)** | ** ** | **Net (2)** | ** ** |
| Yemen                           |       | 463                |       | 274              |       | —             |       | — |   | 463 |   | 274 |   |
| Canada                          |       | 2,231              |       | 1,550            |       | 2,884              |       | 2,522 |   | 5,115 |   | 4,072 |   |
| United States                   |       | 193                |       | 94               |       | 202                |       | 141 |   | 395 |   | 235 |   |
| United Kingdom                  |       | 48                 |       | 21               |       | —             |       | — |   | 48 |   | 21 |   |
| Colombia                        |       | 121                |       | 25               |       | —             |       | — |   | 121 |   | 25 |   |
| **Total**                       | ** ** | **3,056**          | ** ** | **1,964**        | ** ** | **3,086**          | ** ** | **2,663** | ** ** | **6,142** | ** ** | **4,627** | ** ** |

 

----

*Notes:*

| *(1)* | *Gross wells are the total number of wells in  which we own an interest.* |
|-------|---------------------------------------------------------------------------|
| *(2)* | *Net wells are the sum of fractional interests  owned in gross wells.*    |

 

17

----

 

Item 1 and 2           Businessand Properties     Drilling Activity

 

Drilling Activity

 
| ** **                               | ** ** | **2007**                 | ** ** |
|------------------------------------------|------------|--------------------------|------------|
| ** **                               | ** ** | **Net Exploratory** | ** ** | **Net Development** | ** ** | ** ** | ** ** |
| **(number of net wells)** | ** ** | **Productive**           | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Productive** | ** ** | ** Dry Holes** | ** ** | **Total** | ** ** | **Total** | ** ** |
| Yemen                                    |       | 1.0                      |       | 1.0 |   | 2.0 |   | 28.0 |   | — |   | 28.0 |   | 30.0 |   |
| Canada                                   |       | 23.2                     |       | 0.6 |   | 23.8 |   | 295.6 |   | 3.2 |   | 298.8 |   | 322.6 |   |
| United States                            |       | 0.8                      |       | 2.9 |   | 3.7 |   | 8.6 |   | 1.0 |   | 9.6 |   | 13.3 |   |
| United Kingdom                           |       | 2.0                      |       | 3.2 |   | 5.2 |   | 4.2 |   | — |   | 4.2 |   | 9.4 |   |
| Colombia                                 |       | —                   |       | 0.9 |   | 0.9 |   | 7.0 |   | — |   | 7.0 |   | 7.9 |   |
| **Total**                                | ** ** | **27.0**                 | ** ** | **8.6** | ** ** | **35.6** | ** ** | **343.4** | ** ** | **4.2** | ** ** | **347.6** | ** ** | **383.2** | ** ** |
|                                          |            |                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                               | ** ** | **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** | ** ** |

 

Wells in Progress

** **

At December 31, 2007, we were drilling 3 wells in Yemen (2 net), 2wells in Canada (2 net), 4 wells in the United States (1.9 net), 3 wells in theUnited Kingdom (1.4 net), and 1 well in Colombia (0.2 net).

 

18

----

 

Items 1 and 2         Businessand Properties     Reserves

 

**Proved Reserves including Proved Undeveloped Reserves**

** **

At December 31,2007, we had 734 mmboe of proved oil and gas reserves before royalties (650after royalties). This is a 1% increase over the prior year (2% afterroyalties). Including Syncrude, our total proved oil and gas and Syncrudereserves increased 1% to 1,058 mmboe (1% to 917 after royalties).

 

The following tableprovides a summary of the changes in our proved oil and gas reserves (beforeroyalties) excluding our Syncrude reserves during 2007. Refer to page 120for proved reserves information on an after-royalties basis.

 
| ** **                 | ** ** | ** ** | ** ** | **United**  | ** ** | **United** | ** ** | ** ** | ** ** | **Other**     | ** ** | ** ** | ** ** |
|----------------------------|------------|------------|------------|-------------|------------|------------|------------|------------|------------|---------------|------------|------------|------------|
| **(mmboe)**                | ** ** | **Canada** | ** ** | **Kingdom** | ** ** | **States** | ** ** | **Yemen**  | ** ** | **Countries** | ** ** | **Total**  | ** ** |
| December 31, 2006     |       | 364        |       | 182         |       | 73         |       | 66         |       | 40            |       | 725        |       |
| Extension and Discoveries  |       | 7          |       | 10          |       | 4          |       | 2          |       | —        |       | 23         |       |
| Revisions                  |       | 28         |       | 44          |       | (12        | )          | 1          |       | —        |       | 61         |       |
| Acquisitions               |       | —     |       | 1           |       | 11         |       | —     |       | —        |       | 12         |       |
| Divestments                |       | —     |       | —      |       | (2         | )          | —     |       | —        |       | (2         | )          |
| Production                 |       | (13        | )          | (30         | )          | (12        | )          | (28        | )          | (2            | )          | (85        | )          |
| **December 31, 2007** | ** ** | **386**    | ** ** | **207**     | ** ** | **62**     | ** ** | **41**     | ** ** | **38**        | ** ** | **734**    | ** ** |

 

Extensions anddiscoveries contributed 23 mmboe. The majority of the increase results fromupdip drilling at Buzzard in the North Sea, appraisal drilling at Longhorn inthe Gulf of Mexico, and ongoing development of coalbed methane in Canada. Otherincreases relate to ongoing exploitation activities in the North Sea, Yemen,the Gulf of Mexico and Canada.

 

More than half of the 61mmboe of positive revisions occurred at Buzzard where drilling results andproduction performance supported higher reserve estimates. About a third of therevisions are from our Long Lake Project where performance of analogouscommercial SAGD projects support increased expected recoveries. The remainingpositive revisions are primarily from price revisions in Canadian heavy oilproperties and the Ettrick field, recovery factor improvements on our CanadianCBM lands and other areas. In the United States, the negative revision mainlyrelates to our deep-water Gulf of Mexico Aspen property where unsuccessfuldevelopment drilling and production declines resulted in a reassessment of theproperty. In addition, four Gulf of Mexico shelf properties recognized negativereserve revisions from unsuccessful recompletions, production declines andincreasing operating costs on older platforms reduced their economic life.

 

Acquisitions anddivestments accounted for a net 10 mmboe addition (8 after royalties),primarily in the Gulf of Mexico where we acquired Shelf properties, pooled ourdeep-water Ringo well within the Longhorn development, and swapped our interestin Great White West for an overriding royalty interest in the entire GreatWhite reservoir. In addition, we acquired additional interests in our operatedScott and Telford properties in the North Sea.

 

The following provides asummary of the changes in our proved oil and gas reserves (before royalties)excluding Syncrude, during the past three years. Refer to page 120 forproved reserves information on an after royalty basis for the past three years.

 
| ** **                 | ** ** | ** ** | ** ** | **United**  | ** ** | **United** | ** ** | ** ** | ** ** | **Other**     | ** ** | ** ** | ** ** |
|----------------------------|------------|------------|------------|-------------|------------|------------|------------|------------|------------|---------------|------------|------------|------------|
| **(mmboe)**                | ** ** | **Canada** | ** ** | **Kingdom** | ** ** | **States** | ** ** | **Yemen**  | ** ** | **Countries** | ** ** | **Total**  | ** ** |
| December 31, 2004     |       | 164        |       | 130         |       | 103        |       | 133        |       | 12            |       | 542        |       |
| Extension and Discoveries  |       | 30         |       | 41          |       | 24         |       | 17         |       | 31            |       | 143        |       |
| Revisions                  |       | 283        |       | 79          |       | (33        | )          | (4         | )          | 1             |       | 326        |       |
| Acquisitions               |       | 2          |       | 1           |       | 11         |       | —     |       | —        |       | 14         |       |
| Divestments                |       | (49        | )          | —      |       | (2         | )          | —     |       | —        |       | (51        | )          |
| Production                 |       | (44        | )          | (44         | )          | (41        | )          | (105       | )          | (6            | )          | (240       | )          |
| **December 31, 2007** | ** ** | **386**    | ** ** | **207**     | ** ** | **62**     | ** ** | **41**     | ** ** | **38**        | ** ** | **734**    | ** ** |

 

19

----

 

Since the end of 2004, we added 483 mmboe, sold 51mmboe and produced 240 mmboe. Extensions and discoveries of 143 mmboe occurredprimarily at our Usan, Ettrick and Buzzard fields, Canadian CBM and heavy oil,and the deep-water Gulf of Mexico. Our net positive revisions of 326 mmboeinclude economic revisions of 261 million boe, related to changes in year-endprices and costs. This includes 246 mmboe from reinstatement of Long Lakebitumen reserves that we had removed due to low bitumen prices at the end of2004. The net technical revisions of 65 mmboe includes 77 mmboe of positiverevisions in the UK primarily attributed to production performance at ourBuzzard property and increased expected recoveries for our Long Lake Project.Negative technical revisions occurred primarily from lower-than-expectedproduction performance at our Aspen field and some Shelf properties in the U.S.Gulf of Mexico. Our divestments are primarily from the 2005 sale of variousCanadian properties.

 

Proved UndevelopedReserves

 

The following table providesa summary of the proved undeveloped reserves (PUDs) for our oil and gasactivities at the end of the last two years:

 
| ** **                 | ** ** | **2007**                  | ** ** |
|----------------------------|------------|---------------------------|------------|
| ** **                 | ** ** | **Before Royalties** | ** ** | **After Royalties** | ** ** |
| **(mmboe)**                | ** ** | **PUDs**                  | ** ** | **Total Proved (1)** | ** ** | **% of Total** | ** ** | **PUDs** | ** ** | **Total Proved (1)** | ** ** | **% of Total** | ** ** |
| Canada                     |       | 236                       |       | 386 |   | 61 | % | 200 |   | 334 |   | 60 | % |
| United Kingdom             |       | 54                        |       | 207 |   | 26 | % | 54 |   | 207 |   | 26 | % |
| United States              |       | 20                        |       | 62 |   | 32 | % | 17 |   | 53 |   | 32 | % |
| Yemen                      |       | 2                         |       | 41 |   | 5 | % | 1 |   | 23 |   | 4 | % |
| Other Countries            |       | 30                        |       | 38 |   | 79 | % | 25 |   | 33 |   | 76 | % |
| **December 31, 2007** | ** ** | **342**                   | ** ** | **734** | ** ** | **47** | **%** | **297** | ** ** | **650** | ** ** | **46** | **%** |
|                            |            |                           |            |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                 | ** ** | **2006**                  | ** ** |
|----------------------------|------------|---------------------------|------------|
| ** **                 | ** ** | **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 | % |
| United States              |       | 9                         |       | 73 |   | 12 | % | 7 |   | 63 |   | 11 | % |
| Yemen                      |       | 9                         |       | 66 |   | 14 | % | 5 |   | 38 |   | 13 | % |
| Other Countries            |       | 31                        |       | 40 |   | 78 | % | 25 |   | 35 |   | 71 | % |
| **December 31, 2006** | ** ** | **315**                   | ** ** | **725** | ** ** | **43** | **%** | **275** | ** ** | **637** | ** ** | **43** | **%** |
|                            |            |                           |            |  |  |  |  |  |  |  |  |  |  |  |

 

----

*Note:*
| *(1)* | * * | *Excludes proved reserves for our Syncrude  operations of 324 mmboe (267 after royalties) in 2007 and 324 mmboe (274  after royalties) in 2006.* |
|-------|----------|--------------------------------------------------------------------------------------------------------------------------------------------------|

 

In 2007, our PUDs increased by 27 mmboe (22 afterroyalties). We added 22 mmboe (14 after royalties) at Long Lake primarilyrelating to increased recovery factors on proved reserves outside of theinitial 81 well-pair SAGD development area. We also added PUDs from ongoingactivities at Buzzard, Ettrick, Longhorn and CBM. We converted 18 mmboe (14after royalties) of PUDs to developed, with the majority relating to Buzzard,Masila, Block 51 and CBM development activities. Other small additions andconversions occurred from ongoing development activities in Canada, UnitedStates, United Kingdom and Colombia.

 

In Canada, our PUDs increased from 216 mmboe (188after royalties) to 236 mmboe (200 after royalties). Substantially all of theincrease relates to Long Lake. Long Lake PUDs of 228 mmboe (194 afterroyalties) are expected to be converted to developed over the next 20 years aswe drill additional wells to provide feedstock to run the upgrader at capacity.

 

The remaining PUDs relate to infill drilling,recompletions or facilities enhancements on our various heavy oil and naturalgas fields. The majority of these PUDs are expected to be converted toproducing reserves in 2008 and 2009. Also, a small portion of the PUDs relateto our CBM properties, which are expected to be converted to producing byinfill drilling and field development planned for 2008 and 2009.

 

In the United Kingdom,our PUDs increased from 50 mmboe (50 after royalties) to 54 mmboe (54 afterroyalties). About 60% of the PUDs relate to Buzzard while the remainder relateto Ettrick. At Buzzard, we converted 6 mmboe of PUDs to producing and added 6mmboe for increased recovery factors on remaining undrilled locations. TheBuzzard PUDs are expected to be converted to proved over the next few years aswe drill additional wells to keep the platform operating at capacity. We expectto convert the majority of Ettrick PUDs to producing when production isinitiated in 2008.

 

20

----

 

In the United States, ourPUDS increased from 9 mmboe (7 after royalties) to 20 mmboe (17 afterroyalties) largely as a result of the Green Canyon 6 acquisition, andactivities at Longhorn and Great White, which are expected to be producing inthe next two years. Almost all of the remaining PUDs are located in the deepwater of the Gulf of Mexico.

 

In other countries, PUDsrelated primarily to our Usan development, offshore West Africa.

 

Excluding Long Lake andUsan, we expect to convert over 80% of our PUDs to producing in the next threeyears. Usan will be converted by 2012 when it is expected to come on stream.Long Lake PUDs will be converted over the next 20 years as new wells aredrilled to offset declines from the initial SAGD wells. At the same time, weexpect our ongoing exploration and development activities to continue to addnew PUDs.

 

During the past threeyears, our total PUDs before royalties increased from 190 mmboe to 342 mmboe(165 to 297 after royalties). As a result, our PUDs before royalties as apercent of total proved reserves excluding Syncrude increased from 35% to 47%(37% to 46% after royalties). During this time, we converted 164 mmboe beforeroyalties (148 after royalties) to developed. These conversions relate tocompletion of development of our Buzzard, Farragon and Duart fields in theUnited Kingdom and Block 51 in Yemen, and ongoing development of workelsewhere. We also added 316 mmboe before royalties (280 after royalties),primarily related to our active development projects at Long Lake, Usan,Ettrick and Longhorn.

 

Basis of ReservesEstimates

 

Reserve estimates in thisreport are internally prepared. Refer to the section on Critical AccountingEstimates—Oil and Gas Accounting—Reserves Determination on page 68 for adescription of our reserves process. As described therein, we have at least 80%of our oil and gas reserve estimates either evaluated or audited annually byindependent qualified reserves consultants. The nature and scope of theindependent evaluations and audits is determined by agreement between us andthe engineering firm. Independent assessments for other companies may,therefore, be different.

 

The following provides anoverview of the nature and scope of the independent evaluations and audits thatwe have performed. An independent evaluation is a process whereby we request athird-party engineering firm to prepare an estimate of our reserves byassessing and interpreting all available data on a reservoir. An independent auditis a process whereby we request a third party engineering firm to prepare anestimate of our reserves by reviewing our estimates, supporting working papersand other data as they feel is necessary. The primary difference is that anauditor reviews our work and estimate in preparing their estimate whereas anevaluator uses the reservoir data to prepare their estimate.

 

In each case, we requesttheir estimate be prepared using standard geological and engineering methodsgenerally accepted by the petroleum industry. Generally accepted methods forestimating reserves include volumetric calculations, material balancetechniques, production and pressure decline curve analysis, analogy withsimilar reservoirs, and reservoir simulation. The method or combination ofmethods used is based on their professional judgement and experience. Inpreparing their estimates, they obtain information from us with respect toproperty interests, production from such properties, current costs ofoperations, expected future development and abandonment costs, current pricesfor production, agreements relating to current and future operations and saleof production, and various other information and data. They may rely on theinformation without independent verification. However, if in the course oftheir evaluation they question the validity or sufficiency of any information,we request that they not rely on such information until they satisfactorilyresolve their questions or independently verify such information. We do notplace any limitations on the work to be performed. Upon completion of theirwork, the independent evaluator or auditor issues an opinion as to whether ourestimate of the proved reserves for that portfolio of properties is, inaggregate, reasonable relative to the criteria set forth in SEC Rule 4-10(a)(2) ofRegulation S-X. These rules define proved reserves as the estimatedquantities of oil and gas which geological and engineering data demonstratewith reasonable certainty to be recoverable in future years from knownreservoirs under existing economic and operating conditions.

 

Our estimate may differfrom the independent evaluators and auditors as they apply their professionaljudgement and experience, which may result in applying different estimatingmethods or interpreting data differently than us. We believe our estimate for aportfolio of properties is reasonable when it is, in aggregate, within 10% ofthe estimate of the independent evaluator or auditor.

 

We engaged DeGolyer andMacNaughton (D&M) to evaluate 100% of our reserves before royalties (100%after royalties) for the United Kingdom, Yemen Masila, Yemen Block 51 andNigeria. A separate opinion was provided on each of these four areas. D&Mprovided an opinion on each of the areas that the proved reserves estimateprepared by us is, in aggregate, reasonable when compared to their estimatewhich was prepared in accordance with SEC Rules.

 

We engaged McDaniel &Associates Consultants Ltd. (McDaniel) to evaluate 99% of our Canadianconventional,

 

21

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Items 1 and 2         Business andProperties     Syncrude Mining

 

CBMand bitumen reserves before royalties (99% after royalties) and to audit 100%of our Syncrude mining reserves before royalties (100% after royalties). The propertieswere selected by management and reviewed with the Reserves Review Committee ofthe Board. All material properties were selected. McDaniel provided an opinionthat the proved reserves estimate prepared by us is, in aggregate, within 10%of their estimate which was prepared in accordance with SEC Rules.

 

Weengaged Ryder Scott Company (Ryder Scott) to evaluate 79% of our US Gulf ofMexico shelf reserves before royalties (79% after royalties). The propertieswere selected by management and reviewed with the Reserves Review Committee ofthe Board. All material properties were selected. Ryder Scott provided anopinion that the difference between their estimate and ours is within the rangeof reasonable differences and that the estimates have been prepared inaccordance with SEC Rules.

 

Weengaged William M. Cobb & Associates, Inc. (Cobb) to evaluate 98%of our US Gulf of Mexico deep-water reserves before royalties (98% afterroyalties). The properties were selected by management and reviewed with theReserves Review Committee of the Board. All material properties were selected.Cobb provided an opinion that the difference between their estimate and ours iswithin the range of reasonable differences and that the estimates have beenprepared in accordance with SEC Rules.

 

**SYNCRUDE MINING OPERATIONS**

 

Wehold a 7.23% participating interest in Syncrude Canada Ltd. (Syncrude). Thisjoint venture was established in 1975 to mine shallow oil sands deposits usingopen-pit mining methods, extract the bitumen and upgrade it to a high-quality,light (32°API), sweet, synthetic crude oil.

 

Syncrudeexploits a portion of the Athabasca oil sands that contains bitumen in theunconsolidated sands of the McMurray formation. Ore bodies are buried beneath50 to 150 feet of over-burden, have bitumen grades ranging from 4 to 14 percentby weight and ore bearing sand thickness of 100 to 160 feet. Syncrude’soperations are on eight leases (10, 12, 17, 22, 29, 30, 31, and 34) covering248,300 hectares, 40 km north of Fort McMurray in northeast Alberta. Syncrudemines oil sands at three mines: Base, North, and Aurora North. These locationsare readily accessible by public road. Trucks and shovels are used to collectthe oil sands in the open pit mines. The oil sands are transferred for processingusing a hydro-transport system.

 

Theextraction facilities, which separate bitumen from oil sands, are capable ofprocessing more than 270 million tons of oil sands per year and from 150 to 160mmbbls of bitumen

 

 

peryear depending on the average bitumen ore grade. To extract bitumen, the oilsands are mixed with water to form a slurry. Air and chemicals are added toseparate bitumen from the sand grains. The process at the Base Mine uses hotwater, steam and caustic soda to create a slurry, while at the North and AuroraNorth Mines, the oil sands are mixed with warm water to produce a slurry. Mostof the water used in operations is recycled from the upgrader and mine sites.Incremental water is drawn from the Athabasca River in accordance with existinglicenses. In late 2007, the Base Mine was shut down after Syncrude recoveredall of the available oil sands in the final pit.

 

**Our Syncrude production increased to 22,100 bbls/d in 2007, followingcompletion of the Stage 3 expansion in 2006.**

 

Theextracted bitumen is fed into a vacuum distillation tower and three cokers forprimary upgrading. The resulting products are then separated into naphtha,light gas oil, and heavy gas-oil streams. These streams are hydrotreated toremove sulphur and nitrogen impurities to form light, sweet, synthetic crudeoil. Sulphur and coke, which are by-products of the process, are stockpiled forpossible future sale.

 

Thehigh quality of Syncrude’s synthetic crude oil allows it to be sold at pricesapproximating WTI. In 2007, about 35% of the synthetic crude oil was sold toEdmonton area refineries, and the remaining 65% was sold to refineries in easternCanada and the mid-western United States. Electricity is provided to Syncrudefrom two generating plants on site: a 270 MW plant and an 80 MW plant.

 

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Sinceoperations started in 1978, Syncrude has shipped more than 1.8 billion barrelsof synthetic crude oil to Edmonton, Alberta, by Alberta Oil Sands Pipeline Ltd.The pipeline was expanded in 2004 to accommodate increased Syncrude production.

 

AtDecember 31, 2007, our total investment in the property, plant andequipment, including surface mining facilities, transportation equipment, andupgrading facilities, was approximately $1.3 billion. Based on developmentplans, our share of future expansion and equipment replacement costs over thenext 35 years is expected to be about $2.8 billion.

 

In1999, the Alberta Energy and Utilities Board (AEUB) extended Syncrude’soperating license for the eight oil sands leases through to 2035. The licensepermits Syncrude to mine oil sands and produce synthetic crude oil fromapproved development areas on the oil sands leases. The leases areautomatically renewable as long as oil sands operations are ongoing or theleases are part of an approved development plan. All eight leases are includedin a development plan approved by the AEUB. There were no known commercialoperations on these leases prior to the start up of operations in 1978.

 

In1999, the AEUB approved an increase in Syncrude’s production capacity to465,700 bbls/d.  At the end of 2001,Syncrude had increased its synthetic crude oil capacity to 246,500 bbls/d withthe development of the Aurora North Mine, which involved extending miningoperations to a new location about 25 miles north of the main Syncrudesite.  The next expansion of Syncrudecame on stream in 2006, increasing capacity to 360,000 bbls/d with thecompletion of the Stage 3 project.

 

Syncrudepays a royalty to the Alberta government. As of January 2002, this royalty was equal to the greater of 1% of grossrevenue or 25% of net profit after deducting new capital expenditures.  IN connection with the government’s review ofAlberta royalty rates in 2007, the Syncrude owners entered into negotiations atthe end of 2007 at the request of the government that may result in revisedroyalty terms.  These negotiations mayresult in higher royalties paid to the Alberta government in the future.

 

In2007, Syncrude’s production of marketable synthetic crude oil was 305,000bbls/d.  Nexen’s share was 22,100 bbls/dbefore royalties (18,800 after royalties).

 

Thefollowing table provides some operating statistics for Syncrude operations:

 
| ** **                                     | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| **Total Mined Volume (1)**                     |       |     |       |     |       |     |       |
| Millions of Tons                               |       | 470      |       | 428      |       | 353      |       |
| Mined Volume to Oil Sands Ratio (1)            |       | 2.1      |       | 2.2      |       | 2.1      |       |
| **Oil Sands Processed**                        |       |     |       |     |       |     |       |
| Millions of Tons                               |       | 220      |       | 192      |       | 169      |       |
| Average Bitumen Grade (weight%)                |       | 11.6     |       | 11.3     |       | 11.1     |       |
| **Bitumen in Mined Oil Sands**                 |       |     |       |     |       |     |       |
| Millions of Tons                               |       | 26       |       | 22       |       | 19       |       |
| Average Extraction Recovery (%)                |       | 92       |       | 90       |       | 89       |       |
| **Bitumen Production (2)**                     |       |     |       |     |       |     |       |
| Millions of Barrels                            |       | 133      |       | 112      |       | 94       |       |
| Average Upgrading Yield (%)                    |       | 84       |       | 85       |       | 85       |       |
| **Gross Synthetic Crude Oil Shipped (3)**      |       |     |       |     |       |     |       |
| Millions of Barrels                            |       | 111.3    |       | 94.3     |       | 78.1     |       |
| **Nexen’s Share of Marketable Crude Oil** |       |     |       |     |       |     |       |
| Millions of Barrels Before Royalties           |       | 8.1      |       | 6.8      |       | 5.7      |       |
| Millions of Barrels After Royalties            |       | 6.9      |       | 6.2      |       | 5.6      |       |

 

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*Notes:*
| *(1)* | * * | *Includes  pre-stripping of mine areas.*                                                                                                                                                                  |
|-------|----------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | * * | *Bitumen  production in barrels is equal to bitumen in mined oil sands multiplied by  the average extraction recovery and the appropriate conversion factor.*                                             |
| *(3)* | * * | *Approximately  1.0% of the produced synthetic crude oil is used internally, primarily for  diesel that fuels the trucks and shovels at Syncrude. The remaining synthetic  crude oil is sold externally.* |

 

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Items 1 and 2         Businessand Properties     Energy Marketing

 

**ENERGY MARKETING**

 

Ourmarketing group sells proprietary and third-party natural gas, crude oil,natural gas liquids, ethanol and power in certain regional global markets. Wehave built a solid strategic presence within various North American regionalmarkets and have extended our presence into certain global markets. We focus onsecuring access to transportation, storage and facilities, as well as thecommodities we produce or acquire. We optimize the margin on our base businessby physically and financially trading around our access to these physicalassets. We also trade financially for profit where we see opportunities in themarket. We use financial and derivative contracts, including futures, forwards,swaps and options for hedging and trading purposes.

 

Ourmarketing strategy is to:

 

·                  obtaincompetitive pricing on the sale of our oil and gas production;

·                  provide marketintelligence in support of our oil and gas operations;

·                  providesuperior customer service to producers and consumers;

·                  capitalize onmarket opportunities through physical and financial trading; and

·                  optimizephysical assets or contracts to which we have access.

 

Thisstrategy aligns with our corporate focus on realizing the full value from ourassets and provides us with the market intelligence needed to deliver currentand future oil and gas production to market at competitive pricing.

 

**MarketingOffice Locations**

 

 

**NorthAmerican Gas Marketing**

 

Themarketing and trading of North American natural gas is our marketing group’slargest revenue source. We focus on key regional markets where we have astrategic presence—solid customer relationships, in-depth understanding of themarket or established physical assets. We capture regional opportunities bymanaging supply, transportation and storage assets for producers and end users.In addition to the fee-for-service income we realize from managing theseassets, we generate further revenue by:

 

·                  capitalizing onlocation spreads (differences in prices between locations) using ourtransportation assets;

·                  capitalizing ontime spreads (differences in prices between summer and winter) using ourstorage assets; and

·                  financialtrading of location and time spreads.

 

Wehave offices in key regions including Calgary, Detroit and Houston. Our Calgaryoffice provides a variety of services, including supply, storage, andtransportation management as well as netback pool arrangements and othercustomer services. Our customers include producers and consumers in westernCanada as well as consumers (including utilities) in eastern Canada, thenorth-eastern United States and the US mid-continent. Our Detroit office worksclosely with Calgary to provide services to our customers and our presence inHouston has established us in the Gulf Coast region. We use our access totransportation and storage facilities to optimize returns for ourselves as wellas our customers.

 

24

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In2003 and 2004, we grew our asset base by acquiring physical gas purchase andsales contracts, as well as natural gas transportation capacity, on favourableterms. This gave us access to new third party gas supply until the end of 2008,pipeline capacity to 2016 and new relationships that have enabled us tonegotiate new gas purchase and sales contracts. We continue to pursue opportunitiesto grow our storage and transportation positions by reviewing acquisitions andparticipating in the normal bidding processes. Our position as a physicalmarketer at multiple delivery points in key markets gives us flexibility tocapitalize on time and location spreads. With pipeline capacity, we can movegas from producing regions to take advantage of price differences. At the endof 2007, we held 2 bcf/d of pipeline capacity, primarily between western Canadaand the eastern US, and we continue to expand our presence into other marketswithin North America. We also use storage capacity to store normally cheapersummer gas in the ground until the winter heating season arrives. We had accessto 39 bcf of natural gas storage facilities at the end of the year.

 

**At year end, we had access to 39 bcf of natural gas storage facilities.**

 

Inaddition to transportation and storage assets, we enter into financialcontracts that enable us to capture profits around time and location spreads.The risks we assume on these contracts are based on fundamental analysis andknowledge of regional markets. The risk is managed pro-actively by our productgroup teams and monitored by our risk group, with regular reporting tomanagement and the board of directors.

 

**North AmericanCrude Oil Marketing**

 

Ourcrude oil business focuses on marketing physical crude oil to end-use refiners.The crude oil group markets Nexen’s production and more than 650,000 bbls/d ofthird-party production. In addition to physical marketing, we take advantage ofquality, time and location spreads.

 

OurNorth American operations focus on key regions supported by our offices inCalgary, Houston and Denver. In western Canada, our producer services groupconcentrates on purchasing from a diversified supply base, while our tradingteam seeks to optimize the mix for sale to refiners. Traditionally, the Chicagoand Denver areas have been key markets for our western Canadian crude, however,we continue to expand our presence into the US Gulf Coast. Our deep-water Gulfof Mexico crude oil production has expanded our presence in that market throughour Houston office. At the end of 2007, we had access to 2.7 mmbbls of storageand over the course of the year, marketed approximately 655 mbbls per day.

 

Ouroperations also include North American natural gas liquid (NGL) and ethanolbusinesses that focus on buying and selling NGLs, as well as ethanol andnatural gasoline. These businesses acquire and move product within NorthAmerica. They also provide natural gasoline as a denaturant for ethanolproduction and market the finished ethanol in the US. At the end of 2007, wehad access to 550 mbbls of NGL storage and over the course of the year, movedapproximately 26 mbbls per day of product.

 

Ourcrude oil marketing group also enters into financial contracts intended tocapture trading profits around time, quality and location spreads. Like gasmarketing, the risks assumed are based on fundamental analysis and proprietaryknowledge of regional markets, and are monitored by our risk group.

 

**NorthAmerican Power Marketing**

 

Ourpower marketing group is responsible for optimizing our 50% interest in a 120MW gas-fired, combined-cycle power generation facility at Balzac, Alberta, aswell as our 50% interest in the 70 MW Soderglen wind power operation insouthern Alberta. We also market power to larger commercial, industrial andmunicipal clients in Alberta. We are currently the largest supplier of power tocommercial and industrial sectors in the province. Our Balzac facility beganoperations in 2001 and Soderglen in October 2006. We expect to increaseour power generation capacity with a 170 MW cogeneration facility at Long Lakein 2008. We have a 50% interest in this project.

 

**Europe**

 

In2006, we acquired Foundation Energy, a UK-based European gas and powermarketing business. Our trading strategies include capitalizing on time andlocation spreads involving the UK and German gas and power markets, usingprimarily financial contracts. We are increasing our presence in both the UKand continental Europe physical gas markets. During the year, we secured accessto transportation and storage capacity in the UK and Europe. We recruited anexperienced crude oil marketing team and established an office in London, UK in2006 to maximize the value of our North Sea production. The team begansuccessfully marketing Buzzard crude oil production in 2007.

 

**Asia**

 

Ourinternational team in Asia continues to focus on the physical marketing ofMasila crude oil. In order to meet customer needs, we may occasionally marketother regional crude types. In addition to our own crude, we market productionfor our partners and third parties in the Yemen region. By locating ourinternational crude oil marketing office in Singapore, we are well positioned toserve both the producing region and the Asian refining market.

 

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Items 1 and 2         Businessand Properties     Chemicals

 

**CHEMICALS**

 

In2005, we monetized part of our chemicals business through an initial publicoffering of the Canexus Income Fund. We have retained a 61.4% interest in ourchemicals business, and we continue to fully consolidate chemicals in ourConsolidated Financial Statements.

 

Ourchemicals business manufactures sodium chlorate and chlor-alkali products(chlorine, caustic soda and muriatic acid) in Canada and Brazil. Thisproduction is sold in North and South America, with some sodium chloratedistributed in Asia. Our manufacturing facilities are modern, reliable andstrategically located to capitalize on competitive power costs ortransportation infrastructure to minimize production and delivery costs. Thisenables us to have reliable supplies and low costs—key factors for marketingbleaching chemicals.

 

Electricityis the most significant operating cost in producing sodium chlorate andchlor-alkali products, making up over half our cash costs. Therefore, ourcurrent facilities are strategically located to take advantage of economicpower sources. Our second highest cost is transportation. The proximity of ourmanufacturing plants to major customers and competitive freight rates minimizeour transportation 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.

 

 

Togrow value in our chemicals business, we focus on reducing our costs whilemaintaining market share, building a sustainable North American customer baseand capturing new offshore opportunities.

 

AverageAnnual Production Capacity

 
| **(short tons)** | ** ** | **2007**    | ** ** | **2006**    | ** ** | **2005**    | ** ** |
|-----------------------|------------|-------------|------------|-------------|------------|-------------|------------|
| **Sodium Chlorate**   |       |        |       |        |       |        |       |
| North America         |       | 450,055     |       | 446,208     |       | 446,208     |       |
| Brazil                |       | 68,563      |       | 68,563      |       | 68,563      |       |
| **Total**             | ** ** | **518,618** | ** ** | **514,771** | ** ** | **514,771** | ** ** |
| **Chlor-alkali**      |       |        |       |        |       |        |       |
| North America         |       | 364,500     |       | 356,002     |       | 356,002     |       |
| Brazil                |       | 109,430     |       | 109,430     |       | 109,430     |       |
| **Total**             | ** ** | **473,930** | ** ** | **465,432** | ** ** | **465,432** | ** ** |

 

**NorthAmerica**

 

TheNorth American pulp and paper industry consumes approximately 95% of thecontinent’s sodium chlorate production. We market our sodium chlorate productionto numerous pulp and paper mills under multi-year contracts that contain priceand volume adjustment provisions. Approximately 32% of this production is soldin Canada, 61% in the US, and the rest is marketed offshore.

 

Weare the third-largest manufacturer of sodium chlorate in North America withfour Canadian facilities: Nanaimo, British Columbia; Bruderheim, Alberta;Brandon, Manitoba; and Beauharnois, Quebec.

 

InOctober 2004, we completed an expansion of our Brandon plant, increasingcapacity to 260,000 tonnes per year. Brandon is the world’s largest sodiumchlorate facility and has one of the lowest cost structures in the industry,significantly enhancing our competitive position in North America. In late2006, we began another expansion at Brandon which is expected to increasecapacity by 33,000 tonnes per year, by mid 2008.

 

Ourchlor-alkali facility at North Vancouver, British Columbia, manufacturescaustic soda, chlorine and muriatic acid. Almost all of our caustic soda isconsumed by local pulp and paper mills, while our chlorine is sold to variouscustomers in the polyvinyl chloride, water purification and petrochemicalsindustries, primarily in the United States. In early 2008, a technologyconversion project for the North Vancouver facility was sanctioned. Theconversion project will replace existing diaphragm technology and assets withnewer, proven membrane technology that is expected to be more cost effectiveand will expand productive capacity by 35%. The project is expected to becompleted early 2010.

 

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Items 1 and 2         Businessand Properties     Regulations

 

**Brazil**

 

Weentered Brazil in 1999 by acquiring a sodium chlorate plant and a chlor-alkaliplant from Aracruz Cellulose S.A. (Aracruz), the leading manufacturer of pulpin Brazil. The majority of the sodium chlorate production is sold to Aracruzunder a long-term sales agreement that expires in 2024. Most of the chlorineand about 15% of the sodium chlorate production is sold in the merchant marketunder shorter-term contracts. In 2002, we completed an expansion at bothfacilities to meet Aracruz’s growing needs. The majority of our electricityneeds are supplied by a long-term supply contract in Brazil.

 

**GOVERNMENT REGULATIONS**

 

Ouroperations are subject to various levels of government controls and regulationsin the countries where we operate. These laws and regulations include mattersrelating to land tenure, drilling, production practices, environmentalprotection, marketing and pricing policies, royalties, various taxes and leviesincluding income tax, and foreign trade and investment, that are subject tochange from time to time. Current legislation is generally a matter of publicrecord, and we are unable to predict what additional legislation or amendmentsmay be proposed that will affect our operations or when any such proposals, ifenacted, might become effective. We participate in many industry andprofessional associations and monitor the progress of proposed legislation andregulatory amendments.

 

**ENVIRONMENTAL REGULATIONS**

 

Ouroil and gas, Syncrude and chemical operations are subject to government lawsand regulations designed to protect and regulate the discharge of materialsinto the environment in countries where we operate. We believe our operationscomply in all material respects with applicable environmental laws. To reduceour exposure, we apply industry standards, codes and best practices to meet orexceed these laws and regulations. Occasionally, we may conduct activities in countrieswhere environmental regulatory frameworks are in various stages of evolution.Where regulations are lacking, we observe Canadian standards where applicable,as well as internationally accepted industry environmental managementpractices.

 

Wehave an active safety, environment and social responsibility group that ensuresour worldwide operations are conducted in a safe, ethical and sociallyresponsible manner. We have developed policies for continuing compliance withenvironmental laws and regulations in the countries in which we operate.

 

**EnvironmentalProvisions and Expenditures**

 

Theultimate financial impact of environmental laws and regulations is not clearlyknown and cannot be reasonably estimated as new standards continue to evolve inthe countries in which we operate. We estimate our future environmental costsbased on past experience and current regulations. At December 31, 2007,$832 million ($2,165 million, undiscounted, adjusted for inflation) has beenprovided in our Consolidated Financial Statements for asset retirementobligations. In 2007, we increased our retirement obligations for futuredismantlement and site restoration by $105 million primarily from ongoingdevelopment of the Long Lake Project in the Athabasca oil sands and from industrycost pressures in the North Sea.

 

In2007, our capital expenditures for environmental-related matters, includingenvironment control facilities, were approximately $23 million. Our operatingexpenditures for environmental-related matters were approximately $4 million.In 2008, we estimate these expenditures to be approximately $27 million.

 

**EMPLOYEES**

 

Wehad 4,058 employees on December 31, 2007, of which 326 were employed undercollective bargaining schemes. Information on our executive officers is presentedin Item 10 of this report.

 

**ITEM 1A. RISK FACTORS**

 

**RISKFACTORS**

 

Ouroperations are exposed to various risks, some of which are common to others inour industry and some of which are unique to our operations.

 

**Asubstantial or extended decline in oil and natural gas prices could have amaterial adverse effect on us.**

 

Crudeoil and natural gas are commodities which are sensitive to numerous worldwidefactors, many of which are beyond our control, and are generally sold atcontract or posted prices. Changes in world crude oil and natural gas pricesmay significantly affect our results of operations and cash generated fromoperating activities. Consequently, such prices also may affect the value ofour oil and gas properties and our level of spending for oil and gasexploration and development.

 

Ourcrude oil prices are based on various reference prices, primarily Brent andWest Texas Intermediate (WTI) crude oil reference prices and other prices whichgenerally track the movement of Brent and WTI. Adjustments are made to thereference price to reflect quality differentials and transportation. Brent, WTIand other international reference prices are affected by numerous and complexworldwide factors such as supply and demand fundamentals, economic outlooks,production quotas set by the Organization of Petroleum Exporting Countries andpolitical events. Quality differentials are affected by local supply and demandfactors.

 

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Items 1 and 2         Businessand Properties     Risk Factors

 

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

 

Theoil and gas industry is highly competitive, particularly in the followingareas:

 

·                  gaining accessto areas or countries known to have available resources;

·                  searching forand developing new sources of crude oil and natural gas reserves;

·                  constructingand operating crude oil and natural gas pipelines and facilities; and

·                  transporting andmarketing crude oil, natural gas and other petroleum products.

 

Ourcompetitors include national oil companies, major integrated oil and gascompanies and various other independent oil and gas companies. The petroleumindustry also competes with other industries in supplying energy, fuel andrelated products to customers. The pulp and paper chemicals market is alsohighly competitive. Key success factors in each of these markets are price,product quality, and logistics and reliability of supply.

 

Competitiveforces may result in shortages of prospects to drill, shortages of labour andequipment to carry out exploration, development or operating activities, andshortages of infrastructure to produce and transport production. It may alsoresult in an oversupply of crude oil and natural gas. Each of these factorscould negatively impact our costs and prices and, therefore, our financialresults.

 

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

 

Acquiring,developing and exploring for oil and natural gas involves many risks. Theseinclude:

 

·                  encounteringunexpected formations or pressures;

·                  prematuredeclines of reservoirs;

·                  blow-outs, wellbore collapse, equipment failures and other accidents;

·                  craterings andsour gas releases;

·                  uncontrollableflows of oil, natural gas or well fluids; and

·                  environmentalrisks.

 

Weoperate two facilities that are located in close proximity to populated areas,and each processes materials of potential harm to the local populations. AtBalzac, just north of Calgary, we operate a gas plant that has been producingsour gas for over 45 years. Through our ownership in Canexus LimitedPartnership, we operate a chlor-alkali plant in North Vancouver that has beenproducing chlorine for almost 50 years.

 

Wemay not be fully insured against all of these risks. Losses resulting from theoccurrence of these risks may materially impact our financial results.

 

**Ouroffshore operations are subject to unique operating risks.**

 

Offshoreoperations are subject to a variety of operating risks peculiar to the marineenvironment, such as damage or loss from hurricanes or other adverse weatherconditions. These conditions can cause substantial damage to facilities andinterrupt production.

 

Ouroperations in the Gulf of Mexico have been suspended, from time to time, due tohurricanes or tropical storms. In the last five years, we have had a fewinstances where production was suspended for an extended period of time anddamage to facilities was incurred. In late August 2005, we shut-in all ofour production in the Gulf of Mexico, consisting of approximately 50,000 boe/dbefore royalties, and ceased drilling operations in anticipation of HurricaneKatrina. Production was restored in early September for most of ourfields. In late September 2005, we again shut-in all of our production andceased drilling operations in anticipation of Hurricane Rita. While we incurredminimal damage to most of our facilities, extensive damage was incurred to thethird party infrastructure necessary to accommodate our production. As aresult, our 2005 annualized production was reduced by approximately 6,000boe/d. These storms also resulted in damage to rigs under contract with us,which increased our costs and delayed our drilling schedule. In each of theseinstances, there was no significant financial impact after businessinterruption and property insurance claims.

 

Ourexploration and development capital programs in our offshore operations areexposed to risk of delay or additional costs by limited access to drillingrigs. Recent industry pressure in the Gulf of Mexico has reduced theavailability of drilling rigs. Our profitability and success at findingreserves or bringing new production on stream may be reduced by extended delaysand/or higher costs of obtaining drilling rigs.

 

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

 

Ourfuture crude oil and natural gas reserves and production, and therefore ouroperating cash flows and results of operations, are highly dependent upon oursuccess in exploiting our current reserve base and acquiring or discoveringadditional reserves. Without reserve additions through exploration, developmentor acquisitions, our reserves and production will decline over time as reservesare produced. The business of exploring for, developing or acquiring reservesis capital intensive. To the extent cash flows from operations are insufficientand external sources of capital become limited or unavailable, our ability tomake the necessary capital investments to maintain and expand our oil andnatural gas reserves and production will be impaired.

 

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Items 1 and 2         Businessand Properties     Risk Factors

 

Discoveredoil and natural gas reserves are generally only produced when they areeconomically recoverable. As such, oil and gas prices and capital and operatingcosts have an impact on whether reserves will ultimately be produced. Asrequired by SEC rules, our proved reserves represent the quantities that weexpect to economically recover using prices and costs at the end of the year.Accordingly, proved reserves can increase or decrease under different price andcost scenarios. Our bitumen reserves are particularly sensitive to year endprices and costs. Under SEC rules, we are required to recognize our oil sandsas bitumen reserves rather than the upgraded premium synthetic crude oil thatwe expect to produce from the Long Lake Project. As a result, we expectprice-related revisions, both positive and negative, to occur in the future asthe economic producibility of our bitumen reserves are sensitive to year-endprices. In particular, since we recognize our oil sands as bitumen reserves andthey are related to one project, all or none of the reserves will likely beconsidered economic depending on the year-end prices for bitumen, diluent andnatural gas, even though the Long Lake Project has minimal exposure to thesefactors.

 

**Ourproved reserves include undeveloped properties that require additional capitalto bring them on-stream.**

 

UnderSEC rules, the definition of proved undeveloped reserves includes reserves thatare expected to be recovered from new wells on undrilled acreage or fromexisting wells where a relatively major expenditure is still required beforesuch wells may begin production. Such reserves may be recognized when plans arein place to make the required investments to convert these undeveloped reservesto producing. 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. At December 31, 2007, 47% of our proved reservesbefore royalties (46% after royalties) were undeveloped. Refer to page 20for information on PUDs.

 

**Ourheavy oil production is more expensive and yields lower prices than light oiland gas.**

 

Heavyoil is characterized by high specific gravity or weight and high viscosity orresistance to flow. Because of these features, heavy oil is more difficult andexpensive to extract, transport and refine than other types of oil. Heavy oilalso yields a lower price relative to light oil and gas, as a smallerpercentage of high-value petroleum products can be refined from heavy oil. As aresult, our heavy oil operations are exposed to the following risks:

 

·                  additionalcosts may be incurred to purchase diluent to transport heavy oil;

·                  there could bea shortfall in the supply of diluent which may cause its price to increase; and

·                  the market forheavy oil is more limited than for light oil making it more susceptible tosupply and demand fundamentals which may cause the price to decline.

 

Anyone or a combination of these factors could cause some of our heavy oilproperties to become uneconomic to produce and/or result in negative reserverevisions.

 

**TheLong Lake Project faces additional risks compared to conventional oil and gasproduction.**

 

TheLong Lake Project is planned as a fully integrated production, upgrading andcogeneration facility. We intend to use steam assisted gravity drainage (SAGD)technology to recover bitumen from oil sands. As designed, the bitumen will bepartially upgraded using the proprietary OrCrudeTM process, followed byconventional hydrocracking to produce a sweet, premium synthetic crude oil. TheOrCrudeTM process also yields liquid asphaltines that will be gasified intosyngas. This syngas will be used as fuel for the SAGD process, a source ofhydrogen in the upgrading process, and to generate electricity through acogeneration facility.

 

Wehave a 50% working interest in this project, and our share of the capital costsis estimated to be between $2.9 billion and $3.05 billion ($5.8 billion and$6.1 billion gross). This includes a contingency reserve of $150 million ($300million gross) for cost and productivity pressures over and above currenttrends. Given the initial investment and operating costs to produce and upgradebitumen, the payout period for the project is longer and the economic return islower than a conventional light oil project with an equal volume of reserves.

 

Inaddition to the risks associated with heavy oil production stated above, risksassociated with our Long Lake Project include the following:

 

UncertainTime Line and Cost of the Project

 

TheLong Lake Project is currently in the construction and commissioning stage.There is a risk that actual costs to construct and develop may be higher thanexpected or that the project may not be completed on time or at all due to manyfactors, including:

 

·                  constructionperformance falling below expected levels of output or efficiency;

·                  labourdisputes, disruptions or declines in productivity;

·                  increases inmaterials or labour costs;

·                  inability toattract sufficient numbers of qualified workers;

·                  design errors;

·                  contractor oroperator errors;

·                  non-performanceby third-party contractors;

·                  changes inproject scope;

·                  delays inobtaining, or conditions imposed by, regulatory approvals;

 

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·                  breakdown orfailure of equipment or processes;

·                  violation ofpermit requirements;

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

·                  disruption inthe supply of energy.

 

Thecapital cost estimate at the time our board sanctioned the project in February 2004was $3.4 billion (gross). In December 2004, we accelerated the drilling ofan additional well pad consisting of 13 well-pairs to increase certainty andreliability of bitumen production at the commencement of upgrader operations ata cost of $98 million (gross). In early 2006, we further modified the projectdesign by adding steam generation capacity and soot handling equipment at acost of $360 million (gross). These scope changes increased the estimatedproject cost to $3.8 billion. High activity in the oil sands region is placingongoing pressure on the costs of labour and services. In addition, labourproductivity has been lower than anticipated, requiring a larger workforce tomaintain progress. In October 2007, we announced that the projected costestimate for Phase 1 ranges from $5.8 to $6.1 billion ($2.9 to $3.05 billionnet to Nexen). We are on track to complete the construction and commencecommissioning of all units in sufficient time for first production of syntheticcrude oil in mid 2008.

 

Applicationof Relatively New SAGD Bitumen Recovery Process

 

SAGDhas been used in western Canada to increase recoveries from conventional heavyoil reservoirs for over a decade. However, application of SAGD to the in-siturecovery of bitumen from oil sands is relatively new. Some of the SAGD oilsands applications to date have been pilot projects, however several commercialSAGD projects have been in steady state operation for over five years.

 

Ourestimates for performance and recoverable volumes for the Long Lake Project arebased primarily on our three well-pair SAGD pilot and industry performance fromSAGD operations in like reservoirs in the McMurray formation in the Athabascaoil sands. Using this data, our assumptions included average well-pairproductivity of 900 bbls/d of bitumen and a long-term steam-to-oil ratio of3.0. There can be no certainty that our SAGD operation will produce bitumen atthe expected levels or steam-to-oil ratio. If the assumed production rates orsteam-to-oil ratio are not achieved, we might have to drill additional wells tomaintain optimal production levels, construct additional steam generatingcapacity, purchase natural gas for additional steam generation, and/or makeshort-term bitumen purchases. These could have a significant adverse impact onthe future activities and economic return of the Long Lake Project.

 

Applicationof New Bitumen Upgrading Process

 

Theproprietary OrCrudeTM process we are using to upgrade raw bitumen to syntheticcrude will be the first commercial application of the process although we haveoperated it in a 500 bbl/d demonstration plant. There can be no certainty thatthe commercial upgrader being constructed at Long Lake will achieve the same orsimilar results as the demonstration plant or the results which are forecast.If we are unable to upgrade the bitumen for any reason we may decide to sell itas bitumen without upgrading it, which would expose us to the following risks:

 

·                  the market forbitumen is limited;

·                  additionalcosts would be incurred to purchase diluent for blending and transportingbitumen;

·                  there could bea shortfall in the supply of diluent which may cause its price to increase;

·                  the marketprice for bitumen is relatively low reflecting its quality differential;

·                  the marketprice for bitumen fluctuates over the course of the year; and

·                  additionalcosts would be incurred to purchase natural gas for use in generating steam forthe SAGD process since we would not be producing syngas from the upgradingprocess.

 

Thesefactors could have a significant adverse impact on the future activities andeconomic returns of the Long Lake Project.

 

Ifany of these factors arise, our operating costs would increase and our revenueswould decrease from those we have assumed. This would materially decreaseexpected earnings from the project and the project may not be profitable underthese conditions.

 

Dependenceon OPTI Canada Inc.

 

Weare undertaking the Long Lake Project jointly with OPTI Canada Inc. (OPTI)pursuant to a joint venture agreement governing the construction, ownership andjoint operation of the project. The agreement provides for a managementcommittee that is responsible for the supervision and direction of the managementand operation of the project, the supervision and control of the operators andall other matters relating to the development of the project. If our interestin any element of the project falls below 25%, OPTI may be able to makedecisions respecting that element without our input, which may adversely affectour operations.

 

Dependenceupon Proprietary Technology

 

Thesuccess of the project and our investment depends highly on the proprietarytechnology of OPTI and proprietary technology of third parties that has been,or is required to be,

 

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licensedby OPTI. OPTI currently relies on intellectual property rights and othercontractual or proprietary rights, including (without limitation) copyright,trademark laws, trade secrets, confidentiality procedures, contractualprovisions, licenses and patents, to secure the rights to utilize itsproprietary technology and the proprietary technology of third parties. OPTImay have to engage in litigation to protect the validity of its patents orother intellectual property rights, or to determine the validity or scope ofpatents or proprietary rights of third parties. This kind of litigation can betime-consuming and expensive, whether OPTI is successful or not. The process ofseeking patent protection can itself be long and expensive, and there can be noassurance that any currently pending or future patent applications of OPTI orsuch third parties will actually result in issued patents, or that, if patentsare issued, they will be of sufficient scope or strength to provide meaningfulprotection or any commercial advantage to OPTI. Furthermore, others may developtechnologies that are similar or superior to: 1) the technology of OPTI orthird parties or 2) the design around the patents owned by OPTI and/or thirdparties. There is also a risk that OPTI may not be able to enter into licensingarrangements with third parties for additional technologies required topossibly further expand the Long Lake upgrader.

 

OperationalHazards

 

Theoperation of the project will be subject to the customary hazards ofrecovering, transporting and processing hydrocarbons, such as fires,explosions, gaseous leaks, migration of harmful substances, blowouts and oilspills. A casualty occurrence might result in the loss of equipment or life, aswell as injury or property damage. We may not carry insurance with respect toall potential casualty occurrences and disruptions, and our insurance may notsufficiently cover casualty occurrences or disruptions that occur. The projectcould be interrupted by natural disasters or other events beyond our control.Losses and liabilities arising from uninsured or under-insured events couldhave a material adverse effect on the project and on our business, financialcondition and results of operations.

 

Recoveringbitumen from oil sands and upgrading the recovered bitumen into synthetic crudeoil and other products involve particular risks and uncertainties. The projectis susceptible to loss of production, slowdowns or restrictions on its abilityto produce higher-value products due to the interdependence of its componentsystems. Severe climatic conditions can cause reduced production and in somesituations result in higher costs. SAGD bitumen recovery facilities anddevelopment and expansion of production can entail significant capital outlays.The costs associated with synthetic crude oil production are largely fixed and,as a result, operating costs per unit depend largely on production levels.

 

TheLong Lake Project will process large volumes of hydrocarbons at high pressureand temperatures and will handle large volumes of high-pressure steam.Equipment failures could result in damage to the project’s facilities andliability to third parties against which we may not be able to fully insure ormay elect not to insure because of high premium costs or for other reasons.

 

Certaincomponents of the Long Lake Project will produce sour gas, which is gascontaining hydrogen sulphide. Sour gas is a colourless, corrosive gas that istoxic at relatively low levels to plants and animals, including humans. Theproject will include integrated facilities for handling and treating the sourgas, including the use of gas sweetening units, sulphur recovery systems andemergency flaring systems. Failures or leaks from these systems or otherexposure to sour gas produced as part of the project could result in damage toother equipment, liability to third parties, adverse effect to humans, animalsand the environment, or the shut down of operations.

 

TheLong Lake Project will produce carbon dioxide emissions. Risk factors relatingto environmental regulation are provided separately in this document.

 

AboriginalClaims

 

Aboriginalpeoples have claimed aboriginal title and rights to a substantial portion ofwestern Canada. Certain aboriginal peoples have filed a claim against theGovernment of Canada, the Province of Alberta, certain governmental entitiesand the regional municipality of Wood Buffalo (which includes the city of FortMcMurray, Alberta) claiming, among other things, aboriginal title to largeareas of lands surrounding Fort McMurray, including the lands on which theproject and most of the other oil sands operations in Alberta are located. Suchclaims, if successful, could have a significant adverse effect on the Long LakeProject and on us.

 

Competition

 

TheCanadian and international petroleum industry is highly competitive in allaspects, including exploring for, and developing, new sources of supply,acquiring petroleum interests and distributing and marketing of petroleumproducts. The Long Lake Project competes with other producers of syntheticcrude oil blends and other producers of conventional crude oil. Someconventional 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.

 

Anumber of companies, other than OPTI and us, have announced plans to: 1) enterthe oil sands business and begin producing synthetic crude oil, or 2) expandexisting 

 

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operations.Either plan could materially increase the supply of synthetic crude oil andother competing crude oil products in the marketplace. Depending on futuredemand, increased supplies could have a negative impact on prices.

 

**Some ofour production is concentrated in a few producing assets.**

 

Asignificant portion of our production is generated from highly productiveindividual wells or central production facilities. Examples include:

 

·                  Scott andBuzzard production platforms in the North Sea;

·                  centralprocessing facilities, oil pipelines, and export terminal at our two Yemenoperations;

·                  Gunnison SPARproduction platform in the Gulf of Mexico;

·                  Aspen wellstied-in to a third-party processing facility in the Gulf of Mexico; and

·                  upgradingfacilities at Syncrude in the Athabasca oil sands.

 

Assignificant production is generated from each asset, any single event thatinterrupts one of these operations could result in the loss of production.

 

**Ouroperations could be subject to changes in regulations related to air emissions.**

 

TheKyoto Protocol came into force on February 16, 2005 and Canada ratifiedthe Kyoto Protocol in December 2002. In 1997, Canada committed to anemission reduction of 6% below 1990 levels during the First Commitment period(2008 to 2012). Alberta became the first jurisdiction in Canada to enact andimplement binding emission reductions (a 12% reduction in carbon intensity) onfacilities emitting more than 100 kilo-tonnes of CO2 equivalent.Facilities unable to make internal reductions have unlimited access to atechnology fund at the rate of $15 per tonne of CO2 equivalent. In 2007, the Federal government introduceda Regulatory Framework for Air Emissions which indicates that the governmentintends to regulate both greenhouse gases and air pollutants beginning as earlyas 2010, with progressively more stringent reductions applied out to 2050.Greenhouse gases (GHGs) will be regulated based on intensity until 2020–2025,when a cap and trade system may be imposed. The intent appears to offercompanies the option of making internal reductions, purchasing offsets ormaking payments into a technology fund (with escalating fixed costs). Duringthe period 2010 to 2020 there will be increasing exposure to a Canadian carbonmarket which could be short of supply leading to very high carbon prices. Itremains to be seen if the two levels of government will harmonize theircompliance regimes and how the revenue in the technology funds will beallocated. The federal government has also indicated their intent to regulateair pollutants concurrent with greenhouse gases but their schedule andlong-term objectives are less clear. Based on what is known today, there couldbe technical challenges in meeting some of the criteria for certain pollutants.

 

Anyrequired reductions in the GHGs emitted from our operations could result inincreases in our capital or operating expense, or reduced operating rates,especially at the Long Lake Project, which could have an adverse effect on ourresults of operations and financial condition. As a “new facility” startingoperations in 2008, Long Lake will have three years to establish an emissionsbaseline before having a reduction obligation assigned. In 2007 our Canadianoperations, including Syncrude, accounted for 23% of our production before royalties.

 

Ourtwo installations in the UK sector of the North Sea have allocations from theregulator and are part of the European Union Emission Trading System. Theallocations cover emissions from combustion equipment and flaring from 2008until 2012. The installations are both expected to have emissions in excess ofallowances which will be covered by eligible offsets from the Clean DevelopmentMechanism and over-the-counter trades.

 

**Ourenergy marketing operations expose us to the risk of trading losses andliquidity constraints.**

 

Ourtrading operations expose us to the risk of financial losses from varioussources. The markets in which we trade are susceptible to significant changes,which could expose us to the risk of material financial losses. Significantchanges in the commodities and financial markets could require us to provideadditional liquidity to support our energy marketing operations. Adverse creditrelated events such as a downgrade of our credit rating to non-investment gradecould require additional collateral to be placed with counterparties. Anysignificant loss of liquidity could adversely affect our financial condition.

 

**Use ofmarine transportation may expose us to the risk of financial loss and damagedreputation.**

 

Fromtime to time, we may choose to charter marine vessels for the transportation ofcrude oil. This may expose us to the risk of financial loss and damagedreputation in the event of oil spills.

 

**Fluctuationsin exchange rates give rise to foreign currency exposure.**

 

Manyof our activities are transacted in or referenced to US dollars. Revenues,expenses, capital expenditures and related net assets of our oil and gas andchemicals operations outside Canada are primarily US-dollar denominated. Pricesreceived in Canada for sales of our crude oil, natural gas and some chemicalsproducts are referenced to US-dollar denominated prices. Also, we have theability to borrow on a short-term and

 

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long-termbasis in US dollars. Fluctuations in exchange rates between the US and theCanadian dollar, and between US or Canadian dollar and other foreigncurrencies, including but not limited to the British pound and the Euro, couldadversely affect our financial condition.

 

**Increasesin interest rates could give rise to increased debt servicing obligations.**

 

Weuse both fixed and floating rate debt to finance our operations. Our floatingrate debt obligations expose us to changes in interest payments due tofluctuating interest rates. This could adversely affect our financialcondition.

 

**Theinability of counterparties to fulfill their obligations to us could adverselyimpact our results of operations.**

 

Creditrisk affects both our trading and non-trading activities and there is the riskof loss if counterparties do not fulfill their contractual obligations. Most ofour receivables are with counterparties in the energy industry and are subjectto normal industry credit risk. The inability of any one or more of thesecounterparties to fulfill their obligations to us may adversely impact ourresults of operations.

 

**We maynot achieve commercial production rates in our coalbed methane or shale gasoperations.**

 

Part ofNexen’s growth strategy is unconventional Canadian gas resource plays,including coalbed methane (CBM) and shale gas. Both gas resource plays havesignificant potential; however, exploitation techniques and practices for theseresources in Canada generally remain in the early stages of development and itis very difficult to determine whether or not these resource plays will provecommercial, or to what degree.

 

CBMis commonly 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. Some of the uncertainties associated withdevelopment of CBM resources are as follows:

 

·                  If the coalbed is water saturated, such asthe Mannville coals in the Fort Assiniboine region of Alberta, water generallyneeds to be extracted to reduce the pressure and allow gas production to occur.A significant period of time may be required to dewater these wet coals anddetermine if commercial production is feasible. We may also have to investsignificant capital in these assets before they achieve commercial rates ofproduction, if ever;

·                  Some coalbeds may not have sufficient naturalpermeability in the coalbed to recover the gas in place and can thereforerequire more extensive, and expensive, completion technologies which canincrease the cost of drilling and production;

·                  The public may react negatively to certainwater disposal practices related to water saturated CBM projects, even thoughthese water disposal practices are regulated to ensure public safety and waterconservation. Nevertheless, negative public perception around water saturatedCBM production could impede our access to the resource;

·                  CBM wells typically have lower producingrates and reserves per well than conventional gas wells, although this variesby area; and

·                  Regulatory approval is required to drill morethan one well per section. As a result, the timing of drilling programs andland development can be uncertain.

 

Shalegas is an unconventional gas produced from reservoirs composed of organic richshales. The gas is stored in pore spaces, fractures or adsorbed into organicmatter. Some of the uncertainties associated with development of shale gasresources are as follows:

 

·                  Shale gas wells typically have higherproduction decline rates, lower producing rates and reserves per well thanconventional gas wells, although this varies by area;

·                  Regulatory approval is required to drill morethan one well per section. As a result, the timing of drilling programs andland development can be uncertain; and

·                  Shales are typically less permeable thanconventional gas reservoirs, and can therefore require more extensive, andexpensive, completion technologies which can increase the cost of drilling andproduction.

 

**We havesignificant up-front commitments related to our current development projects.**

 

Wehave significant commitments in connection with various development activitiescurrently underway. At Long Lake, we essentially completed module and siteconstruction of the SAGD facilities in 2006 and steam injection began in 2007.Module fabrication of the Long Lake Upgrader is complete and all modules are onsite. Construction of the upgrader is approximately 97% complete and start up isscheduled for mid 2008. At Long Lake, we are exposed to the possibility of costoverruns and/or delays in the commencement of commercial production, which maybe significant. Specific risk factors relating to our Long Lake oil sandsproject are provided separately. See “The Long Lake Project faces additionalrisks compared to conventional oil and gas production”.

 

**Weoperate in countries with political and economic risk.**

 

Weoperate in numerous countries, some of which may be considered politically andeconomically unstable. Our operations and related assets are subject to therisks of actions by governmental authorities, insurgent groups or terroristswhich may have material adverse financial consequences.

 

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Items 1 and 2         Businessand Properties     Legal Proceedings

 

Forinstance, on September 15, 2006 our oil export terminal in Yemen wasassaulted by two explosive laden vehicles. One worker was killed and two othersreceived minor injuries. The ability of the terminal to receive and export oilwas not affected and operations continued as normal. There can be no assurancethat we will be successful in protecting ourselves against these risks and therelated financial consequences.

 

**We maybe affected by changes in government rules and regulations.**

 

Ouroperations are subject to various levels of government controls and regulationsin the countries where we operate. These laws and regulations include mattersrelating to land tenure, drilling, production practices, environmentalprotection, marketing and pricing policies, royalties, various taxes and leviesincluding income tax, and foreign trade and investment, that are subject tochange from time to time. For example, the US government has proposed increasesto the royalty rates for new deep-water Gulf of Mexico leases and has proposedamendments to deep-water leases issued in 1998 and 1999. In 2007, the Albertagovernment proposed changes to royalty rates effective 2009. Currentlegislation is generally a matter of public record, and we cannot predict whatadditional legislation or amendments may be proposed that will affect ouroperations or when any such proposals, if enacted, might become effective.Changes in government regulations could adversely affect our results ofoperations and financial condition.

 

**Ouroperations are exposed to environmental liabilities.**

 

Environmentalliabilities inherent in the oil and gas and chemicals industries are becomingincreasingly sensitive as related laws and regulations become more stringentworldwide. Many of these laws and regulations require us to remove or remedythe effect of our activities on the environment at present and former operatingsites, including dismantling production facilities and remediating damage causedby disposing or releasing specified substances. This could have an adversefinancial consequence on us.

 

Certainoperations require the use of fresh and saline water. We currently usesub-surface sources of water for these operations. Additional costs may beincurred if allocation limits are placed on our saline water usage, if oursub-surface fresh water needs exceed allocated amounts or if existingsubsurface fresh water allocations are reduced.

 

**Item 1B. Unresolved StaffComments**

 

Thereare no unresolved staff comments with the SEC.

 

**Item 3. Legal Proceedings**

 

Thereare a number of lawsuits and claims pending against Nexen, the ultimate resultsof which cannot be ascertained at this time. Management is of the opinion thatany amounts assessed 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.

 

Certainof our US oil and gas operations have received, over the years, notices anddemands from the US Environmental Protection Agency (EPA), state environmentalagencies, and certain third parties for certain sites seeking to requireinvestigation and remediation under federal or state environmental statutes. Inaddition, notices, demands, and lawsuits have been received for certain sitesrelated to historical operations and activities in the US for which, althoughno assurances can be made, we believe that certain assumption andindemnification agreements protect our US operations from any present or futurematerial liabilities that may arise from these particular sites.

 

**Item 4. Submission of Matters toa Vote of Security Holders**

 

Nomatters were submitted to a vote of Nexen’s security holders during the fourthquarter of 2007.

 

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Item 5     Businessand Properties     Market Data

 

**PART II**

 

**Item 5. Market for the Registrant’sCommon equity; Related Stockholder Matters and Issuer Purchases of Equity Securities**

 

Nexen’scommon shares are traded on the Toronto Stock Exchange (TSX) and the New YorkStock Exchange (NYSE) under the symbol NXY.

 

OnDecember 31, 2007, there were 1,569 registered holders of common sharesand 528,304,813 common shares outstanding. The number of registered holders ofcommon shares is calculated excluding individual participants in securitiespositions listings. During the year, we made no purchases of our own equitysecurities.

 

TradingRange of Nexen’s Common Shares

 
| ** **          | ** ** | **TSX ****(Cdn$ )** | ** ** | **NYSE ****(US$ )** | ** ** |
|---------------------|------------|-------------------------------|------------|-------------------------------|------------|
| **($ /share)** | ** ** | **High**                      | ** ** | **Low**                       | ** ** | **High** | ** ** | **Low** | ** ** |
| **2007**            |       |                          |       |                          |       |   |   |   |   |
| First Quarter       |       | 37.60                         |       | 29.66                         |       | 31.88 |   | 25.18 |   |
| Second Quarter      |       | 36.51                         |       | 31.25                         |       | 32.21 |   | 29.08 |   |
| Third Quarter       |       | 36.32                         |       | 27.21                         |       | 34.79 |   | 25.25 |   |
| Fourth Quarter      |       | 32.63                         |       | 27.88                         |       | 34.37 |   | 27.58 |   |
| **2006**            |       |                          |       |                          |       |   |   |   |   |
| First Quarter       |       | 34.05                         |       | 27.17                         |       | 29.97 |   | 23.49 |   |
| Second Quarter      |       | 34.75                         |       | 25.41                         |       | 30.84 |   | 22.82 |   |
| Third Quarter       |       | 35.61                         |       | 26.07                         |       | 31.82 |   | 23.35 |   |
| Fourth Quarter      |       | 32.90                         |       | 26.46                         |       | 29.19 |   | 23.45 |   |

 

QuarterlyDividends Declared on Common Shares

 
| **($ /share)** | ** ** | **First  Quarter** | ** ** | **Second  Quarter** | ** ** | **Third  Quarter** | ** ** | **Fourth  Quarter** | ** ** |
|---------------------|------------|--------------------|------------|---------------------|------------|--------------------|------------|---------------------|------------|
| 2007                |       | 0.025              |       | 0.025               |       | 0.025              |       | 0.025               |       |
| 2006                |       | 0.025              |       | 0.025               |       | 0.025              |       | 0.025               |       |

 

Paymentdate for dividends was the first day of the next quarter. All dividends paid toholders of common shares in 2007 have been designated as “eligible dividends”for Canadian tax purposes.

 

TheIncome Tax Act of Canada requires us to deduct a withholding tax from alldividends remitted to non-residents. According to the Canada-US Tax Treaty, wehave deducted a withholding tax of 15% on dividends paid to residents of theUnited States, except in the case of a company that owns at least 10% of thevoting stock, where the withholding tax is 5%.

 

TheInvestment Canada Act requires that a “non-Canadian”, as defined, file noticewith Investment Canada and obtain government approval prior to acquiringcontrol of a Canadian business, as defined. Otherwise, there are nolimitations, either under the laws of Canada or in Nexen’s charter on the rightof a non-Canadian to hold or vote Nexen’s securities (refer to the table ofsecurities authorised for issuance under equity compensation plans on page154).

 

OnFebruary 3, 2000, at a Special Meeting of Shareholders, a ShareholderRights Plan was approved. On May 2, 2002, at the Annual General andSpecial Meeting of Shareholders, an Amended and Restated Shareholder RightsPlan (Plan) was approved. According to the Plan, a right is attached to eachpresent and future outstanding common share, entitling the holder to acquireadditional common shares during the term of the right. Prior to the separationdate, the rights are not separable from the common shares, and no separatecertificates are issued. The separation date would typically occur at the timeof an unsolicited takeover bid, but our board can defer the separation date.

 

Rightscreated under the Plan, which can only be exercised when a person acquires 20%or more of our common shares (a Flip-In Event), entitle each shareholder, otherthan the 20% buyer, to acquire additional common shares at one-half of themarket price at the time of exercise. The Plan must be reapproved byshareholders on or before our annual general meeting in 2008 to remaineffective past that date. A copy of the Plan is available on our web site atwww.nexeninc.com.

 

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Item 6     SelectedFinancial Data       US GAAP Summary Data

 

**Item 6. Selected Financial Data**

 

Five-YearSummary of Selected Financial Data in Accordance with US GAAP

 
| **(Cdn$ millions, except otherwise indicated)**         | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-----------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
|                                                                        |       |     |       |     |       |     |       |     |       |     |       |
| **Oil & Gas and Syncrude Production**                              |       |     |       |     |       |     |       |     |       |     |       |
| Production Before Royalties (mboe/d) (1)                                    |       | 254      |       | 212      |       | 242      |       | 250      |       | 269      |       |
| Production After Royalties (mboe/d) (1)                                     |       | 207      |       | 156      |       | 173      |       | 174      |       | 185      |       |
|                                                                        |       |     |       |     |       |     |       |     |       |     |       |
| **Results of Operations**                                                   |       |     |       |     |       |     |       |     |       |     |       |
| Revenue                                                                     |       |     |       |     |       |     |       |     |       |     |       |
| Oil & Gas and Syncrude (2)                                         |       | 5,174    |       | 3,656    |       | 3,535    |       | 2,573    |       | 2,261    |       |
| Marketing                                                                   |       | 926      |       | 1,373    |       | 864      |       | 625      |       | 586      |       |
| Chemicals                                                                   |       | 447      |       | 413      |       | 413      |       | 383      |       | 377      |       |
| Other                                                                       |       | (26      | )          | (47      | )          | (193     | )          | 59       |       | 31       |       |
| Total Revenue                                                               |       | 6,521    |       | 5,395    |       | 4,619    |       | 3,640    |       | 3,255    |       |
|                                                                        |       |     |       |     |       |     |       |     |       |     |       |
| Net Income from Continuing Operations                                       |       | 1,012    |       | 579      |       | 658      |       | 705      |       | 419      |       |
| Basic Earnings per Common Share from Continuing Operations ($/share)  (3)   |       | 1.92     |       | 1.10     |       | 1.26     |       | 1.37     |       | 0.85     |       |
| Diluted Earnings per Common Share from Continuing Operations  ($/share) (3) |       | 1.88     |       | 1.08     |       | 1.23     |       | 1.35     |       | 0.84     |       |
|                                                                        |
| Net Income                                                                  |       | 1,012    |       | 579      |       | 1,110    |       | 788      |       | 420      |       |
| Basic Earnings per Common Share ($/share) (3)                               |       | 1.92     |       | 1.10     |       | 2.13     |       | 1.53     |       | 0.85     |       |
| Diluted Earnings per Common Share ($/share) (3)                             |       | 1.88     |       | 1.08     |       | 2.08     |       | 1.51     |       | 0.84     |       |
|                                                                        |       |     |       |     |       |     |       |     |       |     |       |
| **Financial Position**                                                      |       |     |       |     |       |     |       |     |       |     |       |
| Total Assets (1)                                                            |       | 17,982   |       | 17,079   |       | 14,493   |       | 12,339   |       | 7,703    |       |
| Long-Term Debt (4)                                                          |       | 4,610    |       | 4,618    |       | 3,630    |       | 4,214    |       | 2,470    |       |
| Shareholders’ Equity                                                   |       | 5,449    |       | 4,614    |       | 3,961    |       | 2,892    |       | 2,131    |       |
| Capital Investment, including Acquisitions                                  |       | 3,401    |       | 3,408    |       | 2,638    |       | 4,264    |       | 1,432    |       |
| Dividends per Common Share ($/share) (3), (5)                               |       | 0.10     |       | 0.10     |       | 0.10     |       | 0.10     |       | 0.08     |       |
| Common Shares Outstanding (thousands) (3)                                   |       | 528,305  |       | 525,026  |       | 522,281  |       | 516,798  |       | 502,424  |       |

 

----

*Notes:*

*1    In 2004, production declinedfrom our maturing assets in Yemen at Masila, in Canada and in the US Gulf ofMexico Shelf. In late 2004, we acquired North Sea assets and began productionfrom Block 51 in Yemen. In 2005, we sold producing properties in Canada andsuffered hurricane-related downtime in the Gulf of Mexico. A full year’sproduction from the North Sea and Block 51 in Yemen offset declines caused bythese events. In early 2007, the Buzzard field came on stream and offsetdeclines from Masila in Yemen.*

*2    During 2003, we sold non-coreconventional light oil assets in southeast Saskatchewan in Canada producing9,000 bbls/d. In late 2004, we concluded production from our Buffalo field,offshore Australia, as anticipated. In the third quarter of 2005, we soldCanadian conventional oil and gas properties in Saskatchewan, British Columbiaand Alberta producing 18,300 bbls/d. The results of these operations have beenshown as discontinued operations.*

*3    Our shareholders approved asplit of our issued and outstanding common shares on a two-for-one basis at ourannual and special meeting on April 26, 2007. All common share and percommon share amounts presented have been retroactively restated to reflect thisshare split.*

*4    In December 2004, wedrew US$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 withproceeds from the issuance of US$1.04 billion in senior notes in the firstquarter and from asset dispositions in the third quarter. Our long-term debtincreased in 2006 as a result of our capital investments, primarily at Buzzardand Long Lake. In May 2007, we issued US$1.5 billion of senior notes withUS$250 million maturing in 10 years and US$1,250 million maturing in 30 years.In June 2007, we filed a universal base shelf prospectus in the US andCanada allowing us to potentially raise US$2.5 billion of debt, equity or otherhybrid securities, should the need arise.*

*5    Quarterly dividends wereincreased to 2.5¢ per share in the fourth quarter of 2003.*

 

36

----

 

management’s

discussion

 

With significant production

growth and strong oil prices, cash

flow from operating activities

reached a record $2.8 billion.

 

37

----

 

**ITEM 7. MANAGEMENT’S DISCUSSIONAND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

 

Thefollowing should be read in conjunction with the Consolidated FinancialStatements included in this report. The Consolidated Financial Statements havebeen prepared in accordance with generally accepted accounting principles(GAAP) in Canada. The impact of significant differences between Canadian and UnitedStates (US) accounting principles on the financial statements is disclosed inNote 21 to the Consolidated Financial Statements. The date of this discussionis February 13, 2008.

 

Unlessotherwise noted, tabular amounts are in millions of Canadian dollars. Ourdiscussion and analysis of our oil and gas activities include our Syncrudeactivities since the product produced from Syncrude competes in the oil and gasmarket. Oil and gas volumes, reserves and related performance measures arepresented on a working interest before-royalties basis. We measure ourperformance in this manner consistent with other Canadian oil and gascompanies. Where appropriate, we have provided information on an after-royaltybasis in tabular format.

 

Notes:

 

1Investors should read the Special Note Regarding Forward-Looking Statements onpage 75.

 

2Canadian investors should read the Special Note to Canadian Investors on page 76which highlights differences between our reserve estimates and relateddisclosures that are otherwise required by Canadian regulatory authorities.

 
| Executive Summary                                           | 39 |
|-------------------------------------------------------------|----|
| Capital Investment                                          | 40 |
| Financial Results                                           | 44 |
| Year-to-Year  Change in Net Income                          | 44 |
| Oil & Gas and  Syncrude                            | 45 |
| Production                                                  | 45 |
| Commodity Prices                                            | 48 |
| Operating Expenses                                          | 50 |
| Depreciation,  Depletion, Amortization and Impairment       | 52 |
| Exploration Expense                                         | 53 |
| Oil & Gas  and Syncrude Netbacks                   | 55 |
| Energy Marketing                                            | 56 |
| Chemicals                                                   | 59 |
| Corporate Expenses                                          | 60 |
| Outlook for 2008                                            | 62 |
| Liquidity  and Capital Resources                            | 63 |
| Critical  Accounting Estimates                              | 68 |
| New  Accounting Pronouncements                              | 71 |
| Quantitative  and Qualitative Disclosures about Market Risk | 72 |

 

38

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Item 7     Management’s Discussionand Analysis        Executive Summary

 

**EXECUTIVE SUMMARY**

 
| **(Cdn$ millions)**                                  | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|-----------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net Income                                                |       | 1,086    |       | 601      |       | 1,140    |       |
| Earnings per Common Share, Basic ($/share)                |       | 2.06     |       | 1.15     |       | 2.19     |       |
| Cash Flow from Operating Activities                       |       | 2,830    |       | 2,374    |       | 2,143    |       |
| Production before Royalties (mboe/d) (1)                  |       | 254      |       | 212      |       | 242      |       |
| Production after Royalties (mboe/d)                       |       | 207      |       | 156      |       | 173      |       |
| Capital Investment, including Acquisitions                |       | 3,401    |       | 3,408    |       | 2,638    |       |
| Net Debt (2)                                              |       | 4,404    |       | 4,730    |       | 3,639    |       |
| Average Foreign Exchange Rate (Canadian to  US dollar)    |       | 0.93     |       | 0.88     |       | 0.83     |       |
| Proved Oil and Gas Reserves before  Royalties (mmboe) (3) |       | 734      |       | 725      |       | 468      |       |
| Proved Oil and Gas Reserves after Royalties  (mmboe) (3)  |       | 650      |       | 637      |       | 393      |       |
| Proved Syncrude Reserves before Royalties  (mmboe) (3)    |       | 324      |       | 324      |       | 318      |       |
| Proved Syncrude Reserves after Royalties  (mmboe) (3)     |       | 267      |       | 274      |       | 264      |       |

 

----

*Notes:*
| *(1)* | * * | *Production before royalties reflects our  working interest before royalties and includes production of synthetic crude  oil from Syncrude. We have presented our working interest before royalties as  we measure our performance on this basis consistent with other Canadian oil  and gas companies.* |
|-------|----------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | * * | *Long-term debt and short-term borrowings  less cash and cash equivalents.*                                                                                                                                                                                                                              |
| *(3)* | * * | *Includes developed and undeveloped proved  reserves as at December 31.*                                                                                                                                                                                                                            |

* *

Our strategy is to grow long-term value for shareholders responsibly.We started to monetize this value by bringing Buzzard on stream early in 2007and expect more to follow as Ettrick and the first phase of Long Lake come onstream in 2008. We also added value by increasing our reserves and capturingadditional acreage in attractive growth areas like the US Gulf of Mexico,Norway, and shale gas and oil sands in western Canada. Higher net income andcash flow from operating activities in 2007 were due to a 33% increase inproduction after royalties (20% increase before royalties) and strong commodityprices. Although WTI rose 9% from 2006, a stronger Canadian dollar limited theincrease in our realized crude oil prices. This was offset by changes in ourproduction mix as we are transitioning to higher-value crude oil from Buzzard.Our average realized oil and gas price increased 9% over last year to$68.46/boe.

 

Our share of production from Buzzard averaged more than 64,000 boe/d in2007. While commissioning of all systems took longer than expected, thefacilities have produced as high as 220,000 boe/d (95,000 boe/d net to us)during the year, higher than originally expected. Looking forward, with a fullyear of Buzzard on stream and new production expected from Ettrick and LongLake, we expect 2008 net production to average between 220,000 and 240,000boe/d (260,000 and 280,000 before royalties).

 

Net income in 2007 includes impairment expense of $366 million (beforetax) related to four properties in the Gulf of Mexico as required by successfulefforts accounting for oil and gas. The majority of the expense relates to theAspen deep-water field where recent unsuccessful development drilling and steepproduction declines resulted in negative reserve revisions. Unsuccessfulrecompletions, production declines and disappointing development results on theshelf reduced reserves and generated the remainder of the impairment expense.

 

We invested almost half of our 2007 capital on major developmentprojects at Long Lake and Ettrick. In the Athabasca oil sands, we invested $1.1billion in Long Lake Phase 1 and future phases. We are currently injectingsteam into the reservoir through all well pads and the SAGD facilities areoperating as expected. Upgrader construction is 97% complete and commissioningis progressing well. The upgrader is expected to come on stream mid 2008. Inthe North Sea, we brought additional development wells on stream at Buzzard andmade significant progress on Ettrick. We also invested $130 million in buildingour prospect inventory in the US Gulf of Mexico deepwater and Canadian shalegas.

 
|        |   |  |   |  |
|--------|--------|--|--------|--|
|   |   |

 

39

----

 

Our 2007 exploration program was focused primarily in the Gulf ofMexico and the North Sea. We were successful with discoveries in the Gulf atVicksburg and on the shelf, and at Selkirk and Kildare in the North Sea. Wealso successfully appraised prior discoveries at Longhorn in the Gulf of Mexicoand Golden Eagle in the North Sea. Unfortunately, we did not advance our KnottyHead discovery in the Gulf as a suitable drilling rig was not available.

 

With the weaker US dollar, our net debt decreased over $300 millionfrom last year. Our US-dollar denominated debt was lower by $800 million whentranslated to Canadian dollars. This was partially offset by capital investmentthat exceeded our cash flow from operations.

 

Throughout 2007 ,the US dollar continued to weaken relative to theCanadian dollar. Our sales revenue is denominated in, or referenced to, USdollars and, as a result, our reported Canadian dollar revenues are lower asthe US dollar weakens. On the other hand, our US-dollar capital spending andoperating costs are also lower when translated to Canadian dollars, as well asour US denominated debt. Overall, the weaker US dollar reduced our 2007 cashflow from operating activities by $255 million and net income by $122 million.

 

During 2007, our proved oil and gas and Syncrude reserves additionsreplaced 109% of our oil and gas and Syncrude production (108% after royalties)as shown below:

 
| ** **                               | ** ** | **Before**    | ** ** | **After**     | ** ** |
|------------------------------------------|------------|---------------|------------|---------------|------------|
| **(mmboe)**                              | ** ** | **Royalties** | ** ** | **Royalties** | ** ** |
| **Production**                           |       |          |       |          |       |
| Oil and Gas                              |       | 85            |       | 68            |       |
| Syncrude                                 |       | 8             |       | 7             |       |
| **Total**                                | ** ** | **93**        | ** ** | **75**        | ** ** |
|                                     |       |          |       |          |       |
| **Reserve Changes excluding Production** |       |          |       |          |       |
| Oil and Gas                              |       | 94            |       | 81            |       |
| Syncrude                                 |       | 8             |       | –        |       |
| **Total**                                | ** ** | **102**       | ** ** | **81**        | ** ** |

 

Two-thirds of our additions relate to our key projects at Buzzard inthe North Sea and Long Lake in the Athabasca oil sands. Other additions came fromsuccessful exploration and development activities in virtually all areas of ouroperations, somewhat offset by lower production performance and unsuccessfulactivities at Aspen and the shelf in the Gulf of Mexico. We also added 10 mmboe(8 after royalties), net of dispositions, from acquisitions and swaps primarilyin the Gulf of Mexico.

 

**CAPITAL INVESTMENT**

 
| **(Cdn$ millions)**                  | ** ** | **Estimated 2008** | ** ** | **2007**  | ** ** | **2006**  | ** ** |
|-------------------------------------------|------------|--------------------|------------|-----------|------------|-----------|------------|
| Major Development                         |       | 700                |       | 1,479     |       | 1,849     |       |
| Early Stage Development                   |       | 400                |       | 162       |       | 123       |       |
| New Growth Exploration                    |       | 600                |       | 573       |       | 491       |       |
| Core Asset Development                    |       | 600                |       | 1,069     |       | 748       |       |
| Total Oil  & Gas and Syncrude         |       | 2,300              |       | 3,283     |       | 3,211     |       |
| Marketing, Corporate, Chemicals and Other |       | 100                |       | 118       |       | 197       |       |
| **Total  Capital**                        | ** ** | **2,400**          | ** ** | **3,401** | ** ** | **3,408** | ** ** |

 

40

----

 

Our strategy and capital programs are focused on growing long-termvalue for our shareholders responsibly. To maximize value, we invest in: 
| · | core assets for short-term production and  free cash flow to fund capital programs and repay debt;           |
|--------|--------------------------------------------------------------------------------------------------------------|
| · | development projects that convert our  discoveries into new production and cash flow in the medium term; and |
| · | exploration projects for longer-term  growth.                                                                |

 

 

As conventional basins in North America mature, we have beentransitioning toward less mature basins and unconventional resources. Key focusareas include the North Sea, Athabasca oil sands, Canadian CBM and shale gas,Gulf of Mexico deep waters, offshore West Africa and the Middle East—areas webelieve have attractive fiscal terms, significant remaining opportunity, andwhere we have a competitive advantage.

 

In 2007, we invested $3.4 billion in capital expenditures, mostly inmajor development projects and long cycle-time exploration. In 2008, we plan toinvest $2.4 billion, which is $1 billion lower than 2007 as we incurred most ofthe capital costs for the first phase of Long Lake. About half of the 2008capital investment will be focused on major and early stage developmentprojects, 29% on core assets to sustain production and provide cash flow, and theremainder to drill high-impact exploration wells and continue building ouracreage.

 

**2007 Capital**

 
| ** **                      | ** ** | **Major**       | ** ** | **Early Stage** | ** ** | **New Growth**  | ** ** | **Core Asset**  | ** ** | ** ** | ** ** |
|---------------------------------|------------|-----------------|------------|-----------------|------------|-----------------|------------|-----------------|------------|------------|------------|
| **(Cdn$ millions)**        | ** ** | **Development** | ** ** | **Development** | ** ** | **Exploration** | ** ** | **Development** | ** ** | **Total**  | ** ** |
| Oil and Gas                     |       |            |       |            |       |            |       |            |       |       |       |
| Synthetic (mainly Long Lake)    |       | 1,025           |       | 108             |       | 6               |       | —          |       | 1,139      |       |
| United States                   |       | 28              |       | 2               |       | 275             |       | 488             |       | 793        |       |
| United Kingdom                  |       | 323             |       | —          |       | 119             |       | 274             |       | 716        |       |
| Canada                          |       | 103             |       | 21              |       | 117             |       | 125             |       | 366        |       |
| Yemen                           |       | —          |       | —          |       | 12              |       | 124             |       | 136        |       |
| Other Countries                 |       | —          |       | 31              |       | 44              |       | 22              |       | 97         |       |
| Syncrude                        |       | —          |       | —          |       | —          |       | 36              |       | 36         |       |
|                            | ** ** | **1,479**       | ** ** | **162**         | ** ** | **573**         | ** ** | **1,069**       | ** ** | **3,283**  | ** ** |
| Marketing,  Corporate and Other |       | —          |       | —          |       | —          |       | 118             |       | 118        |       |
| **Total  Capital**              | ** ** | **1,479**       | ** ** | **162**         | ** ** | **573**         | ** ** | **1,187**       | ** ** | **3,401**  | ** ** |
|                            |       |            |       |            |       |            |       |            |       |       |       |
| As a % of  Total Capital        |       | 43              | %          | 5               | %          | 17              | %          | 35              | %          | 100        | %          |

 

**2008 Estimated Capital**

 
| ** **                      | ** ** | **Major**       | ** ** | **Early  Stage** | ** ** | **New  Growth** | ** ** | **Core  Asset** | ** ** | ** ** | ** ** |
|---------------------------------|------------|-----------------|------------|------------------|------------|-----------------|------------|-----------------|------------|------------|------------|
| **(Cdn$ millions)**        | ** ** | **Development** | ** ** | **Development**  | ** ** | **Exploration** | ** ** | **Development** | ** ** | **Total**  | ** ** |
| Oil and Gas                     |       |            |       |             |       |            |       |            |       |       |       |
| Synthetic (mainly Long Lake)    |       | 400             |       | 150              |       | —          |       | —          |       | 550        |       |
| United States                   |       | 80              |       | —           |       | 225             |       | 85              |       | 390        |       |
| United Kingdom                  |       | 200             |       | 20               |       | 210             |       | 325             |       | 755        |       |
| Canada                          |       | 20              |       | 50               |       | 70              |       | 80              |       | 220        |       |
| Yemen                           |       | —          |       | —           |       | —          |       | 65              |       | 65         |       |
| Other Countries                 |       | —          |       | 180              |       | 95              |       | —          |       | 275        |       |
| Syncrude                        |       | —          |       | —           |       | —          |       | 45              |       | 45         |       |
|                            | ** ** | **700**         | ** ** | **400**          | ** ** | **600**         | ** ** | **600**         | ** ** | **2,300**  | ** ** |
| Marketing,  Corporate and Other |       | —          |       | —           |       | —          |       | 100             |       | 100        |       |
| **Total  Capital**              | ** ** | **700**         | ** ** | **400**          | ** ** | **600**         | ** ** | **700**         | ** ** | **2,400**  | ** ** |
|                            |       |            |       |             |       |            |       |            |       |       |       |
| As a % of  Total Capital        |       | 29              | %          | 17               | %          | 25              | %          | 29              | %          | 100        | %          |

 

41

----

 

Synthetic

 

In 2007, we invested a total of $1.1 billion to develop our insitu oilsands resource. This included approximately $1 billion on the first phase of LongLake, $591 million of which related to the upgrader.

 

Long Lake continues to progress well towards first production ofpremium synthetic crude in mid 2008. We are currently injecting steam into thereservoir through all well pads. We have started converting wells to SAGDoperation and we have also recently started up our first cogeneration unitwhich allows us to produce electricity and build our steaming capacity. Thesecond cogeneration unit is expected to start up towards the end of the firstquarter. We expect bitumen production to ramp up in the spring and we are ontrack to have sufficient bitumen production for the start up of the upgrader.The bitumen production capacity of the SAGD facilities is approximately 72,000bbls/d (36,000 bbls/d net to us).

 

**In 2007,we invested a total of $1.1 billion  todevelop our insitu oil sands resource.**

 

At the end of 2007, construction of the upgrader was 97% complete andcommissioning is progressing well. We have turned over the hydrocracker, theOrCrudeTM unit and all main plant utilities to operations. The gasifier and airseparation unit were essentially mechanically complete at year end 2007, and weare completing final electrical and insulation work. Construction of thesulphur recovery unit is expected to be completed by the end of the firstquarter, in sufficient time for first production of synthetic crude oil in mid2008. Production of premium synthetic crude will ramp up to full rates over a12 to 18 month period following initial upgrader start up. The upgrader isdesigned to produce approximately 60,000 bbls/d (30,000 bbls/d net to us) ofpremium synthetic crude.

 

The total cost estimate for the Project remains unchanged at between$5.8 billion and $6.1 billion (between $2.9 billion and $3.05 billion net). Weare planning to increase synthetic crude oil production as we sequentiallydevelop our lands with additional 60,000 bbls/d (30,000 bbls/d net) phasesusing the same technology and design as Long Lake.

 

United States

 

At Longhorn, where we have a 25% working interest, we completeddrilling an appraisal well which exceeded our expectations and encounteredhydrocarbons in multiple sands. The Longhorn project has been sanctioned anddevelopment will consist of subsea tie-backs to a host facility with firstproduction expected in 2009.

 

In late 2007, we invested $104 million to acquire three producingdeep-water properties at Garden Banks Block 205 and Green Canyon Blocks 137 and6/50. These properties are currently producing approximately 3,000 boe/d. Drillingof a development well at Green Canyon 6/50 is underway and we expect productionfrom this well to add up to 5,000 boe/d to our 2008 annual volumes.

 

At Knotty Head, we continue to pursue rig availability in the shortterm to allow us to spud an appraisal well. To date, we have evaluated two rigsbut determined that these rigs did not have the drilling capability required.We have contracted two new deep-water drilling rigs that are scheduled toarrive in mid 2009 and 2010, respectively.

 

Our 2007 exploration program resulted in discoveries at Vicksburg,Mississippi Canyon 72 and South Marsh Island 257. The Vicksburg discovery well,located on De Soto Canyon Block 353 in the Eastern Gulf of Mexico, was drilledto a depth of approximately 25,400 feet and encountered hydrocarbons. Core wasrecovered from the well and studies are underway to assess the potentialproductivity. Additional drilling in the area is planned in 2008. We have a 25%non-operated working interest in this discovery. Shell is the operator with a57.5% working interest and Plains Exploration & Production Companyholds the remaining 17.5% interest. In the same area, we participated in adiscovery well in 2003 at Shiloh located on DeSoto Canyon Block 269, that wasdrilled by Shell. This well was drilled to a total depth of approximately24,000 feet, encountered hydrocarbons and was temporarily abandoned pendingfurther evaluation of the area. We have a 20% non-operated working interest inShiloh.

 

In the Eastern Gulf of Mexico, where the discoveries at Shiloh andVicksburg are located, we have identified a number of additional explorationopportunities in the region. We also have the right to extend our acreageposition through the

 

42

----

 

acquisition of working interests in various blocks recently awarded toShell as a result of their participation in Lease Sale 205 late last year.

 

Our other discoveries at Mississippi Canyon 72 and South Marsh Island257 are currently being evaluated. Both discoveries are expected to come onproduction in 2008. We have working interests of 33% and 34.5% respectively inthese discoveries.

 

United Kingdom

 

In the UK, we invested over $700 million in 2007. This included $160million at Buzzard where we drilled six development wells. Our Ettrickdevelopment in the North Sea is progressing well towards first oil mid 2008. In2007, we invested approximately $260 million. This development will utilize aleased floating production, storage and off-loading vessel (FPSO) designed tohandle 30,000 bbls/d of oil and 35 mmcf/d of gas. We expect to ramp up toproduction of approximately 30,000 boe/d gross by the end of the year. Weoperate Ettrick with an 80% working interest. We have also identified a numberof exploration opportunities in the immediate area that could be futuretie-backs to Ettrick. We have plans to drill at least two of theseopportunities this year.

 

Elsewhere, we are assessing development alternatives for our GoldenEagle discovery where we have a 34% operated working interest. At Kildare, weare planning to drill an appraisal well this year. The discovery well wasdrilled to a depth of approximately 14,100 feet. We also completed an appraisalwell at Selkirk which confirmed commercial quantities of hydrocarbons and weare currently reviewing development options. We have a 38% operated workinginterest here.

 

At Bugle, we are currently drilling an appraisal well. Well results arestill being analyzed but initial test results are encouraging. We have a 41%working interest here.

 

Canada

 

In Canada, we are developing the first commercial coalbed methane (CBM)project in the Mannville coals. In 2007, we invested $173 million inexploration and development activities on our CBM lands.

 

In northeast British Columbia we have a material land position ofapproximately 190 net sections in an emerging Devonian shale gas play which hasthe potential to be one of the most significant shale gas plays in Canada. Weare currently evaluating this opportunity with a program of drilling,completing and production testing.

 

Yemen

 

Yemen remains a significant asset for us and is expected to generateapproximately 15% of our projected cash flow in 2008. In 2007, we invested $136million and in 2008, we expect to produce between 50,000 and 55,000 boe/dbefore royalties here.

 

Other Countries

 

The Usan field development, located in Nigeria on offshore Block OPL-222, continues to move forward. We expect the project to advance to theexecution phase shortly and this will facilitate the award of the majordeep-water facilities contracts. The project will have the ability to processan average of 180,000 bbls/d of oil during the initial production plateauperiod through a new FPSO with a two million barrel storage capacity. We have a20% interest in exploration and development on this block.

 

Syncrude

 

At Syncrude, we invested $36 million in 2007. In 2008, we haveturnarounds scheduled in the second and third quarters and expect annualproduction of between 20,000 and 25,000 bbls/d.

 

 

|  |   |  |
|--|--------|--|

 

43

----

 

**FINANCIAL RESULTS**

 

**Year-to-Year Change in Net Income**

 
| **(Cdn$ millions)**                                             | ** ** | **2007 vs 2006** | ** ** | **2006 vs 2005** | ** ** |
|----------------------------------------------------------------------|------------|------------------|------------|------------------|------------|
| **Net Income for 2006 and 2005 (****1)**                             | ** ** | **601**          | ** ** | **1,140**        | ** ** |
|                                                                 |       |             |       |             |       |
| Favourable  (unfavourable) variances: (2)                            |       |             |       |             |       |
|                                                                 |       |             |       |             |       |
| Production Volumes, After Royalties                                  |       |             |       |             |       |
| Crude Oil                                                            |       | 1,354            |       | (245             | )          |
| Natural Gas                                                          |       | (17              | )          | (55              | )          |
| Change in Crude Oil Inventory                                        |       | 22               |       | (74              | )          |
| Total Volume Variance                                                |       | 1,359            |       | (374             | )          |
|                                                                 |       |             |       |             |       |
| Realized Commodity Prices in Canadian  Dollars                       |       |             |       |             |       |
| Crude Oil                                                            |       | 308              |       | 325              |       |
| Natural Gas                                                          |       | (24              | )          | (133             | )          |
| Total Price Variance                                                 |       | 284              |       | 192              |       |
|                                                                 |       |             |       |             |       |
| Operating Expense                                                    |       |             |       |             |       |
| Conventional Oil & Gas                                           |       | (178             | )          | 13               |       |
| Syncrude                                                             |       | (21              | )          | (35              | )          |
| Total Operating Expense Variance                                     |       | (199             | )          | (22              | )          |
|                                                                 |       |             |       |             |       |
| Depreciation, Depletion, Amortization and  Impairment                |       |             |       |             |       |
| Oil & Gas and Syncrude                                           |       | (636             | )          | (48              | )          |
| Other                                                                |       | (7               | )          | 4                |       |
| Total Depreciation, Depletion, Amortization  and Impairment Variance |       | (643             | )          | (44              | )          |
|                                                                 |       |             |       |             |       |
| Exploration Expense                                                  |       | 36               |       | (111             | )          |
|                                                                 |       |             |       |             |       |
| Energy Marketing Contribution                                        |       | (373             | )          | 336              |       |
|                                                                 |       |             |       |             |       |
| Chemicals Contribution                                               |       | 27               |       | (12              | )          |
|                                                                 |       |             |       |             |       |
| General and Administrative Expense                                   |       | 181              |       | 254              |       |
|                                                                 |       |             |       |             |       |
| Interest Expense                                                     |       | (115             | )          | 44               |       |
|                                                                 |       |             |       |             |       |
| Current Income Taxes                                                 |       | (66              | )          | (29              | )          |
|                                                                 |       |             |       |             |       |
| Future Income Taxes                                                  |       | (43              | )          | (549             | )          |
|                                                                 |       |             |       |             |       |
| Other                                                                |       |             |       |             |       |
| Block 51 Settlement                                                  |       | 151              |       | (151             | )          |
| Business Interruption Insurance Proceeds                             |       | (154             | )          | 152              |       |
| Gains from Divestiture Programs                                      |       | —           |       | (418             | )          |
| Increase (Decrease) in Fair Value of Crude  Oil Put Options          |       | (32              | )          | 185              |       |
| Other                                                                |       | 72               |       | 8                |       |
|                                                                 |       |             |       |             |       |
| **Net  Income for 2007 and 2006**                                    | ** ** | **1,086**        | ** ** | **601**          | ** ** |

 

----

Notes:
| (1) | 2005 includes results of discontinued  operations (see Note 14 to our Consolidated Financial Statements). |
|-----|-----------------------------------------------------------------------------------------------------------|
| (2) | All amounts are presented before provision  for income taxes.                                             |

 

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

 

44

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Item 7     Management’s Discussion and Analysis        Executive Summary

 

**OIL &GAS AND SYNCRUDE**

**Production**

 
| ** **                    | ** ** | **2007**         | ** ** | **2006**      | ** ** | **2005**         |       |
|-------------------------------|------------|------------------|------------|---------------|------------|------------------|------------|
| ** **                    | ** ** | **Before**       | ** ** | **After**     | ** ** | **Before**       | ** ** | **After** | ** ** | **Before** | ** ** | **After** | ** ** |
| ** **                    | ** ** | **Royalties  1** | ** ** | **Royalties** | ** ** | **Royalties  1** | ** ** | **Royalties** | ** ** | **Royalties  1** | ** ** | **Royalties** | ** ** |
| **Oil and  Liquids**(mbbls/d) |       |             |       |          |       |             |       |   |   | ** ** |   |   |   |
| United Kingdom                |       | 81.2             |       | 81.2          |       | 16.9             |       | 16.9 |   | 12.6 |   | 12.6 |   |
| Yemen                         |       | 71.6             |       | 39.8          |       | 92.9             |       | 51.8 |   | 112.7 |   | 60.6 |   |
| Canada (2)                    |       | 17.1             |       | 13.4          |       | 20.0             |       | 15.8 |   | 29.2 |   | 22.6 |   |
| United States                 |       | 16.4             |       | 14.5          |       | 17.0             |       | 15.0 |   | 22.2 |   | 19.6 |   |
| Other Countries               |       | 6.2              |       | 5.7           |       | 6.3              |       | 5.7 |   | 5.6 |   | 5.1 |   |
| Syncrude (mbbls/d) (3)        |       | 22.1             |       | 18.8          |       | 18.7             |       | 16.9 |   | 15.5 |   | 15.3 |   |
|                          |       | 214.6            |       | 173.4         |       | 171.8            |       | 122.1 |   | 197.8 |   | 135.8 |   |
| **Natural  Gas**(mmcf/d)      |       |             |       |          |       |             |       |   |   |   |   |   |   |
| United Kingdom                |       | 16               |       | 16            |       | 20               |       | 20 |   | 23 |   | 23 |   |
| Canada (2)                    |       | 118              |       | 98            |       | 108              |       | 91 |   | 124 |   | 101 |   |
| United States                 |       | 101              |       | 86            |       | 111              |       | 94 |   | 116 |   | 99 |   |
|                          |       | 235              |       | 200           |       | 239              |       | 205 |   | 263 |   | 223 |   |
|                          |       |             |       |          |       |             |       |   |   |   |   |   |   |
| **Total******(mboe/d)         | ** ** | **254**          | ** ** | **207**       | ** ** | **212**          | ** ** | **156** | ** ** | **242** | ** ** | **173** | ** ** |

 

----

*Notes:*
| *(1)* | *We have  presented production volumes before royalties as we measure our performance  on this basis consistent with other Canadian oil and gas companies.* |
|-------|-------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Includes  the following production from discontinued operations. See Note 14 to our Consolidated  Financial Statements.*                                   |

 
| ** **                | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------|------------|----------|------------|----------|------------|----------|------------|
| Before Royalties          |       |     |       |     |       |     |       |
| Oil and Liquids (mbbls/d) |       | —   |       | —   |       | 6.7      |       |
| Natural Gas (mmcf/d)      |       | —   |       | —   |       | 24       |       |
| After Royalties           |       |     |       |     |       |     |       |
| Oil and Liquids (mbbls/d) |       | —   |       | —   |       | 5.3      |       |
| Natural Gas (mmcf/d)      |       | —   |       | —   |       | 17       |       |

 
| *(3)* | *Considered  a mining operation for US reporting purposes.* |
|-------|-------------------------------------------------------------|

 

2007 vs 2006—Higherproduction increased net income by $1,359 million

 

Production before royaltiesincreased 20% from 2006, 33% after royalties. This increase reflects the startup of Buzzard in early 2007, offset by declines in our maturing Yemen fields.

 

The following tablesummarizes our production changes year over year:

 
| ** **           | ** ** | **Before**    | ** ** | **After**     | ** ** |
|----------------------|------------|---------------|------------|---------------|------------|
| **(mboe/d)**         | ** ** | **Royalties** | ** ** | **Royalties** | ** ** |
| 2006 Production      |       | 212           |       | 156           |       |
| Production Changes   |       |          |       |          |       |
| United Kingdom       |       | 64            |       | 64            |       |
| Yemen                |       | (21           | )          | (12           | )          |
| Syncrude             |       | 3             |       | 2             |       |
| Other                |       | (4            | )          | (3            | )          |
| **2007  Production** | ** ** | **254**       | ** ** | **207**       | ** ** |

 

In 2008, we expect additionalproduction growth over 2007 and expect production to range from 220,000 to240,000 boe/d (260,000 and 280,000 boe/d before royalties). Increases areexpected from a full year of Buzzard, and from the mid-year start up of LongLake Phase 1 and the North Sea Ettrick development.

 

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

** **

**United Kingdom**

 

The addition of high-margin,royalty-free Buzzard volumes increased North Sea production by 64,000 boe/d(net to us), up 300% from last year. Buzzard came on stream January 7,2007 and ramped up to peak production during the year. While the ramp-up wasslower due to pipeline restrictions and the reliability of the acid gas removalsystem, we regularly exceeded initial expectations. Buzzard has safely produced

 

45

----

 

as high as 220,000 boe/d(95,000 net to us), higher than originally expected. We are proceeding withwork to add additional sweetening facilities to handle higher levels ofhydrogen sulphide, and are reviewing debottlenecking opportunities to increasethe processing capacity of the platform. We had ten wells on stream at Buzzardat the end of 2007.

 

**Buzzard came on stream in January 2007 and has safely produced ashigh as 220,000 boe/d (95,000 net to us), 10% above expectations.**

 

Scott/Telford produced 16,500boe/d, comparable with 2006 rates. During the second quarter of 2007, weincreased our interests in the Scott and Telford fields by 0.9% and 17.4%,respectively. The additional production we purchased was offset by naturaldeclines and downtime caused by increased maintenance activity. Farragonproduced 2,600 boe/d during the year, 30% lower than 2006 as a result ofnatural declines. In the fourth quarter, production from our non-operated Duartfield came on stream.

 

In 2008, we plan to drilladditional development wells at Buzzard and Scott/Telford and we anticipatebringing production on stream at Ettrick mid year. We expect production fromthe North Sea to average between 95,000 and 115,000 boe/d in 2008. Our expectedproduction for 2008 reflects some provision for planned and unplanned downtime.

 

**Yemen**

 

Yemen production declined 23%from 2006. Masila production decreased 19%, consistent with expectations. In2007, we drilled 18 development wells and 12 sidetrack wells. Strong initialrates from new wells, combined with well optimizations and reservoirmanagement, helped to minimize expected production declines. Base declines atMasila are expected to continue as most of the development opportunities werepreviously drilled to maximize reserve and capital recoveries under theproduction sharing agreement. We continue to concentrate capital on maximizingrecoveries, and therefore economic returns, from ourexisting wells before our contract expires in 2011. In 2008, we plan to drill10 development wells and continue to optimize well performance.

 

On Block 51 in Yemen,production from the East Al Hajr field declined 35% as a result of naturaldeclines and fewer development wells. We drilled 13 development wells in 2007as compared to 24 the year before. Five development wells are planned for 2008.

 

Substantial value stillremains in our Yemen assets as we expect to generate approximately 22% of thetotal project free cash flow from Masila over the remaining life of thecontract. We expect our share of Yemen production to average between 50,000 and55,000 boe/d in 2008.

 

**Canada**

 

Production in Canadadecreased 3% from the previous year. CBM production rates continue to increaseas our wells in the Fort Assiniboine area de-water and we bring additionaldevelopment wells and facilities on stream. We are optimizing the operation ofthe CBM development wells to maximize up-time and efficiency. Declines in ournatural gas properties in the Medicine Hat region have been more than offset byinfill drilling, and future opportunities remain in the region for additionalinfill drilling. Our capital investment in heavy oil properties continues topartially offset natural declines. At our Balzac gas facility, north ofCalgary, we completed a turnaround mid year, which required production to be shut-infor approximately 48 days.

 

In 2008, we expect productionfrom Canada to average between 45,000 and 50,000 boe/d, with new premiumsynthetic crude oil at Long Lake expected mid year and higher CBM volumes.

 

**United States**

 

Gulf of Mexico production decreased6%, or about 2,300 boe/d from 2006. At Aspen, production increased 1,500 boe/dfrom the previous year. Natural declines in the field, and maintenance andweather-related shut-ins of the non-operated processing facilities partiallyoffset production from new development wells. In late 2006, we brought theAspen 5 development well

 
|  |   |  |
|--|--------|--|

 

46

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on stream; however, declinerates in this well were higher than expected. We previously identified otheropportunities at Aspen and completed a sidetrack mid year to exploit deepersands. While we were encouraged by well log data indicating thick pay zones inthe sidetrack, well deliverability rates could not be sustained. This likelyindicates barriers within this section of the reservoir that are not presentelsewhere. The other Aspen wells continue to produce in line with expectations;however, we expect field production to continue declining as a result ofincreasing water cuts and reservoir depletion.

 

Gunnison production wasapproximately 3,800 boe/d or 36% lower than last year due to natural declinesand mechanical issues in one high volume well. Gunnison accounted for 20% ofour production from the Gulf of Mexico during the year and we expect to bringanother development well on stream in 2008. The Wrigley development came onstream early July but gas production was restricted by limited heatexchanger capability on the non-operated processing facility resulting in anannualized average production rate of 7 mmcf/d in 2007. We are currentlyworking with the facility operator and expect production to increase to peakrates of 24 mmcf/d (net to us) in 2008. Late in the third quarter, we acquiredthree deepwater properties producing approximately 3,000 boe/d. We expect todrill an additional development well at one of these properties in early 2008.

 

On the shelf, our matureassets continue to be impacted by natural declines, and limited workover andrecompletion activity. Declines at Vermilion 76, Eugene Island 18 and WestCameron 170 were only partially offset by Vermillion 340 production that wasrestored in early 2007. Vermillion 340 was shut-in since 2005 due to damage tothe sub-surface pipeline system caused by hurricanes in 2005. Our shelfproduction declined 13% from 2006.

 

In 2008, we expect totalproduction from the Gulf of Mexico to average between 25,000 and 30,000 boe/d.

 

**Other Countries**

** **

Production from Guando inColombia was consistent with 2006. We sustained production rates by maintainingreservoir pressure through an active waterflood program and by drillingadditional infill wells. We expect to maintain current production rates in2008; however, our interest in the field will decrease to 10% once the fieldhas produced 60 million barrels, likely in 2009.

 

**Syncrude**

** **

At Syncrude, productionaveraged 22,060 boe/d, up 18% from 2006 as the Stage 3 expansion contributed afull year of production. Despite this increase, production was lower thanexpected as Coker 8-3 had a utilization rate of less than 70% over the yearbecause of a variety of operating issues with the new equipment. After anextended turnaround on the LC Finer and Coker 8-3 in the second quarter of2007, the Coker processed bitumen at expected capacity until early October whenit was temporarily shut in due to coke build up. In December, production waspartially reduced for four days due to a fire in Coker 8-3’s environmentalprecipitators. In early 2008, production at Syncrude was temporarily suspendedfor six days due to an upset in the amine and fuel gas system that was broughton by extremely cold weather conditions.

 

Strong realized prices forour production have enabled us to fully recover capital costs at Syncrudeincluding costs associated with the Stage 3 expansion. Consequently, our Syncruderoyalties increased from a 1% gross revenue royalty to a 25% net revenueroyalty, beginning in 2006. This translates into lower after royalty productionrelative to our working interest production volumes. The Alberta government iscurrently negotiating with the Syncrude owners to amend the existing royaltyagreement, which is in place until 2016. This could result in Syncrude movingto the proposed royalty framework, which features higher royalty rates, before January 2016in exchange for other concessions.

 

In 2008, we expect our shareof Syncrude production to average between 20,000 and 25,000 bbls/d.

 

2006 vs 2005—Lower productiondecreased net income by $374 million

 

Production before royaltiesdecreased 12% from 2005, 10% after royalties. Our 2006 production excludedvolumes from our Canadian oil and gas properties that were sold in the thirdquarter of 2005. Removing the impact of these property dispositions, productionbefore and after royalties decreased 8% and 5%, respectively. Decreases werecaused by natural declines at mature fields in Yemen and at Aspen in the Gulfof Mexico.

 

47

----

 

**Commodity Prices**

 
| ** **                                                      | ** ** | **2007**  | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|-----------------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| **Crude  Oil**                                                  |       |      |       |      |       |      |       |
| West Texas Intermediate (WTI) (US$/bbl)                         |       | 72.31     |       | 66.22     |       | 56.58     |       |
| Benchmark Differentials (1) (US$/bbl)                      |       |      |       |      |       |      |       |
| Heavy Oil                                                       |       | 23.44     |       | 21.79     |       | 20.82     |       |
| Mars                                                            |       | 5.67      |       | 7.34      |       | 6.59      |       |
| Masila                                                          |       | 0.50      |       | 3.00      |       | 5.71      |       |
| Dated Brent                                                     |       | (0.21     | )          | 1.08      |       | 2.20      |       |
| Producing Assets (Cdn$/bbl)                                     |       |      |       |      |       |      |       |
| Yemen                                                           |       | 76.29     |       | 71.57     |       | 62.07     |       |
| Canada                                                          |       | 44.07     |       | 42.79     |       | 40.51     |       |
| United States                                                   |       | 69.83     |       | 65.80     |       | 57.63     |       |
| United Kingdom                                                  |       | 76.30     |       | 71.19     |       | 60.55     |       |
| Other Countries                                                 |       | 71.29     |       | 66.09     |       | 59.96     |       |
| Syncrude                                                        |       | 79.76     |       | 72.32     |       | 71.00     |       |
|                                                            |       |      |       |      |       |      |       |
| Corporate Average (Cdn$/bbl)                                    |       | 73.43     |       | 67.50     |       | 58.98     |       |
| **Natural  Gas**                                                |       |      |       |      |       |      |       |
| New York Mercantile Exchange (US$/mmbtu)                        |       | 7.12      |       | 6.99      |       | 8.99      |       |
| AECO (Cdn$/mcf)                                                 |       | 6.26      |       | 6.62      |       | 8.04      |       |
| Producing Assets (Cdn$/mcf)                                     |       |      |       |      |       |      |       |
| Canada                                                          |       | 6.32      |       | 6.49      |       | 7.51      |       |
| United States                                                   |       | 7.80      |       | 7.86      |       | 10.56     |       |
| United Kingdom                                                  |       | 4.71      |       | 7.43      |       | 7.86      |       |
|                                                            |       |      |       |      |       |      |       |
| Corporate Average (Cdn$/mcf)                                    |       | 6.81      |       | 7.18      |       | 8.89      |       |
|                                                            |       |      |       |      |       |      |       |
| **Nexen’s  Average Realized Oil and Gas Price (Cdn$/boe)** | ** ** | **68.46** | ** ** | **62.92** | ** ** | **57.97** | ** ** |
|                                                            |       |      |       |      |       |      |       |
| Average Foreign Exchange Rate–Canadian to  US Dollar       |       | 0.9304    |       | 0.8818    |       | 0.8253    |       |

* *

----

*Note:*
| *(1)* | *These  differentials are a discount/(premium) to WTI.* |
|-------|---------------------------------------------------------|

 

2007 vs 2006—Higher realizedprices increased net income $284 million

 

Average WTI and Dated Brentin US dollars were 9% and 11% higher, respectively, from the prior year, andour average realized crude oil price increased 9% to $73.43/bbl. Our higheraverage realized price reflects the change in production mix with the additionof new high quality Buzzard production. This change helped to offset the impactof the weaker US dollar on our Canadian dollar realized prices. Our realizednatural gas price fell 5% from 2006 as a result of the stronger Canadiandollar, despite NYMEX increasing 2% in the same period. The weaker US dollarreduced net sales by approximately $225 million, and reduced our realized crudeoil and natural gas prices by approximately $3.20/bbl and $0.30/mcf,respectively, as compared to 2006.

 

**Crude Oil Reference Prices**

** **

Crude oil prices remainedstrong in 2007. Crude oil prices climbed steadily throughout the year, with WTIranging from a low of US$49.90/bbl early in the year to US$95.98/bbl inDecember. In early 2008, WTI broke through US$100/bbl in intra-day trading buthas since slipped to about US$90/bbl on fears of a US recession. The maindrivers of the high prices last year were concerns over supply resulting fromgeopolitical tensions around the world, strong global demand, declininginventory levels and a weakening US dollar.

 

 

48

----

 

Geopolitical risk continued to be an underlying themethroughout 2007. In the Middle East, on-going tensions between the US and Iranover its uranium enrichment program led to fears that it would escalate topotential US action against Iran and a reduction in oil exports. Conflict alsoescalated between Turkey and Kurdish rebels in Northern Iraq, where asubstantial portion of the country’s oil production is located. Supply outagesin Nigeria caused by continued violence, and nationalization of Venezuela’senergy industry also contributed to higher prices and market volatility.

 

Global demand growth forcrude oil continues to be robust. Demand from China, the world’s second largestoil consumer, India, Russia and the Middle East grew from last year whereas globalsupply increased marginally. There are concerns over supply from politicallyunstable locations such as Nigeria, Iran and Iraq, some of the world’s majoroil producers and exporters. A sustained decline in inventories alsocontributed to strong oil prices. Crude oil inventories at theend of 2007 were at their lowest levels in the last five years.

 

A steadily weakening USdollar helped fuel the rise of crude oil prices to an all-time nominal highsince global crude oil is denominated in US dollars. Weak equity markets also re-directedinvestment into the financial commodity markets, increasing volatility.

 

**Crude Oil Differentials**

 

In Canada, heavy crude oildifferentials averaged US$23.44/bbl (32% of WTI) for the year, compared toUS$21.79/bbl (33% of WTI) in 2006. Differentials were narrower than usual atthe beginning of the year as OPEC cuts from late 2006 tended to be heavy oil,thereby increasing prices for heavier crude. As we headed into the summerasphalt season, we expected a seasonal narrowing. However, a major fire at BP’sWhiting refinery in March curtailed its ability to process heavy oil forthe remainder of the year reducing the demand for Canadian heavy crude by100,000 barrels a day. Late in the year, the differentials widened substantiallydue to pipeline constraints until a shutdown at the Albian upgrader in the Athabascaoil sands freed up pipeline space. In December, the heavy oil differentialimproved from $45/bbl to $25/bbl as a result of weaker WTI prices and theAlbian upgrader incident. Heavy oil prices are expected to weaken again in January andFebruary once the Albian upgrader is back on stream.

 

The Brent/WTI differentialstrengthened during 2007 with Brent trading at a premium of US$0.21/bblcompared to a discount of US$1.08/bbl in 2006. The Brent index is relevant forus as approximately 80% of our current crude production is priced based onBrent. WTI traded at a discount to Brent for almost half of the year. Regionalissues, such as an overabundance of crude in local storage around the Cushing,Oklahoma area where WTI is priced and the limited ability to move that crude toworld markets caused WTI to trade at lower prices than other internationalgrades of crude oil. By comparison, Brent prices were strong as multiple transportationoptions allow it to remain a global crude oil. However, WTI regained itsstrength and traded at a premium to Brent during the latter part of the year.

 

The US Gulf Coast Marsdifferential narrowed, averaging US$5.67/bbl in 2007 compared to US$7.34/bbl in2006. Since Mars can be moved globally, it competes with international crudesand was not readily affected by the pipeline constraints at Cushing earlier inthe year which depressed WTI.

 

The Yemen Masila differentialnarrowed substantially relative to WTI during 2007, averaging US$0.50/bblcompared to US$3.00/ bbl last year. Yemen Masila traded at a premium to WTI inthe summer, reflecting the impact of stronger Brent pricing since Masila crudeis priced off Brent. As WTI regained its strength relative to Brent in thefall, the Yemen Masila differential traded at a discount to WTI for theremainder of the year.

 

**Natural Gas Reference Prices**

 

NYMEX natural gas pricesaveraged US$7.12/mmbtu, compared to US$6.99/mmbtu in 2006. In January 2007,gas prices were unusually soft at the peak of the withdrawal season as January experiencedthe highest global temperature on record for this time of year. However,natural gas prices rebounded in the following months as a result of strongcrude oil prices, technical trading in financial markets and cold weather inseveral key North American natural gas consuming regions. Natural gas pricesweakened during the summer and autumn seasons reflecting higher storage levelsthat were approaching the top of the North American five-year average. The highstorage levels were caused by LNG cargoes being diverted to North America fromweak European markets, mild summer weather and a quiet hurricane season in theGulf of Mexico.

 

49

----

 

2006 vs 2005 – Higherrealized prices increased net income by $192 million

 

Crude oil prices remainedstrong for most of 2006, with WTI finishing the year at US$61.05/bbl, roughlywhere it began. The steady decline in crude prices from August to the endof the year was largely driven by warm weather, above average crude oilinventories, concerns over the US economy, the perceived reduction ofgeopolitical tensions in the Middle East and institution-led sell offs in thecrude oil markets.

 

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, mildJanuary temperatures experienced in several key North American natural gasconsuming regions resulted in a weaker NYMEX. This created a significant gasstorage overhang. Prices remained soft throughout the year reflecting highstorage levels, an uneventful hurricane season and a mild 2006/2007 winterprediction due to the warming effect of El Nino.

 

The full impact of theincrease in WTI was not reflected in our higher realized crude oil price as theCanadian dollar strengthened relative to the US dollar. The impact of theweaker US dollar was offset by narrower crude oil differentials. The weaker USdollar reduced net sales by approximately $250 million, and reduced ourrealized crude oil and natural gas prices by approximately $4.85/bbl and$0.50/mcf, respectively as compared to 2005.

 

**OperatingExpenses**

 
| ** **                   | ** ** | **2007**                       | ** ** | **2006**             | ** ** | **2005**                       | ** ** |
|------------------------------|------------|--------------------------------|------------|----------------------|------------|--------------------------------|------------|
| **(Cdn$ /boe)**         | ** ** | **Before  Royalties (1)** | ** ** | **After  Royalties** | ** ** | **Before  Royalties (1)** | ** ** | **After  Royalties** | ** ** | **Before  Royalties (1)** | ** ** | **After  Royalties** | ** ** |
| **Conventional Oil and Gas** |       |                           |       |                 |       |                           |       |   |   |   |   |   |   |
| Yemen                        |       | 6.56                           |       | 12.00                |       | 4.45                           |       | 8.11 |   | 3.63 |   | 6.75 |   |
| Canada                       |       | 12.91                          |       | 15.93                |       | 10.31                          |       | 12.73 |   | 8.21 |   | 10.34 |   |
| United States                |       | 8.43                           |       | 9.69                 |       | 8.17                           |       | 9.45 |   | 6.35 |   | 7.33 |   |
| United Kingdom               |       | 6.94                           |       | 6.94                 |       | 11.28                          |       | 11.28 |   | 14.90 |   | 14.90 |   |
| Other Countries              |       | 3.45                           |       | 3.76                 |       | 2.87                           |       | 3.13 |   | 5.55 |   | 6.08 |   |
| Average Conventional         |       | 7.89                           |       | 9.75                 |       | 6.95                           |       | 9.69 |   | 6.03 |   | 8.70 |   |
|                         |       |                           |       |                 |       |                           |       |   |   |   |   |   |   |
| **Synthetic Crude Oil**      |       |                           |       |                 |       |                           |       |   |   |   |   |   |   |
| Syncrude                     |       | 25.80                          |       | 30.32                |       | 27.53                          |       | 30.43 |   | 26.95 |   | 27.22 |   |
| **Average Oil and Gas**      |       | 9.45                           |       | 11.63                |       | 8.77                           |       | 11.96 |   | 7.36 |   | 10.34 |   |

 

----

*Note:*

| *(1)* | *Operating  expenses per boe are our total oil and gas operating costs divided by our  working interest production before royalties. We use production before  royalties to monitor our performance consistent with other Canadian oil and  gas companies.* |
|-------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

2007 vs 2006—Higher operatingexpenses decreased net income by $199 million

 

Our oil and gas operatingcosts increased $199 million from 2006 primarily as a result of Buzzard comingon-stream in early 2007 and higher Syncrude production. Our production mix alsochanged from last year as a result of this production, altering our averageunit cost. Operating costs at Buzzard are lower than our corporate average,reducing our corporate average by $1.58/boe. However, the higher-cost Syncrude barrelsincreased our corporate average by $0.74/boe.

 

At Masila in Yemen, operatingcosts increased with higher service rig activity and maintenance programs.These costs are necessary to minimize production declines and maximize therecovery of the remaining reserves, given the maturity of the field. The highercosts and lower production increased our corporate average by $0.57/boe.Similarly at Block 51, our operating expenditures were higher as additionalservice rig activity and higher water handling, fuel and equipment costsincreased operating expenditures. The higher costs increased our corporate average$0.37/boe. We expect the average per-unit cost to continue to increase in Yemenas production declines.

 

50

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Canadian production increasedour corporate average $0.50/ boe during the year as a result of industry costpressures, the extended Balzac turnaround and lower production. Ourheavy oil properties havehigher unit operating costs as many of the costs are fixed in nature and heavyoil production is declining. Operating costs have also increased withadditional CBM wells coming on-stream at Fort Assiniboine. Unit operating costsare initially higher as we de-water the wells to stimulate gas production. Weexpect our CBM operating costs to decrease over time as the wells de-water,reliability improves and gas production increases.

 

In the Gulf of Mexico, whiletotal operating costs remained consistent year over year, lower productionincreased our corporate average by $0.18/boe. During 2007, industry pressuresincreased costs and we performed additional downhole and surface maintenanceactivity to maintain production. However, these costs had minimal impact on ourcorporate average when compared to last year as our 2006 costs includedextended maintenance and turnaround activity at Eugene Island on the shelf.

 

**Operatingcosts at Buzzard are low, reducing our corporate average by $1.58/boe.**

 

In the UK North Sea, ourScott/Telford costs increased our corporate average by $0.33/boe. During theyear, our total operating expenditures increased as we performed maintenanceand work overs on the platform and producing wells, including repairingturbines and improving water injection facilities.

 

Lower Syncrude operatingcosts reduced our corporate average by $0.16/boe, and were 6% lower than 2006as the impact of the higher production from the expansion completed in 2006 wasonly partially offset by increased maintenance costs. In 2007, maintenance andturnarounds on the Coker 8-3 and the LC Finer interrupted production andincreased operating costs.

 

US-dollar denominatedoperating costs were lower when translated into Canadian dollars, reducing ourcorporate average $0.26/boe.

 

2006 vs 2005—Higher operatingexpenses decreased net income by $22 million

 

In Yemen, operating costs ona per-unit basis increased as fixed costs from our central processingfacilities and increased water handling costs were spread over lower productionvolumes. Masila increased our corporate average by $0.20/boe, reflecting lowerproduction, increased service rig activity to minimize production declines, andcosts to replace a single point mooring system to load oil tankers. 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.

 

Following the sale ofCanadian conventional oil and gas properties in 2005, we had proportionatelymore heavy oil production, which had higher operating costs than the lighter oilproduction we sold. Canadian operating costs in 2006 increased our corporateaverage by $0.18/boe. Operating costs in the Gulf of Mexico increased from 2005due to industry cost pressures caused by strong commodity prices and the 2005hurricane season. Lower production volumes and workovers on our shelfproperties early in 2006 increased our corporate average by $0.39/boe.

 

With the sale of Canadianproduction in 2005, barrels from the North Sea contributed a higher percentageof our total production. As the North Sea had higher operating costs than ouraverage cost per barrel, the change in production mix increased our corporateaverage by $0.32/boe. This was offset by lower operating costs relative to2005, as operating expenses in 2005 included repair costs related to turbinefailures. This reduced our corporate average by $0.26/boe.

 

Syncrude increased our corporateaverage operating costs by $0.72/boe from 2005 as a result of maintenanceactivities and the coker turnaround during the first quarter of 2006, combined withcosts related to start-up of the Stage 3 expansion.

 

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

 

51

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

 
| ** **                   | ** ** | **2007**                       | ** ** | **2006**             | ** ** | **2005**                       | ** ** |
|------------------------------|------------|--------------------------------|------------|----------------------|------------|--------------------------------|------------|
| **(Cdn$ /boe)**         | ** ** | **Before  Royalties (1)** | ** ** | **After  Royalties** | ** ** | **Before  Royalties (1)** | ** ** | **After  Royalties** | ** ** | **Before  Royalties (1)** | ** ** | **After  Royalties** | ** ** |
| **Conventional Oil and Gas** |       |                           |       |                 |       |                           |       |   |   |   |   |   |   |
| Yemen                        |       | 8.15                           |       | 14.92                |       | 9.67                           |       | 17.61 |   | 8.56 |   | 15.93 |   |
| Canada                       |       | 12.46                          |       | 15.37                |       | 11.22                          |       | 13.84 |   | 9.26 |   | 11.67 |   |
| United States (2)            |       | 22.64                          |       | 26.03                |       | 16.28                          |       | 18.84 |   | 15.39 |   | 17.77 |   |
| United Kingdom               |       | 19.59                          |       | 19.59                |       | 30.22                          |       | 30.22 |   | 33.25 |   | 33.25 |   |
| Other Countries              |       | 3.68                           |       | 4.06                 |       | 4.30                           |       | 4.69 |   | 6.20 |   | 6.79 |   |
| Average Conventional         |       | 14.94                          |       | 18.47                |       | 13.12                          |       | 18.30 |   | 11.78 |   | 17.00 |   |
|                         |       |                           |       |                 |       |                           |       |   |   |   |   |   |   |
| **Synthetic Crude Oil**      |       |                           |       |                 |       |                           |       |   |   |   |   |   |   |
| Syncrude                     |       | 6.59                           |       | 7.74                 |       | 4.81                           |       | 5.32 |   | 3.08 |   | 3.12 |   |
| **Average Oil and Gas**      |       | 14.21                          |       | 17.49                |       | 12.38                          |       | 16.88 |   | 11.23 |   | 15.77 |   |

 

----

*Notes:*
| *(1)* | * * | *DD&A  per boe is our DD&A for oil and gas operations divided by our working  interest production before royalties. We use production before royalties to  monitor our performance consistent with other Canadian oil and gas companies.* |
|-------|----------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | * * | *DD&A  per boe excludes the impairment charges described in Note 6 of our  Consolidated Financial Statements.*                                                                                                                                |

 

2007 vs 2006—Higher oil andgas and Syncrude DD&A decreased net income by $636 million

 

In 2007, our DD&A expenseincludes $366 million ($3.96/boe) of impairment expense primarily related toour Aspen, Vermillion 320/340 and West Cameron 170 properties in the Gulf ofMexico as we had poor results from capital investments and lower reserveestimates. At Aspen, disappointing results from our recent investment indevelopment drilling resulted in negative reserve revisions. While we wereencouraged by well log data indicating thick pay zones, well deliverabilityrates could not be sustained. This likely indicates barriers within thissection of the reservoir. At Vermillion 320/340 and West Cameron 170, negativereserve revisions primarily relate to gas properties, where unsatisfactoryinvestment results, production performance, revised mapping and higherprojected operating costs resulted in a downward revision to reservesestimates. The carrying values of these properties were reduced to theirestimated fair value.

 

Production from Buzzardincreased our corporate average unit DD&A rate by $1.44/boe. Buzzard costsare higher than our corporate average as they include acquisition and projectcompletion costs. We expect Buzzard unit depletion to decrease over time as weexpect to book more proved reserves from production experience and furtherdevelopment drilling. We recognized additional proved reserves at the end of2006 for our other UK assets, which lowered the corporate average $0.59/boe in2007.

 

A reduced capital program andslower recovery of capital costs paid on the Yemen government’s behalfdecreased our corporate average DD&A rate by $0.15/boe.

 

Depletion of our Canadianassets increased our corporate average by $0.24/boe reflecting the timing ofreserve bookings from our CBM projects in central Alberta, and land acquisitionsin 2006. As our new CBM wells progress through the de-watering stage andproduction increases, we expect to recognize additional proved reserves whichwill reduce our unit depletion rate.

 

In the Gulf of Mexico,unsuccessful development drilling at Aspen and on the shelf increased ourcapital base, increasing our corporate average rate by $1.29/boe.

 

Syncrude DD&A includescosts to develop the Stage 3 expansion that came on stream in mid 2006, whichincreased our corporate average by $0.21/boe.

 

The strong Canadian dollarrelative to the US dollar decreased our corporate average DD&A rate by$0.53/boe as our US and international depletion is denominated in US dollars.

 

52

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2006 vs 2005—Higher oil andgas DD&A decreased net income by $48 million

 

Our 2006 DD&A expenseincluded $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 were reduced to theirestimated fair value. In addition, our 2006 DD&A expense included $15million (2005—$58 million) relating to a partial write down of our purchaseprice allocation to unproved properties purchased in the North Sea, as a resultof unsuccessful exploration activities. Our 2006 average depletion rateexcluding impairment charges was $12.38/boe, up 10% from 2005.

 

In Yemen, we began depletingthe permanent production facilities on Block 51 in 2006 following theircommissioning earlier in the year. Strong crude oil prices allowed us tocontinue to maximize recovery of costs we paid on the government’s behalf. Thisincreased our corporate average by $0.64/boe.

 

Our increased Canadiandepletion rate reflected depletion of costs for our CBM projects in centralAlberta, which increased our corporate average by $0.35/boe. Depletion ratesfor our deep-water assets in the Gulf of Mexico increased our average by$0.28/boe primarily as a result of reserve revisions late in 2005.

 

Our depletion rate for ourNorth Sea assets was higher than our average, primarily from the purchase priceallocation assigned to them when acquired in 2004. Our corporate average isincreasing as the North Sea becomes a larger proportion of our total productionand Canada becomes a small portion, following the sale of Canadian conventionaloil and gas assets in 2005. This change increased our corporate average by$0.42/boe.

 

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 corporate DD&A by $0.72/boe from 2005 as the depletion of ourinternational and US assets is denominated in US dollars.

 

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

 
| **(Cdn$ millions)**                               | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Seismic                                                |       | 123      |       | 128      |       | 53       |       |
| Unsuccessful Drilling                                  |       | 126      |       | 169      |       | 143      |       |
| Other                                                  |       | 77       |       | 65       |       | 55       |       |
| **Total Exploration Expense**                          | ** ** | **326**  | ** ** | **362**  | ** ** | **251**  | ** ** |
|                                                   |       |     |       |     |       |     |       |
| New Growth Exploration                                 |       | 573      |       | 491      |       | 456      |       |
| Geological and Geophysical Costs                       |       | 123      |       | 128      |       | 53       |       |
| **Total Exploration Expenditures**                     | ** ** | **696**  | ** ** | **619**  | ** ** | **509**  | ** ** |
|                                                   |       |     |       |     |       |     |       |
| Exploration Expense as a % of Exploration Expenditures |       | 47       | %          | 58       | %          | 49       | %          |

 

----

*Note:*

*(1) 2005includes exploration expense from discontinued operations. See Note 14 to ourConsolidated Financial Statements.*

 

2007 vs 2006–Lowerexploration expense increased net income by $36 million

 

We invested almost $700million in exploration oriented activities during the year, primarily relatedto drilling in the Gulf of Mexico, UK North Sea and CBM in Canada, andacquiring seismic data in the Gulf of Mexico and Norway. In addition, weacquired material land positions in the Gulf of Mexico, and in northeastBritish Columbia related to an emerging Devonian shale gas play.

 

Exploration expense decreased$43 million or 25% from last year as a result of fewer unsuccessful explorationwells. In the Gulf of Mexico, we incurred dry hole costs of $59 million ascompared to $135 million in 2006; however, this decrease was partially offsetby higher unsuccessful well costs in the UK North Sea, Colombia and Canada.

 

**In thedeep-water Gulf of Mexico, we drilled a successful appraisal well at Longhorn. Developmenthas been sanctioned and production is expected in 2009.**

 

53

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** **

In the deep-water Gulf ofMexico, we drilled a successful appraisal well at Longhorn and evaluatedresource estimates. The Longhorn development has been sanctioned and productionis expected in 2009. Also in the deep water, our Vicksburg prospect was drilledto a depth of 25,400 feet and encountered hydrocarbons. Core was recovered fromthe well and studies are underway to assess the potential productivity.Additional drilling in the area is planned in 2008. Our unsuccessful drillingresults in the Gulf of Mexico were primarily on the shelf where we expensed $35million for dry holes. In the deep water, we drilled a sidetrack at Aspentargeting two zones in deeper sands; however, results from the lowest zone wereunsuccessful and we expensed $20 million for a portion of the drilling costs ofthe well.

 

In the UK North Sea, we hadseveral exploration successes. We followed up on our successful Golden Eaglewell by drilling a sidetrack to appraise the accumulation. We are currentlyevaluating development options for this discovery. At Selkirk, we successfullycompleted an appraisal well and sidetrack and are currently assessingdevelopment alternatives. At Kildare, we plan to drill an appraisal well inthird quarter of 2008. Our 2007 dry hole costs in the UK North Sea were $39million compared to $21 million in 2006. The $15 million Guinea well wascompleted in the first quarter; however, the target reservoir was water bearingand the well was abandoned. Further exploration wells at Stag and Dee wereplugged and abandoned,resulting in $12 million and $8 million, respectively, in expensedcosts.

 

In Colombia, we expensed $11million related to the unsuccessful Guaini-1 and Atalea-1 exploratory wells. InCanada, we expensed costs associated with unsuccessful CBM activities atProvost, Kakwa and Sullivan Lake. Seismic data costs of $123 million werecomparable with 2006. The Gulf of Mexico and Norway accounted for 74% of theseismic expenditures, as we consider these areas to have significantexploration potential. Data has been acquired during the last two years tosupport our acreage accumulation efforts.

 

We plan to investapproximately $600 million in our 2008 exploration and appraisal program andanticipate drilling up to 11 exploration and four appraisal wells in the Gulfof Mexico, North Sea and Yemen.

 

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 on acquiring seismic data. We were successful at Great WhiteWest and Longhorn (formerly Ringo) in the Gulf of Mexico. In early 2007, wecompleted drilling at our Golden Eagle prospect in the UK North Sea. Thediscovery well was drilled to approximately 7,500 feet and encounteredhydrocarbons.

 

Our unsuccessful drillingresults were primarily in the Gulf of Mexico, where we expensed $135 million indry hole costs. Early in 2006, we expensed $49 million for the Pathfinder well,which found non-commercial quantities of hydrocarbons, after reaching a totaldepth of 31,196 feet. Unsuccessful wells on the shelf in the Gulf of Mexicoinclude West Cameron 135 and 109 ($23 million and $14 million respectively) andVermilion 65 ($15 million). During 2006, we also expensed $29 million ofcapitalized costs related to Big Bend as it was determined that development wasuneconomic 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.

 

Our geological andgeophysical costs include $128 million of seismic data acquired during 2006,half related to the Gulf of Mexico. The balance was spent on acquiring data inCanada, Norway, the North Sea, Nigeria and other international targets.

** **

54

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** **

**OIL & GAS AND SYNCRUDE NETBACKS**

 

Netbacks are the cashmargins, before general and administrative expenses, we receive for everyequivalent barrel sold. The following table lists the sales prices, per-unitcosts and netbacks for our producing assets, calculated using our working interestproduction before and after royalties. A combination of strong realized pricesand new high-margin production from Buzzard increased our cash netback by 32%from 2006 (17% after royalties).

 

Before Royalties

 
| ** **           | ** ** | **2007**  | ** ** |
|----------------------|------------|-----------|------------|
| **($ /boe)**    | ** ** | **Yemen** | ** ** | **Canada** | ** ** | **US** | ** ** | **UK** | ** ** | **Other** | ** ** | **Syncrude** | ** ** | **Total** | ** ** |
| Sales                |       | 76.29     |       | 40.79 |   | 58.16 |   | 74.79 |   | 71.29 |   | 79.76 |   | 68.46 |   |
| Royalties and Other  |       | (34.69    | )          | (7.81 | ) | (7.45 | ) | — |   | (5.90 | ) | (12.02 | ) | (13.10 | ) |
| Operating Expenses   |       | (6.56     | )          | (12.91 | ) | (8.43 | ) | (6.94 | ) | (3.45 | ) | (25.80 | ) | (9.45 | ) |
| In-country Taxes (1) |       | (9.52     | )          | — |   | — |   | — |   | — |   | — |   | (2.69 | ) |
|                 |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Cash Netback**     | ** ** | **25.52** | ** ** | **20.07** | ** ** | **42.28** | ** ** | **67.85** | ** ** | **61.94** | ** ** | **41.94** | ** ** | **43.22** | ** ** |

 
| ** **           | ** ** | **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** | ** ** |

 

After Royalties

 
| ** **           | ** ** | **2007**  | ** ** |
|----------------------|------------|-----------|------------|
| **($ /boe)**    | ** ** | **Yemen** | ** ** | **Canada** | ** ** | **US** | ** ** | **UK** | ** ** | **Other** | ** ** | **Syncrude** | ** ** | **Total** | ** ** |
| Sales                |       | 76.29     |       | 40.79 |   | 58.16 |   | 74.79 |   | 71.29 |   | 79.76 |   | 68.46 |   |
| Operating Expenses   |       | (12.00    | )          | (15.93 | ) | (9.69 | ) | (6.94 | ) | (3.76 | ) | (30.32 | ) | (11.63 | ) |
| In-country Taxes (1) |       | (17.42    | )          | — |   | — |   | — |   | — |   | — |   | (3.31 | ) |
|                 |       |      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Cash Netback**     | ** ** | **46.87** | ** ** | **24.86** | ** ** | **48.47** | ** ** | **67.85** | ** ** | **67.53** | ** ** | **49.44** | ** ** | **53.52** | ** ** |

 
| ** **           | ** ** | **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** | ** ** |

 

----

*Note:*

*(1)Comprises income taxes payable in Yemen that are included in the Government’sshare of profit oil.*

 

55

----

 

**ENERGY MARKETING**

 
| **(Cdn$ millions)**                                                                    | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Physical Sales (1)                                                                          |       | 47,826   |       | 40,920   |       | 37,873   |       |
| Physical Purchases (1)                                                                      |       | (46,897  | )          | (39,925  | )          | (36,988  | )          |
| Net Financial Transactions (1)                                                              |       | (49      | )          | 314      |       | (38      | )          |
| Increase in Fair Market Value of Inventory                                                  |       | 79       |       | —   |       | —   |       |
| Net Revenue                                                                                 |       | 959      |       | 1,309    |       | 847      |       |
| Transportation Expense                                                                      |       | (806     | )          | (789     | )          | (641     | )          |
| Other                                                                                       |       | 14       |       | 20       |       | (2       | )          |
| **Net Marketing Revenue**                                                                   | ** ** | **167**  | ** ** | **540**  | ** ** | **204**  | ** ** |
|                                                                                        |       |     |       |     |       |     |       |
| **Contribution to Net Marketing Revenue by Region:**                                        |       |     |       |     |       |     |       |
| North America                                                                               |       | 151      |       | 526      |       | 186      |       |
| Asia                                                                                        |       | 11       |       | 13       |       | 18       |       |
| Europe                                                                                      |       | 5        |       | 1        |       | —   |       |
| **Net Marketing Revenue**                                                                   | ** ** | **167**  | ** ** | **540**  | ** ** | **204**  | ** ** |
| Depreciation, Depletion, Amortization and Impairment                                        |       | (13      | )          | (12      | )          | (11      | )          |
| General and Administrative                                                                  |       | (87      | )          | (112     | )          | (89      | )          |
|                                                                                        |       |     |       |     |       |     |       |
| **Marketing Contribution to Income from Continuing********Operations  before Income taxes** |       | **67**   | ** ** | **416**  | ** ** | **104**  | ** ** |
|                                                                                        |       |     |       |     |       |     |       |
| **North America**                                                                           |       |     |       |     |       |     |       |
| **Natural Gas**                                                                             |       |     |       |     |       |     |       |
| Physical Sales Volumes (2) (bcf/d)                                                     |       | 5.8      |       | 5.4      |       | 4.9      |       |
| Transportation Capacity (bcf/d)                                                             |       | 2.0      |       | 3.3      |       | 4.0      |       |
| Storage Capacity (bcf)                                                                      |       | 39       |       | 50       |       | 30       |       |
| Financial Volumes(bcf/d)                                                                    |       | 21.9     |       | 19.8     |       | 12.1     |       |
| **Crude Oil**                                                                               |       |     |       |     |       |     |       |
| Physical Sales Volumes (2) (mbbls/d)                                                   |       | 655      |       | 553      |       | 318      |       |
| Storage Capacity (mbbls)                                                                    |       | 2,734    |       | 1,749    |       | 580      |       |
| Financial Volumes(mbbls/d)                                                                  |       | 2,134    |       | 1,976    |       | 819      |       |
| **Power**                                                                                   |       |     |       |     |       |     |       |
| Physical Sales Volumes (2) (MW/d)                                                      |       | 4,516    |       | 4,388    |       | 2,548    |       |
| Generation Capacity (MW/hr)                                                                 |       | 87       |       | 87       |       | 53       |       |
|                                                                                        |       |     |       |     |       |     |       |
| **Asia**                                                                                    |       |     |       |     |       |     |       |
| Physical Sales Volumes (2) (mbbls/d)                                                   |       | 183      |       | 152      |       | 192      |       |
| Financial Volumes (mbbls/d)                                                                 |       | 256      |       | 207      |       | 163      |       |
|                                                                                        |       |     |       |     |       |     |       |
| **Europe**                                                                                  |       |     |       |     |       |     |       |
| Financial Volumes (mbbls/d)                                                                 |       | 529      |       | 52       |       | —   |       |
|                                                                                        |       |     |       |     |       |     |       |
| **Value-at-Risk**                                                                           |       |     |       |     |       |     |       |
| Year End                                                                                    |       | 26       |       | 26       |       | 24       |       |
| High                                                                                        |       | 38       |       | 33       |       | 28       |       |
| Low                                                                                         |       | 24       |       | 17       |       | 11       |       |
| Average                                                                                     |       | 30       |       | 23       |       | 21       |       |

 

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*Notes:*
| *(1)* | *Marketing’s  physical sales, physical purchases and net financial transactions are  reported net on the Consolidated Statement of Income as marketing and other.* |
|-------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Excludes  intra-segment transactions.*                                                                                                                                 |

 

56

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2007 vs 2006—Reduced energymarketing contribution decreased net income by $373 million

 

Results from our energymarketing group were below the record year we experienced in 2006 as there werefewer market events to capitalize on, and fundamental changes in commoditymarkets were difficult to predict with confidence.

 

As part of our gas marketingstrategy, we hold physical transportation and storage capacity contracts thatallow us to take advantage of pricing differences between locations (i.e. westvs. east) and time periods (i.e. summer vs. winter). These strategies,particularly time spreads, contributed less to net revenue in 2007 as therewere fewer significant weather-related market events (hurricanes or cold winterweather) to capitalize on. These events typically cause time spreads to widenand location spreads to dislocate, presenting trading opportunities for us. Inaddition, gas prices were supported throughout the year by high oil pricesdespite record gas storage levels. We were successful at generating revenuethrough the day-to-day optimization of our transportation and storage capacity,as well as our fee-for-service asset management activities.

 

The contribution of our NorthAmerican crude oil marketing team was lower than 2006 as their portfolio, bothphysical and financial, was positioned to take advantage of contango (risingforward month prices) in the crude oil forward curve. Late summer, near-termcrude oil prices moved up sharply, moving the forward curve from contango tobackwardation (falling forward month prices). As a result, we suffered lossesin our financial time spread positions. We continued to capture profits fromlocation and quality spreads by diverting crude oil to more attractive marketsor blending to enhance crude quality.

 

Our power marketing groupremains the largest supplier of power to the commercial and industrial sectorin Alberta and continued to deliver solid returns.

 

Our 2007 results include fairvalue gains of $79 million on our natural gas and crude oil in storage andpipelines in the fourth quarter. New inventory standards under Canadian GAAPrequire us to carry our trading commodity inventories at fair value, ratherthan at cost as was previously the case. We adopted these new rules in thefourth quarter.

 

In late 2006, wede-designated certain futures contracts that were designated as cash flowhedges of future sales of our natural gas in storage. These contracts werede-designated since it became uncertain that the future sales would occurwithin the designated time frame. As it was reasonably possible that the futuresales could have taken place as designated at the inception of the hedgingrelationship, gains of $65 million on the futures contracts were deferred inaccounts payable at December 31, 2006. These gains were recognized inmarketing and other income during the first quarter of 2007.

 

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.

 

2006 vs 2005—Net marketingrevenue increased net income by $336 million

 

Marketing had record resultsin 2006, with all areas achieving records. The largest contribution came fromour North American natural gas marketing group where we capitalized on ourasset-based trading strategy. Time and location spread trading generated mostof our gas gains but we were also successful in generating revenues through theoptimization of our transportation and storage capacity. Volatility within theNorth American gas markets created market opportunities for us to capitalizeon. North American gas prices started 2006 at US$10.63/mcf and closed the yearat US$6.30/mcf. Storage overhang and speculation around weather and possiblehurricanes caused significant changes in prices during the year. We also tookadvantage of opportunities late in the year to add to our storage capacity.

 

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 were consistent with prioryears, we executed more transactions and added more capacity, particularlystorage, during the year.

 

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

 

We continued our expansioninto new markets during 2006 with acquisitions in the North American NGLtrading business and a UK acquisition which positioned us in the UK andEuropean gas and power markets.

 

57

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**Composition of Net MarketingRevenue**

 
| **(Cdn$ millions)**                    | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Trading Activities (Physical and Financial) |       | 147      |       | 520      |       | 195      |       |
| Non-Trading Activities                      |       | 20       |       | 20       |       | 9        |       |
| **Total Net Marketing Revenue**             | ** ** | **167**  | ** ** | **540**  | ** ** | **204**  | ** ** |

 

Trading Activities

 

In our energy marketinggroup, we enter into contracts to purchase and sell crude oil and natural gas.We also use financial and derivative contracts, including futures, forwards,swaps and options for hedging and trading purposes. We account for allderivative contracts not designated as hedges for accounting purposes usingmark-to-market accounting and record the net gain or loss from theirrevaluation in marketing and other income. The fair value of these instrumentsis included with accounts receivable or payable. They are classified aslong-term or short-term based on their anticipated settlement date.

 

We value derivative tradingcontracts daily using:

 

·                  actively quotedmarkets such as the New York Mercantile Exchange and the InternationalPetroleum Exchange; and 

·                  other externalsources such as the Natural Gas Exchange, independent price publications andover-the-counter broker quotes. We do not value any derivative contracts usinginternal models.

 

Fair Value of DerivativeContracts

 

At December 31, 2007,the fair value of our derivative contracts totalled $6 million (2006—$360million). Below is a breakdown of this fair value by valuation method and contractmaturity.

 
| ** **                                  | ** ** | **Maturity**              | ** ** |
|---------------------------------------------|------------|---------------------------|------------|
| **(Cdn$ millions)**                    | ** ** | **< 1 year** | ** ** | **1-3 years** | ** ** | **4-5 years** | ** ** | **> 5 years** | ** ** | **Total** | ** ** |
| **Prices**                                  |       |                      |       |   |   |   |   |   |   |   |   |
| Actively Quoted Markets                     |       | (204                      | )          | 96 |   | (21 | ) | (8 | ) | (137 | ) |
| From Other External Sources                 |       | 125                       |       | 9 |   | 7 |   | 2 |   | 143 |   |
| Based on Models and Other Valuation Methods |       | —                    |       | — |   | — |   | — |   | — |   |
| **Total**                                   | ** ** | **(79**                   | **)**      | **105** | ** ** | **(14** | **)** | **(6** | **)** | **6** | ** ** |

 

Changes in Fair Value ofDerivative Contracts

 
| **(Cdn$ millions)**                            | ** ** | **Total** | ** ** |
|-----------------------------------------------------|------------|-----------|------------|
| **Fair value at December 31, 2006**            | ** ** | **360**   | ** ** |
| Change in Fair Value of Contracts                   |       | (10       | )          |
| Net Losses (Gains) on Contracts Closed              |       | (344      | )          |
| Changes in Valuation Techniques and Assumptions (1) |       | —    |       |
| **Fair value at December 31, 2007**            | ** ** | **6**     | ** ** |

 

----

*Note:*

*(1) Ourvaluation methodology has been applied consistently year-over-year.*

 

The fair values of ourderivative contracts will be realized over time as the contracts settle. Untilthen, the value of certain contracts will vary with forward commodity pricesand price differentials. The average term of our derivative contracts isapproximately 1.4 years. Those maturing beyond one year primarily relate toNorth American natural gas positions.

 

Fair Value of TradingInventories and Capacity Contracts 

 

As part of our gas marketingstrategy, we hold physicaltransportation and storage capacity contracts that allow us to takeadvantage of pricing differences between locations (i.e. west vs. east) andtime periods (i.e. summer vs. winter). These capacity contracts have marketvalue, similar to financial commodity contracts, as future margins realizeddepend on future prices and, more importantly, pricing differences. The marketvalue of these capacity contracts varies depending on the change in futureprices and pricing relationships. We routinely hedge the economic value of ourcapacity contracts using various types of derivative contracts, therebyreducing volatility in our economic results. Accounting rules can increasevolatility in our reported results since they require us to recognize thechange in fair value of derivative contracts hedging our capacity contracts,but do not allow us to recognize the change in fair value of the capacitycontracts themselves until the contracts are used. As a result, when prices orpricing relationships change, we may be required to include gains or losses inour reported results in different periods even though our underlying economicresults may be largely unchanged.

 

58

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Similar to capacitycontracts, we hold commodity inventories for trading purposes that allow us totake advantage of pricing differences between time periods (i.e. summer vswinter). We carry these inventories at fair value as measured by the one-monthforward price, less any costs to sell. We economically hedge the future valueof our trading inventories based on our expected holding period, which isgenerally more than one month. The derivative contracts used to hedge ourtrading inventories are carried at fair value, which considers the futuresettlement of the contract, whereas the commodity inventories are valued onlyone-month forward. The timing difference can create volatility in our reportedresults.

 

At the end of 2007, theunrecognized future value of the commodity inventory and capacity contracts wasa gain of $51 million(2006 — $81 million loss). The future commitment for these capacity contractshas been included in our contractual obligations, commitments and guarantees inthe MD&A.

 

**CHEMICALS**

 
| **(Cdn$ millions)**                                                         | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|----------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net Sales                                                                        |       | 414      |       | 407      |       | 398      |       |
| Sales Volumes (thousand short tons)                                              |       |     |       |     |       |     |       |
| Sodium Chlorate                                                                  |       | 478      |       | 487      |       | 493      |       |
| Chlor-alkali                                                                     |       | 465      |       | 451      |       | 450      |       |
| Operating Profit 1, 3                                                            |       | 151      |       | 124      |       | 136      |       |
| Operating Margin 2, 3                                                            |       | 36       | %          | 30       | %          | 34       | %          |
| Chemicals Contribution to Income from Continuing Operations Before  Income Taxes |       | 64       |       | 44       |       | 37       |       |
| Capacity Utilization                                                             |       | 94       | %          | 95       | %          | 96       | %          |

 

----

*Notes:*

 
| *(1)* | * * | *Total  revenues less operating costs, transportation and other.* |
|-------|----------|-------------------------------------------------------------------|
| *(2)* | * * | *Operating  profit divided by net sales.*                         |
| *(3)* | * * | *Includes  foreign exchange gains or losses on debt.*             |

 

2007 vs 2006—Higher chemicalsoperating profit increased net income by $27 million

 

Our investment in thechemicals business is held through our 61.4% interest in the Canexus LimitedPartnership. The remaining interest is publicly traded through the CanexusIncome Fund. Realized North America chlorate prices were up 5% in 2007 andsales volumes remained strong, despite unplanned maintenance of our facilitiesand pulp mill shut downs. The full effect of the price increase was partiallyeroded by the strengthening Canadian dollar which reduced US-dollar denominatedsales by $9 million. Brazilian sales remained strong with continued demand fromour main pulp mill customer Aracruz Cellulose.

 

The expansion at our plant inBrandon, Manitoba is well underway. Completion is expected in 2008 withcapacity expected to increase 12%. The Brandon plant benefits from lowelectricity rates in Manitoba where the electricity market is based onhydroelectric power and is regulated. We also benefit from the economies ofscale we achieve as this is the world’s largest sodium chlorate facility.

 

Operating profit includesforeign exchange gains of $30 million, primarily from unrealized gains onrevaluation of long-term debt.

 

2006 vs 2005—Lower chemicalsoperating profit decreased net income by $12 million

 

While North American pricesfor sodium chlorate remained strong throughout 2006, sales volumes fellslightly from 2005 as a result of pulp mill closures. Chlor-alkali volumes andprices in North America remained steady. US-dollar denominated North Americansales were reduced $12 million from the stronger Canadian dollar during 2006.Sales and operations from the Brazil plant remained solid as a result of strongdemand from Aracruz Cellulose, our primary customer, and from the merchantmarket.

 

59

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**CORPORATE EXPENSES**

 

**General andAdministrative (G&A)**

 
| **(Cdn$ millions)**                                            | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| General and Administrative Expense before  Stock-Based Compensation |       | 336      |       | 345      |       | 302      |       |
| Stock-Based Compensation (1)                                        |       | 38       |       | 210      |       | 507      |       |
| **Total General and Administrative Expense**                        | ** ** | **374**  | ** ** | **555**  | ** ** | **809**  | ** ** |

 

----

*Note:*
| *(1)* | *Includes  cash and non-cash expenses related to our tandem option plan and stock  appreciation rights plan.* |
|-------|---------------------------------------------------------------------------------------------------------------|

 

2007 vs 2006—Lower costsincreased net income by $181 million

 

G&A expense dropped 33%from 2006 with lower stock-based compensation expense. Changes in our shareprice create volatility in our net income as we account for stock-basedcompensation using the intrinsic-value method. This method uses our share priceat the end of the reporting period to determine our stockbased compensationexpense and related obligations. At the end of 2007, our stock price closedunchanged from the end of 2006. As a result, most of our 2007 stock-basedcompensation expense is related to vesting of stock-based compensation plans.Cash payments to employees for stock-based compensation programs increased 24%from 2006 to $147 million.

 

During the year, we incurredadditional employee costs as we continue to expand oil and gas operationsinternationally and marketing operations in Europe and North America. This wasoffset by lower variable compensation on oil and gas and marketing operations.

 

2006 vs 2005—Lower costsincreased net income by $254 million

 

Our 2006 G&A expensebefore stock-based compensation increased 14% primarily from additional coststo expand our marketing operations into new markets. Acquisitions during 2006allowed us to increase our North American NGL business and to expand ourEuropean trading operations. Our G&A expense also included higher variablecompensation stemming from our marketing group’s strong performance in 2006.

 

In 2006, our share priceincreased 16%, creating over $2.3 billion of shareholder value. The stock basedcompensation expense represented approximately 9% of the increase inshareholder value. Cash payments to employees for our stock-based compensationprograms were $119 million in 2006, up 61% from 2005.

 

**Interest**

 
| **(Cdn$ millions)** | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest                 |       | 341      |       | 294      |       | 275      |       |
| Less: Capitalized        |       | (173     | )          | (241     | )          | (178     | )          |
| **Net Interest Expense** | ** ** | **168**  | ** ** | **53**   | ** ** | **97**   | ** ** |
|                     |       |     |       |     |       |     |       |
| Effective Rate           |       | 6.2      | %          | 6.3      | %          | 6.4      | %          |

 

2007 vs 2006—Higher netinterest expense decreased net income by $115 million

 

Financing costs increased $47million from 2006. Additional borrowings to finance our 2007 capital program increasedinterest costs by approximately $69 million. This was partially offset by thestronger Canadian dollar which reduced our US-dollar denominated interest by$22 million.

 

Interest capitalized on ourmajor development projects was lower by $68 million from 2006. We stoppedcapitalizing interest on the Syncrude Stage 3 expansion and Buzzard in 2007 asthese projects were brought on stream. We expect to continue capitalizinginterest on Long Lake and Ettrick until their planned completion in 2008. Afterthat, we expect net interest expense to increase.

 

 2006 vs 2005—Lower net interest expenseincreased net income by $44 million

 

Our 2006 financing costsincreased $19 million from 2005. Additional borrowings to finance our 2006capital program increased financing costs by approximately $28 million. Thiswas partially offset by the stronger Canadian dollar which decreased ourUS-dollar denominated interest by $16 million. The Canexus debt, consolidatedwith 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 Buzzard, Long Lake and Syncrude’s Stage 3expansion prior to its start-up.

 

60

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**Income Taxes**

 
| **(Cdn$ millions)**                                     | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Current                                                      |       | 434      |       | 368      |       | 339      |       |
| Future                                                       |       | 358      |       | 315      |       | (234     | )          |
| **Total Provision for Income Taxes**                         | ** ** | **792**  | ** ** | **683**  | ** ** | **105**  | ** ** |
|                                                         |       |     |       |     |       |     |       |
| Disclosed as:                                                |       |     |       |     |       |     |       |
| Provision for Income Taxes—Continuing Operations        |       | 792      |       | 683      |       | 234      |       |
| Provision for Income Taxes—Discontinued  Operations (1) |       | —   |       | —   |       | (129     | )          |
| **Total Provision for Income Taxes**                         | ** ** | **792**  | ** ** | **683**  | ** ** | **105**  | ** ** |
|                                                         |       |     |       |     |       |     |       |
| Effective Rate                                               |       | 42       | %          | 53       | %          | 8        | %          |

 

----

*Note:*
| *(1)* | *See Note  14 to our Consolidated Financial Statements.* |
|-------|----------------------------------------------------------|

 

2007 vs 2006—Effective taxrate decreases from 53% to 42%

 

Our 2007 effective tax ratewas lower than 2006, as we recorded additional tax expense in 2006 due to a UKtax rate increase. Excluding the impact of this rate increase, our effectivetax rate in 2006 would have been 33%. The 2007 increase is due to a higherproportion of earnings from the UK where the corporate income tax rate on oiland gas activities is 50%. Current income taxes include cash taxes in Yemen,the UK, Colombia and the US.

 

2006 vs 2005—Effective taxrate increases from 8% to 53%

 

Effective January 1,2006, the UK government increased the supplementary tax rate on our North Seaoil and gas activities from 10% to 20%, increasing the combined rate to 50%.This increased our future income tax liabilities, resulting in a charge of $277million during the first quarter of 2006. Federal and certain provincialgovernments in Canada also reduced corporate income tax rates in 2006, whichlowered our future income tax liabilities by $32 million. Our effective taxrate excluding the impact of these tax rate changes was 33%. Our current incometax provision included cash taxes in Yemen, the US, Colombia and Canada.

 

**Other**

 
| **(Cdn$ millions)**                                                       | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Decrease in Fair Value of Crude Oil Put  Options                               |       | (43      | )          | (11      | )          | (196     | )          |
| Block 51 Settlement                                                            |       | —   |       | (151     | )          | —   |       |
| Business Interruption Insurance Proceeds                                       |       | —   |       | 154      |       | 2        |       |
| Gain on Dilution of Interest in Chemicals  Business                            |       | —   |       | —   |       | 193      |       |
| Gain on Disposition of Oil and Gas Assets  included as Discontinued Operations |       | —   |       | —   |       | 225      |       |

 

During 2007, we purchased putoptions on 36 million barrels of our 2008 crude oil production. These optionsestablish a Dated Brent floor price of US$50/bbl on these volumes, are settledannually and provide downside price protection without limiting our upside tohigher prices. Accounting rules require that these options be recorded atfair value throughout their term. As a result, changes in forward crude oilprices create gains or losses on these options at each period end. The putoptions were purchased for $24 million; however, strong crude oil pricesreduced the fair value of these options to nil, and we recorded a loss of $24million during the year.

 

During 2006, we purchased putoptions on approximately 105,000 bbls/d of our 2007 crude oil production for$26 million. These options established a WTI floor price of US$50/bbl on thesevolumes. During 2006, an increase in the forward WTI prices lowered the fairvalue of the options and we recognized a loss of $7 million for the year ended December 31,2006. Strengthening WTI in 2007 reduced the market value of the options to nil,creating a loss of $19 million in 2007.

 

Following our North Seaacquisition in late 2004, we purchased put options on 60,000 bbls/d of oil productionfor 2005 and 2006. These options created an average floor price for thisproduction of US$43.17/bbl in 2005 and US$38.17/bbl in 2006. During 2005, asignificant increase in forward crude prices reduced the value of these optionsby $196 million. Strong WTI prices in 2006 reduced the market value of theseremaining options to nil, causing us to expense $4 million in 2006.

 

61

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In 2006, 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 settled the arbitration byagreeing to pay Occidental US$135 million ($151 million) as monetary damages. Thisamount was paid in the first quarter of 2007.

 

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

 

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, British Columbiaand Saskatchewan was $225 million.

 

**OUTLOOK FOR 2008**

 

In 2008, we plan to invest$2.4 billion in capital activities as follows:

 

·                  29% in development projects to bring Long LakePhase 1 and Ettrick in the North Sea on stream in 2008, and progress Longhornin the Gulf of Mexico and CBM at Fort Assiniboine in Alberta;

·                  17% on early-stage development projectsexpected to contribute production and cash flow growth beyond 2008. Theseinclude additional phases of oil sands in the Athabasca region, Usan offshoreNigeria, and our Knotty Head and Golden Eagle discoveries in the Gulf of Mexicoand North Sea, respectively;

·                  25% on exploration primarily in our North Seaand Gulf of Mexico growth areas; and

·                  29% to exploit potential in our existingproducing assets and in other corporate assets.

 

Details of our 2008 capitalprogram are included in the Capital Investment section of the MD&A.

 

**DailyProduction**

 

In 2008 we expect additionalproduction growth over 2007 and expect production to range between 220,000 and240,000 boe/d (260,000 and 280,000 boe/d before royalties). In 2008, we expectto see the impact of a full year of Buzzard production and first oil fromEttrick in mid 2008. We are steaming the reservoir at Long Lake and expectbitumen production to ramp up in the spring, prior to upgrader start up mid2008.

 

**2008Estimated Production**

 
| ** **          | ** ** | **2008 Estimated Production** | ** ** | **2007 Production** | ** ** |
|---------------------|------------|-----------------------------------------|------------|--------------------------|------------|
| **(mboe/d)**        | ** ** | **Before  Royalties**                   | ** ** | **After  Royalties**     | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** |
| United States       |       | 25 – 30                            |       | 20 – 25             |       | 33 |   | 29 |   |
| United Kingdom      |       | 95 – 115                           |       | 95 – 115            |       | 84 |   | 84 |   |
| Yemen               |       | 50 – 55                            |       | 27 – 32             |       | 72 |   | 40 |   |
| Canada              |       | 45 – 50                            |       | 40 – 45             |       | 37 |   | 30 |   |
| Syncrude            |       | 20 – 25                            |       | 17 – 22             |       | 22 |   | 19 |   |
| Other International |       | 6 – 7                              |       | 5 – 6               |       | 6 |   | 5 |   |
| **Total**           |       | 260 – 280                          |       | 220 – 240           | ** ** | **254** | ** ** | **207** | ** ** |

 

Cash Flow and Sensitivities

 

We expect to generateapproximately $2.9 billion in cash flow from operating activities in 2008, aftercash taxes of approximately $1 billion, assuming the following:

 
| WTI (US$/bbl)                                               |   | 70.00 |   |
|-------------------------------------------------------------|--------|-------|--------|
| NYMEX Natural Gas (US$/mmbtu)                               |   | 6.75  |   |
| Oil & Gas and Syncrude Operating  Costs (Cdn$/boe) |   | 10.00 |   |
| US to Canadian Dollar Exchange Rate                         |   | 0.97  |   |

 

Changes in commodity pricesand exchange rates impact our annual cash flow from operating activities, aftercash taxes, as follows:

 
| **(Cdn$ millions)**                   | ** ** | ** ** | ** ** |
|--------------------------------------------|------------|------------|------------|
| WTI—US$1/bbl change above US$50       |       | 39         |       |
| WTI—US$1/bbl change below US$50       |       | 22         |       |
| NYMEX Natural Gas—US $0.50/mcf change |       | 24         |       |
| Exchange Rate—$0.01 US/Cdn change     |       | 28         |       |

 

62

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**LIQUIDITY AND CAPITAL RESOURCES**

 

**CapitalStructure**

 
| **(Cdn$ millions)**          | ** ** | **2007**  | ** ** | **2006**  | ** ** |
|-----------------------------------|------------|-----------|------------|-----------|------------|
| **Net Debt (1)**                  |       |      |       |      |       |
| Bank Debt                         |       | 413       |       | 1,410     |       |
| Public Senior Notes               |       | 3,758     |       | 2,885     |       |
| Total Senior Debt                 |       | 4,171     |       | 4,295     |       |
| Subordinated Debt                 |       | 439       |       | 536       |       |
| Total Debt                        |       | 4,610     |       | 4,831     |       |
| Less: Cash and Cash Equivalents   |       | (206      | )          | (101      | )          |
| **Total Net Debt**                | ** ** | **4,404** | ** ** | **4,730** | ** ** |
|                              |       |      |       |      |       |
| **Shareholders’ equity (2)** | ** ** | **5,610** | ** ** | **4,636** | ** ** |

 

----

*Notes:*
| *(1)* | *Includes  all of our debt and is calculated as long-term debt and short-term borrowings  less cash and cash equivalents.*                                                                                                                                                                                                                           |
|-------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *At  January 31, 2008, there were 528,502,991 common shares and US$460  million of unsecured subordinated securities outstanding. After November 8,  2008, we have the option to redeem these subordinated securities by issuing  common shares. The number of shares issuable depends on the common share  price on the redemption date.* |

 

**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 and capital investment. Weended the year with net debt of $4.4 billion, $326 million lower than 2006. Thedecrease was primarily caused by the strengthening Canadian dollar relative tothe US-dollar which reduced our US-dollar denominated debt by over $700million. The impact of foreign exchange was partially offset as our capitalinvestment exceeded cash flow from operating activities by over $500 million. Thisshortfall was financed with long-term debt.

 

In May 2007, we issuedUS$250 million of 10-year senior notes and US$1,250 million of 30-year seniornotes and used the proceeds to repay amounts outstanding under term creditfacilities. Issuing this debt extended the average term-to-maturity of our debtto 21 years. Approximately 7% of our long-term debt is repayable within thenext three years.

 

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

 
| **(Cdn$ millions)**                                 | ** ** | **2007** | ** ** | **2006**  | ** ** |
|----------------------------------------------------------|------------|----------|------------|-----------|------------|
| Capital Investment                                       |       | 3,401    |       | 3,408     |       |
| Cash Flow from Operating Activities                      |       | (2,830   | )          | (2,374    | )          |
| Excess of Capital Investment over Cash Flow              |       | 571      |       | 1,034     |       |
| Dividends on Common Shares                               |       | 53       |       | 52        |       |
| Issue of Common Shares                                   |       | (56      | )          | (48       | )          |
| Foreign Exchange Translation of US-dollar  Debt and Cash |       | (745     | )          | 31        |       |
| Net Proceeds on Disposition of Assets                    |       | (4       | )          | (27       | )          |
| Other                                                    |       | (145     | )          | 49        |       |
| **Increase (Decrease) in Net Debt**                      | ** ** | **(326** | **)**      | **1,091** | ** ** |

 

The change in our net debthas improved our 2007 leverage as reflected in the following ratios:

 
| **(times)**                                      | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net Debt to Cash Flow from Operating  Activities |       | 1.6      |       | 2.0      |       | 1.7      |       |
| Interest Coverage (1)                            |       | 12.1     |       | 9.6      |       | 9.7      |       |

 

----

*Note:*

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

 

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Our business strategy isfocused on value-based growth through full-cycle exploration and development ofconventional and unconventional resources, supplemented by strategicacquisitions when appropriate. Since most of our projects have long-cycletimes, requiring significant amounts of capital prior to cash flow generation,we have successfully leveraged our balance sheet many times in the past,including 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; and

·                  construct the first phase of Long Lake.

 

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 investing in major development projects at Buzzardand Long Lake. With new cash flow from Buzzard in 2007, we reduced our ratio ofnet debt to cash flow from operating activities.

 

**Change inWorking Capital**

 
| ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** | **Increase/**  | ** ** |
|------------------------------------------|------------|------------|------------|------------|------------|----------------|------------|
| **(Cdn$ millions)**                 | ** ** | **2007**   | ** ** | **2006**   | ** ** | **(Decrease)** | ** ** |
| Cash and Cash Equivalents                |       | 206        |       | 101        |       | 105            |       |
| Restricted Cash and Margin Deposits      |       | 203        |       | 197        |       | 6              |       |
| Accounts Receivable                      |       | 3,502      |       | 2,951      |       | 551            |       |
| Inventories and Supplies                 |       | 659        |       | 786        |       | (127           | )          |
| Future Income Tax Assets                 |       | 18         |       | 479        |       | (461           | )          |
| Accounts Payable and Accrued Liabilities |       | (4,180     | )          | (3,879     | )          | (301           | )          |
| Other                                    |       | 4          |       | (1         | )          | 5              |       |
| **Total**                                | ** ** | **412**    | ** ** | **634**    | ** ** | **(222**       | **)**      |

 

Increased production ratesand stronger commodity prices contributed to higher accounts receivable. Ourmarketing group reduced the amount of natural gas in storage at the end of2007; however, this was partially offset by slightly higher crude oilinventories. New accounting rules require that the commodity inventoryheld by our energy marketing group be carried at fair value. These new rules alsorequire us to reclassify $51 million of critical spare parts for our oil andgas activities from inventories and supplies to property, plant and equipment.The current portion of future income tax assets decreased from 2006 as strongBuzzard production contributed to utilizing available tax losses in the UK.Stronger crude oil prices also increased accrued liabilities for our marketingoperation. This increase was partially offset by lower stock-based compensationaccruals.

 

The strengthening Canadiandollar relative to the US dollar impacted our US-dollar denominated workingcapital by reducing accounts receivable, inventories and accounts payable byapproximately $275 million, $75 million and $250 million, respectively.

 

**Liquidity**

 

We generally rely onoperating cash flows to fund capital requirements and provide liquidity. Giventhe long cycle-time of some of our development projects and volatile commodityprices, it is not unusual in any year for capital expenditures to exceed ourcash flow. In addition, we require liquidity for our energy marketing business.Accordingly, we maintain significant committed credit facilities. At December 31,2007, we had unsecured term credit facilities of US$3 billion that areavailable until 2012. At year end, $211 million was drawn on these facilitiesand $283 million of these facilities was utilized to support letters of credit.We also had $665 million of uncommitted, unsecured credit facilities, of which$196 million was supporting letters of credit at December 31, 2007.

 

From time to time, we accesscapital markets to meet our financing needs. We also use various financialinstruments to minimize exposure to fluctuating commodity prices and foreignexchange. For example, we routinely purchase WTI put options to mitigate cashflow volatility. Overall, we manage our capital structure to maintainflexibility so we can fund our capital programs throughout highs and lows ofthe price cycles inherent in the oil and gas business.

 

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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)**            | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003**  | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|-----------|------------|
| Cash Flow from Operating Activities |       | 2,830    |       | 2,374    |       | 2,143    |       | 1,606    |       | 1,405     |       |
| Cash Flow from Investing Activities |       | (3,281   | )          | (3,388   | )          | (1,864   | )          | (4,013   | )          | (1,219    | )          |
| Surplus (Deficiency)                |       | (451     | )          | (1,014   | )          | 279      |       | (2,407   | )          | 186       |       |
| Cash Flow from Financing Activities |       | 677      |       | 1,081    |       | (274     | )          | 1,426    |       | 1,006     |       |
| ** **                          | ** ** | **226**  | ** ** | **67**   | ** ** | **5**    | ** ** | **(981** | **)**      | **1,192** |       |

 

In late 2003, we pre-fundeddebt repayments by raising more than $1 billion in senior and subordinateddebt. We used these funds in 2004 to repay higher-cost debt, and coupled withacquisition credit facilities, acquired the North Sea assets. In 2005, we usedcash flow and proceeds from asset dispositions to fund our capital program andrepay debt. In 2006, we borrowed approximately $1 billion under our committedterm credit facilities and used cash flow from operating activities to fund ourcapital program. In 2007, we issued US$1.5 billion in senior debt to repayoutstanding term credit facilities and $150 million in medium term notes, andto partially fund our 2007 capital 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 collateral be posted if adversecredit-related events, such as reduced credit ratings, occur. In evaluating ourliquidity requirements, we consider the current requirements of our marketingbusiness as well as additional collateral or other payments that could berequired if our credit ratings were reduced.

** **

**FutureLiquidity**

 

Our future liquidity dependsprimarily on cash flow generated from our operations, existing committed creditfacilities and our ability to access debt and equity markets. Assuming WTI ofUS$70/bbl, we expect our 2008 cash flow to exceed capital and dividendrequirements by approximately $400 million. In July 2008, we will repay$125 million of medium term notes that become due with funds from our termcredit facilities.

 

In 2008, we expect cash flowof approximately $2.9 billion (before remediation and geological andgeophysical expenditures) assuming:

 
| WTI (US$/bbl)                       | 70.00 |   |
|-------------------------------------|-------|--------|
| NYMEX Natural Gas (US$/mmbtu)       | 6.75  |   |
| US to Canadian Dollar Exchange Rate | 0.97  |   |

 

 

Changes in commodity pricesand exchange rates will impact our cash flow and borrowing requirements. Referto the Outlook for 2008 section on page 62 to see how changes in the aboveassumptions can impact our cash flow.

 

A number of our developmentprojects require capital to bring them on stream. In 2008, we expect to invest$400 million to bring Long Lake Phase 1 on stream, $165 million to progress ourUsan development offshore Nigeria, and $200 million to bring Ettrick in theNorth Sea on stream. While these development projects lack exploration risk,they are subject to other risks including higher than anticipated capital costsor delayed start-up. We maintain undrawn committed credit facilities to managethis risk. We also have a US$2.5 billion shelf prospectus available in the USand Canada.

 

At December 31, 2007,the average term-to-maturity of our long-term debt was 21 years.

 
| **(Cdn$ millions)**          | ** ** | **2008** | ** ** | **2009**   | ** ** | **2010** | ** ** | **2011**   | ** ** | **2012** | ** ** |
|-----------------------------------|------------|----------|------------|------------|------------|----------|------------|------------|------------|----------|------------|
| Term Credit Facilities 1          |       | —   |       | —     |       | —   |       | —     |       | 211      |       |
| Canexus LP Term Credit Facilities |       | —   |       | —     |       | 202      |       | —     |       | —   |       |
| Medium Term Notes                 |       | 125      |       | —     |       | —   |       | —     |       | —   |       |
| **Total**                         | ** ** | **125**  | ** ** | **—** | ** ** | **202**  | ** ** | **—** | ** ** | **211**  | ** ** |

 

----

*Note:*

| *(1)* | *$3.0  billion available until 2012.* |
|-------|---------------------------------------|

 

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With our expected cash flowstreams, commodity price and hedging strategies, current liquidity levels, andaccess to debt and equity markets, we expect to be able to fund all plannedcapital, dividends and debt repayments, and meet other obligations that mayarise from our oil and gas, Syncrude, chemicals and energy marketingoperations.

 

In the last four years, wedeclared common share dividends of $0.10 per share each year. 

 

**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                  |       | 4,688        |       | 125 |   | 202 |   | 211 |   | 4,150 |   |
| Interest on Long-Term Debt (1)                 |       | 6,395        |       | 268 |   | 527 |   | 527 |   | 5,073 |   |
| Operating Leases (2)                           |       | 610          |       | 76 |   | 201 |   | 176 |   | 157 |   |
| Capital Leases                                 |       | 117          |       | 5 |   | 10 |   | 10 |   | 92 |   |
| Energy Commodity Contract Liabilities          |       | 576          |       | 413 |   | 135 |   | 25 |   | 3 |   |
| Transportation and Storage Commitments (2)     |       | 922          |       | 368 |   | 271 |   | 151 |   | 132 |   |
| Work Commitments and Purchase  Obligations (3) |       | 2,137        |       | 966 |   | 575 |   | 522 |   | 74 |   |
| Asset Retirement Obligations                   |       | 2,165        |       | 40 |   | 58 |   | 39 |   | 2,028 |   |
| **Total**                                      |       | 17,610       |       | 2,261 |   | 1,979 |   | 1,661 |   | 11,709 |   |

 

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*Notes:*
| *(1)* | *Excludes  interest on variable rate debt.*                                                                                             |
|-------|-----------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Payments  for operating leases and transportation and storage commitments are deducted  from our cash flow from operating activities.* |
| *(3)* | *Some of  these payments relate to work commitments that we can cancel 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-term and long-term debt amounts areincluded on our December 31, 2007 Consolidated Balance Sheet.

·                  Operating leases include the minimum leasepayment obligations associated with leases for office space, rail cars,vehicles and processing agreements that allows our production to flow throughthird-party processing facilities.

·                  Capital leases include pipeline commitmentsprimarily related to future production at Long Lake.

·                  Energy commodity contract liabilities includethe purchase and sale of physical quantities of oil and natural gas, andfinancial derivatives used to manage our exposure to commodity prices. Forcontracts where the price is based on an index, the amount is based on forwardmarket prices at December 31, 2007. For certain contracts, we may netsettle. These contracts are included in our Consolidated Balance Sheet at fairvalue.

·                  Work commitments include non-discretionarycapital spending for drilling, seismic, facilities construction and otherdevelopment commitments in our international operations, and includes Long Lake($192 million) and Ettrick in the North Sea ($139 million). Since the timing ofcertain payments is difficult to determine with certainty, the table wasprepared using our best estimates. The remainder of our 2008 capital investmentis discretionary.

·                  We have included $821 million in workcommitments for drilling rigs we have contracted in the North Sea and Gulf ofMexico, over the next five years.

·                  We have $2,165 million of undiscounted assetretirement obligations after inflation. As of December 31, 2007, thediscounted value ($832 million) of these estimated obligations was provided forin our Consolidated Financial Statements (including $40 million of currentliabilities). Since timing of any payments is difficult to determine withcertainty, the table was prepared using our best estimates.

·                  We have unfunded obligations under our definedbenefit pension plans of $130 million (Nexen—$72 million; Canexus—$7 million;Syncrude—$51 million). Our obligations for Nexen and Canexus include $63million that is unfunded as a result of statutory limitations. These obligationsare backed by irrevocable letters of credit.

 

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·                  We have excluded obligations on our tandemoption and stock appreciation rights programs as theamount and timing of cash payments are not determinable.

·                  We have excluded our normal purchasearrangements as they are discretionary and are reflected in our expected cashflow from operating activities and capital expenditures for 2008.

·                  We have excluded our future income taxliabilities as the amount and timing of any cash payment for income taxes isbased on taxable income for each fiscal year in the various jurisdictions wherewe operate. We have also excluded future income tax liabilities as they relateto uncertain tax positions, as we cannot provide a reasonable estimate as toif, or when future payments would be required.

 

From time to time, we enter intocontracts 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 existing indemnifications would not have amaterial adverse effect on our liquidity, financial condition or results ofoperations.

 

**CreditRatings**

 

Currently, our senior debt israted Baa2 by Moody’s Investor Service, Inc. (Moody’s), BBB by DominionBond Rating Service (DBRS) and BBB- by Standard & Poor’s (S&P). Inaddition, Moody’s and DBRS currently rate our outlook as stable while S&Phas a positive outlook. Our strong financial results, ample liquidity andfinancial flexibility continue to support our credit ratings.

 

**FinancialAssurance Provisions in Commercial Contracts**

 

The commercial agreements ourenergy marketing group enters into often include financial assurance provisionsthat allow Nexen and our counterparties to effectively manage credit risk. Theagreements normally require collateral to be posted if an adversecredit-related event, such as a drop in credit ratings, occurs. Based oncontracts in place and commodity prices at December 31, 2007, we could berequired to post collateral of up to $1.2 billion if we were downgraded tonon-investment grade. These obligations are reflected on our balance sheet. Theposting of collateral merely accelerates the payment of such amounts. Just aswe may be required to post collateral if we were downgraded below investmentgrade, we have similar provisions in many of our contracts that allow us todemand certain counterparties post collateral for amounts they owe us if theyare 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 Contractual Obligations,Commitments and Guarantees on page 66 and in Note 15 to the ConsolidatedFinancial Statements, which is incorporated herein by reference.

 

At December 31, 2007, wehad outstanding letters of credit supported by $283 million of unsecured termcredit facilities and $196 million of uncommitted unsecured credit facilities.

 

**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, which is incorporated here by reference for a discussion of ourcontingencies.

 

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**CRITICAL ACCOUNTING ESTIMATES**

 

We make estimates andassumptions that affect 1) the reported amounts of our assets and liabilities;2) the disclosure of contingent assets and liabilities at the date of theConsolidated Financial Statements; and 3) 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 thedetermination of proved reserves on an ongoing basis. Changes in facts andcircumstances may result in revised estimates and actual results may differfrom 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 quality differentials;

·                  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 CashFlows and 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 either evaluated or auditedannually by independent qualified reserves consultants. Given that reserveestimates are based on numerous assumptions, interpretations and judgements,differences frequently arise between the estimates prepared by differentqualified estimators. When the initial estimate on the portfolio of propertiesdiffers by greater than 10%, we work with the independent reserves consultantto reconcile the difference to within 10%. Estimates pertaining to individualproperties within the portfolio often differ by significantly more than 10%,either positively or negatively. We do not attempt to resolve each property towithin 10% as it would be time and cost prohibitive given the number of wellsin which we have an interest.

 

The nature and extent of theindependent evaluations and audits, and the results thereof, are provided inthe section on Reserves, Production and Related Information on page 16.

 

The board of directors has aReserves Review Committee (Reserves Committee) to assist the board and theAudit and Conduct Review Committee to oversee the annual review of our oil andgas and Syncrude reserves and disclosures of reserves data and related oil andgas and mining activities. The Reserves Committee is comprised of three or moredirectors, the majority of whom are independent and familiar with estimatingoil and gas reserves. The Reserves Committee meets with management periodicallyto review the reserves process, the portfolio of properties selected bymanagement for independent assessment, results and related disclosures. TheReserves Committee appoints and meets with each of the internal qualifiedreserves evaluator and independent reserves consultants, independent ofmanagement, to review the scope of their work, whether they have had access tosufficient information, the nature and satisfactory resolution of any materialdifferences of opinion, and in the case of the independent reserves consultants,their independence.

 

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The Reserves Committee hasreviewed our 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, 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 2007, $126million of our total $360 million spent on exploration drilling was expensed.If none of our exploration drilling had been successful, our net income wouldhave decreased by $150 million, net of income tax.

·                  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 2007, oil and gas depletion of $1,213 million was recorded in depletion,depreciation, amortization and impairment expense. If our reserves estimateschanged by 10%, our depletion, depreciation, amortization and impairmentexpense would have changed by approximately $121 million, assuming no otherchanges to our reserves profiles.

·                  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.

 

**Impairments**

 

Property, Plant and Equipment

 

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 to determine if they are impaired. If theundiscounted future cash flow for a property is less than the carrying amountof that property, we calculate its fair value using a discounted cash flowapproach. The property is then written down to its fair value.

 

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$25.24/bbl to US$99.62/bbl andUS$4.20/mmbtu to US$15.38/mmbtu, respectively. Our forecasts for oil and gasrevenues are based on prices derived from a consensus of future price forecastsamongst industry analysts and our own assessments. Our estimates of future cashflows are generally based on our assumptions of long-term prices and operatingand development costs. Given the significant assumptions required and thepossibility that actual conditions will differ, we consider the assessment ofimpairment to be a critical accounting estimate. A change in these estimateswould impact all businesses with the exception of chemicals and energy marketing.

 

It is difficult to determineand assess how a decrease in proved reserves impacts our impairment tests. Therelationship between the reserves estimate and the estimated undiscounted cashflows, and the nature of the property-by- property impairment test is complex.As a result, we are unable to provide a reasonable sensitivity analysis of theimpact that a reserves estimate decrease would have on our assessment ofimpairment.

 

Goodwill

 

We test goodwill forimpairment annually based on estimated future cash flows of the reporting unitto which the goodwill is attributable. In addition, we test goodwill forimpairment whenever an event or circumstance occurs that may reduce the fairvalue of a reporting unit below its carrying amount. If our goodwill isimpaired, we write it down to its implied fair value, based on the fair valueof the assets and liabilities of the underlying reporting unit. The process ofassessing goodwill for impairment necessarily requires us to determine the fairvalues of our assets and liabilities, and involves making various assumptionsand judgements.

 

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**Asset Retirement 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. In estimating our future asset retirementobligations, we must make estimates and judgments on activities that will occurmany years into the future. Also, the ultimate financial impact ofenvironmental laws and regulations is not always clearly known and cannot be reasonablyestimated as standards evolve in the countries where we operate.

 

We record asset retirementobligations in our Consolidated Financial Statements by discounting the futurevalue 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 judgements are made on ultimatesettlement amounts, inflation factors, credit-adjusted discount rates, timingof settlement and expected changes in legal, regulatory, environmental andpolitical environments. The asset retirement obligations we record increase thecarrying cost of our property, plant and equipment and accretes with thepassage of time. A change in any one of our assumptions could impact our assetretirement obligations, the carrying value of our property, plant and equipmentand our net income.

 

It is difficult to determinewhat impact a change in any of our assumptions would have on our financialresults. As a result, we are unable to provide a reasonable sensitivityanalysis on changes in our assumptions.

 

**Business Combination—PurchasePrice Allocation**

 

We account for businessacquisitions using the purchase method of accounting. Under this method, we arerequired to record on our Consolidated Balance Sheet the estimated fair valuesof the acquired company’s assets and liabilities at the acquisition date. Theexcess of the purchase price over the fair values of the tangible andintangible net assets acquired is recorded as goodwill.

 

We make various assumptionsand judgements in determining the fair values of the acquired company’s assetsand liabilities, the most significant of which are in estimating the fair valueof the oil and gas properties. To determine the fair value of these properties,we estimate (a) oil and gas reserves using our reserve standards, (b) additionalreserves potential and (c) future prices of oil and gas.

 

Our reserve estimates arebased on work performed by our engineers and outside consultants. Judgementsassociated with these estimated reserves are described earlier in our criticalaccounting estimates discussion entitled “Oil and Gas Accounting—ReservesDetermination”. Our estimates of future prices are based on prices derived froma consensus of future price forecasts among industry analysts and our ownassumptions. The judgments associated with these estimates are describedearlier in our critical accounting estimates discussion entitled “Impairments—Property,Plant and Equipment”.

 

We apply our estimated futureprices to the estimated reserves quantities acquired, and we estimate futureoperating and development costs to arrive at estimated future net revenues forthe properties acquired. For proved properties, we discount the future netrevenues using after-tax discount rates. The same principles are applied inarriving at the fair value of unproved properties acquired. These unprovedproperties 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 factoris applied to the discounted future net revenues of the probable and possiblereserves in each particular instance.

 

**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 amounts forfinancial statement and tax purposes. We carry on business in several countriesand as a result, we are subject to income taxes in numerous jurisdictions. Thedetermination of our income tax provision is inherently complex and we arerequired to interpret continually changing regulations and make certainjudgments. While income tax filings are subject to audits and reassessments, webelieve we have adequately provided for all income tax obligations. However,changes in facts and circumstances as a result of income tax audits,reassessments, jurisprudence and any new legislation may result in an increaseor decrease in our provision for income taxes.

 

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**NEW ACCOUNTING PRONOUNCEMENTS**

 

**Canadian Pronouncements**

 

In December 2006, theCanadian Accounting Standards Board (AcSB) issued two new Sections relating tofinancial instruments: Section 3862, *FinancialInstruments—Disclosures*, and Section 3863, *Financial Instruments—Presentation*. Both sectionsare effective for annual and interim periods beginning on or after October 1,2007 and require increased disclosure of financial instruments.

 

In December 2006, theAcSB issued Section 1535, *Capital Disclosures*,requiring disclosure of information about an entity’s capital and theobjectives, policies, and processes for managing capital. The standard iseffective for annual periods beginning on or after October 1, 2007 andwill require additional disclosure.

 

In February 2008, theAcSB issued Section 3064, *Goodwill andIntangible Assets*and amended Section 1000, *Financial Statement Concepts*clarifyingthe criteria for the recognition of assets, intangible assets and internallydeveloped intangible assets. Items that no longer meet the definition of an assetare no longer recognized as assets. The standard is effective for fiscal yearsbeginning on or after October 1, 2008 and early adoption is permitted. Weare currently evaluating the impact these sections will have on our results ofoperations or financial position.

 

In January 2006, theAcSB adopted a strategic plan for the direction of accounting standards inCanada. Accounting standards for public companies in Canada are expected to convergewith the International Financial Reporting Standards by 2011. The timing forconvergence has not been confirmed by the AcSB. We continue to monitor andassess the impact of these convergence efforts.

 

**USPronouncements**

 

In September 2006, theFinancial Accounting Standards Board (FASB) issued Statement 157, *Fair Value Measurements*. Statement 157defines fair value, establishes a framework for measuring fair value under USgenerally accepted accounting principles and expands disclosures about fairvalue measurements. For fiscal years beginning after November 15, 2007, companiesmust implement the standard for financial assets and liabilities, as well asfor any other assets and liabilities carried at fair value on a recurring basisin financial statements. However, a one year deferral for the implementation ofStatement 157 is provided for other non financial assets and liabilities. We donot expect the adoption of this statement to materially impact our results ofoperations or financial position.

 

Effective December 31,2006, we adopted the recognition and disclosure provisions of FASB Statement158, *Employers’ Accounting for DefinedBenefit Pension And Other Postretirement Plans*. This statement alsorequires we measure the funded status of a plan as of the balance sheet date.The measurement provisions of the statement are effective for fiscal yearsending after December 15, 2008. We do not expect the adoption of thechange in measurement date in 2008 to materially impact our results ofoperations or financial position.

 

In February 2007, FASBissued Statement 159, *The Fair Value Optionfor Financial Assets and Financial Liabilities*. The statement allowsfor the elective measurement of eligible financial instruments and certainother items at fair value in order to mitigate volatility in reported earningswithout having to apply complex and detailed hedge accounting rules. Thisstatement is effective for fiscal years beginning after November 15, 2007.We do not expect the adoption of this statement to materially impact ourresults of operations or financial position.

 

In December 2007, FASBissued Statement 141(revised), *BusinessCombinations*. Statement 141(revised) establishes principles andrequirements of the acquisition method for business combinations and relateddisclosures. This statement is effective for fiscal years beginning on or afterDecember 15, 2008. We do not expect the adoption of this statement tomaterially impact our results of operations or financial position.

 

In December 2007, FASBissued Statement 160, *Noncontrolling Interestsin Consolidated Financial Statements*, an amendment of ARB. No 51.This statement clarifies that a noncontrolling interest in a subsidiary is anownership interest in the consolidated entity that should be reported as equityin the consolidated financial statements. This statement is effective forfiscal years beginning on or after December 15, 2008. We do not expect theadoption of this statement to materially impact our results of operations orfinancial position.

 

71

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**Item 7a. Quantitativeand Qualitative 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 sensitive to numerous worldwidefactors, many of which arebeyond our control, and are generally sold at contract or posted prices.Changes in world crude oil and natural gas prices may significantly affect ourresults of operations and cash generated from operating activities. Consequently,such prices also may affect the value of our oil and gas properties and ourlevel of spending for exploration and development.

 

Our crude oil prices arebased on various reference prices, primarily WTI and Brent crude oil referenceprices and other prices which generally track the movement in WTI and Brent. Adjustmentsare made to the reference prices to reflect quality differentials andtransportation. WTI, Brent and other international reference prices areaffected by numerous and complex worldwide factors such as supply and demandfundamentals, economic outlooks, production quotas set by the Organization ofPetroleum Exporting Countries and political events. Quality differentials areaffected by local 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 supply and demand fundamentals, and to a lesser extentlocal market conditions.

 

In 2007, WTI averagedUS$72.31/bbl, reaching a high of US$99.29/bbl and a low of US$49.90/bbl. DatedBrent, on which approximately 80% of our production is priced, averaged $72.52/bbl,reaching a high of US$96.02/bbl and a low of US$50.68/bbl. NYMEX natural gasprices averaged US$7.12/ mmbtu in 2007, reaching a high of US$8.71/mmbtu and alow of US$5.19/mmbtu. Our sensitivities to commodity prices and the expectedimpact on our 2008 cash flow from operating activities and net income are as follows:

 
| **(Cdn $ millions)**                 | ** ** | **Cash  Flow** | ** ** | **Net  Income** | ** ** |
|-------------------------------------------|------------|----------------|------------|-----------------|------------|
| WTI—US$1/bbl change above US$50      |       | 39             |       | 36              |       |
| WTI—US$1/bbl change below US$50      |       | 22             |       | 20              |       |
| NYMEX Natural Gas—US$0.50/mcf change |       | 24             |       | 20              |       |

 

These sensitivities are basedon our estimated 2008 oil and gas production and assume a Canadian/US dollarexchange rate of $0.97. Our estimated oil and gas production range for 2008 isbetween 260,000 and 280,000 boe/d before royalties, of which approximately 16%is gas.

 

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 2007, we purchased DatedBrent put options to manage the commodity price risk exposure on a portion ofour oil production in 2008, by establishing an annual average Dated Brent floorprice of US$50/bbl on 36 million barrels or about 100,000 bbls/d of production.

 

**Foreign Currency Risk**

 

A substantial portion of our activities are transactedin or referenced to US dollars including:

 

·                  sales of crude oil, natural gas and certain chemicalsproducts;

·                  capital spending and expenses for our oil and gas, Syncrudeand chemicals operations; and

·                  short-term and long-term borrowings.

 

The Canadian/US dollar exchange rate averaged $0.93 in2007, ranging from a low of $0.84 to a high of $1.09.

 

Our sensitivities to the US dollar and the expectedimpact of a one cent change on our 2008 cash flow from operating activities,net income, capital expenditures and long-term debt is as follows:

 
| **(Cdn$ millions)**  | ** ** | **Cash  Flow** | ** ** | **Net  Income** | ** ** | **Capital  Expenditures** | ** ** | **Long-term  Debt** | ** ** |
|---------------------------|------------|----------------|------------|-----------------|------------|---------------------------|------------|---------------------|------------|
| $0.01 Change in US to Cdn |       | 28             |       | 17              |       | 15                        |       | 44                  |       |

 

72

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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 2008. These estimates are based on a WTI price for crude oil ofUS$70/bbl, a NYMEX natural gas price of US$6.75/mmbtu, operating costs of$10/boe and a Canadian/ US dollar exchange rate of $0.97.

 

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 self-sustaining foreign operations.

 

Our chemicals operations areexposed to changes in the US-dollar exchange rate as part of their sales aredenominated in US-dollars. Canexus periodically purchases US-dollar call optionsto reduce this exposure. Under outstanding option contracts at December 31,2007, Canexus had the right to sell US$5 million monthly and purchase Canadiandollars at an exchange rate of US$0.95 to February 29, 2008.

 

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 2008 cashflow from operating activities and net income is as follows:

 
| **(Cdn$ millions)**                   | ** ** | **Cash Flow** | ** ** | **Net Income** | ** ** |
|--------------------------------------------|------------|--------------------|------------|---------------------|------------|
| **Interest Rates—1% change in rates** |       | 5                  |       | 3                   |       |

 

Our sensitivity to changes ininterest rates is based on 2008 estimated average floating rate debt of $475million and a Canadian/US dollar exchange rate of $0.97.

 

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 rate borrowingsand facilities. At December 31, 2007, fixed-rate borrowings comprised 91%(2006—73%) of our long-term debt at an effective average rate of 6.3%(2006—6.3%). During the year, we periodically borrow under our committed, unsecured,term credit facilities and at December 31, 2007, floating-rate debtcomprised 9% (2006—27%) of our long-term debt at an effective average rate of5.8% (2006—5.7%) ranging from a low of 4.2% to a high of 8.75% during 2007.

 

We had no interest rate swapsoutstanding in 2007 or 2006.

 

**TRADING**

 

**CommodityPrice Risk**

 

Our marketing group marketsand trades crude oil, natural gas, NGLs, ethanol and power through physicalpurchase and sales contracts, as well as financial commodity contracts. These activitiesexpose us to commodity price risk, as well as foreign currency risk andvolatility within these markets. Our energy marketing group actively managesthis risk by utilizing energy-related futures, forwards, swaps and options, aswell as currency swaps or forwards. We typically take advantage of location,time and quality spreads using physical and financial contracts. The marketinggroup also tries to take advantage of volatility within commodity markets andcan establish net open commodity positions to take advantage of existing marketconditions.

 

Volatility within our variousmarkets can vary and change 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 when notall 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.

 

We control the level ofmarket risk through daily monitoring of our energy-trading portfolio relativeto:

 

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

·                  nominal size of commodity positions;

·                  stop loss limits; and

·                  stress testing.

 

73

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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 primarily by using the Variance-Covariance method basedon historical commodity price volatility, correlation inputs where available andby historical simulation in other situations. Our estimate is based upon thefollowing key assumptions:

 

·      changes incommodity prices are either normally or “T” (for natural gas since May 2006)distributed;

·      price volatilityremains stable; and

·      pricecorrelation 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. 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 $3.6 and $6.1 million in 2007.

 

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

 
| **(Cdn$ millions)** | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------|------------|----------|------------|----------|------------|----------|------------|
| **Value at Risk**        |       |     |       |     |       |     |       |
| Year End                 |       | 26       |       | 26       |       | 24       |       |
| High                     |       | 38       |       | 33       |       | 28       |       |
| Low                      |       | 24       |       | 17       |       | 11       |       |
| Average                  |       | 30       |       | 23       |       | 21       |       |

 

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 are withcounterparties in the energy industry and are subject to normal industry creditrisk. We take the following measures to reduce this risk:

 

·                  we assess the financialstrength of our counterparties through a rigorous credit process;

·                  we limit the total exposureextended to individual counterparties, and may require collateral from some counterparties;

·                  we routinely monitor creditrisk exposures, including sector, geographic and corporate concentrations of credit,and report these to our Risk Management Committee and the Finance Committee ofthe board;

·                  we set credit limits based onrating agency credit ratings and internal assessments based on company and industryanalysis;

·                  we review counterparty creditlimits regularly; and

·                  we use standard agreementsthat allow for the netting 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 December 31,2007:

 

·                  over 96% of our creditexposures were investment grade; and

·                  only three counterpartiesindividually made up more than 5% of our credit exposure, one of which made upmore than 10%. All three were investment grade.

 

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**SPECIAL NOTE REGARDINGFORWARD-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*, constitute “forward-looking statements” (within themeaning of the United States *PrivateSecurities Litigation Reform Act*of 1995, Section 21E of theUnited States *Securities Exchange Act of1934,*as amended, and Section 27A of the United States *Securities Act of 1933,*as amended) or “forward-lookinginformation” (within the meaning of applicable Canadian securitieslegislation). Such statements or information (together “forward-looking statements”)are generally identifiable by the terminology used such as “anticipate”, “believe”,“intend”, “plan”, “expect”, “estimate”, “budget”, “outlook” or other similarwords and include statements relating to or associated with individual wells,regions or projects. Any statements regarding the following are forward-lookingstatements:

 

·                  future crude oil, natural gas or chemicals prices;

·                  future production levels;

·                  future cost recovery oil revenues from our Yemen operations;

·                  future capital expenditures and their allocation toexploration and development activities;

·                  future earnings;

·                  future asset dispositions;

·                  future sources of funding for our capital program;

·                  future debt levels;

·                  possible commerciality;

·                  development plans or capacity expansions;

·                  future ability to execute dispositions of assets or businesses;

·                  future cash flows and their uses;

·                  future drilling of new wells;

·                  ultimate recoverability of reserves or resources;

·                  expected finding and development costs;

·                  expected operating costs;

·                  future demand for chemicals products;

·                  estimates on a per share basis;

·                  sales;

·                  future expenditures and future allowances relating to environmentalmatters;

·                  dates by which certain areas will be developed or willcome on stream; and

·                  changes in any of the foregoing.

 

Statements relating to “reserves”or “resources” are forward-looking statements, as they involve the impliedassessment, based on estimates and assumptions that the reserves and resourcesdescribed exist in the quantities predicted or estimated, and can be profitablyproduced in the future.

 

The forward-lookingstatements are subject to known and unknown risks and uncertainties and otherfactors which may cause actual results, levels of activity and achievements to differmaterially from those expressed or implied by such statements. Such factorsinclude, among others:

 

·                  market prices for oil and gas and chemicals products;

·                  our ability to explore, develop, produce and transportcrude oil and natural gas to markets;

·                  the results of exploration and development drillingand related activities;

·                  volatility in energy trading markets;

·                  foreign-currency exchange rates;

·                  economic conditions in the countries and regions in whichwe carry on business;

·                  governmental actions including changes to taxes orroyalties, changes in environmental and other laws and regulations;

·                  renegotiations of contracts;

·                  results of litigations, arbitration or regulatoryproceedings; and

·                  political uncertainty, including actions byterrorists, insurgent or other groups, or armed conflict, including conflictbetween states.

 

These 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 ona particular forward-looking statement is not determinable with certainty asthese factors are interdependent, and management’s future course of actionwould depend on our assessment of all information at that time.

 

Although we believe that theexpectations conveyed by the forward-looking statements are reasonable based oninformation available to us on the date such forward-looking statements weremade, no assurances can be given as to future results, levels of activity andachievements. Undue reliance should not be placed on the statements contained herein,which are made as of the date hereof and, except as required by law, Nexenundertakes no obligation to update publicly or revise any forward-lookingstatements, whether as a result of new information, future events or otherwise.The forward-looking statements contained herein are expressly qualified by thiscautionary statement.

 

75

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**SPECIALNOTE TO CANADIAN INVESTORS**

 

Nexen is an SEC registrantand a Form 10-K and related forms filer. Therefore, our reserves estimatesand securities regulatory disclosures follow SEC requirements. In Canada, *National Instrument 51-101—Standards of Disclosurefor Oil and Gas Activities*(NI 51-101) prescribes that Canadian companiesfollow certain standards for the preparation and disclosure of reserves andrelated information. Our disclosures may differ from other Canadian companiesas we have received exemptions under NI 51-101 permitting us to:

 

·                  substitute our SECdisclosures for much of the annual disclosure required by NI 51-101;

·                  prepare our reservesestimates and related disclosures in accordance with SEC requirements,generally accepted industry practices in the US and the standards of the *Canadian Oil and Gas Evaluation Handbook*(COGEHandbook) modified to reflect SEC requirements;

·                  dispense withthe requirement to have our reserves estimates and the *Standardized Measure of Discounted Future Net CashFlows and Changes Therein*, included in the Supplementary FinancialInformation, evaluated or audited by independent qualified reserves evaluators;and

·                  not disclose certainprescribed information pertaining to prospects if such disclosures would resultin the contravention of a legal obligation, would likely be detrimental to ourcompetitive interests or the information does not exist.

 

As a result of these exemptions, Canadian investorsshould note the following fundamental differences in reserves estimates andrelated disclosures contained in the Form 10-K:

 

·                  SEC registrants apply SECreserves definitions and prepare their reserves estimates in accordance withSEC requirements and generally accepted industry practices in the US whereas NI51-101 requires adherence to the definitions and standards promulgated by theCOGE Handbook;

·                  the SEC mandates disclosureof proved reserves and the *StandardizedMeasure of Discounted Future Net Cash Flows and Changes Therein*calculatedusing year-end constant prices and costs only whereas NI 51-101 also requiresdisclosure of reserves and related future net revenues using forecast prices;

·                  the SEC mandates disclosureof proved and proved developed reserves by geographic region only whereas NI51-101 requires disclosure of more reserve categories and product types;

·                  the SEC does not prescribethe nature of the information required in connection with proved undeveloped reservesand future development costs whereas NI 51-101 requires certain detailedinformation regarding proved undeveloped reserves, related development plans andfuture development costs;

·                  the SEC does not requiredisclosure of finding and development (F&D) costs per boe of provedreserves additions whereas NI 51-101 requires that various F&D costs perboe be disclosed. NI 51-101 requires that F&D costs be calculated bydividing the aggregate of exploration and development costs incurred in thecurrent year and the change in estimated future development costs relating toproved reserves by the additions to proved reserves in the current year.However, this will generally not reflect full cycle finding and developmentcosts related to reserve additions for the year;

·                  the SEC leaves the engagementof independent qualified reserves evaluators to the discretion of a company’s boardof directors whereas NI 51-101 requires issuers to engage such evaluators andto file their reports;

·                  the SEC does not consider theupgrading component of our integrated oil sands project at Long Lake as an oiland gas activity, and therefore permits recognition of bitumen reserves only.NI 51-101 specifically includes such activity as an oil and gas activity andrecognizes synthetic oil as a product type, and therefore permits recognitionof synthetic reserves. At year end, we have recognized 268 million barrelsbefore royalties of proved bitumen reserves (234 million barrels afterroyalties) under SEC requirements, whereas under NI 51-101 we would have recognized218 million barrels before royalties of proved synthetic reserves (210 millionbarrels after royalties); and

·                  the SEC considers ourSyncrude operation as a mining activity rather than an oil and gas activity,and therefore does not permit related reserves to be included with oil and gasreserves. NI 51-101 specifically includes such activity as an oil and gas activityand recognizes synthetic oil as a product type, and therefore permits them tobe included with oil and gas reserves. We have provided a separate tableshowing our share of the Syncrude proved reserves as well as the additionaldisclosures relating to mining activities required by SEC requirements.

 

The foregoing is a generaldescription of the principal differences only.

 

Please note that thedifferences between SEC requirements and NI 51-101 may be material.

 

NI 51-101 requires that wemake the following disclosures:

 

·                  we use oil equivalents (boe)to express quantities of natural gas and crude oil in a common unit. Aconversion ratio of 6 mcf of natural gas to 1 barrel of oil is used. Boe may bemisleading, particularly if used in isolation. The conversion ratio is based onan energy equivalency conversion method primarily applicable at the burner tipand does not represent a value equivalency at the wellhead.

·                  because reserves data arebased on judgements regarding future events actual results will vary and the variationsmay be material. Variations as a result of future events are expected to beconsistent with the fact that reserves are categorized according to theprobability of their recovery.

 

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financial

statements

 

A strong and robust balance

sheet provides the necessary

flexibility to ensure we can fund

our active capital programs.

 

77

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**ITEM 8. FINANCIAL STATEMENTS ANDSUPPLEMENTARY DATA**

 
| Report of Management                                             | 79  |
|------------------------------------------------------------------|-----|
| Report of Independent Registered  Chartered Accountants          | 80  |
| Consolidated Financial  Statements                               |
| Consolidated  Statement of Income                                | 81  |
| Consolidated  Balance Sheet                                      | 82  |
| Consolidated  Statement of Cash Flows                            | 83  |
| Consolidated  Statement of Shareholders’ Equity             | 84  |
| Consolidated  Statement of Comprehensive Income                  | 84  |
| Notes  To Consolidated Financial Statements                      | 85  |
|                                                             |
| Supplementary Data  (Unaudited)                                  |
| Quarterly Financial Data In Accordance with Canadian and US GAAP | 119 |
| Oil And Gas Producing Activities and Syncrude Operations         | 120 |

 

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Item8.    Financial Statements and SupplementaryData               Report of Management

 

**REPORT OF MANAGEMENT**

 

February 13,2008

 

**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 consolidated financialstatements. This responsibility requires us to make significant accountingjudgments and estimates. For example, we are required to choose accountingprinciples and methods that are appropriate to the company’s circumstances, andwe are required to make estimates and assumptions that affect amounts reported.Fulfilling this responsibility requires the preparation and presentation of ourconsolidated financial statements in accordance with generally acceptedaccounting principles in Canada with a reconciliation to generally accepted accountingprinciples 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 assurance thatrelevant and reliable financial information is produced. To gather and controlfinancial data, we have established accounting and reporting systems supportedby internal controls over financial reporting and an internal audit program. Webelieve that our internal controls over financial reporting provide reasonableassurance that our assets are safeguarded against loss from unauthorized use ordisposition, that receipts and expenditures of the company are made only inaccordance with authorization of management and directors of the company, andthat our records are reliable for preparing our consolidated financialstatements and other financial information in accordance with applicable generallyaccepted accounting principles and in accordance with applicable securities rules andregulations. All internal control systems, no matter how well designed, haveinherent limitations. Therefore, even those systems determined to be effectivecan provide only reasonable assurance with respect to financial statementpreparation 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. Our disclosurecontrols 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 of authorityand division of responsibilities. Our policies and procedures are communicatedthroughout the organization and include a written ethics and integrity policythat applies to all employees, including the chief executive officer, chief financialofficer 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 reporting responsibilities.Their financial statement related responsibilities are fulfilled mainly throughthe Audit and Conduct Review Committee (the Audit Committee) with assistancefrom the Reserves Review Committee regarding the annual review of our crude oiland natural gas reserves and the Finance Committee regarding the assessment andmitigation of risk. The Audit Committee is composed entirely of independent directorsand includes three directors with financial expertise. The Audit Committeemeets regularly with management, the internal auditors and the independentregistered Chartered Accountants to review accounting policies, financialreporting and internal control issues and to ensure each party is properly dischargingits responsibilities. The Audit Committee is responsible for the appointmentand compensation of the independent registered Chartered Accountants and alsoconsiders their independence, reviews their fees and (subject to applicable securitieslaws), pre-approves their retention for any permitted non-audit services andtheir fee for such services. The internal auditors and independent registeredChartered Accountants have full and unlimited access to the Audit Committee,with and without the presence of management.

 

(signed) “Charles W. Fischer”

President and Chief ExecutiveOfficer

 

(signed) “Marvin F. Romanow”

Executive Vice President andChief Financial Officer

 

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Item8.    Financial Statements andSupplementary Data               Report ofAuditors

 

**REPORT OF INDEPENDENT REGISTERED**

** **

**CHARTEREDACCOUNTANTS**

 

**To the Boardof Directors and Shareholders of Nexen Inc.:**

 

We have audited theaccompanying consolidated balance sheets of Nexen Inc. and subsidiaries (the “Company”)as of December 31, 2007 and 2006, and the related consolidated statementsof income, cash flows, shareholders’ equity and comprehensive income for eachof the years in the three year period ended December 31, 2007. Thesefinancial statements are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financial statements based onour audits.

 

Weconducted our audits in accordance with Canadian generally accepted auditingstandards and the standards of the Public Company Accounting Oversight Board(United States). These standards require that we plan and perform the audit toobtain reasonable assurance about whether the financial statements are free ofmaterial misstatement. An audit includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements. An audit alsoincludes assessing the accounting principles used and significant estimatesmade by management, as well as evaluating the overall financial statementpresentation. We believe that our audits provide a reasonable basis for ouropinion.

 

In our opinion, theseconsolidated financial statements present fairly, in all material respects, thefinancial position of Nexen Inc. and subsidiaries as of December 31, 2007and 2006 and the results of their operations and their cash flows for each ofthe years in the three year period ended December 31, 2007 in accordancewith Canadian generally accepted accounting principles.

 

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the Company’s internal control over financial reporting as of December 31,2007, based on the criteria established in Internal Control—IntegratedFramework issued by the Committee of Sponsoring Organizations of the Treadway Commissionand our report dated February 13, 2008 expressed an unqualified opinion onthe Company’s internal control over financial reporting.

 

(signed) “Deloitte &Touche LLP”

Independent RegisteredChartered Accountants

Calgary, Canada

February 13, 2008

 

**COMMENTSBY INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS ON CANADA-UNITED STATES OFAMERICA 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 changes 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 13, 2008,is expressed in accordance with Canadian reporting standards which do notrequire a reference to such changes in accounting principles in the auditors’report when the changes are properly accounted for and adequately disclosed inthe financial statements.

 

(signed) “Deloitte &Touche LLP”

Independent RegisteredChartered Accountants

Calgary, Canada

February 13, 2008

 

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Item 8     Financial Statementsand Supplementary Data               FinancialStatements

 

**NEXEN INC.**

** **

**CONSOLIDATED STATEMENT OF INCOME**

** **

**FOR THETHREE YEARS ENDED DECEMBER 31, 2007**

 
| **Cdn$ millions, except per share amounts**    | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|-------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues and  Other Income                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net Sales                                                               |       | 5,583      |       | 3,936      |       | 3,932      |       |
| Marketing and Other (Note 17)                                           |       | 1,021      |       | 1,450      |       | 702        |       |
| Gain on Dilution of Interest in Chemicals  Business (Note 2)            |       | —     |       | —     |       | 193        |       |
|                                                                    |       | 6,604      |       | 5,386      |       | 4,827      |       |
|                                                                    |       |       |       |       |       |       |       |
| Expenses                                                                |       |       |       |       |       |       |       |
| Operating                                                               |       | 1,165      |       | 955        |       | 893        |       |
| Depreciation, Depletion, Amortization and  Impairment (Note  6)         |       | 1,767      |       | 1,124      |       | 1,052      |       |
| Transportation and Other                                                |       | 908        |       | 1,041      |       | 796        |       |
| General and Administrative                                              |       | 374        |       | 555        |       | 809        |       |
| Exploration                                                             |       | 326        |       | 362        |       | 250        |       |
| Interest (Note 8)                                                       |       | 168        |       | 53         |       | 97         |       |
|                                                                    |       | 4,708      |       | 4,090      |       | 3,897      |       |
|                                                                    |       |       |       |       |       |       |       |
| Income from Continuing Operations before  Income Taxes                  |       | 1,896      |       | 1,296      |       | 930        |       |
|                                                                    |       |       |       |       |       |       |       |
| Provision for Income Taxes (Note 18)                                    |       |       |       |       |       |       |       |
| Current                                                                 |       | 434        |       | 368        |       | 339        |       |
| Future                                                                  |       | 358        |       | 315        |       | (105       | )          |
|                                                                    |       | 792        |       | 683        |       | 234        |       |
|                                                                    |       |       |       |       |       |       |       |
| Net Income from Continuing Operations  before Non-Controlling Interests |       | 1,104      |       | 613        |       | 696        |       |
| Net Income Attributable to Non-Controlling  Interests (Note  2)         |       | 18         |       | 12         |       | 8          |       |
|                                                                    |       |       |       |       |       |       |       |
| Net Income from Continuing Operations                                   |       | 1,086      |       | 601        |       | 688        |       |
| Net Income from Discontinued Operations (Note 14)                       |       | —     |       | —     |       | 452        |       |
|                                                                    |       |       |       |       |       |       |       |
| **Net Income**                                                          | ** ** | **1,086**  | ** ** | **601**    | ** ** | **1,140**  | ** ** |
| ** **                                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Earnings Per Common Share from Continuing  Operations**($/share)      |       |       |       |       |       |       |       |
| Basic (Note 13)                                                         |       | 2.06       |       | 1.15       |       | 1.32       |       |
| Diluted(Note 13)                                                        |       | 2.02       |       | 1.12       |       | 1.29       |       |
|                                                                    |       |       |       |       |       |       |       |
| **Earnings Per Common Share****($/share)**                              |       |       |       |       |       |       |       |
| Basic (Note 13)                                                         |       | 2.06       |       | 1.15       |       | 2.19       |       |
| Diluted (Note 13)                                                       |       | 2.02       |       | 1.12       |       | 2.14       |       |

 

*Seeaccompanying notes to Consolidated Financial Statements.*

 

81

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**NEXEN INC.**

 

**CONSOLIDATED BALANCE SHEET**

 

**DECEMBER 31, 2007 AND 2006**

 
| ** **

**Cdn$ millions, except share amounts**                                                                                                                                      | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                                                                                                                                                                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| **ASSETS**                                                                                                                                                                                                   |       |       |       |       |       |
| Current Assets                                                                                                                                                                                               |       |       |       |       |       |
| Cash and Cash Equivalents                                                                                                                                                                                    |       | 206        |       | 101        |       |
| Restricted Cash and Margin Deposits (Note 7(d))                                                                                                                                                              |       | 203        |       | 197        |       |
| Accounts Receivable (Note 4)                                                                                                                                                                                 |       | 3,502      |       | 2,951      |       |
| Inventories and Supplies (Note 5)                                                                                                                                                                            |       | 659        |       | 786        |       |
| Future Income Tax Assets (Note 18)                                                                                                                                                                           |       | 18         |       | 479        |       |
| Other                                                                                                                                                                                                        |       | 71         |       | 67         |       |
| Total Current Assets                                                                                                                                                                                         |       | 4,659      |       | 4,581      |       |
|                                                                                                                                                                                                         |       |       |       |       |       |
| Property, Plant and Equipment (Note 6)                                                                                                                                                                       |       | 12,498     |       | 11,739     |       |
| Goodwill                                                                                                                                                                                                     |       | 326        |       | 377        |       |
| Future Income Tax Assets (Note 18)                                                                                                                                                                           |       | 268        |       | 141        |       |
| Deferred Charges and Other Assets (Note 10)                                                                                                                                                                  |       | 324        |       | 318        |       |
|                                                                                                                                                                                                         |       |       |       |       |       |
| **TOTAL ASSETS**                                                                                                                                                                                             | ** ** | **18,075** | ** ** | **17,156** | ** ** |
| ** **                                                                                                                                                                                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| **LIABILITIES AND SHAREHOLDERS’ EQUITY**                                                                                                                                                                |       |       |       |       |       |
| Current Liabilities                                                                                                                                                                                          |       |       |       |       |       |
| Short-Term Borrowings (Note 8)                                                                                                                                                                               |       | —     |       | 158        |       |
| Accounts Payable and Accrued Liabilities                                                                                                                                                                     |       | 4,180      |       | 3,879      |       |
| Accrued Interest Payable                                                                                                                                                                                     |       | 54         |       | 55         |       |
| Dividends Payable                                                                                                                                                                                            |       | 13         |       | 13         |       |
| Total Current Liabilities                                                                                                                                                                                    |       | 4,247      |       | 4,105      |       |
|                                                                                                                                                                                                         |       |       |       |       |       |
| Long-Term Debt (Note 8)                                                                                                                                                                                      |       | 4,610      |       | 4,673      |       |
| Future Income Tax Liabilities (Note 18)                                                                                                                                                                      |       | 2,290      |       | 2,468      |       |
| Asset Retirement Obligations (Note 9)                                                                                                                                                                        |       | 792        |       | 683        |       |
| Deferred Credits and Other Liabilities (Note 11)                                                                                                                                                             |       | 459        |       | 516        |       |
| Non-Controlling Interests (Note 2)                                                                                                                                                                           |       | 67         |       | 75         |       |
| Shareholders’ Equity (Note 12)                                                                                                                                                                          |       |       |       |       |       |
| Common Shares, no par value                                                                                                                                                                             |       |       |       |       |       |
| Authorized: Unlimited                                                                                                                                                                                        |       |       |       |       |       |
| Outstanding: 2007—528,304,813 shares                                                                                                                                                                    |       |       |       |       |       |
|                                2006—525,026,412 shares |       | 917        |       | 821        |       |
| Contributed Surplus                                                                                                                                                                                          |       | 3          |       | 4          |       |
| Retained Earnings                                                                                                                                                                                            |       | 4,983      |       | 3,972      |       |
| Accumulated Other Comprehensive Loss                                                                                                                                                                         |       | (293       | )          | (161       | )          |
| Total Shareholders’ Equity                                                                                                                                                                              |       | 5,610      |       | 4,636      |       |
| Commitments, Contingencies and Guarantees (Notes 15 and 18)                                                                                                                                                  |       |       |       |       |       |
| **TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY**                                                                                                                                                          | ** ** | **18,075** | ** ** | **17,156** | ** ** |

 

*Seeaccompanying notes to Consolidated Financial Statements.*

 
| Approved on behalf of the  Board:       |   |                                        |
|-----------------------------------------|--------|---------------------------------------------|
|                                    |   |                                        |
| (signed) “Charles W. Fischer” |   | (signed) “Thomas C. O’Neill” |
| Director                                |   | Director                                    |

 

82

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**NEXEN INC.**

 

**CONSOLIDATED STATEMENT OF CASH FLOWS**

 

**FOR THE THREE YEARS ENDED DECEMBER 31, 2007**

 
| **Cdn$ millions**                                                 | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Operating Activities**                                               |       |       |       |       |       |       |       |
| Net Income from Continuing Operations                                  |       | 1,086      |       | 601        |       | 688        |       |
| Net Income from Discontinued Operations                                |       | —     |       | —     |       | 452        |       |
| Charges and Credits to Income not Involving  Cash (Note 19)            |       | 2,073      |       | 1,629      |       | 1,081      |       |
| Exploration Expense                                                    |       | 326        |       | 362        |       | 250        |       |
| Changes in Non-Cash Working Capital (Note 19)                          |       | (348       | )          | (177       | )          | (195       | )          |
| Other                                                                  |       | (307       | )          | (41        | )          | (133       | )          |
|                                                                   |       | 2,830      |       | 2,374      |       | 2,143      |       |
|                                                                   |       |       |       |       |       |       |       |
| **Financing Activities**                                               |       |       |       |       |       |       |       |
| Proceeds from Long-Term Notes and  Debentures (Note  8)                |       | 1,660      |       | —     |       | 1,253      |       |
| Repayment of Long-Term Notes and Debentures  (Note 8)                  |       | (150       | )          | (93        | )          | (1,818     | )          |
| Proceeds from (Repayment of) Term Credit  Facilities, Net              |       | (697       | )          | 1,044      |       | (66        | )          |
| Proceeds from (Repayment of) Short-Term  Borrowings, Net               |       | (150       | )          | 160        |       | (99        | )          |
| Dividends on Common Shares                                             |       | (53        | )          | (52        | )          | (52        | )          |
| Issue of Common Shares and Exercise of  Tandem Options for Shares      |       | 56         |       | 48         |       | 58         |       |
| Net Proceeds from Canexus Initial Public  Offering (Note 2)            |       | —     |       | —     |       | 301        |       |
| Proceeds from Term Credit Facilities of  Canexus, Net (Notes  2 and 8) |       | 60         |       | 2          |       | 176        |       |
| Other                                                                  |       | (49        | )          | (28        | )          | (27        | )          |
|                                                                   |       | 677        |       | 1,081      |       | (274       | )          |
|                                                                   |       |       |       |       |       |       |       |
| **Investing Activities**                                               |       |       |       |       |       |       |       |
| Capital Expenditures                                                   |       |       |       |       |       |       |       |
| Exploration and Development                                            |       | (3,132     | )          | (3,198     | )          | (2,564     | )          |
| Proved Property Acquisitions                                           |       | (151       | )          | (13        | )          | (20        | )          |
| Chemicals, Corporate and Other                                         |       | (118       | )          | (119       | )          | (54        | )          |
| Business Acquisitions, Net of Cash Acquired  (Note 3)                  |       | —     |       | (78        | )          | —     |       |
| Proceeds on Disposition of Assets                                      |       | 4          |       | 27         |       | 911        |       |
| Changes in Non-Cash Working Capital (Note 19)                          |       | 130        |       | 134        |       | (54        | )          |
| Changes in Restricted Cash and Margin  Deposits                        |       | (16        | )          | (127       | )          | (70        | )          |
| Other                                                                  |       | 2          |       | (14        | )          | (13        | )          |
|                                                                   |       | (3,281     | )          | (3,388     | )          | (1,864     | )          |
|                                                                   |       |       |       |       |       |       |       |
| Effect of Exchange Rate Changes on Cash and  Cash Equivalents          |       | (121       | )          | (14        | )          | (30        | )          |
|                                                                   |       |       |       |       |       |       |       |
| Increase (Decrease) in Cash and Cash  Equivalents                      |       | 105        |       | 53         |       | (25        | )          |
|                                                                   |       |       |       |       |       |       |       |
| Cash and Cash Equivalents—Beginning of Year                       |       | 101        |       | 48         |       | 73         |       |
|                                                                   |       |       |       |       |       |       |       |
| **Cash and Cash Equivalents—End of Year**                         | ** ** | **206**    | ** ** | **101**    | ** ** | **48**     | ** ** |

 

*See accompanyingnotes to Consolidated Financial Statements.*

 

83

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**NEXEN INC.**

** **

**CONSOLIDATEDSTATEMENT OF SHAREHOLDERS’ EQUITY**

** **

**FOR THE THREE YEARS ENDED DECEMBER 31, 2007**

 
| **Cdn$ millions**                                                             | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                                         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Common Shares****(Note 12)**                                                     |       |       |       |       |       |       |       |
| Balance at Beginning of Year                                                       |       | 821        |       | 732        |       | 637        |       |
| Issue of Common Shares                                                             |       | 32         |       | 32         |       | 29         |       |
| Proceeds from Tandem Options Exercised for  Shares                                 |       | 24         |       | 16         |       | 29         |       |
| Accrued Liability Relating to Tandem  Options Exercised for Shares                 |       | 40         |       | 41         |       | 37         |       |
| **Balance at End of Year**                                                         | ** ** | **917**    | ** ** | **821**    | ** ** | **732**    | ** ** |
| ** **                                                                         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Contributed Surplus**                                                            |       |       |       |       |       |       |       |
| Balance at Beginning of Year                                                       |       | 4          |       | 2          |       | —     |       |
| Stock-Based Compensation Expense (Note 12)                                         |       | 1          |       | 2          |       | 2          |       |
| Exercise of Tandem Options                                                         |       | (2         | )          | —     |       | —     |       |
| **Balance at End of Year**                                                         | ** ** | **3**      | ** ** | **4**      | ** ** | **2**      | ** ** |
| ** **                                                                         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Retained Earnings**                                                              |       |       |       |       |       |       |       |
| Balance at Beginning of Year                                                       |       | 3,972      |       | 3,423      |       | 2,335      |       |
| Net Income                                                                         |       | 1,086      |       | 601        |       | 1,140      |       |
| Dividends on Common Shares                                                         |       | (53        | )          | (52        | )          | (52        | )          |
| Transition Adjustment Resulting from  Adoption of New Inventory Standard (Note 1u) |       | (22        | )          | —     |       | —     |       |
| **Balance at End of Year**                                                         | ** ** | **4,983**  | ** ** | **3,972**  | ** ** | **3,423**  | ** ** |
| ** **                                                                         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Accumulated Other Comprehensive Loss**                                           |       |       |       |       |       |       |       |
| Balance at Beginning of Year                                                       |       | (161       | )          | (161       | )          | —     |       |
| Opening Cumulative Foreign Currency  Translation Adjustment (Note 1u)              |       | —     |       | —     |       | (105       | )          |
| Opening Derivatives Designated as Cash Flow  Hedges (Note 1u)                      |       | 61         |       | —     |       | —     |       |
| Other Comprehensive Loss                                                           |       | (193       | )          | —     |       | (56        | )          |
| **Balance at End of Year (1)**                                                     | ** ** | **(293**   | **)**      | **(161**   | **)**      | **(161**   | **)**      |

 

----

*Note:*

*(1)  Includes unrealized foreign currencytranslation adjustment.*

 

**NEXEN INC.**

 

**CONSOLIDATEDSTATEMENT OF COMPREHENSIVE INCOME**

** **

**FOR THE THREE YEARS ENDED DECEMBER 31, 2007**

 
| **Cdn$ millions**                                                  | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|-------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Net Income**                                                          |       | 1,086      |       | 601        |       | 1,140      |       |
| ** **                                                              |       |       |       |       |       |       |       |
| Other Comprehensive Income (Loss), net of  income taxes:                |       |       |       |       |       |       |       |
| Foreign Currency Translation Adjustment:                                |       |       |       |       |       |       |       |
| Net Gains (Losses) on Investment in  Self-Sustaining Foreign Operations |       | (867       | )          | 16         |       | (179       | )          |
| Net Gains (Losses) on Hedges of  Self-Sustaining Foreign Operations (1) |       | 738        |       | (20        | )          | 99         |       |
| Realized Translation Adjustments Recognized  in Net Income (2)          |       | (3         | )          | 4          |       | 24         |       |
| Cash Flow Hedges:                                                       |       |       |       |       |       |       |       |
| Realized Mark-to-Market Gains Recognized in  Net Income                 |       | (61        | )          | —     |       | —     |       |
| Other Comprehensive Loss, net of income  taxes                          |       | (193       | )          | —     |       | (56        | )          |
|                                                                    |       |       |       |       |       |       |       |
| **Comprehensive Income**                                                | ** ** | **893**    | ** ** | **601**    | ** ** | **1,084**  | ** ** |

 

----

*Notes:*
| *(1)* | *Net of  income tax expense for the year ended December 31, 2007 of $97 million  (2006—$12 million recovery; 2005—$19 million expense).* |
|-------|---------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Net of  income tax recovery for the year ended December 31, 2007 of $1 million  (2006—$1 million expense; 2005—$17 million expense).*   |

*Seeaccompanying notes to Consolidated Financial Statements.*

 

84

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Item 8     Financial Statementsand Supplementary Data               Notesto Financial Statements

 

**NEXEN INC.**

 

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

Cdn$millions, except as noted

 

**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) Useof estimates**

 

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, impairments, incometaxes, derivative contract assets and liabilities and the determination ofproved reserves on an ongoing basis. Changes in facts and circumstances mayresult in revised estimates, and actual results may differ from theseestimates.

 

**(b) Principlesof 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 inter-company accountsand transactions have been eliminated.

 

In August 2005, we soldour chemicals operations to Canexus LP, but retained control of theseoperations through our 61.4% interest in Canexus LP. All of the assets,liabilities and results of operations of Canexus LP and its subsidiaries havebeen included in our Consolidated Financial Statements. The non-Nexen ownershipinterests in Canexus LP and its subsidiaries are shown as non-controllinginterests.

 

We proportionatelyconsolidate our undivided interests in our oil and gas exploration, developmentand production activities conducted under joint venture arrangements. We alsoproportionately consolidate our 7.23% undivided interest in the Syncrude joint venture,which is considered a mining activity under US regulations. While the jointventures under which these activities are carried out do not comprise distinctlegal entities, they are operating entities. The significant operating policiesof which are, by contractual arrangement, jointly controlled by all workinginterest 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) Inventoriesand supplies**

 

Inventories and supplies forour oil and gas and chemicals operations are stated at the lower of cost andnet realizable value. Cost is determined on the first-in, first-out method.Inventory costs include expenditures and other costs, including depletion,directly or indirectly incurred in bringing the inventory to its existingcondition.

 

Commencing October 1,2007 (see Note 1(u)), commodity inventories for our energy marketing operationsare held for trading purposes and are stated at fair value, as measured by theone-month forward price, less any costs to sell. Any changes in fair value areincluded as gains or losses in marketing and other during the period of change.

 

**(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. Major spareparts and standby equipment whose useful life is expected to last longer thanone year are included with PP&E.

 

We follow successful effortsaccounting for our oil and gas operations. All property acquisition costs areinitially capitalized to PP&E as unproved property costs. Once provedreserves are discovered, the acquisition costs are reclassified to provedproperty acquisition costs. Exploration drilling costs are capitalized pendingevaluation as to whether sufficient quantities of reserves have been found tojustify commercial production. If commercial quantities of reserves are notfound, exploration drilling costs are expensed. All exploratory wells areevaluated for commercial viability on a regular basis following completion ofdrilling. Exploration drilling costs remain capitalized when a well has found asufficient quantity of reserves to justify its completion as a producing welland sufficient progress is being made to assess the reserves and the economicand operating viability of the well. All other exploration costs, includinggeological and geophysical and annual lease rentals, are expensed to earningsas incurred. All development costs are capitalized as proved property costs.General and administrative costs that directly relate to acquisition,exploration and development activities are capitalized to PP&E.

 

85

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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 DD&A. Our cash flow estimatesrequire assumptions about future commodity prices, operating costs and other factors.Actual results can differ from 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.

 

**(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 DD&A. Actual retirement costs are recorded against theobligation when incurred. Any difference between the recorded asset retirementobligation and the actual retirement costs incurred is recorded as a gain orloss in the settlement period.

 

**(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 EnergyMarketing and UK reporting units.

 

86

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**(j) Revenuerecognition**

 

**Crude Oil and Natural Gas**

 

Revenue from the productionof crude oil and natural gas is recognized when title passes to the customer.In Canada and the US, our customers primarily take title when the crude oil andnatural gas reaches the end of the pipeline. For our other internationaloperations, including the UK, our customers take title when crude oil is loadedonto tankers. When we produce or sell more or less oil or natural gas than ourshare, 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 takes place when we have a sales contract in place specifying deliveryvolumes and sales prices. We assess customer credit worthiness before enteringinto sales contracts to minimize collection risk.

 

Energy Marketing

 

Substantially all of thephysical purchase and sales contracts entered into by our energy marketingoperations are considered to be derivative instruments. Accordingly, financialand physical commodity contracts (collectively derivative instruments) held byour marketing operations are stated at fair value on the balance sheet (seeNote 1(n)). We record any change in fair value as a gain or loss in marketingand other unless requirements for hedge accounting are met.

 

Any margin earned 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 average market-based prices and reported in our oil and gassegments. Intercompany profits and losses between segments are eliminated. Weassess customer credit worthiness before entering into contracts and providefor netting terms to minimize collection risk. Amounts are recorded on a netbasis where we have the legal right of offset.

 

**(k) Incometaxes**

 

We follow the liabilitymethod of accounting for income taxes. This method recognizes income tax assetsand liabilities at current rates, based on temporary differences in reportedamounts for financial statement and tax purposes. The effect of a change inincome tax rates on future income tax assets and future income tax liabilitiesis 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 at the balance sheet dates;and

 

·                       revenues and expenses using average exchange rates throughout the year.

 

Gains and losses resultingfrom this translation are included in other comprehensive income. Monetarybalances denominated in a currency other than a functional currency aretranslated into the functional currency using exchange rates at the balancesheet dates. Gains and losses arising from this translation, except on ourdesignated US-dollar debt, are included in income. We have designated ourUS-dollar debt as a hedge against our net investment in US-dollar basedself-sustaining foreign operations. Gains and losses resulting from thetranslation of the designated US-dollar debt are included in othercomprehensive income. 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) Capitalizedinterest**

 

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) Financialinstruments**

 

Financial assets andfinancial liabilities are recognized on the balance sheet when we become aparty to the contractual provisions of the instrument. Our derivative financialinstruments are initially recognized at fair value and subsequently remeasuredto fair value on each reporting period with changes in fair value recognized innet income. Transaction costs relating to derivative instruments are includedin net income when incurred. Our other financial instruments are initiallyrecognized at fair value. After initial recognition, these instruments aremeasured at cost or amortized cost using the effective interest method andgains and losses are recognized in net income when the assets and liabilitiessettle.

 

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Non-Trading Activities

 

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. Derivative instruments that have been designated andqualify for hedge accounting are classified as either cash flow or fair valuehedges.

 

For cash flow hedges, changesin the fair value of a financial instrument designated as a cash flow hedge arerecognized in net income in the same period as the hedged item. Any fair valuechange in the financial instrument before that period is recognized on thebalance sheet. The effective portion of this fair value change is recognized inother comprehensive income with any ineffectiveness recognized in net incomeduring the period of change.

 

For fair value hedges, boththe financial instrument designated as a fair value hedge and the underlyingcommitment are recognized on the balance sheet at fair value. Changes in thefair value of both are reflected in net income.

 

Trading Activities

 

Our energy marketingoperation uses derivative instruments for marketing and trading natural gas,crude oil, natural gas liquids, ethanol and power including:

 

·                       commodity contracts settled with physical delivery;

 

·                       exchange-traded futures and options; and

 

·                       non-exchange traded 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 payable if weanticipate settling the instruments within a year of the balance sheet date. Ifwe anticipate settling the instruments beyond twelve months, we record them asdeferred charges and other assets or deferred credits and other liabilities.

 

**(o) Employeefuture benefits**

 

The employee future benefitprograms consist of both defined benefit and defined contribution pensionplans, as well as other post-retirement benefits as described in Note 16. Thecost of pension benefits earned by employees in our defined benefit pensionplans is actuarially determined using the projected-benefit method prorated onservice and our best estimate of the plans’ investment performance, salaryescalations and retirement ages of employees. To calculate the plans’ expectedreturns, assets are measured at fair value. Past service costs arising fromplan amendments, and net actuarial gains and losses that exceed 10% of the greaterof the accrued benefit obligation and the fair value of plan assets, areexpensed in equal amounts over the expected average remaining service life ofthe employee group. We measure the plan assets and the accrued benefitobligation on October 31 each year. Company contributions to the definedcontribution plan are expensed as incurred.

 

**(p) Stock-basedcompensation**

 

Wemaintain tandem option and stock appreciation right (StARs) plans as describedin Note 12. The tandem options give the holders a right to either purchasecommon shares at the exercise price or to receive cash payments equal to theexcess of the market value of the common shares over the exercise price. Werecord obligations for the tandem options using the intrinsic-value method ofaccounting and recognize compensation expense in the Consolidated Statement ofNet Income. Obligations are accrued on a graded vesting basis and represent thedifference between the market value of our common shares and the exercise priceof the options. The obligations are revalued each reporting period based on thechange in 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 accrued liability istransferred to share capital. We account for stock appreciation rights toemployees on the same basis as our tandem options. Obligations are accrued ascompensation expense over the graded vesting period of the stock appreciationrights.

 

For employees eligible toretire during the vesting period, the compensation expense is recognized overthe period from the grant date to the retirement eligibility date on a gradedvesting basis. In instances where an employee is eligible to retire on thegrant date of the stock-based award, compensation expense is recognized in fullat that date.

 

**(q) Cashand cash 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.

 

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**(r) Restrictedcash and margin deposits**

 

Restricted cash includesmargin deposits relating to our exchange-traded derivative contracts.

 

**(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.

 

**(t) Transportation**

 

We pay to transport the crudeoil, natural gas and chemicals products that we market, and then bill our customersfor the transportation. This transportation is presented in our ConsolidatedFinancial Statements as a cost to us and is recorded as transportation andother. Our energy marketing operation has received cash payments in exchangefor assuming certain transportation obligations from third parties. These cashpayments have been recorded as deferred liabilities and are recognized in netincome as the transportation is used.

 

**(u) Changesin accounting principles**

 

Financial Instruments

 

On January 1, 2007, weadopted the following new accounting standards issued by the CanadianAccounting Standards Board (AcSB): *FinancialInstruments—Recognition and Measurement*(Section 3855), *Hedges*(Section 3865) and *Comprehensive Income*(Section 1530).

 

**Financial Instruments Recognitionand Measurement**

 

Section 3855 requiresall financial assets and liabilities to be carried at fair value in theConsolidated Balance Sheet with the exception of loans and receivables,investments that are intended to be held to maturity, and non-trading financialliabilities which are to be carried at cost or amortized cost.

 

Realized and unrealized gainsand losses on financial assets and liabilities carried at fair value arerecognized in net income in the periods such gains and losses arise.Transaction costs related to these financial assets and liabilities areincluded in net income when incurred. Unrealized gains and losses on financialassets and liabilities carried at cost or amortized cost are recognized in netincome when these assets or liabilities settle.

 

We hold financial instrumentsthat were carried at fair value prior to the adoption of Section 3855 asdescribed in Note 7. The valuation methods we use to determine the fair valueof these financial instruments remain unchanged. Financial instruments we carryat cost or amortized cost include our accounts receivable, accounts payable,short-term and long-term debt. The carrying value of short-term receivables andpayables approximates their fair value. On adoption of Section 3855, wecarry our long-term debt at amortized cost using the effective interest ratemethod. Accordingly, we have reclassified deferred financing costs previouslyincluded in deferred charges and other assets as unamortized debt issue costs,reducing the carrying value of our long-term debt.

 

Hedges

 

Section 3865 prescribesnew standards for hedge accounting. For cash flow hedges, changes in the fairvalue of a financial instrument designated as a cash flow hedge are recognizedin net income in the same period as the hedged item. Any fair value change inthe financial instrument before that period is recognized on the balance sheet.The effective portion of this fair value change is recognized in othercomprehensive income with any ineffectiveness recognized in net income duringthe period of change.

 

For fair value hedges, boththe financial instrument designated as a fair value hedge and the underlyingcommitment are recognized on the balance sheet at fair value. Changes in thefair value of both are reflected in net income.

 

Adoption of these newstandards for hedge accounting required us to record unrealized mark-to-marketgains on cash flow hedges that were previously not included on our ConsolidatedBalance Sheet at December 31, 2006, as an adjustment to the openingbalance of accumulated other comprehensive income (see Note 7).

 

Comprehensive Income

 

Section 1530 providesfor a new statement of comprehensive income and establishes accumulated othercomprehensive income (AOCI) as a separate component of shareholders’ equity.The statement of comprehensive income reflects changes in AOCI and includes theeffective portion of changes in the fair value of financial instrumentsdesignated as cash flow hedges, as well as changes in foreign currencytranslation amounts arising from our self-sustaining foreign operations,together with the impact of any related hedges. Amounts included in AOCI arereclassified to income when realized. On adoption of Section 1530,cumulative foreign currency translation adjustments relating to ourself-sustaining foreign operations were reclassified to AOCI and comparativeamounts have been restated.

 

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Impact of Adoption

 

We adopted these standardsprospectively. Comparative amounts for prior periods have not been restatedwith the exception of amounts related to cumulative foreign currencytranslation adjustments. Adoption of these standards as at January 1, 2007had the following impact on our Consolidated Balance Sheet:

 
| ** **                                                                                     | ** ** | **As at January 1, 2007** | ** ** |
|------------------------------------------------------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                                                     | ** ** | **Increase/(Decrease)**                       | ** ** |
| To Include Unrealized Mark-to-Market Gains  on Cash Flow Hedges at December 31, 2006:     |       |                                          |       |
| Accounts Receivable                                                                            |       | 25                                            |       |
| Accounts Payable                                                                               |       | (65                                           | )          |
| Future Income Tax Liabilities                                                                  |       | 29                                            |       |
| Accumulated Other Comprehensive Income                                                         |       | 61                                            |       |
|                                                                                           |       |                                          |       |
| To Include Cumulative Foreign Currency  Translation in Accumulated Other Comprehensive Income: |       |                                          |       |
| Cumulative Foreign Currency Translation  Adjustment                                            |       | 161                                           |       |
| Accumulated Other Comprehensive Income                                                         |       | (161                                          | )          |
|                                                                                           |       |                                          |       |
| To Include Unamortized Debt Issue Costs  with Long-Term Debt:                                  |       |                                          |       |
| Deferred Charges and Other Assets                                                              |       | (59                                           | )          |
| Long-Term Debt                                                                                 |       | (59                                           | )          |

 

**Inventories**

 

The AcSB issued Section 3031,*Inventories*, which is effective January 1,2008. We adopted this standard prospectively in the fourth quarter of 2007 inaccordance with the transitional provisions. Effective October 1, 2007, webegan carrying the commodity inventories held for trading by our energymarketing group at fair value, less any costs to sell. Section 3031 alsoclarifies that major spare parts and standby equipment not in use should beincluded in PP&E. On adoption of Section 3031, we reclassified $51million from inventories and supplies to PP&E related to major spare parts.

 

Prior periods presented havenot been restated and adoption of the standard had the following impact:

 
| ** **                                 | ** ** | **As at October 1, 2007 ** | ** ** | **Three Months Ended  December 31, 2007 ** | ** ** |
|--------------------------------------------|------------|-----------------------------------------------------|------------|---------------------------------------------------------------------|------------|
| ** **                                 | ** ** | **Increase/(Decrease)**                             | ** ** | **Increase/(Decrease)**                                             | ** ** |
| Inventories and Supplies                   |       | (86                                                 | )          | 79                                                                  |       |
| Property, Plant and Equipment              |       | 51                                                  |       | —                                                              |       |
| Future Income Tax Liabilities              |       | (13                                                 | )          | 27                                                                  |       |
| Retained Earnings                          |       | (22                                                 | )          | —                                                              |       |
| Marketing and Other                        |       |                                                |       | 79                                                                  |       |
| Provision for Future Income Taxes          |       |                                                |       | 27                                                                  |       |
| Net Income                                 |       |                                                |       | 52                                                                  |       |
| Basic/Diluted Earnings per Share ($/share) |       |                                                |       | $0.10                                                               |       |

 

90

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New Accounting Pronouncements

 

In December 2006, theAcSB issued two new sections in relation to financial instruments: Section 3862,*Financial Instruments—Disclosures*,and Section 3863, *FinancialInstruments—Presentation*. Both sections are effective for annual andinterim periods for fiscal years beginning on or after October 1, 2007 andwill require additional disclosures for our financial instruments.

 

In December 2006, theAcSB issued Section 1535, *CapitalDisclosures*, requiring disclosure of information about an entity’scapital and the objectives, policies, and processes for managing capital. Thestandard is effective for annual periods beginning on or after October 1,2007 and will require additional disclosure.

 

In February 2008, theAcSB issued Section 3064, *Goodwill andIntangible Assets*and amended Section 1000, *Financial Statement Concepts*clarifyingthe criteria for the recognition of assets, intangible assets and internallydeveloped intangible assets. Items that no longer meet the definition of an assetare no longer recognized with assets. The standard is effective for fiscalyears beginning on or after October 1, 2008 and early adoption ispermitted. We are currently evaluating the impact these sections will have onour results of operation and financial position.

 

In January 2006, theAcSB adopted a strategic plan for the direction of accounting standards inCanada. Accounting standards for public companies in Canada are expected toconverge with the International Financial Reporting Standards by 2011. Thetiming for convergence has not been confirmed by the AcSB. We continue tomonitor and assess the impact of these convergence efforts.

 

**2. CANEXUS INCOME FUND**

 

In June 2005, our boardof directors 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,with Canexus Income Fund (Canexus) issuing 30 million units at a price of $10per unit 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 LimitedPartnership (Canexus LP) using the net proceeds from the initial publicoffering. Canexus LP acquired Nexen’s chemicals business for approximately $1billion, comprised of the net proceeds from Canexus’ initial public offeringand $200 million (US$167 million) of bank debt, plus the issuance of 52.3million exchangeable limited partnership units (Exchangeable LP Units) ofCanexus LP. At that time, the Exchangeable LP Units held by Nexen represented a63.5% interest in Canexus LP.

 

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,the underwriters 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).As a 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,with responsibility for the strategic management and operational decisions ofCanexus and Canexus LP. Nexen currently has nominated two representatives tothe ten-member board of Canexus Limited. Since we have retained effectivecontrol of our chemicals business, the results, assets and liabilities of thisbusiness have been included in these financial statements. The non-Nexenownership interests in our chemicals business are shown as non-controllinginterests.

 

During the year, $28 million(2006—$28 million; 2005—$10 million) of distributions were paid to non-Nexenownership interests.

 

**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.

 

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**4. ACCOUNTS RECEIVABLE**

 
| ** **                         | ** ** | **2007**  | ** ** | **2006**  | ** ** |
|------------------------------------|------------|-----------|------------|-----------|------------|
| Trade                              |       |      |       |      |       |
| Marketing                          |       | 2,501     |       | 2,226     |       |
| Oil and Gas                        |       | 819       |       | 600       |       |
| Chemicals and Other                |       | 60        |       | 58        |       |
|                               |       | 3,380     |       | 2,884     |       |
| Non-Trade                          |       | 132       |       | 80        |       |
|                               |       | 3,512     |       | 2,964     |       |
| Allowance for Doubtful Receivables |       | (10       | )          | (13       | )          |
|                               |       |      |       |      |       |
| **Total Accounts Receivable**      | ** ** | **3,502** | ** ** | **2,951** | ** ** |

 

**5. INVENTORIES AND SUPPLIES**

 
| ** **                         | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------|------------|----------|------------|----------|------------|
| Finished Products                  |       |     |       |     |       |
| Marketing (1)                      |       | 577      |       | 609      |       |
| Oil and Gas                        |       | 14       |       | 21       |       |
| Chemicals and Other                |       | 13       |       | 14       |       |
|                               |       | 604      |       | 644      |       |
| Work in Process                    |       | 3        |       | 5        |       |
| Field Supplies (Note 1(u))         |       | 52       |       | 137      |       |
|                               |       |     |       |     |       |
| **Total Inventories and Supplies** | ** ** | **659**  | ** ** | **786**  | ** ** |

 

----

*Note:*
| *(1)* | * * | *Marketing  consists of commodity inventories held for trading purposes. At  December 31, 2006, these inventories were carried at the lower of cost  and net realizable value. On October 1, 2007, we adopted  Section 3031 and at December 31, 2007, marketing inventories are  carried at fair value less any costs to sell. (see Note 1(u)).* |
|-------|----------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

 

**6. PROPERTY, PLANT AND EQUIPMENT**

 
| ** **                    | ** ** | **2007**   | ** ** | **2006**        | ** ** |
|-------------------------------|------------|------------|------------|-----------------|------------|
| ** **                    | ** ** | ** ** | ** ** | **Accumulated** | ** ** | **Net Book** | ** ** | ** ** | ** ** | **Accumulated** | ** ** | **Net Book** | ** ** |
| ** **                    | ** ** | **Cost**   | ** ** | **DD&A**    | ** ** | **Value** | ** ** | **Cost** | ** ** | **DD&A** | ** ** | **Value** | ** ** |
| Oil and Gas                   |       |       |       |            |       |   |   |   |   |   |   |   |   |
| Yemen                         |       | 701        |       | 590             |       | 111 |   | 779 |   | 599 |   | 180 |   |
| Yemen — Carried Interest |       | 1,477      |       | 1,360           |       | 117 |   | 1,625 |   | 1,529 |   | 96 |   |
| Canada 1                      |       | 6,736      |       | 1,597           |       | 5,139 |   | 5,216 |   | 1,448 |   | 3,768 |   |
| United States                 |       | 3,069      |       | 1,765           |       | 1,304 |   | 2,889 |   | 1,445 |   | 1,444 |   |
| United Kingdom                |       | 4,723      |       | 908             |       | 3,815 |   | 4,710 |   | 432 |   | 4,278 |   |
| Other Countries               |       | 263        |       | 77              |       | 186 |   | 249 |   | 78 |   | 171 |   |
|                          |       | 16,969     |       | 6,297           |       | 10,672 |   | 15,468 |   | 5,531 |   | 9,937 |   |
| Marketing                     |       | 246        |       | 62              |       | 184 |   | 226 |   | 47 |   | 179 |   |
| Syncrude                      |       | 1,332      |       | 205             |       | 1,127 |   | 1,304 |   | 179 |   | 1,125 |   |
| Chemicals                     |       | 831        |       | 463             |       | 368 |   | 854 |   | 494 |   | 360 |   |
| Corporate and Other           |       | 315        |       | 168             |       | 147 |   | 286 |   | 148 |   | 138 |   |
|                          |       |       |       |            |       |   |   |   |   |   |   |   |   |
| **Total PP&E**            | ** ** | **19,693** | ** ** | **7,195**       | ** ** | **12,498** | ** ** | **18,138** | ** ** | **6,399** | ** ** | **11,739** | ** ** |

 

----

*Note:*
| *(1)* | * * | *Includes  capitalized costs related to our Long Lake (Phase 1 and future phases) of  $3,695 million (2006—$2,556 million).* |
|-------|----------|-----------------------------------------------------------------------------------------------------------------------------------|

 

Theabove table includes capitalized costs of $5,828 million (2006—$6,708million) relating to unproved properties and projects under construction ordevelopment. These costs are not being depreciated, depleted or amortized. OurLong Lake capitalized costs include $1,711 million related to the Phase 1upgrader (2006—$1,120 million), $1,026 million for Phase 1 SAGD andcogeneration facilities (2006—$804 million) and $958 million related tocapitalized interest and future phases (2006—$632 million).

 

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** **

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

 

In2007, our DD&A expense includes $366 million of impairment expenseprimarily related to our Aspen, Vermillion 320/340 and West Cameron 170properties in the Gulf of Mexico as we had poor results from capitalinvestments and lower reserve estimates. At Aspen, disappointing results fromour recent investment in development drilling resulted in negative reserverevisions. At Vermillion 320/340 and West Cameron 170, negative reserverevisions primarily relate to gas properties, where unsatisfactory investment results,production performance, revised mapping and higher projected operating costsresulted in a downward revision to reserves estimates. These properties werewritten down to their fair value equal to their estimated total future cashflows, discounted for the time value of money.

 

Our2006 DD&A expense includes $93 million of impairment expense, primarilyrelated to two natural gas producing properties in the Gulf of Mexico in the UScaused by unsuccessful development programs and negative year-end reserverevisions. In addition there was $15 million in 2006 relating to the write offof a portion of our purchase price allocation to unproved properties purchasedin the North Sea as a result of unsuccessful exploration activities.

 

**Researchand Development**

 

Weincurred $40 million (2006—$53 million) in connection with research anddevelopment activities related to developing new technologies for increasingoil recoveries. Research costs of $38 million (2006—$50 million) were includedin other expense on the Consolidated Statement of Income. The development costshave been deferred and are included in PP&E.

 
| ** **                                    | ** ** | **2007** | ** ** | **2006** | ** ** |
|-----------------------------------------------|------------|----------|------------|----------|------------|
| Development Costs Deferred, Beginning of Year |       | 28       |       | 25       |       |
| Deferred in the Year                          |       | 2        |       | 3        |       |
| Amortized in the Year                         |       | —   |       | —   |       |
| **Development Costs Deferred, End of Year**   | ** ** | **30**   | ** ** | **28**   | ** ** |

 

**SuspendedWell Costs**

 

Thefollowing table shows the changes in capitalized exploratory well costs duringthe years ended December 31, 2007 and 2006, and does not include amountsthat were initially capitalized and subsequently expensed in the same period.

 
| ** **                                                                                    | ** ** | **2007** | ** ** | **2006** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Balance at Beginning of Year                                                                  |       | 226      |       | 252      |       |
| Additions to Capitalized Exploratory Well Costs Pending the  Determination of Proved Reserves |       | 215      |       | 129      |       |
| Capitalized Exploratory Well Costs Charged to Expense                                         |       | (10      | )          | (70      | )          |
| Transfers to Wells, Facilities and Equipment Based on Determination  of Proved Reserves       |       | (74      | )          | (84      | )          |
| Effects of Foreign Exchange                                                                   |       | (31      | )          | (1       | )          |
| **Balance at End of Year**                                                                    | ** ** | **326**  | ** ** | **226**  | ** ** |

 

Thefollowing table provides an aging of capitalized exploratory well costs basedon the date drilling was completed and shows the number of projects for whichexploratory well costs have been capitalized for a period greater than one yearafter the completion of drilling.

 
| ** **                                                                                          | ** ** | **2007** | ** ** | **2006** | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Capitalized for a Period of One Year or Less                                                        |       | 202      |       | 179      |       |
| Capitalized for a Period of Greater than One Year                                                   |       | 124      |       | 47       |       |
| **Balance at End of Year**                                                                          | ** ** | **326**  | ** ** | **226**  | ** ** |
|                                                                                                |       |     |       |     |       |
| Number of Projects that have Exploratory Well Costs Capitalized for a  Period Greater than One Year |       | 5        |       | 4        |       |

 

Asat December 31, 2007, we have exploratory costs that have been capitalizedfor more than one year relating to our interest in an exploratory block in theGulf of Mexico ($51 million), our coalbed methane exploratory activities inCanada ($31 million), exploratory activities on Block 51 in Yemen ($18million), our interest in an exploratory block offshore Nigeria ($18 million)and an exploratory block in the North Sea ($6 million). These costs relate toprojects with successful exploration wells for which we have not been able torecord proved reserves. We are assessing all of these wells and projects, andare working with our partners to prepare development plans, drill additionalappraisal wells or to assess commercial viability.

 

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**7.  FINANCIALINSTRUMENTS AND FINANCIAL RISK MANAGEMENT**

 

Weuse derivatives in our marketing group for trading purposes and we also usederivatives to manage commodity price risk and foreign currency exchange raterisk for non-trading purposes. Our derivative instruments are carried at fairvalue on the balance sheet. Our other financial instruments are carried at costor amortized cost. The carrying value of short-term receivables and payablesapproximates their fair value because the instruments are near maturity.

 

**(a) Carrying value and estimated fair value of derivative andfinancial instruments**

 

Thecarrying values, fair values and unrecognized gains or losses on ouroutstanding derivatives and long-term financial assets and liabilities at December 31are:

 
| ** **                              | ** ** | **2007**     | ** ** | **2006**            | ** ** |
|-----------------------------------------|------------|--------------|------------|---------------------|------------|
| ** **                              | ** ** | **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 |   | — |   |
| Fixed-Price Natural Gas Contracts       |       | (70          | )          | (70                 | )          | — |   | (96 | ) | (96 | ) | — |   |
| Natural Gas Swaps                       |       | (9           | )          | (9                  | )          | — |   | (8 | ) | (8 | ) | — |   |
|                                    |       |         |       |                |       |   |   |   |   |   |   |   |   |
| Trading Activities                      |       |         |       |                |       |   |   |   |   |   |   |   |   |
| Crude Oil and Natural Gas               |       | 15           |       | 15                  |       | — |   | 372 |   | 372 |   | — |   |
| Future Sale of Gas Inventory            |       | —       |       | —              |       | — |   | — |   | 25 |   | 25 |   |
|                                    |       |         |       |                |       |   |   |   |   |   |   |   |   |
| **Foreign Currency Exchange Rate Risk** |       |         |       |                |       |   |   |   |   |   |   |   |   |
| Non-Trading Activities                  |       | 1            |       | 1                   |       | — |   | — |   | — |   | — |   |
| Trading Activities                      |       | (9           | )          | (9                  | )          | — |   | (12 | ) | (12 | ) | — |   |
| **Total Derivatives**                   | ** ** | **(72**      | **)**      | **(72**             | **)**      | — | ** ** | **275** | ** ** | **300** | ** ** | **25** | ** ** |
|                                    |       |         |       |                |       |   |   |   |   |   |   |   |   |
| **Other Financial Liabilities**         |       |         |       |                |       |   |   |   |   |   |   |   |   |
| Long-Term Debt                          |       | (4,610       | )          | (4,692              | )          | (82 | ) | (4,673 | ) | (4,728 | ) | (55 | ) |

 

Theestimated fair value of all derivative instruments is based on quoted marketprices and, if not available, on estimates from third-party brokers or dealers.Other financial assets used in the normal course of business include cash andcash equivalents, restricted cash and margin deposits and accounts receivable.Other financial liabilities include accounts payable, accrued interest payable,short-term borrowings and long-term debt. Fair value of long-term debt isestimated based on third-party brokers and quoted market prices.

 

**(b) Commodity price risk management**

 

**Non-TradingActivities**

 

Themajority of our oil and gas production is sold under short-term contracts,exposing us to short-term price movements. Other energy contracts we enter intoalso expose us to commodity price risk between the time we purchase and sellcontracted volumes. From time to time, we actively manage these risks by usingcommodity futures, forwards, swaps and options.

 

**Crudeoil put options**

 

In2007, we purchased put options on 36 million barrels or approximately 100,000bbls/d of our 2008 crude oil production. These options established  an annual average Dated Brent floor price ofUS$50/bbl on these volumes. The put options were purchased for $24 million andthe fair value at December 31, 2007 was $nil. We recorded a loss of $24million in marketing and other on the Consolidated Statement of Income in 2007.

 

In2006, we purchased WTI crude oil put options on 105,000 bbls/d of our 2007crude oil production at a cost of $26 million. These options established anannual average WTI floor price of US$50/bbl on these volumes. The 2007 WTIcrude oil put options were not used and have expired. The fair value at the endof December 31, 2006 was $19 million, which we included as a loss of $19million in marketing and other on the Consolidated Statement of Income in 2007.

 

94

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**Fixedprice natural gas contracts and natural gas swaps**

 

InJuly and August 2005, we sold certain Canadian oil and gas properties,and we retained fixed-price natural gas sales contracts that were previouslyassociated with those properties (see Note 14). Since these contracts are nolonger used in the normal course of our oil and gas operations, they have beenincluded in our Consolidated Balance Sheet at fair value. Amounts settlingwithin 12 months are included in accounts payable and amounts settling beyondthat are included in deferred credits and other liabilities. Any change in fairvalue is included in marketing and other in the Consolidated Statement ofIncome.

 
| ** **                        | ** ** | **Notional Volumes** | ** ** | **Term**   | ** ** | **Average Price** | ** ** | **Fair Value**      | ** ** |
|-----------------------------------|------------|---------------------------|------------|------------|------------|------------------------|------------|--------------------------|------------|
| ** **                        | ** ** | **(Gj/d)**                | ** ** | ** ** | ** ** | **($/Gj)**             | ** ** | **(Cdn$ millions)** | ** ** |
| Fixed-Price Natural Gas Contracts |       | 15,514                    |       | 2008       |       | 2.46                   |       | (22                      | )          |
|                              |       | 15,514                    |       | 2009-2010  |       | 2.56-2.77              |       | (48                      | )          |
| ** **                        | ** ** | ** **                | ** ** | ** ** | ** ** | ** **             | ** ** | **(70**                  | **)**      |

 

Followingthe sale of the Canadian oil and gas properties, we entered into natural gasswaps to economically hedge our exposure to the fixed-price natural gascontracts. The natural gas swaps are included in our Consolidated Balance Sheetwith amounts settling within 12 months included in accounts payable and amountssettling beyond that are included in deferred credits and other liabilities.Any change in fair value is included in marketing and other in the ConsolidatedStatement of Income.

 
| ** **        | ** ** | **Notional Volumes** | ** ** | ** ** | ** ** | **Average  Price** | ** ** | **Fair Value**           | ** ** |
|-------------------|------------|----------------------|------------|------------|------------|-------------------------|------------|--------------------------|------------|
| ** **        | ** ** | ** **           | **Term**   | ** ** | ** ** | ** **              |
| ** **        | ** ** | **(Gj/d)**           | ** ** | ** ** | ** ** | **($/Gj)**              | ** ** | **(Cdn$ millions)** | ** ** |
| Natural Gas Swaps |       | 15,514               |       | 2008       |       | 7.60                    |       | (6                       | )          |
|              |       | 15,514               |       | 2009-2010  |       | 7.60                    |       | (3                       | )          |
| ** **        | ** ** | ** **           | ** ** | ** ** | ** ** | ** **              | ** ** | **(9**                   | **)**      |

 

**TradingActivities**

 

**Crudeoil and natural gas**

 

Weenter into physical purchase and sales contracts as well as financial commoditycontracts to enhance our price realizations and lock-in our margins. Thephysical and financial commodity contracts (derivative contracts) are stated atfair value. The $15 million fair value of the commodity contracts at December 31,2007 (December 31, 2006—$372 million) is included in the ConsolidatedBalance Sheet and any change in fair value is included in marketing and otherin the Consolidated Statement of Income.

 

**Futuresale of gas inventory**

 

Inan attempt to mitigate the exposure to fluctuations in cash flow from changesin the price of natural gas we have certain NYMEX futures contracts and swapsin place, which effectively lock in our margins on the future sale of ournatural gas inventory in storage. From time to time, we have designated inwriting some of these derivative contracts as cash flow hedges of the futuresale of our storage inventory.

 

AtDecember 31, 2006, we held NYMEX natural gas futures contracts and swapsthat were designated as cash flow hedges on the future sale of natural gasinventory. On adoption of Section 3865 on January 1, 2007 (see Note1(u)), the fair value of $25 million related to these cash flow hedges wasincluded in accounts receivable and gains of $16 million, net of income taxes,were included in accumulated other comprehensive income (AOCI). During thefirst quarter of 2007, the inventory was sold and these gains were recognizedin marketing and other in the Consolidated Statement of Income.

 

Inlate 2006, we de-designated certain futures contracts that were designated ascash flow hedges of future sales of our natural gas in storage. These contractswere de-designated since it became uncertain at that time that the future salesof natural gas would occur within the designated time frame. As it wasreasonably possible that the future sales could have taken place as designatedat the inception of the hedging relationship, gains of $65 million on thefutures contracts were deferred in accounts payable at December 31, 2006.The adoption of Section 3865 on January 1, 2007 (see Note 1 (u))required that the deferred gains ($45 million, net of income taxes) bereclassified to AOCI. The gains were recognized in marketing and other in theConsolidated Statement of Income during the first quarter of 2007.

 

AtDecember 31, 2007, there were no designated cash flow hedges in place.

 

95

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**(c) Foreign currency exchange rate risk management**

 

**Non-TradingActivities**

 

**USdollar call options–Canexus**

 

Theoperations of Canexus are exposed to changes in the US-dollar exchange rate asa portion of its sales are denominated in US dollars while most of its costsare in Canadian dollars. Canexus periodically purchases US-dollar call optionsto reduce this exposure to fluctuations in the Canadian-US dollar exchangerate. Under outstanding option contracts at December 31, 2007, Canexus LPhas the right to sell US$5 million monthly and purchase Canadian dollars at anexchange rate of US$0.95 for the period September 1, 2007 to February 29,2008. The fair value of these contracts at December 31, 2007 was $1million. Changes in fair value are included in marketing and other in theConsolidated Statement of Income.

 

**Other**

 

Theforeign exchange gains or losses related to our designated debt are included inaccumulated other comprehensive income in shareholders’ equity. Our netinvestment in self-sustaining foreign operations and our designated US-dollardebt at December 31 are as follows:

 
| **(US$ millions)**                              | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------------------------|------------|----------|------------|----------|------------|
| Net Investment in Self-Sustaining Foreign Operations |       | 4,667    |       | 4,534    |       |
| Designated US-Dollar Debt                            |       | 4,414    |       | 3,761    |       |

 

Wealso have small exposures to currencies other than the US dollar. A portion ofour United Kingdom operating expenses, capital spending and future assetretirement obligations are denominated in British pounds and Euros. We do nothave any material exposure to highly inflationary foreign currencies.

 

**TradingActivities**

 

Oursales and purchases of crude oil and natural gas are generally transacted in orreferenced to the US dollar, as are most of the financial commodity contractsused by our marketing group. However, we pay for many of our purchases inCanadian dollars. We enter into US-dollar forward contracts and swaps to managethis exposure. Losses of $9 million on our US-dollar forward contracts andswaps at December 31, 2007 (December 31, 2006—$12 million loss) areincluded in the Consolidated Balance Sheet. Any change in fair value isincluded in marketing and other in the Consolidated Statement of Income.

 

**(d) Total carrying value of derivative contracts relatedto trading activities**

 

Amountsrelated to derivative instruments held by our marketing operation are equal tofair value as we use mark-to-market accounting, and are as follows at December 31:

 
| ** **                                                | ** ** | **2007** | ** ** | **2006** | ** ** |
|-----------------------------------------------------------|------------|----------|------------|----------|------------|
| Accounts Receivable                                       |       | 334      |       | 731      |       |
| Deferred Charges and Other Assets (1) (Note 10)      |       | 248      |       | 153      |       |
| **Total Derivative Contract Assets**                      | ** ** | **582**  | ** ** | **884**  | ** ** |
|                                                      |       |     |       |     |       |
| Accounts Payable and Accrued Liabilities                  |       | 413      |       | 325      |       |
| Deferred Credits and Other Liabilities (1) (Note 11) |       | 163      |       | 199      |       |
| **Total Derivative Contract Liabilities**                 | ** ** | **576**  | ** ** | **524**  | ** ** |
|                                                      |       |     |       |     |       |
| **Total Derivative Contract Net Assets (2)**              | ** ** | **6**    | ** ** | **360**  | ** ** |

 

----

*Notes:*

*(1)*       *These derivative instrumentssettle beyond twelve months and are considered non-current.*

*(2)*       *Comprised of $15 million(2006—$372 million) related to commodity contracts and losses of $9 million(2006—$12 million loss) related to US-dollar forward contracts and swaps.*

 

Ourexchange-traded derivative contracts are subject to margin requirements. Wehave margin deposits of $203 million (December 31, 2006—$197 million),which have been included in restricted cash and margin deposits on ourConsolidated Balance Sheet at December 31, 2007.

 

96

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**(e) Interest rate risk management**

 

Weuse fixed and floating rate debt to finance our operations. The floating ratedebt exposes us to changes in interest payments as interest rates fluctuate. Wemanage this exposure by maintaining a combination of fixed and floating rateborrowings and facilities. At December 31, 2007, fixed-rate borrowingscomprised 91% (2006—73%) of our long-term debt at an effective average rate of6.3% (2006—6.3%). During the year, we periodically drew on our floating-rateterm credit facilities. The average interest rate for our floating rateborrowings was 5.8% for the year (2006—5.7%).

 

**(f) Credit risk management**

 

Asubstantial portion of our accounts receivable are with counterparties in theenergy industry and are subject to normal industry credit risk. Thisconcentration of risk within the energy industry is reduced because of ourbroad base of domestic and international counterparties. We assess thefinancial strength of our counterparties, including those involved in marketingand other commodity arrangements, and we limit the total exposure to individualcounterparties. As well, a number of our contracts contain provisions thatallow us to demand the posting of collateral in the event of a downgrade to anon-investment grade credit rating occurs. Credit risk, including creditconcentrations, is routinely reported to our Risk Management Committee. We alsouse standard agreements that allow for the netting of exposures associated witha single counterparty. We believe this minimizes our overall credit risk. At December 31,2007, over 96% of our credit exposures were investment grade quality and onlythree counterparties individually made up more than 5% of our credit exposure.

 

**8.****             ****LONG-TERMDEBT AND SHORT-TERM BORROWINGS**

 
| ** **                                             | ** ** | **2007**  | ** ** | **2006**  | ** ** |
|--------------------------------------------------------|------------|-----------|------------|-----------|------------|
| Canexus LP Term Credit Facilities (US$204 million) (a) |       | 202       |       | 174       |       |
| Term Credit Facilities (US$214 million) (b)            |       | 211       |       | 1,078     |       |
| Medium-Term Notes, due 2007 (c)                        |       | —    |       | 150       |       |
| Medium-Term Notes, due 2008 (d)                        |       | 125       |       | 125       |       |
| Notes, due 2013 (US$500 million) (e)                   |       | 494       |       | 583       |       |
| Notes, due 2015 (US$250 million) (f)                   |       | 247       |       | 291       |       |
| Notes, due 2017 (US$250 million) (g)                   |       | 247       |       | —    |       |
| Notes, due 2028 (US$200 million) (h)                   |       | 198       |       | 233       |       |
| Notes, due 2032 (US$500 million) (i)                   |       | 494       |       | 583       |       |
| Notes, due 2035 (US$790 million) (j)                   |       | 781       |       | 920       |       |
| Notes, due 2037 (US$1,250 million) (k)                 |       | 1,235     |       | —    |       |
| Subordinated Debentures, due 2043 (US$460 million) (l) |       | 454       |       | 536       |       |
| ** **                                             | ** ** | **4,688** | ** ** | **4,673** | ** ** |
| Unamortized Debt Issue Costs (Note 1(u))               |       | (78       | )          | —    |       |
| **Total**                                              | ** ** | **4,610** | ** ** | **4,673** | ** ** |

 

**(a) Canexus LP term credit facilities**

 

CanexusLP has $350 million of committed, secured term credit facilities, which areavailable until 2010. At December 31, 2007, $202 million (US$204 million)was drawn on these facilities (2006—$174 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). The credit facility also contains covenants with respect tocertain financial ratios. During 2007, the weighted-average interest rate onthe Canexus LP term credit facilities was 6.1% (2006—5.9%).

 

**(b) Term credit facilities**

 

Wehave unsecured term credit facilities of US$3 billion, which are availableuntil 2012. At December 31, 2007, $211 million (US$214 million) was drawnon these facilities (2006—$1,078 million). 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 atfloating rates. During 2007, the weighted-average interest rate was 5.8% (2006—5.7%).At December 31, 2007, $283 million of these facilities were utilized tosupport outstanding letters of credit (December 31, 2006—$294 million ).

 

97

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**(c) Medium-term notes, due 2007**

 

DuringJuly 1997, we issued $150 million of notes with interest payablesemi-annually at a rate of 6.45%. The principal of $150 million was repaid infull in July 2007.

 

**(d) Medium-term notes, due 2008**

 

DuringOctober 1997, we issued $125 million of notes. Interest is payablesemi-annually at a rate of 6.3%, and the principal is to be repaid in June 2008.Amounts due June 2008 have not been included in current liabilities as weexpect to repay this amount using our term credit facilities.

 

**(e) Notes, due 2013**

 

DuringNovember 2003, we issued US$500 million of notes. Interest is payablesemi-annually at a rate of 5.05%, and the principal is to be repaid in November 2013.We may redeem part or all of the notes at any time. The redemption price willbe the greater of par and an amount that provides the same yield as a USTreasury security having a term to maturity equal to the remaining term of thenotes plus 0.2%.

 

**(f) Notes, due 2015**

 

DuringMarch 2005, we issued US$250 million of notes. Interest is payablesemi-annually at a rate of 5.2%, and the principal is to be repaid in March 2015.We may redeem part or all of the notes at any time. The redemption price willbe the greater of par and an amount that provides the same yield as a USTreasury security having a term to maturity equal to the remaining term of thenotes plus 0.15%.

 

**(g) Notes, due 2017**

 

DuringMay 2007, we issued US$250 million of notes. Interest is payable semi-annuallyat a rate of 5.65%, and the principal is to be repaid in May 2017. We mayredeem part or all of the notes at any time. The redemption price will be thegreater of par and an amount that provides the same yield as a US Treasurysecurity having a term to maturity equal to the remaining term of the notesplus 0.2%. The proceeds were used to repay outstanding term credit facilities.

 

**(h) Notes, due 2028**

 

DuringApril 1998, we issued US$200 million of notes. Interest is payablesemi-annually at a rate of 7.4%, and the principal is to be repaid in May 2028.We may redeem part or all of the notes at any time. The redemption price willbe the greater of par and an amount that provides the same yield as a USTreasury security having a term to maturity equal to the remaining term of thenotes plus 0.25%.

 

**(i) Notes, due 2032**

 

DuringMarch 2002, we issued US$500 million of notes. Interest is payablesemi-annually at a rate of 7.875%, and the principal is to be repaid in March 2032.We may redeem part or all of the notes at any time. The redemption price willbe the greater of par and an amount that provides the same yield as a USTreasury security having a term to maturity equal to the remaining term of thenotes plus 0.375%.

 

**(j) Notes, due 2035**

 

DuringMarch 2005, we issued US$790 million of notes. Interest is payablesemi-annually at a rate of 5.875%, and the principal is to be repaid in March 2035.We may redeem part or all of the notes at any time. The redemption price willbe the greater of par and an amount that provides the same yield as a USTreasury security having a term to maturity equal to the remaining term of thenotes plus 0.2%.

 

**(k) Notes, due 2037**

 

DuringMay 2007, we issued US$1,250 million of notes. Interest is payablesemi-annually at a rate of 6.4%, and the principal is to be repaid in May 2037.We may redeem part or all of the notes at any time. The redemption price willbe the greater of par and an amount that provides the same yield as a USTreasury security having a term to maturity equal to the remaining term of thenotes plus 0.35%. The proceeds were used to repay outstanding term creditfacilities.

 

**(l) Subordinated debentures, due 2043**

 

DuringNovember 2003, we issued US$460 million of unsecured subordinateddebentures. Interest is payable quarterly at a rate of 7.35%, and the principalis to be repaid in November 2043. We may redeem part or all of thedebentures at any time on or after November 8, 2008. The redemption priceis equal to the par value of the principal amount plus any accrued and unpaidinterest to the redemption date. We may choose to redeem the principal amountwith either cash or common shares.

 

**(m) Long-term debt repayments**

 
| 2008       |       | 125       |       |
|------------|------------|-----------|------------|
| 2009       |       | —    |       |
| 2010       |       | 202       |       |
| 2011       |       | —    |       |
| 2012       |       | 211       |       |
| Thereafter |       | 4,150     |       |
| **Total**  | ** ** | **4,688** | ** ** |

 

98

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**(n) Debt covenants**

 

Someof our debt instruments contain covenants with respect to certain financialratios and our ability to grant security. At December 31, 2007, we were incompliance with all covenants.

 

**(o) Short-term borrowings**

 

Nexenhas uncommitted, unsecured credit facilities of approximately $665 million,none of which were drawn at December 31, 2007 (2006—$158 million). We havealso utilized $196 million of these facilities to support outstanding lettersof credit at December 31, 2007 (2006—$252 million). Interest is payable atfloating rates. During 2007, the weighted-average interest rate on our short-termborrowings was 5.8% (2006—5.5%).

 

**(p) Interest expense**

 
| ** **                 | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|----------------------------|------------|----------|------------|----------|------------|----------|------------|
| Long-Term Debt             |       | 323      |       | 275      |       | 260      |       |
| Other                      |       | 18       |       | 19       |       | 15       |       |
| Total                      |       | 341      |       | 294      |       | 275      |       |
| Less: Capitalized          |       | (173     | )          | (241     | )          | (178     | )          |
| **Total Interest Expense** | ** ** | **168**  | ** ** | **53**   | ** ** | **97**   | ** ** |

 

Capitalizedinterest relates to and is included as part of the cost of oil and gas andSyncrude properties. The capitalization rates are based on our weighted-averagecost of borrowings.

 

**9.****             ****ASSETRETIREMENT OBLIGATIONS**

 

Changesin carrying amounts of the asset retirement obligations associated with ourPP&E are as follows:

 
| ** **                                       | ** ** | **2007** | ** ** | **2006** | ** ** |
|--------------------------------------------------|------------|----------|------------|----------|------------|
| Balance at Beginning of Year                     |       | 704      |       | 611      |       |
| Obligations Incurred with Development Activities |       | 105      |       | 75       |       |
| Obligations Discharged with Disposed Properties  |       | —   |       | (1       | )          |
| Expenditures Made on Asset Retirements           |       | (23      | )          | (44      | )          |
| Accretion                                        |       | 44       |       | 37       |       |
| Revisions to Estimates                           |       | 79       |       | (10      | )          |
| Effects of Foreign Exchange                      |       | (77      | )          | 36       |       |
| **Balance at End of Year (1), (2)**              | ** ** | **832**  | ** ** | **704**  | ** ** |

 

----

*Notes:*

*(1)*       *Obligations due within twelvemonths of $40 million (2006—$21 million) have been included in accounts payableand accrued liabilities.*

*(2)*       *Obligations relating to our oiland gas activities amount to $786 million (2006—$658 million) and obligationsrelating to our chemicals business amount to $46 million (2006—$46 million).*

 

Ourtotal estimated undiscounted inflated asset retirement obligations amount to$2,165 million. We have discounted the total estimated asset retirementobligations using a weighted-average, credit-adjusted risk-free rate of 5.9%.Approximately $137 million included in our asset retirement obligations will besettled over the next five years. The remaining obligations settle beyond fiveyears and will be funded by future cash flows from our operations.

 

Weown interests in assets for which the fair value of the asset retirementobligations cannot be reasonably determined because the assets currently havean indeterminate life and we cannot determine when remediation activities wouldtake place. These assets include our interest in Syncrude’s upgrader andsulphur pile. The estimated future recoverable reserves at Syncrude aresignificant and given the long life of this asset, we are unable to determinewhen asset retirement activities would take place. Furthermore, the Syncrudeplant can continue to run indefinitely with ongoing maintenance activities. Theretirement obligations for these assets will be recorded in the first year inwhich the lives of the assets are determinable.

 

99

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**10.  DEFERREDCHARGES AND OTHER ASSETS**

 
| ** **                                         | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------------------------------|------------|----------|------------|----------|------------|
| Long-Term Marketing Derivative Contracts (Note 7d) |       | 248      |       | 153      |       |
| Deferred Financing Costs (Note 1(u))               |       | —   |       | 59       |       |
| Asset Retirement Remediation Fund                  |       | 13       |       | 13       |       |
| Crude Oil Put Options (Note 7b)                    |       | —   |       | 19       |       |
| Other                                              |       | 63       |       | 74       |       |
| **Total**                                          | ** ** | **324**  | ** ** | **318**  | ** ** |

 

**11.  DEFERREDCREDITS AND OTHER LIABILITIES**

 
| ** **                                         | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------------------------------|------------|----------|------------|----------|------------|
| Long-Term Marketing Derivative Contracts (Note 7d) |       | 163      |       | 199      |       |
| Deferred Transportation Revenue                    |       | 82       |       | 89       |       |
| Fixed-Price Natural Gas Contracts (Note 7b)        |       | 48       |       | 74       |       |
| Defined Benefit Pension Obligations (Note 16)      |       | 57       |       | 48       |       |
| Capital Lease Obligations                          |       | 52       |       | 48       |       |
| Other                                              |       | 57       |       | 58       |       |
| **Total**                                          | ** ** | **459**  | ** ** | **516**  | ** ** |

 

**12.  SHAREHOLDERS’EQUITY**

 

**(a)****         ****Authorizedcapital**

 

Authorizedshare capital consists of an unlimited number of common shares of no par value,and an unlimited number of Class A preferred shares of no par value,issuable in series.

 

Ourshareholders approved a split of our issued and outstanding common shares on atwo-for-one basis at our annual and special meeting on April 26, 2007. Allcommon shares, per common share amounts, tandem options and stock appreciationrights together with their related weighted-average exercise prices, have beenrestated to retroactively reflect the share split.

 

**(b) Issued common shares and dividends**

 
| **(thousands of shares)**              | ** ** | **2007**    | ** ** | **2006**    | ** ** | **2005**    | ** ** |
|--------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|
| Beginning of Year                                |       | 525,026     |       | 522,281     |       | 516,798     |       |
| Issue of Common Shares for Cash                  |       |        |       |        |       |        |       |
| Exercise of Tandem Options                       |       | 2,257       |       | 1,693       |       | 3,647       |       |
| Dividend Reinvestment Plan                       |       | 523         |       | 552         |       | 1,210       |       |
| Employee Flow-through Shares                     |       | 499         |       | 500         |       | 626         |       |
| **End of Year**                                  | ** ** | **528,305** | ** ** | **525,026** | ** ** | **522,281** | ** ** |
| ** **                                       | ** ** | ** **  | ** ** | ** **  | ** ** | ** **  | ** ** |
| **Dividends Declared per Common Share**($/share) | ** ** | **0.10**    | ** ** | **0.10**    | ** ** | **0.10**    | ** ** |
| **Cash Consideration**(Cdn$ millions)       |       |        |       |        |       |        |       |
| Exercise of Tandem Options                       |       | 24          |       | 16          |       | 29          |       |
| Dividend Reinvestment Plan                       |       | 16          |       | 16          |       | 20          |       |
| Employee Flow-through Shares                     |       | 16          |       | 16          |       | 9           |       |
| ** **                                       | ** ** | **56**      | ** ** | **48**      |       | **58**      |       |

 

Duringthe year we increased the number of common shares reserved under the DividendReinvestment Plan by 4 million shares. At December 31, 2007, there were4,475,095 common shares (2006—997,662; 2005—1,549,830) reserved for issuance underthe Dividend Reinvestment Plan. Dividends paid to holders of common shares havebeen designated as “eligible dividends” for Canadian tax purposes.

 

100

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**(c)****         ****Tandemoptions**

 

Wehave granted tandem options to purchase common shares to directors, officersand employees. Each tandem option permits the holder to purchase one Nexencommon share at the exercise price or to receive cash payments equal to theexcess of the market value of the common shares over the exercise price. Optionsgranted prior to February 2001 vest over four years and are exercisable ona cumulative basis over 10 years. Options granted after February 2001 vestover three years and are exercisable on a cumulative basis over five years. Atthe time of grant, the exercise price equals the market price.

 

Followingthe introduction of the *American JobCreation Act of 2004*in the US, stock options awarded to our USemployees between December 1, 2004 and December 1, 2005 did notinclude a tandem option cash feature. We use the fair-value method to recognizecompensation expense associated with these options. The expense is recognizedover the vesting period of the options with a corresponding increase tocontributed surplus. This resulted in compensation expense in 2007 of $1million (2006—$2 million; 2005—$2 million), which was included in general andadministrative expense. In 2005, US tax regulations were modified and as aresult, tandem options have been issued to our US employees after December 1,2005. These options are expensed using the intrinsic-method.

 

Thefollowing options have been granted:

 
| ** **                                                       | ** ** | **2007**        | ** ** | **2006**       | ** ** | **2005**        | ** ** |
|------------------------------------------------------------------|------------|-----------------|------------|----------------|------------|-----------------|------------|
| ** **                                                       | ** ** | ** **      | ** ** | **Weighted**   | ** ** | ** **      | ** ** | **Weighted** | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **                                                       | ** ** | ** **      | ** ** | **Average**    | ** ** | ** **      | ** ** | **Average** | ** ** | ** ** | ** ** | **Average** | ** ** |
| ** **                                                       | ** ** | ** **      | ** ** | **Exercise**   | ** ** | ** **      | ** ** | **Exercise** | ** ** | ** ** | ** ** | **Exercise** | ** ** |
| ** **                                                       | ** ** | **Options**     | ** ** | **Price**      | ** ** | **Options**     | ** ** | **Price** | ** ** | **Options** | ** ** | **Price** | ** ** |
| ** **                                                       | ** ** | **(thousands)** | ** ** | **($/option)** | ** ** | **(thousands)** | ** ** | **($/option)** | ** ** | **(thousands)** | ** ** | **($/option)** | ** ** |
| Balance at Beginning of Year                                     |       | 30,485          |       | 17             |       | 30,629          |       | 14 |   | 32,553 |   | 10 |   |
| Granted                                                          |       | 4,007           |       | 28             |       | 4,802           |       | 32 |   | 6,783 |   | 27 |   |
| Exercised for Stock                                              |       | (2,257          | )          | 10             |       | (1,693          | )          | 9 |   | (3,647 | ) | 8 |   |
| Surrendered for Cash                                             |       | (4,414          | )          | 11             |       | (3,043          | )          | 9 |   | (4,178 | ) | 9 |   |
| Forfeited                                                        |       | (418            | )          | 22             |       | (210            | )          | 19 |   | (882 | ) | 11 |   |
| **Balance at End of Year**                                       | ** ** | **27,403**      | ** ** | **20**         | ** ** | **30,485**      | ** ** | **17** | ** ** | **30,629** | ** ** | **14** | ** ** |
|                                                             |       |            |       |           |       |            |       |   |   |   |   |   |   |
| Options Exercisable at End of Year                               |       | 18,216          |       | 16             |       | 18,691          |       | 12 |   | 16,262 |   | 9 |   |
| Common Shares Reserved for Issuance Under the Tandem Option Plan |       | 29,430          |       |           |       | 32,470          |       |   |   | 34,580 |   |   |   |

 

Therange of exercise prices of options outstanding and exercisable at December 31,2007 is as follows:

 
| ** **        | ** ** | **Outstanding Options** | ** ** | **Exercisable Options** | ** ** |
|-------------------|------------|------------------------------|------------|------------------------------|------------|
| ** **        | ** ** | ** **                   | ** ** | **Weighted**                 | ** ** | **Weighted** | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **        | ** ** | ** **                   | ** ** | **Average**                  | ** ** | **Average** | ** ** | ** ** | ** ** | **Average** | ** ** |
| ** **        | ** ** | **Number of**           | ** ** | **Exercise**                 | ** ** | **Years** | ** ** | **Number of** | ** ** | **Exercise** | ** ** |
| ** **        | ** ** | **Options**                  | ** ** | **Price**                    | ** ** | **to Expiry** | ** ** | **Options** | ** ** | **Price** | ** ** |
| ** **        | ** ** | **(thousands)**              | ** ** | **($/option)**               | ** ** | **(years)** | ** ** | **(thousands)** | ** ** | **($/option)** | ** ** |
| To $4.99          |       | 348                          |       | 4                            |       | 1 |   | 348 |   | 4 |   |
| $5.00 to $9.99    |       | 3,807                        |       | 8                            |       | 3 |   | 3,807 |   | 8 |   |
| $10.00 to $14.99  |       | 8,529                        |       | 12                           |       | 2 |   | 8,508 |   | 12 |   |
| $15.00 to $19.99  |       | 15                           |       | 19                           |       | 3 |   | 9 |   | 19 |   |
| $20.00 to $24.99  |       | 1,054                        |       | 23                           |       | 3 |   | 664 |   | 23 |   |
| $25.00 to $29.99  |       | 9,549                        |       | 28                           |       | 4 |   | 3,510 |   | 27 |   |
| $30.00 to $34.99  |       | 4,081                        |       | 32                           |       | 4 |   | 1,370 |   | 32 |   |
| $35.00 to $39.99  |       | 20                           |       | 36                           |       | 4 |   | — |   | — |   |
| **Total Options** | ** ** | **27,403**                   | ** ** | ** **                   |       |   |   | **18,216** |   |   |   |

 

101

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**(d) Stock appreciation rights**

 

Underour stock appreciation rights (StARs) plan established in 2001, employees areentitled to cash payments equal to the excess of the market price of the commonshares over the exercise price of the right. The vesting period and other termsof the plan are similar to the tandem option plan. The total rights granted andoutstanding at any time cannot exceed 10% of Nexen’s total outstanding commonshares. At the time of grant, the exercise price equals the market price. Thefollowing stock appreciation rights have been granted:

 
| ** **                       | ** ** | **2007**        | ** ** | **2006**     | ** ** | **2005**        | ** ** |
|----------------------------------|------------|-----------------|------------|--------------|------------|-----------------|------------|
| ** **                       | ** ** | ** **      | ** ** | **Weighted** | ** ** | ** **      | ** ** | **Weighted** | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **                       | ** ** | ** **      | ** ** | **Average**  | ** ** | ** **      | ** ** | **Average** | ** ** | ** ** | ** ** | **Average** | ** ** |
| ** **                       | ** ** | ** **      | ** ** | **Exercise** | ** ** | ** **      | ** ** | **Exercise** | ** ** | ** ** | ** ** | **Exercise** | ** ** |
| ** **                       | ** ** | **StARs**       | ** ** | **Price**    | ** ** | **StARs**       | ** ** | **Price** | ** ** | **StARs** | ** ** | **Price** | ** ** |
| ** **                       | ** ** | **(thousands)** | ** ** | **($/StAR)** | ** ** | **(thousands)** | ** ** | **($/StAR)** | ** ** | **(thousands)** | ** ** | **($/StAR)** | ** ** |
| Balance at Beginning of Year     |       | 13,890          |       | 21           |       | 11,928          |       | 15 |   | 12,871 |   | 11 |   |
| Granted                          |       | 4,195           |       | 29           |       | 4,509           |       | 32 |   | 2,886 |   | 27 |   |
| Exercised for Cash               |       | (2,349          | )          | 12           |       | (2,165          | )          | 10 |   | (2,909 | ) | 9 |   |
| Forfeited                        |       | (301            | )          | 26           |       | (382            | )          | 19 |   | (920 | ) | 12 |   |
| **Balance at end of year**       | ** ** | **15,435**      | ** ** | **24**       | ** ** | **13,890**      | ** ** | **21** | ** ** | **11,928** | ** ** | **15** | ** ** |
|                             |       |            |       |         |       |            |       |   |   |   |   |   |   |
| StARs Exercisable at End of Year |       | 7,525           |       | 19           |       | 6,151           |       | 13 |   | 4,852 |   | 10 |   |

 

Therange of exercise prices of StARs outstanding and exercisable at December 31,2007 is as follows:

 
| ** **       | ** ** | **Outstanding StARs** | ** ** | **Exercisable StARs** | ** ** |
|------------------|------------|----------------------------|------------|----------------------------|------------|
| ** **       | ** ** | ** **                 | ** ** | **Weighted**               | ** ** | **Weighted** | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **       | ** ** | ** **                 | ** ** | **Average**                | ** ** | **Average** | ** ** | ** ** | ** ** | **Average** | ** ** |
| ** **       | ** ** | **Number of**         | ** ** | **Exercise**               | ** ** | **Years to** | ** ** | **Number of** | ** ** | **Exercise** | ** ** |
| ** **       | ** ** | **StARs**                  | ** ** | **Price**                  | ** ** | **Expiry** | ** ** | **StARs** | ** ** | **Price** | ** ** |
| ** **       | ** ** | **(thousands)**            | ** ** | **($/StAR)**               | ** ** | **(years)** | ** ** | **(thousands)** | ** ** | **($/StAR)** | ** ** |
| $5.00 to $9.99   |       | 160                        |       | 8                          |       | 1 |   | 160 |   | 8 |   |
| $10.00 to $14.99 |       | 4,305                      |       | 12                         |       | 2 |   | 4,301 |   | 12 |   |
| $15.00 to $19.99 |       | 45                         |       | 17                         |       | 2 |   | 25 |   | 17 |   |
| $20.00 to $24.99 |       | 81                         |       | 23                         |       | 3 |   | 50 |   | 23 |   |
| $25.00 to $29.99 |       | 6,914                      |       | 28                         |       | 4 |   | 1,718 |   | 27 |   |
| $30.00 to $34.99 |       | 3,883                      |       | 32                         |       | 4 |   | 1,271 |   | 32 |   |
| $35.00 to $39.99 |       | 47                         |       | 36                         |       | 4 |   | — |   | — |   |
| **Total StARs**  | ** ** | **15,435**                 | ** ** | ** **                 |       |   |   | **7,525** |   |   |   |

 

**13.  EARNINGS PER COMMON SHARE**

 

Wecalculate basic earnings per common share from continuing operations using netincome from continuing operations divided by the weighted-average number ofcommon shares outstanding. We calculate basic earnings per common share usingnet income and the weighted-average number of common shares outstanding. Wecalculate diluted earnings per common share from continuing operations anddiluted earnings per common share in the same manner as basic, except we usethe weighted-average number of diluted common shares outstanding in thedenominator.

 
| **(millions of shares)**                                | ** ** | **2007**  | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|-------------------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Weighted-Average Number of Common Shares Outstanding              |       | 527.1     |       | 524.2     |       | 520.7     |       |
| Shares Issuable Pursuant to Tandem Options                        |       | 26.6      |       | 27.7      |       | 26.8      |       |
| Shares to be Purchased from Proceeds of Tandem Options            |       | (15.7     | )          | (14.0     | )          | (14.8     | )          |
| **Weighted-Average Number of Diluted Common Shares  Outstanding** | ** ** | **538.0** | ** ** | **537.9** | ** ** | **532.7** | ** ** |

 

Incalculating the weighted-average number of diluted common shares outstandingfor the year ended December 31, 2007, we excluded 49,333 options(2006—422,566; 2005—561,416), because their exercise price was greater than theannual average common share market price in those periods. During the lastthree years, outstanding tandem options were the only potential dilutiveinstruments.

 

102

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** **

**14. DISCONTINUEDOPERATIONS**

 

Inthe third quarter of 2005, we sold certain Canadian conventional oil and gasproperties in southeast Saskatchewan, northwest Saskatchewan, northeast BritishColumbia and the Alberta foothills. The results of operations of theseproperties have been presented as discontinued operations. The sales closed inthe third quarter of 2005 with net proceeds of $900 million after closingadjustments, and we realized gains of $225 million. These gains are net oflosses attributable to pipeline contracts and fixed-price gas sales contractsassociated with these properties that we have retained, but no longer use inconnection with our oil and gas business.

 

Theresults of operations from these properties in Canada are detailed below and shownas discontinued operations in our Consolidated Statement of Income.

 
| ** **                                           | ** ** | **2005** | ** ** |
|------------------------------------------------------|------------|----------|------------|
| Revenues and Other Income                            |       |     |       |
| Net Sales                                            |       | 154      |       |
| Gain on Disposition of Assets                        |       | 225      |       |
|                                                 |       | 379      |       |
| Expenses                                             |       |     |       |
| Operating                                            |       | 27       |       |
| Depreciation, Depletion, Amortization and Impairment |       | 28       |       |
| Exploration Expense                                  |       | 1        |       |
| Income before Income Taxes                           |       | 323      |       |
| Recovery of Future Income Taxes                      |       | (129     | )          |
| **Net Income from Discontinued Operations**          | ** ** | **452**  | ** ** |
| **Earnings per Common Share**($/share)               |       |     |       |
| Basic (Note 13)                                      |       | 0.87     |       |
| Diluted (Note 13)                                    |       | 0.85     |       |

 

Therewere no assets and liabilities related to discontinued operations as at December 31,2007 and 2006.

 

**15. COMMITMENTS, CONTINGENCIES AND GUARANTEES**

 
| ** **                             | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** | **Thereafter** | ** ** |
|----------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|
| Operating Leases                       |       | 76       |       | 102      |       | 99       |       | 92       |       | 84       |       | 157            |       |
| Transportation and Storage Commitments |       | 368      |       | 153      |       | 118      |       | 89       |       | 62       |       | 132            |       |
| Drilling Rig Commitments               |       | 107      |       | 98       |       | 187      |       | 276      |       | 153      |       | —         |       |
| ** **                             | ** ** | **551**  | ** ** | **353**  | ** ** | **404**  | ** ** | **457**  | ** ** | **299**  | ** ** | **289**        | ** ** |

 

Wehave a number of lawsuits and claims pending including income tax reassessments(see Note 18), for which we currently cannot determine the ultimate result. Werecord costs as they are incurred or become determinable. We believe theresolution of these matters would not have a material adverse effect on ourliquidity, consolidated financial position or results of operations.

 

During2007, total rental expense was $53 million (2006—$49 million; 2005—$47million).

 

Fromtime to time, we enter into certain types of contracts that require us toindemnify parties against possible third-party claims, particularly when thesecontracts relate to divestiture transactions. On occasion, we may provideroutine indemnifications. The terms of such obligations vary, and generally, amaximum is not explicitly stated. Because the obligations in these agreementsare often not explicitly stated, the overall maximum amount of the obligationscannot be reasonably estimated. Historically, we have not been obligated tomake significant payments for these obligations. We believe that payments, ifany, related to existing indemnities, would not have a material adverse effecton our liquidity, financial condition or results of operations.

 

103

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**16. PENSIONAND OTHER POST-RETIREMENT BENEFITS**

 

Nexenand Canexus have contributory and non-contributory defined benefit and definedcontribution pension plans, which together cover substantially all employees.Syncrude has a defined benefit plan for its employees, and we disclose only ourproportionate share of this plan. Under the defined benefit plans, we providebenefits to retirees based on their length of service and final averageearnings. Benefits paid out of Nexen’s defined benefit plan are indexed to 75%of the annual rate of inflation less 1%, to a maximum increase of 5%.

 

**(a) Defined benefit pension plans**

 

Thecost of pension benefits earned by employees is determined using theprojected-benefit method prorated on employment services and is expensed asservices are rendered. We fund these plans according to federal and provincialgovernment regulations by contributing to trust funds administered by anindependent trustee. These funds are invested primarily in equities and bonds.

 
| ** **                                         | ** ** | **2007**  | ** ** | **2006**    | ** ** |
|----------------------------------------------------|------------|-----------|------------|-------------|------------|
| ** **                                         | ** ** | **Nexen** | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** | **Nexen** | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** |
|                                               |       |      |       |        |       |   |   |   |   |   |   |   |   |
| **Change in Projected Benefit Obligation (PBO)**   |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Beginning of Year                                  |       | 252       |       | 58          |       | 116 |   | 223 |   | 49 |   | 109 |   |
| Service Cost                                       |       | 18        |       | 3           |       | 5 |   | 16 |   | 3 |   | 5 |   |
| Interest Cost                                      |       | 13        |       | 3           |       | 6 |   | 12 |   | 3 |   | 5 |   |
| Plan Participants’Contributions               |       | 4         |       | 1           |       | 1 |   | 3 |   | 1 |   | 1 |   |
| Actuarial Loss/(Gain)                              |       | (2        | )          | (3          | )          | 1 |   | 9 |   | 2 |   | — |   |
| Benefits Paid                                      |       | (13       | )          | —      |       | (4 | ) | (11 | ) | — |   | (4 | ) |
| **End of Year (1)**                                | ** ** | **272**   | ** ** | **62**      | ** ** | **125** | ** ** | **252** | ** ** | **58** | ** ** | **116** | ** ** |
| **Change in Fair Value of Plan Assets**            |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Beginning of Year                                  |       | 185       |       | 50          |       | 69 |   | 146 |   | 40 |   | 58 |   |
| Actual Return on Plan Assets                       |       | 18        |       | 1           |       | 2 |   | 23 |   | 6 |   | 8 |   |
| Employer’s Contribution                       |       | 6         |       | 3           |       | 6 |   | 24 |   | 3 |   | 5 |   |
| Plan Participants’Contributions               |       | 4         |       | 1           |       | 1 |   | 3 |   | 1 |   | 1 |   |
| Benefits Paid                                      |       | (13       | )          | —      |       | (4 | ) | (11 | ) | — |   | (3 | ) |
| **End of Year**                                    | ** ** | **200**   | ** ** | **55**      | ** ** | **74** | ** ** | **185** | ** ** | **50** | ** ** | **69** | ** ** |
| **Reconciliation of Funded Status**                |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Funded Status (2)                                  |       | (72       | )          | (7          | )          | (51 | ) | (67 | ) | (8 | ) | (47 | ) |
| Unamortized Transitional Obligation                |       | —    |       | —      |       | — |   | — |   | — |   | — |   |
| Unamortized Prior Service Costs                    |       | 2         |       | —      |       | — |   | 3 |   | — |   | — |   |
| Unamortized Net Actuarial Loss                     |       | 31        |       | 6           |       | 36 |   | 39 |   | 7 |   | 32 |   |
| **Pension Liability**                              | ** ** | **(39**   | **)**      | **(1**      | **)**      | **(15** | **)** | **(25** | **)** | **(1** | **)** | **(15** | **)** |
| **Pension Liability Recognized**                   |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Deferred Charges and Other Assets                  |       | 4         |       | —      |       | — |   | 10 |   | — |   | — |   |
| Accounts Payable and Accrued Liabilities           |       | (2        | )          | —      |       | — |   | (1 | ) | — |   | (2 | ) |
| Other Deferred Credits and Liabilities (Note 11)   |       | (41       | )          | (1          | )          | (15 | ) | (34 | ) | (1 | ) | (13 | ) |
| **Pension Liability**                              | ** ** | **(39**   | **)**      | **(1**      | **)**      | **(15** | **)** | **(25** | **)** | **(1** | **)** | **(15** | **)** |
| Assumptions (%)                                    |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Accrued Benefit Obligation at December 31     |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Discount Rate                                      |       | 5.25      |       | 5.25        |       | 5.25 |   | 5.00 |   | 5.00 |   | 5.00 |   |
| Long-Term Rate of Employee Compensation Increase   |       | 4.00      |       | 4.00        |       | 5.00 |   | 4.00 |   | 4.00 |   | 4.00 |   |
| Benefit Cost for Year Ended December 31 (3)   |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Discount Rate                                      |       | 5.00      |       | 5.00        |       | 5.25 |   | 5.25 |   | 5.25 |   | 5.00 |   |
| Long-Term Rate of Employee Compensation Increase   |       | 4.00      |       | 4.00        |       | 5.00 |   | 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)*  *Theaccumulated benefit obligations (the projected benefit obligation excludingfuture salary increases) of the Nexen and Canexus plans were $182 million and$47 million at December 31, 2007, respectively (2006—$180 million and $44million, respectively).  Nexen’s supplementalpension plan’s accumulated benefit obligation was $48 million at December 31,2007 (2006—$35 million).  Nexen’s shareof Syncrude’s employee pension plan’s accumulated benefit obligation was $92million at December 31, 2007 (2006—$89 million).*

*(2)*  *Includesunfunded obligations for supplemental benefits to the extent that the benefitis limited by statutory guidelines.  At December 31,2007, the PBO for Nexen’s supplemental benefits was $62 million (2006—$53million) and $1 million for Canexus (2006—$1million)*

*(3)*  *Theassumptions have been used to calculate the recognized expense for Nexen andCanexus. There were no changes to the assumptions between the measurement dateof October 31, 2007 and December 31, 2007. Syncrude’s measurementdate was December 31, 2007*

*(4)*  *Thelong-term annual rate of return on plan assets assumption is based on a mix ofhistorical market returns for debt and equity securities.*

 

104

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Net Pension ExpenseRecognized Under Our Defined Benefit Pension Plans

 
| ** **                                                                                    | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|-----------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| **Nexen**                                                                                     |       |       |       |       |       |       |       |
| Cost of Benefits Earned by Employees                                                          |       | 18         |       | 16         |       | 15         |       |
| Interest Cost on Benefits Earned                                                              |       | 13         |       | 12         |       | 12         |       |
| Actual Return on Plan Assets                                                                  |       | (18        | )          | (23        | )          | (18        | )          |
| Actuarial (Gains)/Losses                                                                      |       | (2         | )          | 9          |       | 33         |       |
| Pension Expense Before Adjustments for the Long-Term Nature of  Employee Future Benefit Costs |       | 11         |       | 14         |       | 42         |       |
| Difference Between Actual and Expected Return on Plan Assets                                  |       | 5          |       | 12         |       | 8          |       |
| Difference Between Actual and Recognized Actuarial Losses                                     |       | 3          |       | (7         | )          | (32        | )          |
| Difference Between Actual and Recognized Past Service Costs                                   |       | 1          |       | 1          |       | —     |       |
| **Net Pension Expense**                                                                       | ** ** | **20**     | ** ** | **20**     | ** ** | **18**     | ** ** |
| ** **                                                                                    |       |       |       |       |       |       |       |
| **Canexus**                                                                                   |       |       |       |       |       |       |       |
| Cost of Benefits Earned by Employees                                                          |       | 3          |       | 3          |       | 1          |       |
| Interest Cost on Benefits Earned                                                              |       | 3          |       | 3          |       | 1          |       |
| Actual Return on Plan Assets                                                                  |       | (2         | )          | (6         | )          | —     |       |
| Actuarial (Gains)/Losses                                                                      |       | (3         | )          | 2          |       | (2         | )          |
| Pension Expense Before Adjustments for the Long-Term Nature of  Employee Future Benefit Costs |       | 1          |       | 2          |       | —     |       |
| Difference Between Actual and Expected Return on Plan Assets                                  |       | (1         | )          | 3          |       | (1         | )          |
| Difference Between Actual and Recognized Actuarial Gains                                      |       | 3          |       | (2         | )          | 2          |       |
| Difference Between Actual and Recognized Past Service Costs                                   |       | —     |       | —     |       | —     |       |
| **Net Pension Expense**                                                                       | ** ** | **3**      | ** ** | **3**      | ** ** | **1**      | ** ** |
| ** **                                                                                    |       |       |       |       |       |       |       |
| **Syncrude**                                                                                  |       |       |       |       |       |       |       |
| Cost of Benefits Earned by Employees                                                          |       | 5          |       | 5          |       | 4          |       |
| Interest Cost on Benefits Earned                                                              |       | 6          |       | 5          |       | 5          |       |
| Actual Return on Plan Assets                                                                  |       | (2         | )          | (8         | )          | (6         | )          |
| Actuarial Losses                                                                              |       | 1          |       | —     |       | 11         |       |
| Pension Expense Before Adjustments for the Long-Term Nature of  Employee Future Benefit Costs |       | 10         |       | 2          |       | 14         |       |
| Difference Between Actual and Expected Return on Plan Assets                                  |       | (4         | )          | 3          |       | 2          |       |
| Difference Between Actual and Recognized Actuarial Losses                                     |       | 1          |       | 2          |       | (8         | )          |
| Difference Between Actual and Recognized Past Service Costs                                   |       | —     |       | —     |       | —     |       |
| **Net Pension Expense**                                                                       | ** ** | **7**      | ** ** | **7**      | ** ** | **8**      | ** ** |
| ** **                                                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Total Net Pension Expense**                                                                 | ** ** | **30**     | ** ** | **30**     | ** ** | **27**     | ** ** |

 

**(b) Planasset allocation at December 31**

 

Our investment goal for theassets in our defined benefit pension plans is to preserve capital and earn along-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-Canadian corporationsthat are traded on recognized stock exchanges. Allowable and prohibitedinvestment types are also prescribed in Nexen’s investment policies.

 

105

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Syncrude’s pension plan isgoverned and administered separately from ours. Syncrude’s investment assetsare subject to similar investment goals, policies and strategies.

 
| **(%)**           | ** ** | **Expected 2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|-------------------|------------|------------------------|------------|----------|------------|----------|------------|
| **Nexen**         |       |                   |       |     |       |     |       |
| Equity Securities |       | 64                     |       | 64       |       | 60       |       |
| Debt Securities   |       | 36                     |       | 36       |       | 40       |       |
| **Total**         | ** ** | **100**                | ** ** | **100**  | ** ** | **100**  | ** ** |
| ** **        |       |                   |       |     |       |     |       |
| **Canexus**       |       |                   |       |     |       |     |       |
| Equity Securities |       | 50                     |       | 50       |       | 60       |       |
| Debt Securities   |       | 50                     |       | 50       |       | 40       |       |
| **Total**         | ** ** | **100**                | ** ** | **100**  | ** ** | **100**  | ** ** |
| ** **        |       |                   |       |     |       |     |       |
| **Syncrude**      |       |                   |       |     |       |     |       |
| Equity Securities |       | 68                     |       | 68       |       | 70       |       |
| Debt Securities   |       | 32                     |       | 32       |       | 30       |       |
| **Total**         | ** ** | **100**                | ** ** | **100**  | ** ** | **100**  | ** ** |

 

**(c) Definedcontribution pension plans**

 

Under these plans, pensionbenefits are based on plan contributions. During 2007, Canadian pension expensefor these plans was $6 million (2006—$4 million; 2005—$4 million). During 2007,US pension expense for these plans was $4 million (2006—$4 million; 2005—$4million). During 2007, UK pension expense for these plans was $5 million(2006—$4 million; 2005—$2 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 at December 31,2007 was $10 million (2006— $6 million) and $1 million for Canexus (2006—$2million).

 

**(e) Employerfunding contributions and benefit payments**

 

Canadian regulators haveprescribed funding requirements for our defined benefit plans. Our fundingcontributions over the last three years have met these requirements and alsoincluded additional discretionary contributions permitted by law. For ourdefined contribution plans, we make contributions on behalf of our employeesand no further obligation exists. Our funding contributions for the definedbenefit plans are:

 
| **Defined Benefit Contributions** | ** ** | **Expected 2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|---------------------------------------------|------------|------------------------|------------|----------|------------|----------|------------|
| Nexen                                       |       | 11                     |       | 6        |       | 24       |       |
| Canexus                                     |       | 1                      |       | 3        |       | 3        |       |
| Syncrude                                    |       | 7                      |       | 6        |       | 5        |       |
| **Total Funding Contributions**             | ** ** | **19**                 | ** ** | **15**   | ** ** | **32**   | ** ** |

 

106

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Our most recent fundingvaluation was prepared as of June 30, 2007. Our next funding valuation isrequired by June 30, 2010. Canexus’ most recent funding valuation wasprepared as of December 31, 2007, and their next funding valuation isrequired by December 31, 2010. Syncrude’s most recent funding valuationwas prepared as of December 31, 2007, and their next funding valuation is December 31,2009.

 

Our total benefit paymentsin 2007 were $13 million for Nexen (2006—$11 million). Our share of Syncrude’stotal benefit payments in 2007 was $4 million (2006—$4 million). Our estimatedfuture payments are as follows:

 
| ** ** | ** ** | **Defined Benefit** | ** ** | **Other**   | ** ** |
|------------|------------|--------------------------|------------|-------------|------------|
| ** ** | ** ** | **Nexen**                | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** | **Nexen** | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** |
| 2008       |       | 9                        |       | 1           |       | 4 |   | 2 |   | — |   | — |   |
| 2009       |       | 10                       |       | 1           |       | 4 |   | 2 |   | — |   | — |   |
| 2010       |       | 11                       |       | 1           |       | 4 |   | 2 |   | — |   | — |   |
| 2011       |       | 12                       |       | 2           |       | 5 |   | 3 |   | — |   | — |   |
| 2012       |       | 13                       |       | 2           |       | 5 |   | 3 |   | — |   | 1 |   |
| 2013-2017  |       | 80                       |       | 17          |       | 34 |   | 22 |   | — |   | 1 |   |

 

**17.MARKETING AND OTHER INCOME**

 
| ** **                                              | ** ** | **2007**  | ** ** | **2006**  | ** ** | **2005** | ** ** |
|---------------------------------------------------------|------------|-----------|------------|-----------|------------|----------|------------|
| Marketing Revenue, Net                                  |       | 959       |       | 1,309     |       | 847      |       |
| Business Interruption Insurance Proceeds (1)            |       | —    |       | 154       |       | 2        |       |
| Change in Fair Value of Crude Oil Put Options (Note 7b) |       | (43       | )          | (11       | )          | (196     | )          |
| Interest                                                |       | 39        |       | 36        |       | 29       |       |
| Foreign Exchange Losses                                 |       | (22       | )          | (72       | )          | (19      | )          |
| Gains on Disposition of Assets (2)                      |       | 2         |       | 4         |       | 4        |       |
| Other                                                   |       | 86        |       | 30        |       | 35       |       |
| **Total Marketing and Other**                           | ** ** | **1,021** | ** ** | **1,450** | ** ** | **702**  | ** ** |

 

----

*Notes:*

*(1)** **In2006, we received business interruption insurance proceeds related toproduction losses caused by Gulf of Mexico hurricanes in 2005 and by generatorfailures in our UK operations in 2005.*

*(2**)*   *Gainson disposition of assets resulted from the sale of minor oil and gas assets inour Canadian operations in 2007 and 2006; and from the sale of our Ejulebeassets, offshore Nigeria in 2005.*

 

**18. INCOME TAXES**

 

**(a) Temporarydifferences**

 
| ** **                         | ** ** | **2007**            | ** ** | **2006**            | ** ** |
|------------------------------------|------------|---------------------|------------|---------------------|------------|
| ** **                         | ** ** | **Future**          | ** ** | **Future**          | ** ** | **Future** | ** ** | **Future** | ** ** |
| ** **                         | ** ** | **Income Tax** | ** ** | **Income Tax** | ** ** | **Income Tax** | ** ** | **Income Tax** | ** ** |
| ** **                         | ** ** | **Assets (1)** | ** ** | **Liabilities**     | ** ** | **Assets (1)** | ** ** | **Liabilities** | ** ** |
| Property, Plant and Equipment, Net |       | 25                  |       | 2,229               |       | 26 |   | 2,420 |   |
| Tax Losses Carried Forward         |       | 256                 |       | —              |       | 594 |   | — |   |
| Deferred Income                    |       | —              |       | 61                  |       | — |   | 48 |   |
| RecoverableTaxes                   |       | 5                   |       | —              |       | — |   | — |   |
| **Total**                          | ** ** | **286**             | ** ** | **2,290**           | ** ** | **620** | ** ** | **2,468** | ** ** |

 

----

*Note:*

*(1)*  *Futureincome tax assets of $18 million (2006 — $479 million) that we expect torealize in the following twelve months have been included in current assets.*

 

107

----

 

**(b) Canadianand foreign income taxes**

 
| ** **                                                        | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| **Income (Loss) from Continuing Operations before  Income taxes** |       |     |       |     |       |     |       |
| Canadian                                                          |       | (33      | )          | (352     | )          | (396     | )          |
| Foreign                                                           |       | 1,929    |       | 1,648    |       | 1,326    |       |
|                                                              |       | 1,896    |       | 1,296    |       | 930      |       |
|                                                              |       |     |       |     |       |     |       |
| **Provision for Income Taxes**                                    |       |     |       |     |       |     |       |
| Current                                                           |       |     |       |     |       |     |       |
| Canadian                                                          |       | 1        |       | 14       |       | 1        |       |
| Foreign                                                           |       | 433      |       | 354      |       | 338      |       |
|                                                              |       | 434      |       | 368      |       | 339      |       |
| Future                                                            |       |     |       |     |       |     |       |
| Canadian                                                          |       | 12       |       | (96      | )          | (206     | )          |
| Foreign                                                           |       | 346      |       | 411      |       | 101      |       |
|                                                              |       | 358      |       | 315      |       | (105     | )          |
|                                                              |       |     |       |     |       |     |       |
| **Total Provision for Income Taxes**                              | ** ** | **792**  | ** ** | **683**  | ** ** | **234**  | ** ** |

 

The Canadian and foreigncomponents of the provision for income taxes are based on the jurisdiction inwhich income is taxed. Foreign taxes relate mainly to Yemen, Colombia, theUnited Kingdom and the United States.

 

**(c) Reconciliationof effective tax rate to the Canadian statutory tax rate**

 
| ** **                                                         | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Income from Continuing Operations before Income Taxes              |       | 1,896    |       | 1,296    |       | 930      |       |
|                                                               |       |     |       |     |       |     |       |
| Provision for Income Taxes Computed at the Canadian Statutory Rate |       | 537      |       | 401      |       | 318      |       |
| Add (Deduct) the Tax Effect of:                                    |       |     |       |     |       |     |       |
| Royalties, Rentals and Similar Payments to Provincial Governments  |       | —   |       | 15       |       | 24       |       |
| Resource Allowance and Provincial Tax Rebates                      |       | —   |       | (15      | )          | (24      | )          |
| Foreign Tax Rate Differential                                      |       | 233      |       | (9       | )          | (40      | )          |
| Additional Canadian Tax on Canadian Resource Income                |       | —   |       | 10       |       | 6        |       |
| Lower Tax Rates on Capital Gains                                   |       | (5       | )          | (3       | )          | (54      | )          |
| Federal and Provincial Capital Tax                                 |       | 1        |       | 13       |       | 5        |       |
| Effect of Changes in Tax Rates                                     |       | (15      | )          | 245      |       | —   |       |
| Non-Deductible Expenses and Other                                  |       | 41       |       | 26       |       | (1       | )          |
| **Provision for Income Taxes**                                     | ** ** | **792**  | ** ** | **683**  | ** ** | **234**  | ** ** |
| **Effective Tax Rate**                                             | ** ** | **42**   | **%**      | **53**   | **%**      | **25**   | **%**      |

 

During the first quarter of2006, we recorded a future income tax expense of $277 million related to anincrease in the supplemental tax rate on oil and gas activities in the UnitedKingdom. The United Kingdom parliament increased the supplemental tax rate from10% to 20%, effective January 1, 2006.

 

In 2007 and 2006, thefederal and some provincial governments in Canada reduced statutory corporateincome tax rates. This reduced our liability and provision for future incometaxes by $15 million in 2007 (2006—$32 million).

 

**(d) Availableunused tax losses and tax contingencies**

 

At December 31, 2007,we had unused tax losses totalling $820 million (2006—$1,258 million; 2005—$965million). The majority of these losses are from Canada and the US and willexpire between 2015 and 2027.

 

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.

 

108

----

 

**19. CASHFLOWS**

 

**(a) Charges and credits to income not involving cash**

 
| ** **                                           | ** ** | **2007**  | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Depreciation, Depletion, Amortization and Impairment |       | 1,767     |       | 1,124     |       | 1,052     |       |
| Stock-Based Compensation                             |       | (109      | )          | 101       |       | 428       |       |
| Gains on Disposition of Assets                       |       | (2        | )          | (4        | )          | (4        | )          |
| Provision for Future Income Taxes                    |       | 358       |       | 315       |       | (105      | )          |
| Change in Fair Value of Crude Oil Put Options        |       | 43        |       | 11        |       | 196       |       |
| Non-Cash Items included in Discontinued Operations   |       | —    |       | —    |       | (325      | )          |
| Gain on Dilution of Interest in Chemicals Business   |       | —    |       | —    |       | (193      | )          |
| Net Income Attributable to Non-Controlling Interests |       | 18        |       | 12        |       | 8         |       |
| Other                                                |       | (2        | )          | 70        |       | 24        |       |
| **Total**                                            | ** ** | **2,073** | ** ** | **1,629** | ** ** | **1,081** | ** ** |

 

**(b) Changesin non-cash working capital**

 
| ** **                               | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Accounts Receivable                      |       | (797     | )          | 345      |       | (1,078   | )          |
| Inventories and Supplies                 |       | (97      | )          | (302     | )          | (163     | )          |
| Other Current Assets                     |       | (15      | )          | (14      | )          | (10      | )          |
| Accounts Payable and Accrued Liabilities |       | 691      |       | (72      | )          | 982      |       |
| Other                                    |       | —   |       | —   |       | 20       |       |
| **Total**                                | ** ** | **(218** | **)**      | **(43**  | **)**      | **(249** | **)**      |
|                                     |       |     |       |     |       |     |       |
| Relating to:                             |       |     |       |     |       |     |       |
| Operating Activities                     |       | (348     | )          | (177     | )          | (195     | )          |
| Investing Activities                     |       | 130      |       | 134      |       | (54      | )          |
| **Total**                                | ** ** | **(218** | **)**      | **(43**  | **)**      | **(249** | **)**      |

 

**(c) Othercash flow information**

 
| ** **        | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest Paid     |       | 328      |       | 278      |       | 237      |       |
| Income Taxes Paid |       | 408      |       | 398      |       | 325      |       |

 

Cash flow from otheroperating activities includes cash outflows related to geological andgeophysical expenditures of $123 million (2006 — $128 million; 2005 — $53million).

 

**20.OPERATING SEGMENTS AND  RELATEDINFORMATION**

 

Nexen has the followingoperating segments in various industries and geographic locations:

 

**Oil andgas:** We explore for, develop and produce crude oil, natural gas and relatedproducts around the world. We manage our operations to reflect differences inthe regulatory environments and risk factors for each country. Our coreoperations are onshore in Yemen and Canada, and offshore in the US Gulf ofMexico and the UK North Sea. Our other operations are primarily in Colombia,West Africa and Norway.

 

**Energymarketing:** Our marketing group sells our crude oil and naturalgas, markets third-party crude oil, natural gas, NGL’s, ethanol and power andengages in energy trading, including electricity generation.

 

**Syncrude:** We own 7.23%of the Syncrude Joint Venture, which develops and produces synthetic crude oilfrom mining bitumen in the oil sands in northern Alberta.

 

**Chemicals:** Through ourinvestment in Canexus LP, we manufacture, market and distribute industrialchemicals, principally sodium chlorate, chlorine, muriatic acid and causticsoda. We produce sodium chlorate at four facilities in Canada and one inBrazil. We produce chlorine, caustic soda and muriatic acid at chlor-alkalifacilities 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.

 

109

----

 

**2007Operating and Geographic Segments**

 
|                                                          |       | **Oil and  Gas** |       |       |       |       |       |      |       |                         |       |                  |         |
|---------------------------------------------------------------|------------|------------------|------------|------------|------------|------------|------------|-----------|------------|------------------------------|------------|-----------------------|--------------|
|                                                          |       | **Yemen**        | ** ** | **Canada** | ** ** | **US**     | ** ** | **UK**    | ** ** | **Other  Countries (1****)** |       | **Energy  Marketing** | ** **   | **Syncrude** | ** ** | **Chemicals** | ** ** | **Corporate  and Other** | ** ** | **Total** |   |
| Net Sales (2)                                                 |       | 1,086            |       | 441        |       | 616        |       | 2,285     |       | 148                          |       | 48                    |         | 545 |   | 414 | (3) | — |   | 5,583 |   |
| Marketing and Other                                           |       | 10               |       | 6          |       | —     |       | 39        |       | —                       |       | 959                   |         | — |   | 33 |   | (26 | )(4) | 1,021 |   |
|                                                          |       | 1,096            |       | 447        |       | 616        |       | 2,324     |       | 148                          |       | 1,007                 |         | 545 |   | 447 |   | (26 | ) | 6,604 |   |
| Less: Expenses                                                |       |             |       |       |       |       |       |      |       |                         |       |                  |         |   |   |   |   |   |   |   |   |
| Operating                                                     |       | 171              |       | 173        |       | 102        |       | 212       |       | 8                            |       | 34                    |         | 208 |   | 257 |   | — |   | 1,165 |   |
| Depreciation,  Depletion, Amortization and Impairment         |       | 213              |       | 166        |       | 641        | (5)        | 599       |       | 8                            |       | 13                    |         | 53 |   | 45 |   | 29 |   | 1,767 |   |
| Transportation  and Other                                     |       | 8                |       | 22         |       | —     |       | —    |       | —                       |       | 806                   |         | 17 |   | 39 |   | 16 |   | 908 |   |
| General and  Administrative (6)                               |       | (6               | )          | 50         |       | 38         |       | 3         |       | 40                           |       | 87                    |         | 1 |   | 31 |   | 130 |   | 374 |   |
| Exploration                                                   |       | 5                |       | 27         |       | 134        |       | 69        |       | 91                           | (7)        | —                |         | — |   | — |   | — |   | 326 |   |
| Interest                                                      |       | —           |       | —     |       | —     |       | —    |       | —                       |       | —                |         | — |   | 11 |   | 157 |   | 168 |   |
| Income (Loss)  from Continuing Operations before Income Taxes |       | 705              |       | 9          |       | (299       | )          | 1,441     |       | 1                            |       | 67                    |         | 266 |   | 64 |   | (358 | ) | 1,896 |   |
| Less: Provision  for (Recovery of) Income Taxes (8)           |       | 248              |       | 3          |       | (103       | )          | 712       |       | —                       |       | 21                    |         | 75 |   | 18 |   | (182 | ) | 792 |   |
| Net Income (Loss)  from Continuing Operations                 |       | 457              |       | 6          |       | (196       | )          | 729       |       | 1                            |       | 46                    |         | 191 |   | 46 |   | (176 | ) | 1,104 |   |
| Less:  Non-Controlling Interests                              |       | —           |       | —     |       | —     |       | —    |       | —                       |       | —                |         | — |   | 18 |   | — |   | 18 |   |
| **Net  Income (Loss)**                                        | ** ** | **457**          | ** ** | **6**      | ** ** | **(196**   | **)**      | **729**   | ** ** | **1**                        | ** ** | **46**                | ** **   | **191** | ** ** | **28** | ** ** | **(176** | **)** | **1,086** | ** ** |
|                                                          |       |             |       |       |       |       |       |      |       |                         |       |                  |         |   |   |   |   |   |   |   |   |
| **Identifiable  Assets**                                      | ** ** | **359**          | ** ** | **5,379**  | **(9)**    | **1,640**  | ** ** | **4,642** | ** ** | **317**                      | ** ** | **3,663**             | **(10****)** | **1,212** | ** ** | **487** | ** ** | **376** | ** ** | **18,075** | ** ** |
|                                                          |       |             |       |       |       |       |       |      |       |                         |       |                  |         |   |   |   |   |   |   |   |   |
| Capital  Expenditures                                         |       |             |       |       |       |       |       |      |       |                         |       |                  |         |   |   |   |   |   |   |   |   |
| Development and  Other                                        |       | 124              |       | 1,381      |       | 414        |       | 551       |       | 53                           |       | 4                     |         | 36 |   | 62 |   | 52 |   | 2,677 |   |
| Exploration                                                   |       | 12               |       | 123        |       | 275        |       | 119       |       | 44                           |       | —                |         | — |   | — |   | — |   | 573 |   |
| Proved Property  Acquisitions                                 |       | —           |       | 1          |       | 104        | (11)       | 46        | (12)       | —                       |       | —                |         | — |   | — |   | — |   | 151 |   |
| **Total  Capital Expenditures**                               | ** ** | **136**          | ** ** | **1,505**  | ** ** | **793**    | ** ** | **716**   | ** ** | **97**                       | ** ** | **4**                 | ** **   | **36** | ** ** | **62** | ** ** | **52** | ** ** | **3,401** | ** ** |
|                                                          |       |             |       |       |       |       |       |      |       |                         |       |                  |         |   |   |   |   |   |   |   |   |
| Property, Plant  and Equipment                                |       |             |       |       |       |       |       |      |       |                         |       |                  |         |   |   |   |   |   |   |   |   |
| Cost                                                          |       | 2,178            |       | 6,736      |       | 3,069      |       | 4,723     |       | 263                          |       | 246                   |         | 1,332 |   | 831 |   | 315 |   | 19,693 |   |
| Less: Accumulated  DD&A                                   |       | 1,950            |       | 1,597      |       | 1,765      |       | 908       |       | 77                           |       | 62                    |         | 205 |   | 463 |   | 168 |   | 7,195 |   |
| **Net Book  Value (2)**                                       | ** ** | **228**          | ** ** | **5,139**  | **(9)**    | **1,304**  | ** ** | **3,815** | ** ** | **186**                      | ** ** | **184**               | ** **   | **1,127** | ** ** | **368** | ** ** | **147** | ** ** | **12,498** | ** ** |
|                                                          |       |             |       |       |       |       |       |      |       |                         |       |                  |         |   |   |   |   |   |   |   |   |
| **Goodwill**                                                  | ** ** | **—**       | ** ** | **—** | ** ** | **—** | ** ** | **276**   | ** ** | **—**                   | ** ** | **50**                | ** **   | **—** | ** ** | **—** | ** ** | **—** | ** ** | **326** | ** ** |

 

----

*Notes:*

 
| *(1)*    | *Includes results of  operations from producing activities in Colombia.* |
|----------|--------------------------------------------------------------------------|
| *(2)*    | *Net sales made from all  segments originating in Canada:*               | *1,188* |
|     | *PP&E located in Canada:*                                            | * * | *6,893* |
| *(3)*    | *Net sales for our chemicals  operations include:*                       |   |
| * * | * *                                                                 |   |
| * * | * *                                                                 | *Canada* | *154* |
| * * | * *                                                                 | *United States* | *169* |
| * * | * *                                                                 | *Brazil* | *91* |
| * * | * *                                                                 | *Total* | *414* |
|          |                                                                          |  |  |  |

 
| *(4)*  | *Includes interest income of  $39 million, foreign exchange losses of $22 million and decrease in the fair  value of crude oil put options of $43 million.*                                                                                                            |
|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(5)*  | *Includes an impairment  charge of $366 million related to oil and gas properties in the Gulf of  Mexico.*                                                                                                                                                             |
| *(6)*  | *Includes stock-based  compensation expense of $38 million.*                                                                                                                                                                                                           |
| *(7)*  | *Includes exploration  activities primarily in Nigeria, Norway and Colombia.*                                                                                                                                                                                          |
| *(8)*  | *The provision for (recovery  of) income taxes for foreign locations is based on in-country taxes on  foreign income. For oil and gas locations with no operating activities, the  provision is based on the tax jurisdiction of the entity performing the  activity.* |
| *(9)*  | *Includes costs of $3,695  million related to our Long Lake Project (Phase 1 and future phases).*                                                                                                                                                                      |
| *(10)* | *Approximately 84% of  Marketing’s identifiable assets are accounts receivable and inventories.*                                                                                                                                                                  |
| *(11)* | *Includes acquisition of  producing properties in the Gulf of Mexico.*                                                                                                                                                                                                 |
| *(12)* | *Includes acquisition of  additional interests in the Scott and Telford fields.*                                                                                                                                                                                       |

 

110

----

 

**2006Operating and Geographic Segments**

 
| ** **                                                    | ** ** | **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**  | **(13)**   | **1,620**  | ** ** | **5,490**  | ** ** | **245**                      | ** ** | **3,528**             | **(14)**   | **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**  | **(13)**   | **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 of business interruption  insurance proceeds related to production losses caused by Gulf of Mexico  hurricanes in 2005.*                                                                                                                         |
| *(5)*    | *Includes $74 million of business interruption  insurance proceeds for generator failures in 2005.*                                                                                                                                                                    |
| *(6)*    | *Includes interest income of $36 million, foreign  exchange losses of $72 million and decrease in the fair value of crude oil  put options of $11 million.*                                                                                                            |
| *(7)*    | *Includes an impairment charge of $93 million,  primarily relating to two natural gas properties in the Gulf of Mexico.*                                                                                                                                               |
| *(8)*    | *Includes  $151 million (US$135 million) accrual with respect to the Block 51  arbitration settlement.*                                                                                                                                                                |
| *(9)*    | *Includes  stock-based compensation expense of $210 million.*                                                                                                                                                                                                          |
| *(10)*   | *Includes  exploration activities primarily in Nigeria, Norway and Colombia.*                                                                                                                                                                                          |
| *(11)*   | *The  provision for (recovery of) income taxes for foreign locations is based on  in-country taxes on foreign income. For oil and gas locations with no  operating activities, the provision is based on the tax jurisdiction of the  entity performing the activity.* |
| *(12)*   | *Includes  future income tax expense of $277 million related to an increase in the  supplemental tax rate on oil and gas activities in the United Kingdom (see  Note 18).*                                                                                             |
| *(13)*   | *Includes  costs of $2,444 million related to our Long Lake Project (Phase 1 and future  phases).*                                                                                                                                                                     |
| *(14)*   | *Approximately  80% of Marketing’s identifiable assets are accounts receivable and  inventories.*                                                                                                                                                                 |
|          |                                                                                                                                                                                                                                                                        |                                                                          |  |  |  |  |

 

111

----

 

**2005 Operating and Geographic Segments**

 
| ** **                                                    |   | **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**          | (10))      | **1,433**  |       | **4,775**  |       | **183**                       |       | **3,165**        | (11)       | **1,135** |   | **482** |   | **333** |   | **14,590** |   |
| ** **                                                    |   | ** **       |       | ** **         |       | ** ** |       | ** ** |       | ** **                    |       | ** **            |       | ** ** |   | ** ** |   | ** ** |   | ** ** |   |
| Capital Expenditures                                          |   |             |       |               |       |       |       |       |       |                          |       |                  |       |   |   |   |   |   |   |   |   |
| Development and Other                                         |   | 236              |       | 947                |       | 148        |       | 566        |       | 14                            |       | 16                    |       | 197 |   | 14 |   | 24 |   | 2,162 |   |
| Exploration                                                   |   | 41               |       | 90                 |       | 211        |       | 59         |       | 55                            |       | —                |       | — |   | — |   | — |   | 456 |   |
| Proved Property  Acquisitions                                 |   | —           |       | 17                 |       | 3          |       | —     |       | —                        |       | —                |       | — |   | — |   | — |   | 20 |   |
| **Total Capital Expenditures**                                |   | **277**          |       | **1,054**          |       | **362**    |       | **625**    |       | **69**                        |       | **16**                |       | **197** |   | **14** |   | **24** |   | **2,638** |   |
| ** **                                                    |   | ** **       |       | ** **         |       | ** ** |       | ** ** |       | ** **                    |       | ** **            |       | ** ** |   | ** ** |   | ** ** |   | ** ** |   |
| Property, Plant and Equipment Cost                            |   | 2,243            |       | 3,631              |       | 2,437      |       | 4,013      |       | 249                           |       | 177                   |       | 1,240 |   | 827 |   | 245 |   | 15,062 |   |
| Less: Accumulated  DD&A                                   |   | 1,841            |       | 1,311              |       | 1,159      |       | 216        |       | 119                           |       | 72                    |       | 171 |   | 456 |   | 123 |   | 5,468 |   |
| **Net Book Value**(3)                                    |   | **402**          |       | **2,320**          | (10)       | **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 income of $29 million, foreign exchange losses of $19 million,  decrease in the fair value of crude oil put options of $196 million and  decrease in the fair value of foreign currency call options of $7 million.*                               |
| *(6)*    | *Includes  impairment charge of $12 million related to the closure of our sodium  chlorate plant in Amherstburg, Ontario.*                                                                                                                                             |
| *(7)*    | *Includes  stock-based compensation expense of $507 million.*                                                                                                                                                                                                          |
| *(8)*    | *Includes  exploration activities primarily in Nigeria, Colombia and Equatorial Guinea.*                                                                                                                                                                               |
| *(9)*    | *The  provision for (recovery of) income taxes for foreign locations is based on  in-country taxes on foreign income. For oil and gas locations with no  operating activities, the provision is based on the tax jurisdiction of the  entity performing the activity.* |
| *(10)*   | *Includes  costs of $1,321 million related to our Long Lake Project (Phase 1 and future  phases).*                                                                                                                                                                     |
| *(11)*   | *Approximately  86% of Marketing’s identifiable assets are accounts receivable and  inventories.*                                                                                                                                                                 |

 

112

----

 

**21.****                              ****DIFFERENCESBETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES**

 

The Consolidated FinancialStatements have been prepared in accordance with Canadian GAAP. US GAAPConsolidated

Financial Statements andsummaries of differences from Canadian GAAP are as follows:

 

**ConsolidatedStatement of Income—US GAAP**

**For theThree Years ended December 31, 2007**

 
| **(Cdn$ millions, except per share amounts)**  | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|-------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Revenues and Other Income                                               |       |       |       |       |       |       |       |
| Net Sales                                                               |       | 5,583      |       | 3,936      |       | 3,932      |       |
| Marketing and Other (ii); (vii) (viii)                             |       | 938        |       | 1,459      |       | 687        |       |
| Gain on Dilution of Interest in Chemicals Business                      |       | —     |       | —     |       | 193        |       |
|                                                                    |       | 6,521      |       | 5,395      |       | 4,812      |       |
| Expenses                                                                |       |       |       |       |       |       |       |
| Operating (iii)                                                         |       | 1,167      |       | 958        |       | 903        |       |
| Depreciation, Depletion, Amortization and Impairment (i)                |       | 1,767      |       | 1,124      |       | 1,081      |       |
| Transportation and Other (vii)                                          |       | 906        |       | 1,037      |       | 792        |       |
| General and Administrative (vi)                                         |       | 401        |       | 597        |       | 792        |       |
| Exploration                                                             |       | 326        |       | 362        |       | 250        |       |
| Interest                                                                |       | 168        |       | 53         |       | 97         |       |
|                                                                    |       |       |       |       |       |       |       |
|                                                                    |       | 4,735      |       | 4,131      |       | 3,915      |       |
| Income from Continuing Operations before Income Taxes                   |       | 1,786      |       | 1,264      |       | 897        |       |
|                                                                    |       |       |       |       |       |       |       |
| Provision for Income Taxes                                              |       |       |       |       |       |       |       |
| Current                                                                 |       | 434        |       | 368        |       | 339        |       |
| Deferred (ii) – (viii)                                        |       | 322        |       | 305        |       | (108       | )          |
|                                                                    |       | 756        |       | 673        |       | 231        |       |
|                                                                    |       |       |       |       |       |       |       |
| Net Income from Continuing Operations before Non-Controlling  Interests |       | 1,030      |       | 591        |       | 666        |       |
| Net Income Attributable to Non-Controlling Interests                    |       | 18         |       | 12         |       | 8          |       |
| Net Income from Continuing Operations                                   |       | 1,012      |       | 579        |       | 658        |       |
| Net Income from Discontinued Operations                                 |       | —     |       | —     |       | 452        |       |
|                                                                    |       |       |       |       |       |       |       |
| **Net Income—US GAAP(1)**                                          | ** ** | **1,012**  | ** ** | **579**    | ** ** | **1,110**  | ** ** |
| ** **                                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Earnings Per Common Share****($/share)**                              |       |       |       |       |       |       |       |
| Basic (Note 13)                                                         |       |       |       |       |       |       |       |
| Net Income from Continuing Operations                                   |       | 1.92       |       | 1.10       |       | 1.26       |       |
| Net Income from Discontinued Operations                                 |       | —     |       | —     |       | 0.87       |       |
|                                                                    |       | 1.92       |       | 1.10       |       | 2.13       |       |
|                                                                    |       |       |       |       |       |       |       |
| Diluted (Note 13)                                                       |       |       |       |       |       |       |       |
| Net Income from Continuing Operations                                   |       | 1.88       |       | 1.08       |       | 1.23       |       |
| Net Income from Discontinued Operations                                 |       | —     |       | —     |       | 0.85       |       |
| ** **                                                              | ** ** | **1.88**   | ** ** | **1.08**   | ** ** | **2.08**   |       |

 

----

*Note:*

*(1) Reconciliationof Canadian and US GAAP Net Income*

* *
| **(Cdn$ millions)**                                 | ** ** | **2007**  | ** ** | **2006** | ** ** | **2005**  | ** ** |
|----------------------------------------------------------|------------|-----------|------------|----------|------------|-----------|------------|
| Net Income—Canadian GAAP                            |       | 1,086     |       | 601      |       | 1,140     |       |
| Impact of US Principles, Net of Income Taxes:            |       |      |       |     |       |      |       |
| Ineffective Portion of Cash Flow Hedges (ii)             |       | (2        | )          | 9        |       | (7        | )          |
| Depreciation, Depletion, Amortization and Impairment (i) |       | —    |       | —   |       | (29       | )          |
| Pre-operating Costs (iii)                                |       | (1        | )          | (2       | )          | (6        | )          |
| Stock-based Compensation (vi)                            |       | (19       | )          | (29      | )          | 12        |       |
| Inventory Valuation(viii)                                |       | (52       | )          | —   |       | —    |       |
| **Net Income—US GAAP**                              | ** ** | **1,012** | ** ** | **579**  | ** ** | **1,110** | ** ** |

 

113

----

 

**ConsolidatedBalance Sheet—US GAAP**

**December 31,2007 and 2006**

 
| **(Cdn$ millions, except share amounts)**                                                                                                                                                                                                        | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| **ASSETS**                                                                                                                                                                                                                                                           |       |       |       |       |       |
| Current Assets                                                                                                                                                                                                                                                       |       |       |       |       |       |
| Cash and Cash Equivalents                                                                                                                                                                                                                                            |       | 206        |       | 101        |       |
| Restricted Cash and Margin Deposits                                                                                                                                                                                                                                  |       | 203        |       | 197        |       |
| Accounts Receivable (ii)                                                                                                                                                                                                                                             |       | 3,502      |       | 2,976      |       |
| Inventories and Supplies (viii)                                                                                                                                                                                                                                      |       | 615        |       | 786        |       |
| Deferred Income Tax Assets                                                                                                                                                                                                                                           |       | 18         |       | 479        |       |
| Other                                                                                                                                                                                                                                                                |       | 71         |       | 67         |       |
| Total Current Assets                                                                                                                                                                                                                                                 |       | 4,615      |       | 4,606      |       |
| Property, Plant and Equipment                                                                                                                                                                                                                                        |       |       |       |       |       |
| Net of Accumulated Depreciation, Depletion, Amortization and Impairment  of $7,588 (December 31, 2006—$6,792) (iii); (v)                                                                                                                                   |       | 12,449     |       | 11,692     |       |
| Goodwill                                                                                                                                                                                                                                                             |       | 326        |       | 377        |       |
| Deferred Income Tax Assets                                                                                                                                                                                                                                           |       | 268        |       | 141        |       |
| Deferred Charges and Other Assets                                                                                                                                                                                                                                    |       | 324        |       | 263        |       |
|                                                                                                                                                                                                                                                                 |       |       |       |       |       |
| **TOTAL ASSETS**                                                                                                                                                                                                                                                     | ** ** | **17,982** | ** ** | **17,079** | ** ** |
| ** **                                                                                                                                                                                                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| **LIABILITIES AND SHAREHOLDERS’ EQUITY**                                                                                                                                                                                                                        |       |       |       |       |       |
| Current Liabilities                                                                                                                                                                                                                                                  |       |       |       |       |       |
| Short-Term Borrowings                                                                                                                                                                                                                                                |       | —     |       | 158        |       |
| Accounts Payable and Accrued Liabilities (ii); (vi)                                                                                                                                                                                                                  |       | 4,233      |       | 3,839      |       |
| Accrued Interest Payable                                                                                                                                                                                                                                             |       | 54         |       | 55         |       |
| Dividends Payable                                                                                                                                                                                                                                                    |       | 13         |       | 13         |       |
| Total Current Liabilities                                                                                                                                                                                                                                            |       | 4,300      |       | 4,065      |       |
|                                                                                                                                                                                                                                                                 |       |       |       |       |       |
| Long-Term Debt                                                                                                                                                                                                                                                       |       | 4,610      |       | 4,618      |       |
| Deferred Income Tax Liabilities (i) – (viii)                                                                                                                                                                                                               |       | 2,230      |       | 2,427      |       |
| Asset Retirement Obligations                                                                                                                                                                                                                                         |       | 792        |       | 683        |       |
| Deferred Credits and Other Liabilities (iv)                                                                                                                                                                                                                          |       | 534        |       | 597        |       |
| Non-Controlling Interests                                                                                                                                                                                                                                            |       | 67         |       | 75         |       |
|                                                                                                                                                                                                                                                                 |       |       |       |       |       |
| Shareholders’ Equity                                                                                                                                                                                                                                            |       |       |       |       |       |
| Common Shares, no par value 

Authorized:  Unlimited 

Outstanding: 2007—528,304,813 shares 

                       2006—525,026,412 shares |       | 917        |       | 821        |       |
| Contributed Surplus                                                                                                                                                                                                                                                  |       | 3          |       | 4          |       |
| Retained Earnings (i) – (viii)                                                                                                                                                                                                                             |       | 4,876      |       | 3,945      |       |
| Accumulated Other Comprehensive Loss (ii); (iv)                                                                                                                                                                                                                      |       | (347       | )          | (156       | )          |
| Total Shareholders’ Equity                                                                                                                                                                                                                                      |       | 5,449      |       | 4,614      |       |
| Commitments, Contingencies and Guarantees                                                                                                                                                                                                                            |       |       |       |       |       |
| **TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY**                                                                                                                                                                                                                  | ** ** | **17,982** | ** ** | **17,079** | ** ** |

 

114

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**ConsolidatedStatement of Comprehensive Income—US GAAP**

**For theThree Years ended December 31, 2007**

 
| **(Cdn$ millions)**                                | ** ** | **2007** | ** ** | **2006** | ** ** | **2005**  | ** ** |
|---------------------------------------------------------|------------|----------|------------|----------|------------|-----------|------------|
| Net Income—US GAAP                                 |       | 1,012    |       | 579      |       | 1,110     |       |
| Other Comprehensive Income (Loss), Net of Income Taxes: |       |     |       |     |       |      |       |
| Foreign Currency Translation Adjustment                 |       | (132     | )          | —   |       | (56       | )          |
| Change in Mark to Market on Cash Flow Hedges (ii)       |       | (61      | )          | 77       |       | (20       | )          |
| Minimum Unfunded Pension Liability (iv)                 |       | —   |       | 5        |       | (10       | )          |
| Unamortized Defined Benefit Pension Plan Costs (iv)     |       | 2        |       | —   |       | —    |       |
| **Comprehensive Income**                                | ** ** | **821**  | ** ** | **661**  | ** ** | **1,024** | ** ** |

 

**ConsolidatedStatement of Accumulated Other Comprehensive Loss—US GAAP**

**December 31,2007 and 2006**

 
| **(Cdn$ millions)**                            | ** ** | **2007** | ** ** | **2006** | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|
| Foreign Currency Translation Adjustment             |       | (293     | )          | (161     | )          |
| Mark to Market on Cash Flow Hedges (ii)             |       | —   |       | 61       |       |
| Unamortized Defined Benefit Pension Plan Costs (iv) |       | (54      | )          | (56      | )          |
| **Accumulated Other Comprehensive Loss (AOCI)**     | ** ** | **(347** | **)**      | **(156** | **)**      |

 

**Notes to the Consolidated US GAAP**

 

**Financial Statements:**

 

i. Under US GAAP, theliability method of accounting for income taxes was adopted in 1993. In Canada,the liability method was adopted in 2000. In 1997, we acquired certain oil andgas assets and the amount paid for these assets differed from the tax basisacquired. Under US principles, this difference was recorded as a deferred taxliability with an increase to PP&E rather than a charge to retainedearnings. As a result, additional depreciation, depletion, amortization andimpairment of $29 million was included in net income during 2005. The differencewas fully amortized during 2005.

 

ii. Under US GAAP, allderivative instruments are recognized on the balance sheet as either an assetor a liability measured at fair value. Changes in the fair value of derivativesare recognized in earnings unless specific hedge criteria are met. On January 1,2007, we adopted the equivalent Canadian standard for derivative instrumentsand hedging (see note 1(u)).

 

*Future saleof gas inventory:*

 

We use futures and swaps ascash flow hedges against the commodity price risk on the future sale of our gasinventory. Prior to January 1, 2007, we included the hedging derivativecontracts on our US GAAP Consolidated Balance Sheet with the effective portionof gains or losses recognized in AOCI. The ineffective gain or loss is includedin marketing and other on the US GAAP net income immediately.

 

In 2005, we recognized $11million ($7 million, net of income taxes) of ineffective losses related tothese hedges in our US GAAP net income. Under Canadian GAAP, these losses wererecognized in 2006.

 

At December 31, 2006, weincluded $25 million of gains on these cash flow hedges in accounts receivable.AOCI includes the effective portion of $23 million ($16 million, net of incometaxes) and $2 million ($2 million, net of income taxes) of the ineffectiveportion in our US GAAP net income. Under Canadian GAAP, these gains wererecognized in 2007.

 

Under US GAAP, AOCI includedgains of $65 million ($45 million, net of income taxes) at December 31,2006 related to de-designated cash flow hedges as described in Note 7(b). Thesegains were recognized in marketing and other in the first quarter of 2007.Under Canadian GAAP, these deferred gains were included in accounts payable andaccrued liabilities at December 31, 2006 and were recognized in marketingand other in the first quarter of 2007.

 

iii. Under Canadian GAAP, wedefer certain development costs and all pre-operating revenues and costs toPP&E. Under US GAAP, these costs have been included in operating expenses.As a result:

 

·      operating expenses includepre-operating costs of $2 million ($1 million, net of income taxes) (2006—$3 million ($2million, net of income taxes); 2005—$10 million ($6 million, netof income taxes)); and

·       PP&E is lower under USGAAP by $30 million (December 31, 2006—$28 million).

 

iv. On December 31,2006, we adopted FASB Statement No. 158 *Employers’Accounting for Defined Benefit Pension and Other Postretirement Plans*forUS GAAP. This requires, among other things, the recognition of the over-fundedand under-funded status of a defined benefit plan on the balance sheet as anasset or liability.

 

115

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At year end, the unfundedamount of our defined benefit pension plans was $75 million (2006—$81 million).This amount has been included in deferred credits and other liabilities and $54million, net of income taxes, (2006—$56 million, net of income taxes), has beenincluded in AOCI. Prior to the adoption of FAS 158 on December 31, 2006,we included our minimum unfunded pension liability in our US GAAP ConsolidatedBalance Sheet. This liability decreased by $5 million in 2006 and increased $10million in 2005.

 

v. On January 1, 2003,we adopted FASB Statement No. 143, *Accountingfor Asset Retirement Obligations*(FAS 143) for US GAAP reportingpurposes. We adopted the equivalent Canadian standard for asset retirementobligations on January 1, 2004. These standards are consistent, except forthe adoption date, which resulted in our PP&E under US GAAP being lower by$19 million.

 

vi. Under Canadianprinciples, we record obligations for liability-based stock compensation plansusing the intrinsic-value method of accounting. Under US principles,obligations for liability-based stock compensation plans are recorded using thefair-value method of accounting. In addition, under Canadian principles, weretroactively adopted EIC–162 which requires the accelerated recognition ofstock-based compensation expense for all stock-based awards made to our retiredand retirement-eligible employees. However, US GAAP requires the acceleratedrecognition of stock-based compensation expense for such employees for awardsgranted on or after January 1, 2006. As a result:

 

·      general and administrativeexpense is higher by $27 million ($19 million, net of income taxes) for theyear ended December 31, 2007 (2006—higher by $42 million ($29 million, netof income taxes); 2005—lower by $17 million ($12 million, net of income taxes));and

·      accounts payableand accrued liabilities are higher by $53 million at December 31, 2007(2006—higher by $25 million).

 

vii. Under US GAAP, assetdisposition gains and losses are included with transportation and otherexpense. Gains of $2 million were reclassified from marketing and other totransportation and other (2006—$4 million; 2005—$4 million).

 

viii. Under Canadian GAAP, webegan carrying our commodity inventory held for trading purposes at fair value,less any costs to sell effective October 1, 2007 (see Note 1(u)). Under USGAAP, we are required to carry this inventory at the lower of cost or netrealizable value. As a result:

 

·      marketing and other is lowerby $79 million ($52 million, net of income taxes) for the year ended December 31,2007; and

·      inventories are lower by $44million at December 31, 2007.

 

**Stock-Based Compensation**

 

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*(theintrinsic-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 remeasured in each subsequent reportingperiod.

 

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.

 

*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)                  |   | 0.10            |   |
|-----------------------------------------------------------------------|--------|-----------------|--------|
| Expected Volatility                                                   |   | 31              | %      |
| Risk-Free Interest Rate                                               |   | 4.2%—4.5   | %      |
| 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.

 

116

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*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, 2007                       |       | 27,403          |       | 20                      |       | 2.9                          |       | 325                      |       | 13                  |       |
| Outstanding at December 31, 2007 and  Expected to Vest |       | 27,263          |       | 20                      |       | 2.9                          |       | 320                      |       | 14                  |       |
| Exercisable at December 31, 2007                       |       | 18,216          |       | 16                      |       | 2.3                          |       | 295                      |       | 16                  |       |

 

The total intrinsic value of stock options exercised during the yearended December 31, 2007 was $149 million (2006—$109 million; 2005—$83million). As at December 31, 2007, we had $51 million of unrecognizedcompensation expense related to stock options which we expect to recognize overa 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, 2007                       |       | 15,435          |       | 24                      |       | 3.3                          |       | 122                      |       | 11                  |       |
| Outstanding at December 31, 2007 and  Expected to Vest |       | 15,052          |       | 24                      |       | 3.3                          |       | 120                      |       | 11                  |       |
| Exercisable at December 31, 2007                       |       | 7,525           |       | 19                      |       | 2.3                          |       | 100                      |       | 14                  |       |

 

Thetotal intrinsic value of stock appreciation rights exercised during the yearended December 31, 2007 was $50 million (2006—$46 million; 2005—$34million). As at December 31, 2007, we had $45 million of unrecognizedcompensation expense related to stock appreciation rights which we expect torecognize over a weighted-average period of 1.6 years.

 

*Stock-BasedCompensation Expense and Payments*

 

Forthe year ended December 31, 2007, stock-based compensation expense of $65million (2006—$252 million; 2005—$490 million) was included in general andadministrative expense in the Consolidated Statement of Income—US GAAP.

 

Forthe year ended December 31, 2007, cash proceeds of $24 million werereceived related to the exercise of stock options (2006—$16 million; 2005—$29million). For the year ended December 31, 2007, $149 million was paidrelated to the exercise of stock options and stock appreciation rights(2006—$119 million; 2005—$74 million). The income tax benefit recorded from theexercise of stock options and stock appreciation rights was $42 million(2006—$37 million; 2005—$24 million) for the period.

 

*StockBased Compensation Expense for Retired and Retirement Eligible Employees*

 

Werecognize stock-based compensation expense for our retired and retirement-eligibleemployees over an accelerated graded vesting period in accordance with theprovisions of Statement 123(R) for stock-based awards granted to employeeson or after January 1, 2006. For stock-based awards granted prior to theadoption of Statement 123(R), stock-based compensation expense for our retiredand retirement-eligible employees is recognized over a graded vesting period.If we applied the accelerated graded vesting provisions of Statement 123(R) tostock-based awards granted to our retired and retirement-eligible employeesprior to the adoption of Statement 123(R), our stock-based compensation expensewould decrease by $9 million for the year ended December 31, 2007(2006—decrease by $10 million; 2005—increase by $19 million).

 

**Changesin Accounting Policies—US GAAP**

 

IncomeTaxes

 

OnJanuary 1, 2007, we adopted FASB Interpretation 48 *Accountingfor Uncertainty in Income Taxes* (FIN 48) regarding accounting anddisclosure for uncertain tax positions. FIN 48 clarifies the accounting for uncertaintyin income taxes recognized in the financial statements and prescribes how a companyshould recognize, measure, present and disclose uncertain tax positions that ithas taken or expects to take on a tax return. The evaluation of tax positionsunder FIN 48 is a two-step process, whereby (1) the company determines whetherit is more-likely-than-not that the tax positions will be sustained based onthe technical merits of the position; and (2) for those tax positions thatmeet the more-likely-than-not recognition threshold, the company recognizes thelargest amount of tax benefit that is greater than 50 percent likely of beingrealized upon ultimate settlement with the taxing

 

 

117

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authority.On the adoption of FIN 48, we recorded a cumulative effect of a change inaccounting principle of $28 million. This amount increased our deferred incometax liabilities and decreased our retained earnings as at January 1, 2007in our US GAAP—Consolidated Balance Sheet.

 

Asat December 31, 2007, the total amount of our unrecognized tax benefitswas approximately $221 million, all of which, if recognized, would affect oureffective tax rate. To the extent interest and penalties may be assessed bytaxing authorities on any underpayment of income tax, such amounts have beenaccrued and are classified as a component of income taxes in the ConsolidatedStatement of Income. As at December 31, 2007, the total amount of interestand penalties related to uncertain tax positions recognized in deferred incometax liabilities in the US GAAP—Consolidated Balance Sheet was approximately $9million. We had no interest or penalties included in the US GAAP—ConsolidatedStatement of Income for the year ended December 31, 2007.

 

Ourincome tax filings are subject to audit by taxation authorities and as at December 31,2007 the following tax years remained subject to examination; (i) Canada—1985to date, (ii) United Kingdom—2002 to date and (iii) UnitedStates—2004 to date. We do not anticipate any material changes to theunrecognized tax benefits previously disclosed within the next twelve months.

 

Reconciliationof Unrecognized Tax Benefits (Cdn$ millions)

 
| Balance at January 1, 2007                          |   | 210 |   |
|----------------------------------------------------------|--------|-----|--------|
| Additions for tax positions related to the current  year |   | 10  |   |
| Additions for tax positions related to  prior years      |   | 33  |   |
| Reductions for tax positions related to  prior years     |   | (32 | )      |
| Balance at December 31, 2007                        |   | 221 |   |

 

**NewAccounting Pronouncements—US GAAP**

 

InSeptember 2006, the Financial Accounting Standards Board (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. For fiscal years beginning after November 15,2007, companies will be required to implement the standard for financial assetsand liabilities, as well as for any other assets and liabilities that arecarried at fair value on a recurring basis in financial statements. However, aone year deferral for the implementation of Statement 157 is provided for othernonfinancial assets and liabilities. We do not expect the adoption of thisstatement to have a material impact on our results of operations or financialposition.

 

EffectiveDecember 31, 2006, we adopted the recognition and disclosure provisions ofFASB Statement 158, *Employers’ Accounting ForDefined Benefit Pension And Other Postretirement Plans*. Thisstatement also requires measurement of the funded status of a plan as of thebalance sheet date. The measurement provisions of the statement are effectivefor fiscal years ending after December 15, 2008. We do not expect theadoption of the change in measurement date in 2008 to have a material impact onour results of operations or financial position.

 

InFebruary 2007, FASB issued Statement 159, *The FairValue Option For Financial Assets and Financial Liabilities*. Thestatement allows for the elective measurement of eligible financial instrumentsand certain other items at fair value in order to mitigate volatility inreported earnings without having to apply complex and detailed hedge accountingrules. This statement is effective for fiscal years beginning after November 15,2007. We do not expect the adoption of this statement to have a material impacton our results of operations or financial position.

 

InDecember 2007, FASB issued Statement 141(revised), *BusinessCombinations*. Statement 141(revised) establishes principles andrequirements of the acquisition method for business combinations and relateddisclosures. This statement is effective for fiscal years beginning on or afterDecember 15, 2008. We do not expect the adoption of this statement to havea material impact on our results of operations or financial position.

 

InDecember 2007, FASB issued Statement 160, *NoncontrollingInterests In Consolidated Financial Statements, an amendment of ARB. No 51*.This statement clarifies that a noncontrolling interest in a subsidiary is anownership interest in the consolidated entity that should be reported as equityin the consolidated financial statements. This statement is effective forfiscal years beginning on or after December 15, 2008. We do not expect theadoption of this statement to have a material impact on our results ofoperations or financial position.

 

118

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Item 8     Financial Statements and SupplementaryData     Quarterly Data

 

SUPPLEMENTARYDATA (UNAUDITED)

 

**QuarterlyFinancial Data in Accordance with Canadian and US GAAP**

 
| ** **                                          | ** ** | **Quarter Ended** | ** ** |
|-----------------------------------------------------|------------|------------------------|------------|
| ** **                                          | ** ** | **March 31**      | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| **(Cdn$ millions)**                            | ** ** | **2007**               | ** ** | **2006** | ** ** | **2007** | ** ** | **2006** | ** ** | **2007** | ** ** | **2006** | ** ** | **2007** | ** ** | **2006** | ** ** |
| Net Sales                                           |       | 1,140                  |       | 980 |   | 1,399 |   | 1,039 |   | 1,446 |   | 997 |   | 1,598 |   | 920 |   |
|                                                |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Income (Loss) before Income Taxes is  Comprised of: |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Oil and Gas (1)                                     |       | 303                    |       | 196 |   | 604 |   | 476 |   | 642 |   | 372 |   | 308 |   | 56 |   |
| Energy Marketing                                    |       | (4                     | )          | 166 |   | 70 |   | 69 |   | (4 | ) | 42 |   | 5 |   | 139 |   |
| Syncrude                                            |       | 54                     |       | 20 |   | 48 |   | 59 |   | 88 |   | 77 |   | 76 |   | 51 |   |
| Chemicals                                           |       | 11                     |       | 12 |   | 21 |   | 22 |   | 25 |   | 10 |   | 7 | ** ** | **—** | ** ** |
| Corporate and Other                                 |       | (145                   | )          | (66 | ) | (93 | ) | (92 | ) | (63 | ) | (171 | ) | (57 | ) | (142 | ) |
| ** **                                          | ** ** | **219**                | ** ** | **328** | ** ** | **650** | ** ** | **534** | ** ** | **688** | ** ** | **330** | ** ** | **339** | ** ** | **104** | ** ** |
|                                                |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Net Income (Loss)—Canadian GAAP**            | ** ** | **121**                | ** ** | **(83** | **)** | **368** | ** ** | **408** | ** ** | **403** | ** ** | **199** | ** ** | **194** | ** ** | **77** | ** ** |
| US GAAP Adjustments                                 |       | (3                     | )          | 282 |   | (14 | ) | (11 | ) | (15 | ) | (283 | ) | (42 | ) | (10 | ) |
| **Net Income (Loss)—US GAAP**                  | ** ** | **118**                | ** ** | **199** | ** ** | **354** | ** ** | **397** | ** ** | **388** | ** ** | **(84** | **)** | **152** | ** ** | **67** | ** ** |
|                                                |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Earnings (Loss) per Common Share ($/share)**      |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Canadian GAAP—Basic                            |       | 0.23                   |       | (0.16 | ) | 0.70 |   | 0.78 |   | 0.77 |   | 0.38 |   | 0.37 |   | 0.15 |   |
| Canadian GAAP—Diluted                          |       | 0.22                   |       | (0.16 | ) | 0.68 |   | 0.76 |   | 0.75 |   | 0.37 |   | 0.36 |   | 0.14 |   |
| US GAAP—Basic                                  |       | 0.22                   |       | 0.38 |   | 0.67 |   | 0.76 |   | 0.74 |   | (0.16 | ) | 0.29 |   | 0.13 |   |
| US GAAP—Diluted                                |       | 0.22                   |       | 0.37 |   | 0.66 |   | 0.74 |   | 0.72 |   | (0.16 | ) | 0.28 |   | 0.12 |   |
|                                                |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Dividends Declared (2)**                          |       | 0.025                  |       | 0.025 |   | 0.025 |   | 0.025 |   | 0.025 |   | 0.025 |   | 0.025 |   | 0.025 |   |
|                                                |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Common Share Prices ($/share)**                   |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Toronto Stock Exchange—High                    |       | 37.60                  |       | 34.05 |   | 36.51 |   | 34.75 |   | 36.32 |   | 35.61 |   | 32.63 |   | 32.90 |   |
| Toronto Stock Exchange—Low                     |       | 29.66                  |       | 27.17 |   | 31.25 |   | 25.41 |   | 27.21 |   | 26.07 |   | 27.88 |   | 26.46 |   |
| New York Stock Exchange—High (US$)             |       | 31.88                  |       | 29.97 |   | 32.21 |   | 30.84 |   | 34.79 |   | 31.82 |   | 34.37 |   | 29.19 |   |
| New York Stock Exchange—Low (US$)              |       | 25.18                  |       | 23.49 |   | 29.08 |   | 22.82 |   | 25.25 |   | 23.35 |   | 27.58 |   | 23.45 |   |

 

----

| *Notes:* |
|----------|
| *(1)*    | *The  fourth quarter of 2007 includes an impairment charge of $366 million relating  to oil and gas properties in the Gulf of Mexico. The fourth quarter of 2006  includes an impairment charge of $93 million, primarily relating to two  natural gas properties in the Gulf of Mexico.* |
| *(2)*    | *In  February 2008, the Board of Directors declared a quarterly dividend of  $0.025 per common share, payable April 1, 2008, to shareholders of  record on March 10, 2008.* |
| *(3)*    | *At  December 31, 2007, there were 1,569 registered holders of common shares  and 528,304,813 common shares outstanding.* |

 

119

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Item 8     Financial Statements and SupplementaryData     FAS 69 Reserves

 

OIL AND GASPRODUCING ACTIVITIES AND SYNCRUDE OPERATIONS (UNAUDITED)

 

Thefollowing oil and gas information is provided in accordance with the FASBStatement No. 69 *Disclosures about Oil andGas Producing Activities.* It also includes information relating toour interest in Syncrude as it produces a crude oil product similar to our oiland gas activities even though these operations are considered mining activitiesunder SEC regulations.

 

**A.Reserve Quantity Information**

 

Ournet proved reserves and changes in those reserves for our conventionaloperations (excluding Syncrude) are disclosed below. The net proved reservesrepresent management’s best estimate of proved oil and natural gas reservesafter royalties. Reserve estimates for each property are prepared internallyeach year, and at least 80% of the reserves (including Syncrude) have beenassessed by independent qualified reserves consultants.

 

Estimatesof crude oil and natural gas proved reserves are determined through analysis ofgeological and engineering data, and demonstrate reasonable certainty that theyare recoverable from known reservoirs under economic and operating conditionsthat existed at year end. See Critical Accounting Estimates in Item 7 for adescription of our oil and gas and mining reserves estimation process.

 
| ** **                              | ** ** | ** ** | ** ** | ** **   | ** ** | ** ** | ** ** | ** **             | ** ** | ** **              | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Other** | ** ** |
|-----------------------------------------|------------|------------|------------|--------------|------------|------------|------------|------------------------|------------|-------------------------|------------|------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|-----------|------------|
| **Conventional oil and bitumen are in** | ** ** | **Total**  | ** ** | **Yemen(1)** | ** ** | **Canada** | ** ** | **United States** | ** ** | **United Kingdom** | ** ** | **Countries(3)** | ** ** |
| **mmbbls and natural gas is in bcf**    | ** ** | **Oil**    | ** ** | **Gas**      | ** ** | **Oil**    | ** ** | **Oil**                | ** ** | **Gas**                 | ** ** | **Bitumen (2)**  | ** ** | **Oil**    | ** ** | **Gas**    | ** ** | **Oil**    | ** ** | **Gas**    | ** ** | **Oil**   | ** ** |
| **Proved  Developed and**               | ** ** |       |       |         |       |       |       |                   |       |                    |       |             |       |       |       |       |       |       |       |       |       |      |       |
| **Undeveloped  Reserves (4)**           | ** ** |       |       |         |       |       |       |                   |       |                    |       |             |       |       |       |       |       |       |       |       |       |      |       |
| **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**    | ** ** |
|                                    | ** ** |       |       |         |       |       |       |                   |       |                    |       |             |       |       |       |       |       |       |       |       |       |      |       |
| Extensions and  Discoveries             | ** ** | 13         |       | 51           |       | 1          |       | 1                      |       | 31                      |       | —           |       | 1          |       | 18         |       | 10         |       | 2          |       | —    |       |
| Purchases of  Reserves in Place         | ** ** | 3          |       | 42           |       | —     |       | —                 |       | 1                       |       | —           |       | 2          |       | 41         |       | 1          |       | —     |       | —    |       |
| Sales of Reserves  in Place             | ** ** | —     |       | (10          | )          | —     |       | —                 |       | —                  |       | —           |       | —     |       | (10        | )          | —     |       | —     |       | —    |       |
| Revisions of  Previous Estimates        | ** ** | 53         |       | (11          | )          | (2         | )          | 3                      |       | 7                       |       | 15               |       | (6         | )          | (24        | )          | 43         |       | 6          |       | —    |       |
| Production                              | ** ** | (57        | )          | (72          | )          | (14        | )          | (5                     | )          | (35                     | )          | —           |       | (6         | )          | (31        | )          | (30        | )          | (6         | )          | (2        | )          |
| **December 31,  2007**             | ** ** | **561**    | ** ** | **532**      | ** ** | **23**     | ** ** | **47**                 | ** ** | **318**                 | ** ** | **234**          | ** ** | **21**     | ** ** | **189**    | ** ** | **203**    | ** ** | **25**     | ** ** | **33**    | ** ** |
|                                    | ** ** |       |       |         |       |       |       |                   |       |                    |       |             |       |       |       |       |       |       |       |       |       |      |       |
| **Proved  Developed Reserves (5)**      | ** ** |       |       |         |       |       |       |                   |       |                    |       |             |       |       |       |       |       |       |       |       |       |      |       |
| 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        |       |
| **December 31,  2007**             | ** ** | **281**    | ** ** | **423**      | ** ** | **22**     | ** ** | **44**                 | ** ** | **293**                 | ** ** | **40**           | ** ** | **17**     | ** ** | **114**    | ** ** | **151**    | ** ** | **16**     | ** ** | **7**     | ** ** |

 

----

| *Notes:*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(1) Under the terms of the Masila and the Block 51  production sharing contracts, production is divided into cost recovery oil  and profit oil. Cost recovery oil provides for the recovery of all our costs  and those of our partners. Remaining production is profit oil, which is  shared between the partners and the Government of Yemen based on production  rates, with the partners’ share ranging from 20% to 33%. The Government’s  share of profit oil represents its royalty interest and an amount for income  taxes payable in Yemen. Yemen’s net proved reserves have been determined  using the economic interest method and include our share of future cost  recovery and profit oil after the Government’s royalty interest, but before  reserves relating to income taxes payable. Under this method, reported  reserves will increase as oil prices decrease (and vice versa) as the barrels  necessary to achieve cost recovery change with prevailing oil prices.  Production includes volumes used for fuel.* |
| *(2) Represents bitumen reserves from the insitu recovery  of Canadian oil sands, rather than upgraded synthetic crude oil reserves to  be sold.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| *(3) Represents reserves in Nigeria and Colombia.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *(4) Proved oil and gas reserves are the estimated  quantities of natural gas, crude oil, condensate and natural gas liquids that  geological and engineering data demonstrate with reasonable certainty can be  recovered in future years from known reservoirs under existing economic and  operating conditions. Reserves are considered “proved” if they can be  produced economically, as demonstrated by either actual production or  conclusive formation test.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |

 

120

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*(5)Proved developed oil and gas reserves are expected to be recovered throughexisting wells with existing equipment and operating methods.*

 

Ournet proved reserves and changes in those reserves for our Syncrude operationsare disclosed below. Additional disclosures required by SEC Industry Guide 7are on pages 22 and 23. The net proved reserves represent management’s bestestimate of proved synthetic reserves after royalties.

 

Estimatesof Syncrude’s synthetic crude oil reserves are based on detailed geological andengineering assessments of the bitumen volume in-place, the mining plan,historical extraction recovery and upgrading yield factors, installed plantoperating capacity and operating approval limits. The in-place volume, depthand grade are established through extensive and closely spaced core drillingdensity of less than 500 metres. In accordance with the approved mining plan,there are an estimated 1,780 million tons of economically extractable oil sandsin the Base and North Mines, with an average bitumen grade of 10.6 weightpercent. The Aurora North Mine contains an estimated 4,810 million tons ofeconomically extractable oil sands at an average bitumen grade of 11.2 weightpercent. Aurora South Lease 31 contains measured economically extractable oilsands of 4,309 million tons at an average bitumen grade of 10.8 weight percent.

 
| ** **                          | ** ** | **Synthetic Crude Oil** | ** ** |
|-------------------------------------|------------|-----------------------------------|------------|
| ** **                          | ** ** | **Base Mine and**       | ** ** | ** ** | ** ** | ** ** | ** ** |
| **(millions of barrels)** | ** ** | **North Mine (1)**           | ** ** | **Aurora (2)** | ** ** | **Total** | ** ** |
| **December 31, 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** | ** ** |
| Revision of Previous Estimates      | ** ** | **—**                        |       | (7 | ) | (7 | ) |
| Extensions and Discoveries          | ** ** | **—**                        |       | 7 |   | 7 |   |
| Production                          |       | (3                                | )          | (4 | ) | (7 | ) |
| **December 31, 2007**          | ** ** | **42**                            | ** ** | **225** | ** ** | **267** | ** ** |

 

----

*Notes:*

*(1)**      **Leases 17 and 22*

*(2)**      **Leases 10, 12, 31 and 34.*

 

121

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**B.****           ****Capitalized Costs (excludingSyncrude operations)**

 
| ** **                  | ** ** | **Proved**     | ** ** | **Unproved**   | ** ** | **Accumulated** | ** ** | **Capitalized** | ** ** |
|-----------------------------|------------|----------------|------------|----------------|------------|-----------------|------------|-----------------|------------|
| **(Cdn$ millions)**    | ** ** | **Properties** | ** ** | **Properties** | ** ** | **DD&A**    | ** ** | **Costs**       | ** ** |
| **December 31, 2007**  |       |           |       |           |       |            |       |            |       |
| Yemen                       |       | 2,178          |       | —         |       | (1,950          | )          | 228             |       |
| Canada                      |       | 4,364          |       | 734            |       | (1,990          | )          | 3,108           |       |
| United States               |       | 2,931          |       | 138            |       | (1,765          | )          | 1,304           |       |
| United Kingdom              |       | 4,318          |       | 405            |       | (908            | )          | 3,815           |       |
| Other Countries             |       | 105            |       | 158            |       | (77             | )          | 186             |       |
| **Total Capitalized Costs** | ** ** | **13,896**     | ** ** | **1,435**      | ** ** | **(6,690**      | **)**      | **8,641**       | ** ** |
| **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**       | ** ** |

 

**C.****           ****Costs Incurred (excludingSyncrude operations)**

 
| ** **                            | ** ** | ** **                | ** ** | **Oil and Gas** | ** ** |
|---------------------------------------|------------|---------------------------|------------|---------------------------|------------|
| ** **                            | ** ** | **Total**                 | ** ** | ** **                | ** ** | ** ** | ** ** | **United** | ** ** | **United** | ** ** | ** ** | ** ** |
| **(Cdn$ millions)**              | ** ** | **Oil and Gas** | ** ** | **Yemen**                 | ** ** | **Canada** | ** ** | **States** | ** ** | **Kingdom** | ** ** | **Other** | ** ** |
| **Year Ended December 31, 2007** |       |                      |       |                      |       |   |   |   |   |   |   |   |   |
| Property Acquisition Costs            |       |                      |       |                      |       |   |   |   |   |   |   |   |   |
| Proved                                |       | 151                       |       | —                    |       | 1 |   | 104 |   | 46 |   | — |   |
| Unproved                              |       | 59                        |       | —                    |       | 34 |   | 24 |   | 1 |   | — |   |
| Exploration Costs                     |       | 637                       |       | 15                        |       | 93 |   | 311 |   | 128 |   | 90 |   |
| Development Costs                     |       | 1,817                     |       | 124                       |       | 675 |   | 414 |   | 551 |   | 53 |   |
| Asset Retirement Costs                |       | 169                       |       | 6                         |       | 48 |   | 30 |   | 85 |   | — |   |
| **Total Costs Incurred**              | ** ** | **2,833**                 | ** ** | **145**                   | ** ** | **851** | ** ** | **883** | ** ** | **811** | ** ** | **143** | ** ** |
| **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** | ** ** |

 

122

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**D.****           ****Results of Operations forProducing Activities (excluding Syncrude operations)**

 
| ** **                                            | ** ** | ** **                | ** ** | **Oil and Gas** | ** ** |
|-------------------------------------------------------|------------|---------------------------|------------|---------------------------|------------|
| ** **                                            | ** ** | **Total**                 | ** ** | ** **                | ** ** | ** ** | ** ** | **United** | ** ** | **United** | ** ** | **Other** | ** ** |
| **(Cdn$ millions)**                              | ** ** | **Oil and Gas** | ** ** | **Yemen**                 | ** ** | **Canada (1)** | ** ** | **States** | ** ** | **Kingdom** | ** ** | **Countries** | ** ** |
| **Year Ended December 31, 2007**                 |       |                      |       |                      |       |   |   |   |   |   |   |   |   |
| Net Sales                                             |       | 4,576                     |       | 1,086                     |       | 441 |   | 616 |   | 2,285 |   | 148 |   |
| Production Costs                                      |       | 668                       |       | 171                       |       | 175 |   | 102 |   | 212 |   | 8 |   |
| Exploration Expense                                   |       | 326                       |       | 5                         |       | 27 |   | 134 |   | 69 |   | 91 |   |
| Depreciation, Depletion, Amortization and  Impairment |       | 1,627                     |       | 213                       |       | 166 |   | 641 |   | 599 |   | 8 |   |
| Other Expenses (Income)                               |       | 100                       |       | (8                        | )          | 66 |   | 38 |   | (36 | ) | 40 |   |
|                                                  |       | 1,855                     |       | 705                       |       | 7 |   | (299 | ) | 1,441 |   | 1 |   |
| Income Tax Provision (Recovery)                       |       | 859                       |       | 248                       |       | 2 |   | (103 | ) | 712 |   | — |   |
| **Results of Operations**                             | ** ** | **996**                   | ** ** | **457**                   | ** ** | **5** | ** ** | **(196** | **)** | **729** | ** ** | **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                                        |       | 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** | **)** |

 

----

*Note:*

*(1) 2005 includes results of discontinuedoperations (see Note 14).*

 

123

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**E.Standardized Measure of Discounted Future Net Cash Flows and Changes Therein(excluding Syncrude operations)**

 

Thefollowing disclosure is based on estimates of net proved reserves (excludingSyncrude) and the period during which they are expected to be produced. Futurecash inflows are computed by applying year-end prices to our after royaltyshare of estimated annual future production from proved oil and gas reserves(excluding Syncrude operations). Future development and production costs to beincurred in producing and further developing the proved reserves are based onyear-end cost indicators. Future income taxes are computed by applying year-endstatutory tax rates. These rates reflect allowable deductions and tax credits,and are applied to the estimated pre-tax future net cash flows.

 

Discountedfuture net cash flows are calculated using 10% mid-period discount factors. Thecalculations assume the continuation of existing economic, operating andcontractual conditions. However, such arbitrary assumptions have not proved tobe the case in the past. Other assumptions could give rise to substantiallydifferent results.

 

Webelieve this information does not in any way reflect the current economic valueof our oil and gas producing properties or the present value of their estimatedfuture 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.

 
| **(Cdn$ millions)**                              | ** ** | **Total**  | ** ** | **Yemen**  | ** ** | **Canada** | ** ** | **United  States** | ** ** | **United  Kingdom** | ** ** | **Other  Countries** | ** ** |
|-------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|--------------------|------------|---------------------|------------|----------------------|------------|
| **December 31,  2007**                           |       |       |       |       |       |       |       |               |       |                |       |                 |       |
| Future Cash Inflows                                   |       | 43,888     |       | 1,952      |       | 17,365     |       | 3,207              |       | 17,977              |       | 3,387                |       |
| Future Production Costs                               |       | 11,988     |       | 468        |       | 7,229      |       | 539                |       | 3,347               |       | 405                  |       |
| Future Development Costs                              |       | 3,229      |       | 22         |       | 957        |       | 328                |       | 778                 |       | 1,144                |       |
| Future Dismantlement and Site Restoration  Costs, Net |       | 1,143      |       | 16         |       | 273        |       | 197                |       | 595                 |       | 62                   |       |
| Future Income Tax                                     |       | 8,793      |       | 452        |       | 1,135      |       | 437                |       | 6,589               |       | 180                  |       |
| Future Net Cash Flows                                 |       | 18,735     |       | 994        |       | 7,771      |       | 1,706              |       | 6,668               |       | 1,596                |       |
| 10% Discount Factor                                   |       | 7,606      |       | 111        |       | 4,236      |       | 441                |       | 1,561               |       | 1,257                |       |
| **Standardized Measure**                              | ** ** | **11,129** | ** ** | **883**    | ** ** | **3,535**  | ** ** | **1,265**          | ** ** | **5,107**           | ** ** | **339**              | ** ** |
| ** **                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **         | ** ** | ** **          | ** ** | ** **           | ** ** |
| **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**              | ** ** |

 

124

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Item 8     Financial Statementsand Supplementary Data     Controls andProcedures

 

**Changesin the Standardized Measure of Discounted Future Net Cash Flows**

 

Thefollowing are the principal sources of change in the standardized measure ofdiscounted future net cash flows:

 
| **(Cdn$ millions)**                                                                  | ** ** | **2007**   | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|-------------------------------------------------------------------------------------------|------------|------------|------------|-----------|------------|-----------|------------|
| Beginning of Year                                                                         |       | 8,373      |       | 8,042     |       | 6,290     |       |
| Sales and Transfers of Oil and Gas  Produced, Net of Production Costs                     |       | (3,010     | )          | (2,291    | )          | (2,028    | )          |
| Net Changes in Prices and Production Costs  Related to Future Production                  |       | 3,385      |       | (1,065    | )          | 3,302     |       |
| Extensions, Discoveries and Improved  Recovery, Less Related Costs                        |       | 758        |       | 695       |       | 977       |       |
| Changes in Estimated Future Development and  Dismantlement Costs                          |       | (443       | )          | (692      | )          | (135      | )          |
| Previous Estimated Future Development and  Dismantlement Costs Incurred During the Period |       | 1,102      |       | 1,048     |       | 638       |       |
| Revisions of Previous Quantity Estimates                                                  |       | 2,189      |       | 1,936     |       | 478       |       |
| Accretion of Discount                                                                     |       | 1,191      |       | 1,117     |       | 799       |       |
| Purchases of Reserves in Place                                                            |       | 272        |       | 2         |       | 15        |       |
| Sales of Reserves in Place                                                                |       | (49        | )          | (2        | )          | (882      | )          |
| Net Change in Income Taxes                                                                |       | (2,639     | )          | (417      | )          | (1,412    | )          |
| **End of Year**                                                                           | ** ** | **11,129** | ** ** | **8,373** | ** ** | **8,042** | ** ** |

 

**ITEM 9. CHANGES IN ANDDISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE**

 

Therewere no disagreements with accountants on accounting and financial disclosure.

 

**ITEM 9A. CONTROLS AND PROCEDURESEVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES**

 

OurChief Executive Officer and Chief Financial Officer have evaluated theeffectiveness of our disclosure controls and procedures (as defined in ExchangeAct Rules 13a-15(e) and 15-d-15(e)) as of the end of the periodcovered by this report. They concluded that, as of the end of the periodcovered by this report, our disclosure controls and procedures were adequateand effective in ensuring that material information relating to the Company andits consolidated subsidiaries would be made known to them by others withinthose entities, particularly during the period in which this report was beingprepared. Management recognizes that any controls and procedures, no matter howwell designed and operated, can provide only reasonable assurance of achievingthe desired control objectives, and in reaching a reasonable level ofassurance, management necessarily is required to apply its judgement inevaluating the cost-benefit relationship of possible controls and procedures.

 

**MANAGEMENT’SREPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING**

 

Ourmanagement is responsible for establishing and maintaining adequate internalcontrol over financial reporting (as defined in Exchange Act Rules 13a-15(f)).Under the supervision and with the participation of our management, includingour principal executive officer (CEO) and principal financial officer (CFO), weconducted an evaluation of the effectiveness of our internal control overfinancial reporting based on the Internal Control-Integrated Framework issuedby the Committee of Sponsoring Organizations of the Treadway Commission. Basedon our evaluation, we concluded that our internal control over financialreporting is effective as of December 31, 2007. We have documented thisassessment and made this assessment available to our independent registeredChartered Accountants. We recognize that 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.

 

Deloitte &Touche LLP audited our Consolidated Financial Statements as stated in theirreport which is on page 126 of this Form 10-K and has issued anattestation report on our internal control over financial reporting.

 

**CHANGESIN INTERNAL CONTROLS**

 

Wehave continually had in place systems relative to internal controls overfinancial reporting. There have not been any changes in the Company’s internalcontrol over financial reporting during the last quarter that have materiallyaffected, or are reasonably likely to materially affect, our internal controlover financial reporting. As well, no material weaknesses requiring correctiveaction were identified in the conduct of our evaluation of internal controlover financial reporting. As a result, no such corrective actions were taken.

 

125

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Item 8     Financial Statementsand Supplementary Data     Auditors’Report on Internal Controls

 

**REPORTOF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS**

 

**To theBoard of Directors and Shareholders of Nexen Inc.:**

 

Wehave audited the internal control over financial reporting of Nexen Inc. andsubsidiaries (the “Company”) as of December 31, 2007, based on criteriaestablished in Internal Control— Integrated Framework issued by the Committeeof Sponsoring Organizations of the Treadway Commission. The Company’smanagement is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting, included in the accompanying Management’sReport on Internal Control over Financial Reporting. Our responsibility is toexpress an opinion on the Company’s internal control over financial reportingbased on our audit.

 

Weconducted our audit in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whethereffective internal control over financial reporting was maintained in allmaterial respects. Our audit included obtaining an understanding of internalcontrol over financial reporting, assessing the risk that a material weaknessexists, testing and evaluating the design and operating effectiveness of internalcontrol based on the assessed risk, and performing such other procedures as weconsidered necessary in the circumstances. We believe that our audit provides areasonable basis for our opinion.

 

Acompany’s internal control over financial reporting is a process designed by,or under the supervision of, the company’s principal executive and principalfinancial officers, or persons performing similar functions, and effected bythe company’s board of directors, management, and other personnel to provide reasonableassurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generallyaccepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (1) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (3) provide reasonable assurance regarding preventionor timely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

 

Becauseof the inherent limitations of internal control over financial reporting,including the possibility of collusion or improper management override ofcontrols, material misstatements due to error or fraud may not be prevented ordetected on a timely basis. Also, projections of any evaluation of theeffectiveness of the internal control over financial reporting to futureperiods are subject to the risk that the controls may become inadequate becauseof changes in conditions, or that the degree of compliance with the policies orprocedures may deteriorate.

 

Inour opinion, the Company maintained, in all material respects, effectiveinternal control over financial reporting as of December 31, 2007, basedon the criteria established in Internal Control — Integrated Framework issuedby the Committee of Sponsoring Organizations of the Treadway Commission.

 

Wehave also audited, in accordance with Canadian generally accepted auditingstandards and the standards of the Public Company Accounting Oversight Board(United States), the consolidated financial statements of the Company as of andfor the year ended December 31, 2007, and our report dated February 13,2008, expressed an unqualified opinion on those financial statements andincludes a separate report titled Comments by Independent Registered CharteredAccountants on Canada—United States of America Reporting Difference referringto changes in accounting principles that have a material effect on thecomparability of the Company’s financial statements.

 

(signed)“Deloitte & Touche LLP”

IndependentRegistered Chartered Accountants

Calgary,Canada

February 13,2008

 

126

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| corporategovernance              |
|----------------------------------|
|                             |
| Recognized as a leader           |
| in corporate governance,         |
| we are committed to              |
| meaningful, transparent          |
| disclosure for all stakeholders. |

 

127

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**PARTS III AND IV**

 

**ITEMS 10 TO 15**

 
| Directors                                                                  | 129 |
|----------------------------------------------------------------------------|-----|
| Director Compensation                                                      | 131 |
| Compensation  Committee Report                                             | 134 |
| Compensation  Committee Interlocks and Insider Participation               | 135 |
| Compensation  Overview                                                     | 135 |
| Executive Officers                                                         | 141 |
| Summary Compensation  Table                                                | 142 |
| CEO Compensation and 2007 Goals                                            | 143 |
| CEO  Three-Year Look-Back                                                  | 143 |
| Equity Ownership and Changes in 2007                                       | 144 |
| Tops Tables                                                                | 144 |
| Pension  Plan Tables                                                       | 146 |
| All  Other Compensation                                                    | 148 |
| Termination  Arrangements                                                  | 148 |
| Share Performance Graph                                                    | 150 |
| Corporate Governance                                                       | 151 |
| Governance Committee  Report                                               | 151 |
| Security  Ownership of Certain Beneficial Owners and Management            | 154 |
| Certain  Relationships and Related Transactions, and Director Independence | 155 |
| Principal  Accounting Fees and Services                                    | 155 |
| Exhibits,  Financial Statement Schedules                                   | 157 |
| Certifications                                                             | 160 |

 

128

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| Item 10 to 15 | Corporate Governance | Directors |
|---------------|----------------------|-----------|

** **

**PART III**

**Items 10and 11. Directors, Executive Officers and Corporate**

**Governance, and ExecutiveCompensation**

 

**DIRECTORS**

 

According to our Articles,Nexen must have between three and 15 directors. On July 5, 2006, the boarddetermined that, until changed, there will be 12 directors.

 

Our By-Laws provide thatdirectors will be elected at the annual general meeting of shareowners (AGM)each year and will hold office until their successors are elected. All of our currentdirectors were elected at the last AGM.

 

This shows our directors’principal occupations or employment during the past five years and any otherdirectorships they held in public companies as at February 14, 2008. Thefollowing directors are management nominees for election to the board.

 
| **Name****(Age)**                      | ** ** | **Principal Occupation**                                                                                                                                                                                                                                                                                                                     | ** ** | **Other Directorships**                                                                        | ** ** | **Nexen  Director Since** | ** ** |
|----------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------|------------|---------------------------|------------|
| Charles W. Fischer (57)                |       | President and Chief Executive Officer (CEO) of  Nexen.                                                                                                                                                                                                                                                                                       |       |                                                                                           |       | 2000                      |       |
| Dennis G. Flanagan (1), (3) (68)       |       | Retired oil executive.                                                                                                                                                                                                                                                                                                                       |       | Canexus Income Fund  (Chair) NAL Oil & Gas Trust                                           |       | 2000                      |       |
| David A. Hentschel (4) (74)            |       | Retired oil executive.  Formerly: Oil and gas consultant.                                                                                                                                                                                                                                                                                    |       | Cimarex Energy Co.                                                                             |       | 1985                      |       |
| S. Barry Jackson (1) (55)              |       | 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) (51)         |       | Managing Director of  TriWest Capital Partners Formerly: President and CEO of The Westaim  Corporation.                                                                                                                                                                                                                                      |       |                                                                                           |       | 1996                      |       |
| A. Anne McLellan, P.C. (1)  (57)       |       | Counsel with 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:  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. (63)              |       | Retired Chair and CEO of  Syncrude Canada Ltd.                                                                                                                                                                                                                                                                                               |       |                                                                                           |       | 2004                      |       |
| Thomas C. O’Neill (1), (2) (62)   |       | 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) (69)      |       | Chair of Nexen. Counsel  with 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) (74) |       | Retired banking executive.                                                                                                                                                                                                                                                                                                                   |       | The Thomson Corporation                                                                        |       | 1997                      |       |
| John M. Willson (1) (68)               |       | Retired mining executive.                                                                                                                                                                                                                                                                                                                    |       | Finning International Inc.

Harry Winston Diamond  Corporation Pan American Silver Corporation |       | 1996                      |       |
| Victor J. Zaleschuk (5) (64)           |       | Retired oil executive.                                                                                                                                                                                                                                                                                                                       |       | Agrium Inc.

Cameco Corporation (Chair)                                                        |       | 1997                      |       |

 

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*Notes:*

*(1)**       **All membersof the Audit and Conduct Review (Audit), Corporate Governance and Nominating(Governance) and Compensation and Human Resources (Compensation) Committees areindependent. All members of the Audit Committee are independent underadditional regulations for audit committee members.*

*(2)**      **FinancialExperts on Nexen’s Audit Committee.*

*(3)**      **Mr. Flanaganwas a director of Elek-Tek Inc., a US public computer retailing company, thatwas subject to bankruptcy proceedings in 1998.*

*(4)**      **Mr. Hentschelwas Chair and CEO of Occidental Oil and Gas Corporation from 1997 to 1999 andPresident and CEO of Nexen from 1995 to 1997.*

*(5)**      **Mr. Zaleschukwas President and CEO of Nexen from 1997 to 2001.*

 

129

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**Independenceand Board Committees**

 

The board affirmed directorindependence under our categorical standards for director independence(categorical standards), which are available at www.nexeninc.com. The categoricalstandards have been in place since 2003 and most recently amended on February 14,2008. Our categorical standards meet or exceed the requirements set out in SEC rules andregulations, the Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley), the NYSE rules, *National Policy 58-201—CorporateGovernance Guidelines, Multilateral Instrument 52-110*—*Audit Committees*, and applicableprovisions of *National**Instrument51-101*—*Standards of Disclosure forOil and Gas Activities.*

 

Mr. Fischer is notindependent as he is President and CEO.

 

Mr. Flanagan is notindependent as his son is Senior Vice President, Engineering, of TriAxonResources Ltd. (TriAxon). In 2006, TriAxon acquired a company that was party tocontracts with a subsidiary of Nexen. Under one of the contracts, Nexen paidapproximately $4.5 million to TriAxon between July and December 2006for products purchased at market price. Accordingly, Mr. Flanagan is nottechnically independent as of July 1, 2007. Mr. Flanagan was notaware that the company acquired by TriAxon held contracts with Nexen. The boardhas determined that Mr. Flanagan’s independence of mind has not beencompromised by this transaction and accordingly, the board continues to includehim in their meetings without management.

 

Ms. McLellan has beencounsel with Bennett Jones LLP (BJ), Barristers and Solicitors, Edmonton,Alberta, since June 27, 2006. BJ provided legal services to us in each ofthe last five years. Ms. McLellan does not solicit or participate in thoseservices and does not receive any portion of the fees we pay to BJ. She isindependent under our categorical standards.

 

Mr. Saville was a seniorpartner of Fraser Milner Casgrain LLP (FMC), Barristers and Solicitors,Calgary, Alberta, until the end of January 2004. Since February 1,2004, he has been counsel with the firm. FMC provided legal services to us ineach of the last five years. Mr. Saville does not solicit or participatein those services and does not receive any portion of the fees we pay to FMC.He is independent under our categorical standards.

 

We have not had an executivecommittee of the board since July 11, 2000.

 
|                                            |   | **Committees  (Number  of Members)** | ** ** |
|-------------------------------------------------|--------|--------------------------------------|------------|
|                                            |   | **Audit****(1), (2)****(6)**         | ** ** | **Compensation  (****1)****(7)** | ** ** | **Governance  (****1)****(7)** | ** ** | **Finance(6)** | ** ** | **Reserves  (3)********(7)** | ** ** | **HSE  & SR (8)** | ** ** |
| **Management  Director — Not Independent** |   |                                 |       |   |   |   |   |   |   |   |   |   |   |
| Charles W. Fischer                              |   |                                 |       |   |   |   |   |   |   |   |   |   |   |
| **Outside  Director — Not Independent**    |   |                                 |       |   |   |   |   |   |   |   |   |   |   |
| Dennis G.  Flanagan                             |   |                                 |       |   |   |   |   | ü |   | ü |   | ü |   |
| **Independent  Outside Directors**              |   |                                 |       |   |   |   |   |   |   |   |   |   |   |
| David A.  Hentschel                             |   |                                 |       |   |   |   |   | ü |   | ü |   | ü |   |
| S. Barry Jackson                                |   | ü                               |       | ü |   |   |   |   |   | ü |   | Chair |   |
| Kevin J. Jenkins  (4)                           |   | ü                               |       | Chair |   | ü |   |   |   |   |   | ü |   |
| A. Anne McLellan, P.C.                          |   |                                 |       | ü |   | ü |   | ü |   |   |   | ü |   |
| Eric P. Newell,  O.C.                           |   | ü                               |       |   |   | ü |   |   |   | ü |   | ü |   |
| Thomas C.  O’Neill (4), (5)                |   | Chair                                |       | ü |   | ü |   |   |   | ü |   |   |   |
| Francis M.  Saville, Q.C.                       |   |                                 |       | ü |   | ü |   | ü |   |   |   | ü |   |
| Richard M.  Thomson, O.C. (4)                   |   | ü                               |       | ü |   | Chair |   | ü |   |   |   |   |   |
| John M. Willson                                 |   | ü                               |       | ü |   | ü |   |   |   | Chair |   |   |   |
| Victor J.  Zaleschuk                            |   |                                 |       |   |   |   |   | Chair |   | ü |   | ü |   |
|                                                 |        |                                      |            |  |  |  |  |  |  |  |  |  |  |  |

 

----

*Notes:*

*(1)**      **All membersare independent. All Audit Committee members are independent under additionalregulatory requirements applicable to them.*

*(2)**      **Experienceof the members of the Audit Committee that indicates an understanding of theaccounting principles we use to prepare our financial statements is shown intheir biographies on page 131.*

*(3)**      **A majorityof the Reserves Review (Reserves) Committee are independent.*

*(4)**      **Auditcommittee financial expert under US regulatory requirements.*

*(5)**      **The boardhas determined that Mr. O’Neill’s service on the audit committees of threeother public companies and one not–for–profit organization does not impair hisability to serve as Chair of Nexen’s Audit Committee. The board considered thatMr. O’Neill had a 30+ year career as a Chartered Accountant and, sinceretiring as Chair of PWC Consulting in 2002, his only business commitments areto the boards and committees on which he serves.*

 

130

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**AuditCommittee Financial Expert Experience**

 
| **Name**     | ** ** | **Experience**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
|--------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Jenkins      | ** ** | Kevin Jenkins, 51, 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 Vice Chair of World Vision Canada.                   |
|         |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| O’Neill |       | Tom O’Neill, 62, 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 and Adecco S.A. He is a member of the External  Audit Committee of the International Monetary Fund. 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, 74, 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’ andofficers’ liability insurance policy. The policy provides coverage for costsincurred to defend and settle claims against directors and officers of Nexen toan annual limit of US$150 million with a US$12.5 million deductible for anindemnifiable occurrence and no deductible for a non-indemnifiable occurrence.The cost of coverage for 2007 was approximately US$1 million. Directors andofficers do not pay any portion of the premiums and no indemnity claims weremade or paid in 2007.

 

**Directors’and Officers’ Fiduciary Insurance**

 

Nexen maintains a fiduciaryliability insurance policy. It provides coverage for costs incurred to defendand settle claims against Nexen, our directors, officers and employees forbreach of fiduciary duty in connection with company sponsored plans, such aspension and savings plans. The policy has an annual limit of US$25 million witha US$2.5 million deductible for an indemnifiable occurrence and no deductiblefor a non-indemnifiable occurrence. The cost of coverage for 2007 wasapproximately US$30,000. Directors and officers do not pay any portion of thepremiums and no claims were made or paid in 2007.

 

**Loans toDirectors**

 

As set out in the corporategovernance policy, we do not make loans to our directors. There are no loansoutstanding from Nexen to any of our directors.

 

**DIRECTOR COMPENSATION**

 

Nexen provides its directorswith a comprehensive compensation package consisting of annual cash retainers,meeting fees and equity-based incentives in the form of deferred share units (DSUs).The total compensation package provides a competitive level of remuneration forthe increasing responsibilities, time commitments and accountability of boardmembers. All elements of director compensation are reviewed annually forcompetitiveness against a peer group of oil and gas companies by management,the Compensation Committee and the board. Our compensation philosophy targetsand currently provides total compensation between the 50th and 75th percentile.This is intended to attract and retain qualified talent to serve on our board.

 

Directors may choose toreceive select benefits coverage at Nexen’s expense, including basic lifeinsurance, extended health care, dental, business travel accident insurance,and the reimbursement of provincial health care premiums (in certain jurisdictions).Mr. Zaleschuk, a former CEO of Nexen is a retiree in the Nexen pensionplan. The pension benefit provided to him is for previous service as anemployee.

 

See page 132 for thechanges to director compensation made January 1, 2008 and page 133 formore information on DSUs.

 

131

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**DirectorSummary Compensation Table**

 
| **Name**     | ** ** | **Total  Fees Earned (1)** | ** **    | **DSU  Awards (2)** | ** ** | **All Other  Compensation (3)** | ** ** | **Total  Compensation** | ** **  |
|--------------|------------|---------------------------------|---------------|---------------------|------------|--------------------------------------|------------|-------------------------|-------------|
| Fischer (4)  |       | —                          |          | —              |       | —                               |       | —                  | ** **  |
| Flanagan     |       | 107,933                         |          | 141,950             |       | 97,178                               | (5)        | 347,061                 |        |
| Hentschel    |       | 104,300                         |          | 141,950             |       | 2,787                                |       | 249,037                 |        |
| Jackson      |       | 124,700                         |          | 141,950             |       | 3,242                                |       | 269,892                 |        |
| Jenkins      |       | 126,500                         |          | 141,950             |       | 4,007                                |       | 272,457                 |        |
| McLellan     |       | 121,200                         |          | 141,950             |       | 1,128                                |       | 264,278                 |        |
| Newell       |       | 110,967                         |          | 141,950             |       | 4,254                                |       | 257,171                 |        |
| O’Neill |       | 143,600                         |          | 141,950             |       | 3,692                                |       | 289,242                 |        |
| Saville      |       | 271,200                         |          | 227,120             |       | 3,219                                |       | 501,539                 |        |
| Thomson      |       | 131,000                         |          | 141,950             |       | 5,665                                |       | 278,615                 |        |
| Willson      |       | 127,400                         |          | 141,950             |       | 3,920                                |       | 273,270                 |        |
| Zaleschuk    |       | 106,600                         |          | 141,950             |       | 2,823                                |       | 251,373                 |        |
| **Total**    | ** ** | ** **                      | **1,475,400** | ** **          | ** ** | **1,646,620**                        | ** ** | ** **              | **131,915** | ** ** | ** ** | **3,253,935** | ** ** |
|              |            |                                 |               |                     |            |                                      |            |                         |             |  |  |  |  |

 

----

*Notes:*

*(1)**      **Includesall retainers and meetings fees, including those paid in DSUs.*

*(2)**      **The valueof DSUs granted on December 3, 2007, based on the closing market price ofNexen common shares on the TSX on November 30, 2007 of $28.39.*

*(3)**      **The totalvalue of perquisites provided to each director is less than both $50,000 or 10%of total fees, and is not included in this column. Amounts reflect lifeinsurance premiums paid by Nexen, reinvested dividends earned in 2007 valued atthe closing market price of Nexen common shares on the TSX on the paymentdates, travel allowance paid by Nexen, and Canexus fees as set out in note 5.*

*(4)**      **As anexecutive of Nexen, Mr. Fischer is not paid any director compensation.*

*(5)**      **Mr. Flanaganis the Board Chair of Canexus and was paid fees of $57,500, received deferredtrust units of Canexus valued at $29,340 and distributions on his trust unitsof $7,665 in 2007. The total is included in this column.*

 

**Director Retainersand Fees**

 

Annual board and committeeretainers are paid quarterly and pro-rated for partial service. The same feesare paid for attending meetings in person or by conference call. A travel allowanceof $1,500 was introduced on February 15, 2007. It is paid whenever adirector travels outside of his or her home province or state, or travels morethan a total of three hours, round trip, to attend a Nexen meeting or sitevisit. Nexen also reimburses directors for out-of-pocket travel expenses. New retainerswere approved as of January 1, 2008.

 
| ** **                                              | ** ** | **2007** | ** ** | **2008** | ** ** |
|---------------------------------------------------------|------------|----------|------------|----------|------------|
| Board Chair Retainer                                    |       | 178,100  | (1)        | 250,000  | (2)        |
| Board Member Retainer                                   |       | 28,100   |       | 35,000   |       |
| Audit Committee Chair Retainer                          |       | 19,700   |       | 19,700   |       |
| Other Committee Chair Retainer                          |       | 5,300    |       | 5,300    |       |
| Committee Member Retainer                               |       | 9,100    |       | 9,100    |       |
| Board and Committee Meeting Fees (per meeting attended) |       | 1,800    |       | 1,800    |       |

 

----

*Notes:*

*(1)**           **Totalof the Board Chair Retainer of $150,000, plus the Board Member Retainer of$28,100.*

*(2)**           **As of January 1,2008, the Board Chair is paid only this retainer and the travel allowance. Hedoes not receive any other retainers or meetings fees.*

** **

**2007Retainers and Fees**

 
| **Name**     | ** ** | **Annual  Board  Retainer** | ** **  | **Annual  Committee  Retainer** | ** ** | **Annual  Committee  Chair  Retainer** | ** ** | **Board  Meeting  Fees** | ** ** | **Committee  Meeting  Fees** | ** ** | **Travel  Allowance** | ** ** | **Total Fees  Earned** | ** **  | **Total Fees  Credited in  DSUs (1)** | ** ** | **Total Fees  Earned in  Cash** | ** ** |
|--------------|------------|-----------------------------|-------------|---------------------------------|------------|----------------------------------------|------------|--------------------------|------------|------------------------------|------------|-----------------------|------------|-----------------------------|-------------|-------------------------------------------------|------------|-------------------------------------------|------------|
| Fischer (2)  |       | —                      |        | —                          |       | —                                 |       | —                   |       | —                       |       | —                |       | —                      |        | —                                          |       | —                                    | ** ** |
| Flanagan     |       | 28,100                      |        | 30,333                          |       | —                                 |       | 16,200                   |       | 28,800                       |       | 4,500                 |       | 107,933                     |        | —                                          |       | 107,933                                   | ** ** |
| Hentschel    |       | 28,100                      |        | 27,300                          |       | —                                 |       | 16,200                   |       | 25,200                       |       | 7,500                 |       | 104,300                     |        | —                                          |       | 104,300                                   | ** ** |
| Jackson      |       | 28,100                      |        | 36,400                          |       | 5,300                                  |       | 16,200                   |       | 34,200                       |       | 4,500                 |       | 124,700                     |        | 120,200                                         |       | 4,500                                     |       |
| Jenkins      |       | 28,100                      |        | 36,400                          |       | 5,300                                  |       | 16,200                   |       | 36,000                       |       | 4,500                 |       | 126,500                     |        | —                                          |       | 126,500                                   |       |
| McLellan     |       | 28,100                      |        | 36,400                          |       | —                                 |       | 16,200                   |       | 36,000                       |       | 4,500                 |       | 121,200                     |        | 116,700                                         |       | 4,500                                     |       |
| Newell       |       | 28,100                      |        | 33,367                          |       | —                                 |       | 16,200                   |       | 28,800                       |       | 4,500                 |       | 110,967                     |        | 106,467                                         |       | 4,500                                     |       |
| O’Neill |       | 28,100                      |        | 36,400                          |       | 19,700                                 | (3)        | 16,200                   |       | 34,200                       |       | 9,000                 |       | 143,600                     |        | —                                          |       | 143,600                                   |       |
| Saville      |       | 178,100                     |        | 36,400                          |       | —                                 |       | 16,200                   |       | 36,000                       |       | 4,500                 |       | 271,200                     |        | —                                          |       | 271,200                                   |       |
| Thomson      |       | 28,100                      |        | 36,400                          |       | 5,300                                  |       | 16,200                   |       | 36,000                       |       | 9,000                 |       | 131,000                     |        | 122,000                                         |       | 9,000                                     |       |
| Willson      |       | 28,100                      |        | 36,400                          |       | 5,300                                  |       | 14,400                   |       | 34,200                       |       | 9,000                 |       | 127,400                     |        | —                                          |       | 127,400                                   |       |
| Zaleschuk    |       | 28,100                      |        | 27,300                          |       | 5,300                                  |       | 16,200                   |       | 25,200                       |       | 4,500                 |       | 106,600                     |        | 28,100                                          |       | 78,500                                    |       |
| **Total**    | ** ** | ** **                  | **459,100** | ** **                      | ** ** | **373,100**                            | ** ** | ** **               | **46,200** | ** **                   | ** ** | **176,400**           | ** ** | ** **                  | **354,600** | ** **                                      | **66,000** | ** **                                | ** ** | **1,475,400** | ** ** | ** ** | **493,467** | ** ** | ** ** | **981,933** | ** ** |
|              |            |                             |             |                                 |            |                                        |            |                          |            |                              |            |                       |            |                             |             |                                                 |            |                                           |            |  |  |  |  |  |  |  |  |

 

----

*Notes:*

*(1) Detailsof DSU holdings are set out in the table on page 133.*

*(2) As anexecutive officer of Nexen, Mr. Fischer is not paid any directorcompensation.*

*(3) Mr. O’Neillis the Audit Committee chair.*

 

132

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**ShareOwnership Guideline**

 

Directors demonstrate theircommitment to Nexen’s success through share ownership. On February 14,2008, the board approved guidelines that set out that directors are expected toown or control at least 16,800 shares or DSUs. This amount represents at leastthree times both the base annual board retainer of $35,000 and the value of thebase annual DSU grant. They must be accumulated as follows:

 

·    5,600 by end of year 1

·    11,200 by end of year 2

·    16,800 by end of year 3

 

New directors will berequired to take their base annual retainer in DSUs until the current thresholdis met. If there is a change in share value or size of the annual grant of DSUsthat causes a director to no longer meet the requirement, he or she will havenine months to meet the threshold again.

 

All directors surpass theseguidelines.

 

**DeferredShare Units**

 

Nexen has two DSU plans.Under the first plan, eligible directors may elect annually to receive all orpart of their fees in DSUs, rather than cash. Under the second plan, DSUs replacedstock options in 2003 as the long-term incentive used to align the interests ofdirectors with shareowners.

 

DSUs provide directors with astake in Nexen during their term of service. DSUs don’t grant the right to voteas there are no shares underlying the plans. A DSU is a bookkeeping entry thattracks the value of one Nexen common share. When cash dividends are paid onNexen common shares, eligible directors are credited with additional DSUs,equal to the value of the dividend paid. DSUs accumulate over a director’s termof service and are only paid out when the director leaves the board. At thattime, payments may be made in cash or in Nexen common shares purchased on theopen market, at Nexen’s option.

 
| **Name**     | ** ** | **DSUs Held as of December 31, 2007 (1)** | ** ** |
|--------------|------------|-------------------------------------------------------------------------|------------|
| Fischer      |       | —                                                                  |       |
| Flanagan     |       | 30,536                                                                  |       |
| Hentschel    |       | 30,531                                                                  |       |
| Jackson      |       | 37,989                                                                  |       |
| Jenkins      |       | 43,611                                                                  |       |
| McLellan     |       | 17,052                                                                  |       |
| Newell       |       | 47,988                                                                  |       |
| O’Neill |       | 40,453                                                                  |       |
| Saville      |       | 37,962                                                                  |       |
| Thomson      |       | 62,322                                                                  |       |
| Willson      |       | 43,025                                                                  |       |
| Zaleschuk    |       | 32,298                                                                  |       |

 

----

*Note:*

*(1) Numberof DSUs has been adjusted to account for Nexen’s share splits that occurred in May 2005and May 2007.*

 

**DSUs Grantedin 2007**

 
| ** **    | ** ** | ** **          | ** ** | ** ** | ** ** | **Base**      | ** ** | **Value of** | ** ** |
|---------------|------------|---------------------|------------|------------|------------|---------------|------------|-------------------|------------|
| **Position**  | ** ** | **Grant Date** | ** ** | **DSUs**   | ** ** | **Price (1)** | ** ** | **DSUs (2)**      | ** ** |
| ** **    | ** ** | ** **          | ** ** | **(#)**    | ** ** | **($)**       | ** ** | **($)**           | ** ** |
| Board Chair   |       | Dec  3, 2007        |       | 8,000      |       | 28.39         |       | 227,120           |       |
| Other         |       |                |       |       |       |          |       |              |       |
| non-executive |       |                |       |       |       |          |       |              |       |
| Directors     |       | Dec  3, 2007        |       | 5,000      |       | 28.39         |       | 141,950           |       |

 

----

*Notes:*

*(1) Theclosing market price of Nexen common shares on the TSX on November 30,2007.*

*(2) Thenumber of DSUs times the base price.*

** **

**TOPsExercised or Exchanged and Awards Vested During 2007**

 

All exercises or exchanges oftandem options (TOPs) in 2007 occurred within nine months of their expiry.There are no vesting provisions and no value realized on vesting under the DSUplan.

 
| ** **   | ** ** | **TOPs Awards**                 | ** ** | **DSU Awards**         | ** ** |
|--------------|------------|--------------------------------------|------------|-----------------------------|------------|
| **Name**     | ** ** | **Exercised or Exchanged** | ** ** | **Value Realized (1)** | ** ** | **Shares Acquired on Vesting** | ** ** | **Value Realized ** | ** ** |
| ** **   | ** ** | **(#)**                              | ** ** | **($)**                     | ** ** | **(#)** | ** ** | **($)** | ** ** |
| Flanagan     |       | 7,260                                |       | 157,742                     |       | — |   | — |   |
| Hentschel    |       | 22,000                               |       | 445,885                     |       | — |   | — |   |
| Jackson      |       | 22,000                               |       | 517,165                     |       | — |   | — |   |
| Jenkins      |       | 22,000                               |       | 484,385                     |       | — |   | — |   |
| O’Neill |       | 22,000                               |       | 503,305                     |       | — |   | — |   |
| Saville      |       | 7,260                                |       | 157,669                     |       | — |   | — |   |
| Thomson      |       | 33,200                               |       | 776,133                     |       | — |   | — |   |
| Willson      |       | 7,332                                |       | 197,066                     |       | — |   | — |   |
| **Total**    | ** ** | **143,052**                          | ** ** | **3,239,350**               | ** ** | **—** | ** ** | **—** | ** ** |

 

----

*Note:*

*(1) Marketprice at the time of the exercise or exchange, minus the exercise price, asdefined in the Tandem Option (TOPs) plan.*

 

133

----

 

**COMPENSATION COMMITTEE REPORT**

 

The Compensation Committeeassists the board in overseeing key compensation and human resources policies,CEO and executive 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.

 

All members of the Committeeare independent and knowledgeable about our compensation programs and policies.Five members of the Committee are skilled or expert in compensation, the areaof expertise most relevant to carrying out the Committee’s mandate.

 

**Changes toCommittee Membership in 2007**

 

There were no changes to theCommittee membership in 2007.

 

**KeyActivities in 2007**

 

·                  Recommendedcompensation programs for base salary, annual cash and long-term incentives(Tandem Option (TOPs) Plan and Stock Appreciation Rights (STARs) Plan);

·                  Recommendedsalaries, bonuses and grants of TOPs to the executives;

·                  Assessed CEOperformance on short-term and long-term corporate goals and objectives andrecommended CEO compensation, which was approved by the independent directorsof the board;

·                  Reviewed the CEO’sannual objectives and our executive management succession and development plans;

·                  Evaluated andrecommended organizational changes and officer appointments;

·                  Recommendedspecial recognition awards for key business initiatives;

·                  Recommendeddirector compensation, including DSU grants; and

·                  Reviewedexisting change of control agreements for executives in light of currentcompensation.

 

**OutsideConsultant**

 

The Committee engaged MercerHuman Resources Consulting (Mercer) to provide a confidential report andtechnical analysis of market data on the CEO’s compensation, in light of our operationsand compensation programs. Mercer also provided a compensation report on aselect group of our executives. The reports included competitive informationfrom a list of peer companies recommended by Mercer. The decisions of theCommittee are their responsibility and may reflect factors other than theinformation and recommendations provided by Mercer and management.

 

Mercer did not provide anycompensation consulting services to management in 2007. We participated incompensation surveys in Canada and international locations and purchased selectpublished results. Management must obtain Committee approval before retainingMercer for any compensation consulting work.

 

**Fees Billedby Outside Consultant (Mercer)**

 
| **Type of Fee**                                        | ** ** | **Billed in 2006** | ** ** | **Billed in 2007** | ** ** | **Percentage of Total  Fees billed in 2007** | ** ** |
|------------------------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|-----------------------------------------------------------------------|------------|
| Committee work—Assessment of CEO and executive compensation |       | 37,780                       |       | 49,610                       |       | 100                                                                   | %          |
| Management work—Administrative services                     |       | 3,470                        |       | —                       |       | —                                                                |       |
| **Total annual Fees**                                            | ** ** | **41,250**                   | ** ** | **49,610**                   | ** ** | **100**                                                               | **%**      |

 

**ExternalRecognition and Verification**

 

Nexen was recognized for itshuman resource practices during 2007, including being named one of:

 

·                  Canada’s 50 BestEmployers in Canada by Hewitt Associates Inc.;

·                  Alberta’s TopEmployers by Mediacorp Canada Inc.; and

·                  Canada’s 30 BestPension and Benefits Plans by Benefits Canada magazine.

 

**CommitteeApproval**

 

The Committee has reviewedand discussed with management the compensation disclosure in this document,including the information in the Board of Directors section on pages 131 through132, in the Compensation Overview section on pages 135 through 140 and inthe Executive Compensation section on pages 142 through 150, and hasrecommended to the board that it be included in the Management Proxy Circularfor the 2008 Annual General and Special Meeting of Shareholders and, asappropriate, Form 10-K.

 

**Submittedon behalf of the Compensation Committee:**

 

Kevin Jenkins, Chair

Barry Jackson

Anne McLellan

Tom O’Neill

Francis Saville

Dick Thomson

John Willson

 

134

----

 

**COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION**

 

The members of theCompensation Committee are set out on page 130. Mr. Saville had arelationship requiring disclosure, the details of which are set out under “CertainRelationships and Related Transactions, and Director Independence” on page 155.There are no Compensation Committee interlocks during 2007.

 

**COMPENSATION OVERVIEW**

 

**CompensationDisclosure**

 

Our compensation disclosurecomplies with the requirements of the Canadian Securities Administrators. As aforeign private issuer in the US, we are not required to disclose compensation accordingto the SEC rules issued in 2006. We have, however, complied with thespirit of those rules where possible, without compromising requiredCanadian disclosure.

 

**CompensationPhilosophy**

 

Our policies and practicesfor executive compensation are linked to strategic business objectives,including increasing shareowner returns. Our philosophy is to compensateexecutives:

 

·                  based onperformance;

·                  at a levelcompetitive with our peers; and

·                  in a mannerdesigned to attract and retain talented leadership focused on managing Nexen’soperations, finances and assets.

 

All of our compensationprograms are designed to meet pay-for-performance and competitivenessobjectives. Actual rewards are directly linked to the results of Nexen and our divisions.The objective and subjective performance measures are aligned with shareownerinterests, including financial and non-financial goals. Measures set each yearrepresent improvements to our operations.

 

Our programs are responsiveto market changes. We aim for simplicity in our compensation programs to helpemployees understand the value of the various components. Executive programsare generally consistent with employee programs in the same location. Wherecertain programs, such as perquisites, are only provided to executives orsenior management, they reflect competitive practice and particular business needsand objectives.

 

**BenchmarkReview**

 

We use third-partycompensation surveys to compare our pay levels and practices, including basepay, annual cash incentives and long-term incentives, to our peers. We look mainlyat Canadian-based oil and gas and integrated pipeline companies with whom wecompete for talent. Given similar positions across the industry, the surveyseffectively represent competitive pay levels. It should be noted, however, wedo not know the extent to which our peers particpate in the surveys andbenchmark each position. The peer group is modified in some cases to reflect (i) geographicallocation, (ii) a particular business line, (iii) a more comparableposition, or (iv) industry mergers and acquisitions.

 

The composition of our peergroup is reviewed annually by third-party consultants and the CompensationCommittee for continued relevance. In 2007, our executive peer groups comprisedup to 16 companies, including the following publicly-traded companies:

 

Canadian Natural ResourcesLimited

Enbridge Inc.

EnCana Corporation

Husky Energy Inc.

Petro-Canada

Suncor Energy Inc.

Talisman Energy Inc.

TransCanada Corporation

 

The Compensation Committeereviews all programs to ensure we continue to attract and retain thehigh-performing employees needed to achieve our business objectives, whiledemonstrating long-term fiscal responsibility to shareowners.

 

**CompensationObjectives**

 

Our compensation programsinclude three components: base salary, annual cash incentive and long-termincentive. At least once a year we assess the competitiveness of theseindividual components and the overall compensation. Our goal is to provide totalcompensation for top performing employees between the 50th and 75th percentileas compared to our peers.

 

**Key Elements of Compensation**

* *
| **Element**           | ** ** | **Component** | ** ** | **Form**       | ** ** | **Performance Period** | ** ** |
|-----------------------|------------|---------------|------------|----------------|------------|-----------------------------|------------|
| Base salary           |       | Fixed         |       | Cash           |       | 1 year                      |       |
| Annual cash incentive |       | Variable      |       | Cash           |       | 1 year                      |       |
| Long-term incentive   |       | Variable      |       | TOPs and StARs |       | Greater than 1 year         |       |

 

135

----

 

**Target Weightings**

 

Since our compensationprograms are designed to meet both performance and competitiveness objectives,actual pay will vary from year to year against the target weightings. Ingeneral, the targets are designed to provide most executive compensation in theform of at-risk pay to ensure alignment with shareowners. Base salary providesa competitive foundation considering both internal comparability and externalmarket data. Annual cash incentives reward the delivery of results againstobjective and subjective measures within a one-year period. Long-termincentives reward Nexen’s sustained performance as seen in share priceappreciation. The actual mix between the compensation elements varies,depending on the executive’s ability to influence short and long-term businessresults, their level, and competitive local market practices.

 
| ** **        | ** ** | ** **           | ** ** | **At-Risk Compensation**** (1)** | ** ** |
|-------------------|------------|----------------------|------------|--------------------------------------------|------------|
| **Position**      | ** ** | **Base Salary** | ** ** | **Annual Cash Incentive**        | ** ** | **Long-Term Incentive** | ** ** |
| CEO               |       | 20                   | %          | 15                                         | %          | 65 | % |
| CFO/Executive VPs |       | 25                   | %          | 20                                         | %          | 55 | % |
| Senior VPs        |       | 30                   | %          | 20                                         | %          | 50 | % |

 

----

*Note:*

*(1) Represents the percentage of total compensation,excluding benefits, pension and perquisites.*

 

**CompensationApproval Process**

 

 

In determining our executives’base salary, annual cash and long-term incentives, the Compensation Committeeconsiders a comprehensive analysis, including a tally sheet prepared bymanagement with help from an executive compensation consultant. The analysisincludes market data for similar positions within the peer group and CEOrecommendations for his direct reports, including all of the other namedexecutive officers (executives) and information on prior year annual cash andlong-term incentives. Management also provides a sensitivity analysis thatconsiders the pension cost implications for each 1% of incremental pensionableearnings.

 

The Committee reviews thevarious compensation elements both individually and in total to ensure theyalign with the program objectives. In addition, the Committee retains theservices of its own executive compensation consultant, Mercer, to provide externalmarket data and commentary on the relative positioning of executives,particularly the CEO. The Committee then makes recommendations on all executivepayments and grants to the board or independent directors for approval.Typically, this process begins in the fall and concludes with totalcompensation being approved the following February.

 

136

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**BaseSalaries**

 

A framework of job levelsbased on internal comparability and external market data is used to determinebase salaries, considering the individual’s current and sustained performance,skills and potential.

 

**Annual CashIncentives**

 

The program providescompetitive bonus compensation that reflects Nexen’s overall performance andthat of the individual.

 

**2007 Annual Incentive Measures**

 

The board, at therecommendation of the Compensation Committee, approves the factor thatdetermines the cash pool available for annual cash incentives after reviewingNexen’s objective and subjective performance measures. The factor may range from0 to 200%. The factors used were 200% in 2005, 120% in 2006 and 88% in 2007.

 

**2007 Objective PerformanceMeasures (50%)**

 
| **Measure**      | ** ** | **Target** | ** **     | **Results** | ** ** | **Results versus Target** | ** ** |
|------------------|------------|------------|----------------|-------------|------------|-------------------------------------|------------|
| Cash flow (25%)  |       | $          | 3,290  million |        | $          | 3,458  million                      |       | 105 | % |
| Net income (25%) |       | $          | 981  million   |        | $          | 1,086  million                      |       | 111 | % |

 

**2007 Subjective PerformanceMeasures (50%)**

 

The Compensation Committeesubjectively considers 19 business measures commonly used in our industry. Theyinclude, among other things, stock performance, annual stock performanceagainst peers, production volumes, safety and environmental incidents, andreserve-related metrics. The Committee also assesses costs, including findingand development, operating and administrative. The business measures areassessed against objectives in light of our external environment and currentbusiness circumstances, including key projects and initiatives critical toNexen’s success. Both absolute performance and performance relative to peers arereviewed. The Committee also considers management’s assessment of Nexen’sperformance and progress against the strategic plan. The Committee exercisesits discretion in assessing Nexen’s overall performance and may increase or decreasethe total cash available for these awards. For 2007, the Committee consideredthat, while our financial results were strong, we were not as successful in achievingcertain other business targets.

 

The cash pool available forannual incentives is then allocated to employees and executives based onindividual target levels and performance. The targets for individual awardsincrease as job responsibilities grow so that the ratio of at-risk versus fixedcompensation is greater for higher levels of responsibility. Individualperformance is assessed by the direct supervisor and reflects performanceagainst pre-determined objectives. The actual incentive award received by theexecutive may be more or less than the target level. Typically, executiveawards range from 0 to 200% of the target for that position.

 

**2007 Annual Incentive Targets (****1)**

 
| **Position**      | ** ** | **Minimum** | ** ** | **Target** | ** ** | **Maximum** | ** ** |
|-------------------|------------|-------------|------------|------------|------------|-------------|------------|
| CEO (2)           |       | 0           | %          | 80         | %          | 160         | %          |
| CFO/Executive VPs |       | 0           | %          | 60         | %          | 120         | %          |
| Senior VPs        |       | 0           | %          | 45         | %          | 90          | %          |

 

----

*Note:*

*(1)** **Reflectspercentage of base salary on December 31, 2007.*

*(2)**      **To ensurecompetitive compensation, the independent directors of the board increased thetarget from 75% to 80% and the maximum from 150% to 160% effective January 1,2007.*

 

**Reimbursement**

 

If, as a result ofmisconduct, Nexen’s performance results were restated in a way that decreasedthe incentive awards, the CEO and CFO would reimburse Nexen proportionately asrequired by law.

 

**Share OwnershipGuidelines**

 

All executive officersdemonstrate their commitment to Nexen by holding more shares than requiredunder our board approved guidelines. Shares must be accumulated within five yearsfrom date the executive was appointed. Share ownership includes the net valueof exercisable options or TOPs, flow-through shares, shares purchased and heldwithin the Nexen employee savings plan and any other personal holdings. Theguidelines are reviewed periodically by the Compensation Committee and the board.See page 144 for the current share ownership of each executive.

** **
| **Position**             | ** ** | **Required Share Ownership** |
|--------------------------|------------|------------------------------|
| CEO                      |       | Three  times annual salary   |
| CFO                      |       | Two  times annual salary     |
| Other executive officers |       | One  times annual salary     |

 

137

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**Long-termIncentives**

 

The TOPs and STARs plansprovide employees with a long-term incentive to continue high performance,demonstrate commitment to Nexen and, most importantly, align their interests withthose of our shareowners. As Nexen’s share price rises, grants increase invalue. Nexen’s long-term incentive program (the TOPs and STARs plans) aregranted to officers and employees whose actions can most directly impact our businessresults.

 

In determining the number ofTOPs and STARs to grant each year, Nexen considers the program’s dilutiveimpact on shareowners and market information on options and other forms oflong-term incentives. Market information also determines the extent to whichemployees at different levels participate in the program. Management and theCompensation Committee have considered alternative long-term incentive programsused by our peers, including full-value plans such as DSUs, restricted shareunits and performance-based stock options. At this time, TOPs and STARscontinue to best meet Nexen’s objectives, considering competitive position,retention value, tax effectiveness for both our employees and Nexen, shareownerinterests, and dilution levels.

 

**TOPs Plan**

 

Our TOPs plan has been inplace since 2004. It allows employees to either:

 

·                  exchange theirvested TOPs for a cash payment equal to  thedifference between the grant price and the closing market price of our commonshares on the date the TOPs were exchanged; or

·                  exercise theirTOPs for shares.

 

When employees exchange theirTOPs for cash: (i) no shares are issued, which prevents further shareownerdilution over time; and (ii) Nexen receives a Canadian income taxdeduction.

 
| **2007 TOPs Plan Exercises and Exchanges** | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------|------------|------------|------------|

 
| Total exercised or exchanged   |   | 6,670,714      |   |
|--------------------------------|--------|----------------|--------|
| Exercised for shares (percent) |   | 2,256,954  (34 | )%     |
| Exchanged for cash (percent)   |   | 4,413,760  (66 | )%     |

 

TOPs do not provide employeeswith the right to vote the underlying shares. The TOPs plan is Nexen’s onlyequity-based compensation arrangement for the purposes of disclosure requirements.

 

The board, on therecommendation of the Compensation Committee, may grant TOPs to Nexen officersand employees. TOPs granted before February 2001 have a term of ten years;20% of the grant vested after six months and 20% vested each year for fouryears on the grant’s anniversary. TOPs granted after February 2001 have aterm of five years and vest one-third each year for three years.

 

Generally, if a change ofcontrol event occurs (as defined in the TOPs plan), all issued but unvestedoptions will vest. The board  approvedminor amendments to the TOPs plan in 2007.

 

**STARs Plan**

 

The STARs plan, introduced in2001, provides a cash payment to participants equal to the appreciation inNexen’s share price between the date the STARs are granted and the date they areexercised. STARs are typically granted to employees below mid-level departmentmanager. They have a five-year term and vest one-third each year for threeyears.

 

**Grant Date and Exercise Price**

 

TOPs and STARs are grantedduring the annual grant process and at the time of hiring key positions. Since1998, the annual grants have been approved at the December board meeting. Accordingto our plans, the CEO can approve grants to key new hires and typically theyoccur shortly after the hire date. Under the plans, the exercise price is theclosing market price of Nexen’s common shares on the relevant stock exchange (TSXfor Canadian-based employees or NYSE for US-based employees) on the day beforethe grant is approved. Accordingly, backdating is not allowed. Nexen’s grantsare not intentionally timed to occur immediately prior to the release ofmaterial information (spring-loaded). The exercise price of existing TOPs orSTARs may not be reduced except for automatic adjustments under the plans (forexample, on share splits) or according to TSX rules.

 

138

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**Grants in the Last Three Years**

 

Our 2007 long-term incentivesrecognized high performance, future potential within Nexen and retention risk.

 
| ** ** | ** ** | **Granted to**         | ** ** | **Granted**           | ** ** | **Percentage of Employees** | ** ** | **Total Number** | ** ** |
|------------|------------|-----------------------------|------------|-----------------------|------------|---------------------------------------|------------|-----------------------|------------|
| **Year**   | ** ** | **Executive Officers** | ** ** | **to Employees** | ** ** | **Receiving Grants**             | ** ** | **Granted**           | ** ** |
| **TOPs**   |       |                        |       |                  |       |                                  |       |                  |       |
| 2007       |       | 1,735,000                   |       | 2,272,100             |       | 7                                     | %          | 4,007,100             |       |
| 2006 (1)   |       | 1,480,000                   |       | 3,321,000             |       | 7                                     | %          | 4,801,000             |       |
| 2005 (1)   |       | 1,184,000                   |       | 5,599,000             |       | 20                                    | %          | 6,783,000             |       |
| **STARs**  |       |                        |       |                  |       |                                  |       |                  |       |
| 2007       |       | —                      |       | 4,194,600             |       | 54                                    | %          | 4,194,600             |       |
| 2006 (1)   |       | —                      |       | 4,508,600             |       | 51                                    | %          | 4,508,600             |       |
| 2005 (1)   |       | —                      |       | 2,886,100             |       | 39                                    | %          | 2,886,100             |       |

 

----

*Note:*

*(1) Numbers of TOPs and StARs granted have been adjusted to account forNexen’s two-for-one share split in May 2005 and May 2007.*

 

**Benefit andPension Plans**

 

Our benefit and pension planssupport the health and well-being of our employees, and encourage retirementsavings. The plans are reviewed periodically to ensure they remain competitiveand continue to meet our objectives. Market survey data is reviewed to ensurethe plans provide benefits between the 50th and 75th percentile of plans withinour peer group of companies. Executives participate in the same plans providedto all employees at the same location.

 

Disclosure in this documentis specific to the Canadian and US plans in which the executives participate.Nexen provides a variety of other benefit and pension plans outside of Canada andthe US that reflect local market practices.

 

**Health and Welfare Benefits**

 

Our benefit plans aredesigned to protect employees’ health and that of their dependents, and coverthem in the event of disability or death. Under the flexible benefits plans, employeeschoose the level of coverage that best fits their needs. Those who selectenhanced coverage levels are required to contribute to the cost of thatcoverage.

 

**Employee Savings Plan**

 

In the employee savings plan,all eligible Canadian employees may contribute, through payroll deduction, 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, depending on the investment option and how long the employeehas participated in the plan. Nexen contributions are invested in our commonshares purchased on the open market and vest immediately. All contributions maybe allocated to registered or non-registered accounts. Employees may vote theNexen common shares they hold in their employee savings plan.

 

The employee savings plan inthe US is intended to qualify under Section 401(a) and 501(a) ofthe Internal Revenue Code. Nexen’s matching contribution, of up to 6% ofeligible compensation, is provided in cash, which vests immediately.

 

**Defined Benefit Pension Plan(Canada)**

 

Canadian employees of Nexenelect, upon hire, to participate in either the defined contribution pensionplan or the defined benefit pension plan, both of which are registered. All executivesparticipated in the defined benefit pension plan in 2007. It is funded by apension trust and features:

 

·                  participantcontributions at 3% of their regular gross earnings (up to an annual planmaximum);

·                  retirementbenefits at 1.8% (1.7% for years prior to 2005) of their average earnings forthe 36 highest-paid consecutive months during the ten years before retirement, multipliedby the years of credited service;

·                  integration withCanada Pension Plan (CPP) to provide a maximum offset of one-half of thecurrent CPP benefit;

·                  benefits onretirement that are generally paid monthly for the life of the retiree, subjectto payment elections; and

·                  ability forparticipants to periodically switch between the defined benefit pension planand defined contribution pension plan at different stages in their career.

 

Pension benefits earned priorto 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 between 0and 5% based on the greater of:

 

·                  75% of the increase in the consumerprice index, less 1%; and

·                  25% of the increase in theconsumer price index.

 

139

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Plan participants mayincrease their defined benefit accrual formula on a go-forward basis, from 1.8%to 2%. Employees who choose this option must contribute an additional 2% of pensionableearnings up to an allowable maximum under the Canadian Income Tax Act. Themaximum employee contribution allowed under the defined benefit pension plan in2007 was $10,700.

 

**Executive Benefit Plan (Canada)**

 

The executive benefit plan isavailable to all Canadian employees. It provides supplemental retirementbenefits for participants who have earned a retirement benefit in excess of thestatutory limits, which varies by employees’ pension elections. This allowsemployees to accrue a pension that is aligned with their final earnings leveland is competitive within our market. Under this plan, benefits accrue and arepaid monthly in a similar manner to the underlying defined benefit pension planset out above on page 139. For executives, annual cash incentive paymentsduring the last three years they participated in this plan are included forbenefit accrual purposes. For annual cash incentives, the pension benefit is accruedon the lesser of target bonus or actual bonus paid, averaged over the finalthree years of participation.

 

**Pension Benefit Security**

 

The pension expense for thissupplemental plan is accounted for annually. Benefits are paid from Nexen’scash flows and reduce the related pension liability. As liabilities under this planare not funded outside of Nexen, a level of protection is provided toparticipants through a letter of credit. The letter of credit is intended tomake participants secured creditors for the total value of Nexen’s unfundedpension obligation. The cost of servicing the letter of credit in 2007 for allplan participants was $509,135.

 

**Pension Benefit Obligation**

 

At December 31, 2007, asindicated in the notes to our financial statements, the:

 

·                  supplementalpension plan’s accumulated benefit obligation (the projected benefitobligation, excluding future salary increases) for the executive benefit planwas $48 million; and

·                  projected benefitobligation was $62 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 those used byothers and, as a result, the estimate may not be directly comparable acrosscompanies. The key assumptions used for the projected benefit obligation were:

 

·                  a discount rateof 5.25% per year;

·                  a long-termcompensation rate increase of 4% per year; and

·                  an expectedaverage remaining service life of ten years.

 

As of January 1, 2005,the executive benefit plan was amended to provide a supplemental pension allocationfor defined contribution pension plan participants who are impacted by annualstatutory contribution limits. In 2007, the supplemental allocation foreligible participants was $35,341 and is estimated to be $37,000 in 2008.

 

**Defined Contribution Pension Plan(US)**

 

All US employees participatein this qualified retirement plan. Nexen contributes 6% of eligiblecompensation up to the social security wage base, and, 11.5% of eligiblecompensation that exceeds the social security taxable wage base. For 2007,Nexen’s maximum contribution per participant was US$20,513. Employees are notpermitted to contribute to the plan. Investment decisions are made by theemployee from a variety of mutual funds. The contributions vest after two yearsof service. This plan is intended to be an Employee Retirement Income SecurityAct (ERISA) 404(c) plan. Only one executive participated in the definedcontribution pension plan for US employees in 2007.

 

**Non-Qualified Restoration Plan(US)**

 

This supplemental plan isavailable to all US employees. It is an unfunded arrangement that providesdeferred compensation benefits to participants who have earned a retirement benefitin excess of the statutory limits. The returns in this plan reflect the returnson the investments selected by the employee. The plan complies with Section 409Aof the Internal Revenue Code.

 

**Loans to Officers**

 

As set out in the corporategovernance policy, Nexen does not make loans to its officers. There are noloans outstanding from Nexen to any of its officers.

 

140

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**EXECUTIVE OFFICERS**

 

Theboard determines the term of office for each executive officer. Below are Nexen’sofficers, including prior offices and non-executive positions for officers whohave held their current executive positions with Nexen for less than fiveyears. Start dates are indicated for officer positions with Nexen.

 
| **Officer (Age)**          | ** ** | **Current and  Past Position(s) with Nexen**                                                                                                                                                                                     | ** ** | **Effective Date  of****Current Position** | ** ** | **Executive****Officer Since** |
|----------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|--------------------------------|
| Charles W. Fischer (57)    |       | President and CEO and a  director                                                                                                                                                                                                     |       | June 1,  2001                         |       | 1994                           |
| Marvin F. Romanow (52)     |       | Executive VP and CFO                                                                                                                                                                                                                  |       | June 1,  2001                         |       | 1997                           |
| Laurence Murphy (56)       |       | Executive VP, International  Oil and Gas  Formerly: Senior VP, International Oil and Gas since January 1, 1999                                                                                                                   |       | November 1,  2007                     |       | 1998                           |
| Roger D. Thomas (55)       |       | Executive VP, North America  Formerly: Senior VP, Canadian Oil and Gas since February 19,1999                                                                                                                                    |       | November 1,  2007                     |       | 1998                           |
| Gary H. Nieuwenburg (49)   |       | Senior VP, Synthetic Crude  Formerly: VP, Synthetic Crude since July 11, 2002                                                                                                                                                    |       | November 1,  2007                     |       | 2001                           |
| Kevin J. Reinhart (49)     |       | Senior VP, Corporate Planning  and Business Development  Formerly: VP, Corporate Planning and Business Development since July 11,  2002                                                                                          |       | November 1,  2007                     |       | 1994                           |
| Brian C. Reinsborough (46) |       | Senior VP, United States Oil  and Gas  Formerly: Division VP, Exploration, Operations and Production since  May 12, 2006; Division VP, Exploration since July 8, 2002                                                       |       | November 1,  2007                     |       | 2007                           |
| Timothy J. Thomas (50)     |       | Senior VP, Canadian Oil and  Gas  Formerly: Division VP, Exploration and Production, Canadian Oil and Gas since  April 1, 2004; Division VP, Yemen Operations and International Business  Development since January 1, 2003 |       | November 1,  2007                     |       | 2007                           |
| Randy J. Jahrig (52)       |       | VP, Human Resources and  Corporate Services Formerly: Division VP, Human Resources Canada and  International since April 1, 2002                                                                                                 |       | April 26,  2007                       |       | 2007                           |
| Kim D. McKenzie (59)       |       | VP and Chief Information  Officer  Formerly: Division VP, Information Technology since January 1, 1992                                                                                                                           |       | November 1,  2007                     |       | 2007                           |
| Eric B. Miller (45)        |       | VP, General Counsel and Secretary  Formerly: Division VP and Chief Legal Counsel since July 1, 2006;  Division VP, Legal Canadian Oil and Gas since March 1, 2002                                                           |       | July 11,  2007                        |       | 2007                           |
| Una M. Power (43)          |       | Treasurer                                                                                                                                                                                                                             |       | July 11,  2002                        |       | 1998                           |
| Brendon T. Muller (39)     |       | Controller  Formerly: Manager, Corporate External Reporting since November 1, 2003;  Team Lead, Corporate Accounting since April 1, 2002                                                                                    |       | April 9,  2007                        |       | 2007                           |

 

141

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**SHARE SPLITs**

 

All grant prices and numbersgranted have been adjusted to account for the May 2005 and May 2007share splits.

 

**SUMMARY COMPENSATION TABLE**

 

The compensation for the CEO,CFO and the next three highest paid officers (named executive officers orexecutives), plus Mr. Douglas Otten who retired November 1, 2007, isprovided. To determine the next three highest paid officers we total their salary,special bonus and non-equity cash incentive compensation as show below.

 
| ** **                  | ** ** | ** ** | ** ** | **Annual** | ** ** | **Long-Term**  | ** ** | **Other**               | ** ** | ** **     | ** ** |
|-----------------------------|------------|------------|------------|------------|------------|----------------|------------|-------------------------|------------|----------------|------------|
| ** **                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** **     | ** ** | **Non-Equity**          | ** ** | ** **     | ** ** | ** ** | ** ** | **Changes in** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Name and**           | ** ** | ** ** | ** ** | ** ** | ** ** | **Special**    | ** ** | **Cash Incentive** | ** ** | **TOPs ** | ** ** | **TOPs** | ** ** | **Pension** | ** ** | **AllOther** | ** ** | **Total** | ** ** |
| **Principal Position** | ** ** | **Year**   | ** ** | **Salary** | ** ** | **Bonus  (1)** | ** ** | **Compensation  (2)**   | ** ** | **Awards**     | ** ** | **Awards  (3)** | ** ** | **Obligations  (4)** | ** ** | **Compensation  (5), (6)** | ** ** | **Compensation  (6)** | ** ** |
| ** **                  | ** ** | ** ** | ** ** | **($)**    | ** ** | **($)**        | ** ** | **($)**                 | ** ** | **(#)**        | ** ** | **($)** | ** ** | **($)** | ** ** | **($)** | ** ** | **($)** | ** ** |
| Charles W. Fischer,         |       | 2007       |       | 1,275,000  |       | —         |       | 916,000                 |       | 600,000        |       | 5,110,200 |   | 949,300 |   | 119,640 |   | 8,370,140 |   |
| President                   |       | 2006       |       | 1,150,000  |       | 500,000        |       | 1,300,000               |       | 550,000        |       | 5,010,654 |   | 1,673,800 |   | 111,621 |   | 9,746,075 |   |
| and CEO                     |       | 2005       |       | 975,000    |       | 300,000        |       | 1,500,000               |       | 400,000        |       | 3,110,490 |   | 879,300 |   | 101,364 |   | 6,866,154 |   |
|                        |       |       |       |       |       |           |       |                    |       |           |       |   |   |   |   |   |   |   |   |
| Marvin F. Romanow  (7),     |       | 2007       |       | 566,250    |       | —         |       | 330,000                 |       | 180,000        |       | 1,533,060 |   | 323,300 |   | 117,129 |   | 2,869,739 |   |
| Executive VP                |       | 2006       |       | 528,000    |       | —         |       | 402,000                 |       | 160,000        |       | 1,457,645 |   | 534,800 |   | 118,073 |   | 3,040,518 |   |
| and CFO                     |       | 2005       |       | 486,000    |       | 175,000        |       | 590,000                 |       | 124,000        |       | 964,252 |   | 176,300 |   | 89,557 |   | 2,481,109 |   |
|                        |       |       |       |       |       |           |       |                    |       |           |       |   |   |   |   |   |   |   |   |
| Laurence Murphy,            |       |       |       |       |       |           |       |                    |       |           |       |   |   |   |   |   |   |   |   |
| Executive VP,               |       | 2007       |       | 495,833    |       | —         |       | 303,000                 |       | 165,000        |       | 1,405,305 |   | 583,300 |   | 57,214 |   | 2,844,652 |   |
| International               |       | 2006       |       | 455,000    |       | 300,000        |       | 342,000                 |       | 130,000        |       | 1,184,336 |   | 580,800 |   | 53,711 |   | 2,915,847 |   |
| Oil and Gas                 |       | 2005       |       | 405,000    |       | —         |       | 410,000                 |       | 100,000        |       | 777,623 |   | 141,300 |   | 44,439 |   | 1,778,362 |   |
|                        |       |       |       |       |       |           |       |                    |       |           |       |   |   |   |   |   |   |   |   |
| Roger D. Thomas,            |       | 2007       |       | 487,500    |       | —         |       | 275,000                 |       | 165,000        |       | 1,405,305 |   | 792,300 |   | 56,690 |   | 3,016,795 |   |
| Executive VP,               |       | 2006       |       | 445,000    |       | —         |       | 336,000                 |       | 130,000        |       | 1,184,336 |   | 735,800 |   | 53,086 |   | 2,754,222 |   |
| North America               |       | 2005       |       | 394,250    |       | 200,000        |       | 400,000                 |       | 100,000        |       | 777,623 |   | 167,300 |   | 50,773 |   | 1,989,946 |   |
|                        |       |       |       |       |       |           |       |                    |       |           |       |   |   |   |   |   |   |   |   |
| Gary H. Nieuwenburg,        |       | 2007       |       | 360,667    |       | —         |       | 191,000                 |       | 100,000        |       | 851,700 |   | 267,300 |   | 48,775 |   | 1,719,442 |   |
| Senior VP,                  |       | 2006       |       | 328,850    |       | —         |       | 210,000                 |       | 100,000        |       | 911,028 |   | 284,800 |   | 51,944 |   | 1,786,622 |   |
| Synthetic Crude             |       | 2005       |       | 303,050    |       | 7,500          |       | 275,000                 |       | 80,000         |       | 622,098 |   | 61,300 |   | 50,459 |   | 1,319,407 |   |
|                        |       |       |       |       |       |           |       |                    |       |           |       |   |   |   |   |   |   |   |   |
| Douglas B. Otten,  (8)      |       | 2007       |       | 387,763    |       | —         |       | 201,245                 |       | —         |       | — |   | — |   | 93,518 |   | 682,526 |   |
| Senior VP,                  |       | 2006       |       | 439,716    |       | —         |       | 326,938                 |       | 110,000        |       | 990,017 |   | — |   | 107,228 |   | 1,863,899 |   |
| US Oil and Gas              |       | 2005       |       | 423,489    |       | —         |       | 430,154                 |       | 100,000        |       | 815,163 |   | — |   | 102,853 |   | 1,771,659 |   |

 

----

*Notes:*

*(1)  Specialdiscretionary award(s) are earned in the year shown and include cashawards approved by the board for successful delivery of key businessobjectives.*

*(2)  Reflects the valueof awards earned in each year under Nexen’s annual cash incentive program. Theawards are paid to the executives in the following calendar year based on theirsalary on December 31 of the previous year.*

*(3)  Reflects theestimated fair value under the Black-Scholes pricing model of TOPs granted inthe year.*

*(4)  Represents theemployer service cost, plus changes in compensation in excess of actuarialassumptions, less required member contributions to the plan.*

*(5)  The total value ofthe perquisites portion of All Other Compensation provided to each executive isless than $50,000 and less than 10% of their total annual salary plus bonus.See the table on page 148 for details of these amounts.*

*(6)  Certain prior yearnumbers have been restated to include the total value of perquisites asdescribed in note 5.*

*(7)  Mr. Romanowis a director of Canexus and was paid fees of $32,500, received deferred trustunits of Canexus valued at $19,560 and distributions on his trust units of$4,259 in 2007. In 2006, he was paid fees of $34,000, received deferred trustunits of Canexus valued at $24,000 and distributions on his trust units of$2,571. In 2005, he was paid fees of $13,875, received deferred trust units ofCanexus valued at $20,000 and distributions on his trust units of $659. These amountsare included in the All Other Compensation table on page 148.*

*(8)  2007 TOPs grantsoccurred after Mr. Otten retired. Nexen contributed to a qualified definedcontribution pension plan and a restoration plan with Nexen Petroleum U.S.A.Inc. for Mr. Otten, which are reported in All Other Compensation on page 148.*

 

**Changes inCompensation Arrangements in 2007**

 

The compensation paid toexecutives in 2007 is consistent with our philosophy and objectives oftargeting total compensation between 50th and 75th percentile as detailed on pages 135through 137. Variable compensation links to Nexen’s business results and theexecutive’s performance, consistent with our pay-for-performance philosophy. Thedecrease in the executives’ annual cash incentives in 2007 reflects the board’sassessment of our relative level of success on certain of our business objectives.

 

We did not introduce any newcompensation or benefit programs in 2007 for Nexen’s executives.

 

142

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**Changes inPension Obligations**

 

Thesummary compensation table shows the year-over-year change in pensionobligations. The value reflects the employer service cost, plus any changes inobligations resulting from compensation increases over actuarial assumptions.Actual compensation changes may vary from the assumed rate of compensationincrease and will vary among each executive from year to year. These valuesdiffer from pension benefit reported on page 147, which disclosesestimated values of annual pension benefits earned to date, as well as at age60 (the earliest unreduced retirement age). They also differ from thetermination values reported under the change of control agreements on page 150,which disclose additional lump sum pension benefits provided if a change ofcontrol occurs.

 

 **CEO COMPENSATION AND****2007****GOALS**

 

 Mr. Fischer’s responsibility is toprovide leadership in setting and achieving goals that create value for ourshareowners in the short term and long term. His 2007 annual cash incentiveaward was based on the corporate results described on page 137, whichdetermined the total cash available for the awards. Cash incentive awards are determinedfrom the available pool and distributed to individuals based on specific annualgoals. Based on the board’s assessment of Mr. Fischer’s achievement ofobjectives in 2007 and their positive assessment of his contribution tocontinued shareowner value growth and strategic plan execution, he was awardedan annual cash incentive of $916,000 which was his target bonus times 88%.Specifically, Mr. Fischer’s goals in 2007 were to:

 

·      develop and implement a corporatestrategy, balancing short-term growth while positioning Nexen for sustainable growth;

·      achieve capital, operating, and generaland administrative cost performance targets set out in the annual operating plan(AOP);

·      achieve targets for operating cash flow,earnings, production levels and reserve replacement set out in the AOP; 

·      maintainfinancial flexibility and liquidity to support our business strategies;

·      achieve top-quartile performance inhealth, safety and environmental performance and social responsibility; 

·      providefor corporate management succession and development;

·      ensure Nexen adheres to the higheststandards of integrity; and

·      demonstratehis personal commitment to community and industry leadership.

 

**CEO THREE-YEAR LOOK-BACK**

 
| **CASH**                                             | ** ** | **Total**      | ** ** | **2007**      | ** ** | **2006**      | ** ** | **2005**      | ** ** |
|------------------------------------------------------|------------|----------------|------------|---------------|------------|---------------|------------|---------------|------------|
| Base Salary                                          |       | 3,400,000      |       | 1,275,000     |       | 1,150,000     |       | 975,000       |       |
| Annual Cash Incentive (1)                            |       | 4,516,000      |       | 916,000       |       | 1,800,000     |       | 1,800,000     |       |
| **EQUITY**                                           |       |           |       |          |       |          |       |          |       |
| Value of TOPs (2)                                    |       | 13,231,344     |       | 5,110,200     |       | 5,010,654     |       | 3,110,490     |       |
| Total Direct Compensation                            |       | 21,147,344     |       | 7,301,200     |       | 7,960,654     |       | 5,885,490     |       |
| All Other Compensation (3)                           |       | 332,625        |       | 119,640       |       | 111,621       |       | 101,364       |       |
| Annual Change in Pension Obligation (4)              |       | 3,502,400      |       | 949,300       |       | 1,673,800     |       | 879,300       |       |
| **Total Cost**                                       | ** ** | **24,982,369** | ** ** | **8,370,140** | ** ** | **9,746,075** | ** ** | **6,866,154** | ** ** |
|                                                 |       |           |       |          |       |          |       |          |       |
| Annual Average                                       |       | 8,327,456      |       |          |       |          |       |          |       |
| Total Market Capitalization Growth ($ millions) |       | 10,640         |       | 90            |       | 2,370         |       | 8,180         |       |
| Total Cost as a % of Market Capitalization  Growth   |       | 0.23           | %          |          |       |          |       |          |       |

 

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*Notes:*

*(1)  Includes specialbonuses of $500,000 in 2006 for the success of Buzzard and $300,000 in 2005 forsuccessful divestitures.*

*(2)  Reflects theestimated fair value of TOPs using the Black-Scholes pricing model valued onthe grant date.*

*(3)  See page 148for details of All Other Compensation.*

*(4)  Represents the employerservice cost, plus changes in compensation in excess of actuarial assumptions,less required member contributions to the plan.*

 

In 2007, the CompensationCommittee reviewed the information above and analyzed Mr. Fischer’s totalpay and shareowner value created from the date he became CEO. In the analysis,dollar values were assigned and tallied for each compensation componentincluding salary, annual cash incentives, TOPs awards, benefits, pension(including annual increases to liabilities) and potential payments on change ofcontrol. The Committee reviewed his total compensation relative to Nexen’sgrowth in shareowner value (market capitalization) and the growth of industrypeers.

 

143

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**EQUITY OWNERSHIP AND CHANGES IN2007**

 

According to our shareownership guidelines, Mr. Fischer is required to hold three times hisannual salary, Mr. Romanow, two times his annual salary and the otherexecutives, one times their annual salary.

 
| ** **  | ** ** | **Dec 31, 2006** | ** ** | **Dec 31, 2007** | ** ** | **Net Change** | ** ** | **Equity at Risk** | ** ** |
|-------------|------------|----------------------------|------------|----------------------------|------------|---------------------|------------|------------------------------|------------|
| ** **  | ** ** | ** **                 | ** ** | ** **                 | ** ** | ** **          | ** ** | ** **                   | ** ** | ** ** | ** ** | ** ** | ** ** | **Value** | ** ** | **Multiple of** | ** ** |
| **Name**    | ** ** | **Shares**                 | ** ** | **TOPs (1)**               | ** ** | **Shares**          | ** ** | **TOPs (1)**                 | ** ** | **Shares** | ** ** | **TOPs (2)** | ** ** | **($) (3)** | ** ** | **Salary (4)** | ** ** |
| Fischer     |       | 166,516                    |       | 2,458,000                  |       | 183,416             |       | 2,215,000                    |       | 16,900 |   | (243,000 | ) | 46,460,074 |   | 36 |   |
| Romanow     |       | 51,874                     |       | 814,920                    |       | 80,938              |       | 785,480                      |       | 29,064 |   | (29,440 | ) | 16,729,050 |   | 30 |   |
| Murphy      |       | 111,656                    |       | 236,240                    |       | 125,226             |       | 164,000                      |       | 13,570 |   | (72,240 | ) | 5,387,856 |   | 11 |   |
| Thomas      |       | 8,580                      | (5)        | 269,200                    |       | 16,227              |       | 399,200                      |       | 7,647 |   | 130,000 |   | 6,683,592 |   | 14 |   |
| Nieuwenburg |       | 59,040                     |       | 238,800                    |       | 65,795              |       | 265,600                      |       | 6,755 |   | 26,800 |   | 5,944,054 |   | 16 |   |
| Otten       |       | 70,072                     |       | 460,288                    |       | 34,458              |       | 254,952                      |       | (35,614 | ) | (205,336 | ) | 5,483,913 |   | 14 |   |
| **Total**   | ** ** | **467,738**                | ** ** | **4,477,448**              | ** ** | **506,060**         | ** ** | **4,084,232**                | ** ** | **38,322** | ** ** | **(393,216** | **)** | **86,688,539** |   |   |   |

 

----

*Notes:*

*(1)  Represents totalTOPs granted, vested and unexercised.*

*(2)  Reflects thenumber of TOPs that vested, minus the number exercised or exchanged during2007.*

*(3)  Equity at risk isthe market value of common shares and vested TOPs using the closing price ofNexen shares on the TSX on December 31, 2007 of $32.10.*

*(4)  Reflects theequity at risk, divided by the executive’s 2007 salary amount shown on page 142.*

*(5)  Amount includeseight common shares not previously reported.*

 

**TOPS TABLES**

 

To value TOPs grants, Nexen usesthe Black-Scholes pricing model, which is a generally accepted method formeasuring this type of long-term incentive. The actual value realized onexercises may be higher or lower depending on the Nexen share price at the timeof exercise.

 

**TOPs Granted in 2007**

 
| ** **  | ** ** | ** **          | ** ** | ** **  | ** ** | ** **               | ** ** | ** **    | ** ** | ** **  | ** ** | ** **    | ** ** | **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 3, 2007         |       | 600,000     |       | 15.0                     |       | 28.39         |       | Dec 2, 2012 |       | 5,110,200     |       | 4,706,180                                                |       | 10,399,427 |   |
| Romanow     |       | Dec 3, 2007         |       | 180,000     |       | 4.5                      |       | 28.39         |       | Dec 2, 2012 |       | 1,533,060     |       | 1,411,854                                                |       | 3,119,828 |   |
| Murphy      |       | Dec 3, 2007         |       | 165,000     |       | 4.1                      |       | 28.39         |       | Dec 2, 2012 |       | 1,405,305     |       | 1,294,200                                                |       | 2,859,843 |   |
| Thomas      |       | Dec 3, 2007         |       | 165,000     |       | 4.1                      |       | 28.39         |       | Dec 2, 2012 |       | 1,405,305     |       | 1,294,200                                                |       | 2,859,843 |   |
| Nieuwenburg |       | Dec 3, 2007         |       | 100,000     |       | 2.5                      |       | 28.39         |       | Dec 2, 2012 |       | 851,700       |       | 784,363                                                  |       | 1,733,238 |   |
|             |            |                     |            |             |            |                          |            |               |            |             |            |               |            |                                                          |            |  |  |  |

 

----

*Notes:*

*(1)  Reflects theclosing market price of Nexen common shares on the TSX on November 30,2007.*

*(2)  Reflects theestimated fair value of the TOPs as at December 3, 2007 using theBlack-Scholes pricing model.*

 

**TOPs Exercisedor Exchanged and Awards Vested in 2007**

 
| ** ** | ** ** | **TOPs Awards**  | ** ** | **Stock Awards (1)**   | ** ** |
|------------|------------|-----------------------|------------|-----------------------------|------------|
| ** ** | ** ** | **Exercised or** | ** ** | ** **                  | ** ** | **Shares Acquired** | ** ** | ** ** | ** ** |
| **Name**   | ** ** | **Exchanged**         | ** ** | **Value Realized (2)** | ** ** | **on Vesting** | ** ** | **Value Realized** | ** ** |
| ** ** | ** ** | **(#)**               | ** ** | **($)**                     | ** ** | **(#)** | ** ** | **($)** | ** ** |
| Fischer    |       | 760,000               |       | 18,182,000                  |       | — |   | — |   |
| Romanow    |       | 200,000               |       | 4,381,500                   |       | — |   | — |   |
| Murphy     |       | 202,240               |       | 4,802,413                   |       | — |   | — |   |
| Thomas     |       | —                |       | —                      |       | — |   | — |   |
| Niewenburg |       | 73,200                |       | 1,860,128                   |       | — |   | — |   |
| Otten      |       | 300,608               |       | 7,566,047                   |       | — |   | — |   |
| **Total**  | ** ** | **1,536,048**         | ** ** | **36,792,088**              |       | — |   | — |   |

 

----

*Notes:*

*(1)  Nexen does notprovide stock awards to executives.*

*(2)  Reflects themarket price at the time of the exercise or exchange, minus the exercise price,as defined in the TOPs plan.*

 

144

----

 

**TOPsHoldings and Value of In-the-Money TOPs**

 
| ** **  | ** ** | ** **   | ** ** | ** **           | ** ** | ** **           | ** ** | ** **    | ** ** | **Vested and Unvested**                     | ** ** | **Vested TOPs**                   | ** ** |
|-------------|------------|--------------|------------|----------------------|------------|----------------------|------------|---------------|------------|-------------------------------------------------------|------------|----------------------------------------|------------|
| ** **  | ** ** | **Date**     | ** ** | ** **           | ** ** | ** **           | ** ** | ** **    | ** ** | **TOPs at Dec 31, 2007 (1), (2)** | ** ** | **at Dec 31, 2007 (2)** | ** ** |
| **Name**    | ** ** | **Granted**  | ** ** | **Expiry Date** | ** ** | **Grant Price** | ** ** | **Granted**   | ** ** | **Number**                                            | ** ** | **Value (3)**                          | ** ** | **Number** | ** ** | **Value (3)** | ** ** |
| ** **  | ** ** | ** **   | ** ** | ** **           | ** ** | **($)**              | ** ** | **(#)**       | ** ** | **(#)**                                               | ** ** | **($)**                                | ** ** | **(#)** | ** ** | **($)** | ** ** |
| Fischer     |       | Dec 15, 1998 |       | Dec 14, 2008         |       | 4.4625               |       | 200,000       |       | 200,000                                               |       | 5,527,500                              |       | 200,000 |   | 5,527,500 |   |
|        |       | Dec 14, 1999 |       | Dec 13, 2009         |       | 6.8125               |       | 280,000       |       | 280,000                                               |       | 7,080,500                              |       | 280,000 |   | 7,080,500 |   |
|        |       | Dec 12, 2000 |       | Dec 11, 2010         |       | 9.0250               |       | 280,000       |       | 280,000                                               |       | 6,461,000                              |       | 280,000 |   | 6,461,000 |   |
|        |       | Dec 9, 2003  |       | Dec 8, 2008          |       | 10.8750              |       | 400,000       |       | 400,000                                               |       | 8,490,000                              |       | 400,000 |   | 8,490,000 |   |
|        |       | Dec 7, 2004  |       | Dec 6, 2009          |       | 12.7175              |       | 600,000       |       | 600,000                                               |       | 11,629,500                             |       | 600,000 |   | 11,629,500 |   |
|        |       | Dec 6, 2005  |       | Dec 5, 2010          |       | 27.2850              |       | 400,000       |       | 400,000                                               |       | 1,926,000                              |       | 268,000 |   | 1,290,420 |   |
|        |       | Dec 4, 2006  |       | Dec 3, 2011          |       | 31.6000              |       | 550,000       |       | 550,000                                               |       | 275,000                                |       | 187,000 |   | 93,500 |   |
|        |       | Dec 3, 2007  |       | Dec 2, 2012          |       | 28.3900              |       | 600,000       |       | 600,000                                               |       | 2,226,000                              |       | — |   | — |   |
| **Total**   | ** ** | ** **   | ** ** | ** **           | ** ** | ** **           | ** ** | **3,310,000** | ** ** | **3,310,000**                                         | ** ** | **43,615,500**                         | ** ** | **2,215,000** | ** ** | **40,572,420** | ** ** |
|        |       |         |       |                 |       |                 |       |          |       |                                                  |       |                                   |       |   |   |   |   |
| Romanow     |       | Dec 12, 2000 |       | Dec 11, 2010         |       | 9.0250               |       | 200,000       |       | 200,000                                               |       | 4,615,000                              |       | 200,000 |   | 4,615,000 |   |
|        |       | Dec 9, 2003  |       | Dec 8, 2008          |       | 10.8750              |       | 220,000       |       | 220,000                                               |       | 4,669,500                              |       | 220,000 |   | 4,669,500 |   |
|        |       | Dec 7, 2004  |       | Dec 6, 2009          |       | 12.7175              |       | 228,000       |       | 228,000                                               |       | 4,419,210                              |       | 228,000 |   | 4,419,210 |   |
|        |       | Dec 6, 2005  |       | Dec 5, 2010          |       | 27.2850              |       | 124,000       |       | 124,000                                               |       | 597,060                                |       | 83,080 |   | 400,030 |   |
|        |       | Dec 4, 2006  |       | Dec 3, 2011          |       | 31.6000              |       | 160,000       |       | 160,000                                               |       | 80,000                                 |       | 54,400 |   | 27,200 |   |
|        |       | Dec 3, 2007  |       | Dec 2, 2012          |       | 28.3900              |       | 180,000       |       | 180,000                                               |       | 667,800                                |       | — |   | — |   |
| **Total**   | ** ** | ** **   | ** ** | ** **           | ** ** | ** **           | ** ** | **1,112,000** | ** ** | **1,112,000**                                         | ** ** | **15,048,570**                         | ** ** | **785,480** | ** ** | **14,130,940** | ** ** |
|        |       |         |       |                 |       |                 |       |          |       |                                                  |       |                                   |       |   |   |   |   |
| Murphy      |       | Dec 7, 2004  |       | Dec 6, 2009          |       | 12.7175              |       | 160,000       |       | 52,800                                                |       | 1,023,396                              |       | 52,800 |   | 1,023,396 |   |
|        |       | Dec 6, 2005  |       | Dec 5, 2010          |       | 27.2850              |       | 100,000       |       | 100,000                                               |       | 481,500                                |       | 67,000 |   | 322,605 |   |
|        |       | Dec 4, 2006  |       | Dec 3, 2011          |       | 31.6000              |       | 130,000       |       | 130,000                                               |       | 65,000                                 |       | 44,200 |   | 22,100 |   |
|        |       | Dec 3, 2007  |       | Dec 2, 2012          |       | 28.3900              |       | 165,000       |       | 165,000                                               |       | 612,150                                |       | — |   | — |   |
| **Total**   | ** ** | ** **   | ** ** | ** **           | ** ** | ** **           | ** ** | **555,000**   | ** ** | **447,800**                                           | ** ** | **2,182,046**                          | ** ** | **164,000** | ** ** | **1,368,101** | ** ** |
|        |       |         |       |                 |       |                 |       |          |       |                                                  |       |                                   |       |   |   |   |   |
| Thomas      |       | Dec 9, 2003  |       | Dec 8, 2008          |       | 10.8750              |       | 128,000       |       | 128,000                                               |       | 2,716,800                              |       | 128,000 |   | 2,716,800 |   |
|        |       | Dec 7, 2004  |       | Dec 6, 2009          |       | 12.7175              |       | 160,000       |       | 160,000                                               |       | 3,101,200                              |       | 160,000 |   | 3,101,200 |   |
|        |       | Dec 6, 2005  |       | Dec 5, 2010          |       | 27.2850              |       | 100,000       |       | 100,000                                               |       | 481,500                                |       | 67,000 |   | 322,605 |   |
|        |       | Dec 4, 2006  |       | Dec 3, 2011          |       | 31.6000              |       | 130,000       |       | 130,000                                               |       | 65,000                                 |       | 44,200 |   | 22,100 |   |
|        |       | Dec 3, 2007  |       | Dec 2, 2012          |       | 28.3900              |       | 165,000       |       | 165,000                                               |       | 612,150                                |       | — |   | — |   |
| **Total**   | ** ** | ** **   | ** ** | ** **           | ** ** | ** **           | ** ** | **683,000**   | ** ** | **683,000**                                           | ** ** | **6,976,650**                          | ** ** | **399,200** | ** ** | **6,162,705** | ** ** |
|        |       |         |       |                 |       |                 |       |          |       |                                                  |       |                                   |       |   |   |   |   |
| Nieuwenburg |       | Dec 9, 2003  |       | Dec 8, 2008          |       | 10.8750              |       | 108,000       |       | 58,000                                                |       | 1,231,050                              |       | 58,000 |   | 1,231,050 |   |
|        |       | Dec 7, 2004  |       | Dec 6, 2009          |       | 12.7175              |       | 120,000       |       | 120,000                                               |       | 2,325,900                              |       | 120,000 |   | 2,325,900 |   |
|        |       | Dec 6, 2005  |       | Dec 5, 2010          |       | 27.2850              |       | 80,000        |       | 80,000                                                |       | 385,200                                |       | 53,600 |   | 258,084 |   |
|        |       | Dec 4, 2006  |       | Dec 3, 2011          |       | 31.6000              |       | 100,000       |       | 100,000                                               |       | 50,000                                 |       | 34,000 |   | 17,000 |   |
|        |       | Dec 3, 2007  |       | Dec 2, 2012          |       | 28.3900              |       | 100,000       |       | 100,000                                               |       | 371,000                                |       | — |   | — |   |
| **Total**   | ** ** | ** **   | ** ** | ** **           | ** ** | ** **           | ** ** | **508,000**   | ** ** | **458,000**                                           | ** ** | **4,363,150**                          | ** ** | **265,600** | ** ** | **3,832,034** | ** ** |
|        |       |         |       |                 |       |                 |       |          |       |                                                  |       |                                   |       |   |   |   |   |
| Otten       |       | Dec 7, 2004  |       | Dec 6, 2009          |       | US$                  | 10.5800    |          | 160,000    |                                                  | 150,552    |                                   | 3,552,214  |   | 150,552 |   | 3,552,214 |   |
|        |       | Dec 6, 2005  |       | Dec 5, 2010          |       | US$                  | 23.6050    |          | 100,000    |                                                  | 100,000    |                                   | 942,587    |   | 67,000 |   | 631,534 |   |
|        |       | Dec 4, 2006  |       | Dec 3, 2011          |       | US$                  | 27.5000    |          | 110,000    |                                                  | 110,000    |                                   | 570,774    |   | 37,400 |   | 194,063 |   |
| **Total**   | ** ** | ** **   | ** ** | ** **           | ** ** | ** **           | ** ** | **370,000**   | ** ** | **360,552**                                           | ** ** | **5,065,575**                          | ** ** | **254,952** | ** ** | **4,377,811** | ** ** |

 

----

*Notes:*

*(1)  Excludes grantsthat have been fully exercised.*

*(2)  The number andvalue of unvested TOPs can be determined by subtracting the vested TOPs fromthe vested and unvested TOPs. The value of unvested TOPs can be confirmed on page 150in the Change of Control table.*

*(3)  The differencebetween the market value of Nexen common shares at year end (TSX—$32.10;NYSE—US $32.27) and the grant price of TOPs, times the number of TOPs.*

 

145

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**PENSION PLAN TABLES**

 

All executives, except Mr. Otten,are members of Nexen’s registered defined benefit pension plan and executivebenefit plan. Mr. Otten was employed in the US and is a member of a qualifieddefined contribution pension plan and a non-qualified restoration plan,described on page 148.

 

**EstimatedPension Benefit (Canada)**

 

The normal form of benefitpaid from these plans is a joint life and survivor benefit with a five-yearguarantee. It is payable for the participant’s lifetime and provides the spousewith a survivor benefit of 66 2/3% of the monthly payment. If the participantdies before receiving 60 monthly payments the five-year guarantee allows the survivingspouse to receive the balance of the 60 monthly payments first and then thereduced survivor pension of 66 2/3%. 

 

In determining the estimatedvalue of future pension benefits for Canadian executives, you must referenceboth tables below due to an amendment effective on January 1, 2005. Theamendments increased the accrual formula on the defined benefit pension plan from1.7% to a maximum of 2%. The first table is for actual credited service up toand including December 31, 2004, and the second table is for creditedservice on and after January 1, 2005. Also, please use the final averageearnings outlined in the Pension Value Earned in 2007 (Canada) table on page 147when referencing tables. The final average earnings will differ from thethree-year average of base salary and cash incentive payments reported in the summarycompensation table on page 142 due to the timing of base salary increasesand because final average earnings include the lesser of the target bonus oractual bonus paid.

 

The table below shows theestimated annual pension a retiring executive would receive for creditedservice to and including December 31, 2004. The annual benefit is based ona pension accrual formula of 1.7% of final average earnings, less a plan CPPoffset. It includes benefits from both the registered defined benefit pensionplan and the executive benefit plan and assumes a retirement age of 60, theearliest age an individual may receive full retirement benefits.

 
| ** **                                    | ** ** | **Years of Credited Service through Dec 31, 2004** | ** ** |
|-----------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|
| **Final Average Earnings ($)** | ** ** | **5**                                                                                 | ** ** | **10** | ** ** | **15** | ** ** | **20** | ** ** | **25** | ** ** |
| 400,000                                       |       |                                                                                  | 33,260     |   | 66,519 |   | 99,779 |   | 133,039 |   | 166,298 |   |
| 600,000                                       |       |                                                                                  | 50,260     |   | 100,519 |   | 150,779 |   | 201,039 |   | 251,298 |   |
| 800,000                                       |       |                                                                                  | 67,260     |   | 134,519 |   | 201,779 |   | 269,039 |   | 336,298 |   |
| 1,000,000                                     |       |                                                                                  | 84,260     |   | 168,519 |   | 252,779 |   | 337,039 |   | 421,298 |   |
| 1,200,000                                     |       |                                                                                  | 101,260    |   | 202,519 |   | 303,779 |   | 405,039 |   | 506,298 |   |
| 1,400,000                                     |       |                                                                                  | 118,260    |   | 236,519 |   | 354,779 |   | 473,039 |   | 591,298 |   |
| 1,600,000                                     |       |                                                                                  | 135,260    |   | 270,519 |   | 405,779 |   | 541,039 |   | 676,298 |   |
| 1,800,000                                     |       |                                                                                  | 152,260    |   | 304,519 |   | 456,779 |   | 609,039 |   | 761,298 |   |
| 2,000,000                                     |       |                                                                                  | 169,260    |   | 338,519 |   | 507,779 |   | 677,039 |   | 846,298 |   |
| 2,200,000                                     |       |                                                                                  | 186,260    |   | 372,519 |   | 558,779 |   | 745,039 |   | 931,298 |   |
| 2,400,000                                     |       |                                                                                  | 203,260    |   | 406,260 |   | 609,779 |   | 813,039 |   | 1,016,298 |   |

 

The table below shows theestimated annual pension benefit a retiring executive would receive forcredited service earned on and after January 1, 2005, based on a pensionbenefit accrual formula of 2% of final average earnings, less a plan CPPoffset. It includes benefits from both the registered defined benefit pensionplan and executive benefit plan and assumes a retirement age of 60, theearliest age an individual may receive full retirement benefits.

 
| ** **                                    | ** ** | **Years of Credited Service from Jan 1, 2005** | ** ** |
|-----------------------------------------------|------------|-----------------------------------------------------------------------------------|------------|
| **Final Average Earnings ($)** | ** ** | **3**                                                                             | ** ** | **5** | ** ** | **10** | ** ** | **15** | ** ** | **20** | ** ** | **25** | ** ** |
| 400,000                                       |       |                                                                              | 23,556     |   | 39,260 |   | 78,519 |   | 117,779 |   | 157,039 |   | 196,298 |   |
| 600,000                                       |       |                                                                              | 35,556     |   | 59,260 |   | 118,519 |   | 177,779 |   | 237,039 |   | 296,298 |   |
| 800,000                                       |       |                                                                              | 47,556     |   | 79,260 |   | 158,519 |   | 237,779 |   | 317,039 |   | 396,298 |   |
| 1,000,000                                     |       |                                                                              | 59,556     |   | 99,260 |   | 198,519 |   | 297,779 |   | 397,039 |   | 496,298 |   |
| 1,200,000                                     |       |                                                                              | 71,556     |   | 119,260 |   | 238,519 |   | 357,779 |   | 477,039 |   | 596,298 |   |
| 1,400,000                                     |       |                                                                              | 83,556     |   | 139,260 |   | 278,519 |   | 417,779 |   | 557,039 |   | 696,298 |   |
| 1,600,000                                     |       |                                                                              | 95,556     |   | 159,260 |   | 318,519 |   | 477,779 |   | 637,039 |   | 796,298 |   |
| 1,800,000                                     |       |                                                                              | 107,556    |   | 179,260 |   | 358,519 |   | 537,779 |   | 717,039 |   | 896,298 |   |
| 2,000,000                                     |       |                                                                              | 119,556    |   | 199,260 |   | 398,519 |   | 597,779 |   | 797,039 |   | 996,298 |   |
| 2,200,000                                     |       |                                                                              | 131,556    |   | 219,260 |   | 438,519 |   | 657,779 |   | 877,039 |   | 1,096,298 |   |
| 2,400,000                                     |       |                                                                              | 143,556    |   | 239,260 |   | 478,519 |   | 717,779 |   | 957,039 |   | 1,196,298 |   |

 

146

----

 

**Pension Value Earned in 2007 (Canada)**

 

The board must approve additional past service creditsor accelerated service credits. No accelerated service credits were authorizedin 2007. The table below shows additional past service credits authorized bythe board for the executives who participate in the Canadian defined benefitpension plan and the executive benefit plan. The final average earningsreported for each executive include his:

 

·                  average base salary for the 36 highest paidconsecutive months during the ten years before his retirement; plus

·                  annual cash incentive payments at the lesser of thetarget bonus or actual bonus paid, averaged over his final three years ofparticipation.

 

No benefit payments were made to executives in thelast fiscal year.

 
| ** **  | ** ** | **Years of Credited Service** | ** ** | ** **                  | ** ** | **Accrued Annual Pension Benefit (1)** | ** ** | **Estimated Annual Pension Benefit  at Age 60 (2)** | ** ** |
|-------------|------------|----------------------------------------------|------------|-----------------------------|------------|------------------------------------------------------------|------------|-----------------------------------------------------------------------------------|------------|
| **Name**    | ** ** | **Up to  Dec 31,  2004**           | ** ** | **From  Jan 1,  2005** | ** ** | **Total**                                                  | ** ** | **Final  Average  Earnings (1)**                                             | ** ** | **Under the  Defined Benefit  Pension Plan** | ** ** | **Under the  Executive Benefit  Plan (3)** | ** ** | **Under the  Defined Benefit  Pension Plan** | ** ** | **Under the  Executive Benefit  Plan (3)** | ** ** |
| ** **  | ** ** | **(#)**                                      | ** ** | **(#)**                     | ** ** | **(#)**                                                    | ** ** | **($)**                                                                           | ** ** | **($)** | ** ** | **($)** | ** ** | **($)** | ** ** | **($)** | ** ** |
| Fischer     |       | 20.58                                        | (4)        | 3.00                        |       | 23.58                                                      |       | 1,908,333                                                                         |       | 30,185 |   | 748,579 |   | 38,704 |   | 992,228 |   |
| Romanow     |       | 17.50                                        | (4), (5)   | 3.00                        |       | 20.50                                                      |       | 818,950                                                                           |       | 23,333 |   | 302,420 |   | 44,407 |   | 463,685 |   |
| Murphy      |       | 18.67                                        |       | 3.00                        |       | 21.67                                                      |       | 666,278                                                                           |       | 48,148 |   | 200,053 |   | 61,315 |   | 305,566 |   |
| Thomas      |       | 24.50                                        | (4)   | 3.00                        |       | 27.50                                                      |       | 651,183                                                                           |       | 38,889 |   | 267,328 |   | 55,000 |   | 419,576 |   |
| Nieuwenburg |       | —                                       | (6)        | 3.00                        |       | 3.00                                                       |       | 461,199                                                                           |       | 6,667 |   | 72,818 |   | 34,426 |   | 198,907 |   |

 

----

*Notes:*

*(1)  Allinformation as of December 31, 2007.*

*(2)  Age60 is the earliest age an individual can receive full retirement benefits.*

*(3)  Representsthe portion of the accrued annual pension benefit estimated under the executivebenefit plan.*

*(4)  Ten years of additional past service creditswere granted to each of Messrs. Fischer, Romanow and Thomas by the boardin 2001.*

*(5)**      **Mr. Romanow joined the definedbenefit pension plan after 7.25 years in the defined contribution pension plan.The pensionable bonus provision recognizes a pension benefit for Mr. Romanowbased on his combined 27.75 years of service, while the base salary provisionrecognizes a pension benefit for his 20.5 years of defined benefit pension planservice only. The value of the pension benefit resulting from the additional7.25 years is reflected in the pension benefit values above.*

*(6)  Mr. Nieuwenburgjoined the defined benefit pension plan after 23.58 years in the definedcontribution pension plan.*

 

**Pension Benefit Obligation Increasein 2007 (Canada)**

 

Our reported values use actuarial assumptions andmethods consistent with those used to calculate pension liabilities and the relatedannual expense disclosed in our financial statements. As the assumptionsreflect our best estimate of future events, our reported values may not bedirectly comparable to similar pension liability values disclosed by othercompanies.

 
| **Name**    | ** ** | **Obligation at  Dec 31, 2006** | ** ** | **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, 2006** | ** ** | **Obligation at  Dec 31, 2007** | ** ** |
|-------------|------------|------------------------------------------------|------------|----------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|------------------------------------------------|------------|
| Fischer     |       | 11,157,800                                     |       | 949,300                                                                                            |       | 552,900                                                                                                         |       | 1,502,200                                                             |       | 12,660,000                                     |       |
| Romanow     |       | 4,296,800                                      |       | 323,300                                                                                            |       | 101,900                                                                                                         |       | 425,200                                                               |       | 4,722,000                                      |       |
| Murphy      |       | 3,287,800                                      |       | 583,300                                                                                            |       | 169,900                                                                                                         |       | 753,200                                                               |       | 4,041,000                                      |       |
| Thomas      |       | 4,195,800                                      |       | 792,300                                                                                            |       | 121,900                                                                                                         |       | 914,200                                                               |       | 5,110,000                                      |       |
| Nieuwenburg |       | 933,800                                        |       | 267,300                                                                                            |       | 24,900                                                                                                          |       | 292,200                                                               |       | 1,226,000                                      |       |
| **Total**   | ** ** | **23,872,000**                                 | ** ** | **2,915,500**                                                                                      | ** ** | **971,500**                                                                                                     | ** ** | **3,887,000**                                                         | ** ** | **27,759,000**                                 | ** ** |

 

----

*Notes:*

*(1)**      **Includes the 2007 employer servicecost, plus changes in compensation in excess of actuarial assumptions, lessrequired member contributions to the plan.*

*(2)**      **Reflects the impact of interest onprior year’s obligations, changes in discount rates used to measure theobligations and the impact of assumption and employee demographic changes.*

 

147

----

 

**Pension Value Earned in 2007 (US)**

 

Mr. Otten is the only executive who is a memberof this US pension plan. He did not make any withdrawals in 2007.

 
| **Name** | ** ** | **Contributions under the Defined  Contribution Pension Plan** | ** ** | **Contributions under the  Non-Qualified Restoration Plan** | ** ** | **Total Pension Compensation** | ** ** |
|----------|------------|-----------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|------------------------------------------|------------|
| Otten    |       | 22,314                                                                                  |       | 34,970                                                                          |       | 57,284                                   |       |

 

**ALL OTHER COMPENSATION**

 

The total value of perquisites provided to anyexecutive was less than $50,000 and less than 10% of the executive’s totalannual salary plus bonus in 2007. Certain perquisites shown below are at themaximum reimbursable amount available to executives. This maximum is oftenhigher than what the executive actually claimed in the year. These perquisitesare not available to the broader employee population.

 
| ** **  | ** ** | **Perquisites**    | ** ** | ** **                 | ** ** | ** ** | ** ** | ** **                    | ** ** | **Other Compensation**          | ** ** | ** **                             | ** ** | ** **                         | ** ** |
|-------------|------------|--------------------|------------|----------------------------|------------|------------|------------|-------------------------------|------------|--------------------------------------|------------|----------------------------------------|------------|------------------------------------|------------|
| **Name**    | ** ** | **Car  Allowance** | ** ** | **Other  Perquisites (1)** | ** ** | **Total**  | ** ** | **Life  Insurance  Premiums** | ** ** | **Savings Plan  Contributions** | ** ** | **Amounts  Paid by  Canexus (2)** | ** ** | **US Pension  Contributions** | ** ** | **Total** | ** ** | **Total All Other  Compensation** | ** ** |
| Fischer     |       | 31,200             |       | 10,500                     |       | 41,700     |       | 1,440                         |       | 76,500                               |       | —                                 |       | —                             |       | 77,940 |   | 119,640 |   |
| Romanow     |       | 19,200             |       | 7,100                      |       | 26,300     |       | 535                           |       | 33,975                               |       | 56,319                                 |       | —                             |       | 90,829 |   | 117,129 |   |
| Murphy      |       | 19,200             |       | 7,100                      |       | 26,300     |       | 1,164                         |       | 29,750                               |       | —                                 |       | —                             |       | 30,914 |   | 57,214 |   |
| Thomas      |       | 19,200             |       | 7,100                      |       | 26,300     |       | 1,140                         |       | 29,250                               |       | —                                 |       | —                             |       | 30,390 |   | 56,690 |   |
| Nieuwenburg |       | 19,200             |       | 7,100                      |       | 26,300     |       | 835                           |       | 21,640                               |       | —                                 |       | —                             |       | 22,475 |   | 48,775 |   |
| Otten       |       | 13,054             |       | 7,723                      |       | 20,777     |       | 2,132                         |       | 13,325                               |       | —                                 |       | 57,284                             |       | 72,741 |   | 93,518 |   |

 

----

*Notes:*

*(1)**      **Represents a maximum reimbursementamount for financial counseling, luncheon club memberships, medical exam andsecurity monitoring. For the CEO, this also includes a maximum reimbursementamount for a golf club membership.*

*(2)** **Includes fees of $32,500, deferred trust units of Canexusvalued at $19,560 and distributions on his trust units of $4,259.*

 

**TERMINATION ARRANGEMENTS**

 

Nexen doesn’t enter into employment service contracts.Depending on the conditions of termination, we treat executives and employeesfairly as follows:

 
| **Events**                | ** ** | **Action**                                                                                                                                                                                                                                                                                             |
|---------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Resignation               |       | All salary and benefit  programs cease  Annual incentive bonus is not paid  TOPs must be exercised within 90 days  Pension paid as a commuted value or deferred benefit                                                                                                                                |
| Retirement                |       | Salary and benefit  coverages cease except for a $5,000 life insurance policy  Monthly benefit to cover the cost of provincial health care premiums  continues  Annual incentive bonus paid on a pro rata basis  TOPs must be exercised within 18 months  Pension paid as a monthly benefit            |
| Death                     |       | All salary and benefit  programs cease except for a 1-year benefit  coverage for surviving dependents and payout of any applicable insurance  benefits  Annual incentive bonus paid on a pro rata basis  TOPs must be exercised within 18 months  Pension paid as a commuted value or deferred benefit |
| Termination without cause |       | All salary and benefit  programs cease  TOPs must be exercised within 90 days  Pension paid as a commuted value or deferred benefit  Severance provided on an individual basis reflecting service, age and salary  level                                                                               |
| Termination for cause     |       | All salary and benefit  programs cease  Annual incentive bonus is not paid  TOPs must be exercised on termination  Pension paid as a commuted value or deferred benefit                                                                                                                                |

 

148

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**Payments on Resignation**

 

The following table discloses the lump sum value ofpension benefits accrued under the defined benefit pension plan and executivebenefit plan for our top five executives had they resigned effective December 31,2007. If they are over the age of 55 and have at least 10 years of Nexenservice, they are deemed to have retired and a lump sum benefit option is notavailable. Also included in this table is the value of vested TOPs at December 31,2007.

 
| ** **  | ** ** | ** **                    | ** ** | **Pension** | ** ** | **Value of Vested** | ** ** | **Total**  | ** ** |
|-------------|------------|-------------------------------|------------|-------------|------------|-------------------------------|------------|------------|------------|
| **Name**    | ** ** | **Termination Scenario** | ** ** | **$**       | ** ** | **TOPs (1),(2)**         | ** ** | **$**      | ** ** |
| Fischer     |       | Deemed Retirement             |       | 12,122,000  |       | 40,572,420                    |       | 52,694,420 |       |
| Romanow     |       | Resignation                   |       | 3,703,000   |       | 14,130,940                    |       | 17,833,940 |       |
| Murphy      |       | Deemed Retirement             |       | 3,660,000   |       | 1,368,101                     |       | 5,028,101  |       |
| Thomas      |       | Deemed Retirement             |       | 4,297,000   |       | 6,162,705                     |       | 10,459,705 |       |
| Nieuwenburg |       | Resignation                   |       | 752,000     |       | 3,832,034                     |       | 4,584,034  |       |

 

----

*Notes:*

*(1)**      **Does not include unvested TOPs whichwill vest according to the TOPs plan over 18 months for deemed retirement orover 90 days for resignation.*

*(2)**      **The difference between the marketvalue of Nexen common shares at year end of $32.10 and the grant price of TOPs,times the number of vested TOPs.*

 

**Change of Control Agreements**

 

Nexen has entered into change of control agreements withMessrs. Fischer, Romanow, Murphy, Thomas, Nieuwenburg and other keyexecutives. The agreements were effective October 1999, amended in December 2000and then amended and restated in December 2001. We recognize that theseexecutives are critical to Nexen’s ongoing business. Therefore, it is vital wework to retain the executives, protect them from employment interruption causedby a change of control and treat them in a fair and equitable manner. Consistentwith industry standards for executives in similar circumstances, there are norestrictions on future employment, or non-compete clauses in the agreements.Each year, the Compensation Committee reviews the estimated payments upon achange of control including the termination value of pension benefits due underthe defined benefit pension plan and executive benefit plan.

 

Under these agreements, a change of control includesany acquisition of common shares or other securities that carries the right tocast more than 35% of the common share votes. Generally, it is any event thatresults in a person or group exercising effective control of Nexen.

 

If the executives terminate following a change ofcontrol, they are entitled to salary, target bonus and other compensatory benefitsfor the severance period specified below.

 
| ** **  | ** ** | **Severance Period in Months on Change of  Control** | ** ** |
|-------------|------------|------------------------------------------------------------------------------------|------------|
| **Name**    | ** ** | **If Terminated**                                                             | ** ** | **Upon Resignation (1)** | ** ** |
| Fischer     |       | 36                                                                                 |       | 36 |   |
| Romanow     |       | 36                                                                                 |       | 30 |   |
| Murphy      |       | 30                                                                                 |       | — |   |
| Thomas      |       | 30                                                                                 |       | — |   |
| Nieuwenburg |       | 24                                                                                 |       | — |   |

 

----

*Note:*

*(1)**      **Within 12 months of change of control.*

 

The next table outlines the estimated incrementalpayments executives would be entitled to, had a change of control occurred on December 31,2007. Under the agreement, bonuses would be paid at target for the fullseverance period. A benefits uplift, equal to 13% of base salary, would beprovided in lieu of medical, dental and life insurance coverage. In addition,the agreement provides a payment for other employee benefits, including carallowance and savings plan contributions during the severance period, and anallowance for financial counseling, security monitoring and career transitionservices.

 

Executives would also be entitled to incrementalpension relating to their salary and annual incentive targets over the severanceperiod. The pension value reported below reflects this, as well as a taxgross-up on the resulting lump sum payout. These additional pension benefits donot include any termination benefits that would be payable under the defined benefitpension plan and executive benefit plan if a termination or retirement occurredthat was not triggered by a change of control.

 

149

----

 

**Estimated Incremental Payment on Change of Control**

 
| **Name**    | ** ** | **Severance  Period**       | ** ** | **Base Salary** | ** ** | **Bonus  Target Value** | ** ** | **Benefits  Uplift** | ** ** | **Other  Employee  Benefits** | ** ** | **Additional  Lump Sum  Value of  Pension (1)** | ** ** | **Accelerated  TOPs Value (2)** | ** ** | **Total  Incremental  Obligation** | ** ** |
|-------------|------------|-----------------------------|------------|----------------------|------------|------------------------------|------------|----------------------|------------|-------------------------------|------------|-----------------------------------------------------------|------------|--------------------------------------|------------|------------------------------------|------------|
| ** **  | ** ** | **(# of months)** | ** ** | **($)**              | ** ** | **($)**                      | ** ** | **($)**              | ** ** | **($)**                       | ** ** | **($)**                                                   | ** ** | **($)**                              | ** ** | **($)**                            | ** ** |
| Fischer     |       | 36                          |       | 3,900,000            |       | 3,120,000                    |       | 507,000              |       | 365,500                       |       | 9,157,000                                                 |       | 3,043,080                            |       | 20,092,580                         |       |
| Romanow     |       | 36                          |       | 1,725,000            |       | 1,035,000                    |       | 224,250              |       | 199,000                       |       | 3,879,000                                                 |       | 917,630                              |       | 7,979,880                          |       |
| Murphy      |       | 30                          |       | 1,300,000            |       | 780,000                      |       | 169,000              |       | 163,900                       |       | 3,237,000                                                 |       | 813,945                              |       | 6,463,845                          |       |
| Thomas      |       | 30                          |       | 1,300,000            |       | 780,000                      |       | 169,000              |       | 163,900                       |       | 3,905,000                                                 |       | 813,945                              |       | 7,131,845                          |       |
| Nieuwenburg |       | 24                          |       | 800,000              |       | 360,000                      |       | 104,000              |       | 124,300                       |       | 1,316,000                                                 |       | 531,116                              |       | 3,235,416                          |       |
| **Total**   | ** ** | ** **                  | ** ** | **9,025,000**        | ** ** | **6,075,000**                | ** ** | **1,173,250**        | ** ** | **1,016,600**                 | ** ** | **21,494,000**                                            | ** ** | **6,119,716**                        | ** ** | **44,903,566**                     |       |

 

----

*Notes:*

*(1)**      **Does not include regular terminationpension values which are reported in Payments on Resignation on page 149.Benefits payable under the defined benefit pension plan are funded from thepension trust and payable monthly if the executive is 55 or older.*

*(2)**      **Reflects the value of TOPs thatautomatically vest on a change of control, based on the number of TOPs withaccelerated vesting, times the closing price of Nexen common shares on the TSXon December 31, 2007 of $32.10, less the exercise price.*

 

**SHARE PERFORMANCE GRAPH**

 

The following graph shows the change in a $100investment in Nexen common shares over the past five years, compared to theS&P/TSX Composite Index, the S&P/TSX Energy Sector Index and theS&P/TSX Oil & Gas Exploration & Production Index as at December 31,2007. Our common shares are included in each of these indices.

 

**Total Return Index Values (1)**

 

 
| ** **                                                          | ** ** | **2002/12** | ** ** | **2003/12** | ** ** | **2004/12** | ** ** | **2005/12** | ** ** | **2006/12** | ** ** | **2007/12** | ** ** |
|---------------------------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|
|  Nexen Inc.                                                    |       | 100.00      |       | 138.21      |       | 144.57      |       | 330.52      |       | 384.10      |       | 385.26      |       |
|  S&P/TSX Oil & Gas Exploration &  Production Index |       | 100.00      |       | 120.15      |       | 169.02      |       | 293.50      |       | 297.38      |       | 327.52      |       |
|  S&P/TSX Energy Sector Index                               |       | 100.00      |       | 124.97      |       | 162.82      |       | 266.10      |       | 282.22      |       | 305.45      |       |
|  S&P/TSX Composite Index                                   |       | 100.00      |       | 126.72      |       | 145.07      |       | 180.08      |       | 211.16      |       | 231.92      |       |

 

----

*Note:*

*(1) Assuming an investment of $100and the reinvestment of dividends.*

 

150

----

 

**CORPORATE GOVERNANCE**

 

Nexen’s board takes its duties and responsibilitiesfor good corporate governance seriously. Nexen supports and conducts businessaccording to the rules of the Toronto Stock Exchange (TSX), NYSE, *National Policy 58-201—Corporate Governance Guidelines*and *Multilateral Instrument52-110—Audit Committees*. Except as noted below, Nexen’s corporate governancepractices comply with those followed by domestic companies under NYSE listingstandards.

 

Nexen has a DSU plan for non-executive directors as describedon page 133. For this plan, Nexen follows the TSX rules which, unlikethe NYSE rules, exempt plans from shareowner approval where the common sharesissued under the plan are purchased on the open market rather than issuing newshares.

 

On February 21, 2008, 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 21, 2008. Nexen also filed an Interim WrittenAffirmation on April 26, 2007 reporting changes to audit committeemembership.  As well, our CEO and CFO havecertified the quality of Nexen’s public disclosure to the SEC.

 

All Committee mandates, including those for the Audit,Compensation and Governance Committees, and our corporate governance policy andcategorical standards are available at www.nexeninc.com, and we intend toprovide disclosure in this manner. Shareowners wishing to receive a copy ofthese documents may contact the Governance Office by telephone at 403.699.4926,or by email at governance@nexeninc.com.

 

**GOVERNANCE COMMITTEE REPORT**

 

The Governance Committee assists the board to oversee implementationof our corporate governance programs, recommending nominees for directorappointments and evaluating the board, its committees and all individualdirectors and chairs, to ensure we implement best-in-class corporate governancepractices appropriate to Nexen.

 

All members of the Committee are independent andknowledgeable about our corporate governance programs. Six members of theCommittee are skilled or expert in governance and board experience ordiversity, the two areas of expertise most relevant to carrying out theCommittee’s mandate.

 

**Changes to Committee Membership in2007**

 

Mr. Flanagan left the Committee and Mr. Newelljoined in April 2007.

 

**Key Activities in 2007**

 

·                  Recommended revisions to the corporate governance policy,including a minimum attendance standard for directors, and the externalcommunications policy;

·                  Reviewed our position on current governance issues, includingsay on pay (the concept of advisory votes on management compensation);

·                  Recommended the adoption of a modified majority vote by-lawfor the election of directors to the shareowners for approval;

·                  Recommended changes to committee memberships in lightof Mr. Flanagan becoming non-independent as of July 1, 2007;

·                  Recommended updated mandates for the board, individualdirectors and all board committees;

·                  Recommended new and updated questions in the boardperformance evaluation based on rankings and comments received the previousyear; and

·                  Consulted with Dr. Richard Leblanc, AssistantProfessor of Corporate Governance, York University, on the board’s performanceevaluations.

 

**The Board and Committees**

 

The Committee reviews board and committee memberships annually,considering director independence and the skills and preferences of thedirectors. The board is comprised of 12 directors, which is large enough topermit a diversity of views and run the committees, without being so large as todetract from effectiveness. A skills matrix that sets out the various areas ofexpertise determined to be essential to ensure appropriate strategic directionand oversight 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.

 

**Nominating a New Director forElection**

 

The Committee identifies and assesses candidates for appointmentor nomination to the board. Our forward-looking skills matrix has identifiedthe skills with the greatest opportunity to strengthen the board uponretirement of two current directors in 2009.

 

Before recommending a new candidate to the board, the Committeeconsiders his or her performance, independence, competencies, skills andfinancial acumen. Character and behavioural qualities, including credibility,integrity and communication skills are also taken into account. The Committee Chairand/or Board Chair meets with the candidate to discuss his or her interest andability to devote sufficient time and resources to the position. Prior tonomination, potential directors must disclose possible conflicts of interestwith Nexen and background checks, as appropriate, are completed.

 

151

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The Committee maintains an evergreen list of potentialdirectors whose skills complement the board and who the Committee recommends beasked to join the board if they are available when an opening arises.

 

The Committee will also consider any nominee forelection as a director recommended by a shareowner. See page 153 forinformation on communicating with the board.

 

**Performance Evaluations**

 

The board and management work together to fostercontinuous, open and honest communication, where concerns are brought forwardand dealt with as they occur. In this spirit, the annual board evaluation isseen as an opportunity to review the past year and consider contributions,successes and opportunities for improvement. The special report on our directorevaluation process provided in our 2007 proxy circular, is available atwww.nexeninc.com.

 

Our six-part performance evaluation review is ourprimary tool for determining who should be on the board. In light of the evaluationprocess, the board does not have a tenure policy and has flexible term limits.Nexen’s average board tenure is 9.8 years. We do have a set retirement age of75.

 

The Committee considered comments from the lastevaluation when it updated the 2007 questionnaire to further explore CEO succession,crisis management, director recruitment, risk, compensation and the evaluationprocess itself.

 

The board rates its overall effectiveness on aten-point scale, where 10 is the best. The average rating for 2007 was 9.23.

 

**External Recognition and Verification**

 

Nexen was recognized for its governance practicesduring 2007, including the following:

 

·                  Conference Board of Canada/Spencer Stuart 2007National Award in Governance for the private sector;

·                  Named first, together with SNC-Lavalin Group Inc.,onthe Top 25 Boards in Canada by Canadian Business

                        Magazine;

·                  Received an Honourable Mention for the 2007 GovernanceGavel Award for Excellence in Director Disclosure from the Canadian Coalitionfor Good Governance;

·                  Received the Honourable Mention for Excellence inCorporate Governance Disclosure in the 2007 Corporate Reporting Awards from theChartered Accountants of Canada;

·                  Named as having the Best Corporate GovernancePractices in North America by IR Global Rankings; and

·                  Had an average 2007 global rating of 9.9 out of 10 andhave a current rating of 9.5 from Governance Metrics International for governancepractices and disclosure.

 

**Committee Approval**

 

The Committee has reviewed and discussed thegovernance disclosure in this document, including the information in the Boardof Directors section on pages 129 through 133 and has recommended to the boardthat it be included in the proxy circular and, as appropriate, Form 10-K.

 

**Submitted on behalf of the Governance Committee:**

 

Dick Thomson, Chair

Kevin Jenkins

Anne McLellan

Eric Newell

Tom O’Neill

Francis Saville

John Willson

 

152

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**Ethics Policy**

 

Under our ethics policy, all directors, officers andemployees 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 policy mustbe board approved and disclosed. There has never been a waiver. The ethicspolicy was amended on December 3, 2007. We made minor revisions to updatethe name of an integrity-related policy. Our ethics policy provides for anexternal integrity helpline, in place since February 1, 2005.

 

Nexen’s ethics policy is available at www.nexeninc.comand we intend to disclose any waivers of or changes to this policy online. Ourethics policy and any future amendments to it are filed on SEDAR atwww.sedar.com. To request a copy of the policy, contact the Integrity ResourceCentre by calling 403.699.4727 or by emailing integrity@nexeninc.com.

 

**Reporting Concerns**

 

Please direct any concerns about Nexen’s financialstatements, accounting practices or internal controls to either:

 

·                  management or the Chair of the Audit Committee as setout in the ethics policy; or

·                  EthicsPoint, as set out below.

 

Employees, customers, suppliers, partners, shareownersand other external stakeholders who have a concern are encouraged to raise itwith 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 our integrityhelpline – a secure reporting system, which is owned and managed byEthicsPoint, an independent third-party service provider. To find out moreabout our integrity helpline and for toll free numbers for other countries,access our web site at www.nexeninc.com and click on the “Integrity Helpline”link at the top of the page or access the helpline directly:

 
| Online:       |   | www.ethicspoint.com                          |
|---------------|--------|----------------------------------------------|
| By telephone: |   | 1.866.384.4277  (toll-free in North America) |

 

**Communicating with the Board**

** **

Shareowners may write to the board or any member ormembers of the board in care of the following address:

 
| By mail:  |   | Nexen Inc.   801 -7th Avenue SW    |
|-----------|--------|------------------------------------|
|      |   | Calgary, Alberta, Canada   T2P 3P7 |
|      |   | Attention: Governance Office       |
| By email: |   | board@nexeninc.com                 |

 

We receive a number of inquiries on a large range ofsubjects every day. The board has consulted with management to develop aprocess to assist in managing inquiries directed to the board or its members.

 

Letters and emails addressed to the board, any of itsmembers or the independent directors, as a group, are reviewed to determine ifa response from the board is appropriate. While the board oversees management,it does not participate in our day-to-day functions and operations and is notnormally in the best position to respond to inquiries on those matters. Thoseinquiries will be directed to the appropriate personnel for response. The boardhas instructed the Governance Office to review all correspondence and, in itsdiscretion, not forward items that are:

 

·                  not relevant to Nexen’s operations, policies or philosophies;

·                  commercial in nature; or

·                  not appropriate for consideration by the board.

 

All inquiries will receive a response from the boardor management. The Governance Office 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 155 for a full report on the AuditCommittee.

 

153

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**Item 12. SecurityOwnership of Certain Beneficial Owners and Managementand Related Stockholder Matters**

 

**SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS**

 

Nexen’s common shares are the only class of votingsecurities. Based on information known to Nexen, the following table shows eachperson or group who beneficially owns (pursuant to SEC Regulations) more than5% of Nexen’s voting securities as at the date noted below.

 
| **Name and Address of  Beneficial Owner** | ** ** | **# of Shares  Beneficially  Owned** | ** ** | **% of   Shares** | ** ** | **Effective  Date**    | ** ** |
|---------------------------------------------------------------|------------|------------------------------------------------|------------|-----------------------------|------------|------------------------|------------|
| Jarislowsky, Fraser Limited (1)                               |       | 53,090,139                                     |       | 10.05                       |       | January 31,  2008 |       |
| Suite 2005, 1010 Sherbrooke Street West                  |       |                                           |       |                        |       |                   |       |
| Montreal, Quebec, Canada, H3A 2R7                             |       |                                           |       |                        |       |                   |       |
|                                                          |       |                                           |       |                        |       |                   |       |
| Ontario Teachers’ Pension Plan Board (2)                 |       | 52,677,672                                     |       | 9.97                        |       | January 8,  2008  |       |
| 5650 Yonge Street                                             |       |                                           |       |                        |       |                   |       |
| Toronto, Ontario, Canada, M2M 4H5                             |       |                                           |       |                        |       |                   |       |

 

----

*Notes:*

*(1)**      **The beneficial owner has sole votingpower over 44,870,646 shares, shared voting power over 8,219,493 shares andsole power to dispose of 53,090,139 shares and shared power to dispose of 268,680shares.*

*(2)  Thebeneficial owner has sole voting power and power to dispose of all shares.*

 

**SECURITY OWNERSHIP OF MANAGEMENT**

 

At February 14, 2008, 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                                           |       | 184,161                        |       | 2,215,000                 |       |
| Dennis G. Flanagan                                           |       | 31,264                         |       | 20,000                    |       |
| David A. Hentschel                                           |       | 70,814                         |       | 100,000                   |       |
| S. Barry Jackson                                             |       | 72,000                         |       | —                    |       |
| Kevin J. Jenkins                                             |       | 12,362                         |       | 60,000                    |       |
| A. Anne McLellan, P.C.                                       |       | 100                            |       | —                    |       |
| Eric P. Newell, O.C.                                         |       | 12,000                         |       | —                    |       |
| Thomas C. O’Neill                                       |       | 16,000                         |       | —                    |       |
| Francis M. Saville, Q.C.                                     |       | 48,860                         |       | 71,004                    |       |
| Richard M. Thomson, O.C.                                     |       | 92,004                         |       | 150,000                   |       |
| John M. Willson                                              |       | 22,004                         |       | —                    |       |
| Victor J. Zaleschuk                                          |       | 62,982                         |       | 240,000                   |       |
| Laurence Murphy                                              |       | 125,504                        |       | 164,000                   |       |
| Marvin F. Romanow                                            |       | 81,237                         |       | 785,480                   |       |
| Roger D. Thomas                                              |       | 16,553                         |       | 399,200                   |       |
| Gary H. Nieuwenburg                                          |       | 66,006                         |       | 265,600                   |       |
| Douglas B. Otten                                             |       | 46,892                         |       | 254,952                   |       |
| All directors and executive officers as a group (25 persons) |       | 1,112,455                      |       | 6,035,954                 |       |

 

----

*Notes:*

*(1)  Thenumber of shares held and TOPs exercisable by each beneficial owner representsless than 1% of the shares outstanding.*

*(2)  Includesall TOPs exercisable within 60 days of February 14, 2008. All TOPs held bynon-executive directors are vested.*

 

Under the terms of our TOPs plan, the board may grantoptions 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 TOP’s** | ** ** | **Weighted-Average  Exercise Price of  Outstanding TOP’s** | ** **          | **Number of  Securities Remaining  Available for Future  Issuance under Equity  Compensation Plans** | ** **     |
|-------------------------------------------------------|------------|------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------|---------------------|-----------------------------------------------------------------------------------------------------------|----------------|
|                                                  |
| ** **                                            |
| Equity compensation plans approved by shareowners     |       | 27,402,722                                                                         |       | $                                                                    | 20/option           |                                                                                                      | 29,430,190     |   |
| Equity compensation plans not approved by shareowners |       | —                                                                             |       | —                                                               |                | —                                                                                                    |           |
| **Total**                                             | ** ** | **27,402,722**                                                                     | ** ** | **$**                                                                | ** 20/option** | ** **                                                                                                | **29,430,190** | ** ** |

 

154

----

 

**Item 13.Certain Relationships and Related Transactions, and DirectorIndependence**

 

**RELATED PARTY TRANSACTION**

 

As a Canadian foreign private issuer, Nexen providesthe disclosure required under Item 7.B. of Form 20-F dealing with “relatedparty transactions.” Nexen did not have any related party transactions in 2007as defined under that standard. Certain other transactions described belowwhich are not related party transactions, involving Nexen and certain of ourdirectors were entered into in 2007.

 

**DIRECTOR INDEPENDENCE**

 

Mr. Saville, was a senior partner of FraserMilner Casgrain LLP (FMC), Barristers and Solicitors, Calgary, Alberta, untilthe end of January 2004. Since February 1, 2004, he has been counsel withthe firm. FMC provided legal services to us in each of the last five years. Mr. Savilledoes not solicit or participate in these services and does not receive anyportion of the fees we pay to FMC. He is independent under our categoricalstandards.

 

Ms. McLellan, has been counsel with Bennett Jones(BJ), Barristers and Solicitors, Edmonton, Alberta since June 27, 2006. BJprovided legal services to us in each of the last five years. Ms. McLellandoes not solicit or participate in those services and does not receive anyportion of the fees we pay to BJ. She is independent under to our categoricalstandards.

 

Mr. Fischer is not independent as he is Presidentand CEO.

 

Mr. Flanagan is not independent as his son isSenior Vice President, Engineering, of TriAxon Resources Ltd. (TriAxon). In 2006,TriAxon acquired a company that was party to contracts with a subsidiary ofNexen. Under one of the contracts Nexen paid approximately $4.5 million toTriAxon between July and December 2006 for products purchased atmarket price. Accordingly, Mr. Flanagan is not technically independent asof July 1, 2007. Mr. Flanagan was not aware that the company acquiredby TriAxon held contracts with Nexen. The board has determined that Mr. Flanagan’sindependence of mind has not been compromised by this transaction and,accordingly, the board continues to include him in their meetings withoutmanagement.

 

**Item 14.Principal Accounting Fees andServices**

 

**AUDIT COMMITTEE REPORT**

 

The Audit Committee is responsible for appointing(subject to shareowner approval), compensating and overseeing the IndependentRegistered Chartered Accountants (IRCAs). The IRCAs are accountable to andreport directly to the Committee, and understand that they must maintain anopen and transparent relationship with the Committee, as representatives of theshareowners.

 

All members of the Committee are independent andknowledgeable about our financial reporting controls, and internal and externalaudit processes. Five members are skilled or expert in financial acumen,particularly financial accounting, reporting and internal controls, the area ofexpertise most relevant to carrying out the Committee’s mandate.

 

The Committee assists the board in overseeing internalaccounting and financial reporting controls, internal and external auditprocesses, and implementation of the ethics policy.

 

Management is responsible for our internal controlsand financial reporting process. The IRCAs are responsible for performing andreporting on an independent audit of our: (i) consolidated financialstatements according to generally accepted auditing standards; and, (ii) internalcontrol over financial reporting according to the standards of the Public CompanyAccounting Oversight Board. The Committee’s responsibility is to monitor andoversee these processes.

 

**Changes to Committee Membership in2007**

 

Mr. Flanagan left the Committee and Mr. Newelljoined April 2007.

 

**Key Activities for 2007**

 

·                  Met separately with management and the IRCAs to reviewthe December 31, 2007 consolidated financial statements;

·                  Discussed with the IRCAs matters required by Canadianregulators under Section 5751 of the General Assurance and AuditingStandards of the Canadian Institute of Chartered Accountants “Communications withThose having Oversight Responsibility for the Financial Reporting Process” andby US regulators under the Statement on Auditing Standards No. 61 “Communicationwith Audit Committees” issued by the American Institute of Certified PublicAccountants;

·                  Received written disclosures from the IRCAs requiredby the SEC according to the Independence Standards Board Standard No. 1 “IndependenceDiscussions with Audit Committees”;

·                  Discussed with the IRCAs that firm’s independence;

·                  Based on the reviews and discussions referred toabove, recommended to the board that the audited consolidated financialstatements be included in Nexen’s annual report on Form 10-K for the yearended December 31, 2007;

·                  Oversaw Section 404 Sarbanes-Oxley complianceactivities undertaken by management to report on the effectiveness of internalcontrol over financial reporting as at December 31, 2007;

 

155

----

 

·                  reviewed and approved the quarterly consolidatedfinancial statements; and

·                  Recommended changes to the ethics policy.

 

**Audit Partner Rotation**

 

In compliance with applicable law, the lead auditpartner of our IRCAs is replaced every five years.

 

**Section 404 of Sarbanes-Oxley**

 

Nexen is a voluntary filer of Form 10-K in the USand has complied with the requirements of Section 404 of Sarbanes-Oxleysince December 31, 2004. During 2007, management evaluated theeffectiveness of our internal control over financial reporting and concludedthat it was effective as of December 31, 2007. This assessment was auditedby the IRCAs in 2006 as part of the integrated audit of the consolidated financialstatements. This particular audit is no longer required as part of the IRCA’sintegrated audit due to US regulatory changes. The Committee’s mandate,available at www. nexeninc.com, has been updated accordingly. Their integrated auditreport for 2007 is included in our Form 10-K.

 

**IRCA Engagement and Fees Billed**

 

Before Deloitte & Touche LLP, the IRCA isengaged by Nexen or its subsidiaries to render additional audit or non-audit services,the engagement is approved by the Committee. All audit, audit-related, tax andother services provided by Deloitte & Touche LLP since May 6,2003 have been approved by the Committee.

 
| **Type of Fee**                                                                                                                | ** ** | **Billed in  2006** | ** ** | **Billed in  2007** | ** ** | **Percentage  of Total  Fees Billed in**

**2007** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|---------------------|------------|---------------------------------------------------------|------------|
| **Audit Fees**                                                                                                                 |       |                |       |                |       |                                                    |       |
| For the integrated audit of Nexen’s consolidated financial statements  included in our annual report on Form 10-K    |       | 2,332,500           | (1)        | 2,966,000           | (2)        |                                                    |       |
| For the integrated audit of the consolidated financial statements of   Canexus (3)                                             |       | 302,900             |       | 145,000             | (4)        |                                                    |       |
| For the first, second and third quarter reviews of Nexen’s  consolidated financial statements included in Form 10-Qs |       | 72,000              |       | 90,000              |       |                                                    |       |
| For the first, second and third quarter reviews of the consolidated  financial statements of Canexus (3)                       |       | 45,000              |       | 45,000              |       |                                                    |       |
| For comfort letters and submissions to commissions                                                                             |       | 2,500               |       | 153,500             |       |                                                    |       |
| **Total Audit Fees**                                                                                                           | ** ** | **2,754,900**       | ** ** | **3,399,500**       | ** ** | **76**                                                  | **%**      |
| Audit-Related Fees — Nexen and Canexus (3)                                                                                |       |                |       |                |       |                                                    |       |
| For the annual audits and quarterly reviews of subsidiary financial  statements and employee benefit plans                     |       | 719,500             |       | 828,100             |       |                                                    |       |
| **Total Audit-Related Fees**                                                                                                   | ** ** | **719,500**         | ** ** | **828,100**         | ** ** | **19**                                                  | **%**      |
| Tax Fees — Nexen and Canexus (3)   For tax return preparation assistance and tax-related consultation                     |       | 84,300              |       | 116,400             |       |                                                    |       |
| **Total Tax Fees**                                                                                                             | ** ** | **84,300**          | ** ** | **116,400**         | ** ** | **3**                                                   | **%**      |
| **All Other Fees**                                                                                                             | ** ** | **86,000**          | **(5)**    | **110,600**         | **(5)**    | **2**                                                   | **%**      |
| **Total Annual Fees**                                                                                                          | ** ** | **3,644,700**       | ** ** | **4,454,600**       | ** ** | **100**                                                 | **%**      |

 

----

*Notes:*

*(1)  Consistingof $1,032,500 to complete the 2005 audit and $1,300,000 to commence the 2006audit.*

*(2)  Consistingof $1,366,000 to complete the 2006 audit and $1,600,000 to commence the 2007audit.*

*(3)  Includesfees for Canexus Income Fund, Canexus Limited Partnership and its subsidiaries.*

*(4)  Consistingof $95,000 to complete the 2006 audit and $50,000 to commence the 2007 audit.*

*(5)  Annualrenewal fees for an upstream information database used in our UK office.*

 

**Committee Approval**

 

The Committee is of the view that the provision ofservices by Deloitte & Touche LLP described in “All Other Fees” aboveis compatible with maintaining that firm’s independence.

 

Based on the Committee’s discussions with managementand the IRCAs, and its review of the representations of management and theIRCAs, the Committee recommended to the board that the audited consolidatedfinancial statements be included in Nexen’s annual report on Form 10-K forthe year ended December 31, 2007.

 

**Submitted on behalf of the Audit Committee:**

 

Tom O’Neill, Chair

Eric Newell

Barry Jackson

Dick Thomson

Kevin Jenkins

John Willson

 

156

----

 

**PART IV**

**Item 15. Exhibits,Financial Statement Schedules**

 

**FINANCIAL STATEMENTS AND SCHEDULES**

 

We refer you to the index to Financial Statements andSupplementary Data in Item 8 of this report where these documents are listed.

 

Schedules and separate financial statements ofsubsidiaries are omitted because they are not required or applicable, or the requiredinformation is shown in the Consolidated Financial Statements or notes.

 

**EXHIBITS**

 

Exhibits filed as part of this report are listedbelow. Certain exhibits have been previously filed with the Commission and are incorporatedin this Form 10-K by reference. Instruments defining the rights of holdersof debt securities that do not exceed 10% of Nexen’s consolidated assets havenot been included. A copy of such instruments will be furnished to theCommission upon request.

 
| 2.2    |   | Agreement for the Sale and Purchase of EnCana (U.K.)  Limited, between EnCana (U.K.) Holdings Limited and Nexen Energy Holdings  International Limited dated October 28, 2004 (filed as Exhibit 2.1  to Form 8-K dated October 29, 2004).                                                                                                                  |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                           |
| 3.14   |   | Restated Certificate and Articles of Incorporation  of the Registrant dated May 20, 2005 (filed as Exhibit 3.12 to  Form 10-Q for the quarterly period ended June 30, 2005).                                                                                                                                                                               |
|   |   |                                                                                                                                                                                                                                                                                                                                                                           |
| 3.15   |   | By-Law No. 3 of the Registrant enacted  December 4, 2006, being a by-law relating generally to the transaction  of the business and affairs of the Registrant (filed as Exhibit 3.15 to  Form 8-K dated December 5, 2006).                                                                                                                            |
|   |   |                                                                                                                                                                                                                                                                                                                                                                           |
| 3.16   |   | Certificate and Articles of Amendment of the  Registrant dated April 26, 2007 (filed as Exhibit 3.16 to  Form 8-K dated April 27, 2007).                                                                                                                                                                                                                   |
|   |   |                                                                                                                                                                                                                                                                                                                                                                           |
| 4.42   |   | Trust Indenture dated April 28, 1998 between  the Registrant and CIBC Mellon Trust Company providing for the issue of debt  securities from time to time (filed as Exhibit 4.42 to Form 10-K  for the year ended December 31, 2003).                                                                                                                       |
|   |   |                                                                                                                                                                                                                                                                                                                                                                           |
| 4.43   |   | First Supplemental Indenture dated April 28,  1998 to the Trust Indenture dated April 28, 1998 between the Registrant  and CIBC 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 December 31, 2003).                                                  |
|   |   |                                                                                                                                                                                                                                                                                                                                                                           |
| 4.46   |   | Third Supplemental Indenture dated March 11,  2002 to the Trust Indenture dated April 28, 1998 between the Registrant  and CIBC 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 December 31, 2003).                                                         |
|   |   |                                                                                                                                                                                                                                                                                                                                                                           |
| 4.47   |   | Subordinated Debt Indenture dated November 4,  2003 between the Registrant and Deutsche Bank Trust Company Americas,  pertaining to the issue of subordinated notes from time to time (filed as  Exhibit 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  between the Registrant and Deutsche Bank Trust Company Americas, pertaining  to the issuance of US$460 million, 7.35% subordinated notes due 2043 (filed  as Exhibit 4.48 to Form 10-K for the year ended December 31,  2003). |
|   |   |                                                                                                                                                                                                                                                                                                                                                                           |
| 4.51   |   | Fourth Supplemental Indenture dated  November 20, 2003 to the Trust Indenture dated April 28, 1998,  between the Registrant and CIBC Mellon Trust Company pertaining to the  issuance of US$500 million, 5.05% notes due 2013 (filed as Exhibit 4.51  to Form 10-K for the year ended December 31, 2003).                                             |
|   |   |                                                                                                                                                                                                                                                                                                                                                                           |
| 4.53   |   | Fifth Supplemental Indenture dated March 10,  2005 to the Trust Indenture dated April 28, 1998, between the Registrant  and 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 Rights Plan  Agreement dated April 27, 2005 between the Registrant and CIBC Mellon  Trust Company, as Rights Agent, which includes the Form of Rights  Certificate as Exhibit A (filed as Exhibit 4.54 to Form 10-K  for the year ended December 31, 2005).                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                           |
| 4.55   |   | Senior Debt Indenture dated May 4, 2007 between  the Registrant and Deutsche Bank Trust Company Americas, pertaining to the  issue of senior notes from time to time (filed as Exhibit 4.1 to  Form 8-K dated May 7, 2007).                                                                                                                                |

 

157

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| 4.56   |   | First Supplemental Indenture dated May 4, 2007  to the Trust Indenture dated May 4, 2007 between the Registrant and  Deutsche Bank Trust Company Americas pertaining to the issuance of US$250  million, 5.65% notes due 2017 and the issuance of US$1.25 billion, 6.40%  notes due 2037 (filed as Exhibit 4.2 to Form 8-K dated May 7,  2007). |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 10.40  |   | Amended and Restated Change of Control Agreements  with Executive Officers dated during December, 2001 (filed as  Exhibit 10.41 to Form 10-K for the year ended December 31,  2001).                                                                                                                                                                      |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 10.41  |   | Indemnification Agreements made between the  Registrant and its directors and officers during 2002 (filed as  Exhibit 10.41 to Form 10-K for the year ended December 31,  2002).                                                                                                                                                                          |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 10.42  |   | Indemnification Agreement made between the  Registrant 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, 2005  between 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 as Schedule  K to the Credit Agreement (filed as Exhibit 10.2 to Form 8-K dated  July 28, 2005).                                                                                                                                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 10.46  |   | Indemnification Agreement made between the  Registrant 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  Registrant and the Toronto-Dominion Bank, as Agent, and the Lenders (filed as  Exhibit 10.1 to Form 8-K dated July 20, 2006).                                                                                                   |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 10.48  |   | Indemnification Agreement made between the  Registrant and Brendon Muller dated April 9, 2007 (filed as  Exhibit 10.48 to Form 8-K dated April 12, 2007).                                                                                                                                                                                            |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 10.49  |   | Amended and Restated Change of Control Agreement  with Roger Thomas dated during December 2001 (filed as  Exhibit 10.48 to Form 10-Q for the quarterly period ended  March 31, 2007).                                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 10.50  |   | Pricing Agreement dated May 1, 2007 among the  Registrant and Banc of America Securities LLC, Citigroup Global Markets Inc.  and Deutsche Bank Securities Inc., as Underwriters (filed as  Exhibit 10.1 to Form 8-K dated May 7, 2007).                                                                                                              |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 10.51* |   | Change of Control Agreement with Gary Nieuwenburg  dated during January 2002.                                                                                                                                                                                                                                                                                       |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 11.1*  |   | Statement regarding the Computation of Per Share  Earnings for the three years ended December 31, 2007.                                                                                                                                                                                                                                                             |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 21.1*  |   | Subsidiaries of the Registrant.                                                                                                                                                                                                                                                                                                                                          |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 23.1*  |   | Consent of Independent Registered Chartered  Accountants.                                                                                                                                                                                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 23.2*  |   | Consent of William M. Cobb &  Associates, Inc.                                                                                                                                                                                                                                                                                                             |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 23.3*  |   | Consent of Ryder Scott Company, L.P.                                                                                                                                                                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 23.4*  |   | Consent of McDaniel & Associates  Consultants Ltd.                                                                                                                                                                                                                                                                                                              |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 23.5*  |   | Consent of DeGolyer and MacNaughton.                                                                                                                                                                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 31.1*  |   | Certification of Chief Executive Officer pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 31.2*  |   | Certification of Chief Financial Officer pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 32.1*  |   | Certification of periodic report by Chief Executive  Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                       |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 32.2*  |   | Certification of periodic report by Chief Financial  Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                       |
|   |   |                                                                                                                                                                                                                                                                                                                                                                     |
| 99.1*  |   | Opinion of Internal Qualified Reserves Evaluator on  National Instrument 51-101 Form F2 as required by certain Canadian  securities regulatory authorities.                                                                                                                                                                                                         |

 

----

** Filed with this Form 10-K.*

 

158

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**SIGNATURES**

 

Pursuant to the requirements of Section 13 or 15(d) ofthe Securities Exchange Act of 1934, the Company has duly caused this report tobe signed on its behalf by the undersigned, thereunto duly authorized, on February 21,2008.

 
|   | NEXEN INC.                                 |
|--------|--------------------------------------------|
|   |                                       |
|   | By:                                        |  /s/ Charles  W. Fischer |
|   | Charles W. Fischer                         |
|   | President, Chief Executive Officer         |
|   | and Director (Principal Executive Officer) |

 

Pursuant to the requirements of the SecuritiesExchange Act of 1934, this report has been signed below by the following personson behalf of the registrant and in the capacities indicated on February 21,2008.

 
| /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, Director   |   | /s/ Brendon T. Muller                                |
| A. Anne McLellan, Director       |   | Brendon T. Muller                                    |
|                             |   | Controller                                           |
| /s/ Eric P. Newell               |   | (Principal Accounting Officer)                       |
| Eric P. Newell, Director         |   |                                                 |
|                             |   |                                                 |
| /s/ Thomas C. O’Neill       |   | /s/ Eric B. Miller                                   |
| Thomas C. O’Neill, Director |   | Eric B. Miller                                       |
|                             |   | 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                                    |
|                             |   | Senior Vice President, Corporate Planning            |
| /s/ John M. Willson              |   | and Business Development                             |
| John M. Willson, Director        |   |                                                 |
|                             |   |                                                 |
| /s/ Victor J. Zaleschuk          |   |                                                 |
| Victor J. Zaleschuk, Director    |   |                                                 |

 

159

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