**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-K**

** **

**ANNUAL REPORT PURSUANTTO SECTION 13 or 15(d) ofTHE SECURITIES EXCHANGE ACT OF 1934**

** **

**For the yearended December 31, 2008**

** **

**CommissionFile Number 1-6702**

** **

**NEXEN INC.**

Incorporated under the Laws ofCanada

 

 

**98-6000202**

(I.R.S. Employer IdentificationNo.)

 

**801 – 7th Avenue S.W.**

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

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

**Web site: www.nexeninc.com**

 

**Securitiesregistered 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   |

 

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

** **

Indicate by check mark if theregistrant is a well-known seasoned issuer, as defined in Rule 405 of theSecurities Act.

 

| Yes  x |   | No  o |
|------------------|--------|-----------------|

 

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

 

| Yes  o |   | No  x |
|------------------|--------|-----------------|

 

Indicate by check mark whetherthe 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 (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days.

 

| Yes  x |   | No  o |
|------------------|--------|-----------------|

 

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 mark whetherthe registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, or a smaller reporting company. See the definitions of “largeaccelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2of the Exchange Act.

 
| Large accelerated  filer   x | Accelerated  filer   o | Non-accelerated  filer   o | Smaller reporting  company   o |
|---------------------------------------------|---------------------------------------|-------------------------------------------|-----------------------------------------------|

 

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

 

| Yes  o |   | No  x |
|------------------|--------|-----------------|

 

On June 30, 2008, theaggregate market value of the voting shares held by non-affiliates of theregistrant was approximately Cdn $22 billion based on the Toronto Stock Exchange closing price on that date.On January 30, 2009, there were 519,820,961 common shares issued andoutstanding.

 

 

** **

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** **

**TABLE OF CONTENTS**

** **
| **PART I**   | **ITEMS 1 AND 2.**   | **Business and  Properties**                                                                                               | **1**   |
|-------------------|----------------------|----------------------------------------------------------------------------------------------------------------------------|---------|
|              | ITEM 1A.             | Risk Factors                                                                                                               | 28      |
|              | ITEM 1B.             | Unresolved Staff  Comments                                                                                                 | 36      |
|              | ITEM 3.              | Legal Proceedings                                                                                                          | 36      |
|              | ITEM 4.              | Submission of  Matters to a Vote of Security Holders                                                                       | 36      |
| **PART II**  | **ITEM 5.**          | **Market for the Registrant’s Common  Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities** | **36**  |
|              | ITEM 6.              | Selected Financial  Data                                                                                                   | 38      |
|              | ITEM 7.              | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                                | 39      |
|              | ITEM 7A.             | Quantitative and  Qualitative Disclosures about Market Risk                                                                | 75      |
|              | ITEM 8.              | Financial Statements  and Supplementary Data                                                                               | 81      |
|              | ITEM 9.              | Changes in and  Disagreements with Accountants on Accounting and Financial Disclosure                                      | 131     |
|              | ITEM 9A.             | Controls and  Procedures                                                                                                   | 131     |
| **PART III** | **ITEMS 10 AND 11.** | **Directors,  Executive Officers and Corporate Governance, and Executive Compensation**                                    | **133** |
|              | ITEM 12.             | Security Ownership of Certain Beneficial Owners and  Management and Related Stockholder Matters                            | 160     |
|              | ITEM 13.             | Certain  Relationships and Related Transactions, and Director Independence                                                 | 161     |
|              | ITEM 14.             | Principal Accounting  Fees and Services                                                                                    | 161     |
| **PART IV**  | ITEM 15.             | Exhibits, Financial Statement Schedules                                                                                    | 163     |

** **

**Special Note to CanadianInvestors****—****see page 79**

** **

**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 an after-royaltiesbasis is provided in tabular format. Volumes and reserves include Syncrudeoperations unless otherwise stated.**

 

**Below is a list of terms specific to theoil and gas industry. They are used throughout the Form 10-K.**

 
| /d     | = | per day                            |
|--------|---|------------------------------------|
| bbl    | = | barrel                             |
| mbbls  | = | thousand barrels                   |
| mmbbls | = | million barrels                    |
| mmbtu  | = | million British thermal units      |
| km     | = | kilometre                          |
| MW     | = | megawatt                           |
| PSCTM  | = | Premium Synthetic Crude            |
| mboe   | = | thousand barrels of oil equivalent |
| mmboe  | = | million barrels of oil equivalent  |
| mcf    | = | thousand cubic feet                |
| mmcf   | = | million cubic feet                 |
| bcf    | = | billion cubic feet                 |
| WTI    | = | West Texas Intermediate            |
| NGL    | = | natural gas liquid                 |
| NYMEX  | = | New York Mercantile Exchange       |

 

In this 10-K, we refer tooil and gas in common units called barrel of oil equivalent (boe). A boe isderived by converting six thousand cubic feet of gas to one barrel of oil(6mcf/1bbl). This conversion may be misleading, particularly if used inisolation, as the 6mcf/1bbl ratio is based on an energy equivalency at theburner tip and does not represent the value equivalency at the well head.

 

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

 
| **(US$)** | ** ** | **December 31** | ** ** | **Average** | ** ** | **High** | ** ** | **Low** | ** ** |
|-----------|------------|----------------------|------------|-------------|------------|----------|------------|---------|------------|
| 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  |       |
| 2008      |       | 0.8166               |       | 0.9381      |       | 1.0289   |       | 0.7711  |       |

 

On January 30, 2009,the noon-day exchange rate was US $0.8088 for Cdn $1.00.

 

Electronic copies of ourfilings with the Securities Exchange Commission (SEC) and the OntarioSecurities Commission (OSC) (from November 8, 2002 onward) are available,free of charge, on our website (www.nexeninc.com). Filings prior to November 8,2002 are available free of charge, 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. The information on our website, is not, andshall not be deemed to be, a part of this Annual Report on Form 10-K.

 

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| ** **       | **Operations**                                                                                                                  | ** ** |
|------------------|---------------------------------------------------------------------------------------------------------------------------------|------------|
| ** **       |                                                                                                                            | ** ** |
| **PART I**  | ITEMS  1 AND 2.  Business and Properties                                                                                        | ** ** |
|             | About Us                                                                                                                        | 1          |
|             | Strategy                                                                                                                        | 2          |
|             | Understanding the Oil and Gas  Business                                                                                         | 3          |
|             | Oil and Gas Operations                                                                                                          | 4          |
|             | Reserves, Production and  Related Information                                                                                   | 15         |
|             | Syncrude Mining Operations                                                                                                      | 20         |
|             | Energy Marketing                                                                                                                | 22         |
|             | Chemicals                                                                                                                       | 25         |
|             | Government Regulations                                                                                                          | 26         |
|             | Environmental Regulations                                                                                                       | 26         |
|             | Employees                                                                                                                       | 28         |
|             |                                                                                                                            |       |
|             | ITEM 1A.                                                                                                                        |       |
|             | Risk Factors                                                                                                                    | 28         |
|             |                                                                                                                            |       |
|             | ITEM 1B.                                                                                                                        |       |
|             | Unresolved Staff Comments                                                                                                       | 36         |
|             |                                                                                                                            |       |
|             | ITEM 3.                                                                                                                         |       |
|             | Legal Proceedings                                                                                                               | 36         |
|             |                                                                                                                            |       |
|             | ITEM 4.                                                                                                                         |       |
|             | Submission of Matters to a  Vote of Security Holders                                                                            | 36         |
| ** **       | ** **                                                                                                                      | ** ** |
| **PART II** | ITEM 5.  Market for the Registrant’s Common equity, Related Stockholder Matters and  Issuer Purchases of Equity Securities | 36         |
|             |                                                                                                                            |       |
|             | ITEM 6.                                                                                                                         |       |
|             | Selected  Financial Data                                                                                                        | 38         |

 

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**ABOUT US**

 

Nexen Inc. (Nexen, we or our)is an independent, Canadian-based, global energy company. We were formed inCanada in 1971 as Canadian Occidental Petroleum Ltd. when Occidental PetroleumCorporation (Occidental) combined their Canadian crude oil, natural gas,sulphur and chemical operations into one company. We’ve grown from producing10,700 boe/d before royalties with revenues of $26 million in 1971, toproducing over 250,000 boe/d before royalties (including Syncrude production)and revenues of $8.2 billion in 2008. We achieved this growth throughexploration success and strategic acquisitions. Operating for more than 35years, we have been profitable every year, except one, and have been payingquarterly dividends consecutively since 1975.

 

**Where wecame from**

 
|                    | 1970s               | ·     | broadened our western  Canadian asset base and entered the US Gulf of Mexico                                                                                                                                                                                                                                                                                                  |
|-------------------------|---------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | finished the decade with  production of about 11,000 boe/d and revenues of $126 million                                                                                                                                                                                                                                                                                       |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    | 1980s               | ·     | grew our western Canadian  and Gulf of Mexico assets through acquisitions                                                                                                                                                                                                                                                                                                     |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | acquired Canada-Cities  Service doubling our size and captured an interest in Syncrude                                                                                                                                                                                                                                                                                        |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | finished the decade with  production of about 69,000 boe/d and revenues of $591 million                                                                                                                                                                                                                                                                                       |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    | 1990s               | ·     | discovered the first of 17  fields at Masila in Yemen in 1990 and production commenced in 1993                                                                                                                                                                                                                                                                                |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | tripled our Canadian  production in 1997 by purchasing Wascana Energy Inc.                                                                                                                                                                                                                                                                                                    |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | explored and made several  discoveries, such as our 1998 Ukot discovery on block OPL-222, offshore Nigeria                                                                                                                                                                                                                                                                    |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | finished the decade with  production of about 239,000 boe/d and revenues of $1.7 billion                                                                                                                                                                                                                                                                                      |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    | **Who we are  now** | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                    |
|                    | ** **          | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                    |
|                    | 2000—2008      | ·     | made several significant  international discoveries including: Gunnison, Aspen, Knotty Head and  Longhorn in the deep-water Gulf of Mexico; Guando in Colombia; Block 51 in  Yemen; and Usan, offshore Nigeria                                                                                                                                                                |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | acquired properties in the  UK North Sea in 2004, including operatorship of the Buzzard discovery, the  producing Scott and Telford fields and 700,000 exploration acres. Buzzard  came on stream in 2007 on time and on budget.   Made several discoveries including Golden Eagle, Pink and Rochelle                                                                    |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | signed a 50/50 joint  venture agreement with OPTI Canada Inc. to develop, produce and upgrade  bitumen at Long Lake utilizing our patented OrCrudeTM technology, in the Athabasca oil sands.  Construction of the Long Lake Project was completed in 2008                                                                                                                |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | acquired Occidental’s  remaining 29% interest in us with Ontario Teachers’ Pension Plan Board  (Teachers).  Teachers purchased 20.2  million common shares and we repurchased the remaining 20 million common  shares for $605 million. We also exchanged our oil and gas operations in  Ecuador for Occidental’s 15% interest in our chemical operations |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | divested non-core assets in  2005 by selling Canadian properties producing about 18,300 boe/d before  royalties and by monetizing 39% of our chemical business through the initial  public offering of Canexus Income Fund                                                                                                                                                    |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | developed our first coalbed  methane (CBM) project in the Fort Assiniboine area in western Canada in 2005                                                                                                                                                                                                                                                                     |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | captured a significant  shale gas position in the Horn River Basin in northeastern BC                                                                                                                                                                                                                                                                                         |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
| **Where we  are going** | ** **          |       |
| ** **              | ** **          | ** ** |                                                                                                                                                                                                                                                                                                                                                                          |
|                    | 2009                | ·     | began producing premium  synthetic crude in January 2009 at Long Lake. Increased our interest in  the Long Lake Project and joint venture lands by 15% and become the sole  operator of both the resource and upgrader                                                                                                                                                   |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | continue to enhance and  develop production at Long Lake and move towards first production at Ettrick  in the UK North Sea and Longhorn in the US Gulf of Mexico later this year                                                                                                                                                                                              |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | focusing on oil sands,  unconventional gas and select conventional exploration and exploitation  properties in our core areas                                                                                                                                                                                                                                                 |
|                    |                |       |                                                                                                                                                                                                                                                                                                                                                                          |
|                    |                | ·     | continue to evaluate and  appraise potentially significant recent discoveries in the UK North Sea                                                                                                                                                                                                                                                                             |
|                         |                     |            |                                                                                                                                                                                                                                                                                                                                                                               |  |  |  |

 

1

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**STRATEGY**

 

Choice — it’s what companiesand investors value most in challenging times. Whether it’s how we allocatecapital, fund our growth, or which projects make the most sense in currenteconomic times, choice is key. Our strategy is to build a sustainable energycompany focused in three areas: oil sands, unconventional gas and selectconventional exploration and exploitation.

 

To be sustainable we must bebetter than average. So we operate where we see the greatest opportunity forlong-term value creation. Then we invest in solid land positions, developingexpertise and applying technology that give us a competitive advantage.

 

Our goal is to grow long-termvalue for our shareholders responsibly. Key drivers to growing value includeincreasing reserves, production, cash flow and net income on a cost-effectivebasis over the long term. We leverage off our competitive advantages togenerate opportunities for long-term success in our evolving industry.

 

As conventional basins inNorth America mature, we’ve developed specific capabilities in oil sands, CBM,deep-water technology and international experience. These skills enable us tofocus on specific types of projects, as we transition toward major projects inestablished basins, exploration in less mature basins and exploitation ofunconventional resources.

 

Today, we are buildingsustainable businesses in western Canada, the North Sea, Gulf of Mexico, andoffshore West Africa, capitalizing on the following corporate strengths:

 

·      diversification—our assetsare geographically diverse and we produce oil and gas, onshore and offshore. Wehave large conventional and unconventional legacy assets in our portfolio;

·      significant capturedresource—we have key resource plays with a low cost of entry. Our Long LakeProject is developing only 10% of our oil sands leases in the Athabasca oilsands, we hold 195 net sections in the emerging Horn River shale gas play innorth east British Columbia and we hold unexplored acreage in the Gulf of Mexico,the North Sea, western Canada and elsewhere;

·      focus on growth—we aregrowing our business through exploration and innovative technology. We aresuccessful explorers with significant undeveloped discoveries at Knotty Headand Vicksburg in the Gulf of Mexico, the Golden Eagle area in the UK North Sea andat Usan, offshore Nigeria. Long Lake is the first oil sands project to usegasification technology to significantly reduce the cost of producing bitumenand we are advancing new techniques for unconventional production of CBM andenhanced heavy oil recovery in western Canada;

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

·      strong financial position—wehave access to $3.5 billion of liquidity (after acquiring the additional 15%interest in Long Lake in January 2009) through cash and undrawn committedcredit facilities to allow us to proceed with investments at the pace of ourchoice and to take advantage of opportunities as they arise like we did withour strategic entry into the UK North Sea in 2004 and our recent acquisition ofan additional 15% working interest at Long Lake; and

·      sustainable businesspractices—leveraging our strength in business practices such as Health, Safety,Environment and Social Responsibility (HSE&SR) to access opportunities andresponsibly create and demonstrate both long-term benefits and value growth forour investors, for the communities in which we operate and for otherstakeholders. This makes us a desired business partner and/or joint ventureoperator.

 

The location and scale of ouroperations often result in: 1) an extended period of time from the capture ofopportunities to first production and 2) non-linear, year-over-year growth inreserves and production. Significant up-front capital investment is oftenrequired prior to realizing production and free cash flows. We fund thisinvestment by maximizing cash flow from our producing assets, issuing long-termdebt and/or equity and selling non-core assets into attractive markets.

 

Our financial position isstrong. We have financial flexibility with major capital projects complete atBuzzard and Long Lake, and industry-leading cash netbacks. We have availableliquidity of approximately $3.5 billion (after acquiring the additional 15%interest in Long Lake), split between cash and undrawn committed credit. Wehave no debt maturities until 2011 and our average term-to-maturity of ourlong-term debt is approximately 18 years.

 

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

 

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For financial reportingpurposes, we report on four main segments:

 

·      oil and gas;

·      Syncrude;

·      energy marketing; and

·      chemicals.

 

Our oil and gas operationsare broken down geographically into the UK North Sea, US Gulf of Mexico,Canada, Yemen and Other International (currently Colombia, offshore West Africaand Norway). Results from our Long Lake Project are included in Canada.Syncrude is our 7.23% interest in the Syncrude Joint Venture. Energy marketingincludes our crude oil, natural gas, natural gas liquids and power marketingbusinesses in North America, Europe and Asia. Chemicals includes operations inNorth America and Brazil that manufacture, market and distribute sodiumchlorate, caustic soda, muriatic acid and chlorine through Canexus LimitedPartnership.

 

Production, revenues, netincome, capital expenditures and identifiable assets for these segments appearin Note 22 to the Consolidated Financial Statements and in Management’sDiscussion and Analysis of Financial Condition and Results of Operations(MD&A) in this report.

 

**UNDERSTANDINGTHE OIL AND GAS BUSINESS**

** **

The oil and gas industry ishighly competitive. With strong global demand for energy, there is intensecompetition to find and develop new sources of supply. Yet, barrels fromdifferent reservoirs around the world do not have equal value. Their valuedepends on the costs to find, develop and produce the oil or gas, the fiscalterms of the host regime and the price that products command in the marketbased on quality and marketing efforts. Our goal is to extract the maximumvalue from each barrel of oil equivalent, so every dollar of capital we investgenerates an attractive return.

 

Numerous factors can affectthis. Changes in crude oil and natural gas prices can significantly affect ournet income and cash flow generated from operating activities. Consequently,these prices may also affect the carrying value of our oil and gas propertiesand how much we invest in oil and gas exploration and development. We attemptto reduce these impacts by investing in projects we believe will generatepositive returns at relatively low commodity prices. We maintain liquidity thatprovides us with the ability to invest in high-quality projects that we believewill generate value over the long term.

 

The prices we receive for ouroil and gas products are determined by global crude oil and natural gasmarkets, which can be volatile, and by worldwide supply/demand fundamentals.With many alternative customers, the loss of any one customer is not expectedto have a significantly adverse effect on the price of

 

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our products or revenues. Oiland gas producing operations are generally not seasonal. However, demand forsome of our products can fluctuate season to season, which impacts price. Inparticular, heavy oil is typically in higher demand in the summer for its usein road construction, and natural gas is generally in higher demand in thewinter for heating. We manage our operations on a country-by-country basis,reflecting differences in the regulatory and competitive environments and riskfactors associated with each country.

 

**OIL AND GASOPERATIONS**

** **

We have oil and gasoperations in the UK North Sea, US Gulf of Mexico, western Canada, Yemen,Colombia, offshore West Africa and Norway. We also have operations in Canada’sAthabasca oil sands which produce synthetic crude oil. We operate most of ourproduction and continue to develop new growth opportunities in each area byactively exploring and applying technology.

 

In this Form 10-K, we provideestimates of remaining quantities of proved oil and gas reserves for ourvarious properties. Such estimates are internally prepared. Additionally, atthe end of the year, 98% of our oil and gas reserves before royalties (98%after royalties) and 100% of our Syncrude reserves before royalties (100% afterroyalties) were assessed (either evaluated or audited as described on page 19)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 70 for a description of our reserves process, and to thesection on Reserves, Production and Related Information on page 15 for adescription of the nature and scope of the independent assessments performedand the results thereof.

 

**Certainstatements in these items 1 and 2 constitute “forward-looking statements” andthe reader should refer to the “Special Note Regarding Forward-LookingStatements” set out on page 78 of this 10-K.**

 

**North Sea — UnitedKingdom (UK)**

** **

The UK North Sea is a keyproducing area. Our assets include a 43.2% operated interest in the Buzzardfield and facilities, a 41.9% operated interest in the Scott field andproduction platform, a 71.8% operated interest in the Telford field, interestsin several satellite discoveries and more than 750,000 net undevelopedexploration acres. We are a significant regional player with concentratedassets, infrastructure and exploration potential for future growth. Our NorthSea properties have high-margin reserves and production, diversify our globalportfolio by adding strong assets in a stable jurisdiction, and complement ourother longer cycle-time projects.

 

Our UK strategy is to growand sustain our existing North Sea production and identify new production hubswith exploration and exploitation opportunities near existing infrastructure.We have a number of exploitation opportunities in our existing fields andsmaller undeveloped discoveries near infrastructure. Most of our unexploredacreage is near Scott/Telford, Buzzard or Ettrick. As a result, new discoveriescan be tied-in quickly.

 

During the year, we produced102,700 boe/d before royalties (102,700 after royalties) in the UK, which wasapproximately 41% of our total production. At year end, our UK proved oil andgas reserves of 175 mmboe before royalties (175 after royalties) representedabout 18% of our total proved oil and gas and Syncrude reserves beforeroyalties (19% after royalties).

 

Buzzard

 

Buzzard is the largestdiscovery in the UK North Sea in over a decade. It was discovered in 2001 andconstruction of the platforms and facilities was completed in 2006. Productioncame on stream early 2007 and the project was completed on time and on budget.

 

The Buzzard field is locatedabout 60 miles northeast of Aberdeen in the Outer Moray Firth, central NorthSea, in 317 feet of water. The Buzzard development includes three platformsthat can process at least 200,000 bbls/d of oil and 60 mmcf/d of gas. We havedrilled 18 development wells and 14 of them are on stream. Development drillingresulted in more well-to-well variability in the concentration of hydrogensulphide than originally expected. To address this, we are constructing a fourthplatform with production sweetening facilities to handle

 

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higher levels of hydrogensulphide. Existing equipment and processes can manage current hydrogen sulphidelevels and maintain current production deliverability until the additionalequipment is commissioned, which is scheduled for 2010.

 

Oil from Buzzard is exportedvia the Forties pipeline to the Grangemouth refinery in Scotland. Gas isexported via the Frigg system to the St. Fergus Gas Terminal in northeastScotland.

 

We expect to produce theBuzzard field through 27 production wells and maintain reservoir pressure withan active water-flood program. During 2008, the Buzzard field reached amilestone when it exported 100 million barrels of crude oil. In 2009, we planto drill four production wells, two water injectors and progress work on thefourth platform. During the third quarter of 2009, we plan to install thejackets for this platform and complete tie-in operations, pending installationof the topsides. This will result in about one month of downtime whichcoincides with a six week planned slowdown of the Forties pipeline.

 

Scott/Telford

 

Scott and Telford areproducing fields with additional exploitation opportunities and both tie backto the Scott platform. Scott was discovered in 1987 and began producing inSeptember 1993, while Telford was discovered in 1991 and came on stream in1996. We have a 41.9% working interest in the Scott platform and field, and a71.8% working interest in Telford. In 2008, our share of production from thesefields was approximately 10,500 boe/d. The production is around 90% oil andproduced through subsea wells tied back to the Scott platform. Oil is deliveredto the Grangemouth refinery in Scotland via the Forties pipeline, while gas isexported via the SAGE pipeline to the St. Fergus Gas Terminal in northeastScotland. In recent years, the Scott platform underwent a significantmaintenance turnaround and facilities upgrade to improve reliability and extendfacility life.

 

 

Ettrick

 

We are progressingdevelopment of the Ettrick field and first oil is expected in the next fewmonths. The FPSO is currently being commissioned and expected to be on locationshortly. Development of the field includes five subsea production wells andthree water injectors tied back to a leased FPSO; however, we are developingEttrick as a new production hub and we expect to tie in new discoveries. We arereviewing our recent exploration success at Blackbird as a potential tie-backto the Ettrick FPSO. The FPSO is designed to handle 30,000 bbls/d of oil, 35mmcf/d of gas and to re-inject 55,000 bbls/d of water. We operate Ettrick withan 80% working interest.

 

Other

 

We have interests in twosmaller non-operated fields in the UK North Sea. The Farragon field was broughton stream in late 2005. In 2007, the Duart field began producing oil from asingle well tied back to the Tartan platform. Our share of production in 2008from these properties was 3,900 boe/d before royalties (3,900 after royalties).

 

5

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Explorationand Undeveloped Assets

 

We continue to activelyexplore in the UK North Sea and hold several undeveloped discoveries onoperated blocks near Scott, Buzzard and Ettrick as follows:

 
| **Field**        | ** ** | **Interest (%)** | ** ** | **Operator Status** | ** ** | **Comments**                                                       |
|------------------|------------|-----------------------|------------|--------------------------|------------|--------------------------------------------------------------------|
| Blackbird        |       | 80                    |       | operated                 |       | discovery near Ettrick;  appraisal well planned for 2009           |
| Black Horse      |       | 50                    |       | operated                 |       | discovery near Scott;  evaluating development alternatives         |
| Bugle            |       | 41                    |       | operated                 |       | discovery near Scott;  evaluating development alternatives         |
| Ferret (Polecat) |       | 40                    |       | operated                 |       | discovery near Buzzard;  appraisal well planned for 2009           |
| Golden Eagle     |       | 34                    |       | operated                 |       | discovery near Buzzard;  evaluating development alternatives       |
| Hobby            |       | 34                    |       | operated                 |       | discovery near Buzzard;  successful well drilled January 2009 |
| Kildare          |       | 50                    |       | operated                 |       | discovery near Scott;  evaluating development alternatives         |
| Perth            |       | 42                    |       | operated                 |       | discovery near Scott;  evaluating development alternatives         |
| Pink             |       | 46                    |       | operated                 |       | discovery near Golden  Eagle; appraisal well planned for 2009      |
| Rochelle         |       | 44                    |       | non-operated             |       | discovery near Scott;  successful well drilled January 2009   |

 

In 2007, we discoveredhydrocarbons at Golden Eagle, which was further appraised with a sidetrackwell. We are currently evaluating development options and expect to sanctiondevelopment in 2009. In 2008, we drilled two exploration wells in the UK NorthSea that found hydrocarbons at Blackbird and Pink. In early 2009, we discoveredhydrocarbons at Rochelle and Hobby.

 

In 2009, we plan to drillfour exploration wells and four appraisal wells. We may modify our current 2009drilling plans depending on various factors, including our partners’ financialsituation, the current global economic environment and declining commodityprices.

 

We are also assessingemerging CBM opportunities onshore in the UK. In 2006, we acquired an 80%working interest in one opportunity and subsequently drilled two successfulexploration wells. Both wells encountered coal seams and are being monitoredthrough ongoing production testing.

 

FiscalTerms

 

In the UK, new discoveriespay no royalties and result in cash netbacks that are higher than our companyaverage. Scott is subject to Petroleum Revenue Tax (PRT), although no PRT ispayable until available oil allowances have been fully utilized, which isn’texpected before 2010. Once payable, PRT is levied at 50% of cash flow aftercapital expenditures, operating costs and an oil allowance. PRT is applicableto fields receiving development consent prior to March 1993. Buzzard,Ettrick, Farragon, Duart and Telford are not subject to PRT. PRT is deductiblefor corporate income tax purposes. The UK corporate income tax rate on oil andgas activities is 30% of taxable income and is also subject to a 20%supplemental charge.

 

**Gulf ofMexico — United States (US)**

** **

The Gulf of Mexico is anintegral part of our growth strategy. Large discoveries, relatively highsuccess rates, expanding production infrastructure and attractive fiscal termsmake the deep-water Gulf of Mexico one of the world’s most prospective sourcesfor oil and gas. While costs of deep-water exploration are high relative toother basins, deep-water prospects generally have multiple sands and highproduction rates—factors which improve economics. Technology to find, drill,and develop deep-water discoveries is rapidly progressing and becoming morecost effective. The deep-water Gulf is near infrastructure and continental USmarkets, so discoveries can be brought on stream in reasonable time.

 

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

 

·      deep-water prospects nearexisting infrastructure;

·      deep-water, Miocene and LowerTertiary sub-salt plays with the potential to become new core areas; and

·      deep-water, Norphlet targetsin the eastern Gulf of Mexico.

 

These plays are relativelyunder-explored, hold potential for large discoveries and have attractive fiscalterms. The shorter cycle-times for deep-water prospects near 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 a significant leaseholder in the deep-water.

 

In 2009, we plan to furtherour growth strategies. This includes tieing in our four-well subsea tie-back atLonghorn and completing development of Mississippi Canyon 72, both of which areexpected on stream in 2009. We also plan to continue to advance our explorationstrategy with additional exploratory drilling and seismic evaluation.

 

6

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**USProduction**

 
| ** ** | ** ** | **2008**              | ** ** | **2007**             | ** ** | **2006**              | ** ** |
|------------|------------|-----------------------|------------|----------------------|------------|-----------------------|------------|
| **mboe/d** | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** |
| Deep Water |       | 12.2                  |       | 10.7                 |       | 19.4                  |       | 17.4 |   | 19.6 |   | 17.5 |   |
| Shelf      |       | 10.1                  |       | 8.4                  |       | 13.8                  |       | 11.5 |   | 15.9 |   | 13.2 |   |
| **Total**  | ** ** | **22.3**              | ** ** | **19.1**             | ** ** | **33.2**              | ** ** | **28.9** | ** ** | **35.5** | ** ** | **30.7** | ** ** |

 

At year end, proved reservesof 49 mmboe before royalties (43 after royalties) in the Gulf of Mexicorepresented about 5% of our total proved oil and gas and Syncrude reserves. OurGulf production and reserves are primarily concentrated in four deep-water andfive shallow-water (shelf) areas.

 

DeepWater

 

Most of our deep-waterproduction comes from our 30% non-operated Gunnison field and our 100% operatedAspen field. The remainder comes from our 50% non-operated Wrigley field andthree 100% operated properties acquired in 2007. In 2009, our 25% non-operatedLonghorn field is expected to come on stream and contribute to our Gulf ofMexico production volumes.

 

Gunnison is in 3,100 feet ofwater and includes Garden Banks Blocks 667, 668 and 669. Gunnison beganproduction in December 2003 through our truss SPAR platform that canhandle 40,000 bbls/d of oil and 200 mmcf/d of gas. Our Gunnison SPAR facilityhas excess capacity, leaving room for growth from regional exploration andprocessing of third-party volumes. We achieved payout on Gunnison inDecember 2005, just two years after first production. In 2008, our shareof production before royalties was approximately 4,200 boe/d (3,700 afterroyalties).

 

Aspen is on Green CanyonBlock 243 in 3,150 feet of water. The project was developed using subsea wellstied back to the Shell-operated Bullwinkle platform 16 miles away and beganproducing in December 2002. Our share of 2008 production before royaltieswas approximately 3,100 boe/d (2,800 after royalties).

 

Wrigley is on MississippiCanyon Block 506 in 3,300 feet of water. The project consists of a singlesubsea well tied back to the Shell-operated Cognac platform 17 miles away.Wrigley began gas production in July 2007 and our share before royaltiesin 2008 was approximately 2,400 boe/d (2,100 after royalties).

 

In 2007, we acquired threenew deep-water producing fields: 1) Garden Banks Block 205; 2) Green Canyon137; and 3) Green Canyon 6/50. These fields are in water depths between 700 and1,100 feet. Production from Green Canyon 6/50/137 has been temporarilysuspended as the third-party platform that processed our oil and gas wasdestroyed by Hurricane Ike in September 2008. We are currently assessing ouroptions to restore field production.

 

In 2009, we expect to havetwo fields begin producing oil and gas. Our non-operated Mississippi Canyon 72property is designed to come on stream through a single subsea gas well tiedback to the BP-operated Pompano Platform five miles northwest of the field. TheLonghorn property is on Mississippi Canyon Block 502 in 2,400 feet of water.The project is a non-operated three-well subsea tie-back to the Corral platformlocated 19 miles north of the field. We expect production from these propertiesto commence in mid 2009.

 

Shelf

 

Our shelf producing assetsare offshore Louisiana, primarily in five 100%-owned field areas: Eugene Island18, Eugene Island 255/257/258/259, Eugene Island 295, Vermilion320/321/339/340, and Vermilion 76 (consisting of Blocks 65, 66 and 67). Wecontinue to look for opportunities to optimize these assets. In 2009, our shelfdevelopment program includes a well at Vermilion 76 to access additionalreserves and four recompletion projects.

 

 

7

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Exploration and UndevelopedAssets

 

Our undeveloped deep-waterdiscoveries include:

 
| **Well**    | ** ** | **Interest (%)** | ** ** | **Operator Status** | ** ** | **Comments**                           |
|-------------|------------|-----------------------|------------|--------------------------|------------|----------------------------------------|
| Tobago      |       | 10                    |       | non-operated             |       | sanctioned; production  expected 2010  |
| Knotty Head |       | 25                    |       | operated                 |       | discovery; further  appraisal required |
| Vicksburg   |       | 25                    |       | non-operated             |       | discovery; further  appraisal required |

 

During the year, we drilledtwo exploratory dry holes in deep water and acquired additional deep-wateracreage. We hold approximately 236 blocks and expect this acreage and futureexploration opportunities to position us well for continued growth. In 2009,our expected exploration program includes one exploration well and twoappraisal wells, all in deep water. To explore our land inventory and evaluateexisting discoveries, we secured two new-build dynamically-positionedfifth-generation semi-submersible drilling rigs. We share access to the rigsthat provides us with the ability to use each rig for a total of 24 months overthe next four years. We expect the first rig will become available late 2009,followed by the second rig in 2010.

 

FiscalTerms

 

In 2008, royalty rates on ourUS production averaged 16.5% for shelf volumes and 12.2% for deep-watervolumes. The US government increased royalty rates from 12.5% to 16.7% for newdeep-water leases awarded after July 2007. We qualify for royalty reliefat our deep-water Aspen and Gunnison fields on the first 87.5 mmboe ofproduction. The US Department of the Interior’s Minerals Management Service (MMS)suspended royalty relief on our Gunnison lease and assessed royalties on ourproduction from the field. The oil and gas industry litigated theenforceability of these actions and won a judgement in a US District Court. TheMMS subsequently lost their appeal of that judgement in January 2009. OurAspen field is not subject to a minimum price threshold. US taxable income issubject to federal income tax of 35% and state taxes ranging from 0% to 12%.

 

**Canada**

** **

Our strategy in Canada is twofold: 1) develop unconventional resource opportunities (oil sands, CBM andshale gas) and 2) maximize value from our established operations throughdisciplined or selective conventional development and enhanced recoverymethods. In 2008, we produced 41,900 boe/d before royalties (34,300 afterroyalties) in Canada, which was approximately 17% of our total productionincluding Syncrude. At year end 2008, Canadian proved reserves (includingbitumen and excluding Syncrude) of 375 mmboe before royalties (362 afterroyalties) were approximately 38% before royalties (39% after royalties) of ourtotal proved oil and gas and Syncrude reserves.

 

Our Canadian conventionalassets include heavy oil production in east-central Alberta and west-centralSaskatchewan, and natural gas near Calgary and in southern Alberta andSaskatchewan. We operate most of our producing properties and hold almost onemillion net acres of undeveloped land across western Canada. These assetsprovide predictable production volumes and earnings while we advance thefollowing initiatives for future growth:

 

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

·                  shalegas—to evaluate natural gas from organic shales;

·                  coalbedmethane (CBM)—to extract natural gas primarily from Upper Mannville andHorseshoe Canyon coals; and

·                  enhancedoil recovery (EOR)—to increase recovery in our heavy oil fields.

 

In 2008, we invested $1,427million in Canada including $1,320 million into these growth initiatives. Withthe completion of Long Lake Phase 1 in the Athabasca oil sands, we plan toreduce our capital expenditures in 2009 in Canada. Our 2009 capital programsare focused on optimizing and sustaining Long Lake, evaluating and progressingour shale gas opportunities and advancing our CBM strategies.

 

AthabascaOil Sands

 

The Athabasca oil sands in northeastAlberta is a key growth area for Nexen. Our strategy is to economically developour bitumen resource in phases to provide low-risk, stable, future

 

 

8

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growth. Our Long Lake Projectinvolves integrating steam-assisted-gravity-drainage (SAGD) bitumen productionwith field upgrading technology to produce a premium synthetic crude for sale,and a synthetic gas, which significantly reduces our need to purchase naturalgas for operations. We also have a 7.23% investment in the Syncrude oil sandsmining operation.

 

*Long Lake Project*

* *

In 2001, we formed a 50/50joint venture with OPTI Canada Inc. (OPTI) to develop the Long Lake lease usingSAGD for bitumen production and proprietary OrCrudeTM technology for our firststage of upgrading. OPTI has the exclusive Canadian license for the OrCrudeTMtechnology. We acquired the exclusive right to use this technology with OPTIwithin approximately 100 miles of Long Lake, and the right to use thetechnology independently elsewhere in the world.

 

SAGD bitumen operationsstarted in mid 2008 and we began producing premium synthetic crude from theupgrader in January 2009. Early in 2009, we acquired an additional 15%interest in the Long Lake Project and the joint venture lands from OPTI,increasing our ownership level to 65%. Following this acquisition, we are nowresponsible for operating both the SAGD bitumen extraction process and theupgrader for Phase 1 as well as for future phases.

 

*SAGD and Upgrader Integration*

* *

SAGD involves drilling twoparallel horizontal wells, generally between 2,300 and 3,300 feet long, withabout 16 feet of vertical separation. Steam is injected into the shallowerwell, where it heats the bitumen that then flows by gravity to the deeper producingwell. The OrCrudeTM technology, using conventional distillation, solventde-asphalting and thermal cracking, separates the produced bitumen intopartially upgraded sour crude oil and liquid asphaltenes. By coupling theOrCrudeTM process with commercially available hydrocracking and gasificationtechnologies, sour crude is upgraded to light (39° API) premium synthetic sweetcrude oil, and the asphaltenes are converted to a low-energy, synthetic fuelgas. This gas is available as a low-cost fuel for generating steam and as asource of hydrogen for the hydrocracking process. The gas is also burned in acogeneration plant to produce electricity for on-site use and sold to theprovincial electricity grid. The energy conversion efficiency for our Long Lakeupgrader is about 90% compared to 75% for a typical bitumen-fed coker, which weexpect will provide us with an approximate $10/bbl operating cost advantage.

 

 

*Our Strategic Advantage*

* *

Our integrated SAGD andupgrading process addresses three main economic hurdles of SAGD bitumenproduction: 1) the high cost of natural gas; 2) the cost and availability ofdiluent; and 3) the realized price of bitumen. With synthetic gas from theasphaltenes as fuel, we need to purchase very little additional natural gas.With the upgrading facilities on site, expensive diluent is not required totransport the bitumen to market. By upgrading the bitumen into a highlydesirable refinery feedstock or diluent supply, the end product commandslight-sweet crude oil premium pricing.

 

*Project Milestones and Costs*

* *

The Long Lake Projectreceived regulatory approval in 2003 and Nexen board approval in 2004. Fieldconstruction of the SAGD and upgrader facilities began in 2004. In 2006, wesubstantially completed module and site construction of the SAGD facilities andin 2007, we began injecting steam into the well pads. We continued to steam theSAGD well pairs and began turning wells over to SAGD production in 2008. In2008, we produced 3,900 bbls/d of bitumen before royalties (3,900 after royalties)and are currently producing approximately 20,000 bbls/d (13,000 net to us) asof January 2009. The first several months of steam injection largelyinvolves heating the reservoir, followed by a ramp up of bitumen production topeak rates over 12 to 24 months. The reservoir behavior is meeting ourexpectations.

 

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At the start of production,steam-to-oil ratios are high but will decline as bitumen production ramps up toour target rates. We expect the steam-to-oil ratio to average approximately 3.0over the long-term.

 

We completed construction ofthe upgrader in 2008 and began commissioning for commercial operations.Production of premium synthetic crude oil from the upgrader began in lateJanuary 2009. We expect that it will take approximately 12 to 18 months toreach the upgrader design capacity. As the upgrader ramps up to full capacity,we expect that there will be periods of downtime as we work through the earlystages of operation. This periodic downtime is normal following initialfacility start-up and consistent with industry experience. During the bitumenramp up period, we are purchasing third-party bitumen to take advantage ofexcess upgrading capacity. Production capacity for the first phase of Long Lakeis approximately 60,000 bbls/d (39,000 net at a 65% working interest) ofpremium synthetic crude. We expect to maintain production over the project’slife, estimated at 40 years, by periodically drilling additional SAGD wellpairs.

 

Long Lake’s total capital costsincreased since project sanctioning due to design enhancements and industrycost pressures. As a result, the final cost of Long Lake increased from $3.8billion to $6.4 billion ($3.2 billion net to us before acquiring an additional15% interest in January 2009). Despite capital cost increases, we still expectto achieve positive economic returns which benefit from a significant operatingcost advantage. Combined SAGD, cogeneration and upgrading operating costs areexpected to average about $22/bbl, substantially lower than coking or otherupgrading processes as a result of the reduced need to purchase natural gas. Weexpect ongoing capital to average between $5/bbl and $10/bbl depending on wellspacing, well length and recovery factor. The full-cycle capital costs ofproducing and upgrading bitumen using this technology are comparable to those forsurface mining and coking upgrading on a barrel-of-daily production basis.

 

*FuturePhases*

 

We have approximately 281,000net acres of bitumen-prone lands in the Athabasca region, with plans to acquiremore. We plan to continue developing our bitumen lands in phases using ourintegrated upgrading strategy. In 2008, we invested $175 million on landacquisition, additional drilling, seismic and engineering to develop our leasesand advance regulatory applications for these phases.

 

During 2007, the federal governmentannounced climate change proposals, however, legislation has not yet beendrafted. Due to this regulatory uncertainty and the current global economiccrisis, we are delaying certain planned expenditures on Phase 2. Phase 2 isexpected to be followed by additional phases every three or four years. Eachphase will leverage the knowledge and experience gained from successfullydeveloping Long Lake and subsequent projects will be similar in size anddesign. By 

 

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keeping the core team in placeand repeating and improving on existing designs and implementation plans, weexpect to gain efficiencies in engineering, modular fabrication and on-siteconstruction. We also anticipate enhanced operating efficiencies as we cantrain and move people easily between the various plants.

 

*ReservesRecognition*

 

Under current SEC rules andregulations, we are currently required to recognize bitumen reserves ratherthan the upgraded premium synthetic crude oil that we expect to produce andsell. The economic recoverability of bitumen reserves is sensitive to naturalgas prices, diluent costs and light/heavy differentials, risks that ourintegrated project has been designed to virtually eliminate. At December 31,2008, we recognized proved bitumen reserves of 285 mmboe before royalties (282mmboe after royalties) for our Long Lake Project, representing about 29% beforeroyalties (30% after royalties) of our total proved oil and gas and Syncrudereserves.

 

Heavy Oil

 

Approximately 49% of ourCanadian conventional production is heavy oil. Heavy oil is characterized byhigh specific gravity or weight and high viscosity or resistance to flow.Therefore, heavy oil is more difficult and expensive to extract, transport andrefine than other types of oil. Heavy oil also receives a lower price thanlight oil, as more expensive and complex refineries are required to refineheavy crude into higher-value petroleum products. To maximize heavy oilreturns, it is important to manage capital and operating costs. Our largeproduction base and existing infrastructure are advantageous in managing thesecosts. Heavy oil reservoirs typically have lower recovery factors thanconventional oil reservoirs, leaving substantial amounts of oil in the ground.This creates an opportunity to increase recovery factors by applying newtechnology. We are continuing to research various technologies to increase ourheavy oil recoveries with ongoing pilot projects in west-central Saskatchewan.

 

Natural Gas

 

Approximately 32% of ourCanadian production is natural gas extracted primarily from shallow sweetreservoirs in southern Alberta and Saskatchewan and from sour gas reservoirsnear Calgary. In general, shallower gas targets are cheaper to drill andproduce, but have relatively smaller reserves and lower productivity per well.Sour gas is natural gas that contains hydrogen sulphide. Our Balzac field,northeast of Calgary, has been producing sour natural gas since 1961. This sourgas is processed through our operated Balzac plant, which recently went throughan extensive maintenance upgrade to improve reliability and efficiency.

 

Coalbed Methane (CBM)

 

Approximately 19% of ourCanadian production is from our commercial CBM developments at Corbett, Dorisand Thunder in the Fort Assiniboine area of central Alberta. We begancommercial operations in the Upper Mannville coals in 2005, progressivelydeveloping opportunities on our land base. We are applying horizontal welltechnology to increase gas production rates and reduce de-watering time fromwater-saturated coal. Upper Mannville coals are generally deeper than theHorseshoe Canyon “dry coal” play, which is also being commercially developed inAlberta.

 

At the end of 2008, we heldmore than 725 net sections of land in Alberta with CBM potential, some of whichoverlay existing conventional producing lands. In 2009, we plan to tie-inexisting wells, drill additional wells, fund anticipated partner-initiateddevelopment and invest in new potential CBM plays in the Wetaskiwin and Camroseareas.

 

Shale Gas

 

As part of our growth strategyin unconventional Canadian resource plays, we have approximately 195 netsections of land in an emerging Devonian shale gas play in the Horn River Basinin northeastern British Columbia. Shale gas is natural gas produced fromreservoirs composed of organic shale. The gas is stored in pore spaces,fractures or absorbed into organic matter. Currently, the United States is thelargest producer of shale gas.

 

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This shale gas play has the potential tobecome a significant resource play in North America. It has been compared tothe Barnett Shale in Texas as it displays similar rock properties and playcharacteristics. To date, we have invested $340 million in land, infrastructureand wells in the Horn River Basin to progress our shale gas strategy towardpotential development and reserve recognition. Five horizontal and threevertical wells were drilled on our lands to evaluate the resource potential.Initial production test results are meeting expectations in terms of resource, initial production and decline profile. In 2009, we plan to continueour evaluation program, furthering our technical experience in the play and totest drilling and completion designs for potential commercial development.

 

We have approximately 88,000acres in the Dilly Creek area of the Horn River basin with a 100% workinginterest.

 

Limited infrastructure of gas pipeline and processing capacity in theHorn River Basin could potentially constrain early development of our lands. Toensure sufficient gathering, processing and transportation capacity for ourearly development programs, we have contracted gas pipeline capacity of 96mmcf/d during a five year term. We have entered into additional agreements thatwill allow us to participate in projects that are expanding infrastructure inthe region.

 

Fiscal Terms

 

In Canada, we pay two types ofroyalties to federal and provincial governments on production from lands wherethey own the petroleum and natural gas rights. The first type of royalty, NetProfits Interest (NPI), applies to our oil sands projects. The second type is agross royalty (Gross Royalty) system whereby we pay royalties ranging from 5%to 40% depending upon drilling date, production rate and product sales price.

 

During 2008, the Alberta government legislated a new royalty frameworkfor NPI and Gross Royalty structures effective January 1, 2009. The new NPIroyalty rates for oil sands projects will range from 1% to 9% of gross revenuefor projects that are pre-payout of costs, and from 25% to 40% of net profitfor projects that are post-payout. These royalty rates vary depending onCanadian dollar equivalent of WTI (CAD$55/bbl to CAD$120/bbl). The amended GrossRoyalty system increases the upper royalty rate limit to 50% and reduces thelower limit for conventional oil to nil, depending on production rates andsales price. Most of our conventional Alberta production qualifies for lowerproductivity rates and we expect royalties to range between 5% and 25%.

 

In addition to royalties, some provinces impose taxes on productionfrom lands where they do not own the mineral rights. The Saskatchewangovernment assesses a resource surcharge on gross Saskatchewan resource salesthat are subject to crown royalties, ranging from 1.7% to 3.0%. In Alberta, weare subject to a freehold mineral tax of approximately 4%.

 

Profits earned in Canada fromresource properties are subject to federal and provincial income taxes. In2007, the Federal government reduced the federal corporate income tax rate,ultimately to 15% by 2012. In 2008, federal taxable income is taxed at 19.5%.Provincial income tax rates vary from approximately 10% to 16%.

 

**Middle East — Yemen**

 

Yemen has been a significant international region for us since we firstbegan production at Masila in 1993. We operate the country’s largest oilproject and have developed strong relationships with the government and localcommunities.

 

Our strategy in Yemen is tomaximize the value from our existing blocks, prior to contract expiry. Weoperate from two producing blocks: Masila (Block 14) and East Al Hajr (Block51). In 2008, we produced 56,600 bbls/d of oil before royalties (30,600 afterroyalties), representing approximately 23% of Nexen’s total production. Provedreserves of 31 mmboe before royalties (20 after royalties) compriseapproximately 3% of Nexen’s total proved oil and gas and Syncrude reservesbefore royalties (2% after royalties).

 

 

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Masila Block (Block 14)

 

We operate the Masila Projectwith a 52% working interest. Our share of 2008 production was 45,900 bbls/dbefore royalties (24,400 after royalties). The Masila fields are mature, butsignificant value still remains. As a result of the Production SharingAgreement (PSA) terms that govern Masila production, we still expect togenerate approximately 15% of total project free cash flow before the PSAexpires in late 2011.

 

The first successful Masilaexploratory well was drilled at Sunah in 1990, with additional discoveriesquickly following at Heijah and Camaal. Initial production began in July 1993,with the first lifting of oil in August 1993. Masila Blend oil averages 32° APIat very low gas-oil ratios. Most of the oil is produced from the Upper Qishnformation, but we also produce from deeper formations including the LowerQishn, Upper Saar, Saar, Madbi, Basal Sand and Basement formations. Productionis collected at our Central Processing Facility (CPF) where water is separatedfor reinjection and oil is pumped to the Ash Shihr export terminal on theIndian Ocean and shipped to customers, primarily in Asia.

 

Under the Masila PSA, which wassigned between the Government of Yemen and the Masila joint venture partners(Masila Partners), we have the right to produce oil from Masila into 2011 andcan negotiate a five-year extension. Production is divided into cost recoveryoil and profit oil. Cost recovery oil provides for the recovery of allexploration, 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 four years  |       |
| Development |       | 16.7% per  year for six years |       |

 

The remaining production isprofit oil that is shared between the Masila Partners and the Government and iscalculated on a sliding scale based on production. The Masila Partners’ shareof profit oil ranges from 20% to 33%. The structure of the agreement moderatesthe impact on the Masila Partners’ cash flows during periods of low prices, aswe recover our costs first and then share any remaining profit oil with theGovernment. The Government’s share of profit oil includes a component for Yemenincome taxes payable by the Masila Partners at a rate of 35%. In 2008, theMasila Partners’ share of production, including recovery of past costs, wasapproximately 38%.

 

East Al Hajr Block (Block 51)

 

The first successfulexploratory well was drilled at BAK-A in 2003, with BAK-B discovered shortlyafter. Block 51 development began in 2004 and included a CPF, gathering systemand a 22 km tie-back to our Masila export pipeline. Production began inNovember 2004. During 2008, production averaged 10,700 bbls/d before royalties(6,200 after royalties).

 

We operate Block 51, which isalso governed by a PSA between the Government of Yemen and the East Al Hajrpartners (EAH Partners): The Yemen Company (TYCO) (12.5% carried workinginterest) and Nexen (87.5% working interest). Under the PSA, TYCO has noobligation to fund capital or operating expenditures and therefore, oureffective interest is 100% and for purposes of accounting and reservesrecognition, we treat TYCO’s 12.5% participating interest as a royaltyinterest. We recognize both the Government’s share and TYCO’s share of profitoil under the PSA as royalties and taxes consistent with our treatment of ourMasila operations. The PSA expires in 2023, and we have the right to negotiatea five-year extension. Under the PSA, the EAH Partners pay a royalty rangingfrom 3% to 10% to the Government depending on production volumes. The remainingproduction is divided into cost recovery oil and profit oil. Cost recovery oilprovides for the recovery of all of the project’s exploration, development andoperating costs, funded solely by Nexen. Costs are recovered from a maximum of50% of production each year after royalties, as follows:

 
| **Costs**   |   | **Recovery**                      | ** ** |
|-------------|--------|-----------------------------------|------------|
| Operating   |   | 100% in year  incurred            |       |
| Exploration |   | 75% in year  one, 25% in year two |       |
| Development |   | 75% in year  one, 25% in year two |       |

 

The remaining production isprofit oil that is shared between the EAH Partners and the Government on asliding scale based on production rates. The EAH Partners’ share of profit oilranges from 20% to 30%. The Government’s share of profit oil includes acomponent for Yemen income taxes payable by the EAH Partners at a rate of 35%.In 2008 the EAH Partners’ share of Block 51 production, including recovery ofpast costs, was approximately 47%.

 

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**OffshoreWest Africa**

 

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

 

Nigeria

 

In 1998, we acquired a 20%non-operated interest in Block OPL-222, which covers 448,000 acresapproximately 50 miles offshore in water depths ranging from 600 to 3,500 feet.In 1998, we discovered the Ukot field and encountered three oil-bearingintervals. This was followed up by a successful appraisal well in 2003. In2002, the Usan field was discovered and seven more successful wells confirmedthat significant hydrocarbons exist on the block. In 2008, we acquired a 18%non-operated interest in Block OPL-223, covering 230,000 acres, which providesus with future exploration potential on the adjacent block.

 

The Nigerian governmentapproved converting OPL-222 into two OMLs (Oil Mining Lease) that will allowthe joint venture partners to develop the Usan and Ukot discoveries. OML-138consists of 50% of the original acreage and includes the Usan discovery.OML-139 consists of the remaining OPL-222 acreage and includes the Ukotdiscovery.

 

Appraisal of the Usan field iscomplete and development of the field is progressing. Major contracts forconstruction of the FPSO and subsea facilities were awarded during 2008. Theproject will have the ability to process an average of 180,000 bbls/d of oilduring the initial production plateau period through a new FPSO with a twomillion barrel storage capacity. We expect our share of development andconstruction costs will be approximately US$2 billion with first production in2012. In 2009, we plan to progress with the Usan development program. This willinclude completing detailed engineering, procurement of remaining equipment,fabrication of the FPSO, and initiation of development drilling. At year-end2008, proved reserves of 28 mmboe before royalties (25 after royalties)comprise approximately 3% of our total proved oil and gas and Syncrudereserves.

 

 

**OtherInternational**

 

Colombia

 

In 2000, we made a discovery atGuando on our 20% non-operated Boqueron Block and production from Guando beganin 2001. Boqueron is in the Upper Magdalena Basin of central Colombia,approximately 45 km southwest of Bogota. Our working interest in Guando willdecrease to 10% once the field has produced 60 million barrels of oil, which isexpected to occur in mid 2009. Our share of 2008 production averaged 5,800bbls/d before royalties (5,300 after royalties), about 2% of Nexen’s totalproduction including Syncrude. We also hold three exploration blocks in theUpper Magdalena Basin that we are assessing for future growth opportunities.

 

Production from Guando issubject to a royalty between 5% and 25% depending on daily production, and in2008 averaged 8%. Colombian taxable income is subject to federal income tax of33% in 2009 and future years.

 

Norway

 

Norway is an extension of ourconventional offshore growth strategy in the North Sea. The Norwegian North Seais an established area that has significantly developed infrastructure andrelatively unexplored basins that provide the potential for future growth. TheNorwegian government created incentives for the oil and gas industry to exploreby providing 78% cash tax refunds on qualifying exploration expenditures tocompanies that do not have a taxable income base. We have ten offshore explorationlicences in the Norwegian North Sea with plans to drill our first explorationwell in the near future. In 2009, we expect to invest in seismic and geologicstudies.

 

Norwegian oil and gasactivities are subject to a general corporate income tax rate of 28% plus anadditional 50% special petroleum tax.

 

14

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**RESERVES,PRODUCTION AND RELATED INFORMATION**

 

In addition to the tablesbelow, we refer you to the Supplementary Data in Item 8 of this Form 10-K forinformation on our oil and gas producing activities. Nexen has not filed withnor included in reports to any other United States federal authority or agency,any estimates of total proved crude oil or natural gas reserves since thebeginning of the last fiscal year.

 

**Net Salesby Product from Oil and Gas Operations (including Syncrude)**

 
| **(Cdn$ millions)**                               | ** ** | **2008**  | ** ** | **2007**  | ** ** | **2006**  | ** ** |
|--------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Conventional Crude Oil and Natural Gas  Liquids (NGLs) |       | 5,534     |       | 4,077     |       | 2,479     |       |
| Synthetic Crude Oil                                    |       | 691       |       | 545       |       | 446       |       |
| Natural Gas                                            |       | 652       |       | 499       |       | 553       |       |
| **Total**                                              | ** ** | **6,877** | ** ** | **5,121** | ** ** | **3,478** | ** ** |

 

Crude oil (including syntheticcrude oil) and natural gas liquids represent approximately 90% of our oil andgas net sales, while natural gas represents the remaining 10%.

 

**SalesPrices and Production Costs (excluding Syncrude)**

 
| ** **                    | ** ** | **Average  Sales Price(1)** | ** ** | **Average  Production Cost(1)** | ** ** |
|-------------------------------|------------|-----------------------------|------------|---------------------------------|------------|
| ** **                    | ** ** | **2008**                    | ** ** | **2007**                        | ** ** | **2006** | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
| Crude Oil and NGLs (Cdn$/bbl) |       |                        |       |                            |       |   |   |   |   |   |   |   |   |
| United Kingdom                |       | 96.23                       |       | 76.30                           |       | 71.19 |   | 6.75 |   | 6.94 |   | 11.28 |   |
| Yemen                         |       | 99.87                       |       | 76.29                           |       | 71.57 |   | 15.88 |   | 12.00 |   | 8.11 |   |
| Canada                        |       | 74.51                       |       | 44.07                           |       | 42.79 |   | 22.16 |   | 18.67 |   | 15.50 |   |
| United States                 |       | 104.94                      |       | 69.83                           |       | 65.80 |   | 13.48 |   | 9.69 |   | 9.45 |   |
| Other Countries               |       | 98.98                       |       | 71.29                           |       | 66.09 |   | 4.91 |   | 3.76 |   | 3.13 |   |
| Natural Gas (Cdn$/mcf)        |       |                        |       |                            |       |   |   |   |   |   |   |   |   |
| United Kingdom                |       | 6.78                        |       | 4.71                            |       | 7.43 |   | 1.12 |   | 1.16 |   | 1.88 |   |
| Canada                        |       | 7.73                        |       | 6.32                            |       | 6.49 |   | 2.09 |   | 2.28 |   | 1.65 |   |
| United States                 |       | 10.07                       |       | 7.80                            |       | 7.86 |   | 2.25 |   | 1.61 |   | 1.58 |   |

 

----

*(1)  Salesprices and unit production costs are calculated using our working interestproduction after royalties.*

 

**Oil and GasAcreage**

** **
|                               |       | **Developed** |       | **Undeveloped(1)** |       | **Total** |       |
|------------------------------------|------------|---------------|------------|--------------------|------------|-----------|------------|
| **(thousands of acres)** |       | **Gross**     |       | **Net**            |       | **Gross** |       | **Net** |   | **Gross** |   | **Net** | ** ** |
| United Kingdom                     |       | 197           |       | 81                 |       | 1,107     |       | 752 |   | 1,304 |   | 833 |   |
| Yemen(2)                           |       | 50            |       | 29                 |       | 756       |       | 628 |   | 806 |   | 657 |   |
| Canada                             |       | 817           |       | 634                |       | 1,865     |       | 985 |   | 2,682 |   | 1,619 |   |
| United States                      |       | 215           |       | 125                |       | 1,260     |       | 630 |   | 1,475 |   | 755 |   |
| Colombia(4)                        |       | 1             |       | —             |       | 607       |       | 372 |   | 608 |   | 372 |   |
| Nigeria(2), (3)                    |       | —        |       | —             |       | 678       |       | 131 |   | 678 |   | 131 |   |
| Norway                             |       | —        |       | —             |       | 680       |       | 383 |   | 680 |   | 383 |   |
| **Total**                          | ** ** | **1,280**     | ** ** | **869**            | ** ** | **6,953** | ** ** | **3,881** | ** ** | **8,233** | ** ** | **4,750(** | **5)** |

 

----

| *(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.*                                     |

 

15

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**ProducingOil and Gas Wells**

 
| ** **                      | ** ** | **Oil**      | ** ** | **Gas**    | ** ** | **Total**    | ** ** |
|---------------------------------|------------|--------------|------------|------------|------------|--------------|------------|
| **(number of wells)** | ** ** | **Gross(1)** | ** ** | **Net(2)** | ** ** | **Gross(1)** | ** ** | **Net(2)** | ** ** | **Gross(1)** | ** ** | **Net(2)** | ** ** |
| United Kingdom                  |       | 50           |       | 22         |       | —       |       | — |   | 50 |   | 22 |   |
| Yemen                           |       | 540          |       | 327        |       | —       |       | — |   | 540 |   | 327 |   |
| Canada                          |       | 2,258        |       | 1,571      |       | 3,124        |       | 2,743 |   | 5,382 |   | 4,314 |   |
| United States                   |       | 183          |       | 94         |       | 202          |       | 142 |   | 385 |   | 236 |   |
| Colombia                        |       | 117          |       | 24         |       | —       |       | — |   | 117 |   | 24 |   |
| **Total**                       | ** ** | **3,148**    | ** ** | **2,038**  | ** ** | **3,326**    | ** ** | **2,885** | ** ** | **6,474** | ** ** | **4,923** | ** ** |

 

----

| *(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.*    |

 

**DrillingActivity**

 
| ** **                               | ** ** | **2008**                 | ** ** |
|------------------------------------------|------------|--------------------------|------------|
| ** **                               | ** ** | **Net Exploratory** | ** ** | **Net Development** | ** ** | ** ** | ** ** |
| **(number of net wells)** | ** ** | **Productive**           | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Productive** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Total** | ** ** |
| United Kingdom                           |       | 2.5                      |       | 2.0 |   | 4.5 |   | 3.3 |   | — |   | 3.3 |   | 7.8 |   |
| Yemen                                    |       | —                   |       | 1.0 |   | 1.0 |   | 17.4 |   | — |   | 17.4 |   | 18.4 |   |
| Canada                                   |       | 9.2                      |       | — |   | 9.2 |   | 216.4 |   | — |   | 216.4 |   | 225.6 |   |
| United States                            |       | 0.5                      |       | 1.0 |   | 1.5 |   | 1.3 |   | — |   | 1.3 |   | 2.8 |   |
| Colombia                                 |       | —                   |       | — |   | — |   | 1.6 |   | — |   | 1.6 |   | 1.6 |   |
| **Total**                                | ** ** | **12.2**                 | ** ** | **4.0** | ** ** | **16.2** | ** ** | **240.0** | ** ** | **—** | ** ** | **240.0** | ** ** | **256.2** | ** ** |

 
| ** **                               | ** ** | **2007**                 | ** ** |
|------------------------------------------|------------|--------------------------|------------|
| ** **                               | ** ** | **Net Exploratory** | ** ** | **Net Development** | ** ** | ** ** | ** ** |
| **(number of net wells)** | ** ** | **Productive**           | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Productive** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Total** | ** ** |
| United Kingdom                           |       | 2.0                      |       | 3.2 |   | 5.2 |   | 4.2 |   | — |   | 4.2 |   | 9.4 |   |
| 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 |   |
| 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** | ** ** |
| United Kingdom                           |       | 0.8                      |       | 1.7 |   | 2.5 |   | 5.5 |   | — |   | 5.5 |   | 8.0 |   |
| 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 |   |
| 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** | ** ** |

 

*Wells inProgress*

 

At December 31, 2008, we were drillingfour wells in Yemen (2.1 net), 16 wells in Canada (10 net), one well in theUnited States (0.4 net) and seven wells in the United Kingdom (4.5 net). Therewere no wells drilling in Colombia at December 31, 2008.

 

16

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**Proved Reserves including Proved Undeveloped Reserves**

 

AtDecember 31, 2008, we had 664 mmboe of proved oil and gas reserves beforeroyalties. This is a 10% decrease over the prior year. Including Syncrude, ourtotal proved oil and gas and Syncrude reserves decreased 7% to 988 mmboe. Thedecrease resulted as additions from our capital program and positive technicalrevisions of previous estimates did not offset production and negative economicrevisions from the decline in year end oil and gas prices. On an after royaltybasis, our proved oil and gas reserves decreased 3% to 631 mmboe and increased 1%to 926 mmboe when including Syncrude reserves. The changes on anafter-royalties basis reflects a reduction in royalties primarily at our oilsands projects where the royalties are sensitive to oil prices.

 

Thefollowing table provides a summary of the changes during 2008 in our proved oiland gas reserves (before royalties) excluding our Syncrude reserves. Refer topage 126 for proved reserves information on an after-royalties basis.

 
| **(mmboe)**                | ** ** | **Canada** | ** ** | **United  Kingdom** | ** ** | **United  States** | ** ** | **Yemen** | ** ** | **Other  Countries** | ** ** | **Total** | ** ** |
|----------------------------|------------|------------|------------|---------------------|------------|--------------------|------------|-----------|------------|----------------------|------------|-----------|------------|
| December 31, 2007     |       | 386        |       | 207                 |       | 62                 |       | 41        |       | 38                   |       | 734       |       |
| Extension and Discoveries  |       | 27         |       | 5                   |       | 1                  |       | 1         |       | —               |       | 34        |       |
| Revisions – Technical |       | 5          |       | 17                  |       | (1                 | )          | 11        |       | —               |       | 32        |       |
| Revisions – Economic  |       | (27        | )          | (16                 | )          | (5                 | )          | —    |       | (2                   | )          | (50       | )          |
| Acquisitions               |       | —     |       | —              |       | —             |       | —    |       | —               |       | —    |       |
| Divestments                |       | —     |       | —              |       | —             |       | —    |       | —               |       | —    |       |
| Production                 |       | (16        | )          | (38                 | )          | (8                 | )          | (22       | )          | (2                   | )          | (86       | )          |
| **December 31, 2008** | ** ** | **375**    | ** ** | **175**             | ** ** | **49**             | ** ** | **31**    | ** ** | **34**               | ** ** | **664**   | ** ** |

 

Excludingeconomic revisions, our net oil and gas reserve additions are 66 mmboe (60after royalties) and including Syncrude are 74 mmboe (67 after royalties).

 

Extensionsand discoveries of 34 mmboe (33 after royalties) are primarily from extendingour Long Lake Project by core hole delineation, development drilling atBuzzard, and ongoing development of coalbed methane in Canada. Other increasesrelate to ongoing exploitation activities in the North Sea, Yemen, the Gulf ofMexico and Canada. No proved reserves will be recognized for explorationdiscoveries at Golden Eagle, Pink or Blackbird in the UK until we advance ourunderstanding of these discoveries further and demonstrate a commitment todevelopment.

 

Positivetechnical revisions of 32 mmboe (27 after royalties) are primarily fromadditions at Buzzard, Yemen and Canadian coalbed methane where drilling resultsand production performance supported higher reserve estimates. Negativetechnical revisions of 13 mmboe relate primarily to Ettrick where ongoingdevelopment drilling and testing did not support previous estimates.

 

Negativeeconomic revisions of 50 mmboe (7 after royalties) are the result of lowercommodity prices (primarily oil) and rising costs at year-end. Under SECregulations, we are required to use year-end prices and costs to estimate ourreserves. About 85% of this revision is price related, of which half occurredin our Canadian heavy oil properties, while the remaining changes occurred atour Buzzard, Ettrick, Scott and Telford fields in the UK, and some of our USshelf properties. The majority of the remaining revisions resulted from higheryear end costs, primarily on our Canadian heavy oil properties.

 

Thefollowing provides a summary of the changes in our proved oil and gas reserves(before royalties) excluding Syncrude, for the past three years. Refer topage 126 for proved reserves information on an after-royalties basis forthe past three years.

 
| **(mmboe)**                | ** ** | **Canada** | ** ** | **United  Kingdom** | ** ** | **United  States** | ** ** | **Yemen** | ** ** | **Other  Countries** | ** ** | **Total** | ** ** |
|----------------------------|------------|------------|------------|---------------------|------------|--------------------|------------|-----------|------------|----------------------|------------|-----------|------------|
| December 31, 2005     |       | 117        |       | 145                 |       | 90                 |       | 105       |       | 11                   |       | 468       |       |
| Extension and Discoveries  |       | 45         |       | 40                  |       | 12                 |       | 7         |       | 30                   |       | 134       |       |
| Revisions – Technical |       | 27         |       | 78                  |       | (21                | )          | 4         |       | 1                    |       | 89        |       |
| Revisions – Economic  |       | 228        |       | (13                 | )          | (8                 | )          | —    |       | (2                   | )          | 205       |       |
| Acquisitions               |       | —     |       | 1                   |       | 11                 |       | —    |       | —               |       | 12        |       |
| Divestments                |       | —     |       | —              |       | (2                 | )          | —    |       | —               |       | (2        | )          |
| Production                 |       | (42        | )          | (76                 | )          | (33                | )          | (85       | )          | (6                   | )          | (242      | )          |
| **December 31, 2008** | ** ** | **375**    | ** ** | **175**             | ** ** | **49**             | ** ** | **31**    | ** ** | **34**               | ** ** | **664**   | ** ** |

 

17

----

 

Sincethe end of 2005, we added 440 mmboe (431 after royalties), sold 2 mmboe (2after royalties) and produced 242 mmboe (191 after royalties). Extensions anddiscoveries of 134 mmboe (122 after royalties) occurred primarily at our Usan,Ettrick and Buzzard fields, Long Lake Project, Canadian coalbed methane, andthe deep-water Gulf of Mexico. The net technical revisions of 89 mmboe (81after royalties) include 78 mmboe (78 after royalties) of positive revisions inthe UK primarily attributed to production performance at Buzzard and increasedexpected recoveries for our Long Lake Project based on analogous commercialSAGD projects. Negative technical revisions occurred primarily fromlower-than-expected production performance at our Aspen field and some Shelfproperties in the US Gulf of Mexico. Economic revisions of 205 mmboe (218 afterroyalties) are related to changes in year-end prices and costs. This includes apositive revision of 246 mmboe (245 after royalties) from reinstatement of LongLake bitumen reserves that we had removed due to low bitumen prices at the endof 2004. This was partially offset by negative revisions of 41 mmboe (27 afterroyalties) as a result of substantial decline in oil and gas prices atDecember 31, 2008 versus 2005 and a rising cost environment that has notyet corrected with the decline in commodity prices.

 

Proved Undeveloped Reserves

 

Thefollowing table provides a summary of the proved undeveloped reserves (PUDs)for our oil and gas activities at the end of the last two years:

 
| ** **                 | ** ** | **2008**                  | ** ** |
|----------------------------|------------|---------------------------|------------|
| ** **                 | ** ** | **Before Royalties** | ** ** | **After Royalties** | ** ** |
| **(mmboe)**                | ** ** | **PUDs**                  | ** ** | **Total Proved(1)** | ** ** | **% of Total** | ** ** | **PUDs** | ** ** | **Total Proved(1)** | ** ** | **% of Total** | ** ** |
| United Kingdom             |       | 40                        |       | 175 |   | 23 | % | 40 |   | 175 |   | 23 | % |
| Yemen                      |       | 3                         |       | 31 |   | 8 | % | 1 |   | 20 |   | 7 | % |
| Canada                     |       | 236                       |       | 375 |   | 63 | % | 234 |   | 362 |   | 65 | % |
| United States              |       | 11                        |       | 49 |   | 23 | % | 10 |   | 43 |   | 23 | % |
| Other Countries            |       | 28                        |       | 34 |   | 82 | % | 25 |   | 31 |   | 82 | % |
| **December 31, 2008** |       | 318                       |       | 664 |   | 48 | % | 310 |   | 631 |   | 49 | % |
| ** **                 | ** ** | ** **                | ** ** |
| ** **                 | ** ** | **2007**                  | ** ** |
| ** **                 | ** ** | **Before Royalties** | ** ** | **After Royalties** | ** ** |
| **(mmboe)**                | ** ** | **PUDs**                  | ** ** | **Total Proved(1)** | ** ** | **% of Total** | ** ** | **PUDs** | ** ** | **Total Proved(1)** | ** ** | **% of Total** | ** ** |
| United Kingdom             |       | 54                        |       | 207 |   | 26 | % | 54 |   | 207 |   | 26 | % |
| Yemen                      |       | 2                         |       | 41 |   | 5 | % | 1 |   | 23 |   | 4 | % |
| Canada                     |       | 236                       |       | 386 |   | 61 | % | 200 |   | 334 |   | 60 | % |
| United States              |       | 20                        |       | 62 |   | 32 | % | 17 |   | 53 |   | 32 | % |
| Other Countries            |       | 30                        |       | 38 |   | 79 | % | 25 |   | 33 |   | 76 | % |
| **December 31, 2007** | ** ** | **342**                   | ** ** | **734** | ** ** | **47** | **%** | **297** | ** ** | **650** | ** ** | **46** | **%** |

 

----

| *(1)* | *Excludes proved reserves for our  Syncrude operations of 324 mmboe (295 after royalties) in 2008 and 324 mmboe  (267 after royalties) in 2007.* |
|-------|--------------------------------------------------------------------------------------------------------------------------------------------------|

* *

In2008, our PUDs decreased by 24 mmboe (increased by 13 after royalties). Weconverted 29 mmboe (26 after royalties) with the start-up of our Long Lake SAGDoperations, the substantial completion of our Longhorn development project, andthe remainder relating to ongoing development of various other properties. Wehad negative revisions of 14 million boe (13 after royalties) primarily atEttrick, and we added 19 mmboe (51 after royalties) with the extension of theLong Lake reservoir. After-royalty changes reflect the impact of lowerprice-sensitive royalties for our Long Lake Project.

 

InCanada, our PUDs remained at 236 mmboe before royalties (increased 34 to 234after royalties). At Long Lake, PUDs increased by 4 mmboe (37 after royalties)due to a 19 mmboe (19 after royalties) addition from ongoing delineationdrilling, offset by a 15 mmboe reduction (18 increase after royalties) from conversionto proved with the ongoing start-up of SAGD wells. Other PUDs declined by 4mmboe (3 after royalties) due to conversions in our coalbed methane propertiesand revisions in our heavy oil properties. The remaining PUDs are substantiallyall from Long Lake where we have 232 mmboe (230 after royalties) which areexpected to be converted to developed over the next 20 years as we drilladditional wells to provide feedstock to run the upgrader at capacity. OtherPUDs relate to infill drilling, recompletions or facilities enhancements on ourvarious CBM, heavy oil and natural gas properties. The majority of these PUDsare expected to be converted to producing reserves in 2009 and 2010.

 

18

----

 

Inthe United Kingdom, our PUDs decreased from 54 mmboe (54 after royalties) to 40mmboe (40 after royalties). The decrease primarily reflects the reduction ofPUDs at Ettrick. About 75% of the PUDs at December 31, 2008 relate to Buzzardwhile the remainder relate to Ettrick. At Buzzard, we converted 5 mmboe of PUDsto producing and added 3 mmboe for increased recovery factors on remainingundrilled locations. The Buzzard PUDs are expected to be converted to producingover the next few years as we drill additional wells and develop increased H2Shandling facilities to keep the platform operating at capacity. We expect toconvert the majority of Ettrick PUDs to producing when production is initiatedin 2009.

 

Inthe United States, our PUDs decreased from 20 mmboe (17 after royalties) to 11mmboe (10 after royalties) largely relating to the completion of thedevelopment at Longhorn and conversion and revision of the remaining Gulf ofMexico shelf PUDs. Almost all of the remaining PUDs are located in the deepwater of the Gulf of Mexico and relate to suspended production from hurricanedamage in our Green Canyon blocks and Gunnison infill drilling. The majority ofthese PUDs are expected to be converted to producing reserves in 2009 and 2010.

 

Inother countries, PUDs relate primarily to our Usan development, offshore WestAfrica.

 

ExcludingLong Lake and Usan, we expect to convert over 90% of our PUDs to producing inthe next three years. Usan will be converted by 2012 when it is expected tocome on stream. Long Lake PUDs will be converted over the next 20 years as newwells are drilled to offset declines from the initial SAGD wells. At the sametime, we expect our ongoing exploration and development activities to continueto add new PUDs.

 

Duringthe past three years, our total PUDs before royalties increased from 180 mmboeto 318 mmboe (165 to 310 after royalties). As a result, our PUDs beforeroyalties as a percent of total proved reserves excluding Syncrude increasedfrom 38% to 48% (42% to 49% after royalties). During this time, we added 206mmboe (179 after royalties) at our Long Lake Project from the reinstatement ofproved reserves previously written off due to low year-end bitumen prices andanother 96 mmboe before royalties (119 after royalties), related to our activedevelopment projects at Long Lake, Usan, Ettrick, CBM and Longhorn. Weconverted 164 mmboe before royalties (153 after royalties) to developed withthe completion of development of our Buzzard, Farragon and Duart fields in theUnited Kingdom, Block 51 in Yemen, and ongoing development of work elsewhere.

 

Basis of Reserves Estimates

 

Reserveestimates in this report are internally prepared. Refer to the section onCritical Accounting Estimates — Oil and Gas Accounting — Reserves Determinationon page 70 for a description of our reserves process. As describedtherein, we have at least 80% of our oil and gas reserve estimates eitherevaluated or audited annually by independent qualified reserves consultants.The nature and scope of the independent evaluations and audits is determined byagreement between us and the engineering firm. Independent assessments forother companies may, therefore, be different.

 

Thefollowing provides an overview of the nature and scope of the independentevaluations and audits that we have performed. An independent evaluation is aprocess whereby we request a third-party engineering firm to prepare anestimate of our reserves by assessing and interpreting all available data on areservoir. An independent audit is a process whereby we request a third partyengineering firm to prepare an estimate of our reserves by reviewing ourestimates, supporting working papers and other data as they feel is necessary.The primary difference is that an auditor reviews our work and estimate inpreparing their estimate whereas an evaluator uses the reservoir data toprepare their estimate.

 

Ineach case, we request their estimate be prepared using standard geological andengineering methods generally accepted by the petroleum industry. Generallyaccepted methods for estimating reserves include volumetric calculations,material balance techniques, production and pressure decline curve analysis,analogy with similar reservoirs, and reservoir simulation. The method orcombination of methods used is based on their professional judgement andexperience. In preparing their estimates, they obtain information from us withrespect to property interests, production from such properties, current costsof operations, expected future development and abandonment costs, year endprices, agreements relating to current and future operations and sale ofproduction, 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 SECRule 4-10(a)(2) of Regulation S-X. 

 

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Theserules define proved reserves as the estimated quantities of oil and gaswhich geological and engineering data demonstrate with reasonable certainty tobe recoverable in future years from known reservoirs under existing economicand operating conditions.

 

Ourestimate may differ from the independent evaluators and auditors as they applytheir professional judgement and experience, which may result in applyingdifferent estimating methods or interpreting data differently than us. Webelieve our estimate for a portfolio of properties is reasonable when it is, inaggregate, within 10% of the estimate of the independent evaluator or auditor.

 

Weengaged DeGolyer and MacNaughton (D&M) to evaluate 100% of our reservesbefore royalties (100% after royalties) for the United Kingdom, Yemen Masila,Yemen Block 51 and Nigeria. A separate opinion was provided on each of thesefour areas. D&M provided an opinion on each of the areas that the provedreserves estimate prepared by us is, in aggregate, reasonable when compared totheir estimate which was prepared in accordance with current SEC Rules.

 

Weengaged McDaniel & Associates Consultants Ltd. (McDaniel) to evaluate99% of our Canadian conventional, CBM and bitumen reserves before royalties(99% after royalties) and to audit 100% of our Syncrude mining reserves beforeroyalties (100% after royalties). The properties were selected by managementand reviewed with the Reserves Review Committee of the Board. All materialproperties were selected. McDaniel provided their opinions that the provedreserves estimates prepared by us are, in aggregate, reasonable when comparedto their estimates which were prepared in accordance with current SEC Rules.

 

Weengaged Ryder Scott Company (Ryder Scott) to evaluate 92% of our US Gulf ofMexico shelf and deep water reserves before royalties (92% after royalties).The properties were selected by management and reviewed with the ReservesReview Committee of the Board. All material properties were selected. RyderScott provided an opinion that the difference between their estimate and oursis within the range of reasonable differences and that the estimates have beenprepared in accordance with current SEC Rules. In prior years, we engagedWilliam M. Cobb & Associates Inc. to evaluate our deep water reserves.The Reserves Review Committee of the Board was satisfied that the change inevaluator was not the result of a dispute with management.

 

**SYNCRUDEMINING OPERATIONS**

 

Wehold a 7.23% participating interest in Syncrude. This joint venture wasestablished in 1975 to mine shallow oil sands deposits using open-pit miningmethods, extract the bitumen and upgrade it to a high-quality, light (32° API),sweet, synthetic crude oil. Syncrude’s operating strategy is to develop thisresource, focusing on safe, reliable and profitable operations.

 

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) covering 248,300hectares, 40 km north of Fort McMurray in northeast Alberta. Syncrude mines oilsands at two mines: Mildred Lake North and Aurora North. These locations arereadily accessible by public road. Trucks and shovels are used to collect theoil 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 between 150 to160 million barrels of bitumen per year depending on the average bitumen oregrade. To extract bitumen, the oil sands are mixed with water to form a slurry.Air and chemicals are added to separate bitumen from the sand grains. Theprocess at the Mildred Lake North Mine uses hot water, steam and caustic sodato create a slurry, while at the Aurora North Mine, the oil sands are mixedwith warm water to produce a slurry. Most of the water used in operations isrecycled from the upgrader and mine sites. Incremental water is drawn from theAthabasca River in accordance with existing licenses.

 

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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 2008, about 40% of the synthetic crude oil was sold toEdmonton area refineries, and the remaining 60% was sold to refineries ineastern Canada and the mid-western United States. Electricity is provided toSyncrude from two generating plants on site: a 270 MW plant and an 80 MW plant.

 

Sinceoperations started in 1978, Syncrude has shipped more than 1.9 billion barrelsof synthetic crude oil to Edmonton by Alberta Oil Sands Pipeline Ltd. Thepipeline was expanded in 2004 to accommodate increased Syncrude production.

 

AtDecember 31, 2008, our total net book value of property, plant andequipment, including surface mining facilities, transportation equipment, andupgrading facilities, was approximately $1.1 billion. Based on developmentplans, our share of future expansion and equipment replacement costs over thenext 35 years is expected to be about $5.2 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 crudeoil capacity to 246,500 bbls/d with the development of the Aurora North Mine,which involved extending mining operations to a new location about 25 milesnorth of the main Syncrude site. The next expansion of Syncrude came on streamin 2006, increasing capacity to 360,000 bbls/d with the completion of the Stage3 project.

 

Syncrudepays a royalty to the Alberta government. As of January 2002, this royaltywas equal to the greater of 1% of gross revenue or 25% of net synthetic-basedprofit after deducting new capital expenditures. In connection with theprovincial government’s review of Alberta royalty rates in 2007, the Syncrudeowners entered into negotiations at the request of the government to revise theroyalty terms. Effective January 1, 2009, and consistent with the rest ofthe oil sands industry, Syncrude will begin paying royalties based on bitumenproduct, rather than paying royalties calculated on fully upgraded syntheticcrude oil. As a part of this conversion, the Alberta government will recaptureupgrader capital expenses of about $5 billion (gross) that were deductedagainst prior royalties payables. The $5 billion royalty deductions previouslyreceived by the Syncrude owners will be recaptured by the Alberta governmentover a 25 year period. In addition, the Province of Alberta and Syncrudereached agreement to establish new transitional royalty terms. Under the termsof the agreement, until December 31, 2015, Syncrude will continue to paybase royalty rates (being the greater of 25% of net bitumen-based revenues, or 1%of gross bitumen-based revenues) plus an incremental royalty of up to $975million (our 

 

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share$70.5 million). The incremental royalty is subject to certain minimum bitumenproduction thresholds and is to be paid in six annual payments, as indicated inthe following table:

 
| **(Cdn$ millions)** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** | **2013** | ** ** | **2014** | ** ** | **2015** | ** ** | **Total** | ** ** |
|--------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|-----------|------------|
| Gross                    |       | 75       |       | 75       |       | 100      |       | 150      |       | 225      |       | 350      |       | 975       |       |
| Nexen’s Share       |       | 5        |       | 5        |       | 7        |       | 11       |       | 17       |       | 25       |       | 70        |       |

 

Thisagreement is in lieu of the Syncrude owners converting to the Province’s newroyalty framework announced in October 2007, that is effectiveJanuary 1, 2009. After January 1, 2016, the rates under the newroyalty framework will apply to the Syncrude project.

 

In2008, Syncrude’s production of marketable synthetic crude oil was 289,100bbls/d. Nexen’s share was 20,900 bbls/d before royalties (18,200 afterroyalties). At year-end, Syncrude reserves of 324 mmboe before royalties (295after royalties) represented about 33% of our total proved oil and gas andSyncrude reserves.

 

Thefollowing table provides some operating statistics for Syncrude operations:

 
| ** **                                     | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| **Total Mined Volume (1)**                     |       |     |       |     |       |     |       |
| Millions of Tons                               |       | 531      |       | 470      |       | 428      |       |
| Mined Volume to Oil Sands Ratio (1)            |       | 2.5      |       | 2.1      |       | 2.2      |       |
| **Oil Sands Processed**                        |       |     |       |     |       |     |       |
| Millions of Tons                               |       | 216      |       | 220      |       | 192      |       |
| Average Bitumen Grade (weight %)               |       | 11.1     |       | 11.6     |       | 11.3     |       |
| **Bitumen in Mined Oil Sands**                 |       |     |       |     |       |     |       |
| Millions of Tons                               |       | 24       |       | 26       |       | 22       |       |
| Average Extraction Recovery (%)                |       | 90       |       | 92       |       | 90       |       |
| **Bitumen Production (2)**                     |       |     |       |     |       |     |       |
| Millions of Barrels                            |       | 122      |       | 133      |       | 112      |       |
| Average Upgrading Yield (%)                    |       | 86       |       | 84       |       | 85       |       |
| **Gross Synthetic Crude Oil Shipped (3)**      |       |     |       |     |       |     |       |
| Millions of Barrels                            |       | 105.8    |       | 111.3    |       | 94.3     |       |
| **Nexen’s Share of Marketable Crude Oil** |       |     |       |     |       |     |       |
| Millions of Barrels Before Royalties           |       | 7.7      |       | 8.1      |       | 6.8      |       |
| Millions of Barrels After Royalties            |       | 6.6      |       | 6.9      |       | 6.2      |       |

* *

----

| *(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% 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.* |
|        |                                         |                                                                                                                                                                                                        |  |  |

 

**ENERGYMARKETING**

 

Ourmarketing group sells proprietary and third-party natural gas, crude oil,natural gas liquids, and power in certain regional global markets. We havebuilt a solid strategic presence within various North American regional marketsand 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;

·                  providemarket intelligence in support of our oil and gas operations;

·                  providesuperior customer service to producers and consumers;

·                  capitalizeon market 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.

 

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**Marketing Office Locations**

 

 

**NorthAmerican Gas Marketing**

 

Themarketing and trading of North American natural gas has historically been ourmarketing group’s largest revenue source. We focus on key regional marketswhere we have a strategic presence, equity production, solid customerrelationships, in-depth understanding of the market or established physicalassets. We capture regional opportunities by managing supply, transportationand storage assets for producers and end users. In addition to thefee-for-service income we realize from managing these assets, we generatefurther revenue by:

 

·                  capitalizingon location spreads (differences in prices between locations) using ourtransportation assets;

·                  offeringcustomized service to our customers that bundle our assets with the commodity;

·                  utilizingour storage assets where we optimize forward and seasonal pricing differences;and

·                  leveragingregional knowledge we gain through optimizing our assets.

 

Wehave offices in key regions including Calgary, Detroit, Denver and Houston. Ouroffices provide a variety of services, including supply, storage, andtransportation management as well as netback pool arrangements and othercustomer services. Our customers include producers and consumers (includingutilities) in western Canada, eastern Canada, the northeastern US, the USmid-continent, the Pacific northwest and the US Rockies. We use our access totransportation and storage facilities to optimize returns for ourselves as wellas our customers.

 

Overthe years, we focused on growing our asset base by acquiring physical gaspurchase and sales contracts, as well as natural gas transportation and storagecapacity, on favourable terms. The growth in our underlying physical businesswas supplemented by an expanding profitable financial trading business with afocus on time and location spreads. In 2008, financial trading provedparticularly challenging causing us to reassess the merits of this activity.While we expect to continue to focus on our core physical business, we arereducing our financial trading levels and exposures in an orderly fashion.

 

Ourposition as a physical marketer at multiple delivery points in key marketsgives us flexibility to capitalize on time and location spreads. With pipelinecapacity, we can move gas from producing to consuming regions to take advantageof price differences. At the end of 2008, we held 1.8 bcf/d of pipelinecapacity, primarily between western Canada and the eastern US. We also usestorage capacity to store normally cheaper summer gas in the ground until thewinter heating season arrives. We had access to 38 bcf of natural gas storagefacilities at the end of the year.

 

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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 by our product group teamsand monitored by our risk group, with regular reporting to Management and theboard of directors.

 

**NorthAmerican Crude 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. The Chicago and Denverareas have been key markets for our western Canadian crude, however, wecontinue to expand our presence into the US Gulf Coast. Our deep-water Gulf ofMexico crude oil production expanded our presence in that market through ourHouston office. At the end of 2008, we had access to 2.6 mmbbls of storage andover the course of the year, marketed approximately 656 mbbls per day.

 

Ouroperations also include a North American natural gas liquids (NGLs) businessthat focuses on buying and selling NGLs. This business acquires and movesproduct within North America. At the end of 2008, we had access to 1.2 mmbblsof NGL storage and over the course of the year, moved approximately 26 mbblsper day of product. In 2008, we were active in the ethanol markets in NorthAmerica but we expect to turn our focus to more traditional NGL markets in2009.

 

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 the surplus power from the 170 MW cogenerationfacility at Long Lake (Nexen 65% interest) that commenced operation in 2008. Wemarket power to larger commercial, industrial and municipal clients in Alberta.We are currently the largest supplier of power to commercial and industrialsectors in the province. Our Balzac facility began operations in 2001 andSoderglen in October 2006.

 

**Europe**

 

OurEuropean operations include a UK-based European gas and power marketingbusiness. Our trading strategies include capitalizing on time and locationspreads involving the UK and European gas and power markets, using primarilyfinancial contracts. We are increasing our presence in both the UK andcontinental Europe physical gas markets. During the year, we secured access totransportation and storage capacity in the UK and Europe. At the end of 2008,we had access to 0.1 bcf/d transportation capacity and 3.7 bcf of storagecapacity. Our European marketing operations also physically market our Buzzardcrude oil production.

 

**Asia**

 

Ourinternational team in Asia continues to focus on the physical marketing ofMasila crude oil. In order to meet customer needs, we occasionally market otherregional crude qualities. In addition to our own crude, we sell production forour 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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**CHEMICALS**

 

In 2005, we monetized part of our chemicals business through an initialpublic offering of the Canexus Income Fund. We currently hold a 63.5% interestin our chemicals business, and continue to fully consolidate chemicals in ourConsolidated Financial Statements.

 

Our chemicals business manufactures sodium chlorate and chlor-alkaliproducts (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 system is reliable, low-cost andstrategically located to capitalize on competitive electricity costs andtransportation infrastructure to minimize production and delivery costs.

 

Electricity is the most significant operating cost in producing sodiumchlorate and chlor-alkali products, making up over half our cash costs.Therefore, our current facilities are strategically located to take advantageof economic power sources. Our second highest cost is transportation. Theproximity of our manufacturing plants to major customers and competitivefreight rates minimize our transportation costs. Labour is also a significantmanufacturing cost. Approximately 50% of our workforce is unionized withcollective agreements in place at all of our unionized plants.

 

To grow value in our chemicals business, we focus on reducing our costswhile maintaining market share, building a sustainable North American customerbase and capturing new offshore opportunities. In 2009, we will fund ourcurrent capital projects from undistributed cash, dividend reinvestment andexisting credit facilities (which were renewed in 2008).

 

**North America**

 

The North American pulp and paper industry consumes approximately 93%of the continent’s sodium chlorate production. We market our sodium chlorateproduction to numerous pulp and paper mills under multi-year contracts thatcontain price and volume adjustment provisions. Approximately 27% of thisproduction is sold in Canada, 66% in the US, and the rest is marketed offshore.

 

 

We are the third-largest manufacturer of sodium chlorate in NorthAmerica with four Canadian facilities: Nanaimo, British Columbia; Bruderheim,Alberta; Brandon, Manitoba; and Beauharnois, Quebec.

 

In 2008, we completed an expansion of our Brandon plant, increasingcapacity to over 290,000 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.

 

Our chlor-alkali facility at North Vancouver, British Columbia,manufactures caustic soda, chlorine and muriatic acid. Almost all of ourcaustic soda is consumed by local pulp and paper mills, while our chlorine issold to various customers in the polyvinyl, chloride, water purification andpetrochemicals industries, primarily in the United States. A technologyconversion project currently underway will replace existing diaphragmtechnology and assets with newer, proven membrane technology that is expectedto be more cost effective and will expand productive capacity by 35%. Thisproject is progressing on time and on budget with committed financing in placethrough to August 2011. The project is expected to start-up in the firstquarter of 2010 and should lower our cost structure and solidify our low-costposition in this regional market.

 

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**Average Annual Production Capacity**

 
| **(short tons)** | ** ** | **2008**    | ** ** | **2007**    | ** ** | **2006**    | ** ** |
|-----------------------|------------|-------------|------------|-------------|------------|-------------|------------|
| **Sodium  Chlorate**  |       |        |       |        |       |        |       |
| North America         |       | 484,800     |       | 450,055     |       | 446,208     |       |
| Brazil                |       | 68,563      |       | 68,563      |       | 68,563      |       |
| **Total**             | ** ** | **553,363** | ** ** | **518,618** | ** ** | **514,771** | ** ** |
| **Chlor-alkali**      |       |        |       |        |       |        |       |
| North America         |       | 364,500     |       | 364,500     |       | 356,002     |       |
| Brazil                |       | 109,430     |       | 109,430     |       | 109,430     |       |
| **Total**             | ** ** | **473,930** | ** ** | **473,930** | ** ** | **465,432** | ** ** |

 

**Brazil**

 

We entered Brazil in 1999 by acquiring a sodium chlorate plant and achlor-alkali plant from Aracruz Cellulose S.A. (Aracruz), the leadingmanufacturer of pulp in Brazil. The majority of the sodium chlorate productionis sold to Aracruz under a long-term sales agreement that expires in 2024. Mostof the chlorine and about 8% of the sodium chlorate production is sold in themerchant market under short-term contracts. In 2002, we completed an expansionat both facilities to meet Aracruz’s growing needs. A 2,000 tonne incrementalsodium chlorate expansion project is currently in progress at our Brazil plantand is scheduled for start up in early 2009. A further 4,400 tonne expansionwas recently approved, which is estimated to start up in early 2010. Themajority of our electricity needs in Brazil are supplied by a long-term supplycontract, which expires in February 2013.

 

**GOVERNMENT REGULATIONS**

 

Our operations are subject to various levels of government controls andregulations in the countries where we operate. These laws and regulationsinclude matters relating to land tenure, drilling, production practices,environmental protection, marketing and pricing policies, royalties, varioustaxes and levies including income tax, and foreign trade and investment, thatare subject to change from time to time. Current legislation is generally amatter of public record, and we are unable to predict what additionallegislation or amendments may be proposed that will affect our operations orwhen any such proposals, if enacted, might become effective. We participate inmany industry and professional associations and monitor the progress ofproposed legislation and regulatory amendments.

 

**ENVIRONMENTAL REGULATIONS**

 

Our oil and gas, Syncrude and chemical operations are subject togovernment laws and regulations designed to protect and regulate the dischargeof materials into the environment in countries where we operate. We believe ouroperations comply, in all material respects, with applicable environmentallaws. To reduce our exposure, we apply industry standards, codes and bestpractices to meet or exceed these laws and regulations. We may conductactivities in countries where environmental regulatory frameworks are invarious stages of evolution. Where regulations are lacking, we observe Canadianstandards where applicable, as well as internationally accepted industryenvironmental management practices.

 

We have an active Health, Safety, Environment and Social Responsibilitygroup (HSE&SR) that ensures our worldwide operations are conducted in asafe, ethical and socially responsible manner. Our HSE&SR practices arereported to our Board of Directors throughout the year. Our overall HSE&SRprogram is guided by the following 12 element management system:

 

·             Leadership and commitment;

 

·             Regulatory compliance;

 

·             Safety and occupational health management;

 

·             Social responsibility;

 

·             Environmental management;

 

·             Supply chain management;

 

·             Documentation and procedure management;

 

·             Training and awareness;

 

·             Process safety management;

 

·             Emergency preparedness;

 

·             Event reporting, investigation and follow-up;and

 

·             Continuous improvement.

 

Our performance against this system is reviewed by an external auditorevery three years and we have been recognized by the Dow Jones SustainabilityIndex as a global sustainability leader for eight years in a row. Our progressis publicly reported in our sustainability report which is available on ourwebsite at www.nexeninc.com.

 

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**Climate Change and Environmental Responsibilities**

 

A growing awareness of possible causes and effects of climate changealong with volatile consumer prices have increased concern over the manner bywhich the world produces and consumes energy. Government and investorexpectations continue to converge on sustainable resource development andresponsible operating practices, including the preservation of air, water andland. Some jurisdictions in which we operate have already formalized theseexpectations into regulation while others move closer to doing so. Regardlessof how the jurisdictions in which we operate ultimately define their emissionsregulation, we expect that our regulatory obligations and the associated costof compliance will increase. Due to the uncertainty surrounding the futureimplementation of emissions regulations, we are unable to estimate our costs ofcompliance.

 

As a result of our commitment to sustainable development andresponsible operating practices, we believe we are well positioned to meet thechallenges of climate change and environmental regulation. We have built acorporate culture of integrity and respect for the communities and environmentsin which we operate, and have developed policies and practices for continuingcompliance with all environmental laws and regulations.

 

Air

 

To meet our current greenhouse gas (GHG) emissions obligations, weadhere to a five point emissions management strategy:

 

·      reduce emissions by decreasing vent gas andimproving energy efficiency;

 

·      self-generate carbon credits from wind power;

 

·      acquire carbon credits through qualifiedoffshore projects, such as the Greenhouse Gas Credit Aggregation Pool (GGCAP);

 

·      participate in eligible international anddomestic offset projects such as methane capture from landfills; and

 

·      purchase carbon credits on the spot market.

 

Water

 

We are developing a company-wide water management strategy to limitwater use. An external consulting firm compiled information on water issuesrelevant to Nexen’s projects and operations, reviewed key business driversrelated to water, and surveyed Nexen’s business units with respect to theirwater policies and practices. Benchmarking of oil and other industry relatedwater policies, strategies and programs was also completed. This informationwas used as the starting point for our HSE&SR group to begin the process ofdeveloping corporate water management principles that are aligned with ourstated objective to “grow value responsibly”.

 

Land

 

Our land use practices are based upon principles of minimal disturbanceand a commitment to return land to its natural state after responsiblyproducing oil and gas resources. We also recognize our ability to effectivelyaccess land is directly linked to the way in which we manage potentialenvironmental effects and in how we cooperate with other industries to reduceour cumulative impact.

 

For many stakeholders, a company’s ability to meet environmentalexpectations is a significant criteria upon which their decision to invest or conductbusiness is based. A failure to meet those expectations can limit access toexploration, development and partnership opportunities. We therefore believethat superior environmental and social responsibility performance is directlylinked to economic performance.

 

We have outlined and more fully discussed our environmental practicesand policies in our sustainability report, available on our website atwww.nexeninc.com.

 

**Environmental Provisions and Expenditures**

 

Meeting the challenges of climate change and environmental regulationand our commitment to sustainable resource development increases the cost ofour operations. The ultimate financial impact of our sustainability practicesand compliance with environmental laws and regulations is not clearly known andcannot be reasonably estimated as new standards continue to evolve in thecountries in which we operate. We estimate our future environmental costs basedon past experience and current regulations. At December 31, 2008, $1,059million ($2,393 million, undiscounted, adjusted for inflation) has beenprovided in our Consolidated Financial Statements for asset retirementobligations. In 2008, we increased our retirement obligations for futuredismantlement and site restoration by over $200 million primarily from ongoingdevelopment of the Long Lake Project in the Athabasca oil sands, our CBM wellsin

 

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Canada and from industry cost pressures in the North Sea and the USGulf of Mexico.

 

In 2008, our expenditures for environmental-related matters, includingenvironment control facilities, were approximately $55 million. In 2009, weestimate these expenditures to range between $35 and $50 million.

 

**EMPLOYEES**

 

We had 4,254 employees on December 31, 2008, of which 309 wereemployed under collective bargaining schemes. Information on our executiveofficers is presented in Item 10 of this report.

 

ITEM 1A.

 

Risk Factors

 

**RISK FACTORS**

 

Our operations are exposed to various risks, some of which are commonto others in the oil and gas industry and some of which are unique to ouroperations. Certain risks set out below constitute “forward-looking statements”and the reader should refer to the “Special Note Regarding Forward LookingStatements” set out on page 78 of this 10-K.

 

**Our profitability and liquidity is highly dependant onthe price of crude oil and natural gas.**

 

Our operations and performance depend significantly on the price ofcrude oil and natural gas. Crude oil and natural gas are commodities which are sensitiveto numerous worldwide factors, many of which are beyond our control, and aregenerally sold at contract or posted prices. Historically, these prices havebeen very volatile, and are likely to remain volatile in the future. Currentworldwide economic conditions have depressed crude oil and natural gas pricessignificantly, which may materially and adversely affect our results ofoperations and revenue generated from operating activities should those pricelevels persist for an extended period of time. The current price environmenthas also affected the value of our oil and gas properties and our level ofspending for oil and gas exploration and development. 

 

Our crude oil prices are based on various reference 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 andgeopolitical events.

 

**The continued and unprecedented disruptions in thecredit markets may negatively impact our liquidity.**

 

While we generally rely upon cash flow from operations to fund ouractivities, a sustained depression in the prices of crude oil and natural gasmay require us to draw upon existing credit facilities or issue new debt orequity to satisfy our funding needs. The current financial turmoil affectingthe banking system and financial markets, and the possibility that financialinstitutions may consolidate or go out of business has resulted in a tighteningof the credit markets, a low level of liquidity in many financial markets, and extremevolatility in fixed income, credit, currency and equity markets. There could bea number of follow-on effects from the credit crisis on our business whichcould negatively impact our liquidity and operations, and which may materiallyaffect our business, including: a reduced ability to access credit or issue newpublic or private debt; higher costs of borrowing; lower returns on investedcash; and a negative change to our ratings outlook or even a reduction in ourcredit ratings by one or more credit rating agencies. A downgrade could limitour access to private and public credit markets and increase the costs ofborrowing under existing facilities that could be available. If our creditratings were downgraded, we could be required to provide additional liquidityto our marketing division if further collateral is required to be placed withcounterparties, or reduce some of our marketing activities.

 

**The inability of counterparties and joint operatingpartners to fulfill their obligations to us could adversely impact our resultsof operations.**

 

Credit risk affects both our trading and non-trading activities andthere is the risk of loss and additional burden if counterparties and jointventure partners do not or can not fulfill their contractual obligations. Inparticular in 2008, the credit crisis that impacted world financial marketscaused some of our counterparties to restructure, declare bankruptcy or sellassets to fund liquidity requirements. In 2009 we may experience similardevelopments. Most of our receivables and partners are with counterparties inthe energy industry and are subject to normal industry credit risk.

 

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The inability of any one or more of these parties to fulfill theirobligations to us may adversely impact our results of operations.

 

**Competitive forces may limit our access to naturalresources, and create labour and equipment shortages.**

 

The oil and gas industry is highly competitive, particularly in thefollowing areas:

 

·      gaining access to areas or countries known tohave available resources;

 

·      searching for and developing new sources ofcrude oil and natural gas reserves;

 

·      constructing and operating crude oil andnatural gas pipelines and facilities; and

 

·      transporting and marketing crude oil, naturalgas and other petroleum products.

 

Our competitors include national oil companies, major integrated oiland gas companies and various other independent oil and gas companies. Thepetroleum industry also competes with other industries in supplying energy,fuel and related products to customers. The pulp and paper chemicals market isalso highly competitive. Key success factors in each of these markets areprice, product quality, logistics and reliability of supply.

 

Competitive forces may result in shortages of prospects to drill,labour, drilling rigs and other equipment to carry out exploration, developmentor operating activities, and shortages of infrastructure to produce andtransport production. It may also result in an oversupply of crude oil andnatural gas. Each of these factors could negatively impact our costs and pricesand, therefore, our financial results.

 

**We operate in harsh and unpredictable climates andlocations where our access is regulated which could adversely impact ouroperations.**

 

Some of our facilities are located in harsh and unpredictable climatesand locations which can experience extreme weather conditions and naturaldisasters such as: sustained ambient temperatures above 40°C or below -35°C,flooding, droughts, wind and dust storms, difficult terrain, high seas,monsoons and hurricanes. These conditions are difficult to anticipate andcannot be controlled. In these conditions, operations can become difficult orunsafe and are often suspended. Some of our facilities and those upon which ourfacilities rely (such as pipelines, power, communications and oilfieldequipment) are vulnerable to these types of extreme weather conditions and maysuffer extensive damage as a result. If any such extreme weather were to occur,our ability to operate certain facilities and proceed with exploration ordevelopment programs could be seriously or completely impaired or destroyed,and could have a material adverse effect on our business, financial conditionand results of operations. The insurance we maintain may not be adequate tocover our losses resulting from disasters or other business interruptions.

 

In some areas of the world, access and operations can only be conductedduring limited times of the year due to weather or government regulation. Theseadverse conditions can limit our ability to operate in those areas and canintensify competition during periods of good weather for oil field equipment,services, and qualified personnel, which may lead to periodic shortages. Theseconstraints and the resulting shortages or high costs could delay ouroperations and materially increase our operating and capital costs, and couldhave a material adverse effect on our business, financial condition and resultsof operations.

 

**Exploration, development and production activities maynot be successful and carry a risk of loss.**

 

Acquiring, developing and exploring for oil and natural gas involvesmany risks. There is a risk that we will not encounter commercially productiveoil or gas reservoirs, and that wells we drill may not be productive, or notsufficiently productive to recover all or any portion of our investment inthose wells. Seismic data and other exploration technologies we use do notprovide conclusive proof prior to drilling a well that crude oil or natural gasis present or may be produced economically. The costs of drilling, completingand operating wells are often uncertain, and drilling operations may becurtailed, delayed or canceled as a result of a variety of factors, including:

 

·             encountering unexpected formations orpressures;

 

·             blow-outs, well bore collapse, equipmentfailures and other accidents;

 

·             craterings and sour gas releases;

 

·             accidents and equipment failures;

 

·             uncontrollable flows of oil, natural gas orwell fluids; and

 

·             environmental risks.

 

We may not achieve production targets should our reservoir productiondecline sooner than expected. Also we operate two facilities that are locatedin close proximity to populated areas, and each processes materials ofpotential harm to the local populations. We may not be fully insured againstall of these risks. Losses resulting from the occurrence of these risks maymaterially impact our operational activities and financial results.

 

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**Unconventional gas resource plays carry additional risksand uncertainties.**

 

Part of Nexen’s growth strategy is unconventional Canadian gas resourceplays, such as CBM and shale gas. Exploitation techniques and practices forthese resources in Canada generally remain in the early stages of developmentand it is very difficult to determine whether or not these resource plays willprove commercially viable, or to what degree.

 

CBM is commonly referred to as an unconventional form of natural gasbecause it is primarily stored through adsorption by the coal itself ratherthan in the pore space of the rock like most conventional gas. The gas isreleased in response to a drop in pressure in the coal. Some of theuncertainties associated with development 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. Negative public perception around water saturated CBM productioncould 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.

 

Shale gas is an unconventional gas produced from reservoirs composed oforganic rich shales. The gas is stored in pore spaces, fractures or adsorbedinto organic matter. Some of the uncertainties associated with development ofshale gas resources 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.

 

**Our heavy oil production is more expensive and yieldslower prices than light oil and gas.**

 

Heavy oil is characterized by high specific gravity or weight and highviscosity or resistance to flow. Because of these features, heavy oil is moredifficult and expensive to extract, transport and refine than other types ofoil. Heavy oil also yields a lower price relative to light oil and gas, as asmaller percentage of high-value petroleum products can be refined from heavyoil. As a result, our heavy oil operations are exposed to the following risks:

 

·             additional costs may be incurred to purchasediluent to transport heavy oil;

 

·             there could be a shortfall in the supply ofdiluent which may cause its price to increase; and

 

·             the market for heavy oil is more limited thanfor light oil making it more susceptible to supply and demand fundamentalswhich may cause the price to decline.

 

Any one or a combination of these factors could cause some of our heavyoil properties to become uneconomic to produce and/or result in negativereserve revisions.

 

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**Without reserve additions, our reserves and productionwill decline over time and we require capital to produce remaining reserves.**

 

Our future crude oil and natural gas reserves and production, andtherefore our future operating cash flows and results of operations, are highlydependent upon our success in exploiting our current reserve base and acquiringor discovering additional reserves. Without reserve additions throughexploration, development or acquisitions, our reserves and production willdecline over time as reserves are produced. The business of exploring for,developing or acquiring reserves is capital intensive. To the extent cash flowsfrom operations are insufficient and external sources of capital become limitedor unavailable, our ability to make the necessary capital investments tomaintain and expand our oil and natural gas reserves and production will beimpaired.

 

Discovered oil and natural gas reserves are generally only producedwhen they are economically recoverable. As such, oil and gas prices, andcapital and operating costs have an impact on whether reserves will ultimatelybe produced. As required by SEC rules, our proved reserves represent thequantities that we expect to economically recover using existing prices andcosts at the end of the year. Proved reserves can increase or decrease underdifferent price and cost scenarios. Our bitumen reserves are particularlysensitive to year end prices and costs. Under current SEC rules, we arerequired to recognize our oil sands as bitumen reserves rather than theupgraded premium synthetic crude oil that we produce from the Long LakeProject. We expect price-related revisions, both positive and negative, tooccur in the future as the economic producibility of our bitumen reserves aresensitive to year-end prices. We recognize our oil sands as bitumen reservesand they 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.

 

**Our proved reserves include undeveloped propertiesthat require additional capital to bring them on stream.**

 

Under SEC rules, the definition of proved undeveloped reserves includesreserves that are expected to be recovered from new wells on undrilled acreageor from existing wells where a relatively major expenditure is still requiredbefore such wells begin production. 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, 2008, 48% of our proved reservesbefore royalties (49% after royalties) were undeveloped. Refer to page 18for information on our PUDs.

 

**The Long Lake Project faces additional risks comparedto conventional oil and gas production.**

 

The Long Lake Project is a fully integrated production, upgrading andcogeneration facility. We use steam assisted gravity drainage (SAGD) technologyto recover bitumen from oil sands. The bitumen is partially upgraded using theproprietary OrCrudeTM process, followed by conventional hydrocracking to producea sweet, premium synthetic crude oil. The OrCrudeTM process also yields liquidasphaltenes that will be gasified into synthetic gas. This syngas is used asfuel for the SAGD process, a source of hydrogen in the upgrading process, andto generate electricity through a cogeneration facility.

 

We have a 65% working interest in this project. Given the initialinvestment and operating costs to produce and upgrade bitumen, the payoutperiod for the project is longer and the economic return is lower than aconventional light oil project with an equal volume of reserves.

 

In addition to the risks associated with heavy oil production statedabove, risks associated with our Long Lake Project include the following:

 

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Application of Relatively New SAGD Bitumen Recovery Process

 

SAGD has been used in western Canada to increase recoveries fromconventional heavy oil reservoirs for over a decade; however, application ofSAGD to the insitu recovery of bitumen from oil sands is relatively new. Someof the SAGD oil sands applications to date have been pilot projects, althoughseveral commercial SAGD projects have been in steady state operation for oversix years.

 

Our estimates for performance and recoverable volumes for the Long LakeProject are based primarily on our three well-pair SAGD pilot, the initialperformance of our first commercial well phase, 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. While some of our wells have achieved these levels, there can be nocertainty that our overall SAGD operation will produce bitumen at the expectedlevels or steam-to-oil ratio. If the assumed production rates or steam-to-oilratio are not achieved, we might have to drill additional wells to maintainoptimal production levels, construct additional steam generating capacity, purchasenatural gas for additional steam generation, and/or make short-term bitumenpurchases. These could have an adverse impact on the future activities andeconomic return of the Long Lake Project.

 

Application of New Bitumen Upgrading Process

 

The proprietary OrCrudeTM process we are using to upgrade raw bitumen tosynthetic crude is the first commercial application of the process although wehave operated it in a 500 bbl/d demonstration plant and initial upgraderoperations which began in January 2009 have produced the desired products.There can be no certainty that the commercial upgrader at Long Lake willsustain or achieve the results which are now being seen or forecast. If we areunable to continue to upgrade the bitumen for any reason we may decide to sellit as bitumen without upgrading, which would expose us to the following risks:

 

·             the market for bitumen is limited;

 

·             additional costs would be incurred topurchase diluent for blending and transporting bitumen;

 

·             there could be a shortfall in the supply ofdiluent which may cause its price to increase;

 

·             the market price for bitumen is relativelylow reflecting its quality differential;

 

·             the market price for bitumen fluctuates overthe course of the year; and

 

·             additional costs would be incurred topurchase natural gas for use in generating steam for the SAGD process since wewould not be producing syngas from the upgrading process.

 

These factors could have a significant adverse impact on the futureactivities and economic returns of the Long Lake Project.

 

If any of these factors arise, our operating costs would increase and ourrevenues would decrease from those we have assumed. This would materiallydecrease expected earnings from the project and the project may not beprofitable under these conditions.

 

Dependence upon Proprietary Technology

 

The success of the project and our investment depends highly on theproprietary technology of OPTI and proprietary technology of third parties thathas been, or is required to be, licensed by OPTI. OPTI currently relies onintellectual property rights and other contractual or proprietary rights,including (without limitation) copyright, trademark laws, trade secrets,confidentiality procedures, contractual provisions, licenses and patents, tosecure the rights to utilize its proprietary technology and the proprietarytechnology of third parties. OPTI may have to engage in litigation to protectthe validity of its patents or other intellectual property rights, or todetermine the validity or scope of patents or proprietary rights of thirdparties. Litigation can be time-consuming and expensive, whether OPTI issuccessful or not. The process of seeking patent protection can itself be longand expensive, with no assurance that any pending or future patent applicationsof OPTI or such third parties will actually result in issued patents, or that,if patents are issued, they will be of sufficient scope or strength to providemeaningful protection or any commercial advantage to OPTI. 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.

 

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Operational Hazards

 

The operation of the project is 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.

 

Recovering bitumen from oil sands and upgrading the recovered bitumeninto synthetic crude oil and other products involve particular risks anduncertainties. The project is susceptible to loss of production, slowdowns orrestrictions on its ability to produce higher-value products due to theinterdependence of its component systems. Severe climatic conditions can causereduced production and in some situations result in higher costs. SAGD bitumenrecovery facilities and development and expansion of production can entailsignificant capital outlays. The costs associated with synthetic crude oilproduction are largely fixed and, as a result, operating costs per unit dependlargely on production levels.

 

The Long Lake Project processes large volumes of hydrocarbons at highpressure and 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.

 

Certain components of the Long Lake Project produce sour gas, which isgas containing hydrogen sulphide. Sour gas is a colourless, corrosive gas thatis toxic at relatively low levels to plants and animals, including humans. Theproject includes integrated facilities for handling and treating the sour gas,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.

 

The Long Lake Project produces carbon dioxide emissions. Risk factorsrelating to environmental regulation are provided separately in this document.

 

Aboriginal Claims

 

Aboriginal peoples have claimed aboriginal title and rights to a substantialportion of western Canada. Certain aboriginal peoples have filed a claimagainst the Government of Canada, the Province of Alberta, certain governmentalentities and the regional municipality of Wood Buffalo (which includes the cityof Fort McMurray, Alberta) claiming, among other things, aboriginal title tolarge areas of lands surrounding Fort McMurray, including the lands on whichthe project and most of the other oil sands operations in Alberta are located.Such claims, if successful, could have a significant adverse effect on the LongLake Project and on us.

 

**Some of our production is concentrated in a fewproducing assets.**

 

A significant portion of our production is generated from highlyproductive individual wells or central production facilities. Examples include:

 

·      Scott and Buzzard production platforms in the North Sea;

 

·      central processing facilities, oil pipelines, and export terminal atour Yemen operations;

 

·      our Long Lake synthetic crude oil operations; and

 

·      upgrading facilities at Syncrude in the Athabasca oil sands.

 

As significant production is generated from each asset, any singleevent that interrupts one of these operations could result in the loss ofproduction.

 

**Our energy marketing operations expose us to the riskof trading losses and liquidity constraints.**

 

Our trading operations expose us to the risk of financial losses fromvarious sources which may have a material and adverse effect on our financialperformance. The commodity markets in which we trade have experienced unanticipatedvolatility relative to historical variances, resulting in unusual andsignificant pricing changes, and deviations from anticipated seasonal pricingtrends and pricing levels. Our energy marketing division maintains a tradingportfolio comprised of both long and short physical and financial positionswhich may be at any time significant in size or number, and which arepredicated on a trading thesis for expected pricing levels and trends inforward or regional markets. Unanticipated volatility in the commodity pricelevel and trends upon which those trading positions are based may cause thosepositions to decrease in value.

 

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Significant changes in the commodities and financial markets could requireus to provide additional liquidity if additional collateral is required to beplaced with counterparties, or reduce some of our activities. Adversecredit-related events such as a downgrade of our credit rating tonon-investment grade could require additional collateral to be placed withcounterparties. Adverse credit-related events could also negatively affecttrading counterparties who fail to fulfill their contractual obligations.

 

The transportation and storage assets and contracts owned by our energymarketing business may decrease in value due to changes in temporal andregional commodity pricing.

 

**Use of marine transportation may expose us to the riskof financial loss and damaged reputation.**

 

From time to time, we may choose to charter marine vessels for thetransportation of crude oil. This may expose us to the risk of financial lossand damaged reputation in the event of oil spills.

 

**We operate in countries with political, economic andsecurity risks.**

 

We operate in numerous countries, some of which may be consideredpolitically and economically unstable. A portion of our revenue is derived fromoperations in these countries. As a result, our financial condition andoperating results could be significantly affected by risks associated with internationalactivities, including:

 

·      civil unrest and general strikes;

 

·      political instability, the risk of war and acts of terrorism;

 

·      taxation policies, including royalty and tax increases and retroactivetax claims, and investment restrictions;

 

·      expropriation or forced renegotiation or modification of existingcontracts;

 

·      exchange controls, currency fluctuations, devaluation or otheractivities that limit or disrupt markets and restrict payments or the movementof funds;

 

·      the possibility of being subject to exclusive jurisdiction of foreigncourts in connection with legal disputes relating to licenses to operate andconcession rights in countries where we currently operate; and

 

·      difficulties in enforcing our rights against a governmental agency becauseof the doctrine of sovereign immunity and foreign sovereignty overinternational operations.

 

The impact that future terrorist attacks or regional hostilities mayhave on the oil and gas industry in general, and on our operations inparticular, is not known at this time. Uncertainty surrounding military strikesor a sustained military campaign may affect operations in unpredictable ways,including disruptions of fuel supplies and markets, particularly oil, and thepossibility that infrastructure facilities, including pipelines, productionfacilities, processing plants and refineries, could be direct targets of, orindirect casualties of, an act of terror or war. We may be required to incursignificant costs in the future to safeguard our assets against terroristactivities.

 

There can be no assurance that we will be successful in protectingourselves against these risks and the related financial consequence.

 

**We may be affected by changes in governmentrules and regulations.**

 

Our operations are subject to various levels of government controls andregulations in the countries where we operate. These laws and regulationsinclude matters relating to land tenure, drilling, production practices,environmental protection, marketing and pricing policies, royalties, varioustaxes and levies including income tax, and foreign trade and investment, thatare subject to change from time to time. Current legislation is generally amatter of public record, and we cannot predict what additional legislation oramendments may be proposed that will affect our operations or when any suchproposals, if enacted, might become effective. Changes in governmentregulations could adversely affect our results of operations and financialcondition.

 

**Increased environmental regulation could increase ouroperating costs.**

 

The Kyoto Protocol came into force in 2005 and Canada ratified theKyoto Protocol in December 2002. In 1997, Canada committed to an emissionreduction of 6% below 1990 levels during the First Commitment period from 2008to 2012. In 2007, the Canadian Federal government introduced a paper titled“Regulatory Framework for Air Emissions” which proposes that the Federalgovernment regulate greenhouse gases (GHGs) and air pollutants beginning asearly as 2010, with progressively more stringent reductions applied through2050. GHGs are regulated based on CO2 equivalent (CO2e) intensity per unit of production until2020—2025, when a cap and trade system may be imposed. The reductionobligations are contemplated to be met through internal reductions, purchasingoffsets or making payments into a technology fund (with escalating but

 

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defined costs). The purchasing of offsets was predicated on theestablishment of a domestic emissions trading market. Offsets can be obtainedfrom approved projects within Canada and from international projects approvedby the Clean Development Mechanism Executive Board subject to certainlimitations.

 

The Federal government was to publish proposed regulations in late2008, however, no definitive regulation has been published to date. The Federalgovernment’s recent announcements indicating an interest in pursuing abi-lateral cap and trade system with the United States has created furtheruncertainty about the implementation of their “Regulatory Framework for AirEmissions”.

 

The Canadian Federal government has also indicated their intent toregulate air pollutants concurrent with GHGs but their schedule and long-termobjectives remain unclear. We could face technical challenges in meeting someof the criteria for certain pollutants. Any required reductions in the GHGsemitted from our operations could result in increases in our capital oroperating expense, or reduced operating rates, especially at the Long LakeProject, which could have an adverse effect on our results of operations andfinancial condition. As a “new facility” Long Lake will have three years toestablish an emissions baseline before having a reduction obligation assigned.In 2008, our Canadian operations, including Syncrude, accounted for 25% of ourproduction before royalties.

 

Alberta became the first jurisdiction in Canada to enact and implementbinding emission reductions (a one time from base, 12% reduction in carbonintensity) on facilities emitting more than 100 kilo-tonnes of CO2 equivalent. Facilities unable to achieveinternal reductions have unlimited ability to pay into a technology fund at therate of $15 per tonne of CO2 equivalent. This amount must be paid annuallyuntil such time as internal reduction is achieved unless other approved offsetsare acquired from projects in Alberta.

 

British Columbia enacted legislation in November 2007 entitled theGreenhouse Gas Reduction Targets Act which targets a 33% reduction in currentprovincial GHG emissions by 2020. Regulations affecting this reduction targethave yet to be finalized and we are monitoring progress in that regard.

 

During the period 2010 to 2020, the Canadian carbon market could beshort of supply leading to high carbon prices. It remains to be seen if theFederal and Alberta Provincial levels of government will harmonize theircompliance regimes and how the revenue in the technology funds will beallocated.

 

Our three installations in the UK 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. Our installations are expected to have emissions in excess ofallowances which will be covered by eligible offsets from the Clean DevelopmentMechanism and purchases of EU Allowances.

 

Environmental liabilities inherent in the oil and gas and chemicalsindustries are becoming increasingly sensitive as related laws and regulationsbecome more stringent worldwide. Many of these laws and regulations imposestringent controls on the manner in which we operate and our impact on theenvironment, and require us to remove or remedy the effect of our activities onthe environment at present and former operating sites, including dismantlingproduction facilities and remediating damage caused by disposing or releasingspecified substances. Significant changes in the environmental laws andregulations governing our operations could have an adverse financialconsequence on us.

 

Certain operations require the use of fresh and saline water which wecurrently obtain from both sub-surface and surface sources. Additional costsmay be incurred if allocation limits are placed on our water usage, if ourwater needs exceed allocated amounts or if existing water allocations arereduced.

 

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ITEM 1B.

 

Unresolved Staff Comments

 

There are no unresolved staff comments with the SEC.

 

ITEM 3.

 

Legal Proceedings

 

There are a number of lawsuits and claims pending against Nexen, theultimate results of which cannot be ascertained at this time. Management is ofthe opinion that any amounts assessed against us would not have a materialadverse effect on our consolidated financial position or results of operations.We believe we have made adequate provisions for such lawsuits and claims.

 

Certain of our US oil and gas operations have received, over the years,notices and demands from the US Environmental Protection Agency (EPA), stateenvironmental agencies, and certain third parties for certain sites seeking torequire investigation and remediation under federal or state environmentalstatutes. In addition, notices, demands, and lawsuits have been received forcertain sites related to historical operations and activities in the US forwhich, although no assurances can be made, we believe that certain assumptionand indemnification agreements protect our US operations from any present orfuture material liabilities that may arise from these particular sites.

 

ITEM 4.

 

Submission of Matters to a Vote of Security Holders

 

No matters were submitted to a vote of Nexen’s security holders duringthe fourth quarter of 2008.

 

**PART II**

 

ITEM 5.

 

Market for the Registrant’s Common Equity, Related Stockholder Mattersand Issuer Purchases of Equity Securities

 

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

 

On December 31, 2008, there were 1,624 registered holders ofcommon shares and 519,448,590 common shares outstanding. The number ofregistered holders of common shares is calculated excluding individualparticipants in securities positions listings.

 

**Issuer Purchases of Equity Securities during theFourth Quarter(1)**

 
| **Period**               | ** ** | **(a) Total number  of shares (or units)  purchased** | ** ** | **(b) Average price  paid per share  (or unit)** | ** ** | **(c) Total number of shares  (or units) purchased as  part of publicly announced  plans or programs** | ** ** | **(d) Maximum number  (or approximate dollar value)  of shares (or units) that  may yet to be purchased  under the plans or programs** | ** ** |
|--------------------------|------------|--------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| October 1-31, 2008  |       | 1,093,900                                                                      |       | $                                                                         | 16.44      |                                                                                                                                                               | 1,093,900  |                                                                                                                                                                                                                        | 41,833,346 |   |
| November 1-30, 2008 |       | 1,056,200                                                                      |       | $                                                                         | 18.92      |                                                                                                                                                               | 1,056,200  |                                                                                                                                                                                                                        | 40,777,146 |   |
| December 1-31, 2008 |       | —                                                                         |       | —                                                                    |       | —                                                                                                                                                             |       | 40,777,146                                                                                                                                                                                                                  |       |

 

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*(1)** **On July 30, 2008, we announced that Nexenreceived approval from the TSX for a Normal Course Issuer Bid that allows us torepurchase up to a maximum of 52,914,046 common shares in the period ofAugust 6, 2008 to August 5, 2009.*

 

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**Trading Range of Nexen’s Common Shares**

 
| ** **     | ** ** | **TSX (Cdn$)** | ** ** | **NYSE (US$)** | ** ** |
|----------------|------------|---------------------|------------|---------------------|------------|
| **($/share)**  | ** ** | **High**            | ** ** | **Low**             | ** ** | **High** | ** ** | **Low** | ** ** |
| **2008**       |       |                |       |                |       |   |   |   |   |
| First Quarter  |       | 34.20               |       | 26.00               |       | 34.57 |   | 25.11 |   |
| Second Quarter |       | 43.45               |       | 29.69               |       | 42.71 |   | 28.87 |   |
| Third Quarter  |       | 41.47               |       | 21.12               |       | 40.99 |   | 20.56 |   |
| Fourth Quarter |       | 29.10               |       | 13.33               |       | 23.99 |   | 10.81 |   |
| **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 |   |

 

**Quarterly Dividends Declared on Common Shares**

 
| **($/share)** | ** ** | **First  Quarter** | ** ** | **Second  Quarter** | ** ** | **Third  Quarter** | ** ** | **Fourth  Quarter** | ** ** |
|---------------|------------|--------------------|------------|---------------------|------------|--------------------|------------|---------------------|------------|
| 2008          |       | 0.025              |       | 0.050               |       | 0.050              |       | 0.050               |       |
| 2007          |       | 0.025              |       | 0.025               |       | 0.025              |       | 0.025               |       |

 

Payment date for dividends was the first day of the next quarter. Alldividends paid to holders of common shares in 2008 have been designated as“eligible dividends” for Canadian tax purposes. This designation will apply toall such dividends paid in the future unless otherwise notified by us.

 

The Income Tax Act of Canada requires us to deduct a withholding taxfrom all dividends remitted to non-residents. According to the Canada-US TaxTreaty, we have deducted a withholding tax of 15% on dividends paid toresidents of the United States, except in the case of a company that owns atleast 10% of the voting stock, where the withholding tax is 5%.

 

The Investment Canada Act requires that a “non-Canadian”, as defined,file notice with Investment Canada and obtain government approval prior toacquiring control 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 of securitiesauthorized for issuance under equity compensation plans on page 161).

 

On February 3, 2000, at a Special Meeting of Shareholders, aShareholder Rights Plan was approved. On May 2, 2002, at the AnnualGeneral and Special Meeting of Shareholders, an Amended and RestatedShareholder Rights Plan (Plan) was approved. According to the Plan, a right isattached to each present and future outstanding common share, entitling theholder to acquire additional common shares during the term of the right. Priorto the separation date, the rights are not separable from the common shares,and no separate certificates are issued. The separation date would typicallyoccur at the time of an unsolicited takeover bid, but our board can defer theseparation date.

 

Rights created under the Plan, which can only be exercised when aperson acquires 20% or more of our common shares (a Flip-In Event), entitleeach shareholder, other than the 20% buyer, to acquire additional common sharesat one-half of the market price at the time of exercise. The Plan must bereapproved by shareholders on or before our annual general meeting in 2011 toremain effective past that date. A copy of the Plan is available on our website at www.nexeninc.com.

 

37

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ITEM 6.

 

Selected Financial Data

 

**Five-Year Summary of Selected Financial Data inAccordance with US GAAP**

 
| **(Cdn$ millions, except otherwise indicated)**     | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Oil &  Gas and Syncrude Production**                         |       |       |       |       |       |       |       |       |       |       |       |
| Production Before  Royalties (mboe/d)(1)                                |       | 250        |       | 254        |       | 212        |       | 242        |       | 250        |       |
| Production After Royalties  (mboe/d)(1)                                 |       | 210        |       | 207        |       | 156        |       | 173        |       | 174        |       |
| ** **                                                              |       |       |       |       |       |       |       |       |       |       |       |
| **Results  of Operations**                                              |       |       |       |       |       |       |       |       |       |       |       |
| Revenue                                                                 |       |       |       |       |       |       |       |       |       |       |       |
| Oil & Gas and  Syncrude(2)                                     |       | 6,907      |       | 5,174      |       | 3,656      |       | 3,535      |       | 2,573      |       |
| Marketing                                                               |       | 522        |       | 926        |       | 1,373      |       | 864        |       | 625        |       |
| Chemicals                                                               |       | 427        |       | 447        |       | 413        |       | 413        |       | 383        |       |
| Other                                                                   |       | 364        |       | (26        | )          | (47        | )          | (193       | )          | 59         |       |
| Total Revenue                                                           |       | 8,220      |       | 6,521      |       | 5,395      |       | 4,619      |       | 3,640      |       |
|                                                                    |       |       |       |       |       |       |       |       |       |       |       |
| Net Income from Continuing  Operations                                  |       | 1,704      |       | 1,012      |       | 579        |       | 658        |       | 705        |       |
| Basic Earnings per Common  Share from Continuing Operations ($/share)   |       | 3.24       |       | 1.92       |       | 1.10       |       | 1.26       |       | 1.37       |       |
| Diluted Earnings per  Common Share from Continuing Operations ($/share) |       | 3.20       |       | 1.88       |       | 1.08       |       | 1.23       |       | 1.35       |       |
| Net Income                                                              |       | 1,704      |       | 1,012      |       | 579        |       | 1,110      |       | 788        |       |
| Basic Earnings per Common  Share ($/share)                              |       | 3.24       |       | 1.92       |       | 1.10       |       | 2.13       |       | 1.53       |       |
| Diluted Earnings per  Common Share ($/share)                            |       | 3.20       |       | 1.88       |       | 1.08       |       | 2.08       |       | 1.51       |       |
|                                                                    |       |       |       |       |       |       |       |       |       |       |       |
| **Financial  Position**                                                 |       |       |       |       |       |       |       |       |       |       |       |
| Total Assets(1)                                                         |       | 22,048     |       | 17,982     |       | 17,079     |       | 14,493     |       | 12,339     |       |
| Long-Term Debt(3)                                                       |       | 6,578      |       | 4,610      |       | 4,618      |       | 3,630      |       | 4,214      |       |
| Shareholders’ Equity                                               |       | 6,946      |       | 5,449      |       | 4,614      |       | 3,961      |       | 2,892      |       |
| Capital Investment,  including Acquisitions                             |       | 3,066      |       | 3,401      |       | 3,408      |       | 2,638      |       | 4,264      |       |
| Dividends per Common Share  ($/share)(4)                                |       | 0.175      |       | 0.10       |       | 0.10       |       | 0.10       |       | 0.10       |       |
| Common Shares Outstanding  (thousands)(5)                               |       | 519,449    |       | 528,305    |       | 525,026    |       | 522,281    |       | 516,798    |       |

 

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| *(1)* | * * | *In late 2004, we acquired North Sea assets and  began production from Block 51 in Yemen. In 2005, we sold producing  properties in Canada and suffered hurricane-related downtime in the Gulf of  Mexico. A full year’s production from the North Sea and Block 51 in Yemen  offset declines caused by these events. In early 2007, the Buzzard field came  on stream and offset declines from Masila in Yemen.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|-------|----------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | * * | *In the third quarter of 2005, we sold Canadian  conventional oil and gas properties in Saskatchewan, British Columbia and  Alberta producing 18,300 bbls/d. The results of these operations have been  shown as discontinued operations.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| *(3)* | * * | *In December 2004, we drew US$1.5 billion on  unsecured acquisition credit facilities to finance the purchase of North Sea  assets. The remainder of the purchase price was funded from cash on hand. The  acquisition credit facility was repaid in 2005 with proceeds from the  issuance of US$1.04 billion in senior notes in the first quarter and from  asset dispositions in the third quarter. Our long-term debt increased in 2006  as a result of our capital investments, primarily at Buzzard and Long Lake.  In May 2007, we issued US$1.5 billion of senior notes with US$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 and  Canada allowing us to potentially raise US$2.5 billion of debt, equity or  other hybrid securities, should the need arise.* |
| *(4)* | * * | *Quarterly dividends were increased to 5¢ per share  in the second quarter of 2008.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| *(5)* | * * | *During the third quarter of 2008, we received  approval from the Toronto Stock Exchange for a Normal Course Issuer Bid that  allows us to repurchase up to a maximum of 52,914,046 common shares for the  period of August 6, 2008 to August 5, 2009. In 2008, we repurchased  and cancelled 12,136,900 common shares for $338 million.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |

 

38

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**MD&A**

 
| **PART II** | ITEM 7.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
|-------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **  | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| ** **  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| ** **  | The  following should be read in conjunction with the Consolidated Financial  Statements included in this report. The Consolidated Financial Statements  have been prepared in accordance with generally accepted accounting  principles (GAAP) in Canada. The impact of significant differences between  Canadian and United States (US) accounting principles on the financial  statements is disclosed in Note 23 to the Consolidated Financial Statements.  The date of this discussion is February 11, 2009. Unless otherwise noted,  tabular amounts are in millions of Canadian dollars. Our discussion and  analysis of our oil and gas activities include our Syncrude activities since  the product produced from Syncrude competes in the oil and gas market. Oil  and gas volumes, reserves and related performance measures are presented on a  working interest before-royalties basis. We measure our performance in this  manner consistent with other Canadian oil and gas companies. Where  appropriate, we have provided information on an after-royalty basis in  tabular format. |

 

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| ** ** | *(1)  Investors should read the Special Note  Regarding Forward-Looking Statements on page 78.*                                                                                                                                                |
|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** ** | *(2)   Canadian investors should read the Special Note to Canadian Investors  on page 79 which highlights differences between our reserve estimates and  related disclosures that are otherwise required by Canadian regulatory  authorities.* |

 
| ** ** | Executive  Summary                                               | 39     |
|------------|------------------------------------------------------------------|--------|
| ** ** | Capital  Investment                                              | 41     |
| ** ** | Financial  Results                                               |   |
|       | Year-to-Year Change in Net Income                                | 46     |
| ** ** | Oil & Gas And Syncrude                                       |   |
| ** ** | Production                                                       | 47     |
| ** ** | Commodity Prices                                                 | 50     |
| ** ** | Operating Expenses                                               | 52     |
| ** ** | Depreciation, Depletion, Amortization and  Impairment (DD&A) | 53     |
| ** ** | Exploration Expense                                              | 54     |
|       | Oil & Gas And Syncrude Netbacks                              | 56     |
|       | Energy Marketing                                                 | 57     |
|       | Chemicals                                                        | 62     |
|       | Corporate Expenses                                               | 62     |
| ** ** | Outlook For 2009                                                 | 64     |
| ** ** | Liquidity and Capital Resources                                  | 65     |
| ** ** | Critical Accounting Estimates                                    | 70     |
| ** ** | New Accounting Pronouncements                                    | 73     |
| ** ** |                                                             |   |
| ** ** | ITEM 7A.                                                         |   |
| ** ** | Quantitative and Qualitative Disclosures about Market Risk       | 75     |
| ** ** | Non-trading                                                      | 75     |
| ** ** | Trading                                                          | 77     |
| ** ** | Credit Risk                                                      | 78     |
| ** ** | Special Note Regarding Forward-looking Statements                | 78     |
| ** ** | Special Note to Canadian Investors                               | 79     |

 

----

 

**EXECUTIVESUMMARY**

 

**2008Results**

 
| **(Cdn$ millions)**                   | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|--------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Production before Royalties (mboe/d)(1)    |       | 250      |       | 254      |       | 212      |       |
| Production after Royalties (mboe/d)        |       | 210      |       | 207      |       | 156      |       |
| Cash Flow from Operating Activities        |       | 4,354    |       | 2,830    |       | 2,374    |       |
| Net Income                                 |       | 1,715    |       | 1,086    |       | 601      |       |
| Earnings per Common Share, Basic ($/share) |       | 3.26     |       | 2.06     |       | 1.15     |       |
| Net Debt(2)                                |       | 4,575    |       | 4,404    |       | 4,730    |       |

 

----

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

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

 

Production before royaltiesaveraged 250,000 boe/d in 2008, slightly below last year’s volumes. Higherrates at Buzzard were offset by declines at our maturing Yemen properties andhurricane interruptions in the Gulf of Mexico. Buzzard continues to operatereliably and production in 2008 averaged 204,200 boe/d (88,200 boe/d net tous). We expect our consolidated production rates will increase in 2009primarily as a result of new volumes from our Long Lake Project, Ettrick in theUK North Sea and Longhorn in the Gulf of Mexico.

 

We achieved record financialresults in 2008, generating cash flow from operating activities in excess of $4billion and net income of $1.7 billion. Commodity prices reached new highsduring the year, but fell in the fourth quarter as a result of the globaleconomic crisis. WTI crude oil averaged US$99.65/bbl for the year, 38% higherthan last year. Despite the fall in crude oil and gas prices in the last partof the year, the strengthening US dollar kept our price realizations strong.

 

Much of our production has lowoperating costs and low royalties. Our cash netbacks continue to be among thehighest in the industry, averaging $72.97/boe after royalties for the year.High netbacks deliver superior relative performance even as commodity pricesdecline.

 

The past year provedchallenging for our energy marketing group as unprecedented market conditionsimpacted physical market fundamentals and the pricing relationships wesuccessfully positioned ourselves to profit from historically. While the globaleconomic slowdown produced challenges for our business, the marketing team wasmost impacted by significant swings in commodity markets. We were positioned totake advantage of normal market fundamentals but these were overwhelmed bysignificant price movements, increased volatility and the economic slowdown.Since the middle of the year, we have been refocusing this division andreducing the size of our trading levels. In response to the rapidlydeteriorating economic environment and financial markets, we were carefullychoosing our exit points. With the gas trading positions we recently exited,the refocusing of our gas marketing business back to physical transportationand storage is now complete.

 

Our net income includesimpairment expense of $568 million (before tax) related to properties in the UKNorth Sea and the Gulf of Mexico. These properties were impaired by lowercommodity prices, lower reserve estimates and unexpected costs.

 

We reduced our net debt byapproximately $1.3 billion with cash flow that exceeded our capital investment.This was offset by the impact of a stronger US dollar which increased ourUS-dollar denominated debt by $1 billion at year end, and by repurchasing 12million common shares for approximately $340 million.

 

Our financial position isstrong. We have financial flexibility with major capital projects complete atBuzzard and Long Lake, and industry-leading cash netbacks. We have liquidity ofapproximately $3.5 billion after acquiring the additional Long Lake interest inJanuary 2009, comprised of cash on hand and undrawn committed credit. We haveno debt maturities until 2011 and the average term-to-maturity of our long-termdebt is approximately 18 years.

 
| **CASH  FLOW FROM OPERATING ACTIVITES** | **NET  INCOME** |
|-----------------------------------------|-----------------|
| (Cdn$millions)                          | (Cdn$millions)  |
|                                         |                 |

 

39

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**Strategy Progress**

 
| **(Cdn$ millions)**                                 | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Capital Investment, including Acquisitions               |       | 3,066    |       | 3,401    |       | 3,408    |       |
| Proved Oil and Gas Reserves before  Royalties (mmboe)(1) |       | 664      |       | 734      |       | 725      |       |
| Proved Oil and Gas Reserves after Royalties  (mmboe)(1)  |       | 631      |       | 650      |       | 637      |       |
| Proved Syncrude Reserves before Royalties  (mmboe)(1)    |       | 324      |       | 324      |       | 324      |       |
| Proved Syncrude Reserves after Royalties  (mmboe)(1)     |       | 295      |       | 267      |       | 274      |       |

 

----

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

 

Our strategy is to build asustainable energy company focused in three areas: oil sands, unconventionalgas and select conventional exploration and exploitation. Our investment inthese areas generated the following results in 2008:

 

·                  Oil Sands — theLong Lake Project began producing bitumen and we completed construction andcommissioning of the upgrader. First production of premium synthetic crude fromthe upgrader began in January 2009. We continued to focus on our oil sandsgrowth strategy by increasing our interest in Long Lake by 15% to 65% in early2009.

·                  UnconventionalGas — we have a significant land position in the Horn River basin in northeast British Columbia and startedto test the area with exploration drilling and fracing activities. We continuedto explore and develop CBM opportunities in Canada.

·                  SelectConventional Exploration and Exploitation — our conventional exploration program was focused in the US Gulf ofMexico and the UK North Sea, which yielded four discoveries that provide opportunitiesfor future growth.

 

During 2008, our proved oil andgas and Syncrude reserves additions replaced 25% of our oil and gas andSyncrude production (112% after royalties). Excluding economic revisions, wereplaced 79% of our oil and gas and Syncrude production (86% after royalties).The difference between before and after royalties reflect a reduction in theroyalties on oil sands activities where the royalty rate is sensitive toprices.

 

**Before Royalties**

 
| **(mmboe)**                               | ** ** | **Oil and Gas** | ** ** | **Syncrude** | ** ** | **Total** | ** ** |
|-------------------------------------------|------------|---------------------------|------------|--------------|------------|-----------|------------|
| **Production**                            | ** ** | **86**                    | ** ** | **8**        | ** ** | **94**    | ** ** |
| ** **                                |       |                      |       |         |       |      | ** ** |
| **Reserve  Changes excluding Production** |       |                      |       |         |       |      | ** ** |
| Net Additions                             |       | 66                        |       | 8            |       | 74        | ** ** |
| Economic Revisions                        |       | (50                       | )          | —       |       | (50       | )          |
|                                      |       | **16**                    | ** ** | **8**        | ** ** | **24**    | ** ** |

 

**After Royalties**

 
| **(mmboe)**                               | ** ** | **Oil and Gas** | ** ** | **Syncrude** | ** ** | **Total** | ** ** |
|-------------------------------------------|------------|---------------------------|------------|--------------|------------|-----------|------------|
| **Production**                            | ** ** | **72**                    | ** ** | **7**        | ** ** | **79**    | ** ** |
| ** **                                |       |                      |       |         |       |      |       |
| **Reserve  Changes excluding Production** |       |                      |       |         |       |      |       |
| Net Additions                             |       | 60                        |       | 7            |       | 67        |       |
| Economic Revisions                        |       | (7                        | )          | 28           |       | 21        |       |
| ** **                                | ** ** | **53**                    | ** ** | **35**       | ** ** | **88**    | ** ** |

 

The majority of our additionsbefore economic revisions relate to activities at Buzzard, Long Lake, Masilaand Canadian CBM. Negative revisions occurred at Ettrick as a result ofdisappointing drilling and testing results which caused us to reduce ourexpectations of recoverable reserves. Additional information on our proved oiland gas and Syncrude reserves can be found in Items 1 and 2 Business andProperties (pages 15 to 20) and in Item 8 Financial Statements andSupplementary Data (pages 126 to 131).

 

40

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**Outlook**

 

In 2009, we expect productionto grow approximately 5% to 10% compared to 2008 and range between 255,000 and270,000 boe/d before royalties. On an after-royalties basis, we expectproduction to grow 7% to 14% and range between 225,000 and 240,000 boe/d,reflecting growth in the UK North Sea and at Long Lake where royalties are low.Increases are expected to come from Ettrick in the UK North Sea, Longhorn inthe US Gulf of Mexico and the Long Lake Project as bitumen rates ramp up.

 

Our capital investment plansfor 2009 total $2.8 billion. We plan to finance this investment through cashflow from operating activities and existing cash and cash equivalents. Theprimary focus of our investment will be on our major and core assetdevelopments at Buzzard and Ettrick in the North Sea, Longhorn in the Gulf ofMexico, and Usan, offshore Nigeria. We also plan to spend approximately $700million advancing our new growth exploration and appraisal opportunitiesincluding our Horn River shale gas play. We are monitoring our capital spendingthroughout the upcoming year and are prepared to reduce our capital budget inresponse to the economic environment.

 

Our large capital projects atBuzzard and Long Lake Phase 1 are behind us and at year end, we had over $2billion of cash on hand, $2.5 billion of undrawn committed credit facilitiesthat are available until 2012 and $613 million in uncommitted creditfacilities. We used existing term credit facilities and cash on hand early in2009 to increase our interest in the Long Lake Project by 15%. We have no debtmaturities over the next few years and believe we will continue to havesubstantial liquidity that provides us with the financial strength andflexibility to weather low commodity prices during this uncertain time. Theaverage term-to-maturity of our debt is approximately 18 years.

 

**CAPITAL INVESTMENT**

 
| **(Cdn$ millions)**                          | ** ** | **Estimated 2009** | ** ** | **2008**  | ** ** | **2007**  | ** ** |
|---------------------------------------------------|------------|-------------------------|------------|-----------|------------|-----------|------------|
| Major Development                                 |       | 780                     |       | 1,437     |       | 1,479     |       |
| Early Stage Development                           |       | 210                     |       | 167       |       | 162       |       |
| New Growth Exploration                            |       | 690                     |       | 582       |       | 573       |       |
| Core Asset Development                            |       | 880                     |       | 731       |       | 1,069     |       |
| Total Oil & Gas and Syncrude             |       | 2,560                   |       | 2,917     |       | 3,283     |       |
| Energy Marketing, Corporate, Chemicals and  Other |       | 270                     |       | 149       |       | 118       |       |
| **Total  Capital**                                | ** ** | **2,830**               | ** ** | **3,066** | ** ** | **3,401** | ** ** |

 

Our strategy and capitalprograms are focused on growing long-term value for our shareholdersresponsibly. To maximize value, we invest in:

 

·                  core assets forshort-term production and free cash flow to fund capital programs and repaydebt;

·                  developmentprojects that convert our discoveries into new production and cash flow in themedium term; and

·                  exploration andnew growth projects for longer-term growth.

 

As conventional basins in NorthAmerica mature, we have been transitioning toward less mature basins andunconventional resource plays. Key focus areas include the North Sea, Athabascaoil sands, Canadian CBM and shale gas, deep-water Gulf of Mexico, offshore WestAfrica and the Middle East — areas we believe have attractive fiscal terms,significant remaining opportunity, and where we have a competitive advantage.

 

41

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**2008 Capital**

 
| **(Cdn$ millions)**              | ** ** | **Major  Development** | ** ** | **Early Stage  Development** | ** ** | **New Growth  Exploration** | ** ** | **Core Asset  Development** | ** ** | **Total** | ** ** |
|---------------------------------------|------------|------------------------|------------|-----------------------------------|------------|----------------------------------|------------|----------------------------------|------------|-----------|------------|
| Oil and Gas                           |       |                   |       |                              |       |                             |       |                             |       |      |       |
| Synthetic (mainly Long Lake)          |       | 847                    |       | 156                               |       | 2                                |       | 20                               |       | 1,025     |       |
| United States                         |       | 87                     |       | —                            |       | 154                              |       | 164                              |       | 405       |       |
| United Kingdom                        |       | 263                    |       | —                            |       | 146                              |       | 282                              |       | 691       |       |
| Canada                                |       | 63                     |       | 11                                |       | 223                              |       | 105                              |       | 402       |       |
| Yemen                                 |       | —                 |       | —                            |       | 9                                |       | 92                               |       | 101       |       |
| Nigeria                               |       | 177                    |       | —                            |       | 3                                |       | —                           |       | 180       |       |
| Other Countries                       |       | —                 |       | —                            |       | 45                               |       | 13                               |       | 58        |       |
| Syncrude                              |       | —                 |       | —                            |       | —                           |       | 55                               |       | 55        |       |
| ** **                            | ** ** | **1,437**              | ** ** | **167**                           | ** ** | **582**                          | ** ** | **731**                          | ** ** | **2,917** |       |
| Chemicals                             |       | —                 |       | —                            |       | —                           |       | 88                               |       | 88        |       |
| Energy Marketing, Corporate and Other |       | —                 |       | —                            |       | —                           |       | 61                               |       | 61        |       |
| **Total  Capital**                    | ** ** | **1,437**              | ** ** | **167**                           | ** ** | **582**                          | ** ** | **880**                          | ** ** | **3,066** | ** ** |
|                                  |       |                   |       |                              |       |                             |       |                             |       |      |       |
| As a % of Total Capital               |       | 47                     | %          | 5                                 | %          | 19                               | %          | 29                               | %          | 100       | %          |

 

**2009 Estimated Capital**

 
| **(Cdn$ millions)**       | ** ** | **Major  Development** | ** ** | **Early Stage  Development** | ** ** | **New Growth  Exploration** | ** ** | **Core Asset  Development** | ** ** | **Total** | ** ** |
|--------------------------------|------------|------------------------|------------|-----------------------------------|------------|----------------------------------|------------|----------------------------------|------------|-----------|------------|
| Oil and Gas                    |       |                   |       |                              |       |                             |       |                             |       |      |       |
| Synthetic (mainly Long Lake)   |       | —                 |       | 180                               |       | —                           |       | 110                              |       | 290       |       |
| United States                  |       | 105                    |       | 10                                |       | 190                              |       | 60                               |       | 365       |       |
| United Kingdom                 |       | 160                    |       | 10                                |       | 175                              |       | 400                              |       | 745       |       |
| Canada                         |       | —                 |       | 10                                |       | 180                              |       | 90                               |       | 280       |       |
| Yemen                          |       | —                 |       | —                            |       | —                           |       | 120                              |       | 120       |       |
| Nigeria                        |       | 515                    |       | —                            |       | 25                               |       | —                           |       | 540       |       |
| Other Countries                |       | —                 |       | —                            |       | 120                              |       | 10                               |       | 130       |       |
| Syncrude                       |       | —                 |       | —                            |       | —                           |       | 90                               |       | 90        |       |
| ** **                     | ** ** | **780**                | ** ** | **210**                           | ** ** | **690**                          | ** ** | **880**                          | ** ** | **2,560** |       |
| Chemicals                      |       | —                 |       | —                            |       | —                           |       | 194                              |       | 194       |       |
| Marketing, Corporate and Other |       | —                 |       | —                            |       | —                           |       | 76                               |       | 76        |       |
| **Total  Capital**             | ** ** | **780**                | ** ** | **210**                           | ** ** | **690**                          | ** ** | **1,150**                        | ** ** | **2,830** | ** ** |
|                           |       |                   |       |                              |       |                             |       |                             |       |      |       |
| As a % of Total Capital        |       | 28                     | %          | 7                                 | %          | 24                               | %          | 41                               | %          | 100       | %          |

 

Synthetic

 

In 2008, we invested $1 billionto develop our insitu oil sands resource. This included an investment ofapproximately $847 million on the first phase of Long Lake, $425 million ofwhich related to the upgrader. The remaining expenditures related topreliminary work for future phases of Long Lake. At Long Lake, we added 19mmboe of proved bitumen reserves based on further core-hole delineation of thelease.

 

In late January 2009, wecompleted the $735 million acquisition of an additional 15% interest in theLong Lake Project and the joint venture lands from OPTI Canada Ltd. We now own65% of the Long Lake Project and joint venture lands. As part of thetransaction, we assumed operatorship of the upgrader from Opti, and are now thesole operator of the Long Lake Project. We expect this will create operationalefficiencies and reduce the cost of managing Long Lake. With the completion ofthis acquisition, our total company proved reserves have increased byapproximately 9%.  These additions willbe booked in 2009.

 

We recently reached asignificant milestone at Long Lake when we produced first Premium SyntheticCrude (PSCTM) from the upgrader. The main process units of the upgrader havebeen successfully started up and are operating. Synthetic natural gas (Syngas)from the upgrader is being used in SAGD operations and this has significantly reducedthe need for purchased natural gas. Currently, we are producing between 10,000and 15,000 bbls/d gross of upgraded on-spec product. The upgrader is expectedto ramp up to full design rates of approximately 60,000 bbls/d (39,000 bbls/dnet to us) over the next 12 to 18 months. As the upgrader ramps up to fullcapacity, we expect that there will be periods

 

42

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of downtime as we work throughthe early stages of production. This periodic downtime is normal and consistentwith industry experience.

 

Bitumen production from thereservoir is performing well but overall ramp up of production has beenaffected by a variety of surface issues that have limited the amount of steaminjected into the reservoir over the past few months. Since steam injectionrates directly impact bitumen production rates, when our ability to generatesteam is limited, our bitumen production is lower. Most recently, our SAGDproduction was reduced as a result of power disruptions, extreme cold weatherand water treating issues. As the weather improves and we recover from powerdisruptions and water treatment issues, our production rates have increased. Weare currently producing approximately 20,000 bbls/d (gross) of bitumen, thehighest we have seen to date. Due to steaming constraints, we have been forcedto allocate our steam injection and accordingly we have 32 of the 81 well pairson production. On average, these well pairs are producing at approximately 75%of their design rates after 11 months of SAGD operation. This is consistentwith expectations as we expected a ramp up period of 12 to 18 months. Theaverage steam-to-oil ratio (SOR) for these wells is currently less than 4.0. Aswe increase our steam capacity, we will bring on all remaining wells.

 

Phase 1 of Long Lake willdevelop approximately 10% of our oil sands inventory. The sanctioning of Phase2 will depend on multiple factors including the initial performance of Phase 1,receiving regulatory approval for Phase 2 SAGD operations, receiving clarity onproposed climate change regulations, finalizing cost estimates and an improvedeconomic environment. We therefore do not expect to sanction Phase 2 until mid2010 at the earliest. In 2009, we plan to advance detailed engineering on theSAGD and upgrader facilities for Phase 2 of Long Lake and conduct core holedrilling to further delineate our leases.

 

UnitedStates

 

Development of Longhorncontinues to progress with first production expected in mid 2009. Thisdevelopment comprises four sub-sea wells tied in to the ENI-operated CorralPlatform, previously known as the Crystal Platform. We expect peak productionrates in excess of 200 mmcf/d gross (50 mmcf/d net to us) by year end. In 2008,we invested $87 million developing Longhorn. We have a 25% non-operated workinginterest in Longhorn and ENI is the operator.

 

In 2008, our explorationprogram primarily focused on the deep water. In the eastern Gulf of Mexico, wedrilled the Fredericksburg exploration well. Target sands were reached but wedid not encounter commercial hydrocarbons. This was the third prospect to bedrilled in the area following earlier successes at Vicksburg and Shiloh. Weremain optimistic about the potential of this emerging play and expect to drillup to two exploration wells and one appraisal well in the area in 2009. Inaddition, we have a feasibility study underway to assess development optionsfor the Vicksburg discovery. We have a 25% interest in Vicksburg and a 20%interest in Shiloh with Shell operating both.

 

At our Cote de Mer prospect,located on the Louisiana coast, exploratory drilling was interrupted byhurricanes Gustav and Ike. Following successful pipe recovery operations, thewell was sidetracked to a depth of 21,700 feet, and penetrated the target zone.We continue to be encouraged by the logging data received to date, and areattempting to drill the remaining 600 feet of the target interval. We have a37.5% working interest in this prospect.

 

In 2008, we invested $164million to add production volumes from the Green Canyon 6 area and torecomplete wells on our producing properties.

 

UnitedKingdom

 

We invested almost $700 millionin the UK last year. This included approximately $250 million at Buzzard andadded proved reserves of 29 mmboe (29 after royalties). Successful drilling andproduction performance resulted in increases in both reservoir size and overallrecovery factor which led to these proved reserve adds. These additions wereoffset by negative economic revisions of 10 mmboe (10 after royalties), due tolow year-end prices.

 

In 2009, Buzzard will continueto be a significant contributor to our cash flow and production volumes.Throughout the year, we will continue construction of the fourth platformcontaining production sweetening facilities designed to handle higher levels ofhydrogen sulphide. During the third quarter, we plan to install the jackets forthis platform and complete tie-in operations, pending installation of thetopsides. This will result in about one month of downtime which coincides witha six week planned slowdown of the Forties pipeline.

 

43

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Our Ettrick development in the North Sea is progressing towards firstoil in the next few months. In 2008, we invested approximately $260 million.During 2008, we had 12 mmboe of negative reserve revisions (12 afterroyalties), of which approximately one quarter relate to lower oil prices. Theremaining revisions are due to disappointing drilling results that lowered ourreserve estimates. The Ettrick development consists of a leased floatingproduction, storage and offloading vessel (FPSO) designed to handle 30,000bbls/d of oil and 35 mmcf/d of gas. We expect Ettrick to add approximately10,000 boe/d to our 2009 production volumes. We also have a discovery atBlackbird which could be a future tie-back to Ettrick. We have no provenreserves booked for Blackbird. In 2009, we plan to drill an appraisal well tofurther evaluate this discovery. We operate both Ettrick and Blackbird, with an80% working interest in each.

 

We recently drilled a successful appraisal well at Rochelle on Block15/27 in the North Sea. The well was tested and flowed at an average restrictedrate of 41 mmcf/d of gas and 2,300 bbls/d of oil condensate. We are evaluatingfuture appraisal and fast-track development options and have a 44% non-operatedworking interest in the well.

 

Elsewhere, we are assessing future appraisal and developmentalternatives for the growing Golden Eagle area. This area includes discoveriesat Golden Eagle, Pink and most recently, Hobby, where we are encouraged byearly results. We are planning to drill multiple sidetracks to determine theextent of both Hobby and Golden Eagle. Hobby is located on Block 20/1Napproximately 1.5 km west of the Golden Eagle discovery. We have a 34% interestin both Hobby and Golden Eagle, a 46% interest in Pink, and operate all three.We have identified additional prospects in the area and have plans for furtherexploratory and appraisal drilling this year.

 

Canada

 

As conventional basins in Canada mature, we are focusing our investmenton unconventional resource plays such as shale gas and CBM. In northeastBritish Columbia, we have a material land position of approximately 126,000acres with a 100% working interest in an emerging Devonian shale gas play. Thisplay has the potential to be one of the most significant shale gas plays inNorth America. Our landholdings include approximately 88,000 acres in the DillyCreek area of the Horn River basin. In 2008, we invested approximately $180million to drill, complete and test wells, and build infrastructure. Onehorizontal well was completed and tied in last winter and is producing at ratein line with our expectations and competitor wells. We expect to complete andtie in two wells later this winder. We continue to construct all season roadsto provide year round access to our lands. In 2009, we plan to enhance ourunderstanding of drilling and fracing techniques for this play with aninvestment plan that includes drilling and testing multiple wells from a singlepad. We expect three of these wells to be drilled and completed by mid year andon production before winter. The remaining wells will be drilled in the futureif economic and financial conditions improve. Further appraisal activity isrequired before we can finalize estimates, establish commerciality and book provedreserves.

 

In 2008, we invested approximately $115 million in exploration anddevelopment activities on our CBM lands and recognized 10 mmboe of provedreserves (10 after royalties). We expect our CBM reserves to grow over thecoming years as additional wells are drilled, development work progresses andmore production history is obtained. Our CBM production continues to increaseas existing wells dewater and we bring new wells on stream. In 2008, ourproduction increased 65% and we exited the year producing approximately 50mmcf/d. Performance is in line with expectations and underscores the increasingvalue of our CBM assets.

 

Elsewhere in Canada, we increased our proved reserves by 3 mmboe (3after royalties), but these additions were offset by negative economic revisionsof 27 mmboe (22 after royalties)

 

**2008 CAPTIAL**

 

 

----

*(1)**      **Mainly Long Lake.*

*(2)**      **Marketing, Corporate and Other.*

** **

****

 

44

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largely relating to our conventional heavy oil properties. Theseeconomic revisions were determined in accordance with current SECrules that require the use of year-end commodity prices and operatingcosts even though we believe year-end operating costs do not reflect thecurrent economic downturn and low commodity price environment.

 

Yemen

 

Yemen remains a significant asset for us and continues to generate cashflow in excess of capital requirements. In 2008, we invested $101 million andadded 12 mmboe (9 after royalties) of proved reserves. We will continue tomaximize the value of these assets over their remaining contract terms andexpect 2009 annual production of between 40,000 and 45,000 boe/d, beforeroyalties.

 

Other Countries

 

Development of the Usan field, offshore West Africa, is underway withfirst production expected in 2012. In 2008, our capital investment at Usan onblock OML-138 focused on detailed engineering, procurement and the initialfabrication of equipment. The development of Usan includes a FPSO with theability to process 180,000 bbls/d and store up to two million barrels of oil.In 2009, we are scheduled to begin fabrication of the FPSO hull and topsidefacilities, begin development drilling, and complete detailed engineering andprocurement. We are also evaluating plans for further exploration on thisblock. We have a 20% interest in exploration and development along with TotalE&P Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited(30%) and Esso Exploration and Production Nigeria (Offshore East) Limited(30%).

 

In the fourth quarter of 2008, Nigerian authorities approved theacquisition of interests in offshore block OPL-223. We have a 20% fundinginterest and 18% beneficial interest in this block. Our partners are TotalE&P Nigeria Limited (18% and Operator) ChevronTexaco Nigeria Deepwater F Limited(27%), Esso Exploration and Production (Upstream) Limited (27%) and NigerianPetroleum Development Company Limited (10% carried interest). During 2009, weplan to advance evaluation of the prospects on this block.

 

Other international include our producing assets in Colombia and ourexploration program in the Norwegian North Sea. In 2008, we investedapproximately $95 million in Norway, primarily to acquire seismic data.

 

Syncrude

 

At Syncrude, we invested $55 million in 2008 and added 8mmboe (7 afterroyalties) of proved reserves. In 2009, we have one coker turnaround scheduledin the second quarter and expect annual production of between 20,000 and 25,000bbls/d before royalties.

 

Chemicals

 

Higher expenditures in 2008 related to the technology conversionproject at our North Vancouver chlor-alkali plant. This was offset by lowerexpenditures related to the expansion of our Brandon sodium chlorate plant,which was completed in early 2008.

 

45

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**FINANCIAL RESULTS**

 

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

 
| **(Cdn$ millions)**                                    | ** ** | **2008 vs 2007** | ** ** | **2007 vs 2006** | ** ** |
|-------------------------------------------------------------|------------|----------------------------|------------|----------------------------|------------|
| **Net  Income for 2007 and 2006**                           | ** ** | **1,086**                  | ** ** | **601**                    | ** ** |
| ** **                                                  | ** ** | ** **                 | ** ** | ** **                 | ** ** |
| Favourable (unfavourable)  variances:(1)                    | ** ** | ** **                 | ** ** | ** **                 | ** ** |
|                                                        | ** ** | ** **                 | ** ** | ** **                 | ** ** |
| Production Volumes, After  Royalties                        |       |                       |       |                       |       |
| Crude Oil                                                   |       | 40                         |       | 1,354                      |       |
| Natural Gas                                                 |       | (22                        | )          | (17                        | )          |
| Change in Crude Oil  Inventory                              |       | 13                         |       | 22                         |       |
| Total Volume Variance                                       |       | 31                         |       | 1,359                      |       |
|                                                        |       |                       |       |                       |       |
| Realized Commodity Prices                                   |       |                       |       |                       |       |
| Crude Oil                                                   |       | 1,495                      |       | 308                        |       |
| Natural Gas                                                 |       | 119                        |       | (24                        | )          |
| Total Price Variance                                        |       | 1,614                      |       | 284                        |       |
|                                                        |       |                       |       |                       |       |
| Operating Expense                                           |       |                       |       |                       |       |
| Conventional  Oil & Gas                            |       | (49                        | )          | (178                       | )          |
| Syncrude                                                    |       | (72                        | )          | (21                        | )          |
| Total Operating Expense  Variance                           |       | (121                       | )          | (199                       | )          |
|                                                        |       |                       |       |                       |       |
| Depreciation, Depletion,  Amortization and Impairment       |       |                       |       |                       |       |
| Oil & Gas and  Syncrude                            |       | (228                       | )          | (636                       | )          |
| Other                                                       |       | (19                        | )          | (7                         | )          |
| Total DD&A                                              |       | (247                       | )          | (643                       | )          |
|                                                        |       |                       |       |                       |       |
| Exploration Expense                                         |       | (76                        | )          | 36                         |       |
|                                                        |       |                       |       |                       |       |
| Net Energy Marketing  Revenue                               |       | (424                       | )          | (373                       | )          |
|                                                        |       |                       |       |                       |       |
| Chemicals Contribution                                      |       | (76                        | )          | 27                         |       |
|                                                        |       |                       |       |                       |       |
| General and Administrative  Expense                         |       | 117                        |       | 181                        |       |
|                                                        |       |                       |       |                       |       |
| Interest Expense                                            |       | 74                         |       | (115                       | )          |
|                                                        |       |                       |       |                       |       |
| Current Income Taxes                                        |       | (425                       | )          | (66                        | )          |
|                                                        |       |                       |       |                       |       |
| Future Income Taxes                                         |       | (240                       | )          | (43                        | )          |
|                                                        |       |                       |       |                       |       |
| Other                                                       |       |                       |       |                       |       |
| Block 51 Settlement                                         |       | —                     |       | 151                        |       |
| Business Interruption  Insurance Proceeds                   |       | —                     |       | (154                       | )          |
| Increase (Decrease) in  Fair Value of Crude Oil Put Options |       | 246                        |       | (32                        | )          |
| Other                                                       |       | 156                        |       | 72                         |       |
|                                                        |       |                       |       |                       |       |
| **Net  Income for 2008 and 2007**                           | ** ** | **1,715**                  | ** ** | **1,086**                  | ** ** |

 

----

*(1)**      **All amounts are presented before provision for income taxes.*

 

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

 

46

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**OIL & GAS AND SYNCRUDE**

 

**Production**

 
| ** **                    | ** ** | **2008**                 | ** ** | **2007**             | ** ** | **2006**                 | ** ** |
|-------------------------------|------------|--------------------------|------------|----------------------|------------|--------------------------|------------|
| ** **                    | ** ** | **Before  Royalties(1)** | ** ** | **After  Royalties** | ** ** | **Before  Royalties(1)** | ** ** | **After  Royalties** | ** ** | **Before  Royalties(1)** | ** ** | **After  Royalties** | ** ** |
| **Oil and  Liquids**(mbbls/d) |       |                     |       |                 |       |                     |       |   |   |   |   |   |   |
| United Kingdom                |       | 99.7                     |       | 99.7                 |       | 81.2                     |       | 81.2 |   | 16.9 |   | 16.9 |   |
| Yemen                         |       | 56.6                     |       | 30.6                 |       | 71.6                     |       | 39.8 |   | 92.9 |   | 51.8 |   |
| Canada                        |       | 16.2                     |       | 12.3                 |       | 17.1                     |       | 13.4 |   | 20.0 |   | 15.8 |   |
| United States                 |       | 9.3                      |       | 8.1                  |       | 16.4                     |       | 14.5 |   | 17.0 |   | 15.0 |   |
| Other Countries               |       | 5.8                      |       | 5.3                  |       | 6.2                      |       | 5.7 |   | 6.3 |   | 5.7 |   |
| Long Lake Bitumen(2)          |       | 3.9                      |       | 3.9                  |       | —                   |       | — |   | — |   | — |   |
| Syncrude (mbbls/d)(3)         |       | 20.9                     |       | 18.2                 |       | 22.1                     |       | 18.8 |   | 18.7 |   | 16.9 |   |
|                          |       | 212.4                    |       | 178.1                |       | 214.6                    |       | 173.4 |   | 171.8 |   | 122.1 |   |
|                          |       |                     |       |                 |       |                     |       |   |   |   |   |   |   |
| **Natural  Gas** (mmcf/d)     |       |                     |       |                 |       |                     |       |   |   |   |   |   |   |
| United Kingdom                |       | 18                       |       | 18                   |       | 16                       |       | 16 |   | 20 |   | 20 |   |
| Canada                        |       | 131                      |       | 109                  |       | 118                      |       | 98 |   | 108 |   | 91 |   |
| United States                 |       | 78                       |       | 66                   |       | 101                      |       | 86 |   | 111 |   | 94 |   |
|                          |       | 227                      |       | 193                  |       | 235                      |       | 200 |   | 239 |   | 205 |   |
|                          |       |                     |       |                 |       |                     |       |   |   |   |   |   |   |
| **Total** (mboe/d)            | ** ** | **250**                  | ** ** | **210**              | ** ** | **254**                  | ** ** | **207** | ** ** | **212** | ** ** | **156** | ** ** |

 

----

*(1)**      **We have presented production volumes before royalties as wemeasure our performance on this basis consistent with other Canadian oil andgas companies.*

*(2)**      **Pre-operating revenues and costs associated with Long Lakebitumen are capitalized as development costs until we reach commercialoperations.*

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

 

2008 vs 2007 — Higher net production increased income by $31 million

 

Production after royalties in 2008 was slightly higher than 2007. AtBuzzard, a full year of production offset declines at our maturing Yemen fieldsand hurricane interruptions in the US Gulf of Mexico. At Long Lake, increasingbitumen production contributed 3,900 boe/d to our 2008 volumes.

 

The following table summarizes our production changes year over year:

 
| **(mboe/d)**         | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** |
|----------------------|------------|-----------------------|------------|----------------------|------------|
| 2007 Production      |       | 254                   |       | 207                  |       |
| Production Changes   |       |                  |       |                 |       |
| United Kingdom       |       | 19                    |       | 19                   |       |
| Yemen                |       | (15                   | )          | (9                   | )          |
| United States        |       | (11                   | )          | (10                  | )          |
| Long Lake Bitumen    |       | 4                     |       | 4                    |       |
| Other                |       | (1                    | )          | (1                   | )          |
| **2008  Production** | ** ** | **250**               | ** ** | **210**              | ** ** |

 

Fourth quarter production averaged 230,000 boe/d (198,000 afterroyalties), down 16,000 boe/d from the prior quarter and 11,000 boe/d from thefourth quarter of 2007. Shut-in production in the Gulf of Mexico was theprimary cause for the shortfall as US rates averaged 9,000 boe/d during thefourth quarter. The US was producing approximately 30,000 boe/d prior to thehurricanes. These shortfalls were partially offset by production at Long Lakewhere we averaged 6,500 boe/d for the quarter.

 

In 2009, we expect production to grow approximately 5% to 10% comparedto 2008 and range between 255,000 and 270,000 boe/d before royalties. On anafter-royalties basis, we expect production to grow 7% to 14% and range between225,000 and 240,000 boe/d, reflecting growth in the UK North Sea and at Long Lakewhere royalties are low. Increases are expected to come from Ettrick in the UKNorth Sea, Longhorn in the US Gulf of Mexico and the Long Lake Project asbitumen rates increase.

 

Production volumes discussed in this section represent our workinginterest before royalties.

 

47

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*United Kingdom*

 

UK production for the year averaged 102,700 boe/d, 22% higher than2007. This increase was primarily the result of a full year’s high-margin,royalty-free Buzzard production, which averaged 88,200 boe/d. The Buzzardplatform operated above expectations with minimal downtime. We are pursuingdebottlenecking opportunities to increase processing capacity on the platformand export facilities.

 

Construction of the fourth platform at Buzzard started during the year.This platform will include production sweetening facilities designed to handlehigher levels of hydrogen sulphide previously identified in the reservoir. Theplatform is expected to be in service in 2010 at a projected cost of betweenUS$350 million and US$400 million, net to us.

 

At Scott/Telford, higher than expected natural declines, combined withincreased downtime for maintenance, reduced production by 36% to 10,500 boe/d.Maintenance on the Scott platform focused on resolving ongoing power supplyissues. Downtime was also associated with platform and subsea workoverscompleted during the year. We recently started an infill drilling program atScott to minimize the natural declines.

 

In 2009, we plan to drill up to three development wells atScott/Telford and we anticipate bringing production on stream at Ettrick in thenext few months. We expect production from the North Sea to average between100,000 and 115,000 boe/d in 2009. Our expected production for 2009 takes intoaccount expected downtime.

 

*Yemen*

 

In 2008, production from our Masila field declined 19% compared to lastyear and averaged 45,900 boe/d. This decline is consistent with ourexpectations as the field matures. We are targeting select infill developmentdrilling opportunities due to the maturity of the field. During the year, wedrilled 20 development wells and two sidetrack wells as we concentrate ourdrilling program on maximizing reserve recoveries and economic returns, priorto the 2011 expiry of our contract. In 2009, we plan to drill up to 35development wells.

 

Production at our East Al Hajr field on Block 51 averaged 10,700 boe/dfor 2008 and reflects natural declines and drilling fewer development wells. Wedrilled six development wells and one exploration well this year and plan todrill up to five development wells in 2009. We expect our share of Yemenproduction to average between 40,000 and 45,000 boe/d in 2009.

 

*Canada*

 

Production in Canada (excluding oil sands) increased 3% in 2008, primarilyas a result of increasing CBM volumes, offset by a decline in heavy oilproduction. CBM production increased 65% to average 43 mmcf/d during the yearas we brought additional wells and facilities on stream and as existing wellsin our Fort Assiniboine development inclined as they de-watered. Productionfrom our heavy oil properties fell 7% in 2008. A successful capital investmentprogram slowed declines in our maturing fields. Our natural gas production inthe Medicine Hat region and at Balzac was comparable with the previous year.

 

Bitumen production at Long Lake averaged 3,900 boe/d (net to us) during2008. We continued to inject steam into the reservoir and resolved a number ofstart-up issues with the SAGD operations during the year. The upgrader beganproducing premium synthetic crude oil in January 2009. The project isupgrading bitumen from our SAGD production and third-party bitumen purchases,and is currently producing between 10,000 and 15,000 boe/d of premium syntheticcrude (between 6,300 and 9,750 net to us). Our SAGD operations and the upgraderstart up were impacted by normal start-up challenges and extraordinarily coldweather. As a result, bitumen production averaged 13,200 boe/d for the fourthquarter (6,600 net to us), although rates are back up to 20,000 boe/d (13,000net to us) in late January 2009. In early 2009, we increased our interestin the Long Lake Project from 50% to 65%.

 

In 2009, we expect our share of production from Canada to averagebetween 35,000 and 40,000 boe/d and bitumen SAGD production at Long Lake isexpected to average between 20,000 and 25,000 boe/d (net to us).

 

**2008 PRODUCTION BEFORE ROYALTIES**

 

 

**2007 PRODUCTION BEFORE ROYALTIES**

 

 

48

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*United States*

 

Our US production fell 33%, or about 11,000 boe/d from 2007, ashurricanes in the Gulf of Mexico temporarily shut-in production in the region.Prior to Hurricanes Gustav and Ike, we were producing approximately 30,000boe/d. Production was reduced to 6,000 boe/d immediately after the hurricanes.Our properties at Gunnison, West Cameron and Eugene Island came back on streamduring the fourth quarter and we exited the year producing approximately 12,000boe/d. Production at Aspen recommenced at the end of January 2009. Wrigleyremains shut in as third-party facilities have not yet been fully repaired.This work is ongoing and we expect production will be restored to pre-hurricanerates in the first quarter of 2009. Our Green Canyon 6, 50 and 137 deep-waterfields remain shut in following the destruction of the third-party processingplatform. We are currently evaluating production options for these fields.

 

Prior to the hurricanes, Aspen was producing 5,000 boe/d, down 50% from2007. The decline is a result of: (i) natural decline rates;(ii) increased downtime due to third-party facility maintenance; and(iii) third-party limitations on handling higher water volumes. Productionwas curtailed while increased water handling equipment was installed on the Shell-operatedplatform. We expect production rates from Aspen to increase slightly in 2009 asthe platform can now handle additional amounts of water from the field.

 

Gunnison suffered only minor damage during the storms and was back onstream in October. Pre-hurricane Gunnison production averaged 5,000 boe/d, down26% from 2007. Lower volumes due to natural declines and ongoing maintenancewere partially offset by an additional development well drilled during the yearand successful recompletions.

 

Our shelf production decreased 3,800 boe/d as a result of naturaldeclines, approximately 27% below 2007 rates. During the year, we completedseveral successful recompletions and workovers to enhance performance; however,we are minimizing the capital invested in our mature shelf assets.

 

In 2009, we expect production from the Gulf of Mexico to averagebetween 20,000 and 25,000 boe/d.

 

*Other Countries*

 

Production from Guando in Colombia decreased marginally to 5,800 boe/din 2008. The infill drilling program was completed in the second quarter of 2008;however, the full benefit of this program was not realized as landslides inApril shut-in six wells. Most of these wells are back on stream. Under theterms of our license, our interest in the field will decrease by half to 10% oncethe field has produced 60 million barrels, which we expect to occur mid 2009.We expect our share of production to average between 3,000 and 5,000 boe/d in2009.

 

*Syncrude*

 

Syncrude production decreased 5% to average 21,000 boe/d during theyear. Production has been impacted by several factors during the yearincluding: (i) two planned coker turnarounds and other maintenance;(ii) shut down of the sulphur plant for maintenance; (iii) reductionin shipments of synthetic crude from outages in the Pembina pipeline; and(iv) shortage of bitumen supply as a result of production challenges inthe mines, which have since been resolved. In 2009, we expect production toaverage between 20,000 and 25,000 boe/d.

 

In late 2008, the Alberta government and the Syncrude owners reached anagreement to amend their existing royalty agreement. The new royalty agreementis expected to increase our after-royalty production volumes.

 

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

 

Production before royalties increased 20% from 2006 (33% afterroyalties). This increase reflected the start up of Buzzard production in early2007, partially offset by declines in our maturing Yemen fields. The additionof high-margin, royalty-free Buzzard volumes increased North Sea production by64,000 boe/d (net to us). Buzzard production ramped up to peak production in2007 and produced above design rates during the year. Production in Canada wascomparable with 2006 rates as we continued to offset mature base declines withstrategic capital investment.

 

In the Gulf of Mexico, deep-water production from Aspen and Gunnisonwas down from 2006 from natural field declines. The Wrigley development came online mid 2007 but rates were lower due to third-party production restrictions.At Syncrude, production was 18% higher than 2006 as the Stage 3 expansioncontributed a full year of production.

 

49

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**Commodity Prices**

 
| ** **                                                     | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|----------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| **Crude Oil**                                                  |       |       |       |       |       |       |       |
| West Texas Intermediate  (WTI) (US$/bbl)                       |       | 99.65      |       | 72.31      |       | 66.22      |       |
| Benchmark  Differentials(1) (US$/bbl)                     |       |       |       |       |       |       |       |
| Heavy Oil                                                      |       | 20.27      |       | 23.44      |       | 21.79      |       |
| Dated Brent                                                    |       | 2.66       |       | (0.21      | )          | 1.08       |       |
| Mars                                                           |       | 6.21       |       | 5.67       |       | 7.34       |       |
| Masila                                                         |       | 4.31       |       | 0.50       |       | 3.00       |       |
| Realized Prices from  Producing Assets (Cdn$/bbl)              |       |       |       |       |       |       |       |
| United Kingdom                                                 |       | 96.23      |       | 76.30      |       | 71.19      |       |
| Yemen                                                          |       | 99.87      |       | 76.29      |       | 71.57      |       |
| Canada                                                         |       | 74.51      |       | 44.07      |       | 42.79      |       |
| United States                                                  |       | 104.94     |       | 69.83      |       | 65.80      |       |
| Other Countries                                                |       | 98.98      |       | 71.29      |       | 66.09      |       |
| Syncrude                                                       |       | 105.47     |       | 79.76      |       | 72.32      |       |
|                                                           |       |       |       |       |       |       |       |
| Corporate Average  (Cdn$/bbl)                                  |       | 96.92      |       | 73.43      |       | 67.50      |       |
| **Natural  Gas**                                               |       |       |       |       |       |       |       |
| New York Mercantile  Exchange (US$/mmbtu)                      |       | 8.90       |       | 7.12       |       | 6.99       |       |
| AECO (Cdn$/mcf)                                                |       | 7.71       |       | 6.26       |       | 6.62       |       |
| Realized Prices from  Producing Assets (Cdn$/mcf)              |       |       |       |       |       |       |       |
| United Kingdom                                                 |       | 6.78       |       | 4.71       |       | 7.43       |       |
| Canada                                                         |       | 7.73       |       | 6.32       |       | 6.49       |       |
| United States                                                  |       | 10.07      |       | 7.80       |       | 7.86       |       |
|                                                           |       |       |       |       |       |       |       |
| Corporate Average  (Cdn$/mcf)                                  |       | 8.44       |       | 6.81       |       | 7.18       |       |
|                                                           |       |       |       |       |       |       |       |
| **Nexen’s  Average Realized Oil and Gas Price**(Cdn$/boe) | ** ** | **89.78**  | ** ** | **68.46**  | ** ** | **62.92**  | ** ** |
| ** **                                                     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Average Foreign Exchange  Rate—Canadian to US Dollar      |       | 0.9381     |       | 0.9304     |       | 0.8818     |       |

 

----

*(1)**      **These differentials are a discount/(premium) to WTI.*

 

2008 vs 2007 — Higher realized prices increased net income $1,614million

 

In 2008, commodity prices reached record highs but declined significantlyin the fourth quarter. WTI averaged US$99.65/bbl for the year, 38% higher than2007, while Dated Brent increased 34% over the same period. Our averagerealized crude oil price increased 32% from $73.43/bbl to $96.92/bbl. Duringthe year, NYMEX gas price increased 25% and AECO increased 23%, averagingUS$8.90/mmbtu and $7.71/mcf, respectively. During the same period, ourcorporate average realized gas price increased 24% to $8.44/mcf, as our gassales are primarily based off of NYMEX and AECO prices. Compared to 2007, theUS dollar weakened relative to the Canadian dollar. As a result, our realizedcrude oil and natural gas price decreased by approximately $0.80/bbl and$0.07/mcf, respectively and our net sales were lower by approximately $56 million.

 

Commodity prices fell dramatically during the fourth quarter as theglobal economic crisis reduced demand for oil and gas. WTI averagedUS$58.73/bbl for the quarter, down 50% from the previous quarter and 35% fromthe same period last year. Our realized average oil price was $59.90/bbl in thefourth quarter compared to $115.56/bbl in the third quarter. NYMEX gas pricesalso fell during the fourth quarter to average US$6.41/mcf.

 

*Crude Oil Reference Prices*

 

Crude oil prices were volatile in 2008, reaching an all-time high ofUS$147.27/bbl in mid-July, before declining to close the year at US$44.60/bbl.The increase during the first half of the year was driven by the weakened USdollar and global political tensions as well as by traditional supply and demandfundamentals. The main driver of falling prices in the second half of the yearwas a weak global economy following the worldwide financial crisis, whichdramatically reduced demand for all commodities.

 

The US dollar weakened during the first half of 2008 and fell to anall-time low against the Euro as the financial markets reacted to the threat ofa US recession and the global credit crisis. Investors re-directed theirinvestments into commodity markets to hedge against the weak dollar and inflation,which contributed to the increase in oil prices.

 

50

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In the second half of the year, the market’s focus moved from concernsabout adequate future supply to fears of declining demand. Geopolitical eventsimpacting global supply had minimal impact on prices as these events wereovershadowed by the weak global economy and declining oil demand. Near-term oilmarket fundamentals weakened and year-end crude oil inventories were highrelative to the last five years.

 

*Crude OilDifferentials*

 

In Canada, heavy crude oildifferentials averaged US$20.27/bbl (20% of WTI) for the year, compared toUS$23.44/bbl (32% of WTI) in 2007. Demand for heavy oil increased when BP’sWhiting refinery came back online in the first quarter of 2008. DecliningVenezuelan and Mexican heavy oil production, a slower ramp up of industry oil sandsproduction, higher demand in the summer asphalt season and the desire to runheavier crude in a low refinery margin environment all contributed to narrowerdifferentials earlier in the year. As WTI prices declined in the fall, theheavy differential widened relative to WTI. The onset of winter and seasonallylower demand contributed to the widening differential.

 

The Brent/WTI differentialweakened during 2008, with Brent trading at a discount of US$2.66/bbl comparedto a premium of US$0.21/bbl in 2007. The WTI/Brent price differential wasvolatile in 2008, but WTI traded at a premium to Brent for most of the year.Higher than expected freight costs and storm displacements during the hurricaneseason increased the WTI premium over Brent, which peaked in November at overUS$5.00/bbl. Since then, weak demand and higher Cushing inventories havedepressed WTI prices and the differential narrowed late in the year.

 

The US Gulf Coast Marsdifferential widened slightly, averaging US$6.21/bbl in 2008 compared toUS$5.67/bbl last year. Overall, the differential remained historically highduring the year. Higher WTI inventories at Cushing in December caused theWTI/Mars differential to narrow towards the end of the year.

 

The Yemen Masila differentialwidened substantially relative to WTI during 2008, averaging US$4.31/bblcompared to US$0.50/bbl last year. Yemen Masila traded at a discount to WTI in2008, reflecting the impact of stronger WTI versus Brent pricing as Masilacrude is typically priced off Brent.

 

*Natural GasReference Prices*

 

NYMEX natural gas pricesaveraged US$8.90/mmbtu in 2008, 25% higher than 2007. Higher crude oil prices,low LNG imports and lower storage levels at the end of the 2007/2008 winterwithdrawal season provided support for prices in the first half of the year.Since mid-year, a weak US economy and significant supply increases inunconventional production increased inventory levels and reduced prices.Declining crude oil prices and continuing weakness in the global economy couldlead to more LNG cargoes coming to North America during 2009, adding downwardpressure on natural gas prices. A colder than expected 2008/2009 winter weatherprovided some offset to the bearish factors impacting gas prices.

 

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

 

Average WTI and Dated Brent inUS dollars were 9% and 11% higher, respectively, from the prior year, and ouraverage realized crude oil price increased 9% to $73.43/bbl. Our higher averagerealized price reflects the change in production mix with the addition of newhigh-quality Buzzard production. This change helped to offset the impact of theweaker US dollar on our Canadian dollar realized prices. Our realized naturalgas price fell 5% from 2006 as a result of the stronger Canadian dollar,despite NYMEX increasing 2% in the same period. The weaker US dollar reducednet sales by approximately $225 million, and reduced our realized crude oil andnatural gas prices by approximately $3.20/bbl and $0.30/mcf, respectively, as comparedto 2006.

 
| **2008  MONTHLY AVERAGE OIL PRICE** | **2008  MONTHLY AVERAGE NATURAL GAS PRICE** |
|-------------------------------------|---------------------------------------------|
| (US$/bbl)                           | (US$/mmbtu)                                 |
|                                     |                                             |

 

51

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**OperatingExpenses**

 
| ** **                   | ** ** | **2008**                 | ** ** | **2007**             | ** ** | **2006**                 | ** ** |
|------------------------------|------------|--------------------------|------------|----------------------|------------|--------------------------|------------|
| **(Cdn$/boe)**               | ** ** | **Before  Royalties(1)** | ** ** | **After  Royalties** | ** ** | **Before  Royalties(1)** | ** ** | **After  Royalties** | ** ** | **Before  Royalties(1)** | ** ** | **After  Royalties** | ** ** |
| **Conventional Oil and Gas** |       |                     |       |                 |       |                     |       |   |   |   |   |   |   |
| United Kingdom               |       | 6.75                     |       | 6.75                 |       | 6.94                     |       | 6.94 |   | 11.28 |   | 11.28 |   |
| Yemen                        |       | 8.51                     |       | 15.88                |       | 6.56                     |       | 12.00 |   | 4.45 |   | 8.11 |   |
| Canada                       |       | 13.12                    |       | 16.38                |       | 12.91                    |       | 15.93 |   | 10.31 |   | 12.73 |   |
| United States                |       | 11.57                    |       | 13.48                |       | 8.43                     |       | 9.69 |   | 8.17 |   | 9.45 |   |
| Other Countries              |       | 4.52                     |       | 4.91                 |       | 3.45                     |       | 3.76 |   | 2.87 |   | 3.13 |   |
| Average Conventional         |       | 8.68                     |       | 10.40                |       | 7.89                     |       | 9.75 |   | 6.95 |   | 9.69 |   |
|                         |       |                     |       |                 |       |                     |       |   |   |   |   |   |   |
| **Synthetic Crude Oil**      |       |                     |       |                 |       |                     |       |   |   |   |   |   |   |
| Syncrude                     |       | 36.53                    |       | 42.04                |       | 25.80                    |       | 30.32 |   | 27.53 |   | 30.43 |   |
| **Average Oil and Gas**      |       | 11.04                    |       | 13.18                |       | 9.45                     |       | 11.63 |   | 8.77 |   | 11.96 |   |

 

----

| *(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.* |
|-------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

2008 vs 2007—Higher operating expenses decreased net income by $121million

 

Overall, operating costsincreased 14% from 2007, primarily due to Buzzard being on-stream for the fullyear and higher expenditures at Syncrude. Our production mix continues tochange as additional Buzzard volumes are offset by lower volumes in Yemen andthe US Gulf of Mexico. Changes in our production profile reduced our corporateaverage by $0.35/boe, as Buzzard has lower operating costs per barrel.

 

In the UK North Sea, operatingcosts increased 19%. The increase is attributable to a full year’s productionat Buzzard, compared to 2007 when we were ramping up production. In addition,transportation costs increased from higher volumes and increased tariffcharges. Elsewhere in the UK North Sea, operating costs increased whileproduction declined, increasing our corporate average by $0.45/boe. Themajority of the cost increase is due to platform maintenance at Scott/Telford,including: (i) additional diesel costs for turbine repairs; (ii) maintenance onour water injection and power generation facilities; and (iii) subseamaintenance.

 

In Yemen, Masila and Block 51increased our corporate average by $0.32/boe and $0.21/boe, respectively, as aresult of lower production rates. Our operating costs are focused on servicerig activity and maintenance programs for existing wells. In the US Gulf ofMexico, operating costs were 8% lower than 2007; however, lower production as aresult of the hurricanes increased the average unit cost by $0.30/boe.

 

Operating costs in Canada weremarginally higher than last year. Costs in our heavy oil operations increasedas a result of higher salaries, utilities and trucking costs. While CBM costswere slightly higher as the number of producing wells increased, theincremental volumes reduced our average cost per barrel. At our natural gasproperties, a combination of increased downhole activity and surfacemaintenance resulted in higher operating costs. These increases were offset bylower costs at our Balzac gas plant, which had a turnaround in the previousyear.

 

Syncrude operating costs were$72 million or 35% higher than the prior year and increased our corporateaverage by $0.91/boe. A number of factors contributed to the higher operatingcosts including: (i) higher contracting costs to increase the mineable oreinventory for bitumen supply; (ii) purchasing additional third-party bitumen toupgrade; (iii) higher natural gas prices in the first half of 2008; and (iv)unscheduled and extended maintenance. We expect Syncrude operating costs willdecrease slightly in 2009.

 

US-dollar denominated operatingcosts were lower when translated to Canadian dollars as a result of the weakerUS dollar for the majority of the year. This decreased our corporate average by$0.23/boe for 2008.

 

2007 vs2006—Higher operating expenses decreased net income by $199 million

 

Our operating costs increased$199 million from 2006 primarily as a result of Buzzard coming on stream inearly 2007 and higher Syncrude production. Our production mix also changed fromlast year as a result of this production, altering our average unit cost. Operatingcosts at Buzzard are lower than our corporate average, reducing our corporateaverage by $1.58/boe. However, the higher-cost Syncrude barrels increased ourcorporate average by $0.74/boe.

 

At Masila in Yemen, operatingcosts increased with higher service rig activity and maintenance programs. Thehigher costs and 

 

52

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lower production increased our corporate average by $0.57/boe.Similarly at Block 51, our operating expenditures were higher as additional servicerig activity and higher water handling, fuel and equipment costs increasedoperating expenditures. The higher costs increased our corporate average$0.37/boe.

 

Canadian production increased our corporate average $0.50/boe duringthe year as a result of industry cost pressures, the extended Balzac turnaroundand lower production. Our heavy oil properties have higher unit operating costsas many of the costs are fixed in nature and heavy oil production is declining.Operating costs have also increased with additional CBM wells coming on-streamat Fort Assiniboine. Unit operating costs are initially higher as we de-waterthe wells to stimulate gas production.

 

In the Gulf of Mexico, while total operating costs remained consistentyear over year, lower production increased our corporate average by $0.18/boe.During 2007, industry pressures increased costs and we performed additionaldownhole and surface maintenance activity to maintain production. However,these costs had minimal impact on our corporate average when compared to lastyear as our 2006 costs included extended maintenance and turnaround activity atEugene Island on the shelf.

 

In the UK North Sea, our Scott/Telford costs increased our corporateaverage by $0.33/boe. During the year, our total operating expendituresincreased as we performed maintenance and work overs on the platform andproducing wells, including repairing turbines and improving water injectionfacilities.

 

Lower Syncrude operating costs reduced our corporate average by $0.16/boe,and were 6% lower than 2006 as the impact of the higher production from theexpansion completed in 2006 was only partially offset by increased maintenancecosts. In 2007, maintenance and turnarounds on the Coker 8-3 and the LC Finerinterrupted production and increased operating costs.

 

US-dollar denominated operatingcosts were lower when translated into Canadian dollars, reducing our corporateaverage $0.26/boe.

 

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

 
| ** **                       | ** ** | **2008**                 | ** ** | **2007**             | ** ** | **2006**                 | ** ** |
|----------------------------------|------------|--------------------------|------------|----------------------|------------|--------------------------|------------|
| **(Cdn$/boe)**                   | ** ** | **Before  Royalties(1)** | ** ** | **After  Royalties** | ** ** | **Before  Royalties(1)** | ** ** | **After  Royalties** | ** ** | **Before  Royalties(1)** | ** ** | **After  Royalties** | ** ** |
| **Conventional Oil and Gas (2)** |       |                     |       |                 |       |                     |       |   |   |   |   |   |   |
| United Kingdom                   |       | 17.72                    |       | 17.72                |       | 19.59                    |       | 19.59 |   | 30.22 |   | 30.22 |   |
| Yemen                            |       | 7.75                     |       | 14.45                |       | 8.15                     |       | 14.92 |   | 9.67 |   | 17.61 |   |
| Canada                           |       | 14.99                    |       | 18.71                |       | 12.46                    |       | 15.37 |   | 11.22 |   | 13.84 |   |
| United States                    |       | 27.46                    |       | 31.97                |       | 22.64                    |       | 26.03 |   | 16.28 |   | 18.84 |   |
| Other Countries                  |       | 7.90                     |       | 8.58                 |       | 3.68                     |       | 4.06 |   | 4.30 |   | 4.69 |   |
| Average Conventional             |       | 15.48                    |       | 18.54                |       | 14.94                    |       | 18.47 |   | 13.12 |   | 18.30 |   |
|                             |       |                     |       |                 |       |                     |       |   |   |   |   |   |   |
| **Synthetic Crude Oil**          |       |                     |       |                 |       |                     |       |   |   |   |   |   |   |
| Syncrude                         |       | 6.39                     |       | 7.35                 |       | 6.59                     |       | 7.74 |   | 4.81 |   | 5.32 |   |
| **Average Oil and Gas**          |       | 14.71                    |       | 17.56                |       | 14.21                    |       | 17.49 |   | 12.38 |   | 16.88 |   |

 

----

| *(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 4 of our Consolidated Financial Statements.*                                                                                                                                 |

 

2008 vs 2007—Higher oil and gas and Syncrude DD&A decreased netincome by $228 million

 

During the fourth quarter, werecorded non-cash impairment charges of $568 million primarily relating to someproperties in the UK North Sea and the Gulf of Mexico. In the North Sea, werecognized an impairment charge of $318 million relating to our Selkirk andEttrick properties. At Selkirk, we expensed $62 million of allocatedacquisition costs as we have no firm development plans. At Ettrick, theimpairment charge largely reflects higher costs and lower reserve estimates. Inthe Gulf of Mexico, our impairment charge relates to four shelf properties($143 million) and our Green Canyon 6 deep-water property ($107 million). Theshelf properties that were impaired are late-life, mature assets that aresensitive to near-term commodity prices. At Green Canyon 6, the impairmentexpense reflects higher costs after Hurricane Ike destroyed a third-partyproduction platform in the third quarter of 2008. This has resulted inunexpected costs to construct new production facilities and, following anevaluation of options, we expect to have production back on stream in late2010.

 

53

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In the UK, our DD&A expenseincreased 14% over last year as a result of additional production from Buzzard.The impact of higher production was offset by a lower DD&A rate at Buzzardwith the addition of new reserves at the beginning of 2008. The lower depletionrate at Buzzard decreased our corporate average rate by $0.74/boe. Elsewhere inthe UK, our depletion rate increased at our mature Scott/Telford and smallerFarragon fields, increasing our corporate average by $0.47/boe.

 

In the Gulf of Mexico, reserverevisions at the end of 2007 resulted in higher depletion rates in 2008 andincreased our corporate average unit cost by $0.59/boe.

 

Depletion of our Canadianassets increased our corporate average rate by $0.38/boe and is primarily dueto our CBM projects in central Alberta. During the year, we invested capital innew wells and facilities. A difference exists between the timing of capitalexpenditures and the recognition of the reserves. This delay results in highinitial depletion rates for our CBM projects. As additional reserves can berecognized, depletion rates should decrease.

 

In Colombia, our depletion ratedoubled from 2007, a result of increased capital costs and lower reserveestimates. This increased our corporate average rate by $0.10/boe.

 

The stronger Canadian dollarrelative to the US dollar decreased our corporate average DD&A rate by$0.45/boe as our US and international depletion is denominated in US dollars.

 

2007 vs 2006—Higher oil and gasand 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, Vermilion 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 investment in developmentdrilling resulted in negative reserve revisions. While we were encouraged bywell log data indicating thick pay zones, well deliverability rates could notbe sustained. This likely indicates barriers within this section of thereservoir. At Vermilion 320/340 and West Cameron 170, negative reserverevisions primarily related to gas properties, where unsatisfactory investmentresults, production performance, revised mapping and higher projected operatingcosts resulted in a downward revision to reserves estimates. The carryingvalues of these properties were reduced to their estimated fair value.

 

Production from Buzzardincreased our corporate average unit DD&A rate by $1.44/boe. Buzzard costswere higher than our corporate average as they include acquisition and projectcompletion costs. We recognized additional proved reserves at the end of 2006for our other UK assets, which lowered the corporate average $0.59/boe in 2007.

 

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 landacquisitions in 2006. In the Gulf of Mexico, unsuccessful development drillingat Aspen and on the shelf increased our capital base, increasing our corporateaverage 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.

 

**ExplorationExpense**

 
| **(Cdn$ millions)**                                | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|---------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Seismic                                                 |       | 137        |       | 123        |       | 128        |       |
| Unsuccessful Drilling                                   |       | 203        |       | 126        |       | 169        |       |
| Other                                                   |       | 62         |       | 77         |       | 65         |       |
| **Total Exploration Expense**                           | ** ** | **402**    | ** ** | **326**    | ** ** | **362**    | ** ** |
| ** **                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| New Growth Exploration                                  |       | 582        |       | 573        |       | 491        |       |
| Geological and Geophysical Costs                        |       | 137        |       | 123        |       | 128        |       |
| **Total Exploration Expenditures**                      | ** ** | **719**    | ** ** | **696**    | ** ** | **619**    | ** ** |
| ** **                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Exploration Expense as a % of Exploration  Expenditures |       | 56         | %          | 47         | %          | 58         | %          |

 

54

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2008 vs 2007—Higher explorationexpense reduced net income by $76 million

 

Our total explorationexpenditures increased $23 million over last year. We focused our investments onexploratory drilling in the US Gulf of Mexico, UK North Sea and CBM in Canada,and on acquiring seismic data in Norway. Exploration expense increased 23% overthe same period due to higher seismic data acquisitions and unsuccessfulexploration wells.

 

In the Gulf of Mexico, wedrilled two successful deep-water exploration wells early in 2008 at GreenCanyon 448 and Mississippi Canyon 72. Elsewhere in the deep water, we drilledtwo unsuccessful wells. At Fredericksburg, we drilled to a depth of 24,560 feetbut failed to encounter commercial hydrocarbons. This well was subsequentlyabandoned and $24 million in exploration costs were written off. Ourunsuccessful exploration well at Sapphire resulted in a $28 million expense. Weare currently drilling our Cote de Mer prospect and results are expected mid2009.

 

In the UK North Sea, we hadsuccesses at Blackbird, Pink, Bugle and Rochelle. Blackbird is located 6 kmsouth of Ettrick and production could be tied to the Ettrick FPSO, followingadditional appraisal drilling and development evaluation. At Pink, we drilled asuccessful exploration well and sidetrack, and we are currently evaluatingdevelopment options, including co-development with our previous Golden Eaglediscovery. We recently completed drilling a successful appraisal well atRochelle where we have a 44% non-operated interest. Rochelle is locatedapproximately 20 km south of the Scott/Telford fields. During the year, wedrilled a dry hole at Full Moon which cost $16 million and we expensed $32million of drilling costs for our Selkirk prospect which we do not plan todevelop at this time.

 

In Canada, we expensed $67million for unsuccessful CBM exploration in Alberta. The costs relate to ourCBM exploration activities in central Alberta where we have no futuredevelopment plans. We continue to investigate the CBM potential of other areas.

 

During 2008, seismic dataacquisition costs were 11% higher than 2007. Norway seismic acquisitionsincreased 47% during the year when we obtained data on newly acquired blocks inthe Norwegian North Sea. In the US Gulf of Mexico, our seismic investmentdecreased from last year as we are focusing on analyzing the seismic dataacquired over the past couple of years. Elsewhere, we acquired seismic data inthe UK North Sea, Nigeria and Colombia.

 

2007 vs 2006—Lower explorationexpense increased net income by $36 million

 

We invested almost $700 millionin exploration-oriented activities in 2007, primarily related to drilling inthe Gulf of Mexico, UK North Sea and CBM in Canada, and acquiring seismic datain the Gulf of Mexico and Norway. In addition, we acquired material landpositions in the Gulf of Mexico, and in northeast British Columbia related toan emerging Devonian shale gas play in the Horn River basin.

 

Exploration expense decreased$43 million or 25% from 2006 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 the deep-water Gulf ofMexico, we drilled a successful appraisal well at Longhorn and evaluatedresource estimates. Development of Longhorn is underway and production isexpected to begin in 2009. Also in the deep water, our Vicksburg prospect wasdrilled to a depth of 25,400 feet and encountered hydrocarbons. Core wasrecovered from the well and studies are underway to assess the potentialproductivity. Our unsuccessful drilling results in the Gulf of Mexico wereprimarily on the shelf where we expensed $35 million for dry holes. In the deepwater, we drilled a sidetrack at Aspen targeting two zones in deeper sands;however, results from the lowest zone were unsuccessful and we expensed $20million for a portion of the drilling costs of the well.

 

In the UK North Sea, we hadseveral exploration successes. We followed up our successful Golden Eagle wellby drilling a sidetrack to appraise the accumulation. Our 2007 dry hole costsin the UK North Sea were $39 million compared to $21 million in 2006. The $15million Guinea well was completed in the first quarter; however, the targetreservoir was water bearing and the well was abandoned. Exploration wells atStag and Dee were plugged and abandoned, resulting in $12 million and $8million, respectively, in expensed costs.

 

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.

 

55

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**OIL & GAS AND SYNCRUDE NETBACKS**

 

Netbacks are the cash margins, before general and administrativeexpenses, we receive for every equivalent barrel sold. The following tablelists the sales prices, per-unit costs and netbacks for our producing assets,calculated using our working interest production before and after royalties. Acombination of strong realized prices and new high-margin production fromBuzzard increased our cash netback by 40% from last year (36% after royalties).

 

**Before Royalties**

 
| ** **          | ** ** | **2008**  | ** ** |
|---------------------|------------|-----------|------------|
| **($/boe)**         | ** ** | **Yemen** | ** ** | **Canada** | ** ** | **US** | ** ** | **UK** | ** ** | **Other** | ** ** | **Syncrude** | ** ** | **Total** | ** ** |
| Sales               |       | 99.87     |       | 58.34 |   | 79.02 |   | 94.45 |   | 98.98 |   | 105.47 |   | 89.78 |   |
| Royalties and Other |       | (46.94    | )          | (12.25 | ) | (11.03 | ) | — |   | (7.88 | ) | (15.11 | ) | (15.06 | ) |
| Operating Expenses  |       | (8.51     | )          | (13.12 | ) | (11.57 | ) | (6.75 | ) | (4.52 | ) | (36.53 | ) | (11.04 | ) |
| In-country Taxes(1) |       | (13.31    | )          | — |   | — |   | — |   | — |   | — |   | (3.04 | ) |
| **Cash Netback**    | ** ** | **31.11** | ** ** | **32.97** | ** ** | **56.42** | ** ** | **87.70** | ** ** | **86.58** | ** ** | **53.83** | ** ** | **60.64** | ** ** |

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

 

**AfterRoyalties**

 
| ** **          | ** ** | **2008**  | ** ** |
|---------------------|------------|-----------|------------|
| **($/boe)**         | ** ** | **Yemen** | ** ** | **Canada** | ** ** | **US** | ** ** | **UK** | ** ** | **Other** | ** ** | **Syncrude** | ** ** | **Total** | ** ** |
| Sales               |       | 99.87     |       | 58.34 |   | 79.02 |   | 94.45 |   | 98.98 |   | 105.47 |   | 89.78 |   |
| Operating Expenses  |       | (15.88    | )          | (16.38 | ) | (13.48 | ) | (6.75 | ) | (4.91 | ) | (42.04 | ) | (13.18 | ) |
| In-country Taxes(1) |       | (24.83    | )          | — |   | — |   | — |   | — |   | — |   | (3.63 | ) |
| **Cash Netback**    | ** ** | **59.16** | ** ** | **41.96** | ** ** | **65.54** | ** ** | **87.70** | ** ** | **94.07** | ** ** | **63.43** | ** ** | **72.97** | ** ** |

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

 

----

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

 

56

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**ENERGY MARKETING**

 
| **(Cdn$ millions)**                                  | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|-----------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Physical Sales(1)                                         |       | 54,772     |       | 34,358     |       | 30,025     |       |
| Physical Purchases(1)                                     |       | (54,047    | )          | (33,417    | )          | (29,060    | )          |
| Net Financial  Transactions(1)                            |       | (142       | )          | (61        | )          | 344        |       |
| Change in Fair Market  Value of Inventory(1)              |       | (116       | )          | 79         |       | —     |       |
| Marketing Revenue                                         |       | 467        |       | 959        |       | 1,309      |       |
| Transportation Expense                                    |       | (751       | )          | (806       | )          | (789       | )          |
| Other                                                     |       | 27         |       | 14         |       | 20         |       |
| **Net  Marketing Revenue**                                | ** ** | **(257**   | **)**      | **167**    | ** ** | **540**    | ** ** |
| ** **                                                |       |       |       |       |       |       |       |
| **Contribution to Net Marketing Revenue by Region:**      |       |       |       |       |       |       |       |
| North America                                             |       | (284       | )          | 151        |       | 526        |       |
| Asia                                                      |       | 13         |       | 11         |       | 13         |       |
| Europe                                                    |       | 14         |       | 5          |       | 1          |       |
| **Net  Marketing Revenue**                                | ** ** | **(257**   | **)**      | **167**    | ** ** | **540**    | ** ** |
| Depreciation, Depletion,  Amortization and Impairment     |       | (19        | )          | (13        | )          | (12        | )          |
| General and Administrative                                |       | (79        | )          | (87        | )          | (112       | )          |
| Allowance for Doubtful  Receivables                       |       | (54        | )          | —     |       | —     |       |
|                                                      |       |       |       |       |       |       |       |
| **Marketing  Contribution to Income before Income Taxes** | ** ** | **(409**   | **)**      | **67**     | ** ** | **416**    | ** ** |
| ** **                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **North  America**                                        |       |       |       |       |       |       |       |
| **Natural  Gas**                                          |       |       |       |       |       |       |       |
| Physical Sales Volumes  (2) (bcf/d)                  |       | 6.7        |       | 5.8        |       | 5.4        |       |
| Transportation Capacity  (bcf/d)                          |       | 1.8        |       | 2.0        |       | 3.3        |       |
| Storage Capacity  (3) (bcf)                          |       | 38         |       | 39         |       | 50         |       |
| Financial Volumes (bcf/d)                                 |       | 16.8       |       | 21.9       |       | 19.8       |       |
|                                                      |       |       |       |       |       |       |       |
| **Crude Oil**                                             |       |       |       |       |       |       |       |
| Physical Sales Volumes  (2) (mbbls/d)                |       | 656        |       | 655        |       | 553        |       |
| Storage Capacity (mbbls)                                  |       | 2,578      |       | 2,734      |       | 1,749      |       |
| Financial Volumes  (mbbls/d)                              |       | 1,591      |       | 2,134      |       | 1,976      |       |
|                                                      |       |       |       |       |       |       |       |
| **Power**                                                 |       |       |       |       |       |       |       |
| Physical Sales Volumes  (2) (MW/d)                   |       | 4,796      |       | 4,516      |       | 4,388      |       |
| Generation Capacity  (MW/hr)                              |       | 87         |       | 87         |       | 87         |       |
|                                                      |       |       |       |       |       |       |       |
| **Asia**                                                  |       |       |       |       |       |       |       |
| Physical Sales Volumes  (2) (mbbls/d)                |       | 182        |       | 183        |       | 152        |       |
| Financial Volumes (mbbls/d)                               |       | 349        |       | 256        |       | 207        |       |
|                                                      |       |       |       |       |       |       |       |
| **Europe**                                                |       |       |       |       |       |       |       |
| Financial Volumes  (mbbls/d)                              |       | 787        |       | 529        |       | 52         |       |
|                                                      |       |       |       |       |       |       |       |
| **Value-at-Risk**                                         |       |       |       |       |       |       |       |
| Year  End (4)                                             |       | 25         |       | 26         |       | 26         |       |
| High                                                      |       | 40         |       | 38         |       | 33         |       |
| Low                                                       |       | 19         |       | 24         |       | 17         |       |
| Average                                                   |       | 30         |       | 30         |       | 23         |       |

 

----

| *(1)* | * * | *Marketing’s physical sales, physical purchases, net  financial transactions and changes in fair market value of inventory are  reported net on the Consolidated Statement of Income as marketing and other.* |
|-------|----------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | * * | *Excludes inter-segment transactions.*                                                                                                                                                                             |
| *(3)* | * * | *Marketing’s storage capacity reflects volumes  contracted but not necessarily used.*                                                                                                                         |
| *(4)* | * * | *Value-at-Risk (VaR) was reduced subsequent to year  end. At January 31, 2009, VaR was $20 million.*                                                                                                          |

 

57

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2008 vs 2007 — Reduced energy marketing net revenue decreased netincome by $424 million

 

The past year proved challenging for our energy marketing group asunprecedented market conditions impacted physical market fundamentals and thepricing relationships we successfully positioned ourselves to profit fromhistorically. In the first half of the year, commodity markets were strong withcrude oil prices hitting an all-time high and natural gas pricing near recordlevels. In the last half of the year, the trend reversed sharply as the US financialcrisis intensified and spread globally, curtailing growth and demand for energycommodities.

 

While the global economic slowdown produced challenges for ourbusiness, we were most heavily impacted by the significant volatility incommodity markets as we were not positioned to take advantage of them. Instead,we were positioned to take advantage of normal physical fundamentals but thesewere overwhelmed by significant downward price movements, increased volatilityand the economic slowdown. In mid-2008, we started exiting positions that didnot support our physical marketing business and we were scaling back ourtrading activities in an orderly fashion to minimize losses on closingpositions. This was a challenging process given the lack of liquidity in themarket, fewer counterparties and deteriorating commodity prices that haveeroded natural gas spreads.

 

The loss in North America was due to losses in our natural gas and NGLsbusinesses, which were partially offset by contributions from our crude oil andpower businesses.

 

Losses in our natural gas business resulted largely from basispositions designed to take advantage of changing price relationships betweenlocations, as well as financial positions designed to protect the value of ourphysical transportation capacity contracts. The losses we incurred in mid-2008related to positions we had taken that were expected to benefit fromstrengthening natural gas prices in the US Rockies following the addition ofnew pipeline capacity in the region. Delays in the start-up of this pipelineworked against these positions and resulted in losses as we closed them out mid-year.This left us with trading positions that were expected to benefit from wideningeast-west location spreads later in the year driven by typical winter demand ineastern consuming gas markets. As we worked to reduce this trading exposure, wewere faced with a rapidly deteriorating economic environment in which naturalgas prices fell from highs of over US$13.00/mmbtu in the summer to winter pricesof approximately US$6.00/mmbtu in December and US$4.50/mmbtu inJanuary 2009, a period normally characterized by increasing prices. Thesefalling natural gas prices compressed spreads causing losses in the thirdquarter and additional losses in the fourth quarter as the widening spreads wewere positioned for did not materialize and spreads narrowed even further despitecold weather in the east due to demand destruction in the economy. We exitedthe last of these positions in January 2009.

 

We also recognized losses on financial positions, including basis,currency and futures contracts, used to hedge our physical transportationcapacity contracts. The offsetting gains on our physical capacity contractscannot be recognized in our results until they are used in the future.

 

Our marketing results also include losses from our NGL business in thefourth quarter. Over the years, we have been developing this business to takeadvantage of growing demand for green fuels, such as ethanol, denaturant andpropane. The loss reflects declining margins for these products followingsubstantial demand reduction caused by the current economic environment. We arein the process of exiting our ethanol and propane businesses and we expect tocomplete this by the end of the first quarter.

 

Our crude oil business was positioned to take advantage of dailyvolatility in both WTI and crude oil quality differentials. Profits weregenerated primarily by blending activities, by diverting crude oil to moreattractive markets and by storing crude oil to capture higher future prices.Losses on financial strategies designed to protect the value of our futurestorage positions partially offset these gains. A portion of these losses willbe recovered in the future when the offsetting gains on the physical positionsare recognized.

 

Our European business has improved their results by focusing on aphysical producer/marketer model. We added physical capacity contracts, bothstorage and transportation, in the UK and continental Europe. Our Asianbusiness continued to generate solid profits by marketing our Masila barrelsfrom Yemen.

 

We are realigning our energy marketing strategies and positions tobetter support our core physical business as a producer/marketer. We expect tofocus on marketing and optimization which involves buying, selling and holdingphysical commodities, as well as the rights to physical transportation andstorage assets. Holding physical assets allows us to extract value when events,particularly weather, cause a disconnect between markets or time periods.Despite recent losses, this business has contributed $380 million of cash flowover the past five years.

 

58

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We have significantly reduced our financial trading levels in NorthAmerica and continue to exit positions that do not support our renewed focus.The following graphs show the changes in underlying drivers of our businessover the last year and the first month of 2009.

 

**VALUE-AT-RISK**

 

 

**NORTH AMERICAN NATURAL GAS**

Volumetric Information (bcf/day)

 

 

**NORTH AMERICAN CRUDE OIL**

Volumetric Information (mbbls/day)

 

 

----

| *(1)* | *Marketing’s physical and financial volumes  represent the exiting average daily volume for the quarter.* |
|-------|----------------------------------------------------------------------------------------------------------------|

 

The graphs reflect our efforts to re-focus our North American gasbusiness back on its core marketing and optimization activities, as well asprudently manage the working capital deployed in the business.

 
| · | Physical volumes are down 25% from their peak with less focus on  buying and selling gas at a point to realize a margin.                                     |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------|
| · | At December 31, 2008  financial volumes were down 54% from their  peak given our focus on exiting trading positions and optimizing assets.         |
| · | Gas storage capacity for the next season is back in line with 2005  levels, giving plenty of capacity to optimize on behalf of ourselves and our  customers. |

 

We also reduced the risk held in our forward trading portfolio asdemonstrated by reducing our value-at-risk 44% from its peak earlier in theyear. Over the past few months, we have significantly reduced our financialtrading positions. We have focused our financial contracts on protecting andoptimizing the value of our near-term physical assets where market liquidityexists.

 

The credit crisis that impacted financial markets caused some of ourcounterparties to restructure or declare bankruptcy. In September 2008,Lehman Brothers filed for bankruptcy protection and our exposure to them in ourtrading operations was approximately $39 million. The entire amount wasexpensed in the third quarter although we continue to pursue recovery of theseamounts. We also provided an additional $15 million for credit risk with ourcounterparties. The majority of our counterparties are integrated oilcompanies, crude oil refiners and marketers, and large utilities.

 

Results from our marketing group vary between periods and historicalresults are not necessarily indicative of future results. Marketing resultsdepend on a variety of factors such as market volatility, changes in time andlocation spreads, the manner in which we use our storage and transportationassets and the change in value of the financial instruments we use to hedgethese assets.

 

59

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2007 vs 2006 — Reduced energy marketing net revenue decreased netincome by $373 million

 

Results from our energy marketing group in 2007 were below the recordyear we experienced in 2006 as there were fewer market events to capitalize on,and fundamental changes in commodity markets were difficult to predict withconfidence.

 

As part of our gas marketing strategy, we hold physical transportationand storage capacity contracts that allow us to take advantage of pricingdifferences between locations (i.e. west vs. east) and time periods (i.e.summer vs. winter). These strategies, particularly time spreads, contributedless to net revenue in 2007 as there were fewer significant weather-relatedmarket events (hurricanes or cold winter weather) to capitalize on. Theseevents typically cause time spreads to widen and location spreads to dislocate,presenting trading opportunities for us. In addition, gas prices were supportedthroughout the year by high oil prices despite record gas storage levels. Wewere successful at generating revenue through the day-to-day optimization ofour transportation and storage capacity, as well as our fee-for-service assetmanagement activities.

 

The contribution of our North American crude oil marketing team waslower than 2006 as their portfolio, both physical and financial, was positionedto take advantage of contango (rising forward month prices) in the crude oilforward curve. Late summer, near-term crude oil prices moved up sharply, movingthe forward curve from contango to backwardation (falling forward monthprices). As a result, we suffered losses in our financial time spreadpositions. We continued to capture profits from location and quality spreads bydiverting crude oil to more attractive markets or blending to enhance crudequality.

 

Our 2007 results include fair value gains of $79 million on our naturalgas and crude oil in storage and pipelines in the fourth quarter. New inventorystandards under Canadian GAAP require us to carry our trading commodityinventories at fair value, rather than at cost as was previously the case. We adoptedthese new rules in the fourth quarter of 2007.

 

In late 2006, we de-designated certain futures contracts that weredesignated as cash flow hedges of future sales of our natural gas in storage.These contracts were de-designated since it became uncertain that the futuresales would occur within the designated time frame. As it was reasonablypossible that the future sales could have taken place as designated at theinception of the hedging relationship, gains of $65 million on the futurescontracts were deferred at December 31, 2006. These gains were recognizedin marketing and other income during the first quarter of 2007.

 

**Composition of Net Marketing Revenue**

 
| **(Cdn$ millions)**                     | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Trading Activities  (Physical and Financial) |       | (287     | )          | 147      |       | 520      |       |
| Non-Trading Activities                       |       | 30       |       | 20       |       | 20       |       |
| **Total Net  Marketing Revenue**             | ** ** | **(257** | **)**      | **167**  | ** ** | **540**  | ** ** |

 

Trading Activities

 

In our energy marketing group, we enter into contracts to purchase andsell crude oil and natural gas. We also use financial and derivative contracts,including futures, forwards, swaps and options for hedging and tradingpurposes. We account for all derivative contracts using fair value accountingand record the net gain or loss from their revaluation in marketing and otherincome. The fair value of these instruments is included with accountsreceivable or payable. They are classified as long-term or short-term based ontheir anticipated settlement date.

 

Other Activities

 

We enter into fee for service contracts related to transportation andstorage of third-party oil and gas. In addition, we earn income from our powergeneration facilities at Balzac and Soderglen.

 

*Fair Value of Derivative Contracts*

 

For purposes of estimating the fair value of our derivative contracts,wherever possible, we utilize quoted market prices and if not available,estimates from third-party brokers. These broker estimates are corroboratedwith multiple sources and/or other observable market data utilizing assumptionsthat market participants would use when pricing the asset or liability,including assumptions about risk and market liquidity. Inputs to fairvaluations may be readily observable, market-corroborated, or generallyunobservable. We utilize valuation techniques that 

 

60

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seek to maximize the use of observable inputs and minimize the use ofunobservable inputs. To value longer-term transactions and transactions in lessactive markets for which pricing information is not generally available,unobservable inputs may be used.

 

As a basis for establishing fair value, we utilize a mid-market pricingconvention between bid and ask and then adjust our pricing to the ask pricewhen we have a net short position and the bid price when we have a net longposition. This adjustment reflects an estimated exit price and incorporates theimpact of liquidity when the bid-ask spread widens in less liquid markets. Weincorporate the credit risk associated with counterparty default, as well asNexen’s own credit risk, into our estimates of fair value.

 

We classify the fair value of our derivatives according to thefollowing hierarchy based on the amount of observable inputs used to value theinstruments.

 
| · | Level 1 — Quoted prices are available in active markets for identical  assets or liabilities as of the reporting date. Active markets are those in  which transactions occur in sufficient frequency and volume to provide  pricing information on an ongoing basis. Level 1 consists of financial  instruments such as exchange-traded derivatives and we use information from  markets such as the New York Mercantile Exchange. |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
|   | ·                                                                                                                                                                                                                                                                                                                                                                                                                                  | Level 2 — Pricing inputs are other than quoted prices in active  markets included in Level 1. Prices in Level 2 are either directly or  indirectly observable as of the reported date. Level 2 valuations are based  on inputs, including quoted forward prices for commodities, time value,  volatility factors, and broker quotations, which can be substantially  observed or corroborated in the marketplace. Instruments in this category  include non-exchange traded derivatives such as over-the-counter physical  forwards and options, including those which have prices similar to quoted  market prices. We obtain information from sources such as the Natural Gas  Exchange, independent price publications and over-the-counter broker quotes.             |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
|   | ·                                                                                                                                                                                                                                                                                                                                                                                                                                  | Level 3 — Valuations in this level are those with inputs which are  less observable, unavailable or where the observable data does not support  the majority of the instrument’s fair value. Level 3 instruments may include  items based on pricing services or broker quotes where we are unable to  verify the observability of inputs into their prices. Level 3 instruments  include longer-term transactions, transactions in less active markets or  transactions at locations for which pricing information is not available. In  these instances, internally developed methodologies are used to determine  fair value which primarily includes extrapolation of observable future prices  to similar locations, similar instruments or later time periods. |
|        |                                                                                                                                                                                                                                                                                                                                                                                                                                         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |  |  |

 

At December 31, 2008, the fair value of our derivative contractsin our energy marketing trading activities totaled $63 million. This includescontracts used to economically hedge our physical storage and transportationcontracts which cannot be carried at fair value until they are used as well asother trading contracts. Below is a breakdown of the derivative fair value byvaluation method and contract maturity.

 
| ** **                                               | ** ** | **Maturity**              | ** ** |
|----------------------------------------------------------|------------|---------------------------|------------|
| **(Cdn$ millions)**                                 | ** ** | **< 1 year** | ** ** | **1-3 years** | ** ** | **4-5 years** | ** ** | **> 5 years** | ** ** | **Total** | ** ** |
| Level 1 – Actively Quoted  Markets                  |       | 90                        |       | (51 | ) | (23 | ) | (3 | ) | 13 |   |
| Level 2 – Based on Other  Observable Pricing Inputs |       | 130                       |       | (4 | ) | 8 |   | (2 | ) | 132 |   |
| Level 3 – Based on  Unobservable Pricing Inputs     |       | (80                       | )          | (2 | ) | — |   | — |   | (82 | ) |
| **Total**                                                | ** ** | **140**                   | ** ** | **(57** | **)** | **(15** | **)** | **(5** | **)** | **63** | ** ** |

 

**Changes in Fair Value of Derivative Contracts**

 
| **(Cdn$ millions)**                            | ** ** | **Total** | ** ** |
|-----------------------------------------------------|------------|-----------|------------|
| **Fair  Value at December 31, 2007**           | ** ** | **6**     | ** ** |
| Change in Fair Value of  Contracts                  |       | (158      | )          |
| Net Losses (Gains) on  Contracts Closed             |       | 227       |       |
| Changes in Valuation  Techniques and Assumptions(1) |       | (12       | )          |
| **Fair  Value at December 31, 2008**           | ** ** | **63**    | ** ** |

 

----

| *(1)* | *Our valuation methodology has been applied  consistently each period, with the exception of two portfolio level reserves  that were included in the first quarter of 2008 to account for: a) credit  risk associated with counterparty defaults; and b) liquidity risk in our  portfolio.* |
|-------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

The fair values of our derivative contracts will be realized over timeas the related contracts settle. Until then, the value of certain contractswill vary with forward commodity prices and price differentials. The averageterm of our derivative contracts is approximately 1.5 years. Those maturingbeyond one year primarily relate to North American natural gas positions.

 

61

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**CHEMICALS**

 
| **(Cdn$ millions)**                                 | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net Sales                                                |       | 477      |       | 414      |       | 407      |       |
| Sales Volumes (thousand  short tons)                     |       |     |       |     |       |     |       |
| Sodium Chlorate                                          |       | 495      |       | 478      |       | 487      |       |
| Chlor-alkali                                             |       | 469      |       | 465      |       | 451      |       |
| Operating Profit (1)                                     |       | 125      |       | 118      |       | 118      |       |
| Operating Margin (2)                                     |       | 26       | %          | 29       | %          | 29       | %          |
| Chemicals Contribution to  Income Before Income Taxes(3) |       | (14      | )          | 64       |       | 44       |       |
| Capacity Utilization                                     |       | 92       | %          | 94       | %          | 95       | %          |

 

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

 

2008 vs 2007 — Lower Chemicals contribution decreased net income by $76million

 

North America sodium chlorate revenues increased 14% in 2008 as aresult of higher realized selling prices and higher sales volumes. Priceincreases implemented in North America in the first and third quarters morethan offset the impact of the stronger Canadian dollar on US-dollar denominatedsales. Strong demand from US customers contributed to the increase in salesvolumes. North American chlor-alkali revenues were up 11% in 2008 as we realizedhigher selling prices for caustic soda. These increases have been offset byhigher operating and transportation costs, as the price of fuel and powerincreased during 2008. In Brazil, we have a pass-through contract with ourprimary customer Aracruz Cellulose that allows us to amend our sales priceswhen operating costs change. Higher costs in 2008 increased the sales revenueswe receive from them.

 

Chemicals contribution to income includes foreign exchange losses of$54 million, primarily from unrealized losses on the revaluation of US-dollardenominated long-term debt.

 

2007 vs 2006 — Higher Chemicals contribution increased net income by$27 million

 

Realized North America chlorate prices were up 5% in 2007 and salesvolumes remained strong, despite unplanned maintenance of our facilities andpulp 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.

 

Operating profit includes foreign exchange gains of $30 million,primarily from unrealized gains on revaluation of US-dollar denominatedlong-term debt.

 

**CORPORATE EXPENSES**

 

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

 
| **(Cdn$ millions)**                                            | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|---------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| General and Administrative  Expense before Stock-Based Compensation |       | 417      |       | 336      |       | 345      |       |
| Stock-Based Compensation  (1)                                       |       | (160     | )          | 38       |       | 210      |       |
| **Total**                                                           | ** ** | **257**  | ** ** | **374**  | ** ** | **555**  | ** ** |

 

----

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

 

2008 vs 2007 — Lower costs increased net income by $117 million

 

Changes in our share price create volatility in our net income as weaccount for stock-based compensation using the intrinsic-value method. Thismethod uses our share price at the end of the reporting period to determine ourstock-based compensation expense and related obligations. During the year, werecovered non-cash stock based compensation costs of $272 million as our stockprice closed at $21.45/share at the end of 2008, compared to $32.10/share theprevious year. This recovery was partially offset by cash payments forstock-based compensation programs of $112 million, 24% lower than 2007.

 

G&A expense before stock-based compensation increased $81 million,primarily as a result of higher employee costs and cost inflation. An integralpart of our strategy to expand our oil and gas operations has been to activelyrecruit experienced employees, positioning us for success in our core areas. Wehave been actively recruiting skilled individuals to strengthen our teams inNorway and the US.

 

62

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2007 vs 2006 — Lower costs increased net income by $181 million

 

G&A expense dropped 33% from 2006 with lower stock-basedcompensation expense. At the end of 2007, our stock price closed unchanged fromthe end of 2006. As a result, most of our 2007 stock-based compensation expenseis related to vesting of stock-based compensation plans. Cash payments toemployees for stock-based compensation programs increased 24% from 2006 to $147million.

 

During the year, we incurred additional employee costs as we continueto expand oil and gas operations internationally and marketing operations inEurope and North America. This was offset by lower variable compensation on oiland gas and marketing operations.

 

**Interest**

 
| **(Cdn$ millions)**  | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|---------------------------|------------|------------|------------|------------|------------|------------|------------|
| Interest                  |       | 334        |       | 341        |       | 294        |       |
| Less: Capitalized         |       | (240       | )          | (173       | )          | (241       | )          |
| **Net  Interest Expense** | ** ** | **94**     | ** ** | **168**    | ** ** | **53**     | ** ** |
| ** **                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Effective Interest Rate   |       | 5.9        | %          | 6.2        | %          | 6.3        | %          |

 

2008 vs 2007 — Lower net interest expense increased net income by $74million

 

Our financing costs are $7 million lower than the previous year as ourstrong cash flow reduced our debt needs. Lower interest rates on our variablerate debt also reduced interest costs. In the third quarter, we completed aninternal reorganization and financing of our assets in the UK. This required usto draw down approximately US$1 billion under our term credit facilities. As aconsequence, our financing costs increased in the fourth quarter of 2008.

 

Interest capitalized on our major development projects increased $67million in 2008 compared to 2007. Our Long Lake capital costs include $207million of capitalized interest, $49 million higher than last year. We alsocapitalized interest of $25 million on our Ettrick development. We continue tocapitalize interest on our development project at Usan and the construction ofthe fourth platform at Buzzard. We expect net interest expense to increase in2009 by approximately $150 million when we cease capitalizing interest at LongLake and Ettrick.

 

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

 

Financing costs increased $47 million from 2006. Additional borrowingsto finance our 2007 capital program increased interest costs by approximately$69 million. This was partially offset by the stronger Canadian dollar whichreduced our US-dollar denominated interest by $22 million.

 

Interest capitalized on our major development projects was lower by $68million from 2006 as we stopped capitalizing interest on the Syncrude Stage 3expansion and Buzzard when these projects were brought on stream.

 

**Income Taxes**

 
| **(Cdn$ millions)**              | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|---------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Current                               |       | 859        |       | 434        |       | 368        |       |
| Future                                |       | 598        |       | 358        |       | 315        |       |
| **Total  Provision for Income Taxes** | ** ** | **1,457**  | ** ** | **792**    | ** ** | **683**    | ** ** |
| ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Effective Tax Rate                    |       | 46         | %          | 42         | %          | 53         | %          |

 

2008 vs 2007 — Effective tax rate increases from 42% to 46%

 

Our provision for income taxes increased $665 million or 84% from theprior year, while our effective tax rate increased 4%. This increase wasprimarily due to record commodity prices and strong production at Buzzard inthe UK, which has a corporate tax rate on oil and gas activities of 50%.Current income taxes include cash taxes in Yemen, the UK, Colombia, Norway andthe US.

 

2007 vs 2006 — Effective tax rate decreases from 53% to 42%

 

Our 2007 effective tax rate was lower than 2006, as we recordedadditional tax expense in 2006 due to a UK tax rate increase. Excluding theimpact of this rate increase, our effective tax rate in 2006 would have been33%. The 2007 increase is due to a higher proportion of earnings from the UKwhere the corporate income tax rate on oil and gas activities is 50%. Currentincome taxes include cash taxes in Yemen, the UK, Colombia and the US.

 

63

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**Other**

 
| **(Cdn$ millions)**                                    | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|-------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Increase (Decrease) in  Fair Value of Crude Oil Put Options |       | 203      |       | (43      | )          | (11      | )          |
| Block 51 Settlement                                         |       | —   |       | —   |       | (151     | )          |
| Business Interruption  Insurance Proceeds                   |       | —   |       | —   |       | 154      |       |

 

In early 2008, we purchased put options on approximately 70,000 bbls/dof our 2009 crude oil production. These options establish a Dated Brent floorprice of US$60/bbl on these volumes, are settled annually and provide a baselevel of price protection without limiting our upside to higher prices.Accounting rules require that these options be recorded at fair valuethroughout their term. As a result, changes in forward crude oil prices creategains or losses on these options at each period end. The put options werepurchased for $14 million and are carried at fair value. During the thirdquarter of 2008, Lehman Brothers, one of the put option counterparties filedfor bankruptcy protection, which impacts 25,000 bbls/d of our 2009 put options.The carrying value of these put options has been reduced to nil. AtDecember 31, 2008, the remaining options had a fair value of $233 million,creating an unrealized gain of $203 million.

 

During 2007, we purchased put options on 36 million barrels of our 2008crude oil production. These options establish a Dated Brent floor price ofUS$50/bbl on these volumes. The put options were purchased for $24 million;however, strong crude oil prices reduced the fair value of these options tonil, and we recorded a loss of $24 million during 2007.

 

During 2006, we purchased put options on approximately 105,000 bbls/dof our 2007 crude oil production for $26 million, establishing a WTI floorprice of US$50/bbl on these volumes. We recognized a loss of $7 million for theyear ended December 31, 2006 as an increase in the forward WTI priceslowered the fair value of the options. In 2007, strengthening WTI reduced themarket value of the options to nil, creating a loss of $19 million.

 

Following our North Sea acquisition in late 2004, we purchased putoptions on 60,000 bbls/d of oil production for 2006 creating an average floorprice for this production of US$38/bbl. Strong WTI prices in 2006 caused us toexpense $4 million as the market value of the remaining options was reduced tonil.

 

In 2006, a court of arbitration concluded that we breached an Area ofMutual Interest agreement with Occidental Petroleum Corporation (Occidental).As a result, Occidental was entitled to monetary damages. In late 2006, wesettled the arbitration by agreeing to pay Occidental US$135 million ($151million) as monetary damages.

 

In 2006, we received $154 million of business interruption insuranceproceeds related to 2005 production losses caused by Gulf of Mexico hurricanesand by generator failures in our UK operations.

 

**OUTLOOK FOR 2009**

 

In 2009, we plan to invest $2.6 billion in capital activities on ouroil and gas, and Syncrude operations as follows:

 
| · | 34% on our existing producing assets, including the fourth platform  at Buzzard;                                                                                                      |
|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                  |
| · | 31% in development projects to progress Usan, offshore West Africa  and bring Ettrick, in the North Sea, and Longhorn, in the Gulf of Mexico, on  stream in 2009;                     |
|   |                                                                                                                                                                                  |
| · | 27% on advancing our Horn River shale gas play and on exploration and  appraisal opportunities in our key regions — the North Sea, Gulf of Mexico  and offshore West Africa; and |
|   |                                                                                                                                                                                  |
| · | 8% on early stage development projects expected to contribute future  production and cash flow including future phases of oil sands in the  Athabasca region.                         |

 

The amount of this capital investment could be reduced due to thecurrent uncertain economic environment. Details of our 2009 capital program areincluded in the Capital Investment section of the MD&A.

 

**Daily Production**

 

In 2009, we expect net production to grow approximately 10% compared to2008 and to range between 225,000 and 240,000 boe/d (255,000 and 270,000 boe/dbefore royalties). We expect to ramp up bitumen production at Long Lake as wellas first oil production from Ettrick in the North Sea and Longhorn in the Gulfof Mexico. These will more than offset natural field declines in Yemen and ashut-down of the Buzzard platform for four weeks as we install the fourth platform.

 

64

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**2009 Estimated Production**

 
| ** **          | ** ** | **2009 Estimated Production** | ** ** | **2008 Production** | ** ** |
|---------------------|------------|-----------------------------------------|------------|--------------------------|------------|
| **(mboe/d)**        | ** ** | **Before  Royalties**                   | ** ** | **After  Royalties**     | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** |
| United Kingdom      |       | 100–115                            |       | 100–115             |       | 103 |   | 103 |   |
| Yemen               |       | 40–45                              |       | 23–28               |       | 56 |   | 31 |   |
| Canada              |       | 35–40                              |       | 27–32               |       | 38 |   | 30 |   |
| United States       |       | 20–25                              |       | 17–22               |       | 22 |   | 19 |   |
| Syncrude            |       | 20–25                              |       | 18–23               |       | 21 |   | 18 |   |
| Long Lake Bitumen   |       | 20–25                              |       | 18–23               |       | 4 |   | 4 |   |
| Other International |       | 3–5                                |       | 2–4                 |       | 6 |   | 5 |   |
| **Total**           | ** ** | **255**–**270**                    | ** ** | **225**–**240**     | ** ** | **250** | ** ** | **210** | ** ** |

 

Cash Flow and Sensitivities

 

We expect to generate cash flowof between $2.3 and $2.9 billion from operating activities in 2009, after cashtaxes of approximately $1 billion, assuming the following:

 
| WTI (US$/bbl)                       |   | $50–$65 |   |
|-------------------------------------|--------|--------------|--------|
| NYMEX Natural Gas (US$/mmbtu)       |   | $6.50        |   |
| US to Canadian Dollar Exchange Rate |   | $0.83        |   |

 

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

 
| **(Cdn$ millions)**                   | ** ** | ** ** | ** ** | ** ** |
|--------------------------------------------|------------|------------|------------|------------|
| WTI—US$1/bbl change above US$60       |       | 50         |       |
| WTI—US$1/bbl change below US$60       |       | 40         |       |
| NYMEX Natural Gas—US $0.50/mcf change |       | 34         |       |
| Exchange Rate—$0.01 US/Cdn change     |       | 36         |       |

 

**LIQUIDITYAND CAPITAL RESOURCES**

 

**CapitalStructure**

 
| **(Cdn$ millions)**        | ** ** | **December 31  2008** | ** ** | **December 31  2007** | ** ** |
|---------------------------------|------------|----------------------------|------------|----------------------------|------------|
| **Net Debt (1)**                |       |                       |       |                       |       |
| Bank Debt                       |       | 1,448                      |       | 413                        |       |
| Public Senior Notes             |       | 4,582                      |       | 3,758                      |       |
| Total Senior Debt               |       | 6,030                      |       | 4,171                      |       |
| Subordinated Debt               |       | 548                        |       | 439                        |       |
| Total Debt                      |       | 6,578                      |       | 4,610                      |       |
| Less: Cash and Cash Equivalents |       | (2,003                     | )          | (206                       | )          |
| **Total Net Debt**              | ** ** | **4,575**                  | ** ** | **4,404**                  | ** ** |
| ** **                      | ** ** | ** **                 | ** ** | ** **                 | ** ** |
| **Shareholders’ Equity**   | ** ** | **7,139**                  | ** ** | **5,610**                  | ** ** |

 

----

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

 

**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 approximately $4.6 billion, $171 million higherthan 2007. The year-over-year change in our net debt results from:

 
| **(Cdn$ millions)**                                 | ** ** | **2008** | ** ** | **2007**   | ** ** |
|----------------------------------------------------------|------------|----------|------------|------------|------------|
| Capital Investment                                       |       | 3,066    |       | 3,401      |       |
| Cash Flow from Operating Activities                      |       | (4,354   | )          | (2,830     | )          |
| (Excess) Deficiency                                      |       | (1,288   | )          | 571        |       |
| Dividends on Common Shares                               |       | 92       |       | 53         |       |
| Issue of Common Shares                                   |       | (64      | )          | (56        | )          |
| Repurchase of Common Shares for  Cancellation            |       | 338      | ** ** | **—** | ** ** |
| Foreign Exchange Translation of US-dollar  Debt and Cash |       | 1,012    |       | (745       | )          |
| Net Proceeds on Disposition of Assets                    |       | (6       | )          | (4         | )          |
| Other                                                    |       | 87       |       | (145       | )          |
| **Increase (Decrease) in Net Debt**                      | ** ** | **171**  | ** ** | **(326**   | **)**      |

 

65

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The change in our net debt,combined with strong cash flow and earnings, have improved our 2008 leverage asreflected in the following ratios:

 
| **(times)**                                      | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|--------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net Debt to Cash Flow from Operating  Activities |       | 1.1      |       | 1.6      |       | 2.0      |       |
| **Interest Coverage(1)**                         |       | 15.6     |       | 12.1     |       | 9.6      |       |

 

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*(1)**      **Earnings before interest,taxes, DD&A, exploration and other non–cash expenses, divided by interestexpense (before capitalized interest).*

 

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:

 

·      developthe Masila project in Yemen in 1993;

·      acquireWascana in 1997;

·      repurchase20 million common shares in 2000;

·      acquirethe remaining interest in Aspen in 2003;

·      acquirethe Buzzard project and other key assets in the North Sea in 2004; and

·      constructthe first phase of Long Lake.

 

Each time, we exceeded ourinternal net debt to cash flow target band, we successfully bring our leveragedown through asset sales and incremental cash flows.

 

**Change inWorking Capital**

 
| **(Cdn$ millions)**                 | ** ** | **December 31  2008** | ** ** | **December 31  2007** | ** ** | **Increase  (Decrease)** | ** ** |
|------------------------------------------|------------|----------------------------|------------|----------------------------|------------|--------------------------|------------|
| Cash and Cash Equivalents                |       | 2,003                      |       | 206                        |       | 1,797                    |       |
| Restricted Cash                          |       | 103                        |       | 203                        |       | (100                     | )          |
| Accounts Receivable                      |       | 3,163                      |       | 3,502                      |       | (339                     | )          |
| Inventories and Supplies                 |       | 484                        |       | 659                        |       | (175                     | )          |
| Accounts Payable and Accrued Liabilities |       | (3,326                     | )          | (4,180                     | )          | (854                     | )          |
| Other                                    |       | 76                         |       | 22                         |       | 54                       |       |
| **Total**                                | ** ** | **2,503**                  | ** ** | **412**                    |       |                     |       |

 

Our cash and cash equivalentsare significantly higher due to higher operating cash flows and the proceeds ofborrowings made on our term credit facilities. Strong production volumes andrecord commodity prices contributed to higher operating cash flows. We alsocompleted an internal reorganization and financing of our UK assets, whichrequired a draw of approximately US$1 billion under our term credit facilities,with a corresponding increase in cash.

 

Accounts receivable and payablefor our Energy Marketing group decreased $250 million and $600 million from2007, respectively. These decreases were due to a combination of: (i) lowercommodity prices in the fourth quarter of 2008 that reduced the size of ouroutstanding physical and financial contracts; and (ii) exiting a portion of ourderivative positions as part of a strategic decision to reduce the size of ourmarketing operation. Lower year-end prices also reduced the value of ourcommodity trading inventories. Additionally, our accrued payables were lower asour outstanding stock-based compensation obligations were reduced by $296million at the end of 2008.

 

The stronger US dollar at theend of the year impacted our US-dollar denominated working capital byincreasing accounts receivable, inventories and accounts payable byapproximately $335 million, $80 million and $290 million, respectively. TheUS/Canadian year-end exchange rate increased 25% from 2007.

 

**Liquidity**

 

We generally rely on operatingcash flows to fund capital requirements and provide liquidity. Given the longcycle-time of some of our development projects and volatile commodity prices,it is not unusual for capital expenditures to exceed our cash flow in any givenyear. We also require liquidity for our energy marketing business. We believethat maintaining strong 

 

66

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liquidity is critical duringperiods of uncertain economic markets. We currently have liquidity of over $3.5billion after acquiring the additional Long Lake interest in January 2009, thatis comprised of cash and undrawn committed credit facilities available until2012.

 

We maintain significantcommitted credit facilities. At December 31, 2008, we had unsecured term creditfacilities of $3.7 billion (US$3.1 billion) that are available until 2012. Ofthese facilities, $1.2 billion (US$1 billion) was drawn and $381 million(US$311 million) was utilized to support letters of credit. We also had $613million (US$501 million) of uncommitted, unsecured credit facilities, of which$29 million (US$24 million) was supporting letters of credit outstanding atDecember 31, 2008. Additionally, Canexus had $420 million (US$343 million) ofcommitted, secured term credit facilities available until 2011 of which $223million (US$182 million) was drawn down at December 31, 2008.

 

From time to time, we accesscapital markets to meet our financing needs. We also use financial instrumentsto minimize exposure to fluctuating commodity prices and foreign exchange. Forexample, we routinely purchase WTI and Dated Brent put options to establish aminimum value for our production. We manage our capital structure to maintainflexibility so we can fund our capital programs given the cyclical nature ofthe oil and gas business.

 

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

 
| **(Cdn$ millions)**            | ** ** | **2008**  | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------|------------|-----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| Cash Flow from Operating Activities |       | 4,354     |       | 2,830    |       | 2,374    |       | 2,143    |       | 1,606    |       |
| Cash Flow from Investing Activities |       | (3,189    | )          | (3,281   | )          | (3,388   | )          | (1,864   | )          | (4,013   | )          |
| Surplus (Deficiency)                |       | 1,165     |       | (451     | )          | (1,014   | )          | 279      |       | (2,407   | )          |
| Cash Flow from Financing Activities |       | 322       |       | 677      |       | 1,081    |       | (274     | )          | 1,426    |       |
| **Net Cash Generated (Used)**       | ** ** | **1,487** | ** ** | **226**  | ** ** | **67**   | ** ** | **5**    | ** ** | **(981** | **)**      |

 

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 fund our 2007 capital program.

 

In 2008, our cash flow fromoperating activities exceeded capital expenditures by approximately $1.3 billionand we used this excess to build our cash balances, repurchase common sharesand repay debt. In June, we repaid maturing medium term notes of $125 millionand in the third quarter, we borrowed approximately US$1 billion under our termcredit facilities. The draw down under our term credit facilities resulted froman internal reorganization and financing of our UK North Sea assets.

 

In the third quarter, wereceived approval from the Toronto Stock Exchange (TSX) for a Normal CourseIssuer Bid (Bid). Under the Bid, we are able to repurchase up to 10% of ourpublic float of common shares (approximately 53 million common shares) forcancellation. Purchases under the Bid commenced August 6, 2008 and can be madeuntil August 5, 2009. We repurchased 12 million common shares at an averageprice of $27.85/share for a cost of $338 million. We currently have no plans torepurchase common shares until economic conditions improve.

 

Our marketing business alsorequires liquidity to support its activities. We require liquidity for workingcapital, cash or credit lines to fund collateral requirements and to absorbunexpected market or credit losses. The commercial agreements our marketingbusiness enters into often include financial assurance provisions that allowNexen and our counterparties to effectively manage credit risk. Theseagreements typically require collateral be posted if adverse credit-relatedevents, such as reduced credit rating to non-investment grade, occur.Additionally, our exchange-traded contracts require that we provide marginbased on daily fluctuations in the value of our contracts. The largest singleday margin call we received during 2008 was $60 million. 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.

 

67

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**FutureLiquidity**

 

Our future liquidity dependsupon cash flow generated from our operations, existing committed creditfacilities and our ability to access debt and equity markets. Our announced 2009capital investment budget is approximately $2.8 billion which we expect tofinance from cash flow and existing cash. We continue to monitor economicconditions and commodity prices and will adjust our capital investment programaccordingly. We are also working with suppliers and contractors to renegotiatesupply rates that reflect existing market conditions.

 

In 2009, we expect cash flow ofbetween $2.3 and $2.9 billion (before remediation and geological andgeophysical expenditures) assuming:

 
| WTI (US$/bbl)                  |   | $50–$65 |   |
|-------------------------------------|--------|--------------|--------|
| NYMEX Natural Gas (US$/mmbtu)       |   | $6.50        |   |
| US to Canadian Dollar Exchange Rate |   | $0.83        |   |

 

Changes in commodity prices andexchange rates will impact our cash flow and borrowing requirements. Refer tothe Outlook for 2009 section on page 65 to see how changes in the aboveassumptions can impact our cash flow.

 

At December 31, 2008 we have $2billion in cash, $2.5 billion (US$2.1 billion) of undrawn committed creditfacilities and $613 million of unsecured credit facilities. We have no debtmaturities over the next few years and the average term of our public debt isapproximately 18 years. When we combine these factors with our strategiccapital investment plans, we believe we are well positioned to bring our nearcompletion projects to production and pursue our next generation of growthwhile preserving our liquidity. At the end of 2008, we agreed to acquire anadditional 15% interest in the Long Lake Project and the joint venture landsfrom OPTI Canada Inc. for $735 million. The acquisition closed late January2009 and was financed using our existing term credit facilities and cash onhand. We now have a 65% interest in the Long Lake Project and are the soleoperator of the resource and upgrader.

 

For the past several years, wehave invested significant capital in a number of major development projectsincluding Buzzard and Long Lake. The large capital investment required in theseprojects is behind us and we expect these assets to make significantcontributions to our future cash flows. In addition, we expect Ettrick andLonghorn to contribute to cash flows when they start production in 2009. Thecash flows generated from these projects allow us to repay debt or invest inour next generation of new growth projects such as Usan, offshore West Africaand shale gas in the Horn River basin. In 2009, we expect to invest $515million to progress our Usan development, and $160 million in the UK North Seato bring Ettrick on stream and assess development options for Blackbird. Whilethese development projects lack exploration risk, they are subject to otherrisks including higher than anticipated capital costs or delayed start-up. Wemaintain significant undrawn committed credit facilities to manage these risks.We also have a US$2.5 billion shelf prospectus filed in the US and Canada forsales of debt securities and common shares.

 

We are well positioned with ourcurrent debt structure, and have no significant debt repayments until 2011. Ouronly debt covenant requires us to maintain a long–term debt to EBITDA ratio ofless than 3.5. At December 31, 2008, this ratio was approximately 1.2 times.Based on our current debt levels and operations, we do not expect to exceed 3.5in the foreseeable future.

 
| **(Cdn$ millions)**          | ** ** | **2009**   | ** ** | **2010**   | ** ** | **2011** | ** ** | **2012**  | ** ** | **2013** | ** ** |
|-----------------------------------|------------|------------|------------|------------|------------|----------|------------|-----------|------------|----------|------------|
| Term Credit Facilities(1)         |       | —     |       | —     |       | —   |       | 1,225     |       | —   |       |
| Long-Term Notes                   |       | —     |       | —     |       | —   |       | —    |       | 612      |       |
| Canexus LP Term Credit Facilities |       | —     |       | —     |       | 223      |       | —    |       | —   |       |
| Canexus LP Notes                  |       | —     |       | —     |       | —   |       | —    |       | 61       |       |
| **Total**                         | ** ** | **—** | ** ** | **—** | ** ** | **223**  | ** ** | **1,225** | ** ** | **673**  | ** ** |

 

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*(1)**      **$3.7 billion (US$3.1billion) available until 2012.*

 

With our expected cash flowstreams, commodity price hedging strategies, current liquidity levels, accessto debt and equity markets, and flexibility to reduce future capitalexpenditure programs, we expect to be able to fund all planned capital,dividends and debt repayments, and meet other obligations that may arise fromour oil and gas, Syncrude, chemicals and energy marketing operations.

 

In 2008, the board declaredcommon share dividends of $0.175. In each of the three years preceding 2008,the board declared common share dividends of $0.10 per share each year.

 

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**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** | ** ** |
| Long-Term Debt                               |       | 6,652        |       | — |   | 223 |   | 1,898 |   | 4,531 |   |
| Interest on Long-Term Debt(1)                |       | 7,611        |       | 331 |   | 662 |   | 657 |   | 5,961 |   |
| Operating Leases(2)                          |       | 715          |       | 91 |   | 224 |   | 205 |   | 195 |   |
| Capital Leases                               |       | 125          |       | 6 |   | 12 |   | 12 |   | 95 |   |
| Energy Commodity Contract Liabilities        |       | 956          |       | 636 |   | 290 |   | 25 |   | 5 |   |
| Transportation and Storage Commitments(2)    |       | 1,261        |       | 379 |   | 411 |   | 267 |   | 204 |   |
| Work Commitments and Purchase Obligations(3) |       | 4,228        |       | 2,029 |   | 1,557 |   | 567 |   | 75 |   |
| Asset Retirement Obligations                 |       | 2,393        |       | 35 |   | 70 |   | 305 |   | 1,983 |   |
| **Total**                                    | ** ** | **23,941**   | ** ** | **3,507** | ** ** | **3,449** | ** ** | **3,936** | ** ** | **13,049** | ** ** |

 

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*(1)**      **Excludes interest on termcredit facilities of $3.7 billion (US$3.1 billion) and Canexus term creditfacilities of $420 million (US$343 million) as the amounts drawn on thefacilities fluctuate. Based on amounts drawn at December 31, 2008 andexisting variable interest rates, we would be required to pay $19 million peryear until the outstanding amounts on the term credit facilities are repaid.*

*(2)**      **Payments for operatingleases and transportation and storage commitments are deducted from our cashflow from operating activities.*

*(3)**      **Some of these paymentsrelate to work commitments that we can cancel without penalties or additionalfees.*

 

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

 

·      Short-termand long-term debt amounts are included on our December 31, 2008Consolidated Balance Sheet.

·      Operatingleases include the minimum lease payment obligations associated with leases foroffice space, rail cars, vehicles and processing agreements that allows ourproduction to flow through third-party processing facilities.

·      Capitalleases include pipeline commitments primarily related to production at LongLake.

·      Energycommodity contract liabilities include the purchase and sale of physical quantitiesof oil and natural gas, and financial derivatives used to manage our exposureto commodity prices. For contracts where the price is based on an index, theamount is based on forward market prices at December 31, 2008. For certaincontracts, we may net settle. These contracts are included in our ConsolidatedBalance Sheet at fair value.

·      Workcommitments include non-discretionary capital spending for drilling, seismic,facilities construction and other development commitments in our internationaloperations, and includes commitments for the Usan development project inNigeria over the next five years ($1,024 million). Also, included in purchaseobligations is $735 million payable in January 2009 for purchasing anadditional 15% ownership interest in the Long Lake Project. Since the timing ofcertain payments is difficult to determine with certainty, the table wasprepared using our best estimates. The majority of our 2009 capital investmentis discretionary.

·      We haveincluded $1,409 million in work commitments for drilling rigs we havecontracted in the UK, Norway and the Gulf of Mexico, over the next five years.

·      We have$2,393 million of undiscounted asset retirement obligations after inflation. Asof December 31, 2008, the discounted value ($1,059 million) of theseestimated obligations was provided for in our Consolidated Financial Statements(including $35 million of estimated current obligations). Since timing of anypayments is difficult to determine with certainty, the table was prepared usingour best estimates.

·      We haveunfunded obligations of $171 million (Nexen—$112 million; Canexus—$9 million;Syncrude—$50 million) under our defined benefit pension plans. Our obligationsfor Nexen and Canexus include $63 million that is unfunded as a result ofstatutory limitations. These obligations are backed by irrevocable letters ofcredit. In addition, existing market conditions created a solvency deficiencyof $46 million for the Nexen defined benefit pension plan during the year.While we were required to fund this over the next five years, we funded thisshortfall in February 2009.

·      We haveexcluded obligations on our tandem option and stock appreciation rightsprograms as the amount and timing of cash payments are not determinable.

 

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·      We haveexcluded our normal purchase arrangements as they are discretionary and arereflected in our expected cash flow from operating activities and capitalexpenditures for 2009.

·      We haveexcluded our future income tax liabilities as the amount and timing of any cashpayment for income taxes is based on taxable income for each fiscal year in thevarious jurisdictions where we operate. We have also excluded future income taxliabilities as they relate to uncertain tax positions, as we cannot provide areasonable estimate as to if, or when future payments would be required.

 

From time to time, we enterinto contracts that require us to indemnify parties against possible claims,particularly when these contracts relate to the sale of assets. On occasion, weprovide indemnifications to the purchaser. Generally, a maximum obligation isnot stated; therefore, the overall maximum amount cannot be reasonablyestimated. We have not made any significant payments related to theseindemnifications. We believe 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 Dominion BondRating Service (DBRS) and BBB- by Standard & Poor’s (S&P). DBRS andS&P currently rate our outlook as stable. Moody’s has placed our ratingunder review for possible downgrade. We believe our strong financial results,ample liquidity and financial flexibility continue to support our creditratings.

 

**Financial AssuranceProvisions 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, 2008, we could berequired to post collateral of up to $1.3 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 and lowersour available liquidity. Just as we may be required to post collateral if wewere downgraded below investment grade, we have similar provisions in many ofour contracts that allow us to demand certain counterparties post collateralfor amounts they owe us if they are downgraded to non-investment grade.

 

**Off-BalanceSheet Arrangements**

 

We have no off-balance sheetarrangements that would have a material adverse effect on our liquidity,consolidated financial position or results of operations. We use operatingleases in the normal course of business as disclosed in ContractualObligations, Commitments and Guarantees on page 69 and in Note 16 to theConsolidated Financial Statements, which is incorporated herein by reference.

 

At December 31, 2008, we hadoutstanding letters of credit supported by $381 million (US$311 million) ofunsecured term credit facilities and $29 million (US$24 million) of uncommittedunsecured credit facilities.

 

**Contingencies**

 

We have no contingencies thatwould have a material adverse effect on our liquidity, consolidated financialposition or results of operations. See Note 16 to the Consolidated FinancialStatements, which is incorporated here by reference for a discussion of ourcontingencies.

 

**CRITICALACCOUNTING ESTIMATES**

 

We make estimates andassumptions that affect: i) the reported amounts of our assets and liabilities;ii) the disclosure of contingent assets and liabilities at the date of theConsolidated Financial Statements; and iii) our revenues and expenses duringthe reporting period. Our management reviews these estimates, including thoserelated to accruals, litigation, environmental and asset retirementobligations, recoverability of assets, income taxes, fair values of derivativeassets and liabilities, capital adequacy, and the determination of provedreserves on an ongoing basis. Changes in facts and circumstances may result inrevised estimates and actual results may differ from these estimates. Ourcritical accounting estimates are discussed below.

 

**Oil andGas Accounting—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.

 

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The process of estimatingreserves is complex. It requires significant judgments 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 on geological, geophysical and engineering assessments;                  |
|--------|--------|--------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                               |
| · |   | future production rates  based on historical performance and expected future operating and investment  activities; |
|   |   |                                                                                                               |
| · |   | future oil and gas prices and  quality differentials;                                                              |
|   |   |                                                                                                               |
| · |   | assumed effects of  regulation by governmental agencies; 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 forthe estimates of the quantities of proved oil and 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 and geoscientists. They are reviewed by engineers familiar with theproperty and by divisional management. An Executive Reserves Committee,including our CEO, CFO and board-appointed internal qualified reservesevaluator, meet with divisional reserves personnel to review the estimates and anychanges from previous estimates.

 

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 as 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 judgments,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 15.

 

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 the internal qualified reserves evaluatorand independent reserves consultants, independent of management, to review thescope of their work, whether they have had access to sufficient information,the nature and satisfactory resolution of any material differences of opinion,and in the case of the independent reserves consultants, their independence. Inthe event of a proposed change to the areas of responsibility of either anindependent reserves consultant or the internal qualified reserves evaluator,the Reserves Committee inquires whether there have been disputes between therespective party and management.

 

The Reserves Committee hasreviewed our procedures for preparing the reserves estimates and relateddisclosures. It 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

 

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free of materialmisstatement. Based on the recommendation of the Reserves Committee, the boardhas approved the reserves estimates and related disclosures in theForm 10-K.

 

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

 
| · |   | determining whether or not  an exploratory well has found economically producible reserves. If  successful, we capitalize the costs of the well, and if not, we expense the  costs immediately. In 2008, $203 million of our total $401 million spent on  exploration drilling was expensed. If none of our exploration drilling had  been successful, our net income would have decreased by $125 million, net of  income tax.                                                                                                                                                                                                                                                                                                                           |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| · |   | calculating our  unit-of-production depletion rates. Both proved and proved developed reserves  estimates are used to determine rates that are applied to each  unit-of-production in calculating our depletion expense. Proved reserves are  used where a property is acquired and proved developed reserves are used  where a property is drilled and developed. In 2008, oil and gas and Syncrude  depletion of $1,340 million (before impairments) was recorded in depletion,  depreciation, amortization and impairment expense. If our reserves estimates  changed by 10%, our depletion, depreciation, amortization and impairment  expense would have changed by approximately $134 million, assuming no other  changes to our reserves profiles. |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| · |   | assessing, when necessary,  our oil and gas assets for impairment. Estimated future undiscounted cash  flows are determined using proved reserves. The critical estimates used to  assess impairment, including the impact of changes in reserves estimates, are  discussed below.                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |

 

Since we do not have any 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, these might include fallingoil and gas prices, a significant negative revision to our reserve estimates,changes in operating and capital costs, or significant or adverse political orregulatory changes. If one of these occurs, we assess estimated undiscountedfuture cash flows for affected properties to determine if they are impaired. Ifthe undiscounted future cash flow for a property is less than the carrying amountof that property, we estimate its fair value using a discounted cash flowmodel.

 

Cash flow estimates for ourimpairment assessments require assumptions about the following primary elements— future prices, reserves and discount rates. Our estimates of future pricesare based on our assumptions of long-term prices and operating and developmentcosts and require significant judgments about highly uncertain future events.Historically, oil and gas prices have exhibited significant volatility — overthe last five years, prices for WTI and NYMEX gas have ranged from US$32.20/bblto US$147.27/bbl and US$4.20/mmbtu to US$15.38/mmbtu, respectively. Ourforecasts for oil and gas revenues are based on prices derived from a consensusof future price forecasts amongst industry analysts, our own assessments andexisting future strip prices. Our estimates of discount rates includeconsideration of the marketplace and risk of the asset. Given the significantassumptions required and the possibility that actual conditions will differ, weconsider the assessment of impairment to be a critical accounting estimate. Achange in these estimates would impact all businesses with the exception ofchemicals and energy marketing.

 

It is difficult to determineand assess how a decrease in proved reserves impacts our impairment tests. Therelationship between our reserve 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 reserve estimate decrease would have on our assessment ofimpairment.

 

Goodwill

 

We test goodwill forimpairment whenever an event or circumstance occurs that may reduce the fairvalue of a reporting unit below its carrying amount and at least annually. Ourgoodwill impairment test is a two-step process. First, the fair value of areporting unit is compared with its carrying amount, including goodwill. If thecarrying amount of the reporting unit exceeds the fair value, the second stepis required. The second step allocates the fair value of the reporting unit toits underlying assets and liabilities, resulting in an implied fair value ofgoodwill. If the carrying amount of the reporting unit exceeds the implied fairvalue of that goodwill, an impairment loss equal to the excess is recorded innet income.

 

The process of assessinggoodwill for impairment necessarily requires us to determine the fair values ofour assets using one or more valuation techniques including present valuecalculations of estimated future cash flows. This process involves

 

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making various assumptionsand judgments about future commodity prices, future income, operating costs anddiscount rates. Changes in any of these assumptions or judgments could resultin an impairment of all or a portion of goodwill.

 

**AssetRetirement Obligations**

 

We are required to remove orremedy the effect of our activities on the environment at our present andformer operating sites by dismantling and removing production facilities andremediating any damage caused. In estimating our future asset retirementobligations, we must make estimates and judgments on activities that will occurmany years into the future. Additionally, contracts and regulations are oftenvague and unclear as to what constitutes removal and remediation. Furthermore,the ultimate financial impact is not always clearly known and cannot bereasonably estimated as asset removal and remediation techniques and costs areconstantly changing, as are legal, regulatory, environmental, political, safetyand other such considerations.

 

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 judgments are made on ultimatesettlement amounts, inflation factors, credit-adjusted discount rates, timingof settlement and expected changes in legal, regulatory, environmental,political and safety environments. The asset retirement obligations we recordincrease the carrying cost of our property, plant and equipment and accreteswith the passage of time.

 

A change in any one of ourassumptions could impact our asset retirement obligations, the carrying valueof our property, plant and equipment and our net income.

 

**Income Taxes**

 

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

 

**Derivativesand Fair Value Measurements**

 

We enter into contracts topurchase and sell crude oil and natural gas and use derivative contracts,including futures, forwards, swaps and options, for hedging and tradingpurposes (collectively derivatives). We also use derivatives to managecommodity price risk and foreign currency risk for non-trading purposes.

 

The fair value of derivativecontracts is estimated. Wherever possible, this estimate is based on quotedmarket prices, and if not available, on estimates from third-party brokers. Weclassify the fair value of our derivatives according to a three-level hierarchybased on the amount of observable inputs used to value the instruments. Inputsmay be; (1) readily observable; (2) market corroborated; or(3) generally unobservable. We utilize valuation techniques that maximizethe use of observable inputs wherever possible and minimize the use ofunobservable inputs. Another significant assumption that we use in determiningthe fair value of derivatives is market data or assumptions that marketparticipants would use when pricing the asset or liability, includingassumptions about risk. Additionally, we utilize a mid-market pricingconvention between bid and ask and then adjust our pricing to the ask pricewhen we have a net open sell position and the bid price when we have a net openbuy position. We incorporate the credit risk associated with counterpartydefault into our estimates of fair value.

 

Our assessment of thesignificance of a particular input to the fair value measurement may affect thevaluation of fair value within the hierarchy. Also for derivative contracts,the time between inception and settlement of the contract may affect fairvalue. The actual settlement of derivatives could differ materially from thefair value recorded and could impact future operating results.

 

**NEWACCOUNTING PRONOUNCEMENTS**

 

**InternationalFinancial Reporting Standards Adoption Plan**

 

In February 2008, theAcSB confirmed that all Canadian publicly accountable enterprises will berequired to adopt International Financial Reporting Standards (IFRS) forinterim and annual reporting purposes for fiscal years beginning on or afterJanuary 1, 2011. We are currently assessing the impact of the convergenceof Canadian GAAP with IFRS on our results of operations, financial position anddisclosures. A project team has been established to manage this transition andto ensure successful implementation within the required time frame.

 

The project team consists ofdedicated personnel who have the experience and IFRS knowledge to ensuresuccess within the required time frame. A steering committee comprised ofsenior

 

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management has beenestablished for project oversight. The steering committee has theresponsibility to ensure the project is adequately planned in sufficientdetail, appropriate resources are available, necessary milestones areestablished and project progress is properly monitored. These senior leaders arealso responsible for internal controls over financial reporting and ourdisclosure controls and procedures.

 

We recognize that thechangeover to IFRS has complex implications on a combination of accounting, ITand business systems, and that there are many aspects to IFRS that we areunfamiliar with. Consequently, we engaged a major accounting firm to providetraining and education, and to advise and assist us with identifying accountingtreatment differences between IFRS and Canadian GAAP. In addition, based ontheir previous conversion engagements, we expect our advisor to be able tocreate efficiencies in our conversion effort by sharing their experiences andinforming us of best practices.

 

Our project consists of 5phases: (i) Diagnostic; (ii) Design and Plan; (iii) DevelopSolution; (iv) Implementation; and (v) Closeout. We are currently inthe Design and Plan phase. During this phase, we are identifying differencesbetween Canadian GAAP and IFRS, gathering information and financial data toassess the potential impacts of these differences, and making recommendationsfor IFRS accounting policy decisions. Discussion papers are being prepared toproperly document the information gathered and support our rationale for ouraccounting policy recommendations. Factors such as financial and keyperformance indicator impacts, information technology and systems, internalcontrol environment, treasury, human resources, and general business impactsare outlined in the papers.

 

Major accounting policychange decisions are expected to be evaluated in early 2009. Our oil and gasbusiness follows successful efforts accounting as described in Note 1 of ourconsolidated financial statements. Our preliminary review of IFRS indicatesthat the majority of our existing oil and gas accounting policies areacceptable under IFRS. However, the analysis and comparison between ourexisting accounting policies and IFRS is complex. Our goal is to chose policiesthat most accurately reflect the underlying economic results of our operationsand financial position within the IFRS framework.

 

Following completion of theDesign and Plan stage, we will be involved with the Develop Solution andImplementation phases throughout the remainder of 2009 and into 2010. We willprovide additional disclosures of the key elements of our plan and progress ofthe project as the information becomes available.

 

**CanadianPronouncements**

 

In February 2008, theAcSB issued Section 3064, *Goodwill andIntangible Assets* and amended Section 1000, *Financial Statement Concepts* clarifyingthe criteria for recognizing assets, intangible assets and internally developedintangible assets. Items that no longer meet the definition of an asset are nolonger recognized with assets. The standard is effective for fiscal years beginningon or after October 1, 2008 and early adoption is permitted. We do notexpect the adoption of this section to have a material impact on our results ofoperations and financial position.

 

In January 2009, theAcSB issued Section 1582, *BusinessCombinations*, which replaces former guidance on businesscombinations. Section 1582 establishes principles and requirements of theacquisition method for business combinations and related disclosures. Thisstatement applies prospectively to business combinations for which theacquisition date is on or after the beginning of the first annual reportingperiod beginning on or after January 2011, with earlier adoptionpermitted. We plan to adopt this standard prospectively effectiveJanuary 1, 2009 and do not expect the adoption of this statement to have amaterial impact on our results of operations or financial position.

 

In January 2009, theAcSB issued Sections 1601, *ConsolidatedFinancial Statements*, and 1602, *Non-controllingInterests*, which replaces existing guidance. Section 1601establishes standards for the preparation of consolidated financial statements.Section 1602 provides guidance on accounting for a non-controllinginterest in a subsidiary in consolidated financial statements subsequent to abusiness combination. These statements are effective on or after the beginningof the first annual reporting period beginning on or after January 2011,with earlier adoption permitted. We plan to adopt these standards prospectivelyeffective January 1, 2009 and do not expect the adoption to have amaterial impact on our results of operations or financial position.

 

**USPronouncements**

 

In December 2007, FASBissued Statement 141 (revised), *BusinessCombinations*. Statement 141 establishes principles and requirementsof the acquisition method for business combinations and related disclosures.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.

 

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In December 2007, FASBissued Statement 160, *Non-controllingInterests In Consolidated Financial Statements*, an amendment of ARBNo. 51. This statement clarifies that a non-controlling interest in asubsidiary should be reported as equity in the consolidated financialstatements. 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.

 

In March 2008, FASBissued Statement 161, *Disclosures aboutDerivative Instruments and Hedging Activities*, an amendment of FASBStatement 133. The statement requires qualitative disclosures about theobjectives and strategies for using derivatives, quantitative data about thefair value of gains and losses on derivative contracts, and details ofcredit-risk-related contingent features in their hedged position. The statementalso requires the disclosure of the location and amounts of derivativeinstruments in the financial statements. This statement is effective for fiscalyears and interim periods beginning on or after November 15, 2008. We donot expect the adoption of this statement to materially impact our results ofoperations or financial position.

 

In December 2008, FASBissued FSP FAS 132 (R)-1, *Employers’Disclosures about Postretirement Benefit Plan Assets*. This positionprovides guidance on disclosures about plan assets of a defined benefit pensionor other postretirement plans, effective for fiscal years ending afterDecember 15, 2009. We do not expect the adoption of this statement tomaterially impact our results of operations or financial position.

 

In December 2008, theSEC issued Rule 33-8995 *Modernizationof Oil and Gas Reporting*. These rules revise oil and gasreporting disclosure requirements and are intended to provide investors with amore meaningful and comprehensive understanding of oil and gas reserves. Theserules are effective for reports filed after January 1, 2010; earlieradoption is not permitted. We are currently evaluating the impact of theserules on our reserve estimates and disclosures.

 

**ITEM 7A.**

** **

**Quantitative and QualitativeDisclosures 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 prices are sensitive to numerousworldwide factors, including the current global financial crisis, many of whichare beyond 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 gasproperties and our level of spending for exploration and development.

 

Our crude oil prices arebased on various reference prices, primarily WTI and Brent and other priceswhich generally track the movement of WTI and Brent. Adjustments are made tothe reference prices to reflect quality differentials and transportation. WTI,Brent and other international reference prices are affected by numerous andcomplex worldwide factors such as supply and demand fundamentals, economicoutlooks, production quotas set by the Organization of Petroleum ExportingCountries and political events. Quality differentials are affected by local supplyand demand factors.

 

We are also exposed tonatural gas price movements. Natural gas prices are generally influenced by oilprices and supply and demand fundamentals, and to a lesser extent local marketconditions.

 

In 2008, WTI averagedUS$99.65/bbl, reaching a high of US$147.27/bbl and a low of US$32.40/bbl. DatedBrent, on which approximately 64% of our production is priced, averaged US$96.99/bbl,reaching a high of US$144.22/bbl and a low of US$33.66/bbl. NYMEX natural gasprices averaged US$8.90/mmbtu in 2008, reaching a high of US$13.69/mmbtu and alow of US$5.21/mmbtu. Our sensitivities to commodity prices and the expectedimpact on our 2009 cash flow from operating activities and net income are asfollows:

 
| **(Cdn$ millions)**                    | ** ** | **Cash  Flow** | ** ** | **Net  Income** | ** ** |
|---------------------------------------------|------------|----------------|------------|-----------------|------------|
| WTI — US$1/bbl change above US$60      |       | 50             |       | 44              |       |
| WTI — US$1/bbl change below US$60      |       | 40             |       | 35              |       |
| NYMEX Natural Gas — US$0.50/mcf change |       | 34             |       | 23              |       |

 

These sensitivities are basedon our estimated 2009 oil and gas production and assume a Canadian/US dollarexchange rate of $0.83. Our estimated oil and gas production range for 2009 isbetween 255,000 and 270,000 boe/d before royalties, of which approximately 16%is gas.

 

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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 2008, we purchased DatedBrent put options to manage the commodity price risk exposure on a portion ofour oil production in 2009. These put options have established an annualaverage Dated Brent floor price of US$60/bbl on about 45,000 bbls/d ofproduction.

 

**ForeignCurrency Risk**

 

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

 

·                  salesof crude oil, natural gas and certain chemicals products;

 

·                  capitalspending and expenses for our oil and gas, Syncrude and chemicals operations;and

 

·                  short-termand long-term borrowings.

 

The Canadian/US dollarexchange rate averaged $0.94 in 2008, ranging from a low of $0.77 to a high of$1.03.

 

Our sensitivities to the USdollar and the expected impact of a one cent change on our 2009 cash flow fromoperating activities, net income, capital expenditures and long-term debt is asfollows:

 
| **(Cdn$ millions)**  | ** ** | **Cash  Flow** | ** ** | **Net  Income** | ** ** | **Capital  Expenditures** | ** ** | **Long-term  Debt** | ** ** |
|---------------------------|------------|----------------|------------|-----------------|------------|---------------------------|------------|---------------------|------------|
| $0.01 Change in US to Cdn |       | 36             |       | 18              |       | 23                        |       | 50                  |       |

 

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 2009. These estimates are based on a WTI price for crude oil rangingbetween US$50/bbl and US$65/bbl, a NYMEX natural gas price of US$6.50/mmbtu anda Canadian/US dollar exchange rate of $0.83.

 

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 calloptions to reduce this exposure. As part of the technical conversion project,Canexus also has a contract in Japanese Yen. To manage these exposures, Canexushad the following outstanding option contracts at December 31, 2008.

 
| · |   | The right to sell US$5  million monthly and purchase Canadian dollars at an exchange rate of US$0.82  from January 1, 2009 to December 31, 2009;      |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                            |
| · |   | The right to sell US$5  million monthly and purchase Canadian dollars at an exchange rate of US$0.817  from January 1, 2009 to December 31, 2009; and |
|   |   |                                                                                                                                                            |
| · |   | A forward exchange contract  to purchase 1.74 billion Japanese Yen (JPY) at a rate of 108.11 JPY per US  dollar on May 20, 2009.                           |

 

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 our exposureto interest rate fluctuations, we occasionally use derivative instruments.

 

Our sensitivity to interestrates and the expected impact of a 1% change in interest rates on our 2009 cashflow from operating activities and net income is as follows:

 
| **(Cdn$ millions)**                 | ** ** | **Cash  Flow** | ** ** | **Net  Income** | ** ** |
|------------------------------------------|------------|----------------|------------|-----------------|------------|
| Interest Rates — 1% change in rates |       | 12             |       | 9               |       |

 

Our sensitivity to changes ininterest rates is based on 2009 estimated average floating rate debt of $1.2billion and a Canadian/US dollar exchange rate of $0.83.

 

Our floating rate debtexposes us to changes in interest payments as interest rates fluctuate. Tomanage this exposure, we maintain a combination of fixed and floating rateborrowings and facilities. At December 31, 2008, fixed-rate borrowingscomprised 78% (2007 — 91%) of our long-term debt at an effective average rateof 6.4% (2007 — 6.3%). During the year, we periodically borrow under ourcommitted, unsecured, term credit facilities and at December 31, 2008,floating-rate debt comprised 22% (2007 — 9%) of our long-term debt at aneffective average rate of 2.7% (2007 — 5.8%) ranging from a low of 1.0% to ahigh of 7.8% during 2008.

 

We had no interest rate swapsoutstanding in 2008 or 2007.

 

76

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**TRADING**

 

**Commodity PriceRisk**

 

Our marketing business isfocused on providing services to our customers and suppliers to meet theirenergy commodity needs. We market and trade physical energy commodities inselected regions of the globe including crude oil, natural gas, electricity andother commodities. We do this by buying and selling physical commodities, byacquiring and holding rights to physical transportation and storage assets forthese commodities, and by building strong relationships with our customers andsuppliers.

 

In order to manage thecommodity and foreign exchange price risks that come from this physicalbusiness, we use financial derivative contracts including energy-relatedfutures, forwards, swaps and options, as well as currency swaps or forwards.

 

We also seek to profit fromour views on the future direction of energy commodity pricing relationships,primarily between different locations, time periods or qualities. We do this byholding open positions, where the terms of physical or financial contracts arenot completely matched to offsetting positions. We may also carry exposures tothe absolute change in commodity prices based on our market views or as aconsequence of managing our physical and financial positions on a day to daybasis.

 

The physical and financialmarketing and trading activities we undertake expose us to the risk of loss(and provide the opportunity to profit) from a range of factors including:

 
| · |   | changes to the absolute  level of commodity prices;                                          |
|--------|--------|----------------------------------------------------------------------------------------------|
|   |   |                                                                                         |
| · |   | changes in the prices of  commodities at specific locations;                                 |
|   |   |                                                                                         |
| · |   | changes in the relative  level of nearer term prices to future prices;                       |
|   |   |                                                                                         |
| · |   | changes in the relative  value of different qualities of a commodity;                        |
|   |   |                                                                                         |
| · |   | changes in the volatility  of commodity prices;                                              |
|   |   |                                                                                         |
| · |   | changes in the  relationships between energy commodity prices and/or derivative instruments; |
|   |   |                                                                                         |
| · |   | changes in the operational  costs of our physical transportation and storage contracts;      |
|   |   |                                                                                         |
| · |   | physical or financial loss  of physical product; and                                         |
|   |   |                                                                                         |
| · |   | disputes over terms of  deals and contracts.                                                 |

 

In order to manage theserisks we have risk management systems and processes including:

 
| · |   | regular reporting to the  Board of Directors;                  |
|--------|--------|----------------------------------------------------------------|
|   |   |                                                           |
| · |   | regular reporting to the  Risk Management Committee;           |
|   |   |                                                           |
| · |   | oversight of activities by  experienced commercial management; |
|   |   |                                                           |
| · |   | a separate Risk Management  Office; and                        |
|   |   |                                                           |
| · |   | comprehensive policies,  procedures and controls.              |

 

Our risk managementactivities make use of tools such as Value at Risk (VaR) and stress testing.VaR is a statistical estimate of the expected profit or loss of a portfolio ofpositions assuming normal market conditions. We use a 95% confidence intervaland an assumed two day holding period in our measure, although actual resultscan differ from this estimate in non-normal market conditions, or if positionsare held longer than two days based on market views or a lack of marketliquidity to exit them, which is typical for long-term assets. We estimate VaRprimarily by using the Variance-Covariance method based on historical commodityprice volatility and correlation inputs where available, and by historicalsimulation in other situations. Our estimate is based upon the following keyassumptions:

 
| · |   | changes in commodity prices  are either normally or “T” (for natural gas since May 2006) distributed; |
|--------|--------|----------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                 |
| · |   | price volatility remains  stable; and                                                                                |
|   |   |                                                                                                                 |
| · |   | price correlation  relationships remain stable.                                                                      |

 

We have defined VaR limitsfor different segments of our business. These limits are calculated on aneconomic basis and include physical and financial derivatives, as well asphysical transportation and storage capacity contracts accounted for asexecutory contracts in our financial statements. We monitor and report ourpositions against these VaR limits daily. Our year end, annual high, annual lowand average VaR amounts are as follows:

 
| **(Cdn$ millions)** | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|--------------------------|------------|----------|------------|----------|------------|----------|------------|
| **Value-at-Risk**        |       |     |       |     |       |     |       |
| Year End                 |       | 25       |       | 26       |       | 26       |       |
| High                     |       | 40       |       | 38       |       | 33       |       |
| Low                      |       | 19       |       | 24       |       | 17       |       |
| Average                  |       | 30       |       | 30       |       | 23       |       |

 

If market shock occurred asin 2008, the key assumptions underlying our VaR estimate could be exceeded andthe potential loss could be greater than our estimate. We perform stress testson a regular basis to complement VaR and assess the impact of non-normalchanges in prices on our positions.

 

Throughout the second half of2008 and into 2009, we have been realigning our marketing strategies andpositions to focus more on physical business which has been built around storage,blending and transportation. To this end, we are reducing our trading levels inan orderly fashion recognizing the challenging economic environment and we havereduced the overall size of our trading business to reduce volatility and focuson the physical side of our business. We are exiting trading positions that donot support our physical business and we are continuing to reduce tradingexposures.

 

77

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**CREDIT RISK**

 

Credit risk affects both ourtrading and non-trading activities and is the risk of loss if counterparties donot fulfill their contractual obligations. Most of our credit exposures arewith counterparties in the energy industry, including integrated oil companies,refiners and utilities and are subject to normal industry credit risk.Approximately 71% of our exposure is with these large energy companies. Thisconcentration of risk within the energy industry is reduced because of ourbroad base of domestic and international counterparties. We take the followingmeasures to reduce this risk:

 
| · |   | assess the financial  strength of our counterparties through a formal credit process;                                                                                                                      |
|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                       |
| · |   | limit the total exposure  extended to individual counterparties, and may require collateral from some  counterparties;                                                                                     |
|   |   |                                                                                                                                                                                                       |
| · |   | routinely monitor credit  risk exposures, including sector, geographic and corporate concentrations of  credit, and report these to our Risk Management Committee and the Finance  Committee of the board; |
|   |   |                                                                                                                                                                                                       |
| · |   | set credit limits based on  rating agency credit ratings and internal assessments based on company and  industry analysis;                                                                                 |
|   |   |                                                                                                                                                                                                       |
| · |   | review counterparty credit  limits regularly; and                                                                                                                                                          |
|   |   |                                                                                                                                                                                                       |
| · |   | use standard agreements  that 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. During 2008,we have taken the following specific actions for certain counterparties deemedto be at higher risk of non-performance:

 
| · |   | ceased trading activities;                                                                                 |
|--------|--------|------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                       |
| · |   | significantly reduced and,  in some cases, revoked credit privileges;                                      |
|   |   |                                                                                                       |
| · |   | redirected business to i)  exchanges or clearing houses; and ii) entities with physical-based  operations; |
|   |   |                                                                                                       |
| · |   | increased “set off”  arrangements with counterparties; and                                       |
|   |   |                                                                                                       |
| · |   | increased collateral and  margining requirements where possible.                                           |

 

At December 31, 2008,only one counterparty individually made up more than 10% of our creditexposure. This counterparty is a major integrated oil company with a stronginvestment grade rating. No other counterparties made up more than 5% of ourcredit exposure. In addition, the following table illustrates the compositionof credit exposure by credit rating.

 
| **Credit Rating** | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------|------------|----------|------------|----------|------------|
| A or Higher            |       | 65       | %          | 68       | %          |
| BBB                    |       | 29       | %          | 27       | %          |
| Non investment Grade   |       | 6        | %          | 5        | %          |

 

Our maximum counterpartycredit exposure at the balance sheet date consists primarily of the carryingamounts of non-derivative financial assets such as accounts receivable, as wellas the fair value of derivative financial assets. In September, Lehman Brothersfiled for bankruptcy protection and our exposure at the time was approximately$39 million. This amount was written off, however, we continue to pursuerecovery of these amounts. We also provided an additional $15 million forcredit risk with our counterparties. We are closely monitoring creditexposures. In addition, we incorporate the credit risk associated withcounterparty default, as well as Nexen’s own credit risk, into our estimates offair value. We based our credit risk estimates, to the extent possible, onmarket observable inputs such as bond spreads.

 

**SPECIAL NOTEREGARDINGFORWARD-LOOKING STATEMENTS**

 

Certain statements in thisreport, including those appearing in *Items 1and 2**—**Business and Properties* and *Item 7**—**Management’s Discussion and Analysis of Financial Conditionand Results of Operations*, constitute “forward-lookingstatements” (within the meaning of the United States *Private Securities Litigation Reform Act*of 1995,Section 21E of the United States *SecuritiesExchange Act of 1934,*as amended, and Section 27A of the UnitedStates *Securities Act of 1933,* asamended) or “forward-looking information” (within the meaning of applicableCanadian securities legislation). Such statements or information (together“forward-looking statements”) are generally identifiable by the forward-lookingterminology used such as “anticipate”, “believe”, “intend”, “plan”, “expect”,“estimate”, “budget”, “outlook”, “forecast” or other similar words and includestatements relating to or associated with individual wells, regions orprojects. Any statements regarding the following are forward-lookingstatements:

 
| · |   | future crude oil, natural  gas or chemicals prices; |
|--------|--------|-----------------------------------------------------|
|   |   |                                                |
| · |   | future production levels;                           |

 

78

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| · |   | future cost recovery oil  revenues from our Yemen operations;                                |
|--------|--------|----------------------------------------------------------------------------------------------|
|   |   |                                                                                         |
| · |   | future capital  expenditures and their allocation to exploration and development activities; |
|   |   |                                                                                         |
| · |   | future earnings;                                                                             |
|   |   |                                                                                         |
| · |   | future asset dispositions;                                                                   |
|   |   |                                                                                         |
| · |   | future sources of funding  for our capital program;                                          |
|   |   |                                                                                         |
| · |   | future debt levels;                                                                          |
|   |   |                                                                                         |
| · |   | availability of committed  credit facilities;                                                |
|   |   |                                                                                         |
| · |   | 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  current and long-term assets;                                    |
|   |   |                                                                                         |
| · |   | ultimate recoverability of  reserves or resources;                                           |
|   |   |                                                                                         |
| · |   | expected finding and  development costs;                                                     |
|   |   |                                                                                         |
| · |   | expected operating costs;                                                                    |
|   |   |                                                                                         |
| · |   | future demand for chemical  products;                                                        |
|   |   |                                                                                         |
| · |   | estimates on a per share  basis;                                                             |
|   |   |                                                                                         |
| · |   | sales;                                                                                       |
|   |   |                                                                                         |
| · |   | future expenditures and  future allowances relating to environmental matters;                |
|   |   |                                                                                         |
| · |   | dates by which certain  areas will be developed or will come on stream; and                  |
|   |   |                                                                                         |
| · |   | changes in any of the  foregoing.                                                            |

 

Statements relating to“reserves” or “resources” are forward-looking statements, as they involve theimplied assessment, based on estimates and assumptions that the reserves andresources described exist in the quantities predicted or estimated, and can beprofitably produced 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 todiffer materially from those expressed or implied by such statements. Suchfactors include, among others:

 
| · |   | market prices for oil and  gas and chemical products;                                                                                            |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                             |
| · |   | our ability to explore,  develop, produce and transport crude oil and natural gas to markets;                                                    |
|   |   |                                                                                                                                             |
| · |   | the results of exploration  and development drilling and related activities;                                                                     |
|   |   |                                                                                                                                             |
| · |   | volatility in energy  trading markets;                                                                                                           |
|   |   |                                                                                                                                             |
| · |   | foreign-currency exchange  rates;                                                                                                                |
|   |   |                                                                                                                                             |
| · |   | economic conditions in the  countries and regions in which we carry on business;                                                                 |
|   |   |                                                                                                                                             |
| · |   | governmental actions  including changes to taxes or royalties, changes in environmental and other  laws and regulations;                         |
|   |   |                                                                                                                                             |
| · |   | renegotiations of  contracts;                                                                                                                    |
|   |   |                                                                                                                                             |
| · |   | results of litigation,  arbitration or regulatory proceedings; and                                                                               |
|   |   |                                                                                                                                             |
| · |   | political uncertainty,  including actions by terrorists, insurgent or other groups, or other armed  conflict, including conflict between states. |

 

These risks, uncertaintiesand other factors and their possible impact are discussed more fully in thesection, titled *Risk Factors* inItem 1A and *Quantitative and QualitativeDisclosures about Market Risk*in Item 7A. The impact of any onerisk, uncertainty or factor on a particular forward-looking statement is notdeterminable with certainty as these factors are interdependent, andmanagement’s future course of action would depend on our assessment of allinformation 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 containedherein, which are made as of the date hereof and, except as required by law, weundertake no obligation to update publicly or revise any forward-looking statements,whether as a result of new information, future events or otherwise. Theforward-looking statements contained herein are expressly qualified by thiscautionary statement.

 

**SPECIALNOTE TO CANADIAN INVESTORS**

 

Nexen is an SEC registrantand a voluntary Form 10-K (and related forms) filer. Therefore, ourreserves estimates and securities regulatory disclosures follow SECrequirements. In Canada, *National Instrument51-101**—**Standards of Disclosure for Oil and Gas Activities*(NI 51-101) prescribes that Canadian companies follow certain standards for thepreparation and disclosure of reserves and related information. Nexen reservesdisclosures are made in reliance upon exemptions granted to Nexen by Canadiansecurities regulators from certain requirements of NI 51-101 which permits usto:

 
| · |   | prepare our reserves  estimates and related disclosures in accordance with SEC disclosure  requirements, generally accepted industry practices in the US and the  standards of the *Canadian Oil and Gas  Evaluation Handbook* (COGE Handbook) modified to reflect SEC  requirements; |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                  |
| · |   | substitute those SEC  disclosures for much of the annual disclosure required by NI 51-101; and                                                                                                                                                                                        |

 

79

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| · |   | rely upon  internally-generated reserves estimates and the *Standardized Measure of Discounted Future Net Cash Flows and Changes  Therein*, included in the Supplementary Financial Information,  without the requirement to have those estimates evaluated or audited by  independent qualified reserves evaluators. |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

As a result of theseexemptions, Nexen’s disclosures may differ from other Canadian companies andCanadian investors should note the following fundamental differences inreserves estimates and related disclosures contained in the Form 10-K:

 
| · |   | SEC registrants apply SEC  reserves definitions and prepare their proved reserves estimates in  accordance with SEC requirements and generally accepted industry practices in  the US whereas NI 51-101 requires adherence to the definitions and standards  promulgated by the COGE Handbook;            |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                      |
| · |   | the SEC mandates  disclosure of proved reserves and the Standardized Measure of Discounted  Future Net Cash Flows and Changes Therein calculated using year-end constant  prices and costs only whereas NI 51-101 requires disclosure of reserves and  related future net revenues using forecast prices; |
|   |   |                                                                                                                                                                                                                                                                                                      |
| · |   | the SEC mandates  disclosure of proved and proved developed reserves by geographic region only  whereas NI 51-101 requires disclosure of more reserve categories and product  types;                                                                                                                      |
|   |   |                                                                                                                                                                                                                                                                                                      |
| · |   | the SEC does not prescribe  the nature of the information required in connection with proved undeveloped  reserves and future development costs whereas NI 51-101 requires certain  detailed information regarding proved undeveloped reserves, related  development plans and future development costs;  |

 
| · |   | the SEC does not require  disclosure of finding and development (F&D) costs per boe of proved  reserves additions whereas NI 51-101 requires that various F&D costs per  boe be disclosed. NI 51-101 requires that F&D costs be calculated by  dividing the aggregate of exploration and development costs incurred in the  current year and the change in estimated future development costs relating to  proved reserves by the additions to proved reserves in the current year.  However, this will generally not reflect full cycle finding and development  costs related to reserve additions for the year;                                                                                |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| · |   | the SEC leaves the  engagement of independent qualified reserves evaluators to the discretion of  a company’s board of directors whereas NI 51-101 requires issuers to engage  such evaluators and to file their reports;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| · |   | the SEC does not consider  the upgrading component of our integrated oil sands project at Long Lake as  an oil and gas activity, and therefore permits recognition of bitumen  reserves only. NI 51-101 specifically includes such activity as an oil and  gas activity and recognizes synthetic oil as a product type, and therefore  permits recognition of synthetic reserves. At year end, we have recognized  285 million barrels before royalties of proved bitumen reserves (282 million  barrels after royalties) under SEC requirements, whereas under NI 51-101 we  would have recognized 233 million barrels before royalties of proved  synthetic reserves (231 million barrels after royalties); |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| · |   | the SEC considers our  Syncrude operation as a mining activity rather than an oil and gas activity,  and therefore does not permit related reserves to be included with oil and  gas reserves. NI 51-101 specifically includes such activity as an oil and gas  activity and recognizes synthetic oil as a product type, and therefore  permits them to be included with oil and gas reserves. We have provided a  separate table showing our share of the Syncrude proved reserves as well as  the additional disclosures relating to mining activities required by SEC  requirements; and                                                                                                                   |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| · |   | any reserves data in this  document reflects our estimates of reserves. While we obtain an independent  assessment of a portion of our reserves estimates, no independent qualified  reserves evaluator or auditor was involved in the preparation of the reserves  data disclosed in this Form 10-K.                                                                                                                                                                                                                                                                                                                                                                                                    |

 

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. A  conversion ratio of 6 mcf of natural gas to 1 barrel of oil is used. Boe may  be misleading, particularly if used in isolation. The conversion ratio is based  on an energy equivalency conversion method primarily applicable at the burner  tip and does not represent a value equivalency at the wellhead; and |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                    |
| · |   | because reserves data are  based on judgments regarding future events actual results will vary and the  variations may be material. Variations as a result of future events are  expected to be consistent with the fact that reserves are categorized  according to the probability of their recovery.                                                                                                                 |

 

80

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----

 

**S****tatements**

 

**PART II**

 
| ITEM 8.                                                                               |   |
|---------------------------------------------------------------------------------------|--------|
| Report of Management                                                                  | 81     |
| Report of Independent Registered Chartered Accountants                                | 82     |
| Consolidated Financial Statements                                                     |   |
| Consolidated Statement of  Income                                                     | 83     |
| Consolidated Balance Sheet                                                            | 84     |
| Consolidated Statement of  Cash Flows                                                 | 85     |
| Consolidated Statement of  Shareholders’ Equity                                  | 86     |
| Consolidated Statement of  Comprehensive Income                                       | 86     |
| Notes to Consolidated  Financial Statements                                           | 87     |
|                                                                                  |   |
| Supplementary Data (Unaudited)                                                        |   |
| Quarterly Financial Data  in Accordance with Canadian and US GAAP                     | 125    |
| Oil and Gas Producing  Activities and Syncrude Operations                             | 126    |
|                                                                                  |   |
| ITEM 9.                                                                               |   |
| Changes in and Disagreements with Accountants on Accounting and  Financial Disclosure | 131    |
|                                                                                  |   |
| Item 9A.                                                                              |   |
| Controls and Procedures                                                               |   |
| Evaluation of Disclosure Controls and Procedures                                      | 131    |
| Management’s Report on Internal Control Over Financial Reporting                 | 131    |
| Changes in Internal Controls                                                          | 132    |
| Report of Independent Registered Chartered Accountants                                | 132    |

 

----

 

ITEM 8.

 

**REPORT OF MANAGEMENT**

 

February 11, 2009

 

**To the Shareholders of Nexen Inc.:**

 

We are responsible for the preparation and fair presentation of theconsolidated financial statements, as well as the financial reporting processthat gives rise to such consolidated financial statements. This responsibilityrequires us to make significant accounting judgments and estimates. Forexample, we are required to choose accounting principles and methods that areappropriate to the company’s circumstances, and we are required to makeestimates and assumptions that affect amounts reported. Fulfilling thisresponsibility requires the preparation and presentation of our consolidatedfinancial statements in accordance with generally accepted accountingprinciples in Canada with a reconciliation to generally accepted accountingprinciples in the US.

 

We also have responsibility for the preparation and fair presentationof other financial information in this report and to ensure the consistency ofthis information with the financial statements.

 

We are responsible for the development and implementation of internalcontrols over the financial reporting process. These controls are designed toprovide reasonable assurance that relevant and reliable financial informationis produced. To gather and control financial data, we have established accountingand reporting systems supported by internal controls over financial reportingand an internal audit program. We believe that our internal controls overfinancial reporting provide reasonable assurance that our assets aresafeguarded against loss from unauthorized use or disposition, that receiptsand expenditures of the company are made only in accordance with authorizationof management and directors of the company, and that our records are reliablefor preparing our consolidated financial statements and other financialinformation in accordance with applicable generally accepted accountingprinciples 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 established disclosure controls and procedures, internalcontrols over financial reporting and corporate-wide policies to ensure thatNexen’s consolidated financial position, results of operations and cash flowsare presented fairly. Our disclosure controls and procedures are designed toensure timely disclosure and communication of all material information requiredby regulators. We oversee, with assistance from our Disclosure ReviewCommittee, these controls and procedures and all required regulatorydisclosures.

 

To ensure the integrity of our financial statements, we carefullyselect and train qualified personnel. We also ensure our organizationalstructure provides appropriate delegation of authority and division ofresponsibilities. Our policies and procedures are communicated throughout theorganization and include a written ethics and integrity policy that applies toall employees, including the chief executive officer, chief financial officerand chief accounting officer or controller.

 

Our board of directors is responsible for reviewing and approving theconsolidated financial statements and for overseeing management’s performanceof its financial reporting responsibilities. Their financial statement relatedresponsibilities are fulfilled mainly through the Audit and Conduct ReviewCommittee (the Audit Committee), with assistance from the Reserves ReviewCommittee regarding the annual review of our petroleum, natural gas andSyncrude reserves, and the Finance Committee regarding the assessment andmitigation of risk. The Audit Committee is composed entirely of independentdirectors and includes three directors with financial expertise. The AuditCommittee meets regularly with management, the internal auditors and theindependent registered Chartered Accountants to review accounting policies,financial reporting and internal control issues and to ensure each party isproperly discharging its responsibilities. The Audit Committee is responsiblefor the appointment and compensation of the independent registered CharteredAccountants and also considers their independence, reviews their fees and(subject to applicable securities laws), pre-approves their retention for anypermitted non-audit services and their fee for such services. The internalauditors and independent registered Chartered Accountants have full andunlimited access to the Audit Committee, with and without the presence ofmanagement.

 
| (signed) “Marvin F. Romanow”            |   |
|---------------------------------------------------|--------|
| President and Chief Executive Officer             |   |
|                                              |   |
| (signed) “Kevin J. Reinhart”            |   |
| Senior Vice President and Chief Financial Officer |   |

 

81

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**REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS**

 

**To the Board of Directors and Shareholders of NexenInc.:**

 

We have audited the accompanying consolidated balance sheets of NexenInc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007,and the related consolidated statements of income, cash flows, shareholders’equity and comprehensive income for each of the years in the three year periodended December 31, 2008. These financial statements are the responsibilityof the Company’s management. Our responsibility is to express an opinion onthese financial statements based on our audits.

 

We conducted our audits in accordance with Canadian generally acceptedauditing standards and the standards of the Public Company Accounting OversightBoard (United States). These standards require that we plan and perform theaudit to obtain reasonable assurance about whether the financial statements arefree of material misstatement. An audit includes examining, on a test basis,evidence supporting the amounts and disclosures in the financial statements. Anaudit also includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation. We believe that our audits provide a reasonable basisfor our opinion.

 

In our opinion, these consolidated financial statements present fairly,in all material respects, the financial position of Nexen Inc. and subsidiariesas of December 31, 2008 and 2007, and the results of their operations andtheir cash flows for each of the years in the three year period endedDecember 31, 2008 in accordance with Canadian generally acceptedaccounting principles.

 

We have also audited, in accordance with the standards of the PublicCompany Accounting Oversight Board (United States), the Company’s internalcontrol over financial reporting as of December 31, 2008, based on thecriteria established in Internal Control—Integrated Framework issuedby the Committee of Sponsoring Organizations of the Treadway Commission and ourreport dated February 11, 2009 expressed an unqualified opinion on theCompany’s internal control over financial reporting.

 
| (signed)  “Deloitte & Touche LLP” |   |
|------------------------------------------------------|--------|
| Independent Registered  Chartered Accountants        |   |
| Calgary, Canada                                      |   |
| February 11, 2009                               |   |

 

**COMMENTS BYINDEPENDENT REGISTERED CHARTERED ACCOUNTANTS ON CANADA-UNITED STATES OF AMERICAREPORTING 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 11, 2009,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 11, 2009

 

82

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**NEXEN INC. CONSOLIDATED STATEMENT OF INCOME FOR THE THREE YEARS ENDED DECEMBER 31, 2008**

 
| **Cdn$ millions, except per share amounts** | ** ** | **2008**  | ** ** | **2007**  | ** ** | **2006** | ** ** |
|----------------------------------------------------------------------|------------|-----------|------------|-----------|------------|----------|------------|
|                                                                 |       |      |       |      |       |     |       |
| Revenues and  Other Income                                           |       |      |       |      |       |     |       |
| Net Sales                                                            |       | 7,424     |       | 5,583     |       | 3,936    |       |
| Marketing and  Other (Note 17)                                       |       | 813       |       | 1,021     |       | 1,450    |       |
|                                                                 |       | 8,237     |       | 6,604     |       | 5,386    |       |
|                                                                 |       |      |       |      |       |     |       |
| Expenses                                                             |       |      |       |      |       |     |       |
| Operating                                                            |       | 1,335     |       | 1,165     |       | 955      |       |
| Depreciation,  Depletion, Amortization and Impairment (Note 4)       |       | 2,014     |       | 1,767     |       | 1,124    |       |
| Transportation  and Other                                            |       | 967       |       | 908       |       | 1,041    |       |
| General and  Administrative                                          |       | 257       |       | 374       |       | 555      |       |
| Exploration                                                          |       | 402       |       | 326       |       | 362      |       |
| Interest (Note  10)                                                  |       | 94        |       | 168       |       | 53       |       |
|                                                                 |       | 5,069     |       | 4,708     |       | 4,090    |       |
|                                                                 |       |      |       |      |       |     |       |
| Income before  Provision for Income Taxes                            |       | 3,168     |       | 1,896     |       | 1,296    |       |
|                                                                 |       |      |       |      |       |     |       |
| Provision for  Income Taxes (Note 18)                                |       |      |       |      |       |     |       |
| Current                                                              |       | 859       |       | 434       |       | 368      |       |
| Future                                                               |       | 598       |       | 358       |       | 315      |       |
|                                                                 |       | 1,457     |       | 792       |       | 683      |       |
|                                                                 |       |      |       |      |       |     |       |
| Net Income before  Non-Controlling Interests                         |       | 1,711     |       | 1,104     |       | 613      |       |
| Net Income (Loss)  Attributable to Non-Controlling Interests         |       | (4        | )          | 18        |       | 12       |       |
|                                                                 |       |      |       |      |       |     |       |
| **Net Income**                                                       | ** ** | **1,715** | ** ** | **1,086** | ** ** | **601**  | ** ** |
| ** **                                                           |       |      |       |      |       |     |       |
| **Earnings  Per Common Share******($/share) (Note 19)                |       |      |       |      |       |     |       |
| Basic                                                                |       | 3.26      |       | 2.06      |       | 1.15     |       |
| Diluted                                                              |       | 3.22      |       | 2.02      |       | 1.12     |       |

 

*See accompanying notes to Consolidated Financial Statements.*

 

83

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**NEXEN INC.**

**CONSOLIDATED BALANCE SHEET**

**DECEMBER 31, 2008 AND 2007**

 
| **Cdn$ millions, except share amounts**                                                                                                                                                           | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                                                                                                                                                                                            |       |       |       |       |       |
| **ASSETS**                                                                                                                                                                                                            |       |       |       |       |       |
| Current Assets                                                                                                                                                                                                        |       |       |       |       |       |
| Cash and Cash  Equivalents                                                                                                                                                                                            |       | 2,003      |       | 206        |       |
| Restricted Cash                                                                                                                                                                                                       |       | 103        |       | 203        |       |
| Accounts  Receivable (Note 2)                                                                                                                                                                                         |       | 3,163      |       | 3,502      |       |
| Inventories and  Supplies (Note 3)                                                                                                                                                                                    |       | 484        |       | 659        |       |
| Other                                                                                                                                                                                                                 |       | 169        |       | 89         |       |
| Total Current  Assets                                                                                                                                                                                                 |       | 5,922      |       | 4,659      |       |
|                                                                                                                                                                                                                  |       |       |       |       |       |
| Property, Plant  and Equipment (Note 4)                                                                                                                                                                               |       | 14,922     |       | 12,498     |       |
| Goodwill                                                                                                                                                                                                              |       | 390        |       | 326        |       |
| Future Income Tax  Assets (Note 18)                                                                                                                                                                                   |       | 351        |       | 268        |       |
| Deferred Charges  and Other Assets (Note 6)                                                                                                                                                                           |       | 570        |       | 324        |       |
| ** **                                                                                                                                                                                                            | ** ** | ** ** | ** ** | ** ** | ** ** |
| **TOTAL ASSETS**                                                                                                                                                                                                      | ** ** | **22,155** | ** ** | **18,075** | ** ** |
| ** **                                                                                                                                                                                                            | ** ** | ** ** | ** ** | ** ** | ** ** |
| **LIABILITIES AND SHAREHOLDERS’ EQUITY**                                                                                                                                                                         |       |       |       |       |       |
| Current  Liabilities                                                                                                                                                                                                  |       |       |       |       |       |
| Accounts Payable  and Accrued Liabilities (Note 9)                                                                                                                                                                    |       | 3,326      |       | 4,180      |       |
| Accrued Interest  Payable                                                                                                                                                                                             |       | 67         |       | 54         |       |
| Dividends Payable                                                                                                                                                                                                     |       | 26         |       | 13         |       |
| Total Current  Liabilities                                                                                                                                                                                            |       | 3,419      |       | 4,247      |       |
|                                                                                                                                                                                                                  |       |       |       |       |       |
| Long-Term Debt  (Note 10)                                                                                                                                                                                             |       | 6,578      |       | 4,610      |       |
| Future Income Tax  Liabilities (Note 18)                                                                                                                                                                              |       | 2,619      |       | 2,290      |       |
| Asset Retirement  Obligations (Note 12)                                                                                                                                                                               |       | 1,024      |       | 792        |       |
| Deferred Credits  and Other Liabilities (Note 13)                                                                                                                                                                     |       | 1,324      |       | 459        |       |
| Non-Controlling  Interests                                                                                                                                                                                            |       | 52         |       | 67         |       |
| Shareholders’  Equity (Note 15)                                                                                                                                                                                  |       |       |       |       |       |
| Common Shares, no  par value                                                                                                                                                                                          |       |       |       |       |       |
| Authorized:                                 Unlimited |       |       |       |       |       |
| Outstanding:                        2008—519,448,590 shares                                        |       |       |       |       |       |
| 2007—528,304,813  shares                                                                                                                                                                                         |       | 981        |       | 917        |       |
| Contributed  Surplus                                                                                                                                                                                                  |       | 2          |       | 3          |       |
| Retained Earnings                                                                                                                                                                                                     |       | 6,290      |       | 4,983      |       |
| Accumulated Other  Comprehensive Loss                                                                                                                                                                                 |       | (134       | )          | (293       | )          |
| Total  Shareholders’ Equity                                                                                                                                                                                      |       | 7,139      |       | 5,610      |       |
| Commitments,  Contingencies and Guarantees (Notes 16 and 18)                                                                                                                                                          |       |       |       |       |       |
| **TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY**                                                                                                                                                                   | ** ** | **22,155** | ** ** | **18,075** | ** ** |

 

*See accompanying notes to Consolidated Financial Statements.*

 
| Approved on behalf of the  Board:      |   |                                         |
|----------------------------------------|--------|----------------------------------------------|
|                                   |   |                                         |
| (signed) “Marvin F. Romanow” |   | (signed) “Thomas C.  O’Neill” |
| Director                               |   | Director                                     |

 

84

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**NEXEN INC.**

**CONSOLIDATED STATEMENT OF CASH FLOWS**

**FOR THE THREE YEARS ENDED DECEMBER 31, 2008**

 
| **Cdn$ millions**                                                       | ** ** | **2008**  | ** ** | **2007** | ** ** | **2006** | ** ** |
|------------------------------------------------------------------------------|------------|-----------|------------|----------|------------|----------|------------|
| ** **                                                                   |       |      |       |     |       |     |       |
| **Operating Activities**                                                     |       |      |       |     |       |     |       |
| Net Income                                                                   |       | 1,715     |       | 1,086    |       | 601      |       |
| Charges and  Credits to Income not Involving Cash (Note 20a)                 |       | 2,136     |       | 2,073    |       | 1,629    |       |
| Exploration  Expense                                                         |       | 402       |       | 326      |       | 362      |       |
| Changes in  Non-Cash Working Capital (Note 20b)                              |       | 119       |       | (348     | )          | (177     | )          |
| Other                                                                        |       | (18       | )          | (307     | )          | (41      | )          |
|                                                                         |       | 4,354     |       | 2,830    |       | 2,374    |       |
|                                                                         |       |      |       |     |       |     |       |
| **Financing  Activities**                                                    |       |      |       |     |       |     |       |
| Proceeds from  Long-Term Notes                                               |       | —    |       | 1,660    |       | —   |       |
| Repayment of  Medium-Term Notes and Debentures                               |       | (125      | )          | (150     | )          | (93      | )          |
| Proceeds from  (Repayment of) Term Credit Facilities, Net                    |       | 803       |       | (697     | )          | 1,044    |       |
| Proceeds from  (Repayment of) Short-Term Borrowings, Net                     |       | (4        | )          | (150     | )          | 160      |       |
| Proceeds from  Canexus Notes                                                 |       | 51        |       | —   |       | —   |       |
| Proceeds from  (Repayment of) Term Credit Facilities of Canexus, Net         |       | (20       | )          | 60       |       | 2        |       |
| Dividends on  Common Shares                                                  |       | (92       | )          | (53      | )          | (52      | )          |
| Distributions  Paid to Non-Controlling Interests                             |       | (17       | )          | (28      | )          | (28      | )          |
| Issue of Common  Shares and Exercise of Tandem Options for Shares (Note 15b) |       | 64        |       | 56       |       | 48       |       |
| Repurchase of  Common Shares for Cancellation (Note 15b)                     |       | (338      | )          | —   |       | —   |       |
| Other                                                                        |       | —    |       | (21      | )          | —   |       |
|                                                                         |       | 322       |       | 677      |       | 1,081    |       |
| **Investing  Activities**                                                    |       |      |       |     |       |     |       |
| Capital  Expenditures                                                        |       |      |       |     |       |     |       |
| Exploration and  Development                                                 |       | (2,895    | )          | (3,132   | )          | (3,198   | )          |
| Proved Property  Acquisitions                                                |       | (22       | )          | (151     | )          | (13      | )          |
| Chemicals,  Corporate and Other                                              |       | (149      | )          | (118     | )          | (119     | )          |
| Business  Acquisitions, Net of Cash Acquired (Note 5)                        |       | —    |       | —   |       | (78      | )          |
| Proceeds on  Disposition of Assets                                           |       | 6         |       | 4        |       | 27       |       |
| Changes in  Non-Cash Working Capital (Note 20b)                              |       | (124      | )          | 130      |       | 134      |       |
| Changes in  Restricted Cash                                                  |       | 106       |       | (16      | )          | (127     | )          |
| Other                                                                        |       | (111      | )          | 2        |       | (14      | )          |
|                                                                         |       | (3,189    | )          | (3,281   | )          | (3,388   | )          |
|                                                                         |       |      |       |     |       |     |       |
| Effect of  Exchange Rate Changes on Cash and Cash Equivalents                |       | 310       |       | (121     | )          | (14      | )          |
|                                                                         |       |      |       |     |       |     |       |
| Increase in Cash  and Cash Equivalents                                       |       | 1,797     |       | 105      |       | 53       |       |
|                                                                         |       |      |       |     |       |     |       |
| Cash and Cash  Equivalents, Beginning of Year                                |       | 206       |       | 101      |       | 48       |       |
|                                                                         |       |      |       |     |       |     |       |
| **Cash and Cash Equivalents, End of Year**                                   | ** ** | **2,003** | ** ** | **206**  | ** ** | **101**  | ** ** |

 

*Cash and cash equivalents at December 31, 2008 consistsof cash of $355 million and short—term investments of $1,648 million.*

 

*See accompanying notes to Consolidated Financial Statements.*

 

85

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**NEXEN INC.**

**CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY**

**FOR THE THREE YEARS ENDED DECEMBER 31, 2008**

 
| **Cdn$ millions**                                                    | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|---------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Common  Shares,******Beginning of Year                                  |       | 917        |       | 821        |       | 732        |       |
| Issue of Common  Shares                                                   |       | 41         |       | 32         |       | 32         |       |
| Exercise of  Tandem Options for Shares                                    |       | 23         |       | 24         |       | 16         |       |
| Accrued Liability  Relating to Tandem Options Exercised for Common Shares |       | 22         |       | 40         |       | 41         |       |
| Repurchased Under  Normal Course Issuer Bid (Note 15b)                    |       | (22        | )          | —     |       | —     |       |
| **End of Year**                                                           | ** ** | **981**    | ** ** | **917**    | ** ** | **821**    | ** ** |
| ** **                                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Contributed Surplus,**Beginning of Year                                 |       | 3          |       | 4          |       | 2          |       |
| Stock-Based  Compensation Expense                                         |       | —     |       | 1          |       | 2          |       |
| Exercise of  Tandem Options                                               |       | (1         | )          | (2         | )          | —     |       |
| **End of Year**                                                           | ** ** | **2**      | ** ** | **3**      | ** ** | **4**      | ** ** |
| ** **                                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Retained Earnings,**Beginning of Year                                   |       | 4,983      |       | 3,972      |       | 3,423      |       |
| Net Income                                                                |       | 1,715      |       | 1,086      |       | 601        |       |
| Dividends on  Common Shares                                               |       | (92        | )          | (53        | )          | (52        | )          |
| Transition  Adjustment on Adoption of New Inventory Standard              |       | —     |       | (22        | )          | —     |       |
| Repurchase of  Common Shares for Cancellation (Note 15b)                  |       | (316       | )          | —     |       | —     |       |
| **End of Year**                                                           | ** ** | **6,290**  | ** ** | **4,983**  | ** ** | **3,972**  | ** ** |
| ** **                                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Accumulated Other Comprehensive Loss,**Beginning of Year                |       | (293       | )          | (161       | )          | (161       | )          |
| Opening  Derivatives Designated as Cash Flow Hedges                       |       | —     |       | 61         |       | —     |       |
| Other  Comprehensive Income (Loss)                                        |       | 159        |       | (193       | )          | —     |       |
| **End of Year(1)**                                                        | ** ** | **(134**   | **)**      | **(293**   | **)**      | **(161**   | **)**      |

 

----

| *(1)* | * * | *Includes  unrealized foreign currency translation adjustment.* |
|-------|----------|-----------------------------------------------------------------|

 

**NEXEN INC.**

**CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME**

**FOR THE THREE YEARS ENDED DECEMBER 31, 2008**

 
| **Cdn$ millions**                                                       | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                                   |       |       |       |       |       |       |       |
| **Net Income**                                                               |       | 1,715      |       | 1,086      |       | 601        |       |
| Other  Comprehensive Income (Loss), net of income taxes:                     |       |       |       |       |       |       |       |
| Foreign Currency  Translation Adjustment:                                    |       |       |       |       |       |       |       |
| Net Gains  (Losses) on Investment in Self-Sustaining Foreign Operations      |       | 1,228      |       | (867       | )          | 16         |       |
| Net Gains  (Losses) on Debt Hedges of Self-Sustaining Foreign Operations (1) |       | (1,062     | )          | 738        |       | (20        | )          |
| Realized  Translation Adjustments Recognized in Net Income                   |       | (7         | )          | (3         | )          | 4          |       |
| Cash Flow Hedges:                                                            |       |       |       |       |       |       |       |
| Realized  Mark-to-Market Gains Recognized in Net Income                      |       | —     |       | (61        | )          | —     |       |
| Other  Comprehensive Income (Loss)                                           |       | 159        |       | (193       | )          | —     |       |
| ** **                                                                   | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Comprehensive Income**                                                     | ** ** | **1,874**  | ** ** | **893**    | ** ** | **601**    | ** ** |

 

----

| *(1)* | * * | *Net of  income tax recovery for the year ended December 31, 2008 of $145 million  (2007—$97 million expense; 2006—$12 million recovery).* |
|-------|----------|-----------------------------------------------------------------------------------------------------------------------------------------------------------|

 

*Seeaccompanying notes to Consolidated Financial Statements.*

 

86

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**NEXEN INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

*Cdn$ millions, except as noted*

 

**1.     ACCOUNTINGPOLICIES**

 

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 23.

 

**(a)    Consolidation**

 

The Consolidated FinancialStatements include the accounts of Nexen and our subsidiary companies (Nexen,we or our). All subsidiary companies, with the exception of Canexus LimitedPartnership and its subsidiaries (Canexus), are wholly owned. All intercompanyaccounts and transactions are eliminated upon consolidation.

 

We have a 63.5% interest inCanexus represented by 56.6 million Exchangeable LP Units. We have the right tonominate a majority of the members of the board of directors, who have thepower to determine the strategic operating, investing and financing policies ofCanexus. Through our majority ownership interest and the ability to elect themajority of the members of the board, Nexen holds effective control overCanexus. All assets, liabilities and results of operations of Canexus areconsolidated and have been included in our Consolidated Financial Statements.Non-Nexen ownership interests in Canexus 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 jointventure, which is considered a mining activity under current US regulations.While the joint ventures under which these activities are carried out do not comprisedistinct legal entities, they are operating entities. The significant operatingpolicies of which are, by contractual arrangement, jointly controlled by allworking interest parties.

 

**(b)    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 on an ongoing basis, including thoserelated to accruals, litigation, environmental and asset retirementobligations, recoverability of assets, income taxes, fair values of derivativeassets and liabilities, capital adequacy, and the determination of proved reserves.Changes in facts and circumstances may result in revised estimates, and actualresults may differ from these estimates.

 

**(c)    Cashand cash equivalents**

 

Cash and cash equivalentsincludes short-term, highly liquid investments that mature within three monthsof their purchase. These investments are recorded at cost, which approximatesfair value.

 

**(d)    Restrictedcash**

 

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

 

**(e)    Accountsreceivable**

 

Accounts receivable arerecorded based on our revenue recognition policy (see Note 1(o)). Our allowancefor doubtful accounts provides for specific doubtful receivables, as well asgeneral counterparty credit risk evaluated using observable market informationand internal assessments.

 

**(f)    Inventoriesand supplies**

 

Inventories and supplies,other than inventory held for trading purposes, are stated at the lower of costand net realizable value. Cost is determined using the first-in, first-outmethod. Inventory costs include expenditures and other costs, includingdepletion, directly or indirectly incurred in bringing the inventory to itsexisting condition.

 

Effective October 1,2007, commodity inventories in our energy marketing operations that are heldfor trading purposes are carried at fair value, as measured by the one-monthforward price, less any costs to sell. Any changes in fair value are includedas gains or losses in marketing and other income during the period of change.

 

**(g)   Property,plant and equipment (PP&E)**

 

PP&E is recorded at costand includes only recoverable costs that directly result in an identifiablefuture benefit. Unrecoverable costs, maintenance and turnaround costs areexpensed as

 

87

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incurred. Improvements thatincrease capacity or extend the useful lives of the related assets arecapitalized to PP&E. Major spare parts and standby equipment whose usefullife is expected to last longer than one year are included with PP&E.

 

We follow successful effortsaccounting for our oil and gas operations. Costs are initially capitalized toPP&E as unproved property costs. Once proved reserves are discovered, thecosts are reclassified to proved property costs. Exploration drilling costs arecapitalized as suspended exploration well costs pending evaluation as towhether sufficient quantities of reserves have been found to justify commercialproduction. If commercial quantities of reserves are not found, explorationdrilling costs are expensed. All exploratory wells are evaluated for commercialviability on a regular basis following completion of drilling. Explorationdrilling costs remain capitalized if a determination is made that a sufficientquantity of reserves have been found and sufficient progress is being made toassess the reserves and the economic and operating viability. All otherexploration costs, including geological and geophysical and annual leaserentals, are expensed to earnings as incurred. All development costs arecapitalized as proved property costs. General and administrative costs thatdirectly relate to acquisition, exploration and development activities arecapitalized 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.

 

**(h)   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 are depleted over remaining proved reserves. Depletion isconsidered a cost of inventory when the oil and gas is produced. When theinventory is sold, 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 plantand equipment costs using the straight-line method based on the estimateduseful lives of the assets, which range from 3 to 30 years. Unproved propertycosts and major projects that are under construction or development are notdepreciated, 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 estimated undiscounted future cash flows, theproperty’s value is impaired. The property is then assigned a fair value equalto its estimated total future net cash flows, discounted for the time value ofmoney, and we expense the excess carrying value to DD&A. Our cash flow estimatesrequire assumptions about future commodity prices, ultimate recoverability ofoil and gas reserves, operating costs and other factors. Actual results candiffer 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.

 

**(i)    Capitalizedinterest**

 

We capitalize interest onmajor development projects until the project is complete using theweighted-average interest rate on all of our borrowings. Capitalized interestcannot exceed the actual interest incurred.

 

**(j)    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.

 

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**(k)   Goodwill**

 

Our goodwill is attributableto our energy marketing and UK operating segments. It has been recorded at costand is not amortized. We test goodwill for impairment at least annually orwhenever events or circumstances indicate that goodwill is impaired. We baseour test on estimated future net cash flows of the reporting unit. If goodwillis impaired we reduce the carrying value to estimated fair value and animpairment loss is recorded in net income. No significant impairments arosefrom the December 2008 and the December 2007 annual tests.

 

**(l)    Financialinstruments and hedging activities**

 

All financial assets andliabilities are recognized on the balance sheet when we become a party to thecontractual provisions of the instrument and are initially recognized at fairvalue. Subsequent measurement of the financial instruments is based on theirclassification. We have classified each financial instrument into one of thefollowing categories: financial assets and financial liabilities held fortrading; loans or receivables; financial assets held to maturity; financialassets available for sale; and other financial liabilities. The classificationdepends on the characteristics and the purpose for which the financialinstruments were acquired. Except in very limited circumstances, theclassification of financial instruments is not subsequently changed.

 

Financial instrumentscarried at fair value on our balance sheet include cash and cash equivalents,restricted cash and derivatives used for trading and non-trading purposes.Realized and unrealized gains and losses from financial assets and liabilitiescarried at fair value are recognized in net income in the periods such gainsand losses arise. Transaction costs related to these financial assets andliabilities are included in net income when incurred.

 

Financial instruments wecarry at cost or amortized cost include our accounts receivable, accountspayable and accrued liabilities, accrued interest payable, dividends payable,short-term borrowings and long-term debt. Transaction costs are included in netincome when incurred for these types of financial instruments except forshort-term borrowings and long-term debt. These transaction costs are includedwith the initial fair value and the instrument is carried at amortized costusing the effective interest rate method. Gains and losses on financial assetsand liabilities carried at cost or amortized cost are recognized in net incomewhen these assets or liabilities settle.

 

Derivatives related to non-trading activities

 

We use derivativeinstruments such as physical purchase and sales contracts, forwards, futures,swaps and options for non-trading purposes to manage fluctuations in commodityprices, foreign currency exchange rates and interest rates (see Notes 7 and 8).We record these instruments at fair value at the balance sheet date and recordany change in fair value as a net gain or loss in marketing and other incomeduring the period of change unless the requirements for hedge accounting aremet.

 

Derivatives related to trading activities

 

Our energy marketingoperation uses derivative instruments for marketing and trading natural gas,crude oil, natural gas liquids and power including: commodity contracts settledwith physical delivery; exchange-traded futures and options; and non-exchangetraded forwards, swaps and options.

 

We record these instrumentsat fair value at the balance sheet date and record changes in fair value as netgains or losses in marketing and other income during the period of change. Thefair value of these instruments is included with accounts receivable or payableif we anticipate settling the instruments within a year of the balance sheetdate. If we anticipate settling the instruments beyond twelve months, weinclude them with deferred charges and other assets or deferred credits andother liabilities.

 

Hedge accounting

 

Hedge accounting may be usedwhen there is a high degree of correlation between price movements in thederivative instruments and the items designated as being hedged. Nexen formallydocuments all hedges and the risk management objectives at the inception of thehedge. Derivative instruments that have been designated and qualify for hedgeaccounting are classified as either cash flow or fair value hedges.

 

For cash flow hedges,changes in the fair value of a financial instrument designated as a cash flowhedge are recognized in net income in the same period as the hedged item. Anyfair value change in the financial instrument before that period is recognizedon the balance sheet. The effective portion of this fair value change isrecognized in other comprehensive income with any ineffectiveness recognized inmarketing and other income during the period of change.

 

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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.

 

Nexen had no cash flow orfair value hedges in place at December 31, 2008 or 2007.

 

Comprehensive income

 

Comprehensive incomeconsists of net income and other comprehensive income (OCI). OCI includes gainsand losses resulting from the foreign exchange translation of our netinvestments in self-sustaining foreign operations and the effective portion ofderivatives used as a hedging item in a cash flow hedge or net investmenthedge. Accumulated other comprehensive income (AOCI) is a separate component ofshareholders’ equity comprised of the cumulative amounts of OCI. Amountsincluded in AOCI are reclassified to income when realized.

 

**(m)  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 obligation is accreted through DD&A expense until itis expected to settle and the cost is amortized through DD&A expense overthe life of the respective asset. The fair value of the obligation is estimatedby discounting expected future cash flows estimated to settle the assetretirement obligation using a weighted-average, credit-adjusted risk freeinterest rate. Nexen recognizes period-to-period changes due to the passage oftime and revisions to either the timing or the amount of the original estimateof undiscounted cash flows. 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.

 

We own interests in assetsfor which the fair value of the asset retirement obligations cannot bereasonably determined because the assets currently have an indeterminate lifeand we cannot determine when remediation activities would take place. Theseassets include our interest in Syncrude’s upgrader and sulphur pile, and ourinterest in the Long Lake upgrader. The estimated future recoverable reservesat Syncrude and Long Lake are significant and given the long life of theseassets, we are unable to determine when asset retirement activities would takeplace. Furthermore, the Syncrude plant and the Long Lake upgrader can bothcontinue to run indefinitely with ongoing maintenance activities. Theretirement obligations for these assets will be recorded in the first year inwhich the obligation to remediate becomes determinable.

 

**(n)   Pensionand other post-retirement benefits**

 

Our employee post-retirementbenefit programs consist of contributory and non-contributory defined benefitand defined contribution pension plans, as well as other post-retirementbenefit programs.

 

For our defined benefitplans, we provide benefits to retirees based on their length of service andfinal average earnings. The cost of pension benefits earned by employees in ourdefined benefit pension plans is actuarially determined using theprojected-benefit method prorated on service and our best estimate of the plans’investment performance, salary escalations and retirement ages of employees. Tocalculate the plans’ expected returns, assets are measured at fair value. Pastservice costs arising from plan amendments, and net actuarial gains and lossesthat exceed 10% of the greater of the accrued benefit obligation and the fairvalue of plan assets, are expensed in equal amounts over the expected averageremaining service life of the employee group. Benefits paid out of Nexen’sdefined benefit plan are indexed to 75% of the annual rate of inflation less 1%to a maximum increase of 5%.

 

During the year, we changedour measurement date for defined benefit plans from October 31 to December 31.This change was applied prospectively and did not have a material impact on ourfinancial statements.

 

Our defined contributionpension plan benefits are based on plan contributions. Company contributions tothe defined contribution plan are expensed as incurred.

 

Other post-retirementbenefits include group life and supplemental health insurance for eligibleemployees and their dependants. Costs are accrued as compensation in the periodemployees work; however, these future obligations are not funded.

 

**(o)    Revenuerecognition**

 

Oil and 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

 

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or sell more or less oil ornatural gas than our share, production overlifts and underlifts occur. Werecord overlifts as liabilities and underlifts as assets. We settle these overtime as liftings are equalized or in cash when production ends.

 

Revenue represents Nexen’sshare and is recorded net of royalty obligations to governments and othermineral interest owners. For our international operations, all governmentinterests, except for income taxes, are considered royalty obligations. Ourrevenue also includes the recovery of costs paid on behalf of foreigngovernments in international locations. See Note 1(j).

 

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 specifying delivery volumesand sales prices. We assess customer credit worthiness before entering intosales contracts to minimize collection risk.

 

Energy marketing

 

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

 

Any margin earned by ourenergy marketing operation on the sale of our proprietary oil and gasproduction is included in marketing and other. Sales of our proprietaryproduction are recorded at monthly average market-based prices and reported in ouroil and gas segments. Intercompany profits and losses between segments areeliminated.

 

We assess customer creditworthiness before entering into contracts and provide for netting terms tominimize collection risk. Amounts are recorded on a net basis where we have alegally enforceable right and intention to offset.

 

**(p)    Foreigncurrency translation**

 

Our foreign operations,which are considered financially and operationally independent, are translatedfrom their functional currency into Canadian dollars at the balance sheet dateexchange rate for assets and liabilities and at the monthly average exchangerate for revenues and expenses. Gains and losses resulting from thistranslation are included in other comprehensive income.

 

We have designated our US-dollardebt (excluding debt related to Canexus) as a hedge against our net investmentin US-dollar based self-sustaining foreign operations. Gains and lossesresulting from the translation of the designated US-dollar debt are included inother comprehensive income. If our US-dollar debt, net of income taxes, exceedsour US-dollar investment in foreign operations, then the gains or lossesattributable to such excess are included in marketing and other income in theConsolidated Statement of Income.

 

Monetary balancesdenominated in a currency other than a functional currency are translated intothe functional currency using exchange rates at the balance sheet dates. Gainsand losses arising from this translation are included in marketing and otherincome in the Consolidated Statement of Income.

 

**(q)    Transportation**

 

We pay to transport thecrude oil, natural gas and chemical products that we market, and then bill ourcustomers for the transportation. This transportation is presented in ourConsolidated Financial Statements as transportation and other expense. Amountsbilled to our customers are presented within marketing and other income. Ourenergy marketing operation has received cash payments in exchange for assumingcertain transportation obligations from third parties. These cash payments havebeen recorded as deferred liabilities and are recognized in net income as thetransportation is used.

 

**(r)    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 and are amortized on astraight-line basis over the period of expected use, consistent with otherPP&E. Rental payments under operating leases are expensed as incurred.

 

**(s)    Stock-basedcompensation**

 

Our stock-based compensationconsists of tandem option (TOPs) and stock appreciation right (StARs) plans.

 

Tandem options to purchasecommon shares are granted to directors, officers and employees at thediscretion of the Board of Directors. Each tandem option gives the holder aright to either purchase one Nexen common share at the exercise price or toreceive a cash payment equal to the excess of the market

 

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value of the common shareover the exercise price. Options granted prior to February 2001 vest overfour years and are exercisable on a cumulative basis over 10 years. Optionsgranted after February 2001 vest over three years and are exercisable on acumulative basis over five years. At the time of the grant, the exercise priceequals the market value.

 

We record obligations forthe tandem options using the intrinsic-value method of accounting and recognizecompensation expense in the Consolidated Statement of Income. Obligations areaccrued on a graded vesting basis and represent the difference between themarket value of our common shares and the exercise price of the options. Theobligations are revalued each reporting period based on the change in themarket value of our common shares and the number of graded vested optionsoutstanding. We reduce the liability when the options are surrendered for cash.When the options are exercised for stock, the accrued liability is transferredto share capital.

 

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.

 

Under our StARs plan,employees are entitled to cash payments equal to the excess of market price ofthe common share over the exercise price of the right. The vesting period andother terms of the plan are similar to the tandem option plan. The total StARsgranted and outstanding at any time cannot exceed 10% of Nexen’s totaloutstanding common shares. At the time of grant, the exercise price equalsmarket value. We account for stock appreciation rights to employees on the samebasis as our tandem options. Obligations are accrued as compensation expenseover the graded vesting period of the stock appreciation rights.

 

**(t)    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 in incometax rates on future income tax assets and future income tax liabilities isrecognized in income when substantively enacted.

 

We do not provide forforeign withholding taxes on the undistributed earnings of our foreignsubsidiaries, as we intend to invest such earnings indefinitely in foreignoperations.

 

**(u)   Changesin accounting principles**

 

Capital disclosures

 

On January 1, 2008, weprospectively adopted Canadian Institute of Chartered Accountants (CICA) Section 1535*Capital Disclosures* issued by theCanadian Accounting Standards Board (AcSB). This Section establishesstandards for disclosing information about an entity’s objectives, policies andprocesses for managing its capital structure. The disclosures have beenincluded in Note 11.

 

Financial instruments disclosures and presentation

 

On January 1, 2008, weprospectively adopted the following new standards issued by the AcSB: *Financial Instruments — Disclosure* (Section 3862)and *Financial Instruments — Presentation*(Section 3863). These accounting standards replaced *Financial Instruments — Disclosure and Presentation*(Section 3861). The disclosures required by Section 3862 and 3863provide additional information on the risks associated with our financialinstruments and how we manage those risks. The additional disclosures requiredby these standards are provided in Notes 7 and 8.

 

New accounting pronouncements

 

In February 2008, theAcSB confirmed that all Canadian publicly accountable enterprises will berequired to adopt International Financial Reporting Standards (IFRS) forinterim and annual reporting purposes for fiscal years beginning on or after January 1,2011. We are currently assessing the impact of the convergence of Canadian GAAPwith IFRS on our results of operations, financial position and disclosures. Aproject team has been set up to manage this transition and to ensure successfulimplementation within the required timeframe.

 

In February 2008, theAcSB issued Section 3064, *Goodwill andIntangible Assets*and amended Section 1000, *Financial Statement Concepts* clarifyingthe criteria for recognizing assets, intangible assets and internally developedintangible assets. Items that no longer meet the definition of an asset are nolonger recognized with assets. The standard is effective for fiscal yearsbeginning on or after October 1, 2008 and early adoption is permitted. Wedo not expect the adoption of this section to have a material impact on ourresults of operations or financial position.

 

In January 2009, theAcSB issued Section 1582, *BusinessCombinations*, which replaces former guidance on businesscombinations. Section 1582 establishes principles and requirements of theacquisition method for business combinations and related disclosures. Thisstatement applies prospectively to business combinations for which theacquisition date is on or after the beginning of the first annual reportingperiod beginning 

 

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on or after January 2011with earlier application permitted. We plan to adopt this standardprospectively effective January 1, 2009 and do not expect the adoption ofthis statement to have a material impact on our results of operations orfinancial position.

 

In January 2009, theAcSB issued Sections 1601, *ConsolidatedFinancial Statements*, and 1602, *Non-controllingInterests*, which replaces existing guidance. Section 1601establishes standards for the preparation of consolidated financial statements.Section1602 provides guidance on accounting for a non-controlling interest in asubsidiary in consolidated financial statements subsequent to a businesscombination. These standards are effective on or after the beginning of thefirst annual reporting period beginning on or after January 2011 withearlier application permitted. We plan to adopt these standards effective January 1,2009 and do not expect the adoption will have a material impact on our resultsof operations or financial position.

 

**2.     ACCOUNTSRECEIVABLE**

 
| ** **                         | ** ** | **2008**  | ** ** | **2007**  | ** ** |
|------------------------------------|------------|-----------|------------|-----------|------------|
| Trade                              |       |      |       |      |       |
| Energy Marketing                   |       | 2,256     |       | 2,501     |       |
| Oil and Gas                        |       | 639       |       | 819       |       |
| Chemicals and Other                |       | 68        |       | 60        |       |
|                               |       | 2,963     |       | 3,380     |       |
| Non-Trade                          |       | 270       |       | 132       |       |
|                               |       | 3,233     |       | 3,512     |       |
| Allowance for Doubtful Receivables |       | (70       | )          | (10       | )          |
| **Total**                          | ** ** | **3,163** | ** ** | **3,502** | ** ** |

 

**3.     INVENTORIES AND SUPPLIES**

 
| ** **          | ** ** | **2008** | ** ** | **2007** | ** ** |
|---------------------|------------|----------|------------|----------|------------|
| Finished Products   |       |     |       |     |       |
| Energy Marketing    |       | 384      |       | 577      |       |
| Oil and Gas         |       | 17       |       | 14       |       |
| Chemicals and Other |       | 16       |       | 13       |       |
|                |       | 417      |       | 604      |       |
| Work in Process     |       | 6        |       | 3        |       |
| Field Supplies      |       | 61       |       | 52       |       |
| **Total**           | ** ** | **484**  | ** ** | **659**  | ** ** |

 

**4.     PROPERTY, PLANT AND EQUIPMENT**

 
| ** **                    | ** ** | **2008**   | ** ** | **2007**                  | ** ** |
|-------------------------------|------------|------------|------------|---------------------------|------------|
| ** **                    | ** ** | **Cost**   | ** ** | **Accumulated  DD&A** | ** ** | **Net Book  Value** | ** ** | **Cost** | ** ** | **Accumulated  DD&A** | ** ** | **Net Book  Value** | ** ** |
| Oil and Gas                   |       |       |       |                      |       |   |   |   |   |   |   |   |   |
| Yemen                         |       | 899        |       | 781                       |       | 118 |   | 701 |   | 590 |   | 111 |   |
| Yemen — Carried Interest |       | 1,909      |       | 1,829                     |       | 80 |   | 1,477 |   | 1,360 |   | 117 |   |
| Canada(1)                     |       | 8,134      |       | 1,786                     |       | 6,348 |   | 6,736 |   | 1,597 |   | 5,139 |   |
| US                            |       | 4,398      |       | 2,702                     |       | 1,696 |   | 3,069 |   | 1,765 |   | 1,304 |   |
| UK                            |       | 6,532      |       | 2,159                     |       | 4,373 |   | 4,723 |   | 908 |   | 3,815 |   |
| Other Countries               |       | 554        |       | 113                       |       | 441 |   | 263 |   | 77 |   | 186 |   |
|                          |       | 22,426     |       | 9,370                     |       | 13,056 |   | 16,969 |   | 6,297 |   | 10,672 |   |
| Energy Marketing              |       | 246        |       | 76                        |       | 170 |   | 246 |   | 62 |   | 184 |   |
| Syncrude                      |       | 1,372      |       | 236                       |       | 1,136 |   | 1,332 |   | 205 |   | 1,127 |   |
| Chemicals                     |       | 940        |       | 507                       |       | 433 |   | 831 |   | 463 |   | 368 |   |
| Corporate and Other           |       | 331        |       | 204                       |       | 127 |   | 315 |   | 168 |   | 147 |   |
| **Total**                     | ** ** | **25,315** | ** ** | **10,393**                | ** ** | **14,922** | ** ** | **19,693** | ** ** | **7,195** | ** ** | **12,498** | ** ** |

 

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| *(1)* | *Includes capitalized costs related to our insitu oil sands  (Long Lake and future phases) of $4,742 million (2007 — $3,695 million).* |
|-------|---------------------------------------------------------------------------------------------------------------------------------------------|

 

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The above table includescapitalized costs of $7,386 million (2007 — $5,828 million) relating tounproved properties and projects under construction or development. These costsare currently not being depreciated, depleted or amortized, however we expectto begin amortizing the capitalized costs of Long Lake Phase 1 in early 2009.Our insitu oil sands capitalized costs in Canada include $1,874 million relatedto the Phase 1 upgrader (2007— $1,711 million), $1,325 million for Phase 1 SAGDand cogeneration facilities (2007 — $1,026 million); and $1,543 million relatedto capitalized interest and future phases (2007 — $958 million).

 

Depreciation, depletion, amortization and impairment

 

In 2008, our DD&Aexpense includes $568 million of impairment expense relating to oil and gasproperties in the Gulf of Mexico and North Sea. These properties were writtendown to their estimated fair value based on their estimated total futurediscounted net cash flows.

 

In the Gulf of Mexico, wereduced the carrying value of four shelf properties by $143 million, primarilyas a result of low oil and gas prices and higher estimated asset remediationcosts. These late-life, mature properties have a shorter production horizon,and therefore are sensitive to near-term commodity prices and to higherabandonment costs. Inflationary pressures in the oil and gas industry increasedthe estimated future costs to remediate the assets. At Green Canyon 6, wereduced the carrying value of our assets by $107 million to reflect the impactof Hurricane Ike which destroyed a third-party production platform in the thirdquarter of 2008. This resulted in unexpected and uninsured costs to rebuildfacilities.

 

In the North Sea, we reducedthe carrying value of our Ettrick project by $256 million, primarily due tohigher costs and lower reserve estimates following drilling and testing activities.We also expensed costs of $62 million related to our Selkirk discovery as wecurrently have no firm plans to continue with development.

 

In 2007, our DD&Aexpense includes $366 million of impairment expense primarily related to ourAspen, Vermilion 320/340 and West Cameron 170 properties in the Gulf of Mexicoas we had poor results from capital investments and lower reserve estimates. AtAspen, disappointing results from our investment in development drillingresulted in negative reserve revisions. At Vermilion 320/340 and West Cameron170, negative reserve revisions primarily related to gas properties, whereunsatisfactory investment results, production performance, revised mapping andhigher projected operating costs resulted in a downward revision to reservesestimates. These properties were written down to their estimated fair valueequal to estimated total future discounted net cash flows.

 

Research and development

 

In 2008, we incurred $30million (2007 — $40 million) in connection with research and developmentactivities related to developing new technologies for increasing oilrecoveries. Research costs of $27 million (2007 — $38 million) were included inother expense on the Consolidated Statement of Income. The development costshave been deferred and are included in PP&E.

 
| ** **            | ** ** | **2008** | ** ** | **2007** | ** ** |
|-----------------------|------------|----------|------------|----------|------------|
| Beginning of Year     |       | 30       |       | 28       |       |
| Deferred in the Year  |       | 3        |       | 2        |       |
| Amortized in the Year |       | —   |       | —   |       |
| **End of Year**       | ** ** | **33**   | ** ** | **30**   | ** ** |

 

Suspended exploration well costs

 

The following table showsthe changes in capitalized exploratory well costs during the years ended December 31,2008 and 2007, and does not include amounts that were initially capitalized andsubsequently expensed in the same period.

 
| ** **                                                                              | ** ** | **2008** | ** ** | **2007** | ** ** |
|-----------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Beginning of Year                                                                       |       | 326      |       | 226      |       |
| Exploratory Well Costs Capitalized Pending  the Determination of Proved Reserves        |       | 254      |       | 215      |       |
| Capitalized Exploratory Well Costs Charged  to Expense                                  |       | (81      | )          | (10      | )          |
| Transfers to Wells, Facilities and  Equipment Based on Determination of Proved Reserves |       | (29      | )          | (74      | )          |
| Effects of Foreign Exchange Rate Changes                                                |       | 48       |       | (31      | )          |
| **End of Year**                                                                         | ** ** | **518**  | ** ** | **326**  | ** ** |

 

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The following table providesan aging of capitalized exploratory well costs based on the date drilling wascompleted and shows the number of projects for which exploratory well costshave been capitalized for a period greater than one year after the completionof drilling.

 
| ** **                                                                                     | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Capitalized for a Period of One Year or  Less                                                  |       | 239      |       | 202      |       |
| Capitalized for a Period of Greater than  One Year                                             |       | 279      |       | 124      |       |
| **Total**                                                                                      | ** ** | **518**  | ** ** | **326**  | ** ** |
| Number of Projects with Exploratory Well  Costs Capitalized for a Period Greater than One Year |       | 7        |       | 5        |       |

 

As at December 31,2008, we have exploratory costs that have been capitalized for more than oneyear relating to our interests in two exploratory blocks in the Gulf of Mexico($120 million), our coalbed methane exploratory activities in Canada ($70million), three exploratory blocks in the North Sea ($67 million), and ourinterest in an exploratory block offshore Nigeria ($22 million). These costsrelate to projects with 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.

 

**5.     BUSINESSACQUISITIONS**

 

In 2006, we completedbusiness acquisitions related to our energy marketing group for $78 million,net of cash acquired. These acquisitions were accounted for using the purchasemethod of accounting. The assets and liabilities purchased were primarilyworking capital and we recorded goodwill of $12 million.

 

**6.     DEFERRED CHARGESAND OTHER ASSETS**

** **
| ** **                                                 | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|
| Crude Oil Put Options and Natural Gas Swaps  (Note 7b)     |       | 234      |       | 1        |       |
| Long-Term Energy Marketing Derivative  Contracts (Note 7a) |       | 217      |       | 248      |       |
| Long-Term Capital Prepayments                              |       | 61       |       | 9        |       |
| Asset Retirement Remediation Fund                          |       | 9        |       | 13       |       |
| Other                                                      |       | 49       |       | 53       |       |
| **Total**                                                  | ** ** | **570**  | ** ** | **324**  | ** ** |

** **

**7.     FINANCIALINSTRUMENTS**

 

Financial instrumentscarried at fair value on our balance sheet include cash and cash equivalents,restricted cash and derivatives used for trading and non-trading purposes. Ourother financial instruments including accounts receivable, accounts payable,income taxes payable, accrued interest payable, dividends payable, short-termborrowings and long-term debt are carried at cost or amortized cost. Thecarrying value of our short-term receivables and payables approximates theirfair value because the instruments are near maturity.

 

In our energy marketinggroup, we enter into contracts to purchase and sell crude oil, natural gas andother energy commodities, and use derivative contracts, including futures,forwards, swaps and options, for hedging and trading purposes (collectivelyderivatives). We also use derivatives to manage commodity price risk andforeign currency risk for non-trading purposes. We categorize our derivativeinstruments as trading or non-trading activities and carry the instruments atfair value on our balance sheet. The fair values are included with amountsreceivable or payable and are classified as long-term or short-term based onanticipated settlement date. Any change in fair value is included in marketingand other income.

 

We carry our long-term debtat amortized cost using the effective interest rate method. At December 31,2008, the estimated fair value of our long-term debt was $5,686 million (December 31,2007 — $4,692 million) as compared to the carrying value of $6,578 million (December 31,2007 — $4,610 million). The fair value of long-term debt is estimated based onprices provided by quoted markets and third-party brokers. The recent economiccrisis impacted market prices for corporate bonds and as a result, theestimated fair value of our long-term debt was lower in the fourth quarter of2008.

 

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**Derivatives**

 

**(a)    Total carryingvalue of derivative contracts related to trading activities**

 

The fair value and carryingamounts related to derivative instruments held by our energy marketingoperations are as follows:

 
| ** **                                      | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|-------------------------------------------------|------------|------------|------------|------------|------------|
| Accounts Receivable                             |       | 755        |       | 334        |       |
| Deferred Charges and Other Assets(1)            |       | 217        |       | 248        |       |
| **Total  Trading Derivative Assets**            | ** ** | **972**    | ** ** | **582**    | ** ** |
| ** **                                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Accounts Payable and Accrued Liabilities        |       | 615        |       | 413        |       |
| Deferred Credits and Other Liabilities(1)       |       | 294        |       | 163        |       |
| **Total  Trading Derivative Liabilities**       | ** ** | **909**    | ** ** | **576**    | ** ** |
| ** **                                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Total  Net Trading Derivative Assets****(2)** | ** ** | **63**     | ** ** | **6**      | ** ** |

 

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| *(1)* | *These  derivative contracts settle beyond 12 months and are considered non-current.*                                                                                                                          |
|-------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Comprised  of $122 million (2007 — $15 million) related to commodity contracts and net  losses of $59 million (2007 — $9 million loss) related to US-dollar and Euro  forward contracts and swaps.* |

 

**(b)    Total carryingvalue of derivative contracts related to non-trading activities**

 

The fair value and carryingamounts related to derivative instruments related to non-trading activities areas follows:

 
| ** **                                                  | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|-------------------------------------------------------------|------------|------------|------------|------------|------------|
| Accounts Receivable                                         |       | 6          |       | —     |       |
| Deferred Charges and Other Assets(1)                        |       | 234        |       | 1          |       |
| **Total  Non-Trading Derivative Assets**                    | ** ** | **240**    | ** ** | **1**      | ** ** |
| ** **                                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Accounts Payable and Accrued Liabilities                    |       | 21         |       | 28         |       |
| Deferred Credits and Other Liabilities (1)                  |       | 26         |       | 51         |       |
| **Total  Non-Trading Derivative Liabilities**               | ** ** | **47**     | ** ** | **79**     | ** ** |
| ** **                                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Total  Net Non-Trading Derivatives Assets (Liabilities)** | ** ** | **193**    | ** ** | **(78**    | **)**      |

 

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*(1)  These derivative contracts settlebeyond 12 months and are considered non-current.*

 

Crudeoil put options

 

In2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crudeoil production for $14 million. These options establish an annual average DatedBrent floor price of US$60/bbl on these volumes. In September 2008, LehmanBrothers filed for bankruptcy protection. This impacts 25,000 bbls/d of our2009 put options and the carrying value of these put options has been reducedto nil.

 

In2007, we purchased put options on approximately 100,000 bbls/d of our 2008crude oil production for $24 million. These options established an annualaverage Dated Brent floor price of US$50/bbl on these volumes. These putoptions expired out of the money.

 

Thecrude oil put options are carried at fair value and are classified as long-termor short-term based on their anticipated settlement date. Fair value of the putoptions is supported by multiple quotes obtained from third party brokers,which were validated with observable market data to the extent possible. Anychange in fair value is included in marketing and other income.

 
| ** **                        | ** ** | **Notional  Volumes  (bbls/d)** | ** ** | **Term** | ** ** | **Average  Floor Price  (US$/bbl)** | ** ** | **Fair Value****(Cdn$ millions)** | ** ** |
|-----------------------------------|------------|---------------------------------|------------|----------|------------|------------------------------------------|------------|---------------------------------------------|------------|
| Dated Brent Crude Oil Put Options |       | 45,000                          |       | 2009     |       | 60                                       |       | 233                                         |       |
| Dated Brent Crude Oil Put Options |       | 25,000                          |       | 2009     |       | 60                                       |       | —                                      |       |

 

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Fixed-price natural gascontracts and natural gas swaps

 

We have fixed-price naturalgas sales contracts and offsetting natural gas swaps that are not part of ourtrading activities. These sales contracts and swaps are carried at fair valueand are classified as long-term or short-term based on their anticipatedsettlement date. Any change in fair value is included in marketing and otherincome.

** **
| ** **                        | ** ** | **Notional  Volumes  (Gj/d)** | ** ** | **Term** | ** ** | **Average  Floor Price  ($/Gj)** | ** ** | **Fair Value****(Cdn$ millions)** | ** ** |
|-----------------------------------|------------|-------------------------------|------------|----------|------------|---------------------------------------|------------|---------------------------------------------|------------|
| Fixed-Price Natural Gas Contracts |       | 15,514                        |       | 2009     |       | 2.28                                  |       | (21                                         | )          |
|                              |       | 15,514                        |       | 2010     |       | 2.28                                  |       | (26                                         | )          |
| Natural Gas Swaps                 |       | 15,514                        |       | 2009     |       | 7.60                                  |       | 6                                           |       |
|                              |       | 15,514                        |       | 2010     |       | 7.60                                  |       | 1                                           |       |
|                              |       |                          |       |     |       |                                  |       | (40                                         | )     |

** **

**(c)    Fair value ofderivatives**

 

For purposes of estimatingthe fair value of our derivative contracts, wherever possible, we utilizequoted market prices, and if not available, estimates from third-party brokers.These broker estimates are corroborated with multiple sources and/or otherobservable market data utilizing assumptions that market participants would usewhen pricing the asset or liability, including assumptions about risk andmarket liquidity. Inputs to fair valuations may be readily observable,market-corroborated, or generally unobservable. We utilize valuation techniquesthat seek to maximize the use of observable inputs and minimize the use ofunobservable inputs. To value longer-term transactions and transactions in lessactive markets for which pricing information is not generally available,unobservable inputs may be used.

 

As a basis for establishingfair value, we utilize a mid-market pricing convention between bid and ask andthen adjust our pricing to the ask price when we have a net short position andthe bid price when we have a net long position. This adjustment reflects anestimated exit price and incorporates the impact of liquidity when the bid-askspread widens in less liquid markets. We incorporate the credit risk associatedwith counterparty default, as well as our own credit risk, into our estimatesof fair value.

 

We classify the fair valueof our derivatives according to the following hierarchy based on the amount ofobservable inputs used to value the instruments.

 
| · | Level 1 — Quoted prices  are available in active markets for identical assets or liabilities as of the  reporting date. Active markets are those in which transactions occur in  sufficient frequency and volume to provide pricing information on an ongoing  basis. Level 1 consists of financial instruments such as exchange-traded  derivatives and we use information from markets such as the New York  Mercantile Exchange.                                                                                                                                                                                                                                                                                                                                        |
|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| · | Level 2 — Pricing inputs  are other than quoted prices in active markets included in Level 1. Prices in  Level 2 are either directly or indirectly observable as of the reported date.  Level 2 valuations are based on inputs, including quoted forward prices for  commodities, time value, volatility factors and broker quotations, which can  be substantially observed or corroborated in the marketplace. Instruments in  this category include non-exchange traded derivatives such as  over-the-counter physical forwards and options, including those which have  prices similar to quoted market prices. We obtain information from sources  such as the Natural Gas Exchange, independent price publications and  over-the-counter broker quotes.              |
| · | Level 3 — Valuations in  this level are those with inputs which are less observable, unavailable or  where the observable data does not support the majority of the instrument’s  fair value. Level 3 instruments may include items based on pricing services  or broker quotes where we are unable to verify the observability of inputs  into their prices. Level 3 instruments include longer-term transactions,  transactions in less active markets or transactions at locations for which  pricing information is not available. In these instances, internally  developed methodologies are used to determine fair value which primarily  includes extrapolation of observable future prices to similar locations,  similar instruments or later time periods. |

 

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The following table includesour derivatives that are carried at fair value for our trading and non-tradingactivities as at December 31, 2008. Financial assets and liabilities areclassified in the fair value hierarchy in their entirety based on the lowestlevel of input that is significant to the fair value measurement. Assessment ofthe significance of a particular input to the fair value measurement requiresjudgment and may affect placement within the fair value hierarchy levels.

 
| **Net Derivatives** | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|--------------------------|------------|------------------|------------|------------------|------------|------------------|------------|-----------|------------|
| Trading Derivatives      |       | 13               |       | 132              |       | (82              | )          | 63        |       |
| Non-Trading Derivatives  |       | —           |       | 193              |       | —           |       | 193       |       |
| **Total**                | ** ** | **13**           | ** ** | **325**          | ** ** | **(82**          | **)**      | **256**   | ** ** |

 

Areconciliation of changes in the fair value of our derivatives classified asLevel 3 for the year ended December 31, 2008 is provided below:

 
| ** **                                                                                | ** ** | **Level 3** | ** ** |
|-------------------------------------------------------------------------------------------|------------|------------------|------------|
| Beginning of Year                                                                         |       | (7               | )          |
| Realized and unrealized gains (losses)                                                    |       | (64              | )          |
| Purchases, issuances and settlements                                                      |       | (9               | )          |
| Transfers in and/or out of Level 3                                                        |       | (2               | )          |
| **End of  Year**                                                                          | ** ** | **(82**          | **)**      |
| Unsettled gains (losses) relating to  instruments still held as of December 31, 2008 |       | 16               |       |

 

Items classified in Level 3are generally economically hedged such that gains or losses on positionsclassified in Level 3 are often offset by gains or losses on positionsclassified in Level 1 or 2. Transfers into or out of Level 3 represent existingassets and liabilities that were either previously categorized as a higherlevel for which the inputs became unobservable or assets and liabilities thatwere previously classified as Level 3 for which the lowest significant inputbecame observable during the period.

 

**8.     RISK MANAGEMENT**

 

**(a)    Market risk**

 

We invest in significantcapital projects, purchase and sell commodities, issue short-term borrowingsand long-term debt and invest in foreign operations. These activities expose usto market risks from changes in commodity prices, foreign currency rates andinterest rates, which could affect our earnings and the value of the financialinstruments we hold. We use derivatives for trading and non-trading purposes aspart of our overall risk management policy to manage these market riskexposures.

 

The following market riskdiscussion relates primarily to commodity price risk and foreign currency riskrelated to our financial instruments as our exposure to interest rate risk isimmaterial.

 

Commodityprice risk

 

We are exposed to commodityprice movements as part of our normal oil and gas operations, particularly inrelation to the prices received for our crude oil and natural gas. Commodityprice risk related to conventional and synthetic crude oil prices is our mostsignificant market risk exposure. Crude oil and natural gas are sensitive tonumerous worldwide factors, many of which are beyond our control, and aregenerally sold at contract or posted prices. Changes in global supply anddemand fundamentals in the crude oil market and geopolitical events cansignificantly affect crude oil prices. Changes in crude oil and natural gasprices may significantly affect our results of operations and cash generatedfrom operating activities. Consequently, these changes also may affect thevalue of our oil and gas properties, our level of spending for exploration anddevelopment, and our ability to meet our obligations as they come due.

 

The majority of our oil andgas production is sold under short-term contracts, exposing us to the risk ofnear-term price movements. Other energy contracts we enter into also expose usto commodity price risk between the time we purchase and sell contracted volumes.We actively manage these risks by using derivative contracts such as commodityput options.

 

Our energy marketingbusiness is focused on providing services to our customers and suppliers tomeet their energy commodity needs. We market and trade physical energycommodities in selected regions of the world including crude oil, natural gas,electricity and other commodities. We do this by buying and selling physicalcommodities, by acquiring and holding rights to physical transportation andstorage assets for these commodities, and by building strong relationships withour customers and suppliers.

 

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In order to manage thecommodity and foreign exchange price risks that come from this physicalbusiness, we use financial derivative contracts including energy-relatedfutures, forwards, swaps and options, as well as currency swaps or forwards.

 

We also seek to profit fromour views on the future movement of energy commodity pricing relationships,primarily between different locations, time periods or qualities. We do this byholding open positions, where the terms of physical or financial contracts arenot completely matched to offsetting positions. We may also carry exposures tothe absolute change in commodity prices based on our market views or as aconsequence of managing our physical and financial positions on a day to daybasis.

 

Our risk managementactivities make use of tools such as Value-at-Risk (VaR) and stress testing.VaR is a statistical estimate of the expected profit or loss of a portfolio ofpositions assuming normal market conditions. We use a 95% confidence intervaland an assumed two day holding period in our measure, although actual resultscan differ from this estimate in non-normal market conditions, or if positionsare held longer than two days based on market views or a lack of marketliquidity to exit them, which is typical for long-term assets and may apply tonearer term positions. We estimate VaR primarily by using the Variance-Covariancemethod based on historical commodity price volatility and correlation inputswhere available, and by historical simulation in other situations. Our estimateis based upon the following key assumptions:

 
| · | changes in commodity  prices are either normally or “T” (for natural gas since May 2006)  distributed; |
|--------|-----------------------------------------------------------------------------------------------------------------------|
| · | price volatility remains  stable; and                                                                                 |
| · | price correlation  relationships remain stable.                                                                       |

 

We have defined VaR limitsfor different segments of our business. These limits are calculated on aneconomic basis and include physical and financial derivatives, as well asphysical transportation and storage capacity contracts accounted for asexecutory contracts in our financial statements. We monitor our positionsagainst these VaR limits daily. Our year end, annual high, annual low andaverage VaR amounts are as follows:

 
| **Value-at-Risk ****(Cdn$ millions)** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-------------------------------------------------|------------|----------|------------|----------|------------|
| Year End                                        |       | 25       |       | 26       |       |
| High                                            |       | 40       |       | 38       |       |
| Low                                             |       | 19       |       | 24       |       |
| Average                                         |       | 30       |       | 30       |       |

 

If market shock occurred asin 2008, the key assumptions underlying our VaR estimate could be exceeded andthe potential loss could be greater than our estimate. We perform stress testson a regular basis to complement VaR and assess the impact of non-normalchanges in prices on our positions.

 

Foreigncurrency risk

 

Foreigncurrency risk is created by fluctuations in the fair values or cash flows offinancial instruments due to changes in foreign exchange rates. A substantialportion of our activities are transacted in or referenced to US dollarsincluding:

 
| · | sales of crude oil,  natural gas and certain chemicals products;                       |
|--------|----------------------------------------------------------------------------------------|
| · | capital spending and  expenses for our oil and gas, Syncrude and chemicals operations; |
| · | commodity derivative  contracts used primarily by our energy marketing group; and      |
| · | short-term borrowings and  long-term debt.                                             |

 

In our oil and gasoperations, we manage our exposure to fluctuations between the US and Canadiandollar by maintaining our expected net cash flows and borrowings in the samecurrency. Cash inflows generated by our foreign operations and borrowings onour US-dollar debt facilities are generally used to fund US-dollar capitalexpenditures and debt repayments. We maintain revolving Canadian and US-dollarborrowing facilities that can be used or repaid depending on expected net cashflows. We designate most of our US-dollar borrowings as a hedge against ourUS-dollar net investment in self-sustaining foreign operations. At December 31,2008, we had US$5,432 million of long-term debt issued in US dollars and a onecent change in the US dollar to Canadian dollar exchange rate would increase ordecrease our accumulated other comprehensive income by approximately $52million, before income tax.

 

We also have exposures tocurrencies other than the US dollar including a portion of our UK operatingexpenses, capital spending and future asset retirement obligations which aredenominated in British pounds and Euros. We do not have any material exposureto highly inflationary foreign currencies. In our energy marketing group, weenter into transactions in various currencies including Canadian and USdollars, British pounds and Euros. We actively manage significant currencyexposures using forward contracts and swaps.

 

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**(b)    Credit risk**

 

Credit risk affects both ourtrading and non-trading activities and is the risk of loss if counterparties donot fulfill their contractual obligations. Most of our credit exposures arewith counterparties in the energy industry, including integrated oil companies,refiners and utilities, and are subject to normal industry credit risk.Approximately 71% of our exposure is with these large energy companies. Thisconcentration of risk within the energy industry is reduced because of ourbroad base of domestic and international counterparties. We take the followingmeasures to reduce this risk:

 
| · | assess the financial  strength of our counterparties through a rigorous credit analysis process;                                                                                                           |
|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| · | limit the total exposure  extended to individual counterparties, and may require collateral from some  counterparties;                                                                                     |
| · | routinely monitor credit  risk exposures, including sector, geographic and corporate concentrations of  credit, and report these to our Risk Management Committee and the Finance  Committee of the board; |
| · | set credit limits based on  rating agency credit ratings and internal assessments based on company and  industry analysis;                                                                                 |
| · | review counterparty credit  limits regularly; and                                                                                                                                                          |
| · | use standard agreements  that 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. During 2008,we have taken the following specific actions for certain counterparties deemedto be at higher risk of non-performance:

 
| · | ceased trading activities;                                                                                 |
|--------|------------------------------------------------------------------------------------------------------------|
| · | significantly reduced and,  in some cases, revoked credit privileges;                                      |
| · | redirected business to i)  exchanges or clearing houses; and ii) entities with physical-based  operations; |
| · | increased “set off”  arrangements with counterparties; and                                       |
| · | increased collateral and  margining requirements where possible.                                           |

 

At December 31, 2008,only one counterparty individually made up more than 10% of our creditexposure. This counterparty is a major integrated oil company with a stronginvestment grade rating. No other counterparties made up more than 5% of ourcredit exposure. The following table illustrates the composition of creditexposure by credit rating.

 
| **Credit Rating** | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------|------------|----------|------------|----------|------------|
| A or higher            |       | 65       | %          | 68       | %          |
| BBB                    |       | 29       | %          | 27       | %          |
| Non-Investment Grade   |       | 6        | %          | 5        | %          |
| **Total**              | ** ** | **100**  | **%**      | **100**  | **%**      |

 

Our maximum counterpartycredit exposure at the balance sheet date consists primarily of the carryingamounts of non-derivative financial assets such as accounts receivable, cashand cash equivalents, restricted cash, as well as the fair value of derivativefinancial assets. In September 2008, Lehman Brothers filed for bankruptcyprotection and our exposure at the time was approximately $39 million. Thisamount was provided for even though we continue to pursue recovery. We alsoprovided an additional $15 million for credit risk with our counterparties. Inaddition, we incorporate the credit risk associated with counterparty default,as well as Nexen’s own credit risk, into our estimates of fair value.

 

Collateral received fromcustomers at December 31, 2008 includes $90 million of cash and $311million of letters of credit. The cash received is included in accounts payableand accrued liabilities.

 

**(c)    Liquidity risk**

 

Liquidity risk is the riskthat we will not be able to meet our financial obligations as they fall due. Werequire liquidity specifically to fund capital requirements, satisfy financialobligations as they become due, and to operate in our energy marketingbusiness. We generally rely on operating cash flows to provide liquidity and wealso maintain significant undrawn committed credit facilities. At December 31,2008, we had about $4.5 billion of cash and available committed lines of credit(US$3.7 billion). This includes $2 billion of cash and cash equivalents onhand. Of this amount, approximately US$1 billion was a result of draws made onour term credit facilities, which were used for an internal reorganization andfinancing of our North Sea assets. In addition, we have undrawn term creditfacilities of $2.5 billion (US$2.1 billion), of which $381 million (US$311million) was supporting letters of credit at December 31, 2008. Thesefacilities are available until 2012. We also have $613 million (US$501 million)of undrawn, uncommitted credit facilities, of which $29 million (US$24 million)was supporting letters of credit at year

 

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end. Subsequent to year end,we used $735 million of our available liquidity to acquire an additional 15%interest in the Long Lake Project.

 

The following table detailsthe contractual maturities for our non-derivative financial liabilities,including both the principal and interest cash flows at December 31, 2008:

 
| ** **                     | ** ** | **Total**  | ** ** | **< 1 Year** | ** ** | **1-3 Years** | ** ** | **4-5 Years** | ** ** | **> 5 Years** | ** ** |
|--------------------------------|------------|------------|------------|---------------------------|------------|--------------------|------------|--------------------|------------|----------------------------|------------|
| Long-Term Debt                 |       | 6,652      |       | —                    |       | 223                |       | 1,898              |       | 4,531                      |       |
| Interest on Long-Term Debt (1) |       | 7,611      |       | 331                       |       | 662                |       | 657                |       | 5,961                      |       |
| **Total**                      | ** ** | **14,263** | ** ** | **331**                   | ** ** | **885**            | ** ** | **2,555**          | ** ** | **10,492**                 | ** ** |

 

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| *(1)* | *Excludes  interest on term credit facilities of $3.7 billion (US$3.1 billion) and  Canexus term credit facilities of $420 million (US$343 million) as the  amounts drawn on the facilities fluctuate. Based on amounts drawn at December 31,  2008 and existing variable interest rates, we would be required to pay $19  million per year until the outstanding amounts on the term credit facilities  are repaid.* |
|-------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

The following table detailscontractual maturities for our derivative financial liabilities. The balancesheet amounts for derivative financial liabilities included below are notmaterially different from the contractual amounts due on maturity.

 
| ** **              | ** ** | **Total** | ** ** | **< 1 Year** | ** ** | **1-3 Years** | ** ** | **4-5 Years** | ** ** | **> 5 Years** | ** ** |
|-------------------------|------------|-----------|------------|---------------------------|------------|--------------------|------------|--------------------|------------|----------------------------|------------|
| Trading Derivatives     |       | 909       |       | 615                       |       | 264                |       | 25                 |       | 5                          |       |
| Non-Trading Derivatives |       | 47        |       | 21                        |       | 26                 |       | —             |       | —                     |       |
| **Total**               | ** ** | **956**   | ** ** | **636**                   | ** ** | **290**            | ** ** | **25**             | ** ** | **5**                      | ** ** |

 

The commercial agreementsour energy marketing group enters into often include financial assuranceprovisions that allow us and our counterparties to effectively manage creditrisk. The agreements normally require collateral to be posted if an adversecredit-related event occurs, such as a drop in credit ratings to non-investmentgrade. Based on contracts in place and commodity prices at December 31,2008, we could be required to post collateral of up to $1.3 billion if we weredowngraded to non-investment grade. These obligations are reflected on ourbalance sheet. The posting of collateral secures the payment of such amounts.In the event of a ratings downgrade, we have trading inventories andreceivables that can be quickly monetized as well as significant undrawn creditfacilities.

 

At December 31, 2008,collateral we have posted with counterparties includes $60 million of cash and$194 million of letters of credit related to our trading activities. Cashposted is included with our accounts receivable. Cash collateral is notnormally applied to contract settlement. Once a contract has been settled, thecollateral amounts are refunded. If there is a default, the cash is retained.

 

Our exchange-tradedderivative contracts are also subject to margin requirements. We have margindeposits of $103 million (December 31, 2007 — $203 million), which havebeen included in restricted cash.

 

**9.     ACCOUNTS PAYABLEAND ACCRUED LIABILITIES**

** **
| ** **                                       | ** ** | **2008**  | ** ** | **2007**  | ** ** |
|--------------------------------------------------|------------|-----------|------------|-----------|------------|
| Accrued Payables                                 |       | 2,033     |       | 2,546     |       |
| Energy Marketing Derivative Contracts (Note  7a) |       | 615       |       | 413       |       |
| Trade Payables                                   |       | 303       |       | 578       |       |
| Stock-based Compensation                         |       | 97        |       | 393       |       |
| Income Taxes Payable                             |       | 69        |       | 45        |       |
| Other                                            |       | 209       |       | 205       |       |
| **Total**                                        | ** ** | **3,326** | ** ** | **4,180** | ** ** |

 

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**10.   SHORT-TERMBORROWINGS AND LONG-TERM DEBT**

 
| ** **                                                           | ** ** | **2008**  | ** ** | **2007**  | ** ** |
|----------------------------------------------------------------------|------------|-----------|------------|-----------|------------|
| Medium-Term Notes, due 2008 (a)                                      |       | —    |       | 125       |       |
| Canexus Term Credit Facilities, due 2011  (US$182 million drawn) (b) |       | 223       |       | 202       |       |
| Term Credit Facilities, due 2012 (US$1  billion drawn) (c)           |       | 1,225     |       | 211       |       |
| Canexus Notes, due 2013 (US$50 million) (d)                          |       | 61        |       | —    |       |
| Notes, due 2013 (US$500 million) (e)                                 |       | 612       |       | 494       |       |
| Notes, due 2015 (US$250 million) (f)                                 |       | 306       |       | 247       |       |
| Notes, due 2017 (US$250 million) (g)                                 |       | 306       |       | 247       |       |
| Notes, due 2028 (US$200 million) (h)                                 |       | 245       |       | 198       |       |
| Notes, due 2032 (US$500 million) (i)                                 |       | 612       |       | 494       |       |
| Notes, due 2035 (US$790 million) (j)                                 |       | 968       |       | 781       |       |
| Notes, due 2037 (US$1,250 million) (k)                               |       | 1,531     |       | 1,235     |       |
| Subordinated Debentures, due 2043 (US$460  million) (l)              |       | 563       |       | 454       |       |
| ** **                                                           | ** ** | **6,652** |       | **4,688** |       |
| Unamortized Debt Issue Costs                                         |       | (74       | )          | (78       | )          |
| **Total**                                                            | ** ** | **6,578** | ** ** | **4,610** | ** ** |

 

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**(a)    Medium-termnotes, due 2008**

 

During October 1997, weissued $125 million of notes with interest payable semi-annually at a rate of6.3%. The principal of $125 million was repaid in full in June 2008.

 

**(b)    Canexus termcredit facilities**

 

Canexus has $420 million(US$343 million) of committed, secured term credit facilities, available until2011. At December 31, 2008, $223 million (US$182 million) was drawn onthese facilities (2007 — $202 million (US$204 million)). Borrowings areavailable as Canadian bankers’ acceptances, LIBOR-based loans, Canadian primerate loans or US-dollar base rate loans. Interest is payable monthly atfloating rates. The term credit facilities are secured by a floating chargedebenture over all of Canexus’ assets. The credit facility also containscovenants with respect to certain financial ratios for Canexus. During 2008,the weighted-average interest rate on the Canexus term credit facilities was4.4% (2007 —6.1%).

 

**(c)    Term creditfacilities**

 

We have unsecured termcredit facilities of $3.7 billion (US$3.1 billion), available until 2012. At December 31,2008, $1.2 billion (US$1 billion) was drawn on these facilities (2007 — $211million (US$214 million)). Borrowings are available as Canadian bankers’acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rateloans or British pound call-rate loans. Interest is payable at floating rates.During 2008, the weighted-average interest rate was 2.8% (2007 — 5.8%). At December 31,2008, $381 million (US$311 million) of these facilities were utilized tosupport outstanding letters of credit (December 31, 2007 — $283 million(US$286 million)).

 

**(d)    Canexus Notes,due 2013**

 

During the second quarter of2008, Canexus issued US$50 million of notes. Interest is payable quarterly at arate of 6.57% and the principal is to be repaid in May 2013. Canexus 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%.

 

**(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**

 

During March 2005, weissued US$250 million of notes. Interest is payable semi-annually at a rate of5.2%, and the principal is to be repaid in March 2015. We may redeem partor all of the notes at any time. The redemption price will be the greater ofpar and an amount that provides the same yield as a US Treasury security havinga term-to-maturity equal to the remaining term of the notes plus 0.15%.

 

102

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**(g)   Notes, due 2017**

 

During May 2007, weissued US$250 million of notes. Interest is payable semi-annually at a rate of5.65%, and the principal is to be repaid in May 2017. We may redeem partor all of the notes at any time. The redemption price will be the greater ofpar and an amount that provides the same yield as a US Treasury security havinga term-to-maturity equal to the remaining term of the notes plus 0.2%.

 

**(h)   Notes,due 2028**

 

During April 1998, weissued US$200 million of notes. Interest is payable semi-annually at a rate of7.4%, and the principal is to be repaid in May 2028. We may redeem part orall of the notes at any time. The redemption price will be the greater of parand an amount that provides the same yield as a US Treasury security having aterm-to-maturity equal to the remaining term of the notes 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**

 

During March 2005, weissued US$790 million of notes. Interest is payable semi-annually at a rate of5.875%, and the principal is to be repaid in March 2035. We may redeempart or all of the notes at any time. The redemption price will be the greaterof par and an amount that provides the same yield as a US Treasury securityhaving a term-to-maturity equal to the remaining term of the notes 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%.

 

**(l)    Subordinateddebentures, 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-termdebt repayments**

 
| 2009       |       | —    |       |
|------------|------------|-----------|------------|
| 2010       |       | —    |       |
| 2011       |       | 223       | (1)        |
| 2012       |       | 1,225     |       |
| 2013       |       | 673       |       |
| Thereafter |       | 4,531     |       |
| **Total**  | ** ** | **6,652** | ** ** |

 

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*(1)**      **Canexus term credit facility.*

 

**(n)   Debtcovenants**

 

Some of our debt instrumentscontain covenants with respect to certain financial ratios and our ability togrant security. At December 31, 2008 and 2007, we were in compliance withall covenants.

 

**(o)    Short-termborrowings**

 

Nexen has uncommitted,unsecured credit facilities of approximately $613 million (US$501 million),none of which were drawn at December 31, 2008 (2007 — $nil).We utilized $29 million (US$24 million) of these facilities to supportoutstanding letters of credit at December 31, 2008 (2007 — $196 million(US$198 million)). Interest is payable at floating rates. During 2008, theweighted-average interest rate on our short-term borrowings was 3.2% (2007 — 5.8%).

 

103

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**(p)    Interest expense**

 
| ** **        | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|-------------------|------------|----------|------------|----------|------------|----------|------------|
| Long-Term Debt    |       | 315      |       | 323      |       | 275      |       |
| Other             |       | 19       |       | 18       |       | 19       |       |
| Total             |       | 334      |       | 341      |       | 294      |       |
| Less: Capitalized |       | (240     | )          | (173     | )          | (241     | )          |
| **Total**         | ** ** | **94**   | ** ** | **168**  | ** ** | **53**   | ** ** |

 

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.

 

**11.   CAPITAL DISCLOSURE**

 

Ourobjective for managing our capital structure is to ensure that we have thefinancial capacity, liquidity and flexibility to fund our investment infull-cycle exploration and development of conventional and unconventionalresources and for energy marketing activities. We generally rely on operatingcash flows to fund capital investments. However, given the long cycle-time ofsome of our development projects which require significant capital investmentprior to cash flow generation and volatile commodity prices, it is not unusualfor capital expenditures to exceed our cash flow from operating activities inany given period. As such, our financing needs depend on the timing of expectednet cash flows in a particular development or commodity cycle. This requires usto maintain financial flexibility and liquidity. Our capital managementpolicies are aimed at:

 

·      maintainingan appropriate balance between short-term borrowings, long-term debt andshareholders’ equity;

·      maintainingsufficient undrawn committed credit capacity to provide liquidity;

·      ensuringample covenant room permitting us to draw on credit lines as required; and

·      ensuringwe maintain a credit rating that is appropriate for our circumstances.

 

Wehave the ability to make adjustments to our capital structure by issuingadditional equity or debt, returning cash to shareholders and making adjustmentsto our capital investment programs. Our capital consists of shareholders’equity, short-term borrowings, long-term debt, and cash and cash equivalents asfollows:

 
| **Net Debt (1)**            | ** ** | **2008**  | ** ** | **2007**  | ** ** |
|----------------------------------|------------|-----------|------------|-----------|------------|
| Long-Term Debt                   |       | 6,578     |       | 4,610     |       |
| Less: Cash and  Cash Equivalents |       | (2,003    | )          | (206      | )          |
| **Total**                        | ** ** | **4,575** | ** ** | **4,404** | ** ** |
|                             |       |      |       |      |       |
| **Shareholders’ Equity**    | ** ** | **7,139** | ** ** | **5,610** | ** ** |

 

----

*(1)**      **Includes all of our borrowings and is calculated aslong-term debt and short-term borrowings less cash and cash equivalents.*

 

Wemonitor the leverage in our capital structure by reviewing the ratio of netdebt to cash flow from operating activities and interest coverage ratios atvarious commodity prices.

 

Weuse the ratio of net debt to cash flow from operating activities as a keyindicator of our leverage and to monitor the strength of our balance sheet. Netdebt is a non-GAAP measure that does not have any standard meaning prescribedby GAAP and is therefore unlikely to be comparable to similar measurespresented by others. We calculate net debt using the GAAP measures of long-termdebt and short-term borrowings less cash and cash equivalents (excludingrestricted cash).

 

Forthe twelve months ended December 31, 2008, our net debt to cash flow fromoperating activities ratio was 1.1 times compared to 1.6 times at December 31,2007. While we typically expect the target ratio to fluctuate between 1.0 and2.0 times under normalized commodity prices, this can be higher when weidentify strategic opportunities requiring additional investment. Whenever weexceed our target ratio, we develop a strategy to reduce our leverage and lowerthis ratio back to target levels over time.

 

Ourinterest coverage ratio allows us to monitor our ability to fund the interestrequirements associated with our debt. Our interest coveragestrengthened in 2008 from 12.1 times at the end of 2007 to 15.6 times at December 31,2008.

 

104

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Interestcoverage is calculated by dividing our twelve-month trailing earnings beforeinterest, taxes, DD&A (EBITDA) by interest expense before capitalizedinterest. EBITDA is a non-GAAP measure which is calculated using net incomeexcluding interest expense, provision for income taxes, exploration expenses,DD&A, impairment and other non-cash expenses. The calculation of EBITDA isset out in the following table.

 
| ** **                                            | ** ** | **2008**  | ** ** | **2007**  | ** ** |
|-------------------------------------------------------|------------|-----------|------------|-----------|------------|
| Net Income                                            |       | 1,715     |       | 1,086     |       |
| Add:                                                  |       |      |       |      |       |
| Interest Expense                                      |       | 94        |       | 168       |       |
| Provision for  Income Taxes                           |       | 1,457     |       | 792       |       |
| Depreciation,  Depletion, Amortization and Impairment |       | 2,014     |       | 1,767     |       |
| Exploration  Expense                                  |       | 402       |       | 326       |       |
| Recovery of  Non-Cash Stock-Based Compensation        |       | (272      | )          | (109      | )          |
| Change in Fair  Value of Crude Oil Put Options        |       | (203      | )          | 43        |       |
| Other Non-Cash  Expenses                              |       | (1        | )          | 14        |       |
| **EBITDA**                                            | ** ** | **5,206** | ** ** | **4,087** | ** ** |

 

**12.   ASSET RETIREMENTOBLIGATIONS**

 

Changesin carrying amounts of the asset retirement obligations associated with ourPP&E are as follows:

 
| ** **                                        | ** ** | **2008**  | ** ** | **2007** | ** ** |
|---------------------------------------------------|------------|-----------|------------|----------|------------|
| Asset Retirement  Obligations, Beginning of Year  |       | 832       |       | 704      |       |
| Obligations  Incurred with Development Activities |       | 32        |       | 105      |       |
| Obligations Settled                               |       | (45       | )          | (23      | )          |
| Accretion Expense                                 |       | 58        |       | 44       |       |
| Revisions to  Estimates                           |       | 159       |       | 79       |       |
| Effects of  Changes in Foreign Exchange Rate      |       | 23        |       | (77      | )          |
| **End of Year (1), (2)**                          | ** ** | **1,059** | ** ** | **832**  | ** ** |

 

----

*(1)**      **Obligations due within twelve months of $35 million (2007 — $40million) have been included in accounts payable and accrued liabilities.*

*(2)**      **Obligations relating to our oil and gas activities amount to$1,009 million (2007 — $786 million) and obligations relating to our chemicalsbusiness amount to $50 million (2007 — $46 million).*

 

Ourtotal estimated undiscounted inflated asset retirement obligations amount to$2,393 million (2007 — $2,165 million). We have discounted the total estimatedasset retirement obligations using a weighted-average, credit-adjustedrisk-free rate of 5.9% (2007— 5.9%). Approximately $409 million included in our asset retirementobligations will be settled over the next five years. The remaining obligationssettle beyond five years and will be funded by future cash flows from ouroperations.

 

**13.   DEFERRED CREDITSAND OTHER LIABILITIES**

 
| ** **                                             | ** ** | **2008**  | ** ** | **2007** | ** ** |
|--------------------------------------------------------|------------|-----------|------------|----------|------------|
| Deferred Tax  Credit                                   |       | 709       |       | —   |       |
| Long-Term  Marketing Derivative Contracts (Note 7a)    |       | 294       |       | 163      |       |
| Deferred  Transportation Revenue                       |       | 69        |       | 82       |       |
| Fixed-Price  Natural Gas Contracts and Swaps (Note 7b) |       | 26        |       | 51       |       |
| Defined Benefit  Pension Obligations (Note 14)         |       | 67        |       | 57       |       |
| Capital Lease  Obligations                             |       | 53        |       | 52       |       |
| Other                                                  |       | 106       |       | 54       |       |
| **Total**                                              | ** ** | **1,324** | ** ** | **459**  | ** ** |

 

Duringthe third quarter of 2008, we completed an internal reorganization andfinancing of our assets in the North Sea which provided us with an additionalone-time tax deduction in the UK. As these transactions were completed withinour consolidated group, we are unable to recognize the benefit of the taxdeductions until the assets are recognized in income by way of a sale to athird party or depletion through use. Accordingly, we have deferred recognizing$709 million of tax deductions in our consolidated income statement.

 

105

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**14.   PENSION AND OTHERPOST-RETIREMENT BENEFITS**

 

Nexenand Canexus have contributory and non-contributory defined benefit and definedcontribution pension plans, as well as other post-retirement benefit programs,which cover substantially all employees. Syncrude has a defined benefit planfor its employees, and we disclose only our proportionate share of this plan.

 

**(a)    Defined benefitpension plans**

 

The cost of pension benefits earnedby employees is determined using the projected-benefit method prorated onemployment services and is expensed as services are rendered. We fund theseplans according to federal and provincial government regulations bycontributing to trust funds administered by an independent trustee. These fundsare invested primarily in equities and bonds.

 
| ** **                                          | ** ** | **2008**  | ** ** | **2007**    | ** ** |
|-----------------------------------------------------|------------|-----------|------------|-------------|------------|
| ** **                                          | ** ** | **Nexen** | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** | **Nexen** | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** |
| **Change in Projected Benefit Obligation (PBO)**    |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Beginning of Year                                   |       | 272       |       | 62          |       | 125 |   | 252 |   | 58 |   | 116 |   |
| Service Cost                                        |       | 23        |       | 4           |       | 4 |   | 18 |   | 3 |   | 5 |   |
| Interest Cost                                       |       | 17        |       | 4           |       | 7 |   | 13 |   | 3 |   | 6 |   |
| Plan Participants’  Contributions              |       | 5         |       | 1           |       | 1 |   | 4 |   | 1 |   | 1 |   |
| Actuarial  Loss/(Gain)                              |       | (39       | )          | (11         | )          | (25 | ) | (2 | ) | (3 | ) | 1 |   |
| Benefits Paid                                       |       | (13       | )          | (1          | )          | (5 | ) | (13 | ) | — |   | (4 | ) |
| **End of Year (1)**                                 | ** ** | **265**   | ** ** | **59**      | ** ** | **107** | ** ** | **272** | ** ** | **62** | ** ** | **125** | ** ** |
| **Change in Fair Value of Plan Assets**             |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Beginning of Year                                   |       | 200       |       | 55          |       | 74 |   | 185 |   | 50 |   | 69 |   |
| Actual Return on  Plan Assets                       |       | (54       | )          | (9          | )          | (19 | ) | 18 |   | 1 |   | 2 |   |
| Employer’s  Contribution                       |       | 15        |       | 4           |       | 6 |   | 6 |   | 3 |   | 6 |   |
| Plan  Participants’ Contributions              |       | 5         |       | 1           |       | 1 |   | 4 |   | 1 |   | 1 |   |
| Benefits Paid                                       |       | (13       | )          | (1          | )          | (5 | ) | (13 | ) | — |   | (4 | ) |
| **End of Year**                                     | ** ** | **153**   | ** ** | **50**      | ** ** | **57** | ** ** | **200** | ** ** | **55** | ** ** | **74** | ** ** |
| **Reconciliation of Funded Status**                 |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Funded Status (2)                                   |       | (112      | )          | (9          | )          | (50 | ) | (72 | ) | (7 | ) | (51 | ) |
| Unamortized  Transitional Obligation                |       | —    |       | —      |       | — |   | — |   | — |   | — |   |
| Unamortized Prior  Service Costs                    |       | 1         |       | —      |       | — |   | 2 |   | — |   | — |   |
| Unamortized Net  Actuarial Loss                     |       | 60        |       | 8           |       | 35 |   | 31 |   | 6 |   | 36 |   |
| **Pension Liability**                               | ** ** | **(51**   | **)**      | **(1**      | **)**      | **(15** | **)** | **(39** | **)** | **(1** | **)** | **(15** | **)** |
| **Pension  Liability******                          |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Deferred Charges  and Other Assets                  |       | 2         |       | —      |       | — |   | 4 |   | — |   | — |   |
| Accounts Payable  and Accrued Liabilities           |       | (2        | )          | —      |       | — |   | (2 | ) | — |   | — |   |
| Other Deferred  Credits and Liabilities (Note 13)   |       | (51       | )          | (1          | )          | (15 | ) | (41 | ) | (1 | ) | (15 | ) |
| **Pension Liability**                               | ** ** | **(51**   | **)**      | **(1**      | **)**      | **(15** | **)** | **(39** | **)** | **(1** | **)** | **(15** | **)** |
| Assumptions (%)                                     |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Accrued Benefit  Obligation at December 31     |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Discount Rate                                       |       | 6.50      |       | 6.50        |       | 6.50 |   | 5.25 |   | 5.25 |   | 5.25 |   |
| Long-Term Rate of  Employee Compensation Increase   |       | 4.00      |       | 4.00        |       | 5.00 |   | 4.00 |   | 4.00 |   | 5.00 |   |
| Benefit Cost for  Year Ended December 31 (3)   |       |      |       |        |       |   |   |   |   |   |   |   |   |
| Discount Rate                                       |       | 5.25      |       | 5.25        |       | 6.50 |   | 5.00 |   | 5.00 |   | 5.25 |   |
| Long-Term Rate of  Employee Compensation Increase   |       | 4.00      |       | 4.00        |       | 5.00 |   | 4.00 |   | 4.00 |   | 5.00 |   |
| Long-Term Annual  Rate of Return on Plan Assets (4) |       | 7.00      |       | 6.50        |       | 8.50 |   | 7.00 |   | 6.50 |   | 8.50 |   |

 

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*(1)**      **The accumulated benefit obligations (the projected benefitobligation (PBO) excluding future salary increases) of the Nexen and Canexusplans were $179 million and $46 million at December 31, 2008, respectively(2007 — $182 million and $47 million, respectively). Nexen’s supplemental pensionplan’s accumulated benefit obligation**was $49 millionat December 31, 2008 (2007 — $48 million). Nexen’s share of Syncrude’semployee pension plan’s accumulated benefit obligation was $82 million at December 31,2008 (2007 — $92 million).*

*(2)**      **Includes unfunded obligations for supplemental benefits tothe extent that the benefit is limited by statutory guidelines. At December 31,2008, the PBO for Nexen’s supplemental benefits was $62 million (2007 — $62million) and $1 million for Canexus (2007 — $1 million). The unfundedobligations for supplemental benefits are backed by irrevocable letters ofcredit. Subsequent to December 31, 2008, we contributed $46 million toNexen’s defined benefit pension plan to fund existing solvency deficiencies.*

*(3)**      **The measurement date is December 31, 2008.*

*(4)**      **The long-term annual rate of return on plan assetsassumption is based on a mix of historical market returns for debt and equitysecurities.*

 

106

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**Net PensionExpense Recognized Under Our Defined Benefit Pension Plans**

 
| ** **                                                                                    | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|-----------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| **Nexen**                                                                                     |       |       |       |       |       |       |       |
| Cost of Benefits  Earned by Employees                                                         |       | 23         |       | 18         |       | 16         |       |
| Interest Cost on  Benefits Earned                                                             |       | 17         |       | 13         |       | 12         |       |
| Actual (Return)  Loss on Plan Assets                                                          |       | 54         |       | (18        | )          | (23        | )          |
| Actuarial (Gains)/Losses                                                                      |       | (39        | )          | (2         | )          | 9          |       |
| Pension Expense  Before Adjustments for the Long-Term Nature of Employee Future Benefit Costs |       | 55         |       | 11         |       | 14         |       |
| Difference  Between Actual and Expected Return on Plan Assets                                 |       | (71        | )          | 5          |       | 12         |       |
| Difference  Between Actual and Recognized Actuarial Losses                                    |       | 41         |       | 3          |       | (7         | )          |
| Difference  Between Actual and Recognized Past Service Costs                                  |       | 1          |       | 1          |       | 1          |       |
| **Net Pension Expense**                                                                       | ** ** | **26**     | ** ** | **20**     | ** ** | **20**     | ** ** |
| ** **                                                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Canexus**                                                                                   |       |       |       |       |       |       |       |
| Cost of Benefits  Earned by Employees                                                         |       | 4          |       | 3          |       | 3          |       |
| Interest Cost on  Benefits Earned                                                             |       | 4          |       | 3          |       | 3          |       |
| Actual (Return)  Loss on Plan Assets                                                          |       | 9          |       | (2         | )          | (6         | )          |
| Actuarial  (Gains)/Losses                                                                     |       | (11        | )          | (3         | )          | 2          |       |
| Pension Expense  Before Adjustments for the Long-Term Nature of Employee Future Benefit Costs |       | 6          |       | 1          |       | 2          |       |
| Difference  Between Actual and Expected Return on Plan Assets                                 |       | (13        | )          | (1         | )          | 3          |       |
| Difference  Between Actual and Recognized Actuarial Gains                                     |       | 11         |       | 3          |       | (2         | )          |
| Difference  Between Actual and Recognized Past Service Costs                                  |       | —     |       | —     |       | —     |       |
| **Net Pension Expense**                                                                       | ** ** | **4**      | ** ** | **3**      | ** ** | **3**      | ** ** |
| ** **                                                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Syncrude (1)**                                                                              |       |       |       |       |       |       |       |
| Cost of Benefits  Earned by Employees                                                         |       | 4          |       | 5          |       | 5          |       |
| Interest Cost on  Benefits Earned                                                             |       | 7          |       | 6          |       | 5          |       |
| Actual (Return)  Loss on Plan Assets                                                          |       | 19         |       | (2         | )          | (8         | )          |
| Actuarial  (Gains)/Losses                                                                     |       | (25        | )          | 1          |       | —     |       |
| Pension Expense  Before Adjustments for the Long-Term Nature of Employee Future Benefit Costs |       | 5          |       | 10         |       | 2          |       |
| Difference  Between Actual and Expected Return on Plan Assets                                 |       | (26        | )          | (4         | )          | 3          |       |
| Difference  Between Actual and Recognized Actuarial Losses                                    |       | 27         |       | 1          |       | 2          |       |
| Difference  Between Actual and Recognized Past Service Costs                                  |       | —     |       | —     |       | —     |       |
| **Net Pension Expense**                                                                       | ** ** | **6**      | ** ** | **7**      | ** ** | **7**      | ** ** |
| ** **                                                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Total Net Pension Expense**                                                                 | ** ** | **36**     | ** ** | **30**     | ** ** | **30**     | ** ** |

 

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*(1)**      **Nexen’s share of Syncrude’s plan.*

 

**(b)    Plan assetallocation at December 31**

 

Ourinvestment goal for the assets in our defined benefit pension plans is topreserve capital and earn a long-term rate of return on assets, net of allmanagement expenses, in excess of the inflation rate. Investment funds aremanaged by external fund managers based on policies approved by the Board ofDirectors and Pension Committees of Nexen and Canexus. Nexen’s and Canexus’investment strategy is to diversify plan assets between debt and equitysecurities of Canadian and non-Canadian corporations that are traded onrecognized stock exchanges. Allowable and prohibited investment types are alsoprescribed in Nexen’s and Canexus’ investment policies.

 

107

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Syncrude’spension plan is governed and administered separately from ours. Syncrude’sinvestment assets are subject to similar investment goals, policies andstrategies.

 
| **(%)**           | ** ** | **Expected 2009** | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|-------------------|------------|------------------------|------------|------------|------------|------------|------------|
| **Nexen******     |       |                   |       |       |       |       |       |
| Equity Securities |       | 65                     |       | 55         |       | 64         |       |
| Debt Securities   |       | 35                     |       | 45         |       | 36         |       |
| **Total**         | ** ** | **100**                | ** ** | **100**    | ** ** | **100**    | ** ** |
| ** **        | ** ** | ** **             | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Canexus******   |       |                   |       |       |       |       |       |
| Equity Securities |       | 50                     |       | 50         |       | 50         |       |
| Debt Securities   |       | 50                     |       | 50         |       | 50         |       |
| **Total**         | ** ** | **100**                | ** ** | **100**    | ** ** | **100**    | ** ** |
| ** **        | ** ** | ** **             | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Syncrude******  |       |                   |       |       |       |       |       |
| Equity Securities |       | 70                     |       | 68         |       | 68         |       |
| Debt Securities   |       | 30                     |       | 32         |       | 32         |       |
| **Total**         | ** ** | **100**                | ** ** | **100**    | ** ** | **100**    | ** ** |

 

**(c)    Definedcontribution pension plans**

 

Underthese plans, pension benefits are based on plan contributions. During 2008,Canadian pension expense for these plans was $7 million (2007 — $6 million;2006 — $4 million). During 2008, US pension expense for these plans was $4million (2007 — $4 million; 2006 — $4 million) and UK pension expense for theseplans was $6 million (2007 — $5 million; 2006 — $4 million).

 

**(d)    Post-retirementbenefits**

 

Nexenprovides certain post-retirement benefits, including group life andsupplemental health insurance, to eligible employees and their dependents. Thepresent value of Nexen employees’ future post retirement benefits at December 31,2008 was $15 million (2007 — $10 million) and $2 million for Canexus (2007 — $1million).

 

**(e)    Employer fundingcontributions and benefit payments**

 

Canadianregulators have prescribed funding requirements for our defined benefit plans.Our funding contributions over the last three years have met these requirementsand also included additional discretionary contributions permitted by law. Forour defined contribution plans, we make contributions on behalf of ouremployees and no further obligation exists. Our funding contributions for thedefined benefit plans are:

 
| ** **                              | ** ** | **Expected 2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-----------------------------------------|------------|------------------------|------------|----------|------------|----------|------------|
| **Nexen****(****1)**                    |       | 58                     |       | 15       |       | 6        |       |
| Canexus                                 |       | 3                      |       | 4        |       | 3        |       |
| Syncrude                                |       | 7                      |       | 7        |       | 6        |       |
| **Total Defined Benefit Contributions** | ** ** | **68**                 | ** ** | **26**   | ** ** | **15**   | ** ** |

 

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*(1)**      **Nexen’s defined benefit plan has a solvency deficiency of$46 million at December 31, 2008 and we funded this amount in February 2009.*

 

Our most recent funding valuationwas prepared as of June 30, 2008. Our next funding valuation is requiredby June 30, 2011. Canexus’ most recent funding valuation was prepared asof December 31, 2007, and their next funding valuation is required by December 31,2010. Syncrude’s most recent funding valuation was prepared as of December 31,2006, and their next funding valuation is December 31, 2009.

 

108

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Ourtotal benefit payments in 2008 were $13 million for Nexen (2007 — $13 million).Our share of Syncrude’s total benefit payments in 2008 was $5 million (2007 — $4million). Our estimated future payments are as follows:

 
| ** **     | ** ** | **Defined Benefit** | ** ** | **Other**   | ** ** |
|----------------|------------|--------------------------|------------|-------------|------------|
| ** **     | ** ** | **Nexen**                | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** | **Nexen** | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** |
| 2009           |       | 10                       |       | 1           |       | 4 |   | 2 |   | — |   | — |   |
| 2010           |       | 11                       |       | 1           |       | 4 |   | 2 |   | — |   | — |   |
| 2011           |       | 12                       |       | 2           |       | 5 |   | 3 |   | — |   | — |   |
| 2012           |       | 13                       |       | 2           |       | 5 |   | 3 |   | — |   | — |   |
| 2013           |       | 14                       |       | 3           |       | 6 |   | 4 |   | — |   | — |   |
| 2014–2018 |       | 88                       |       | 20          |       | 36 |   | 27 |   | — |   | 2 |   |

 

**15.   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.

 

**(b)    Issued commonshares and dividends**

 
| **(thousands of shares)**              | ** ** | **2008**    | ** ** | **2007**    | ** ** | **2006**    | ** ** |
|--------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|
| Issued Common  Shares, Beginning of Year         |       | 528,305     |       | 525,026     |       | 522,281     |       |
| Issue of Common  Shares for Cash                 |       |        |       |        |       |        |       |
| Exercise of  Tandem Options                      |       | 1,911       |       | 2,257       |       | 1,693       |       |
| Dividend  Reinvestment Plan                      |       | 871         |       | 523         |       | 552         |       |
| Employee  Flow-through Shares                    |       | 499         |       | 499         |       | 500         |       |
| Repurchased under  Normal Course Issuer Bid      |       | (12,137     | )          | —      |       | —      |       |
| **End of Year**                                  | ** ** | **519,449** | ** ** | **528,305** | ** ** | **525,026** | ** ** |
| ** **                                       | ** ** | ** **  | ** ** | ** **  | ** ** | ** **  | ** ** |
| **Dividends Declared per Common Share**($/share) | ** ** | **0.18**    | ** ** | **0.10**    | ** ** | **0.10**    | ** ** |
| ** **                                       | ** ** | ** **  | ** ** | ** **  | ** ** | ** **  | ** ** |
| **Cash Consideration**(Cdn$ millions)       |       |        |       |        |       |        |       |
| Exercise of  Tandem Options                      |       | 23          |       | 24          |       | 16          |       |
| Dividend  Reinvestment Plan                      |       | 25          |       | 16          |       | 16          |       |
| Employee  Flow-through Shares                    |       | 16          |       | 16          |       | 16          |       |
| **Total**                                        | ** ** | **64**      | ** ** | **56**      | ** ** | **48**      | ** ** |

 

Duringthe year, 871,254 common shares were issued under the Dividend ReinvestmentPlan leaving a balance of 3,603,841 common shares (2007 — 4,475,095; 2006 — 997,662)reserved for issuance at December 31, 2008. Dividends paid to holders ofcommon shares have been designated as “eligible dividends” for Canadian taxpurposes.

 

Duringthe year, we received approval from the Toronto Stock Exchange (TSX) for aNormal Course Issuer Bid to repurchase up to a maximum of 52,914,046 commonshares between August 6, 2008 and August 5, 2009. Under thisauthorization, we repurchased and cancelled 12,136,900 common shares acquiredon the open market through the TSX at an average price of $27.85 per commonshare, totalling $338 million. Of the amount paid, $22 million reduced the bookvalue of our common shares and the excess of $316 million reduced retainedearnings.

 

109

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Thefollowing summarizes the purchase of equity securities in 2008.

 
| ** **                      | ** ** | **(a) Total number of  shares purchased** | ** ** | **(b) Average price  paid per share** | ** ** | **(c) Total number of shares  purchased as  part of publicly announced  plans or programs** | ** ** | **(d) Maximum number  of shares that may yet  to be purchased under the  plans or programs** | ** ** |
|---------------------------------|------------|---------------------------------------------------------------|------------|-----------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Period**                      | ** ** | **(thousands)**                                               | ** ** | **($/Share)**                                             | ** ** | **(thousands)**                                                                                                                               | ** ** | **(thousands)**                                                                                                                                          | ** ** |
| August 6–31,  2008    |       | 6,200                                                         |       | $31.78                                                    |       | 6,200                                                                                                                                         |       | 46,714                                                                                                                                                   |       |
| September 1–30,  2008 |       | 3,787                                                         |       | $27.22                                                    |       | 3,787                                                                                                                                         |       | 42,927                                                                                                                                                   |       |
| October 1–31,  2008   |       | 1,094                                                         |       | $16.44                                                    |       | 1,094                                                                                                                                         |       | 41,833                                                                                                                                                   |       |
| November 1–30,  2008  |       | 1,056                                                         |       | $18.92                                                    |       | 1,056                                                                                                                                         |       | 40,777                                                                                                                                                   |       |
| December 1–31,  2008  |       | —                                                        |       | —                                                    |       | —                                                                                                                                        |       | 40,777                                                                                                                                                   |       |
| **Total**                       | ** ** | **12,137**                                                    | ** ** | **$27.85**                                                | ** ** | **12,137**                                                                                                                                    |       |                                                                                                                                                     |       |

 

**(c)    Tandem options**

 

Wehave granted tandem options to purchase common shares to directors, officersand employees. Each option permits the right to either purchase one Nexencommon share at the exercise price or receive a cash payment equal to theexcess of market price over the exercise price.

 
| ** **                                                        | ** ** | **2008**        | ** ** | **2007**                                   | ** ** | **2006**        | ** ** |
|-------------------------------------------------------------------|------------|-----------------|------------|--------------------------------------------|------------|-----------------|------------|
| ** **                                                        | ** ** | **Options**     | ** ** | **Weighted  Average  Exercise Price** | ** ** | **Options**     | ** ** | **Weighted  Average  Exercise Price** | ** ** | **Options** | ** ** | **Weighted  Average  Exercise Price** | ** ** |
| **(thousands of shares)**                               | ** ** | **(thousands)** | ** ** | **($/option)**                             | ** ** | **(thousands)** | ** ** | **($/option)** | ** ** | **(thousands)** | ** ** | **($/option)** | ** ** |
| Outstanding  Options, Beginning of Year                           |       | 27,403          |       | 20                                         |       | 30,485          |       | 17 |   | 30,629 |   | 14 |   |
| Granted                                                           |       | 3,534           |       | 19                                         |       | 4,007           |       | 28 |   | 4,802 |   | 32 |   |
| Exercised for  Stock                                              |       | (1,911          | )          | 13                                         |       | (2,257          | )          | 10 |   | (1,693 | ) | 9 |   |
| Surrendered for  Cash                                             |       | (3,839          | )          | 13                                         |       | (4,414          | )          | 11 |   | (3,043 | ) | 9 |   |
| Cancelled                                                         |       | (552            | )          | 30                                         |       | (418            | )          | 22 |   | (210 | ) | 19 |   |
| Expired                                                           |       | (13             | )          | 11                                         |       | —          |       | — |   | — |   | — |   |
| **End of Year**                                                   | ** ** | **24,622**      | ** ** | **22**                                     | ** ** | **27,403**      | ** ** | **20** | ** ** | **30,485** | ** ** | **17** | ** ** |
| ** **                                                        | ** ** | ** **      | ** ** | ** **                                 | ** ** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Options  Exercisable at End of Year                               |       | 17,087          |       | 21                                         |       | 18,216          |       | 16 |   | 18,691 |   | 12 |   |
| Common Shares  Reserved for Issuance Under the Tandem Option Plan |       | 27,429          |       |                                       |       | 29,430          |       |   |   | 32,470 |   |   |   |

 

Therange of exercise prices of options outstanding and exercisable at December 31,2008 is as follows:

 
| ** **       | ** ** | **Outstanding Options** | ** ** | **Exercisable Options**               | ** ** |
|------------------|------------|------------------------------|------------|--------------------------------------------|------------|
| ** **       | ** ** | **Number of  Options**  | ** ** | **Weighted  Average  Exercise Price** | ** ** | **Weighted  Average Years  to Expiry** | ** ** | **Number of  Options** | ** ** | **Weighted  Average  Exercise Price** | ** ** |
| ** **       | ** ** | **(thousands)**              | ** ** | **($/option)**                             | ** ** | **(years)** | ** ** | **(thousands)** | ** ** | **($/option)** | ** ** |
| $5.00 to $9.99   |       | 3,178                        |       | 8                                          |       | 2 |   | 3,178 |   | 8 |   |
| $10.00 to $14.99 |       | 4,429                        |       | 13                                         |       | 1 |   | 4,429 |   | 13 |   |
| $15.00 to $19.99 |       | 3,523                        |       | 19                                         |       | 5 |   | 12 |   | 17 |   |
| $20.00 to $24.99 |       | 10                           |       | 23                                         |       | 2 |   | 10 |   | 23 |   |
| $25.00 to $29.99 |       | 8,777                        |       | 28                                         |       | 3 |   | 6,456 |   | 28 |   |
| $30.00 to $34.99 |       | 4,640                        |       | 32                                         |       | 3 |   | 2,982 |   | 32 |   |
| $35.00 to $39.99 |       | 59                           |       | 36                                         |       | 3 |   | 20 |   | 37 |   |
| $40.00 to $44.99 |       | 6                            |       | 40                                         |       | 4 |   | — |   | — |   |
| **Total**        | ** ** | **24,622**                   |       |                                       |       |   | ** ** | **17,087** |   |   |   |

 

110

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**(d)    Stockappreciation rights**

 

OurStARs plan entitles employees to cash payments equal to the excess of themarket price of the common shares over the exercise price of the right. Thefollowing stock appreciation rights have been granted:

 
| ** **                            | ** ** | **2008**               | ** ** | **2007**                                             | ** ** | **2006**               | ** ** |
|---------------------------------------|------------|------------------------|------------|------------------------------------------------------|------------|------------------------|------------|
| **(thousands of shares)**   | ** ** | **StARs  (thousands)** | ** ** | **Weighted  Average  Exercise Price  ($/StAR)** | ** ** | **StARs  (thousands)** | ** ** | **Weighted  Average  Exercise Price  ($/StAR)** | ** ** | **StARs  (thousands)** | ** ** | **Weighted  Average  Exercise Price  ($/StAR)** | ** ** |
| Outstanding StARs,  Beginning of Year |       | 15,435                 |       | 24                                                   |       | 13,890                 |       | 21 |   | 11,928 |   | 15 |   |
| Granted                               |       | 4,917                  |       | 19                                                   |       | 4,195                  |       | 29 |   | 4,509 |   | 32 |   |
| Exercised for Cash                    |       | (2,837                 | )          | 15                                                   |       | (2,349                 | )          | 12 |   | (2,165 | ) | 10 |   |
| Cancelled                             |       | (529                   | )          | 31                                                   |       | (301                   | )          | 26 |   | (382 | ) | 19 |   |
| Expired                               |       | —                 |       | —                                               |       | —                 |       | — |   | — |   | — |   |
| **End of  Year**                      | ** ** | **16,986**             | ** ** | **25**                                               | ** ** | **15,435**             | ** ** | **24** | ** ** | **13,890** | ** ** | **21** | ** ** |
| ** **                            | ** ** | ** **             | ** ** | ** **                                           | ** ** | ** **             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| StARs Exercisable at End  of Year     |       | 8,119                  |       | 25                                                   |       | 7,525                  |       | 19 |   | 6,151 |   | 13 |   |

 

The range of exercise pricesof StARs outstanding and exercisable at December 31, 2008 is as follows:

 
| ** **       | ** ** | **Outstanding StARs**             | ** ** | **Exercisable StARs**                           | ** ** |
|------------------|------------|----------------------------------------|------------|------------------------------------------------------|------------|
| ** **       | ** ** | **Number of  StARs  (thousands)** | ** ** | **Weighted  Average  Exercise Price  ($/StAR)** | ** ** | **Weighted  Average Years  to Expiry  (years)** | ** ** | **Number of  StARs  (thousands)** | ** ** | **Weighted  Average  Exercise Price  ($/StAR)** | ** ** |
| $5.00 to $9.99   |       | 138                                    |       | 8                                                    |       | 2 |   | 138 |   | 8 |   |
| $10.00 to $14.99 |       | 1,978                                  |       | 13                                                   |       | 1 |   | 1,978 |   | 13 |   |
| $15.00 to $19.99 |       | 4,866                                  |       | 19                                                   |       | 5 |   | 33 |   | 17 |   |
| $20.00 to $24.99 |       | 70                                     |       | 23                                                   |       | 2 |   | 63 |   | 23 |   |
| $25.00 to $29.99 |       | 5,340                                  |       | 28                                                   |       | 3 |   | 3,149 |   | 28 |   |
| $30.00 to $34.99 |       | 4,489                                  |       | 32                                                   |       | 3 |   | 2,740 |   | 32 |   |
| $35.00 to $39.99 |       | 77                                     |       | 37                                                   |       | 4 |   | 18 |   | 37 |   |
| $40.00 to $44.99 |       | 19                                     |       | 44                                                   |       | 4 |   | — |   | — |   |
| $45.00 to $49.99 |       | 9                                      |       | 47                                                   |       | 4 |   | — |   | — |   |
| **Total**        | ** ** | **16,986**                             | ** ** | ** **                                           |       |   |   | **8,119** |   |   |   |

 

**16.   COMMITMENTS,CONTINGENCIES AND GUARANTEES**

 

We assume variouscontractual obligations and commitments in the normal course of our operations.Our operating leases and transportation, storage and drilling rig commitmentsas at December 31, 2008 comprise of the following:

 
| ** **                              | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** | **2013** | ** ** | **Thereafter** | ** ** |
|-----------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|
| Operating Leases                        |       | 91       |       | 115      |       | 109      |       | 105      |       | 100      |       | 195            |       |
| Transportation and Storage  Commitments |       | 379      |       | 235      |       | 176      |       | 150      |       | 117      |       | 204            |       |
| Drilling Rig Commitments                |       | 408      |       | 442      |       | 455      |       | 329      |       | 130      |       | 10             |       |

 

We have a number of lawsuitsand claims pending including income tax reassessments (see Note 18), for whichwe currently cannot determine the ultimate result. We record costs as they areincurred or become determinable. We believe the resolution of these matterswould not have a material adverse effect on our liquidity, consolidatedfinancial position or results of operations.

 

During 2008, total rentalexpense under operating leases was $59 million (2007—$53 million; 2006—$49million).

 

From time to time, we enterinto certain types of contracts that require us to indemnify parties againstpossible third-party claims, particularly when these contracts relate todivestiture transactions. On occasion, we may provide routine indemnifications.The terms of such obligations vary, and generally, a maximum is not explicitlystated. Because the obligations in these agreements are often not explicitlystated, the overall maximum amount of the obligations cannot be reasonablyestimated. Historically, we have not been obligated to make significantpayments for these obligations. We believe that payments, if any, related toexisting indemnities, would not have a material adverse effect on ourliquidity, financial condition or results of operations.

 

111

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**17.   MARKETING AND OTHER INCOME**

 
| ** **                                     | ** ** | **2008** | ** ** | **2007**  | ** ** | **2006**  | ** ** |
|------------------------------------------------|------------|----------|------------|-----------|------------|-----------|------------|
| Marketing Revenue, Net                         |       | 467      |       | 959       |       | 1,309     |       |
| Business Interruption  Insurance Proceeds (1)  |       | —   |       | —    |       | 154       |       |
| Change in Fair Value of  Crude Oil Put Options |       | 203      |       | (43       | )          | (11       | )          |
| Interest                                       |       | 28       |       | 39        |       | 36        |       |
| Foreign Exchange Gains  (Losses)               |       | 128      |       | (22       | )          | (72       | )          |
| Gains on Disposition of  Assets                |       | 3        |       | 2         |       | 4         |       |
| Other                                          |       | (16      | )          | 86        |       | 30        |       |
| **Total**                                      | ** ** | **813**  | ** ** | **1,021** | ** ** | **1,450** | ** ** |

 

----

*(1)**      **In 2006, we received business interruption insuranceproceeds related to production losses caused by Gulf of Mexico hurricanes in2005 and by generator failures in our UK operations in 2005.*

 

**18.   INCOMETAXES**

 

**(a)    Temporary differences**

 
| ** **                          | ** ** | **2008**                            | ** ** | **2007**                                 | ** ** |
|-------------------------------------|------------|-------------------------------------|------------|------------------------------------------|------------|
| ** **                          | ** ** | **Future  Income Tax  Assets** | ** ** | **Future  Income Tax  Liabilities** | ** ** | **Future  Income Tax  Assets (1)** | ** ** | **Future  Income Tax  Liabilities** | ** ** |
| Property, Plant and  Equipment, Net |       | 27                                  |       | 2,543                                    |       | 25 |   | 2,229 |   |
| Tax Losses Carried Forward          |       | 300                                 |       | —                                   |       | 256 |   | — |   |
| Deferred Income                     |       | —                              |       | 76                                       |       | — |   | 61 |   |
| Recoverable Taxes                   |       | 24                                  |       | —                                   |       | 5 |   | — |   |
| **Total**                           | ** ** | **351**                             | ** ** | **2,619**                                | ** ** | **286** | ** ** | **2,290** | ** ** |

 

----

*(1)**      **In 2007, future income tax assets of $18 million that weexpected to realize in the following twelve months were included in othercurrent assets.*

 

**(b)    Canadian and foreign income taxes**

 
| ** **                             | ** ** | **2008**  | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------------------|------------|-----------|------------|----------|------------|----------|------------|
| **Income  (Loss) before Income Taxes** |       |      |       |     |       |     |       |
| Canadian                               |       | (100      | )          | (33      | )          | (352     | )          |
| Foreign                                |       | 3,268     |       | 1,929    |       | 1,648    |       |
|                                   |       | 3,168     |       | 1,896    |       | 1,296    |       |
| **Provision  for Income Taxes**        |       |      |       |     |       |     |       |
| Current                                |       |      |       |     |       |     |       |
| Canadian                               |       | 1         |       | 1        |       | 14       |       |
| Foreign                                |       | 858       |       | 433      |       | 354      |       |
|                                   |       | 859       |       | 434      |       | 368      |       |
| Future                                 |       |      |       |     |       |     |       |
| Canadian                               |       | 22        |       | 12       |       | (96      | )          |
| Foreign                                |       | 576       |       | 346      |       | 411      |       |
|                                   |       | 598       |       | 358      |       | 315      |       |
| **Total**                              | ** ** | **1,457** | ** ** | **792**  | ** ** | **683**  | ** ** |

 

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, the UK,the US and Norway.

 

112

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**(c)    Reconciliation of effective tax rate to theCanadian statutory tax rate**

 
| ** **                                                          | ** ** | **2008**  | ** ** | **2007** | ** ** | **2006** | ** ** |
|---------------------------------------------------------------------|------------|-----------|------------|----------|------------|----------|------------|
| Income before Provision  for Income Taxes                           |       | 3,168     |       | 1,896    |       | 1,296    |       |
|                                                                |       |      |       |     |       |     |       |
| Provision for Income Taxes  Computed at the Canadian Statutory Rate |       | 893       |       | 537      |       | 401      |       |
| Add (Deduct) the Tax  Effect of:                                    |       |      |       |     |       |     |       |
| Royalties, Rentals and  Similar Payments to Provincial Governments  |       | —    |       | —   |       | 15       |       |
| Resource Allowance and  Provincial Tax Rebates                      |       | —    |       | —   |       | (15      | )          |
| Foreign Tax Rate  Differential                                      |       | 525       |       | 233      |       | (9       | )          |
| Additional Canadian Tax on  Canadian Resource Income                |       | —    |       | —   |       | 10       |       |
| Higher (Lower) Tax Rates  on Capital Gains                          |       | 9         |       | (5       | )          | (3       | )          |
| Federal and Provincial  Capital Tax                                 |       | 2         |       | 1        |       | 13       |       |
| Effect of Changes in Tax  Rates                                     |       | —    |       | (15      | )          | 245      |       |
| Non-Deductible Expenses  and Other                                  |       | 28        |       | 41       |       | 26       |       |
| **Provision  for Income Taxes**                                     | ** ** | **1,457** | ** ** | **792**  | ** ** | **683**  | ** ** |
| **Effective  Tax Rate**                                             | ** ** | **46**    | **%**      | **42**   | **%**      | **53**   | **%**      |

 

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 government and some provincial governments in Canada reduced statutorycorporate income tax rates. This reduced our liability and provision for futureincome taxes by $15 million in 2007 and $32 million in 2006.

 

**(d)    Available unused tax losses and taxcontingencies**

 

At December 31, 2008, we hadunused tax losses totalling $954 million (2007—$820 million; 2006—$1,258million). The majority of these losses are in Canada and the US and will expirebetween 2016 and 2028.

 

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 appropriate provision for income taxes based on available information.

 

**19.   EARNINGS PER COMMON SHARE**

 

We calculate basic earningsper common share using net income divided by the weighted-average number ofcommon shares outstanding. We calculate diluted earnings per common share inthe same manner as basic, except we use the weighted-average number of dilutedcommon shares outstanding in the denominator.

 
| **(millions of shares)**                                 | ** ** | **2008**  | ** ** | **2007**  | ** ** | **2006**  | ** ** |
|--------------------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Weighted-Average Number of  Common Shares, Basic                   |       | 526.1     |       | 527.1     |       | 524.2     |       |
| Shares Issuable Pursuant  to Tandem Options                        |       | 18.8      |       | 26.6      |       | 27.7      |       |
| Shares to be Notionally  Purchased from Proceeds of Tandem Options |       | (12.7     | )          | (15.7     | )          | (14.0     | )          |
| **Weighted-Average  Number of Common Shares, Diluted**             | ** ** | **532.2** | ** ** | **538.0** | ** ** | **537.9** | ** ** |

 

In calculating theweighted-average number of diluted common shares outstanding for the year endedDecember 31, 2008, we excluded 5,694,055 tandem options (2007—49,333;2006—422,566), because their exercise price was greater than the annual averagecommon share market price in those periods. During the last three years,outstanding tandem options were the only potential dilutive instruments.

 

113

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**20.   CASH FLOWS**

 

**(a)    Charges and credits to income not involvingcash**

 
| ** **                                                   | ** ** | **2008**  | ** ** | **2007**  | ** ** | **2006**  | ** ** |
|--------------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Depreciation, Depletion,  Amortization and Impairment        |       | 2,014     |       | 1,767     |       | 1,124     |       |
| Stock-Based Compensation                                     |       | (272      | )          | (109      | )          | 101       |       |
| Gains on Disposition of  Assets                              |       | (3        | )          | (2        | )          | (4        | )          |
| Provision for Future  Income Taxes                           |       | 598       |       | 358       |       | 315       |       |
| Change in Fair Value of  Crude Oil Put Options               |       | (203      | )          | 43        |       | 11        |       |
| Net (Loss) Income Attributable  to Non-Controlling Interests |       | (4        | )          | 18        |       | 12        |       |
| Other                                                        |       | 6         |       | (2        | )          | 70        |       |
| **Total**                                                    | ** ** | **2,136** | ** ** | **2,073** | ** ** | **1,629** | ** ** |

 

**(b)    Changes in non-cash working capital**

 
| ** **                                | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|-------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Accounts Receivable                       |       | 950        |       | (797       | )          | 345        |       |
| Inventories and Supplies                  |       | 246        |       | (97        | )          | (302       | )          |
| Other Current Assets                      |       | 5          |       | (15        | )          | (14        | )          |
| Accounts Payable and  Accrued Liabilities |       | (1,232     | )          | 691        |       | (72        | )          |
| Other                                     |       | 26         |       | —     |       | —     |       |
| **Total**                                 | ** ** | **(5**     | **)**      | **(218**   | **)**      | **(43**    | **)**      |
| ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Relating to:                              |       |       |       |       |       |       |       |
| Operating Activities                      |       | 119        |       | (348       | )          | (177       | )          |
| Investing Activities                      |       | (124       | )          | 130        |       | 134        |       |
| **Total**                                 | ** ** | **(5**     | **)**      | **(218**   | **)**      | **(43**    | **)**      |

 

**(c)    Other cash flow information**

 
| ** **        | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|-------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest Paid     |       | 319      |       | 328      |       | 278      |       |
| Income Taxes Paid |       | 1,055    |       | 408      |       | 398      |       |

 

Cash flow from otheroperating activities includes cash outflows related to geological andgeophysical expenditures of $137 million (2007—$123 million; 2006—$128million).

 

**21.   SUBSEQUENT EVENT**

 

In January 2009, wecompleted the acquisition of an additional 15% interest in the Long LakeProject and the joint venture lands for $735 million.

 

**22.   OPERATING SEGMENTS AND RELATED INFORMATION**

 

Nexen has the followingoperating segments in various industries and geographic locations:

 

**Oil and Gas:** 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,offshore West Africa and Norway.

 

**Energy Marketing:** Our energy marketing group sells our crudeoil and natural gas, markets third-party crude oil, natural gas, NGLs and power(including electricity generation) and engages in energy trading.

 

**Syncrude:** We own 7.23% of the Syncrude Joint Venture, which develops andproduces synthetic crude oil from mining bitumen in the Athabasca oil sands innorthern Alberta.

 

114

----

 

**Chemicals:** Through our investment in Canexus, we manufacture, market anddistribute industrial chemicals, principally sodium chlorate, chlorine,muriatic acid and caustic soda. We produce sodium chlorate at four facilitiesin Canada and one in Brazil. We produce chlorine, caustic soda and muriaticacid at chlor-alkali facilities in Canada and Brazil.

 

The accounting policies of our operating segments are the same as thosedescribed in Note 1. Net income of our operating segments excludes interestincome, interest expense, unallocated corporate expenses and foreign exchangegains and losses with the exception of Chemicals. Identifiable assets are thoseused in the operations of the segments.

 

**2008Operating 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)                                               |       | 1,093                     |       | 656        |       | 665        |       | 3,580      |       | 192                     |       | 70                    |       | 691 | ** ** | 477 | (3) | — |   | 7,424 |   |
| Marketing and Other                                        |       | 12                        |       | 3          |       | 4          |       | 5          |       | —                  |       | 467                   |       | 6 |   | (50 | ) | 366 | (4) | 813 |   |
|                                                       |       | 1,105                     |       | 659        |       | 669        |       | 3,585      |       | 192                     |       | 537                   |       | 697 |   | 427 |   | 366 |   | 8,237 |   |
| Less: Expenses                                             |       |                      |       |       |       |       |       |       |       |                    |       |                  |       |   |   |   |   |   |   |   |   |
| Operating                                                  |       | 176                       |       | 182        |       | 94         |       | 253        |       | 10                      |       | 43                    |       | 280 |   | 297 |   | — |   | 1,335 |   |
| Depreciation, Depletion, Amortization and Impairments  (5) |       | 160                       |       | 208        |       | 475        |       | 999        |       | 17                      |       | 19                    |       | 49 |   | 44 |   | 43 |   | 2,014 |   |
| Transportation and Other                                   |       | 9                         |       | 12         |       | 3          |       | 19         |       | —                  |       | 805                   |       | 16 |   | 55 |   | 48 |   | 967 |   |
| General and  Administrative(6)                             |       | (7                        | )          | 20         |       | 38         |       | (8         | )          | 13                      |       | 79                    |       | 1 |   | 33 |   | 88 |   | 257 |   |
| Exploration                                                |       | 5                         |       | 79         |       | 109        |       | 86         | ** ** | 123                     | (7)        | —                |       | — |   | — |   | — |   | 402 |   |
| Interest                                                   |       | —                    |       | —     |       | —     |       | —     |       | —                  |       | —                |       | — |   | 12 |   | 82 |   | 94 |   |
|                                                       |       |                      |       |       |       |       |       |       |       |                    |       |                  |       |   |   |   |   |   |   |   |   |
| Income (Loss) before Income Taxes                          |       | 762                       |       | 158        |       | (50        | )          | 2,236      |       | 29                      |       | (409                  | )          | 351 |   | (14 | ) | 105 |   | 3,168 |   |
| Less: Provision for (Recovery of) Income Taxes(8)          |       | 264                       |       | 45         |       | (19        | )          | 1,126      |       | (4)                     |       | (102                  | )          | 99 |   | 2 |   | 46 |   | 1,457 |   |
| Net Income (Loss)                                          |       | 498                       |       | 113        |       | (31        | )          | 1,110      |       | 33                      |       | (307                  | )          | 252 |   | (16 | ) | 59 |   | 1,711 |   |
| Non-Controlling Interests                                  |       | —                    |       | —     |       | —     |       | —     |       | —                  |       | —                |       | — |   | (4 | ) | — |   | (4 | ) |
| **Net Income (Loss)**                                      | ** ** | **498**                   | ** ** | **113**    | ** ** | **(31**    | **)**      | **1,110**  | ** ** | **33**                  | ** ** | **(307**              | **)**      | **252** | ** ** | **(12** | **)** | **59** | ** ** | **1,715** | ** ** |
| ** **                                                 | ** ** | ** **                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **              | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Identifiable Assets**                                    | ** ** | **342**                   | ** ** | **6,643**  | **(9)**    | **2,044**  | ** ** | **6,632**  | ** ** | **701**                 | ** ** | **3,280**             | **(10)**   | **1,198** | ** ** | **573** | ** ** | **742** | ** ** | **22,155** | ** ** |
|                                                       |       |                      |       |       |       |       |       |       |       |                    |       |                  |       |   |   |   |   |   |   |   |   |
| Capital Expenditures   Development and Other          |       | 92                        |       | 1,180      |       | 251        |       | 545        |       | 190                     |       | 8                     |       | 55 |   | 88 |   | 53 |   | 2,462 |   |
| Exploration                                                |       | 9                         |       | 225        |       | 154        |       | 146        |       | 48                      |       | —                |       | — |   | — |   | — |   | 582 |   |
| Proved Property Acquisitions                               |       | —                    |       | 22         |       | —     |       | —     |       | —                  |       | —                |       | — |   | — |   | — |   | 22 |   |
| **Total**                                                  | ** ** | **101**                   | ** ** | **1,427**  | ** ** | **405**    | ** ** | **691**    | ** ** | **238**                 | ** ** | **8**                 | ** ** | **55** | ** ** | **88** | ** ** | **53** | ** ** | **3,066** | ** ** |
| PP&E                                                   |       |                      |       |       |       |       |       |       |       |                    |       |                  |       |   |   |   |   |   |   |   |   |
| Cost                                                       |       | 2,808                     |       | 8,134      |       | 4,398      |       | 6,532      |       | 554                     |       | 246                   |       | 1,372 |   | 940 |   | 331 |   | 25,315 |   |
| Less: Accumulated DD&A                                 |       | 2,610                     |       | 1,786      |       | 2,702      |       | 2,159      |       | 113                     |       | 76                    |       | 236 |   | 507 |   | 204 |   | 10,393 |   |
| **Net Book Value(2)**                                      | ** ** | **198**                   | ** ** | **6,348**  | **(9)**    | **1,696**  | ** ** | **4,373**  | ** ** | **441**                 | ** ** | **170**               | ** ** | **1,136** | ** ** | **433** | ** ** | **127** | ** ** | **14,922** | ** ** |
| ** **                                                 | ** ** | ** **                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **              | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Goodwill**                                               | ** ** | **—**                | ** ** | **—** | ** ** | **—** | ** ** | **341**    | ** ** | **—**              | ** ** | **49**                | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **390** | ** ** |

 

----

* *
| *(1)*    | *Includes  results of operations from producing activities in Colombia.*                                                                                                                                                                                               |
|----------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)*    | *Net  sales made from all segments originating in Canada:  PP&E located in Canada:*                                                                                                                                                                                | *1,570  8,121* |   |   |
| *(3)*    | *Net  sales for our chemicals operations include:*                                                                                                                                                                                                                     | * * | * * | * * |
| * * | *Canada*                                                                                                                                                                                                                                                               | *153* | * * | * * |
| * * | *US*                                                                                                                                                                                                                                                                   | *214* | * * | * * |
| * * | *Brazil*                                                                                                                                                                                                                                                               | *110* | * * | * * |
| * * | ***Total***                                                                                                                                                                                                                                                            | ***477*** | * * | * * |
| * * | *** ***                                                                                                                                                                                                                                                           | *** *** | * * | * * |
| *(4)*    | *Includes  interest income of $28 million, foreign exchange gains of $128 million,  increase in the fair value of crude oil put options of $203 million and other  income of $7 million.*                                                                              |
| *(5)*    | *Includes  an impairment charge related to oil and gas properties in the UK North Sea  and the US Gulf of Mexico of $318 million and $250 million, respectively.*                                                                                                      |
| *(6)*    | *Includes  recovery of stock-based compensation expense of $160 million.*                                                                                                                                                                                              |
| *(7)*    | *Includes  exploration activities primarily in 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 $4,742 million related to our insitu oil sands (Long Lake and future  phases).*                                                                                                                                                                    |
| *(10)*   | *79% of  Marketing’s identifiable assets are accounts receivable and inventories.*                                                                                                                                                                                |

* *

115

----

 

**2007Operating 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)                                         |       | 1,086                     |       | 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) 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)                                    |       | 457                       |       | 6          |       | (196       | )          | 729        |       | 1                       |       | 46                    |       | 191 |   | 46 |   | (176 | ) | 1,104 |   |
| 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**                                            | ** ** | **136**                   | ** ** | **1,505**  | ** ** | **793**    | ** ** | **716**    | ** ** | **97**                  | ** ** | **4**                 | ** ** | **36** | ** ** | **62** | ** ** | **52** | ** ** | **3,401** | ** ** |
| ** **                                           | ** ** | ** **                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **              | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| PP&E                                             |       |                      |       |       | ** ** |       |       |       |       |                    |       |                  |       |   |   |   |   |   |   |   |   |
| 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** | ** ** |

 

----

| *(1)*    | *Includes results of operations from producing  activities in Colombia.*                                                                                                                                                                                               |
|----------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)*    | *Net sales made from all segments originating in  Canada:  PP&E located in Canada:*                                                                                                                                                                                | *1,188  6,893* | * * | * * |
| *(3)*    | *Net  sales for our chemicals operations include:*                                                                                                                                                                                                                     | *** *** | * * | * * |
| * * | *Canada*                                                                                                                                                                                                                                                               | *154* | * * | * * |
| * * | *US*                                                                                                                                                                                                                                                                   | *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 insitu oil sands (Long Lake and future  phases).*                                                                                                                                                                    |
| *(10)*   | *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.*                                                                                                                                                                                       |

 

116

----

 

**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) 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)                                         |       | 542                       |       | 15         |       | 23         |       | (172       | )          | 4                             |       | 265                   |       | 141 |   | 29 |   | (234 | ) | 613 |   |
| 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**                                                 | ** ** | **182**                   | ** ** | **1,609**  | ** ** | **595**    | ** ** | **659**    | ** ** | **80**                        | ** ** | **47**                | ** ** | **86** | ** ** | **27** | ** ** | **45** | ** ** | **3,330** | ** ** |
|                                                      |       |                      |       |       |       |       |       |       |       |                          |       |                  |       |   |   |   |   |   |   |   |   |
| PP&E                                                  |       |                      |       |       |       |       |       |       |       |                          |       |                  |       |   |   |   |   |   |   |   |   |
| 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** | ** ** |

 

----

 
| *(1)*    | *Includes results of operations from producing  activities in Colombia.*                                                                                                                                                                                               |
|----------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)*    | *Net sales made from all segments originating in  Canada:  PP&E located in Canada:*                                                                                                                                                                                | *1,095  5,483* | * * | * * |
| *(3)*    | *Net  sales for our chemicals operations include:*                                                                                                                                                                                                                     | * * | * * | * * |
| * * | *Canada*                                                                                                                                                                                                                                                               | *139* | * * | * * |
| * * | *US*                                                                                                                                                                                                                                                                   | *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 insitu oil sands (Long Lake and future  phases).*                                                                                                                                                                    |
| *(14)*   | *80% of  Marketing’s identifiable assets are accounts receivable and inventories.*                                                                                                                                                                                |

 

117

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**23.   DIFFERENCESBETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES**

 

The Consolidated FinancialStatements have been prepared in accordance with Canadian GAAP. US GAAPConsolidated Financial Statements and summaries of differences from CanadianGAAP are as follows:

 

**ConsolidatedStatement of Income — US GAAPFor the Three Years ended December 31, 2008**

 
| **(Cdn$ millions, except per share amounts)** | ** ** | **2008**   | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Revenues and Other Income                                              |       |       |       |       |       |       |       |
| Net Sales                                                              |       | 7,424      |       | 5,583      |       | 3,936      |       |
| Marketing and Other (i);  (vi); (vii)                                  |       | 796        |       | 938        |       | 1,459      |       |
|                                                                   |       | 8,220      |       | 6,521      |       | 5,395      |       |
| Expenses                                                               |       |       |       |       |       |       |       |
| Operating (ii)                                                         |       | 1,335      |       | 1,167      |       | 958        |       |
| Depreciation, Depletion,  Amortization and Impairment                  |       | 2,014      |       | 1,767      |       | 1,124      |       |
| Transportation and Other  (vi)                                         |       | 964        |       | 906        |       | 1,037      |       |
| General and Administrative  (v)                                        |       | 263        |       | 401        |       | 597        |       |
| Exploration                                                            |       | 402        |       | 326        |       | 362        |       |
| Interest                                                               |       | 94         |       | 168        |       | 53         |       |
|                                                                   |       | 5,072      |       | 4,735      |       | 4,131      |       |
|                                                                   |       |       |       |       |       |       |       |
| Income before Provision  for Income Taxes                              |       | 3,148      |       | 1,786      |       | 1,264      |       |
| Provision for Income Taxes                                             |       |       |       |       |       |       |       |
| Current                                                                |       | 859        |       | 434        |       | 368        |       |
| Deferred (i); (ii); (v);  (vii)                                        |       | 589        |       | 322        |       | 305        |       |
|                                                                   |       | 1,448      |       | 756        |       | 673        |       |
|                                                                   |       |       |       |       |       |       |       |
| Net Income before  Non-Controlling Interests                           |       | 1,700      |       | 1,030      |       | 591        |       |
| Net Income (Loss)  Attributable to Non-Controlling Interests           |       | (4         | )          | 18         |       | 12         |       |
| **Net Income — US GAAP(1)**                                       | ** ** | **1,704**  | ** ** | **1,012**  | ** ** | **579**    | ** ** |
| **Earnings Per Common Share**($/share) (Note  19)                      | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic                                                                  |       | 3.24       |       | 1.92       |       | 1.10       |       |
| Diluted                                                                |       | 3.20       |       | 1.88       |       | 1.08       |       |

 

----

*(1)  Reconciliation of Canadian and US GAAPNet Income*

 
| **(Cdn$ millions)**                         | ** **   | **2008**    | ** **   | **2007**    | ** **   | **2006**  | ** **   |
|--------------------------------------------------|--------------|-------------|--------------|-------------|--------------|-----------|--------------|
| *Net Income — Canadian GAAP*                | * *     | *1,715*     | * *     | *1,086*     | * *     | *601*     | * *     |
| *Impact of US Principles, Net of Income  Taxes:* |         |        |         |        |         |      |         |
| *Ineffective Portion of Cash Flow Hedges (i)*    | * *     | *—*    | * *     | *(2*        | *)*          | *9*       | * *     |
| *Pre-operating Costs (ii)*                       | * *     | *—*    | * *     | *(1*        | *)*          | *(2*      | *)*          |
| *Stock-based Compensation (v)*                   | * *     | *(4*        | *)*          | *(19*       | *)*          | *(29*     | *)*          |
| *Inventory Valuation (vii)*                      | * *     | *(7*        | *)*          | *(52*       | *)*          | *—*  | * *     |
| ***Net Income — US GAAP***                  | *** *** | ***1,704*** | *** *** | ***1,012*** | *** *** | ***579*** | *** *** |

 

118

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**ConsolidatedBalance Sheet — US GAAPDecember 31, 2008 and 2007**

 
| **(Cdn$ millions, except share amounts)**                                                                          | ** **                                                       | **2008**   | ** ** | **2007**   | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------|------------------------------------------------------------------|------------|------------|------------|------------|
| **ASSETS******                                                                                                                         |                                                             |       |       |       |       |
| Current Assets                                                                                                                         |                                                             |       |       |       |       |
| Cash and Cash Equivalents                                                                                                              |                                                             | 2,003      |       | 206        |       |
| Restricted Cash                                                                                                                        |                                                             | 103        |       | 203        |       |
| Accounts Receivable                                                                                                                    |                                                             | 3,163      |       | 3,502      |       |
| Inventories and Supplies (vii)                                                                                                         |                                                             | 426        |       | 615        |       |
| Other                                                                                                                                  |                                                             | 169        |       | 89         |       |
| Total Current Assets                                                                                                                   |                                                             | 5,864      |       | 4,615      |       |
| Property, Plant and Equipment                                                                                                     |                                                             |       |       |       |       |
| Net of Accumulated Depreciation, Depletion,  Amortization and Impairment of $10,786 (December 31, 2007 — $7,588)  (ii); (iv) |                                                             | 14,873     |       | 12,449     |       |
| Goodwill                                                                                                                               |                                                             | 390        |       | 326        |       |
| Deferred Income Tax Assets                                                                                                             |                                                             | 351        |       | 268        |       |
| Deferred Charges and Other Assets                                                                                                      |                                                             | 570        |       | 324        |       |
|                                                                                                                                   |                                                             |       |       |       |       |
| **TOTAL ASSETS**                                                                                                                       | ** **                                                       | **22,048** | ** ** | **17,982** | ** ** |
| **LIABILITIES AND SHAREHOLDERS’ EQUITY**                                                                                          |                                                             |       |       |       |       |
| Current Liabilities                                                                                                                    |                                                             |       |       |       |       |
| Accounts Payable and Accrued Liabilities  (v)                                                                                          |                                                             | 3,384      |       | 4,233      |       |
| Accrued Interest Payable                                                                                                               |                                                             | 67         |       | 54         |       |
| Dividends Payable                                                                                                                      |                                                             | 26         |       | 13         |       |
| Total Current Liabilities                                                                                                              |                                                             | 3,477      |       | 4,300      |       |
|                                                                                                                                   |                                                             |       |       |       |       |
| Long-Term Debt                                                                                                                         |                                                             | 6,578      |       | 4,610      |       |
| Deferred Income Tax Liabilities (ii);  (iii); (v); (vii); (viii)                                                                       |                                                             | 2,543      |       | 2,230      |       |
| Asset Retirement Obligations                                                                                                           |                                                             | 1,024      |       | 792        |       |
| Deferred Credits and Other Liabilities  (iii)                                                                                          |                                                             | 1,428      |       | 534        |       |
| Non-Controlling Interests                                                                                                              |                                                             | 52         |       | 67         |       |
|                                                                                                                                   |                                                             |       |       |       |       |
| Shareholders’ Equity                                                                                                              |                                                             |       |       |       |       |
| Common Shares, no par value                                                                                                            |                                                             |       |       |       |       |
| Authorized:                                                                                                                            | Unlimited                                                        |       |       |       |       |   |
| Outstanding:                                                                                                                           | 2008 —  519,448,590 shares   2007 — 528,304,813 shares |       | 981        |       | 917        |   |
| Contributed Surplus                                                                                                                    |                                                             | 2          |       | 3          |       |
| Retained Earnings (i)—(v); (vii); (viii)                                                                                          |                                                             | 6,172      |       | 4,876      |       |
| Accumulated Other Comprehensive Loss (i);  (iii)                                                                                       |                                                             | (209       | )          | (347       | )          |
| Total Shareholders’ Equity                                                                                                        |                                                             | 6,946      |       | 5,449      |       |
| Commitments, Contingencies and Guarantees  (Notes 16 and 18)                                                                           |                                                             |       |       |       |       |
| **TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY**                                                                                    | ** **                                                       | **22,048** | ** ** | **17,982** | ** ** |

 

119

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**ConsolidatedStatement of Comprehensive Income — US GAAP**

**For theThree Years ended December 31, 2008**

 
| **(Cdn$ millions)**                                 | ** ** | **2008**  | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------------------------------------|------------|-----------|------------|----------|------------|----------|------------|
| Net Income — US GAAP                                |       | 1,704     |       | 1,012    |       | 579      |       |
| Other Comprehensive Income (Loss), Net of  Income Taxes: |       |      |       |     |       |     |       |
| Foreign Currency Translation Adjustment                  |       | 159       |       | (132     | )          | —   |       |
| Change in Mark to Market on Cash Flow  Hedges (i)        |       | —    |       | (61      | )          | 77       |       |
| Minimum Unfunded Pension Liability (iii)                 |       | —    |       | —   |       | 5        |       |
| Unamortized Defined Benefit Pension Plan  Costs (iii)    |       | (21       | )          | 2        |       | —   |       |
| **Comprehensive Income**                                 | ** ** | **1,842** | ** ** | **821**  | ** ** | **661**  | ** ** |

 

**ConsolidatedStatement of Accumulated Other Comprehensive Loss — US GAAP**

**December 31,2008 and 2007**

 
| **(Cdn$ millions)**                              | ** ** | **2008** | ** ** | **2007** | ** ** |
|-------------------------------------------------------|------------|----------|------------|----------|------------|
| Foreign Currency Translation Adjustment               |       | (134     | )          | (293     | )          |
| Unamortized Defined Benefit Pension Plan  Costs (iii) |       | (75      | )          | (54      | )          |
| **Accumulated Other Comprehensive Loss (AOCL)**       | ** ** | **(209** | **)**      | **(347** | **)**      |

 

**Notes to the Consolidated US GAAP FinancialStatements:**

 
| i.     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | Under US GAAP, all  derivative instruments are recognized on the balance sheet as either an asset  or a liability measured at fair value. Changes in the fair value of  derivatives are recognized in earnings unless specific hedge criteria are  met. On January 1, 2007, we adopted the equivalent Canadian standard for  derivative instruments and hedging.     |
|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |                                                                                                                                                                                                                                                                                                                                                                      |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | Future sale of gas inventory:                                                                                                                                                                                                                                                                                                                                             |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |                                                                                                                                                                                                                                                                                                                                                                      |
|   | We use futures and swaps  as cash flow hedges against the commodity price risk on the future sale of  our gas inventory. Prior to January 1, 2007, we included the hedging  derivative contracts on our US GAAP Consolidated Balance Sheet with the  effective portion of gains or losses recognized in AOCI. The ineffective gain  or loss was included in marketing and other within the US GAAP net income  immediately.                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
|   | In 2005, we recognized $11  million ($7 million, net of income taxes) of ineffective losses related to  these hedges in our US GAAP net income. Under Canadian GAAP, these losses  were recognized in 2006.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |                                                                                                                                                                                                                                                                                                                                                                      |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | At December 31, 2006,  we included $25 million of gains on these cash flow hedges in accounts  receivable. AOCI includes the effective portion of $23 million ($16 million,  net of income taxes) and $2 million ($2 million, net of income taxes) of the  ineffective portion in our US GAAP net income. Under Canadian GAAP, these  gains were recognized in 2007. |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |                                                                                                                                                                                                                                                                                                                                                                      |
| ii.    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | Under Canadian GAAP, we  defer certain development costs and all pre-operating revenues and costs to  PP&E. Under US GAAP, these costs have been included in operating  expenses. As a result:                                                                                                                                                                        |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |                                                                                                                                                                                                                                                                                                                                                                      |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | ·                                                                                                                                                                                                                                                                                                                                                                    | in 2008, operating  expenses do not include any pre-operating costs (2007 — $2 million ($1  million, net of income taxes); 2006 — $3 million ($2 million, net of income  taxes)); and |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |                                                                                                                                                                                                                                                                                                                                                                      |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | ·                                                                                                                                                                                                                                                                                                                                                                    | PP&E is lower under US  GAAP by $30 million (December 31, 2007 — lower by $30 million) and  deferred income tax liabilities is $11 million lower (December 31, 2007  — lower by $11 million). |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |                                                                                                                                                                                                                                                                                                                                                                      |
| iii.   | On December 31, 2006,  we adopted FASB Statement No. 158 *Employers’  Accounting for Defined Benefit Pension and Other Postretirement Plans*  for US GAAP. This requires, among other things, the recognition of the  over-funded and under-funded status of a defined benefit plan on the balance  sheet as an asset or liability. At year end, the unfunded amount of our  defined benefit pension plans that was not included in the Pension Liability  under Canadian GAAP was $104 million (2007 — $75 million). This amount has  been included in deferred credits and other liabilities and $75 million, net  of income taxes, (2007 — $54 million, net of income taxes), has been included  in AOCI. Prior to the adoption of FAS 158 on December 31, 2006, we  included our minimum unfunded pension liability in our US GAAP Consolidated  Balance Sheet. |

 

120

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| iv.    | On January 1, 2003,  we adopted FASB Statement No. 143, *Accounting  for Asset Retirement Obligations*(FAS 143) for US GAAP reporting  purposes. We adopted the equivalent Canadian standard for asset retirement  obligations on January 1, 2004. These standards are consistent, except  for the adoption date, which resulted in our PP&E under US GAAP being  lower by $19 million.                                                                                                                                                                                                                                                                                                            |
|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| v.     | Under Canadian principles,  we record obligations for liability-based stock compensation plans using the  intrinsic-value method of accounting. Under US principles, obligations for  liability-based stock compensation plans are recorded using the fair-value  method of accounting. In addition, under Canadian principles, we  retroactively adopted EIC-162 which requires the accelerated recognition of  stock-based compensation expense for all stock-based awards made to our  retired and retirement-eligible employees. However, US GAAP requires the  accelerated recognition of stock-based compensation expense for such  employees for awards granted on or after January 1, 2006. As a result: |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |   |
|   | ·                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                | general and administrative  expense is higher by $6 million ($4 million, net of income taxes) for the  year ended December 31, 2008 (2007 — higher by $27 million ($19 million,  net of income taxes); 2006 — higher by $42 million ($29 million, net of  income taxes)); and |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |   |
|   | ·                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                | accounts payable and  accrued liabilities are higher by $58 million at December 31, 2008 (2007  — higher by $53 million) and deferred income tax liabilities are $17 million  lower (2007 — lower by $15 million). |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |   |
| vi.    | Under US GAAP, asset  disposition gains and losses are included with transportation and other  expense. Gains of $3 million were reclassified from marketing and other to  transportation and other (2007 — $2 million; 2006 — $4 million).                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| vii.   | Under Canadian GAAP, we  began carrying our commodity inventory held for trading purposes at fair  value, less any costs to sell effective October 1, 2007. Under US GAAP,  we are required to carry this inventory at the lower of cost or net  realizable value. As a result:                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|   | ·                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                | marketing and other is  lower by $14 million ($7 million, net of income taxes) for the year ended  December 31, 2008 (2007 lower by $79 million, ($52 million net of income  tax)); and |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |   |
|   | ·                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                | inventories are lower by  $58 million at December 31, 2008 (2007 — lower by $44 million) and  deferred income tax liabilities are $21 million lower (2007 — lower by $14  million). |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |   |
| viii.  | On January 1, 2007,  we adopted FASB Interpretation 48 *Accounting  for Uncertainty in Income Taxes*(FIN 48) regarding accounting and  disclosure for uncertain tax positions. On the adoption of FIN 48, we  recorded a cumulative effect of a change in accounting principle of $28  million. This amount increased our deferred income tax liabilities and  decreased our retained earnings as at January 1, 2007 in our US GAAP —  Consolidated Balance Sheet.                                                                                                                                                                                                                                     |

 
|   | As at December 31,  2008, the total amount of our unrecognized tax benefits was approximately  $249 million, all of which, if recognized, would affect our effective tax  rate. To the extent interest and penalties may be assessed by taxing  authorities on any underpayment of income tax, such amounts have been accrued  and are classified as a component of income taxes in the Consolidated  Statement of Income. As at December 31, 2008, the total amount of  interest and penalties related to uncertain tax positions recognized in  deferred income tax liabilities in the US GAAP — Consolidated Balance Sheet  was approximately $9 million. We had no interest or penalties included in the  US GAAP — Consolidated Statement of Income for the year ended  December 31, 2008. |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
|   | Our income tax filings are  subject to audit by taxation authorities and as at December 31, 2008 the  following tax years remained subject to examination, (i) Canada — 1985  to date, (ii) United Kingdom — 2007 to date and (iii) United States  — 2005 to date. We do not anticipate any material changes to the unrecognized  tax benefits previously disclosed within the next twelve months.                                                                                                                                                                                                                                                                                                                                                                                    |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
|   | **Reconciliation  of Unrecognized Tax Benefits**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |

 
|   |                                                     |
|--------|----------------------------------------------------------|
|   | **(Cdn$ millions)**                                 | ** ** | ** ** | ** ** |
|   | Balance at January 1, 2008                          |   | 221 |   |
|   | Additions for tax positions related to the  current year |   | 9 |   |
|   | Additions for tax positions related to  prior years      |   | 55 |   |
|   | Reductions for ta x positions related to  prior years    |   | (36 | ) |
|   | **Balance at December 31, 2008**                    | ** ** | **249** | ** ** |

 

121

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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, Accounting for Stock AppreciationRights and Other Variable Stock Option or Award Plans (the intrinsic-valuemethod). Accordingly, obligations were accrued on a graded vesting basis andrepresented the difference between the market value of our common shares andthe exercise price of underlying options and rights. Under Statement 123(R),obligations for liability-based stock compensation plans are measured at theirfair value and remeasured in each subsequent reporting period.

 

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

 

*Assumptions*

 

We use the GeneralizedBlack-Scholes option pricing model to estimate the fair value of ourstock-based compensation, with the following assumptions:

 
| Expected Annual Dividends per Common Share  ($/share)               |   | 0.20           |   |
|---------------------------------------------------------------------|--------|----------------|--------|
| Expected Volatility                                                 |   | 52%            |   |
| Risk-Free Interest Rate                                             |   | 1.0%–1.6% |   |
| Weighted-Average Expected Life of  Compensation Instruments (years) |   | 2.9–3.2   |   |

 

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. Ourvaluation methodology and assumptions are consistent with those previously usedunder FAS 123.

 

**Stock Options**

 
| ** **                                                  | ** ** | **Number****(thousands)** | ** ** | **Weighted  Average  Exercise Price  ($/option)** | ** ** | **Weighted  Average  Remaining  Term to Expiry  (years)** | ** ** | **Aggregate  Intrinsic Value  (Cdn$ millions)** | ** ** | **Weighted  Average  Fair Value  ($/option)** | ** ** |
|-------------------------------------------------------------|------------|---------------------------|------------|--------------------------------------------------------|------------|---------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|----------------------------------------------------|------------|
| Outstanding at December 31, 2008                       |       | 24,622                    |       | 22                                                     |       | 2.6                                                                 |       | 87                                                        |       | 6                                                  |       |
| Outstanding at December 31, 2008 and  Expected to Vest |       | 24,388                    |       | 22                                                     |       | 2.6                                                                 |       | 86                                                        |       | 6                                                  |       |
| Exercisable at December 31, 2008                       |       | 17,087                    |       | 21                                                     |       | 1.9                                                                 |       | 80                                                        |       | 6                                                  |       |

 

The total intrinsic value of stock options exercised during the yearended December 31, 2008 was $88 million (2007 — $149 million; 2006 — $109million). As at December 31, 2008, we had $34 million of unrecognizedcompensation expense related to stock options which we expect to recognize overa weighted-average period of 1.6 years.

 

122

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**Stock Appreciation Rights**

 
| ** **                                                  | ** ** | **Number****(thousands)** | ** ** | **Weighted  Average  Exercise Price  ($/right)** | ** ** | **Weighted  Average  Remaining  Term to Expiry  (years)** | ** ** | **Aggregate  Intrinsic Value  (Cdn$ millions)** | ** ** | **Weighted  Average  Fair Value  ($/right)** | ** ** |
|-------------------------------------------------------------|------------|---------------------------|------------|-------------------------------------------------------|------------|---------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|---------------------------------------------------|------------|
| Outstanding at December 31, 2008                       |       | 16,986                    |       | 25                                                    |       | 3.3                                                                 |       | 30                                                        |       | 5                                                 |       |
| Outstanding at December 31, 2008 and  Expected to Vest |       | 16,558                    |       | 25                                                    |       | 3.3                                                                 |       | 29                                                        |       | 5                                                 |       |
| Exercisable at December 31, 2008                       |       | 8,119                     |       | 25                                                    |       | 2.3                                                                 |       | 19                                                        |       | 4                                                 |       |

 

The total intrinsic value ofstock appreciation rights exercised during the year ended December 31,2008 was $52 million (2007 — $50 million; 2006 — $46 million). As atDecember 31, 2008, we had $42 million of unrecognized compensation expenserelated to stock appreciation rights which we expect to recognize over aweighted-average period of 1.6 years.

 

*Stock-Based Compensation Expense and Payments*

 

For the year endedDecember 31, 2008, stock-based compensation recovery of $154 million (2007— $65 million expense; 2006 — $252 million expense) was included in general andadministrative expense in the Consolidated Statement of Income — US GAAP.

 

For the year endedDecember 31, 2008, cash proceeds of $23 million were received related tothe exercise of stock options (2007 — $24 million; 2006 — $16 million). For theyear ended December 31, 2008, $121 million was paid related to theexercise of stock options and stock appreciation rights (2007 — $149 million;2006 — $119 million). The income tax benefit recorded from the exercise ofstock options and stock appreciation rights was $34 million (2007 — $42million; 2006 — $37 million) for the period.

 

*Stock-Based Compensation Expense for Retired andRetirement Eligible Employees*

 

We recognize stock-basedcompensation expense for our retired and retirement-eligible employees over anaccelerated graded vesting period in accordance with the provisions ofStatement 123(R) for stock-based awards granted to employees on or afterJanuary 1, 2006. For stock-based awards granted prior to the adoption ofStatement 123(R), stock-based compensation expense for our retired andretirement-eligible employees is recognized over a graded vesting period. If weapplied 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 $2 million for the year ended December 31, 2008 (2007 —$9 million; 2006 — $10 million).

 

**Changes in Accounting Policies — US GAAP**

 

Fair Value Measurements

 

On January 1, 2008, we adopted FASB Statement 157, *Fair Value Measurements*which defines fairvalue, establishes a framework for measuring fair value and expands disclosuresabout fair value measurements. The adoption of this statement did not have amaterial impact on our results of operations or financial position. Theadditional disclosures required by the statement are included in Note 7.

 

Pension

 

Effective December 31,2006, we adopted the recognition and disclosure provisions of FASB Statement158, *Employers’ Accounting for DefinedBenefit Pension and Other Post-retirement Plans.* This statement alsorequires measurement of the funded status of a plan as of the balance sheetdate. The measurement provisions of the statement are effective for fiscalyears ending after December 15, 2008. Effective December 31, 2008, weadopted the change in measurement date provision of FASB Statement 158. Thefunded status of our defined benefit pension plan is now as of the balancesheet date of December 31, 2008. The adoption of this change did not havea material impact on our results of operations or financial position.

 

123

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**New Accounting Pronouncements — US GAAP**

 

In December 2007, FASBissued Statement 141 (revised), *BusinessCombinations.* Statement 141 establishes principles and requirementsof the acquisition method for business combinations and related disclosures.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.

 

In December 2007, FASBissued Statement 160, *Non-controllingInterests In Consolidated Financial Statements,* an amendment of ARBNo. 51. This statement clarifies that a non-controlling interest in asubsidiary should be reported as equity in the consolidated financialstatements. 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.

 

In March 2008, FASBissued Statement 161, *Disclosures aboutDerivative Instruments and Hedging Activities,* an amendment of FASBStatement 133. The statement requires qualitative disclosures about theobjectives and strategies for using derivatives, quantitative data about thefair value of gains and losses on derivative contracts, and details ofcredit-risk-related contingent features in their hedged position. The statementalso requires the disclosure of the location and amounts of derivative instrumentsin the financial statements. This statement is effective for fiscal years andinterim periods beginning on or after November 15, 2008. We do not expectthe adoption of this statement to materially impact our results of operationsor financial position.

 

In December 2008, FASBissued FSP FAS 132 (R)-1, *Employers’Disclosures about Post-retirement Benefit Plan Assets* which providesguidance on disclosures about plan assets of a defined benefit pension or otherpost-retirement plans. This statement is effective for fiscal years endingafter December 15, 2009. We do not expect the adoption of this statementto materially impact our results of operations or financial position.

 

124

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**SUPPLEMENTARY DATA (UNAUDITED)**

 

**Quarterly Financial Data in Accordance with Canadianand US GAAP**

 
| ** **                                          | ** ** | **Quarter Ended** | ** ** |
|-----------------------------------------------------|------------|------------------------|------------|
| ** **                                          | ** ** | **March 31**      | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| **(Cdn$ millions)**                            | ** ** | **2008**               | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** |
| Net Sales                                           |       | 1,870                  |       | 1,140 |   | 2,071 |   | 1,399 |   | 2,213 |   | 1,446 |   | 1,270 |   | 1,598 |   |
|                                                |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Income (Loss) before Income Taxes is  Comprised of: |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Oil and Gas(1)                                      |       | 1,050                  |       | 303 |   | 976 |   | 604 |   | 1,364 |   | 642 |   | (255 | ) | 308 |   |
| Energy Marketing                                    |       | 14                     |       | (4 | ) | (183 | ) | 70 |   | (79 | ) | (4 | ) | (161 | ) | 5 |   |
| Syncrude                                            |       | 78                     |       | 54 |   | 97 |   | 48 |   | 139 |   | 88 |   | 37 |   | 76 |   |
| Chemicals                                           |       | (4                     | )          | 11 |   | 11 |   | 21 |   | 5 |   | 25 |   | (26 | ) | 7 |   |
| Corporate and Other                                 |       | (38                    | )          | (145 | ) | (208 | ) | (93 | ) | 77 |   | (63 | ) | 274 |   | (57 | ) |
| ** **                                          | ** ** | **1,100**              | ** ** | **219** | ** ** | **693** | ** ** | **650** | ** ** | **1,506** | ** ** | **688** | ** ** | **(131** | **)** | **339** |   |
| ** **                                          | ** ** | ** **             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Net Income (Loss)—Canadian GAAP**            | ** ** | **630**                | ** ** | **121** | ** ** | **380** | ** ** | **368** | ** ** | **886** | ** ** | **403** | ** ** | **(181** | **)** | **194** | ** ** |
| US GAAP Adjustments                                 |       | (13                    | )          | (3 | ) | (62 | ) | (14 | ) | 120 |   | (15 | ) | (56 | ) | (42 | ) |
| **Net Income (Loss)—US GAAP**                  | ** ** | **617**                | ** ** | **118** | ** ** | **318** | ** ** | **354** | ** ** | **1,006** | ** ** | **388** | ** ** | **(237** | **)** | **152** | ** ** |
| ** **                                          |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Earnings (Loss) per Common Share**($/share)       |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Canadian GAAP—Basic                            |       | 1.19                   |       | 0.23 |   | 0.72 |   | 0.70 |   | 1.68 |   | 0.77 |   | (0.35 | ) | 0.37 |   |
| Canadian GAAP—Diluted                          |       | 1.17                   |       | 0.22 |   | 0.70 |   | 0.68 |   | 1.66 |   | 0.75 |   | (0.35 | ) | 0.36 |   |
| US GAAP—Basic                                  |       | 1.17                   |       | 0.22 |   | 0.60 |   | 0.67 |   | 1.91 |   | 0.74 |   | (0.46 | ) | 0.29 |   |
| US GAAP—Diluted                                |       | 1.15                   |       | 0.22 |   | 0.59 |   | 0.66 |   | 1.89 |   | 0.72 |   | (0.46 | ) | 0.28 |   |
| ** **                                          |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Dividends Declared**(2)                           |       | 0.025                  |       | 0.025 |   | 0.050 |   | 0.025 |   | 0.050 |   | 0.025 |   | 0.050 |   | 0.025 |   |
| ** **                                          |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Common Share Prices**($/share)                    |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Toronto Stock Exchange—High                    |       | 34.20                  |       | 37.60 |   | 43.45 |   | 36.51 |   | 41.47 |   | 36.32 |   | 29.10 |   | 32.63 |   |
| Toronto Stock Exchange—Low                     |       | 26.00                  |       | 29.66 |   | 29.69 |   | 31.25 |   | 21.12 |   | 27.21 |   | 13.33 |   | 27.88 |   |
| New York Stock Exchange—High (US$)             |       | 34.57                  |       | 31.88 |   | 42.71 |   | 32.21 |   | 40.99 |   | 34.79 |   | 23.99 |   | 34.37 |   |
| New York Stock Exchange—Low (US$)              |       | 25.11                  |       | 25.18 |   | 28.87 |   | 29.08 |   | 20.56 |   | 25.25 |   | 10.81 |   | 27.58 |   |

 
| *(1)*  | * * | *The  fourth quarter of 2008 includes an impairment charge of $568 million relating  to oil and gas properties in the US Gulf of Mexico and the UK North Sea. The  fourth quarter of 2007 includes an impairment charge of $366 million relating  to oil and gas properties in the Gulf of Mexico.* |
|--------|----------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |     |                                                                                                                                                                                                                                                                                                |
| *(2)*  | * * | *In  February 2009, the Board of Directors declared a quarterly dividend of  $0.05 per common share, payable April 1, 2009, to shareholders of record  on March 10, 2009.*                                                                                                           |
|   |     |                                                                                                                                                                                                                                                                                                |
| *(3)*  | * * | *At  December 31, 2008, there were 1,624 registered holders of common shares  and 519,448,590 common shares outstanding.*                                                                                                                                                                      |

 

125

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**OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDEOPERATIONS (UNAUDITED)**

 

The following oil and gasinformation is provided in accordance with the FASB Statement No. 69 *Disclosures about Oil and Gas Producing Activities*.It also includes information relating to our interest in Syncrude as itproduces a crude oil product similar to our oil and gas activities even thoughthese operations are considered mining activities under SEC regulations.

 

**A.****            ****Reserve Quantity Information**

 

Our net proved reserves andchanges in those reserves for our conventional operations (excluding Syncrude)are disclosed below. The net proved reserves represent management’s bestestimate of proved oil and gas reserves after royalties. Reserve estimates foreach property are prepared internally each year, and at least 80% of thereserves (including Syncrude) have been assessed by independent qualifiedreserves consultants.

 

Estimates of crude oil andgas proved reserves are determined through analysis of geological andengineering data, and demonstrate reasonable certainty that they arerecoverable from known reservoirs under economic and operating conditions thatexisted at year end. See Critical Accounting Estimates in Item 7 for a descriptionof our oil and gas and mining reserves estimation process.

 

 
| **Conventional  oil and bitumen are in**          | ** ** | **Total** | ** ** | **Yemen****(1)** | ** ** | **Canada** | ** ** | **United States** | ** ** | **United Kingdom** | ** ** | **Other  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, 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—Technical                          |       | 2         |       | (4               | )          | (7         | )          | (3                     | )          | (3                      | )          | —                  |       | (8 | ) | (10 | ) | 19 |   | 9 |   | 1 |   |
| Revisions—Economic                           |       | 229       |       | (12              | )          | 4          |       | 6                      |       | (10                     | )          | 219                     |       | — |   | (2 | ) | — |   | — |   | — |   |
| 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—Technical                          |       | 53        |       | —           |       | —     |       | (1                     | )          | 11                      |       | 19                      |       | (4 | ) | (19 | ) | 39 |   | 8 |   | — |   |
| Revisions—Economic                           |       | —    |       | (11              | )          | (2         | )          | 4                      |       | (4                      | )          | (4                      | )          | (2 | ) | (5 | ) | 4 |   | (2 | ) | — |   |
| 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** | ** ** |
| Extensions and Discoveries                        |       | 26        |       | 39               |       | 1          |       | 1                      |       | 34                      |       | 19                      |       | — |   | 5 |   | 5 |   | — |   | — |   |
| Purchases of Reserves in Place                    |       | —    |       | —           |       | —     |       | —                 |       | —                  |       | —                  |       | — |   | — |   | — |   | — |   | — |   |
| Sales of Reserves in Place                        |       | —    |       | —           |       | —     |       | —                 |       | —                  |       | —                  |       | — |   | — |   | — |   | — |   | — |   |
| Revisions—Technical                          |       | 20        |       | 40               |       | 6          |       | (3                     | )          | 54                      |       | —                  |       | 2 |   | (14 | ) | 17 |   | — |   | (2 | ) |
| Revisions—Economic                           |       | (3        | )          | (21              | )          | 2          |       | (19                    | )          | (16                     | )          | 31                      |       | (3 | ) | (5 | ) | (16 | ) | — |   | 2 |   |
| Production                                        |       | (60       | )          | (71              | )          | (12        | )          | (4                     | )          | (40                     | )          | (2                      | )          | (3 | ) | (24 | ) | (37 | ) | (7 | ) | (2 | ) |
| **December 31, 2008**                        | ** ** | **544**   | ** ** | **519**          | ** ** | **20**     | ** ** | **22**                 | ** ** | **350**                 | ** ** | **282**                 | ** ** | **17** | ** ** | **151** | ** ** | **172** | ** ** | **18** | ** ** | **31** | ** ** |
| **Proved Developed Reserves(5)**                  |       |      |       |             |       |       |       |                   |       |                    |       |                    |       |   |   |   |   |   |   |   |   |   |   |
| 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 |   |
| **December 31, 2008**                        | ** ** | **244**   | ** ** | **464**          | ** ** | **19**     | ** ** | **22**                 | ** ** | **329**                 | ** ** | **52**                  | ** ** | **12** | ** ** | **124** | ** ** | **133** | ** ** | **11** | ** ** | **6** | ** ** |

 

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| *(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.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
|   |     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| *(5)*  | * * | *Proved developed oil and gas reserves  are expected to be recovered through existing wells with existing equipment  and operating methods.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |

 

126

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Ournet proved reserves and changes in those reserves for our Syncrude operationsare disclosed below. Additional disclosures required by SEC Industry Guide 7are on pages 20 through 22. The net proved reserves represent management’sbest estimate 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 2 billion tons of economically extractable oil sands inthe Mildred Lake North Mine, with an average bitumen grade of 10.3 weightpercent. The Aurora North Mine contains an estimated 4.6 million tons ofeconomically extractable oil sands at an average bitumen grade of 11.1 weightpercent. Aurora South Lease 31 contains measured economically extractable oilsands of 3.8 billion tons at an average bitumen grade of 10.8 weight percent.

 
| ** **                          | ** ** | **Synthetic Crude Oil** | ** ** |
|-------------------------------------|------------|-----------------------------------|------------|
| **(millions of barrels)** | ** ** | **Mildred Lake(1)**          | ** ** | **Aurora(2)** | ** ** | **Total** | ** ** |
| **December 31, 2005**          | ** ** | **47**                            | ** ** | **217** | ** ** | **264** | ** ** |
| Extensions and  Discoveries         |       | —                            |       | 11 |   | 11 |   |
| Revision—Economic              |       | 1                                 |       | 4 |   | 5 |   |
| Production                          |       | (3                                | )          | (3 | ) | (6 | ) |
| **December 31, 2006**          | ** ** | **45**                            | ** ** | **229** | ** ** | **274** | ** ** |
| Extensions and  Discoveries         |       | —                            |       | 7 |   | 7 |   |
| Revision—Economic              |       | —                            |       | (7 | ) | (7 | ) |
| Production                          |       | (3                                | )          | (4 | ) | (7 | ) |
| **December 31, 2007**          | ** ** | **42**                            | ** ** | **225** | ** ** | **267** | ** ** |
| Extensions and  Discoveries         |       | —                            |       | 7 |   | 7 |   |
| Revision—Economic              |       | 11                                |       | 17 |   | 28 |   |
| Production                          |       | (4                                | )          | (3 | ) | (7 | ) |
| **December 31, 2008**          | ** ** | **49**                            | ** ** | **246** | ** ** | **295** | ** ** |

 
| *(1)*  | * * | *Leases 17 and 22.*         |
|--------|----------|-----------------------------|
|   |     |                        |
| *(2)*  | * * | *Leases 10, 12, 31 and 34.* |

 

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**B.****            ****Capitalized Costs (excluding Syncrude operations)**

 
| **(Cdn$ millions)**    | ** ** | **Proved  Properties** | ** ** | **Unproved  Properties** | ** ** | **Accumulated  DD&A** | ** ** | **Capitalized  Costs** | ** ** |
|-----------------------------|------------|------------------------|------------|--------------------------|------------|---------------------------|------------|------------------------|------------|
| **December 31, 2008**  |       |                   |       |                     |       |                      |       |                   |       |
| Yemen                       |       | 2,808                  |       | —                   |       | (2,610                    | )          | 198                    |       |
| Canada                      |       | 5,087                  |       | 1,067                    |       | (2,179                    | )          | 3,975                  |       |
| United States               |       | 4,152                  |       | 246                      |       | (2,702                    | )          | 1,696                  |       |
| United Kingdom              |       | 5,954                  |       | 578                      |       | (2,159                    | )          | 4,373                  |       |
| Other Countries             |       | 509                    |       | 45                       |       | (113                      | )          | 441                    |       |
| **Total Capitalized Costs** | ** ** | **18,510**             | ** ** | **1,936**                | ** ** | **(9,763**                | **)**      | **10,683**             | ** ** |
| **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**              | ** ** |

 

**C.****            ****Costs Incurred (excluding Syncrude operations)**

 
| ** **                             | ** ** | ** **                       | ** ** | **Oil and Gas** | ** ** |
|----------------------------------------|------------|----------------------------------|------------|---------------------------|------------|
| **(Cdn$ millions)**               | ** ** | **Total  Oil and Gas** | ** ** | **Yemen**                 | ** ** | **Canada** | ** ** | **United  States** | ** ** | **United  Kingdom** | ** ** | **Other** | ** ** |
| **Year Ended December 31, 2008**  |       |                             |       |                      |       |   |   |   |   |   |   |   |   |
| Property  Acquisition Costs            |       |                             |       |                      |       |   |   |   |   |   |   |   |   |
| Proved                                 |       | 22                               |       | —                    |       | 22 |   | — |   | — |   | — |   |
| Unproved                               |       | 69                               |       | —                    |       | 6 |   | 63 |   | — |   | — |   |
| Exploration Costs                      |       | 650                              |       | 9                         |       | 222 |   | 132 |   | 157 |   | 130 |   |
| Development Costs                      |       | 1,795                            |       | 92                        |       | 717 |   | 251 |   | 545 |   | 190 |   |
| Asset Retirement  Costs                |       | 188                              |       | —                    |       | 25 |   | 153 |   | 10 |   | — |   |
| **Total Costs Incurred**               | ** ** | **2,724**                        | ** ** | **101**                   | ** ** | **992** | ** ** | **599** | ** ** | **712** | ** ** | **320** | ** ** |
| **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** | ** ** |

 

128

----

 

**D.****            ****Results of Operations for Producing Activities (excludingSyncrude operations)**

 
| ** **                                            | ** ** | ** **                       | ** ** | **Oil and Gas** | ** ** |
|-------------------------------------------------------|------------|----------------------------------|------------|---------------------------|------------|
| **(Cdn$ millions)**                              | ** ** | **Total  Oil and Gas** | ** ** | **Yemen**                 | ** ** | **Canada** | ** ** | **United  States** | ** ** | **United  Kingdom** | ** ** | **Other  Countries** | ** ** |
| **Year Ended December 31, 2008**                 |       |                             |       |                      |       |   |   |   |   |   |   |   |   |
| Net Sales                                             |       | 6,186                            |       | 1,093                     |       | 656 |   | 665 |   | 3,580 |   | 192 |   |
| Production Costs                                      |       | 715                              |       | 176                       |       | 182 |   | 94 |   | 253 |   | 10 |   |
| Exploration  Expense                                  |       | 402                              |       | 5                         |       | 79 |   | 109 |   | 86 |   | 123 |   |
| Depreciation,  Depletion, Amortization and Impairment |       | 1,859                            |       | 160                       |       | 208 |   | 475 |   | 999 |   | 17 |   |
| Other Expenses  (Income)                              |       | 75                               |       | (10                       | )          | 29 |   | 37 |   | 6 |   | 13 |   |
|                                                  |       | 3,135                            |       | 762                       |       | 158 |   | (50 | ) | 2,236 |   | 29 |   |
| Income Tax  Provision (Recovery)                      |       | 1,412                            |       | 264                       |       | 45 |   | (19 | ) | 1,126 |   | (4 | ) |
| **Results of Operations**                             | ** ** | **1,723**                        | ** ** | **498**                   | ** ** | **113** | ** ** | **(31** | **)** | **1,110** | ** ** | **33** | ** ** |
| **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** | ** ** |

 

129

----

 

**E.****              ****Standardized Measure of Discounted Future Net Cash Flows andChanges 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,  2008**                           |       |       |       |      |       |       |       |               |       |                |       |                 |       |
| Future Cash  Inflows                                  |       | 25,305     |       | 904       |       | 12,260     |       | 1,809              |       | 8,753               |       | 1,579                |       |
| Future Production  Costs                              |       | 10,847     |       | 424       |       | 6,619      |       | 765                |       | 2,616               |       | 423                  |       |
| Future  Development Costs                             |       | 3,008      |       | 51        |       | 1,488      |       | 33                 |       | 564                 |       | 872                  |       |
| Future  Dismantlement and Site Restoration Costs, Net |       | 1,421      |       | 20        |       | 332        |       | 446                |       | 558                 |       | 65                   |       |
| Future Income Tax                                     |       | 2,653      |       | 141       |       | —     |       | —             |       | 2,467               |       | 45                   |       |
| Future Net Cash  Flows                                |       | 7,376      |       | 268       |       | 3,821      |       | 565                |       | 2,548               |       | 174                  |       |
| 10% Discount  Factor                                  |       | 2,953      |       | 24        |       | 1,988      |       | 84                 |       | 505                 |       | 352                  |       |
| **Standardized Measure**                              | ** ** | **4,423**  | ** ** | **244**   | ** ** | **1,833**  | ** ** | **481**            | ** ** | **2,043**           | ** ** | **(178**             | **)**      |
| ** **                                            |       |       |       |      |       |       |       |               |       |                |       |                 |       |
| **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**              | ** ** |

 

130

----

 

**Changes inthe 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)**                                                                   | ** ** | **2008**  | ** ** | **2007**   | ** ** | **2006**  | ** ** |
|--------------------------------------------------------------------------------------------|------------|-----------|------------|------------|------------|-----------|------------|
| Beginning of Year                                                                          |       | 11,129    |       | 8,373      |       | 8,042     |       |
| Sales and  Transfers of Oil and Gas Produced, Net of Production Costs                      |       | (4,387    | )          | (3,010     | )          | (2,291    | )          |
| Net Changes in  Prices and Production Costs Related to Future Production                   |       | (9,756    | )          | 3,385      |       | (1,065    | )          |
| Extensions,  Discoveries and Improved Recovery, Less Related Costs                         |       | 376       |       | 758        |       | 695       |       |
| Changes in  Estimated Future Development and Dismantlement Costs                           |       | (676      | )          | (443       | )          | (692      | )          |
| Previous  Estimated Future Development and Dismantlement Costs Incurred During the  Period |       | 1,343     |       | 1,102      |       | 1,048     |       |
| Revisions of  Previous Quantity Estimates                                                  |       | 615       |       | 2,189      |       | 1,936     |       |
| Accretion of  Discount                                                                     |       | 1,730     |       | 1,191      |       | 1,117     |       |
| Purchases of  Reserves in Place                                                            |       | —    |       | 272        |       | 2         |       |
| Sales of Reserves  in Place                                                                |       | —    |       | (49        | )          | (2        | )          |
| Net Change in  Income Taxes                                                                |       | 4,049     |       | (2,639     | )          | (417      | )          |
| **End of Year**                                                                            | ** ** | **4,423** | ** ** | **11,129** | ** ** | **8,373** | ** ** |

 

ITEM 9.

 

Changes in and Disagreementswith Accountants on Accounting and Financial Disclosure

 

Therewere no disagreements with accountants on accounting and financial disclosure.

 

ITEM 9A.

 

Controls and Procedures

 

**EVALUATIONOF DISCLOSURE CONTROLS AND PROCEDURES**

 

TheCompany’s Chief Executive Officer and Chief Financial Officer have designeddisclosure controls and procedures (as defined inRules 13(a)-15(e) and 15(d)-15(e) under the Securities ExchangeAct of 1934), or caused such disclosure controls and procedures to be designedunder their supervision, to ensure that material information relating to theCompany is made known to them, particularly during the period in which thisreport is prepared. They have evaluated the effectiveness of such disclosurecontrols and procedures as of the end of the period covered by this report(Evaluation Date). Based upon that evaluation, the Chief Executive Officer andChief Financial Officer concluded that, as of the Evaluation Date, theCompany’s disclosure controls and procedures are effective (i) to ensurethat information required to be disclosed by us in reports that the Companyfiles or submits under the Exchange Act is recorded, processed, summarized andreported within the time periods specified in the Securities and ExchangeCommission rules and forms; and (ii) to ensure that informationrequired to be disclosed in the reports that the Company files or submits underthe Exchange Act is accumulated and communicated to our management, includingthe Company’s Chief Executive Officer and Chief Financial Officer, to allowtimely decisions regarding required disclosure.

 

TheCompany’s management, including its Chief Executive Officer and Chief FinancialOfficer, does not expect that the Company’s disclosure controls and proceduresor internal controls will prevent all possible error and fraud. The Company’sdisclosure controls and procedures are, however, designed to provide reasonableassurance of achieving their objectives, and the Company’s Chief ExecutiveOfficer and Chief Financial Officer have concluded that the Company’s financialcontrols and procedures are effective at that reasonable assurance level.

 

**MANAGEMENT’SREPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING**

 

Ourmanagement is responsible for establishing and maintaining adequate internalcontrol over financial reporting (as defined in Exchange ActRules 13(a)-15(f)). Under the supervision and with the participation ofour management, including our principal executive officer (CEO) and principalfinancial officer (CFO), we conducted an evaluation of the effectiveness of ourinternal control over financial reporting based on the InternalControl-Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission. Based on our evaluation, we concludedthat our internal control over financial reporting is effective as ofDecember 31, 2008. We have documented this assessment and made thisassessment available to our independent registered Chartered Accountants. Werecognize that 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.

 

131

----

 

Deloitte &Touche LLP audited our Consolidated Financial Statements as stated in theirreport which is on page 132 of this Form 10-K and has issued anattestation report on our internal control over financial reporting.

 

**CHANGES ININTERNAL CONTROLS**

 

Wehave continually had in place systems of internal controls over financialreporting. There have not been any changes in the Company’s internal controlover financial reporting during the last quarter that have materially affected,or are reasonably likely to materially affect, our internal control overfinancial 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.

 

**REPORT OF INDEPENDENTREGISTERED 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, 2008, based on criteriaestablished in Internal Control—Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission. The Company’s managementis responsible for maintaining effective internal control over financialreporting and for its assessment of the effectiveness of internal control overfinancial reporting, included in the accompanying Management’s Report onInternal Control over Financial Reporting. Our responsibility is to express anopinion on the Company’s internal control over financial reporting based on ouraudit.

 

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 ofinternal control based on the assessed risk, and performing such otherprocedures as we considered necessary in the circumstances. We believe that ouraudit provides a reasonable 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 providereasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance withgenerally accepted accounting principles. A company’s internal control overfinancial reporting includes those policies and procedures that(1) pertain to the maintenance of records that, in reasonable detail,accurately and fairly reflect the transactions and dispositions of the assetsof the company; (2) provide reasonable assurance that transactions arerecorded as necessary to permit preparation of financial statements inaccordance with generally accepted accounting principles, and that receipts andexpenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (3) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’s assets that could have a materialeffect 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, 2008, basedon the criteria established in Internal Control— Integrated Framework issued bythe 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, 2008, and our report datedFebruary 11, 2009, expressed an unqualified opinion on those financialstatements and includes a separate report titled Comments by IndependentRegistered Chartered Accountants on Canada—United States of America ReportingDifference referring to changes in accounting principles that have a materialeffect on the comparability of the Company’s financial statements.

 
| (signed) “Deloitte & Touche LLP” |
|-----------------------------------------------------|
| Independent Registered Chartered Accountants        |
| Calgary, Canada                                     |
| February 11, 2009                              |

 

132

----

 

**Governance**

 

**CORPORATE GOVERNANCE**

 

 

**As a leader in corporate governance,**

**we are committed to transparent disclosure**

**for all stakeholders.**

 

----

 

**Governance**

 

**PARTS IIIAND IV**

 
| ITEMS 10 AND 11.                                                                                |   |   |
|-------------------------------------------------------------------------------------------------|--------|--------|
| Directors, Executive Officers and Corporate Governance,  and Executive Compensation             |   |   |
| Directors                                                                                       |   | 133    |
| Independence and Board Committees                                                               |   | 134    |
| Director Compensation                                                                           |   | 135    |
| Compensation Committee Report                                                                   |   | 137    |
| Compensation Committee Interlocks and Insider  Participation                                    |   | 139    |
| Compensation Discussion and Analysis                                                            |   | 139    |
| Compensation Objectives                                                                         |   | 140    |
| Share Performance Graph                                                                         |   | 143    |
| Executive Officers                                                                              |   | 147    |
| Share Splits                                                                                    |   | 148    |
| Summary Compensation Table                                                                      |   | 148    |
| CEO Compensation and 2008 Goals and Results                                                     |   | 149    |
| CEO Three-Year Look-Back                                                                        |   | 149    |
| TOPs Tables                                                                                     |   | 150    |
| Equity Ownership and Changes in 2008                                                            |   | 152    |
| Pension Plan Tables                                                                             |   | 152    |
| All Other Compensation                                                                          |   | 153    |
| Termination and Change of Control Benefits                                                      |   | 154    |
| Corporate Governance                                                                            |   | 156    |
| Governance Committee Report                                                                     |   | 156    |
| Audit Committee Report                                                                          |   | 158    |
|                                                                                            |   |   |
| ITEM 12.                                                                                        |   |   |
|                                                                                            |   |   |
| Security Ownership of Certain Beneficial Owners and  Management and Related Stockholder Matters |   | 159    |
|                                                                                            |   |   |
| ITEM 13.                                                                                        |   |   |
|                                                                                            |   |   |
| Certain Relationships and Related Transactions, and  Director Independence                      |   | 160    |
|                                                                                            |   |   |
| ITEM 14.                                                                                        |   |   |
|                                                                                            |   |   |
| Principal Accounting Fees and Services                                                          |   | 160    |
|                                                                                            |   |   |
| ITEM 15.                                                                                        |   |   |
|                                                                                            |   |   |
| Exhibits, Financial Statement Schedules                                                         |   | 162    |

 

----

 

**PART III**

 

ITEMS10 AND 11.

 

Directors,Executive Officers and Corporate Governance, and Executive Compensation

 

**DIRECTORS**

 

Accordingto our Articles, Nexen must have between three and 15 directors. InDecember 2008, the board expanded its size from 12 to 14 directorspursuant to the provisions granted in our articles and approved the appointmentof Mr. Berry (effective December 8, 2008) and of Mr. Bertram(effective January 1, 2009). Mr. Fischer retired on December 31,2008 and Mr. Romanow was appointed to the board effective January 1,2009 upon his appointment as President and Chief Executive Officer (CEO). Theyare management nominees for election to the board at the 2009 annual generalmeeting of shareowners (AGM). All other directors were elected at the last AGM.On February 11, 2009, the board determined to set the size at 12 directorseffective April 28, 2009 when Mr. Hentschel and Mr. Thomsonretire.

 

OurBy-Laws provide that directors will be elected at the AGM each year and willhold office until their successors are elected.

 
| **Name (Age)**                             | ** ** | **Principal Occupation**                                                                                                                                                                                                                                                                                                                       | ** ** | **Other Directorships**                                                      | ** ** | **Nexen Director Since** |
|--------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------|------------|--------------------------|
| William B. Berry (56)                      |       | Retired oil executive.   Formerly: Executive Vice President of ConocoPhillips.                                                                                                                                                                                                                                                                 |       | Willbros Group, Inc.                                                    |       | 2008                     |
| Robert G. Bertram (64)                     |       | Retired pension investment executive.

Formerly: Executive Vice President of Ontario Teachers  Pension Plan Board.                                                                                                                                                                                                                             |       | The Cadillac Fairview Corporation; Maple Leaf Sports and  Entertainment Ltd. |       | 2009                     |
| Dennis G. Flanagan****(69)                 |       | Retired oil executive.                                                                                                                                                                                                                                                                                                                         |       | Canexus Income Fund (Chair) NAL Oil & Gas Trust                     |       | 2000                     |
| David A. Hentschel(3) (75)            |       | Retired oil executive. 

Formerly: Oil and gas consultant                                                                                                                                                                                                                                                                                      |       | Cimarex Energy Co.                                                           |       | 1985                     |
| S. Barry Jackson(1)** **(56)          |       | Retired oil executive. 

Formerly: Chair of Resolute Energy Inc. and Chair of Deer  Creek Energy Limited.                                                                                                                                                                                                                                      |       | TransCanada Corporation (Chair) TransCanada PipeLines  Limited (Chair)       |       | 2001                     |
| Kevin J. Jenkins(1), (2) (52)         |       | Managing Director of TriWest Capital Partners.   Formerly: President and CEO of The Westaim Corporation.                                                                                                                                                                                                                                       |       | —                                                                       |       | 1996                     |
| A. Anne McLellan, P.C.(1)** **(58)    |       | 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, (1) O.C. (64)         |       | Retired Chair and CEO of Syncrude Canada Ltd.                                                                                                                                                                                                                                                                                                  |       | —                                                                       |       | 2004                     |
| Thomas C. O’Neill(1),  (2) (63)  |       | 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; The Bank  of Nova Scotia    |       | 2002                     |
| Marvin F. Romanow (53)                     |       | President and CEO of Nexen. 

Formerly: Executive Vice President and CFO of Nexen.                                                                                                                                                                                                                                                             |       | Canexus Income Fund                                                          |       | 2009                     |
| Francis M. Saville, Q.C.(1)** **(70)  |       | 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) (75) |       | Retired banking executive.                                                                                                                                                                                                                                                                                                                     |       | The Thomson Corporation                                                      |       | 1997                     |
| John M. Willson(1)** **(69)           |       | Retired mining executive.                                                                                                                                                                                                                                                                                                                      |       | Finning International Inc.                                                   |       | 1996                     |
| Victor J. Zaleschuk(4)** **(65)       |       | Retired oil executive.                                                                                                                                                                                                                                                                                                                         |       | Agrium Inc.; Cameco Corporation (Chair)                                      |       | 1997                     |

 

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*(1)**      **All members of the Audit and Conduct Review (Audit),Corporate Governance and Nominating (Governance), and Compensation and HumanResources (Compensation) Committees are independent. All members of the AuditCommittee are independent under additional regulations for audit committeemembers.*

*(2)**      **Financial Experts on Nexen’s Audit Committee.*

*(3)**      **Mr. Hentschel was Chair and CEO of Occidental Oil andGas Corporation from 1997 to 1999 and President and CEO of Nexen from 1995 to1997.*

*(4)**      **Mr. Zaleschuk was President and CEO of Nexen from 1997to 2001.*

 

133

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**INDEPENDENCEAND BOARD COMMITTEES**

 

Theboard affirmed director independence under our categorical standards fordirector independence (categorical standards), which are available atwww.nexeninc.com. The categorical standards have been in place since 2003 andmost recently amended on February 11, 2009. Our categorical standards meetor exceed the requirements in SEC rules and regulations, the Sarbanes-OxleyAct of 2002 (Sarbanes-Oxley), the NYSE rules, *National Policy 58-201**—Corporate Governance Guidelines, Multilateral Instrument 52-110—AuditCommittees,* and applicable provisions of *National Instrument 51-101—Standards of Disclosure for Oil and GasActivities.*

 

Mr. Romanowis not independent as he is Nexen’s President and CEO.

 

Mr. Flanaganis not independent as his son is Senior Vice President, Engineering of TriAxonResources Ltd. (TriAxon). In 2006, TriAxon acquired a company that was party tocontracts with a Nexen subsidiary. 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 has not been compromisedby this transaction and, accordingly, the board continues to include him intheir meetings without management.

 

Ms. McLellanhas been counsel with Bennett Jones LLP (BJ), Barristers and Solicitors,Edmonton, Alberta since June 27, 2006. BJ provided legal services to us in eachof the last five years. Ms. McLellan does not solicit or participate inthose services, does not receive any fees we pay to BJ, nor is she a partner oran employee of the firm. She is independent under our categorical standards.

 

Mr. Savillehas been counsel with Fraser Milner Casgrain LLP (FMC), Barristers andSolicitors, Calgary, Alberta since February 1, 2004. Prior to that time,he was a senior partner of the firm. FMC provided legal services to us in eachof the last five years. Mr. Saville does not solicit or participate inthose services, does not receive any fees we pay to FMC, nor is he a partner oran employee of the firm. He is independent under our categorical standards.

 

Wehave not had an executive committee of the board since July 11, 2000.

 
| ** **                                   | ** ** | **Committees ****(Number of Members)** | ** ** |
|----------------------------------------------|------------|-------------------------------------------------------|------------|
| ** **                                   | ** ** | **Audit(1), (2)  (6)**                           | ** ** | **Compensation(1)  (7)** | ** ** | **Governance(1)  (7)** | ** ** | **Finance  (6)** | ** ** | **HSE&SR  (8)** | ** ** | **Reserves(3)  (7)** | ** ** |
| **Management Director—Not Independent** |       |                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Marvin F. Romanow                            |       |                                                  |       |   |   |   |   |   |   |   |   |   |   |
| **Outside Director—Not Independent**    |       |                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Dennis G. Flanagan                           |       |                                                  |       |   |   |   |   | Ö |   | Ö |   | Ö |   |
| **Independent Outside Directors**            |       |                                                  |       |   |   |   |   |   |   |   |   |   |   |
| William B. Berry(4)                          |       |                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Robert G. Bertram(4)                         |       |                                                  |       |   |   |   |   |   |   |   |   |   |   |
| David A. Hentschel                           |       |                                                  |       |   |   |   |   | Ö |   | Ö |   | Ö |   |
| S. Barry Jackson                             |       | Ö                                                |       | Ö |   |   |   |   |   | Chair |   | Ö |   |
| Kevin J. Jenkins(5)                          |       | Ö                                                |       | Chair |   | Ö |   |   |   | Ö |   |   |   |
| A. Anne McLellan, P.C.                       |       |                                                  |       | Ö |   | Ö |   | Ö |   | Ö |   |   |   |
| Eric P. Newell, O.C.                         |       | Ö                                                |       |   |   | Ö |   |   |   | Ö |   | Ö |   |
| Thomas C. O’Neill(5), (6)               |       | Chair                                                 |       | Ö |   | Ö |   |   |   |   |   | Ö |   |
| Francis M. Saville, Q.C.                     |       |                                                  |       | Ö |   | Ö |   | Ö |   | Ö |   |   |   |
| Richard M. Thomson, O.C.(5)                  |       | Ö                                                |       | Ö |   | Chair |   | Ö |   |   |   |   |   |
| John M. Willson                              |       | Ö                                                |       | Ö |   | Ö |   |   |   |   |   | Chair |   |
| Victor J. Zaleschuk                          |       |                                                  |       |   |   |   |   | Chair |   | Ö |   | Ö |   |

 

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*(1)**      **All members are independent. All Audit Committee members areindependent under additional regulatory requirements applicable to them.*

*(2)**      **Experience of the members of the Audit Committee thatindicates an understanding of the accounting principles we use to prepare ourfinancial statements is shown in their biographies on page 135.*

*(3)**      **A majority of the Reserves Committee members areindependent.*

*(4)**      **Mr. Berry and Mr. Bertram will receive committeeappointments on April 28, 2009, as determined by the board.*

*(5)**      **Audit committee financial expert under US regulatoryrequirements.*

*(6)**      **The board has determined that Mr. O’Neill’s service onthe audit committees of four other public companies and one not-for-profitorganization does not impair his ability to serve as Chair of Nexen’s AuditCommittee. The board considered that Mr. O’Neill has over 30 years ofexperience as a chartered accountant and, since retiring as Chair of PwCConsulting in 2002, his only business commitments are to the boards andcommittees on which he serves.*

 

134

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**AuditCommittee Financial Expert Experience**

 
| **Name**       | ** ** | **Jenkins**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         | ** ** | **O’Neill**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   | ** ** | **Thomson**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|----------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| **Experience** |       | Kevin Jenkins, 52, is a 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. 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 Vice Chair and a director of World Vision Canada. |       | Tom O’Neill, 63, 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 Honorary Doctorate of Law from Queen’s University.   Tom is a director of BCE Inc., Loblaw Companies Limited, The Bank of Nova  Scotia 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. |       | Dick Thomson, 75, 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 board of the Multiple Sclerosis Scientific Research  Foundation. |

 

**Directorand Officer Liability Insurance**

 

Wemaintain a director and officer liability insurance policy. The policy coverscosts to defend and settle claims against Nexen’s directors and officers to anannual limit of US$150 million. It includes a US$12.5 million deductible for anindemnifiable occurrence and no deductible for a non-indemnifiable occurrence.The cost of coverage for 2008 was approximately US$951,000. Directors andofficers do not pay premiums and no indemnity claims were made or paid in 2008.

 

**Directorand Officer Fiduciary Insurance**

 

Nexenmaintains a fiduciary liability insurance policy. It covers costs to defend andsettle claims against Nexen, our directors, officers and employees for breachof fiduciary duty related to company-sponsored plans, such as pension andsavings plans. The policy has an annual limit of US$25 million with a US$2.5million deductible for an indemnifiable occurrence and no deductible for anon-indemnifiable occurrence. The cost of coverage for 2008 was approximatelyUS$27,600. Directors and officers do not pay premiums and no claims were madeor paid in 2008.

 

**Loans toDirectors**

 

Asset out in the corporate governance policy, we do not make loans to ourdirectors. There are no loans outstanding from Nexen to our directors.

 

**DIRECTORCOMPENSATION**

 

Nexenprovides all directors with a comprehensive compensation package of annual cashretainers, meeting fees and equity-based incentives in the form of deferredshare units (DSUs). The package provides competitive remuneration for theincreasing responsibilities, time commitments and accountability of boardmembers. Management, the Compensation Committee and the board regularly reviewthe compensation for competitiveness against a peer group of oil and gascompanies. We target and currently provide total compensation between the 50thand 75th percentile to attract and retain qualified talent to our board.

 

Directorsmay choose select benefits coverage at Nexen’s expense, including basic lifeinsurance, extended health care, dental, business travel accident insurance,and reimbursement of provincial health care premiums (in certainjurisdictions). Directors do not receive compensation from a non-equityincentive plan. Mr. Zaleschuk, a former CEO of Nexen, is a retiree inNexen’s pension plan. His pension benefit is for previous employee service.

 

Seepage 137 for more information on DSUs.

 

135

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**DirectorCompensation Table**

 
| **Name**     | ** ** | **Total  Fees Earned(1)** | ** **    | **DSU  Awards(2)** | ** ** | **All Other   Compensation(3)** | ** ** | **Total  Compensation** | ** **  |
|--------------|------------|--------------------------------|---------------|--------------------|------------|-------------------------------------------|------------|-------------------------|-------------|
| Berry        |       | 6,217                          |          | 96,800             |       | —                                    |       | 103,017                 |        |
| Flanagan     |       | 110,000                        |          | 96,800             |       | 96,054                                    | (4)        | 302,854                 |        |
| Hentschel    |       | 114,500                        |          | 96,800             |       | 4,458                                     |       | 215,758                 |        |
| Jackson      |       | 135,500                        |          | 96,800             |       | 5,887                                     |       | 238,187                 |        |
| Jenkins      |       | 137,300                        |          | 96,800             |       | 6,579                                     |       | 240,679                 |        |
| McLellan     |       | 130,200                        |          | 96,800             |       | 2,719                                     |       | 229,719                 |        |
| Newell       |       | 126,600                        |          | 96,800             |       | 7,383                                     |       | 230,783                 |        |
| O’Neill |       | 154,100                        |          | 96,800             |       | 6,105                                     |       | 257,005                 |        |
| Saville      |       | 254,500                        |          | 154,880            |       | 5,731                                     |       | 415,111                 |        |
| Thomson      |       | 143,300                        |          | 96,800             |       | 9,552                                     |       | 249,652                 |        |
| Willson      |       | 144,500                        |          | 96,800             |       | 6,459                                     |       | 247,759                 |        |
| Zaleschuk    |       | 115,300                        |          | 96,800             |       | 4,876                                     |       | 216,976                 |        |
| **Total**    | ** ** | **$**                          | **1,572,017** | ** **         | **$**      | **1,219,680**                             | ** ** | **$**                   | **155,803** | ** ** | **$** | **2,947,500** | ** ** |
|              |            |                                |               |                    |            |                                           |            |                         |             |  |  |  |  |

 

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*(1)**      **Includes all retainers and meetings fees, including thosepaid in DSUs.*

*(2)**      **The value of DSUs granted on December 8, 2008, based onthe closing market price of Nexen common shares on the TSX on December 5,2008 of $19.36/share. See page 137 for details.*

*(3)**      **The total value of perquisites provided to each director isless than both $50,000 or 10% of total fees, and is not included in thiscolumn. Amounts reflect life insurance premiums paid by Nexen, reinvesteddividends earned in 2008 valued at the closing market price of Nexen commonshares on the TSX on the payment dates, travel allowance paid by Nexen, andCanexus fees as set out in note 4.*

*(4)**      **Mr. Flanagan is the Board Chair of Canexus and was paidfees of $59,000, received deferred trust units of Canexus valued at $21,840 anddistributions on his trust units of $10,630 in 2008. The total is included inthis column.*

 

**DirectorRetainers and Fees**

 

Annualboard and committee retainers are paid quarterly and pro-rated for partialservice. The same fees are paid for attending meetings in person or byconference call. A travel allowance of $1,500 was introduced in 2007. It ispaid when a non-executive director travels outside his or her home province orstate, or travels more than three hours, round trip, to attend a Nexen meetingor site visit. Nexen also reimburses directors for out-of-pocket travelexpenses.

 
| ** **                                               | ** ** | **2008** | ** ** | **2009** | ** ** |
|----------------------------------------------------------|------------|----------|------------|----------|------------|
| Board Chair Retainer                                     |       | $        | 250,000    | (1)      | $          | 250,000 | (1) |
| Board Member Retainer                                    |       | 35,000   |       | 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    |       |
|                                                          |            |          |            |          |            |  |  |

 

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*(1)**      **As of January 1, 2008, the Board Chair is paid onlythis retainer and the travel allowance. He does not receive any other retainersor meetings fees.*

 

**2008Retainers and Fees**

 
| **Name**     | ** ** | **Annual**

**Board**

**Retainer** | ** **  | **Annual  Committee  Retainers** | ** ** | **Annual**

**Committee  Chair  Retainer** | ** ** | **Board  Meeting  Fees** | ** ** | **Committee  Meeting  Fees** | ** ** | **Travel  Allowance** | ** ** | **Total Fees  Earned** | ** **  | **Total Fees  Credited  in DSUs(1)** | ** ** | **Percentage  of Fees  Credited in  DSUs(1)** | ** ** | **Total Fees  Earned in  Cash** | ** **    |
|--------------|------------|-------------------------------------|-------------|----------------------------------|------------|--------------------------------------------|------------|--------------------------|------------|------------------------------|------------|-----------------------|------------|-----------------------------|-------------|------------------------------------------------|------------|---------------------------------------------------------|------------|-------------------------------------------|---------------|
| Berry        |       | 2,917                               |        | —                           |       | —                                     |       | 1,800                    |       | —                       |       | 1,500                 |       | 6,217                       |        | —                                         |       | —                                                  |       | 6,217                                     |          |
| Flanagan     |       | 35,000                              |        | 27,300                           |       | —                                     |       | 18,000                   |       | 25,200                       |       | 4,500                 |       | 110,000                     |        | —                                         |       | —                                                  |       | 110,000                                   |          |
| Hentschel    |       | 35,000                              |        | 27,300                           |       | —                                     |       | 18,000                   |       | 25,200                       |       | 9,000                 |       | 114,500                     |        | —                                         |       | —                                                  |       | 114,500                                   |          |
| Jackson      |       | 35,000                              |        | 36,400                           |       | 5,300                                      |       | 18,000                   |       | 37,800                       |       | 3,000                 |       | 135,500                     |        | 132,500                                        |       | 98                                                      | %          | 3,000                                     |          |
| Jenkins      |       | 35,000                              |        | 36,400                           |       | 5,300                                      |       | 18,000                   |       | 39,600                       |       | 3,000                 |       | 137,300                     |        | —                                         |       | —                                                  |       | 137,300                                   |          |
| McLellan     |       | 35,000                              |        | 36,400                           |       | —                                     |       | 18,000                   |       | 37,800                       |       | 3,000                 |       | 130,200                     |        | 127,200                                        |       | 98                                                      | %          | 3,000                                     |          |
| Newell       |       | 35,000                              |        | 36,400                           |       | —                                     |       | 18,000                   |       | 34,200                       |       | 3,000                 |       | 126,600                     |        | 123,600                                        |       | 98                                                      | %          | 3,000                                     |          |
| O’Neill |       | 35,000                              |        | 36,400                           | ** ** | 19,700                                     | (2)        | 18,000                   |       | 36,000                       |       | 9,000                 |       | 154,100                     |        | —                                         |       | —                                                  |       | 154,100                                   |          |
| Saville      |       | 250,000                             |        | —                           |       | —                                     |       | —                   |       | —                       |       | 4,500                 |       | 254,500                     |        | —                                         |       | —                                                  |       | 254,500                                   |          |
| Thomson      |       | 35,000                              |        | 36,400                           |       | 5,300                                      |       | 18,000                   |       | 39,600                       |       | 9,000                 |       | 143,300                     |        | 134,300                                        |       | 94                                                      | %          | 9,000                                     |          |
| Willson      |       | 35,000                              |        | 36,400                           |       | 5,300                                      |       | 18,000                   |       | 37,800                       |       | 12,000                |       | 144,500                     |        | —                                         |       | —                                                  |       | 144,500                                   |          |
| Zaleschuk    |       | 35,000                              |        | 27,300                           |       | 5,300                                      |       | 18,000                   |       | 25,200                       |       | 4,500                 |       | 115,300                     |        | —                                         |       | —                                                  |       | 115,300                                   |          |
| **Total**    | ** ** | **$**                               | **602,917** | ** **                       | **$**      | **336,700**                                | ** ** | **$**                    | **46,200** | ** **                   | **$**      | **181,800**           | ** ** | **$**                       | **338,400** | ** **                                     | **$**      | **66,000**                                              | ** ** | **$**                                     | **1,572,017** | ** ** | **$** | **517,600** | ** ** | ** ** |   | **$** | **1,054,417** |   |
|              |            |                                     |             |                                  |            |                                            |            |                          |            |                              |            |                       |            |                             |             |                                                |            |                                                         |            |                                           |               |  |  |  |  |  |  |  |  |  |

 

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*(1)**      **Details of DSU holdings are set out in the table on page 137.*

*(2)**      **Mr. O’Neill is the Audit Committee Chair.*

 

136

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**Share Ownership Guideline**

 

Oneway our directors demonstrate their commitment to Nexen’s success is throughshare ownership. On February 14, 2008, the board approved guidelines fordirectors to own or control at least 16,800 shares or DSUs. This amount representsat least three times both the base annual board retainer of $35,000 and thevalue of the base annual DSU grant. Directors must accumulate DSUs as follows:

 

·      5,600 by year 1

·      11,200 by year 2

·      16,800 by year 3

 

Newdirectors, if eligible, are required to take their annual retainer in DSUsuntil the current threshold is met. Eligibility is based on country ofresidence and Mr. Berry, as a US resident, is not eligible to take hisannual retainer in DSUs. If there is a change in share value or number of DSUsgranted that affects a director’s ability to meet the requirement, he or shewill have nine months to meet the threshold again.

 

Alldirectors surpass these guidelines.

 

**DeferredShare Units**

 

Nexenhas two DSU plans. Under the first plan, eligible directors may elect annuallyto receive all or part of their fees in DSUs, rather than cash. The second planwas implemented in 2003 and replaced stock options as the long-term incentiveto align director and shareowner interests.

 

DSUsprovide directors with a stake in Nexen while they serve on the board. DSUs donot have voting rights as there are no shares underlying the plans. A DSU is abookkeeping entry that tracks the value of one Nexen common share. When cashdividends are paid on our common shares, eligible directors are credited DSUsequal to the dividend. DSUs accumulate over a director’s term of service andare only paid when the director leaves the board. Then, at Nexen’s option,payments may be made in cash or in Nexen common shares purchased on the openmarket.

 
| **Name**     | ** ** | **DSUs Held as of December 31, 2008(1)** | ** ** |
|--------------|------------|------------------------------------------------------------------------|------------|
| Berry        |       | 5,000                                                                  |       |
| Flanagan     |       | 35,660                                                                 |       |
| Hentschel    |       | 35,656                                                                 |       |
| Jackson      |       | 48,145                                                                 |       |
| Jenkins      |       | 48,789                                                                 |       |
| McLellan     |       | 26,943                                                                 |       |
| Newell       |       | 57,824                                                                 |       |
| O’Neill |       | 45,618                                                                 |       |
| Saville      |       | 46,117                                                                 |       |
| Thomson      |       | 72,672                                                                 |       |
| Willson      |       | 48,200                                                                 |       |
| Zaleschuk    |       | 37,430                                                                 |       |

 

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*(1)**      **Number of DSUs has been adjusted to account for Nexen’sshare splits that occurred in May 2005 and May 2007.*

 

Mr. Bertramwas appointed to the board on January 1, 2009 and received a grant of5,000 DSUs. The effective date of the grant was January 2, 2009 with abase price of $21.45 per DSU, which was the closing market price of Nexencommon shares on the TSX on December 31, 2008. The value of the DSU grant was$107,250. Mr. Berry was appointed to the board on December 8, 2008and received DSUs as set out in the table above.

 

**TOPsExercised or Exchanged and Awards Vested During 2008**

 

In2008, no tandem options (TOPs) were exercised or exchanged by the board, whichdemonstrates that directors are holding TOPs for the long-term—consistentwith our long-term strategy—and not for short-term purposes. Under the DSUplan, there are no vesting provisions and no value realized on vesting.

 

**COMPENSATIONCOMMITTEE REPORT**

 

TheCompensation Committee assists the board in overseeing key compensation andhuman resource policies, CEO and executive compensation, and executivemanagement succession and development. The Committee reports to the board, asset out in its mandate, and the board or independent directors give finalapproval on compensation matters.

 

AllCommittee members are independent and knowledgeable in our compensationprograms and their long-term implications. Five members are skilled or expertin compensation—expertise most relevant to the Committee’s mandate.

 

**Changes toCommittee Membership in 2008**

 

TheCommittee membership did not change in 2008.

 

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**CommitteeWork Plan**

 

TheCommittee held seven meetings and sessions without management present in 2008.While each meeting agenda is subject to change as business needs arise, thetiming of the Committee’s main activities are provided in this table.

 
| **Agenda Items**                                                                                                                                                                                                                                                                                                                                                                                                                                      | ** ** | ** **         | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|
| Approved  compensation disclosure and Committee report in the proxy circular   Recommended the prior year’s incentive bonus plan pay-out factor  Recommended the current year’s bonus performance target and compensation  program   Reviewed CEO’s prior year accountabilities and results, and provided a bonus  recommendation   Reviewed CEO’s current year accountabilities recommendations and provided a  salary recommendation |       | February 2008 |       |
| Reviewed  competitive analysis of long-term incentive program                                                                                                                                                                                                                                                                                                                                                                                              |       | July 2008     |       |
| Reviewed market  activity update   Reviewed workforce plan                                                                                                                                                                                                                                                                                                                                                                                                 |       | October 2008  |       |
| Recommended  long-term incentive grants   Reviewed market activity update   Reviewed succession and development plan                                                                                                                                                                                                                                                                                                                                       |       | December 2008 |       |
| In camera  meetings                                                                                                                                                                                                                                                                                                                                                                                                                                        |       | At each  meeting   |       |

 

**KeyActivities in 2008**

 

Thekey activities reviewed and recommended during the year are outlined below.

 

·      Compensation programs andbudgets for base salary, annual cash and long-term incentives (Tandem OptionPlan (TOPs) and Stock Appreciation Rights Plan (StARs));

·     Salaries, bonuses and grantsof TOPs to the executives;

·     Retention programs for keybusiness initiatives;

·     CEO performance onshort-term and long-term corporate goals and objectives;

·     CEO compensation, which wasapproved by the independent directors of the board;

·     CEO’s annual objectives andour executive management succession and development plans;

·     CEO and CFO appointments andcompensation;

·     Directors’ annual deferredshare unit grants;

·     Impact of currentcompensation on change of control agreements;

·     Employee benefit plans;

·     Competitive updates oncompensation programs, market forecasts and workforce planning;

·     Executive compensationdisclosure and Committee report for the proxy circular; and

·     Canadian SecuritiesAdministrators’ new rules on executive compensation disclosure for theproxy.

 

**OutsideConsultant**

 

TheCommittee engaged Mercer (Canada) Limited (Mercer) to confidentially report andanalyze market data on the CEO’s compensation, in light of our operations andcompensation programs. Mercer also provided a compensation report on a selectgroup of our executives. The reports included competitive information from alist of peer companies recommended by Mercer. The Committee’s decisions are itsresponsibility and may reflect factors other than the information andrecommendations provided by Mercer and management.

 

Mercerdid not provide compensation consulting services to management in 2008. Weparticipated in compensation surveys in Canada and internationally, andpurchased select published results. Management must obtain Committee approvalbefore retaining Mercer for consulting services.

 

**Fees Billedby Outside Consultant (Mercer)**

 
| **Type of Fee**                                         | ** ** | **Billed in 2007** | ** ** | **Billed in 2008** | ** ** | **Percentage  of Total  Fees Billed  in 2008** | ** ** |
|-------------------------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|---------------------------------------------------------------|------------|
| Committee Work—assessment of CEO and  executive compensation |       | 49,610                       |       | 58,900                       |       | 100                                                           | %          |
| Management Work—consulting services                          |       | —                       |       | —                       |       | —                                                        |       |
| **Total Annual Fees**                                             | ** ** | **49,610**                   | ** ** | **58,900**                   | ** ** | **100**                                                       | **%**      |

 

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**ExternalRecognition and Verification**

 

Nexenwas recognized in 2008 by Benefits Canada magazine for having one of Canada’s30 Best Pension and Benefits Plans.

 

**CommitteeApproval**

 

TheCommittee has reviewed and discussed with management the compensationdisclosure in this document, including the information in the Board ofDirectors section (pages 135 to 136), the Compensation Discussion andAnalysis section (pages 139 to 147) and the Executive Compensation section(pages 147 to 157). It has recommended to the board that the disclosure beincluded in the circular and, as appropriate, the Form 10-K.

 

**Submittedon behalf of the Compensation Committee:**

 

KevinJenkins, Chair

FrancisSaville

BarryJackson

DickThomson

AnneMcLellan

JohnWillson

TomO’Neill

 

**COMPENSATIONCOMMITTEE INTERLOCKS AND INSIDER PARTICIPATION**

 

Themembers of the Compensation Committee are set out on page 134.Mr. Saville had a relationship requiring disclosure, the details of whichare set out under “Certain Relationships and Related Transactions, and DirectorIndependence” on page 161. There are no Compensation Committee interlocksduring 2008.

 

**COMPENSATIONDISCUSSION AND ANALYSIS**

 

Ourcompensation disclosure complies with the requirements of the CanadianSecurities Administrators. As a foreign private issuer in the US, we are notrequired to disclose compensation according to the SEC rules, but we attempt tocomply with the spirit of those rules where possible, without compromisingrequired Canadian disclosure.

 

**CompensationPhilosophy**

 

Ourpolicies and practices for executive compensation are linked to strategicbusiness objectives, including increasing shareowner returns. Our philosophy isto compensate executives: 

 

·  basedon performance;

·  ata level competitive with our peers; and

·  ina manner designed to attract and retain talented leadership focused on managingNexen’s operations, finances and assets.

 

Allof our compensation programs are designed to meet pay-for-performance andcompetitiveness objectives. Actual rewards are directly linked to the resultsof Nexen and our divisions. The objective and subjective performance measuresare aligned with shareowner interests, and financial and non-financial goals.Measures set each year represent improvements and growth to our operationsrelative to prior years.

 

Ourprograms are responsive to market changes. We aim for simplicity in ourcompensation programs to help employees understand the value of the variouscomponents and how they can contribute to business results. 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 businessneeds and objectives.

 

Benchmark Review

 

Weuse third-party compensation surveys to compare our pay levels and practices,including base pay, annual cash incentives and long-term incentives, to ourpeers. We look at Canadian-based oil and gas and integrated pipeline companieswith whom we compete for talent. Given similar positions across the industry,the surveys effectively represent competitive pay levels. It should be noted,however, we do not know the extent to which our peers participate in thesurveys and benchmark each position. The peer groups are modified over time toreflect: (i) geographical location, (ii) a particular business line,(iii) a more comparable position, or, (iv) industry mergers andacquisitions.

 

Ourpeer groups are reviewed annually by third-party consultants and theCompensation Committee for continued relevance. In 2008, our executive peergroup consisted of the following 16 major oil and gas and integrated pipelinecompanies:

 
| BP Canada Energy Company           |   | Husky Energy  Inc.       |   |
|------------------------------------|--------|--------------------------|--------|
| Canadian Natural Resources Limited |   | Imperial Oil  Limited    |   |
| Chevron Canada Resources           |   | Petro-Canada             |   |
| ConocoPhillips Canada              |   | Shell Canada  Limited    |   |
| Devon Canada Corporation           |   | Suncor  Energy Inc.      |   |
| Enbridge Inc.                      |   | Syncrude  Canada Limited |   |
| EnCana Corporation                 |   | Talisman  Energy Inc.    |   |
| ExxonMobil Canada                  |   | TransCanada  Corporation |   |

 

Forthe CEO, the peer group is a subset of the 16 peer companies. This peer groupfocuses on the major Canadian-based and independent oil and gas companies thathave more comparable CEO positions.

 

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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**

 

Ourcompensation programs include three elements: base salary, annual cashincentive and long-term incentive. At least once a year, we assess thecompetitiveness of these individual components and the overall compensationlevels. Our goal is to provide total compensation for fully qualified andperforming employees between the 50th and 75th percentile as compared to ourpeers. Top-performing employees will approach the 75th percentile as theycontinue to accumulate knowledge and experience, which is accompanied by sustainedhigh performance.

 

**KeyElements 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         |       |

 

Pay Mix

 

Sinceour compensation programs are designed to meet both performance andcompetitiveness objectives, actual pay will vary from year to year within ourpay mix. In general, the programs are designed to provide most executivecompensation in the form of at-risk pay to ensure alignment with shareowners.Base salary provides a competitive foundation considering both internalcomparability and external market data. Annual cash incentives reward thedelivery of results against objective and subjective measures within a one-yearperiod. Long-term incentives reward Nexen’s sustained performance as seen inshare price appreciation. The actual mix between the compensation elementsvaries, depending on the executives’ ability to influence short and long-termbusiness results, their level and competitive local market practices.

 
| ** **    | ** ** | ** **       | ** ** | **At-Risk Compensation(1)** | ** ** |
|---------------|------------|------------------|------------|----------------------------------|------------|
| **Position**  | ** ** | **Base  Salary** | ** ** | **Annual  Cash Incentive**       | ** ** | **Long-Term  Incentive** | ** ** |
| CEO           |       | 15               | %          | 20                               | %          | 65 | % |
| CFO           |       | 25               | %          | 20                               | %          | 55 | % |
| Executive VPs |       | 25               | %          | 20                               | %          | 55 | % |
| Senior VPs    |       | 30               | %          | 20                               | %          | 50 | % |

 

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*(1)**      **Represents the percentage of total compensation, excludingbenefits, pension and perquisites averaged over a three-year period.*

 

**CompensationApproval Process**

 

 

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Indetermining our executives’ base salary, annual cash and long-term incentives,the Compensation Committee considers a comprehensive analysis, including atally sheet prepared by management with input from an executive compensationconsultant. The analysis includes market data for similar positions within thepeer group and CEO recommendations for his direct reports, including all of theother named executive officers (executives), and information on prior yearannual cash and long-term incentives. The basic design of our short andlong-term incentive programs mitigates the need to present various performancescenarios to show impact on payout levels. However, before approvingmanagement’s compensation recommendations, the Committee discusses a variety ofscenarios, including analysis of various annual cash incentive payout factorsand the impact of share price variation on our long-term incentive program. Formore complex programs, such as pension, management provides the Committee witha sensitivity analysis that considers the pension cost implications for each 1%of incremental pensionable earnings.

 

TheCommittee reviews the three compensation elements both individually, and intotal, to ensure they align with the program objectives. In addition, theCommittee retains the services of its own executive compensation consultant,Mercer, to provide external market data and commentary on the relativepositioning of executives, particularly the CEO. The Committee then makesrecommendations on all executive payments and grants to the board orindependent directors for approval. Typically, this process begins in the falland concludes with total compensation being approved the following February.

 

**BaseSalaries**

 

Todetermine base salaries, a framework of job levels based on internalcomparability and external market data is used. We also consider theindividual’s current and sustained performance, skills and potential.

 

**Annual CashIncentives**

 

Theprogram provides an opportunity for competitive bonus compensation thatreflects Nexen’s overall and division performance and that of the individual.Variable compensation links Nexen’s business results and the executives’performance, consistent with our pay-for-performance philosophy. The increasein the executives’ annual cash incentives in 2008 reflects the board’sassessment of our relative level of success on certain business objectives.

 

**2008 Annual Incentive Measures**

 

Afterreviewing Nexen’s objective and subjective performance measures, the board, atthe recommendation of the Compensation Committee, approves the payout factor.The payout factor determines the cash pool available for annual cash incentivesand may range from 0 to 200%. The factors used were 120% in 2006, 88% in 2007and 120% in 2008.

 

2008Objective Performance Measures (50%)

 

Thesekey financial measures are consistent with our annual operating plan.

 
| **Measure**      | ** ** | **Target** | ** **    | **Results** | ** ** | **Results versus Target** | ** ** |
|------------------|------------|------------|---------------|-------------|------------|-------------------------------------|------------|
| Cash flow (25%)  |       | $          | 2,912 million |        | $          | 4,229 million                       |       | 145 | % |
| Net income (25%) |       | $          | 1,330 million |        | $          | 1,715 million                       |       | 129 | % |

 

**2008 Subjective PerformanceMeasures (50%)**

 

TheCompensation Committee subjectively considers a combination of quantitative andqualitative measures. The individual measures are not assigned a fixedweighting. This allows the Committee to exercise its discretion and increase ordecrease the payout factor when assessing our overall performance. Itsdiscretion ensures the award is not unduly impacted by an unusual result in anyone area. The business measures that the Committee considers are commonly usedin our industry. They include, among other measures, stock performance, annualstock performance against peers, production volumes, safety and environmentalincidents, and reserve-related metrics. The Committee also assesses costs,including finding and development, operating and administrative. The businessmeasures are assessed against objectives in light of our external environmentand current business circumstances, including key projects and initiativescritical to Nexen’s success. Both absolute performance and performance relativeto peers are reviewed. The Committee also considers management’s assessment ofNexen’s performance and progress against the strategic plan.

 

IfNexen does not achieve the minimum pre-determined performance level of any componentof the objective measures, no allocation will be made for that component in theoverall assessment of the payout factor. The Committee’s assessment of thesubjective measures could also result in a decrease of the payout factor.Alternatively, exceptional performance in our objective and subjective measuresmay be rewarded with a 200% payout factor, which is the maximum allowed underthe annual incentive plan. Exceptional performance means that we exceeded

 

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ourobjective measure targets by at least 25%. For 2008, the Committee consideredthat Nexen’s overall performance exceeded target. Record financial results andstrong relative share price performance were balanced against disappointingresults from the Marketing division and impairment charges.

 

**ANNUAL CASHINCENTIVE PAYOUT**

 

Thecash pool available for annual incentives is then allocated to employees andexecutives based on individual incentive target levels and performance. Thetargets for individual awards increase as job responsibilities grow so that theratio of at-risk versus fixed compensation is greater for higher levels ofresponsibility. Individual performance is assessed by the direct supervisor andreflects performance against pre-determined objectives. The actual incentiveaward received by the individual may be more or less than target level.Typically, annual incentive awards range from 0 to 200% of the target for thatposition.

 

**2008 AnnualIncentive Targets(1)**

 
| **Position**  | ** ** | **Minimum** | ** ** | **Target** | ** ** | **Maximum** | ** ** |
|---------------|------------|-------------|------------|------------|------------|-------------|------------|
| CEO(2)        |       | 0           | %          | 80         | %          | 160         | %          |
| CFO(3)        |       | 0           | %          | 60         | %          | 120         | %          |
| Executive VPs |       | 0           | %          | 60         | %          | 120         | %          |
| Senior VPs    |       | 0           | %          | 45         | %          | 90          | %          |

 

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*(1)**      **Reflects percentage of base salary on December 31,2008.*

*(2)**      **The target decreased to 75% and the maximum to 150%effective January 1, 2009 with the appointment of the new CEO.*

*(3)**      **The target decreased to 50% and the maximum to 100%effective January 1, 2009 with the appointment of the new CFO.*

 

Reimbursement

 

If,as a result of misconduct, Nexen’s performance results were restated in a waythat decreased the incentive awards, the CEO and CFO would reimburse Nexenproportionately as required by law.

 

WhileNexen is aligned and committed to the US requirements for clawbacks, we areconsulting with industry leaders and shareholder advisory groups to betterunderstand the development of clawback policy models in Canada. Identifiedbarriers to implementation include employment law, enforcement and tax issues.Nexen is working to implement a more formal solution that effectively addressesalignment of shareowner and executive interests by ensuring that compensationis not increased as a result of willful misconduct.

 

**SHAREPERFORMANCE GRAPH**

 

Whileshare performance is not the only indicator of pay levels, a more directalignment can be seen with our annual incentive program and the value realizedby employees participating in our long-term incentive programs. There has notbeen a direct correlation between base salary levels and Nexen shareperformance. The sharp increase to our share price from 2004 to 2005 isconsistent with the company’s strong performance year in 2005. The result was apayout factor of 200% for the annual incentive program. The less dramaticmovement in our share price in subsequent years is partially reflected by our payoutfactors declining to 120% in 2006 and 88% in 2007. As indicated by the downwardmovement in the graph, the turbulence in the global financial markets in 2008has impacted Nexen’s share price, not unlike other publicly traded companies.While this is unfavorable, our share performance captured in this graphreflects a point in time and is generally consistent with organizations in oursector for 2008. In 2008, our performance exceeded target, including financialresults and strong relative share performance. These successes were balanced bydisappointing results from the Marketing division and impairment charges. Theresulting payout factor for 2008 was 120%. For long-term incentives, thedownward shift in our share price has significantly decreased the in-the-moneyvalue.

 

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Thefollowing graph shows the change in a $100 investment in Nexen common sharesover the past five years, compared to the S&P/TSX Composite Index, theS&P/TSX Energy Sector Index and the S&P/TSX Oil & Gas Exploration& Production Index as at December 31, 2008. Our common shares are includedin each of these indices.

 

 

**TotalReturn Index Values(1)**

 
| ** **                                                                     | ** ** | **2003/12** | ** ** | **2004/12** | ** ** | **2005/12** | ** ** | **2006/12** | ** ** | **2007/12** | ** ** | **2008/12** | ** ** |
|--------------------------------------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|
|  ·  Nexen  Inc.                                            |       | 100.00      |       | 104.63      |       | 239.28      |       | 278.11      |       | 279.00      |       | 187.59      |       |
|   S&P/TSX  Oil & Gas Exploration & Production Index |       | 100.00      |       | 140.68      |       | 244.28      |       | 247.51      |       | 272.59      |       | 188.70      |       |
|  ·  S&P/TSX Energy Sector Index                        |       | 100.00      |       | 130.29      |       | 212.94      |       | 225.84      |       | 244.43      |       | 161.63      |       |
|   S&P/TSX  Composite Index                                       |       | 100.00      |       | 114.48      |       | 142.10      |       | 166.63      |       | 183.01      |       | 122.61      |       |

 

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*(1)**      **Assuming an investment of $100 and the reinvestment ofdividends.*

 

**ShareOwnership Guideline**

 

Allexecutive officers demonstrate their commitment to Nexen by holding more sharesthan required under our board-approved guideline. Shares must be accumulatedwithin five years from the date the executive was appointed. Share ownershipincludes the net value of exercisable options or TOPs, flow-through shares,shares purchased and held within the Nexen employee savings plan and any otherpersonal holdings. The guideline is reviewed periodically by the CompensationCommittee and the board. See page 153 for the current share ownership ofeach executive.

 
| **Position**             | ** ** | **Required Share Ownership** | ** ** |
|--------------------------|------------|----------------------------------------|------------|
| CEO                      |       | Three times  annual salary             |       |
| CFO                      |       | Two times  annual salary               |       |
| Other executive officers |       | One times  annual salary               |       |

 

**Long-TermIncentives**

 

Nexen’slong-term incentive program, the TOPs and StARs plans, provide employees with along-term incentive to sustain high performance, demonstrate commitment toNexen and, most importantly, align their interests with those of ourshareowners. As Nexen’s share price rises, grants increase in value. TOPs or StARsare granted to employees, based on internal organization levels, whose actionscan most directly impact our business results. Named executives are grantedTOPs.

 

Indetermining the number of TOPs and StARs to grant each year, Nexen considersthe program’s dilutive impact on shareowners and market information on stockoptions and other forms of long-term incentives. Market information alsodetermines the extent to which employees at different levels participate in theprogram. The Compensation Committee reviews and recommends TOPs plan amendmentsfor the board to approve. Management and the Compensation Committee continue toconsider alternative long-term incentive programs used by our peers, includingfull-value plans such as DSUs, restricted share units and performance-basedstock options. At this time, TOPs and StARs continue to best meet Nexen’sobjectives, considering competitive position, retention value, taxeffectiveness for both our employees and Nexen, shareowner interests, anddilution levels.

 

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TOPs Plan

 

OurTOPs plan has been in place since 2004. It allows employees to either:

 

·      exchange their vested TOPsfor a cash payment equal to the difference between the grant price and theclosing market price of our common shares on the date the TOPs were exchanged;or

·      exercise their TOPs forshares. Nexen common shares are issued for TOPs on a one-for-one basis.

 

Whenemployees exchange their TOPs for cash: (i) no shares are issued, whichprevents further shareowner dilution over time; and (ii) Nexen receives aCanadian income tax deduction.

 

**2008 TOPsPlan Exercises and Exchanges**

 
| **Total Exercised   or Exchanged** | ** ** | **Exercised for Shares  (Percent)** | ** ** | **Exchanged for Cash  (Percent)** | ** ** |
|----------------------------------------------|------------|-----------------------------------------------|------------|---------------------------------------------|------------|
| 5,749,570                                    |       | 1,910,488                                     | (33)%      | 3,839,082                                   | (67)%      |

 

TOPsdo not provide employees with the right to vote the underlying shares. The TOPsplan is Nexen’s only equity-based compensation arrangement for the purposes ofdisclosure requirements.

 

Theboard, on the recommendation of the Compensation Committee, may grant TOPs toNexen officers and employees. TOPs granted before February 2001 have a term often years; 20% of the grant vested after six months and 20% vested each yearfor four years on the grant’s anniversary. TOPs granted afterFebruary 2001 have a term of five years and vest one-third each year forthree years. The board has the discretion to set vesting periods within thefive-year term. To allow for the exceptional circumstances of the retirement ofNexen’s CEO in 2008, the CEO’s 2008 TOPs grant was reduced and the vesting setat one-half each year for two years. Normal retirement provisions in the planapply and will result in the expiry and cancellation of 50% of this grant.

 

Generally,if a change of control event occurs (as defined in the TOPs plan), all issuedbut unvested options will vest.

 

StARs Plan

 

TheStARs plan, introduced in 2001, provides a cash payment to participants equalto the appreciation in Nexen’s share price between the date the StARs aregranted and the date they are exercised. StARs are typically granted toemployees below mid-level department manager. They have a five-year term andvest one-third each year for three years.

 

Grant Date and ExercisePrice

 

TOPsand StARs are granted during the annual grant process and at the time of hiringkey positions. Since 1998, the annual grants have been approved at theDecember board meeting. According to our plans, the CEO can approve grantsto key new hires and typically they occur shortly after the hire date. Underthe plans, the exercise price is the closing market price of Nexen’s commonshares on the relevant stock exchange (TSX for Canadian-based employees or NYSEfor US-based employees) on the day before the grant is approved. Accordingly,backdating is not allowed. Nexen’s grants are not intentionally timed to occurimmediately prior to the release of material information (spring-loaded). Theexercise price of existing TOPs or StARs may not be reduced except forautomatic adjustments, such as a share split, or according to TSX rules.Accordingly, repricing is not allowed.

 

Options Outstanding andShares Reserved for Issue

 

Welimit the combined annual grants of TOPs and StARs (even though StARs are notdilutive) to less than 2% of total outstanding shares (on a non-diluted basis).The total TOPs granted, plus shares reserved for future issue underequity-based compensation programs, will not exceed 10% of our totaloutstanding shares (on a non-diluted basis). Since the implementation of thetandem feature in 2004, 9,788,475 shares have been issued at December 31,2008, representing 1.9% dilution.

 

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Grants in the Last ThreeYears

 

Our2008 long-term incentives recognized employees for high performance, futurepotential within Nexen and retention risk.

 
| **Year**  | ** ** | **Granted to  Executive Officers** | ** ** | **Granted to  Employees** | ** ** | **Percentage  of Employees  Receiving Grants** | ** ** | **Total Number  Granted** | ** ** |
|-----------|------------|----------------------------------------------|------------|--------------------------------|------------|----------------------------------------------------------|------------|--------------------------------|------------|
| **TOPs**  |       |                                         |       |                           |       |                                                     |       |                           |       |
| 2008      |       | 1,526,000                                    |       | 2,008,100                      |       | 6                                                        | %          | 3,534,100                      |       |
| 2007      |       | 1,735,000                                    |       | 2,272,100                      |       | 7                                                        | %          | 4,007,100                      |       |
| 2006(1)   |       | 1,480,000                                    |       | 3,321,000                      |       | 7                                                        | %          | 4,801,000                      |       |
| **StARs** |       |                                         |       |                           |       |                                                     |       |                           |       |
| 2008      |       | —                                       |       | 4,917,200                      |       | 53                                                       | %          | 4,917,200                      |       |
| 2007      |       | —                                       |       | 4,194,600                      |       | 54                                                       | %          | 4,194,600                      |       |
| 2006(1)   |       | —                                       |       | 4,508,600                      |       | 51                                                       | %          | 4,508,600                      |       |

 

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*(1)**      **Numbers of TOPs and StARs granted have been adjusted toaccount for Nexen’s two-for-one share splits in May 2005 andMay 2007.*

 

**Benefit andPension Plans**

 

Ourbenefit and pension plans support the health and well-being of our employees,and encourage retirement savings. The plans are reviewed periodically to ensurethey remain competitive and continue to meet our objectives. Market survey datais reviewed to ensure the plans provide benefits between the 50th and 75thpercentile of plans within our peer group. Executives participate in the sameplans provided to all employees at the same location.

 

Disclosurein this document is specific to the Canadian plans in which the executivesparticipate. Nexen provides a variety of other benefit and pension plansoutside of Canada that reflect local market practices.

 

Health and Welfare Benefits

 

Ourbenefit plans are designed to protect employees’ health and that of theirdependents, and cover them in the event of disability or death. Under theflexible benefit plans, employees choose the level of coverage that best fitstheir needs. Those who select enhanced coverage levels are required tocontribute to the cost of that coverage.

 

Employee Savings Plan

 

Tohelp employees save for their future and encourage ownership in the company,Nexen provides the incentive and opportunity to accumulate savings through anemployee savings plan. In the plan, all eligible Canadian employees maycontribute, through payroll deduction, any percentage of their base salary topurchase Nexen common shares, mutual fund units or a combination of both. Nexenmatches employee contributions up to 6% of base salary, depending on theinvestment option and how long the employee has participated in the plan. Nexencontributions are invested in our common shares purchased on the open marketand vest immediately. All contributions may be allocated to registered ornon-registered accounts. Employees may vote the Nexen common shares they holdin their employee savings plan.

 

Defined Benefit Pension Plan

 

Canadianemployees of Nexen elect, upon hire, to participate in either the definedcontribution pension plan or the defined benefit pension plan, both of whichare registered. All named executives participated in the defined benefitpension plan in 2008. Features of the plan are:

 
| · | participant contributions at 3% of their regular gross  earnings (up to an annual plan maximum);                                                                                                                       |
|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| · | retirement benefits at 1.8% (1.7% for years prior to 2005)  of their average earnings for the 36 highest-paid consecutive months during  the ten years before retirement, multiplied by the years of credited service; |
| · | integration with Canada Pension Plan (CPP) to provide a  maximum offset of one-half of the current CPP benefit, prorated by years of  credited service to a maximum of 35 years;                                       |
| · | benefits on retirement that are generally paid monthly for  the life of the retiree, subject to payment elections;                                                                                                     |
| · | members who retire after 10 years of service are eligible  for an early retirement benefit at age 55, with a 4% per year early  retirement reduction for each year that benefits commence prior to age 60;  and        |
| · | ability for participants to periodically switch between  the defined benefit pension plan and defined contribution pension plan at  different stages in their career.                                                  |

 

Planparticipants may annually elect to increase their defined benefit accrualformula from 1.8% to 2%. Employees who choose this option must contribute anadditional 2% of pensionable earnings up to an allowable maximum under theCanadian

 

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Income Tax Act. The maximumemployee contribution allowed under the defined benefit pension plan in 2008was $11,200.

 

The normalform of benefit paid is a joint life and survivor benefitwith a five-year guarantee. It is payable for the participant’s life-time andprovides the spouse with a survivor benefit of 662/3%of the monthly payment. If the participant dies before receiving 60 monthlypayments, the five-year guarantee allows the surviving spouse to receive thebalance of the 60 monthly payments first and then the reduced survivor pensionof 662/3%.

 

Pensionbenefits earned prior to January 1, 1993 may be indexed at the discretion ofmanagement’s pension committee, considering increases in the consumer priceindex. Pension benefits earned after December 31, 1992 are indexed annuallybetween 0 and 5% based on the greater of:

 

·             75%of the increase in the consumer price index, less 1%; and

·             25%of the increase in the consumer price index.

 

*Pension Benefit Obligation*

* *

At December 31, 2008, as indicated in the notes toour consolidated financial statements, the:

 

·    registered pension plan’s accumulatedbenefit obligation (the projected benefit obligation, excluding future salaryincreases) for the defined benefit  planwas $179 million, which includes all active and inactive plan participants; and

·    projected benefit obligation was $203million.

 

The projected benefit obligation is anaccounting-based value of the contractual entitlements that will change overtime. The method used to determine this estimate will not be identical to thoseused by others and, as a result, the estimate may not be directly comparableacross companies. The key assumptions used for the projected benefit obligationwere:

 

·             adiscount rate of 5.25% per year as at December 31, 2007;

·             adiscount rate of 6.5% per year as at December 31, 2008;

·             along-term compensation rate increase of 4% per year; and

·             anassumed rate of inflation of 2.5% per year.

 

Executive Benefit Plan

 

Theexecutive benefit plan is available to all Canadian employees. It providessupplemental retirement benefits for either defined benefit or definedcontribution participants who have earned a retirement benefit in excess of thestatutory limits, which varies by employees’ pension elections. This allows employeesto fully accrue a pension that is aligned with their earnings level and iscompetitive within our market. For defined benefit plan participants, anysupplemental benefits will accrue and be paid monthly in a similar manner tothe underlying defined benefit pension plan set out above on pages 145 and 146.For executives, annual cash incentive payments during the last three years ofplan participation are included for benefit accrual purposes, based on thelesser of target bonus or actual bonus paid.

 

*PensionBenefit Security*

 

Thepension expense for this supplemental plan is accounted for annually. Benefitsare paid from Nexen’s cash flows and reduce the related pension liability. Asliabilities under this plan are unfunded, a level of protection is provided toparticipants through a letter of credit. The letter of credit is intended tomake participants secured creditors for the unfunded pension obligation underthe executive benefit plan. The cost of servicing the letter of credit in 2008for all plan participants was $917,237.

 

*PensionBenefit Obligation*

 

AtDecember 31, 2008, as indicated in the notes to our consolidated financialstatements, the: 

 

·             supplementalpension plan’s accumulated benefit obligation (the projected benefitobligation, excluding future salary increases) for the executive benefit planwas $49 million, which includes all active and inactive plan participants; and

·             projectedbenefit obligation was $62 million.

 

Theprojected benefit obligation and key assumptions used for the projected benefitobligation are the same as those used for the registered pension plan.

 

Asof January 1, 2005, the executive benefit plan was amended to provide asupplemental pension allocation for defined contribution pension planparticipants who are impacted by annual statutory contribution limits. In 2008,the sum of all supplemental allocations for eligible participants was $50,061and is estimated to be $53,000 in 2009.

 

146

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Retirement Benefits

 

AllNexen retirees are provided with retirement benefits that consist of a $5,000life insurance policy and reimbursement for provincial healthcare premiums, ifapplicable.

 

Loans to Officers

 

Asset out in the corporate governance policy, we do not make loans to officers.There are no loans outstanding from Nexen to any of its officers.

 

**EXECUTIVEOFFICERS**

 

Theboard determines the term of office for each executive officer. Below areNexen’s officers, including prior offices and non-executive positions forofficers who have held their current executive positions with Nexen for lessthan five years. 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** |
|----------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------|------------|-----------------------------------|
| Marvin F. Romanow (53)     |       | President and CEO and a director.   Formerly: Executive VP and CFO since June 1, 2001.                                                                                                                                                                     |       | January 1, 2009                                       |       | 1997                              |
| Kevin J. Reinhart (50)     |       | Senior VP and CFO.   Formerly: Senior VP, Corporate Planning and Business Development since  November 1, 2007.   Formerly: VP, Corporate Planning and Business Development since July 11,  2002.                                                      |       | January 1, 2009                                       |       | 1994                              |
| Laurence Murphy (57)       |       | Executive VP, International Oil and Gas.   Formerly: Senior VP, International Oil and Gas since January 1, 1999.                                                                                                                                           |       | November 1, 2007                                      |       | 1998                              |
| Roger D. Thomas (56)       |       | Executive VP, North America.   Formerly: Senior VP, Canadian Oil and Gas since February 19, 1999.                                                                                                                                                          |       | November 1, 2007                                      |       | 1998                              |
| Gary H. Nieuwenburg (50)   |       | Senior VP, Synthetic Crude.   Formerly: VP, Synthetic Crude since July 11, 2002.                                                                                                                                                                           |       | November 1, 2007                                      |       | 2001                              |
| Brian C. Reinsborough (47) |       | 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 (51)     |       | 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 (53)       |       | 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 (60)       |       | VP and Chief Information Officer.   Formerly: Division VP, Information Technology since January 1, 1992.                                                                                                                                                   |       | November 1, 2007                                      |       | 2007                              |
| Eric B. Miller (46)        |       | 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 (44)          |       | VP, Corporate Planning and Business Development.   Formerly: Treasurer since July 11, 2002.                                                                                                                                                                |       | January 16, 2009                                      |       | 1998                              |
| Brendon T. Muller (40)     |       | Controller.   Formerly: Manager, Corporate External Reporting since November 1, 2003.                                                                                                                                                                      |       | April 9, 2007                                         |       | 2007                              |
| J. Michael Backus (38)     |       | Treasurer.   Formerly: Manager, Planning, Synthetic Crude since January 1, 2009;  Project Planner — Phase 2 Long Lake, Synthetic Crude since April 1,  2005; Analyst, Investor Relations and Corporate Communications since  April 1, 2003. |       | February 16, 2009                                     |       | 2009                              |

 

147

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**SHARESPLITS**

 

Allgrant prices and numbers granted have been adjusted to account for theMay 2005 and May 2007 share splits.

 

**SUMMARYCOMPENSATION TABLE**

 

Todetermine the next three highest paid officers, after the CEO and CFO, we totaltheir salary, special bonus, non-equity cash incentive plan compensation,long-term incentive compensation and all other compensation as shown below.Grants of TOPs are considered option-based awards under applicable disclosurerequirements. We do not award share-based awards or non-equity incentive plancompensation under long-term incentive plans, as these terms are used inapplicable disclosure requirements.

 
| ** **                                 | ** ** | ** ** | ** ** | ** **              | ** ** | **Option-Based**      | ** ** | ** **              | ** ** | ** **                                                               | ** ** | ** **                       | ** ** | ** **                          | ** ** | ** **                   |   |
|--------------------------------------------|------------|------------|------------|-------------------------|------------|-----------------------|------------|-------------------------|------------|--------------------------------------------------------------------------|------------|----------------------------------|------------|-------------------------------------|------------|------------------------------|--------|
| **Name and  Principal Position** | ** ** | **Year**   | ** ** | **Annual  Salary  ($)** | ** ** | **TOPs  Awards  (#)** | ** ** | **TOPs  Value(2)  ($)** | ** ** | **Non-Equity Incentive Plan  Compensation (1)(3)****($)** | ** ** | **Pension  Value (4)  ($)** | ** ** | **All Other  Compensation(5)  ($)** | ** ** | **Total  Compensation  ($)** |   |
| Charles W.  Fischer,                       |       | 2008       |       | 1,348,750               |       | 400,000               | (6)        | 2,245,760               |       |                                                                     |       | 1,500,000                        |       | 938,800                             |       | 124,245                      |   | 6,157,555 |   |
| (Retired)  President                       |       | 2007       |       | 1,275,000               |       | 600,000               |       | 5,110,200               |       |                                                                     |       | 916,000                          |       | 949,300                             |       | 119,640                      |   | 8,370,140 |   |
| and CEO                                    |       | 2006       |       | 1,150,000               |       | 550,000               |       | 5,010,654               |       |                                                                     |       | 1,800,000                        |       | 1,673,800                           |       | 111,621                      |   | 9,746,075 |   |
| Marvin F.  Romanow,(7)                     |       | 2008       |       | 601,250                 |       | 475,000               |       | 2,747,514               | (8)        |                                                                     |       | 700,000                          |       | 317,800                             |       | 119,016                      |   | 4,485,580 |   |
| Executive VP                               |       | 2007       |       | 566,250                 |       | 180,000               |       | 1,533,060               |       |                                                                     |       | 330,000                          |       | 323,300                             |       | 117,129                      |   | 2,869,739 |   |
| and CFO                                    |       | 2006       |       | 528,000                 |       | 160,000               |       | 1,457,645               |       |                                                                     |       | 402,000                          |       | 534,800                             |       | 118,073                      |   | 3,040,518 |   |
| Laurence Murphy,                           |       | 2008       |       | 546,250                 |       | 170,000               |       | 921,536                 |       |                                                                     |       | 400,000                          |       | 285,800                             |       | 60,508                       |   | 2,214,094 |   |
| Executive VP,                              |       | 2007       |       | 495,833                 |       | 165,000               |       | 1,405,305               |       |                                                                     |       | 303,000                          |       | 583,300                             |       | 57,214                       |   | 2,844,652 |   |
| International Oil  & Gas               |       | 2006       |       | 455,000                 |       | 130,000               |       | 1,184,336               |       |                                                                     |       | 642,000                          |       | 580,800                             |       | 53,711                       |   | 2,915,847 |   |
| Roger D. Thomas,                           |       | 2008       |       | 542,500                 |       | 170,000               |       | 921,536                 |       |                                                                     |       | 436,000                          |       | 265,800                             |       | 60,188                       |   | 2,226,024 |   |
| Executive VP,                              |       | 2007       |       | 487,500                 |       | 165,000               |       | 1,405,305               |       |                                                                     |       | 275,000                          |       | 792,300                             |       | 56,690                       |   | 3,016,795 |   |
| North America                              |       | 2006       |       | 445,000                 |       | 130,000               |       | 1,184,336               |       |                                                                     |       | 336,000                          |       | 735,800                             |       | 53,086                       |   | 2,754,222 |   |
| Gary H.  Nieuwenburg,                      |       | 2008       |       | 416,500                 |       | 100,000               |       | 542,080                 |       |                                                                     |       | 365,000                          |       | 141,800                             |       | 52,670                       |   | 1,518,050 |   |
| Senior VP,                                 |       | 2007       |       | 360,667                 |       | 100,000               |       | 851,700                 |       |                                                                     |       | 191,000                          |       | 267,300                             |       | 48,775                       |   | 1,719,442 |   |
| Synthetic Crude                            |       | 2006       |       | 328,850                 |       | 100,000               |       | 911,028                 |       |                                                                     |       | 210,000                          |       | 284,800                             |       | 51,944                       |   | 1,786,622 |   |

 

----

| *(1)* | *Reflects the value of awards earned in  each year under Nexen’s annual cash incentive program. The awards are paid to  the executives in the following calendar year based on their salary on  December 31 of the previous year.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|-------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Reflects the estimated fair value under the Black-Scholes pricing  model of TOPs granted in the year. The key assumptions of this valuation  include current market price of the stock, exercise price of the option,  option term, risk-free interest rate, dividend yield of stock and volatility  of stock return. The actual value realized will depend on the Nexen share  price at the time of exercise. The accounting fair value is calculated using  the intrinsic value method, which is the difference between the market price  of the stock and the exercise price of the option. The difference between  these valuation methods is the TOPs value included in this column, as the  intrinsic value was nil at year end. Management’s consultant provides the  annual Black-Scholes value. There were no ammendments to the exercise price  of the TOPs in 2008.* |
| *(3)* | *For Messrs. Fischer, Romanow, Thomas  and Nieuwenburg, includes discretionary recognition in 2008 for a variety of  critical business initiatives. For Messrs. Fischer and Murphy, includes a  discretionary award in 2006 for the success of Buzzard of $500,000 and  $300,000 respectively.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| *(4)* | *Represents the current service cost, less  required member contributions to the plan, plus changes in compensation in  excess of actuarial assumptions.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
| *(5)* | *The total value of the perquisites  portion of All Other Compensation provided to each executive is less than  $50,000 and less than 10% of their annual salary. See the table on  page 155 for details of these amounts.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| *(6)* | *TOPs awarded to Mr. Fischer in  2008 have a two-year vesting period. As vested TOPs can be exercised up to 18  months after retirement, 50% of this grant will expire and be cancelled in  accordance with the provisions of the plan.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| *(7)* | *Mr. Romanow is a director of  Canexus and was paid fees of $34,000, received notional deferred trust units  of Canexus valued at $15,600 and distributions on his trust units of $6,399  in 2008. In 2007, he was paid fees of $32,500, received notional deferred  trust units of Canexus valued at $19,560 and distributions on his trust units  of $4,259. In 2006, he was paid fees of $34,000, received notional deferred  trust units of Canexus valued at $24,000 and distributions on his trust units  of $2,571. These amounts are included in the All Other Compensation table on  page 155.*                                                                                                                                                                                                                                                                    |
| *(8)* | *Mr. Romanow was appointed  President and CEO effective January 1, 2009 and received a grant of  295,000 TOPs upon appointment. The TOPs value of this grant is $1,771,770 and  the value of the 180,000 TOPs granted on December 8, 2008 is $975,744.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |

 

**Changes inCompensation Arrangements in 2008**

 

We did not introduce any newcompensation or benefit program in 2008 for Nexen’s named executives.

 

Asseen in the table above, the December 2008 TOPs awards expected values havedecreased from the prior years. While Nexen’s share price was falling duringthe time of grant, we did not feel it was necessary to increase the grant sizeto maintain the expected value year-over-year. Our 2008 program was designedwith a long-term perspective of share value and to avoid unintended windfallwhen financial markets recover.

 

Thecompensation paid to executives in 2008 is consistent with our philosophy andobjectives of targeting total compensation between the 50th and 75th percentileas detailed on pages 139 through 142.

 

148

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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,less required member contributions to the plan. Actual compensation changes mayvary from the assumed rate of compensation increase and will vary among eachexecutive from year to year. These values differ from the termination valuesreported under the change of control agreements on page 156 which discloseadditional lump sum pension benefits provided if a change of control occurs.

 

**CEOCOMPENSATION AND 2008 GOALS AND RESULTS**

** **

The CEO’s responsibility isto provide leadership in setting and achieving goals that create value for ourshareowners in the short and long term. Mr. Fischer’s 2008 annual cashincentive award was based on the corporate results described on pages 141 and142, which determined the total cash available for the awards. Cash incentiveawards are determined from the available pool and distributed to individualsbased on specific annual goals. Based on the board’s assessment of Mr. Fischer’sachievement of objectives, and their positive assessment of his contribution tocontinued shareowner value growth and strategic plan execution, he was awardedan annual cash incentive of $1,500,000, which is his target bonus times 137%.The incentive includes discretionary recognition for a number of critical businessinitiatives in the year. Mr. Fischer’s 2008 goals and results are outlinedbelow.

** **

**Develop andimplement a corporate strategy, balancing short-term growth while positioningNexen for sustainable growth.**

** **

In 2008, Mr. Fischeronce again led the management team in a review of our strategic plan, which isfocused on creating long-term sustainable growth. Out of this review, theannual operating plan was developed and subsequently approved by the board. In2008, 45% of oil and gas capital was invested in next generation, new growthprojects such as the Usan development offshore West Africa, shale gas, CBM,future oil sands phases and conventional exploration. These investments supporta long-term strategy for sustainable growth.

** **

**Achievecapital, operating, and general and administrative cost performance targets setout in the annual operating plan (AOP).**

** **

Mr. Fischer demonstratedhis ability to manage costs successfully in 2008 despite the volatile economicenvironment. The majority of Nexen’s production has low operating costs and lowroyalties. This is generating cash netbacks that are among the highest in theindustry. As a result, our assets are capable of generating positive cash flowsdespite recent declines in commodity prices.

 

Capital investments in 2008of approximately $2.5 billion in oil and gas exploration and developmentactivities added 74 mmboe of proved reserves before negative economic revisionsof 50 mmboe. Many of our projects are characterized by multi-year investmentswhere capital is invested, in some instances, years before reserves can berecognized. Measuring proved reserves additions against capital expendituresfor a one-year period, and in some cases a three-year period, is not meaningfuland does not tell the whole Nexen story.

** **

**Achievetargets for operating cash flow, earnings, production levels, and reservereplacement set out in the AOP.**

** **

In 2008, under Mr. Fischer’sleadership, Nexen generated record cash flow in excess of $4.2 billion andearnings of approximately $1.7 billion despite losses incurred by the Marketingdivision and impairment charges. The Marketing division reported significant cashflow losses in 2008. Nexen has exited positions that do not support itsphysical marketing business, which was challenging given the lack of liquidityin the market, fewer counterparties and deteriorating commodity prices.Earnings in 2008 were impacted by an impairment charge of $317 million (aftertax) relating to oil and gas properties in the Gulf of Mexico and the NorthSea. These properties were written down to their fair value, based on theestimated total future discounted net cash flows. Production levels reflected amodest increase over 2007 despite hurricane downtime.

** **

**Maintainfinancial flexibility and liquidity to support our business strategies.**

** **

With Mr. Fischer’sdirection, we achieved better than target results related to financialflexibility and liquidity. In 2008, cash flow exceeded capital investment byover $1 billion. This excess was used to repurchase approximately 12 millionshares for $338 million and build cash balances. A portion of this cash wasused to fund the acquisition of an additional 15% in the Long Lake Project andjoint venture lands. Nexen has no debt

 

149

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maturities until 2012 and theaverage term of its public debt is approximately 18 years. We are wellpositioned to weather the downturn in the economy given our strong liquidity.

** **

**Achieve top****-****quartileperformance in health, safety and environmental performance and socialresponsibility.**

** **

Mr. Fischer is highlycommitted to social responsibility. Nexen improved its employee injury ratesover 2007, just missing its best ever results set in 2006. There were no majorenvironmental incidents in the year. Nexen continues to be recognized as asocial responsibility leader and was included again in the Dow JonesSustainability Index for 2008.

** **

**Provide forcorporate management succession and development.**

** **

Mr. Fischer led thereview of Nexen’s succession plan in 2008 and demonstrated its effectiveness aswe were able to fill the vacancies related to his retirement entirely withinternal candidates.

** **

**Ensure Nexenadheres to the highest standards of integrity.**

** **

Mr. Fischer sets a highstandard for integrity in the workplace. Nexen continued to emphasize theimportance of integrity among its employees, 93% of whom attended our integrityworkshop by the end of 2008.

** **

**Demonstratehis personal commitment to community and industry leadership.**

** **

Mr. Fischer fillednumerous leadership roles in the community and industry. These personal andprofessional commitments involved a variety of organizations including theAlberta Children’s Hospital Foundation, Calgary Airport Authority, Hull Childand Family Services, Alberta Energy Research Institute and the Institute forSustainable Energy, Environment and Economy (University of Calgary).

 

**CEOTHREE-YEAR LOOK-BACK**

 
| ** **                                            | ** ** | **Three-Year  Total ($)** | ** ** | **2008 ($)** | ** ** | **2007 ($)** | ** ** | **2006 ($)** | ** ** |
|-------------------------------------------------------|------------|--------------------------------|------------|-------------------|------------|-------------------|------------|-------------------|------------|
| **Cash**                                              |       |                           |       |              |       |              |       |              |       |
| Base Salary                                           |       | 3,773,750                      |       | 1,348,750         |       | 1,275,000         |       | 1,150,000         |       |
| Annual Cash Incentive(1)                              |       | 4,216,000                      |       | 1,500,000         |       | 916,000           |       | 1,800,000         |       |
| **Equity**                                            |       |                           |       |              |       |              |       |              |       |
| Value of TOPs(2)                                      |       | 12,366,614                     |       | 2,245,760         |       | 5,110,200         |       | 5,010,654         |       |
| **Total Direct Compensation**                         | ** ** | **20,356,364**                 | ** ** | **5,094,510**     | ** ** | **7,301,200**     | ** ** | **7,960,654**     | ** ** |
| All Other Compensation(3)                             |       | 355,506                        |       | 124,245           |       | 119,640           |       | 111,621           |       |
| Pension Value(4)                                      |       | 3,561,900                      |       | 938,800           |       | 949,300           |       | 1,673,800         |       |
| **Total Cost**                                        | ** ** | **24,273,770**                 | ** ** | **6,157,555**     | ** ** | **8,370,140**     | ** ** | **9,746,075**     | ** ** |
| ** **                                            | ** ** | ** **                     | ** ** | ** **        | ** ** | ** **        | ** ** | ** **        | ** ** |
| Annual Average                                        |       | 8,091,257                      |       |              |       |              |       |              |       |
| Total Market Capitalization Growth  ($millions)       |       | (3,340                         | )          | (5,800            | )          | 90                |       | 2,370             |       |
| Total Cost as a % of Market Capitalization  Growth(5) |       | (0.73                          | )%         |              |       |              |       |              |       |

 

----

| *(1)* | *Includes discretionary recognition in  2008 for the acquisition of an additional interest in OPTI and $500,000 in  2006 for the success of Buzzard.*            |
|-------|------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Reflects the estimated fair value of  TOPs using the Black-Scholes pricing model valued on the grant date. See  page 148 for details of this calculation.* |
| *(3)* | *See page 155 for details of All  Other Compensation.*                                                                                                      |
| *(4)* | *Represents the current service cost,  plus changes in compensation in excess of actuarial assumptions, less  required member contributions to the plan.*        |
| *(5)* | *The current global financial situation  changes the context of this metric, reducing its associated meaning.*                                                   |

 

In2008, the Compensation Committee reviewed look-back information and analyzedMr. Fischer’s total pay and shareowner value created from the date hebecame CEO. In the analysis, dollar values were assigned and tallied for eachcompensation component including salary, annual cash incentives, TOPs awards,benefits, pension (including annual increases to liabilities) and potentialpayments on change of control. The Committee reviewed his total compensationrelative to Nexen’s market capitalization and that of industry peers.

 

150

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**INCENTIVEPLAN AWARDS**

 

Tovalue incentive plan awards (TOPs), Nexen uses the Black-Scholes pricing model,which is a generally accepted method for measuring this type of long-term incentive.The actual value realized on exercises may be higher or lower depending on theNexen share price at the time of exercise.

 

**IncentivePlan Awards Granted in 2008**

 

Theterm for TOPs granted in 2008 is five years and vesting is one-third each yearfor three years. Mr. Fischer’s grant vests over two years with 50% vestingon each anniversary. Our plans allow retirees to exercise vested TOPs up to 18months after retirement. This means that 50% of the grant will expire and becancelled prior to vesting under these circumstances and he will never be ableto exercise them. Mr. Fischer received that component of his annualcompensation (despite its long-term nature) due to his sustained highperformance and his leadership on many initiatives during the year that createdsustainable future value.

 
| ** **  | ** ** | ** **            | ** ** | **TOPs**             | ** ** | **% of Total  TOPs Granted** | ** ** | **Exercise**       | ** **  | ** **       | ** ** | **TOPs**              | ** ** | **Potential Realizable Value at  Assumed Annual Rates of Share  Price Appreciation for TOPs Term** | ** ** |
|-------------|------------|-----------------------|------------|----------------------|------------|---------------------------------------------|------------|--------------------|-------------|------------------|------------|-----------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Name**    | ** ** | **Grant Date**   | ** ** | **Granted (#)** | ** ** | **to Employees**                       | ** ** | **Price ($)** | ** **  | **Expiry  Date** | ** ** | **Value(2) ($)** | ** ** | **5% ****($)**                                                                                                                                       | ** ** | **10% ($)** | ** ** |
| Fischer     |       | Dec 8, 2008           |       | 400,000              |       | 10.3                                        | %          | 19.36              | (1)         | Dec 7, 2013      |       | 2,245,760             |       | 2,139,524                                                                                                                                                 |       | 4,727,789 |   |
| Romanow     |       | Dec 8, 2008           |       | 180,000              |       | 4.6                                         | %          | 19.36              | (1)         | Dec 7, 2013      |       | 975,744               |       | 962,786                                                                                                                                                   |       | 2,127,505 |   |
|        |       | Jan. 2,  2009(3) | 295,000    |                 | 7.6        | %                                           | 21.45      |               | Jan 1, 2014 |             | 1,771,770  |                  | 1,748,241  |                                                                                                                                                      | 3,863,155  |   |
| Murphy      |       | Dec 8, 2008           |       | 170,000              |       | 4.4                                         | %          | 19.36              | (1)         | Dec 7, 2013      |       | 921,536               |       | 909,298                                                                                                                                                   |       | 2,009,311 |   |
| Thomas      |       | Dec 8, 2008           |       | 170,000              |       | 4.4                                         | %          | 19.36              | (1)         | Dec 7, 2013      |       | 921,536               |       | 909,298                                                                                                                                                   |       | 2,009,311 |   |
| Nieuwenburg |       | Dec 8, 2008           |       | 100,000              |       | 2.6                                         | %          | 19.36              | (1)         | Dec 7, 2013      |       | 542,080               |       | 534,881                                                                                                                                                   |       | 1,181,947 |   |

 

----

| *(1)* | *Reflects the closing market price of  Nexen common shares on the TSX on December 5, 2008.*                                                                                                |
|-------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Reflects the estimated fair value of  the TOPs as at December 8, 2008 using the Black-Scholes pricing model.  See page 148 for details of this calculation.*                         |
| *(3)* | *Mr. Romanow received this grant  upon his appointment as President and CEO. The exercise price is the closing  market price of Nexen common shares on the TSX on December 31, 2008.* |

 

**IncentivePlan Awards - TOPs Exercised or Exchanged and Value Vested or Earned in 2008**

 

TheTOPs value realized in 2008 occurred within two months of grant expiry,demonstrating that executives are holding TOPs for the long-term, in alignmentwith our long-term strategy. The TOPs value vested in 2008 represents whatcould have been earned if executives exercised TOPs immediately upon vesting. Asshown in the table, the TOPs awards vesting in 2008 had no in-the-money valueupon vesting. The actual value realized will depend on the share price at thetime of exercise. Grants of TOPs are considered option-based awards underapplicable disclosure requirements. We do not award named executivesshare-based awards or non-equity incentive plan compensation under long-termincentive plans, as these terms are used in applicable disclosure requirements.

 
| ** **  | ** ** | **TOPs Awards**                      | ** ** | **TOPs Awards**            | ** ** | **Non-Equity Incentive  Compensation Plan** | ** ** |
|-------------|------------|-------------------------------------------|------------|---------------------------------|------------|-------------------------------------------------------|------------|
| **Name**    | ** ** | **Exercised or  Exchanged (#)** | ** ** | **Value  Realized(1) ($)** | ** ** | **Vested  in 2008 (#)**                     | ** ** | **Value Vested  in 2008(2) ($)** | ** ** | **Value Earned During  the Year(3) ($)** | ** ** |
| Fischer     |       | 600,000                                   |       | 6,248,500                       |       | 517,500                                               |       | — |   | 1,500,000 |   |
| Romanow     |       | 220,000                                   |       | 3,217,500                       |       | 154,920                                               |       | — |   | 700,000 |   |
| Murphy      |       | —                                    |       | —                          |       | 132,000                                               |       | — |   | 400,000 |   |
| Thomas      |       | 128,000                                   |       | 1,112,960                       |       | 132,000                                               |       | — |   | 436,000 |   |
| Nieuwenburg |       | 58,000                                    |       | 522,290                         |       | 93,400                                                |       | — |   | 365,000 |   |
| **Total**   | ** ** | **1,006,000**                             | ** ** | **11,101,250**                  | ** ** | **1,029,820**                                         | ** ** | **—** | ** ** | **3,401,000** | ** ** |

 

----

| *(1)* | *Reflects the market price at the time  of the exercise or exchange, minus the exercise price, as defined in the TOPs  plan.*                                                                     |
|-------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *(2)* | *Reflects the market price at the time  of vesting, minus the exercise price, as defined in the TOPs plan. All TOPs  awards vesting in 2008 had an exercise price greater than the market price.* |
| *(3)* | *Represents compensation earned in 2008  and paid in 2009.*                                                                                                                                       |

 

151

----

 

**Outstanding Incentive Plan Awards**

 
| ** **  | ** ** | ** **            | ** ** | ** **           | ** ** | ** **         | ** ** | ** **              | ** ** | **Vested and Unvested  TOPs at Dec. 31, 2008(1), (2)** | ** ** | ** **                     | ** ** |
|-------------|------------|-----------------------|------------|----------------------|------------|--------------------|------------|-------------------------|------------|-------------------------------------------------------------------------------------------|------------|--------------------------------|------------|
| ** **  | ** ** | ** **            | ** ** | ** **           | ** ** | **Exercise**       | ** ** | ** **              | ** ** | **Number of  Securities  Underlying  Unexercised**                                   | ** ** | **Value of  Unexercised** | ** ** | **Vested TOPs  at Dec. 31, 2008(2)** | ** ** |
| **Name**    | ** ** | **Date Granted** | ** ** | **Expiry Date** | ** ** | **Price ($)** | ** ** | **Granted(3) (#)** | ** ** | **TOPs (#)**                                                                         | ** ** | **TOPs(4) ($)**           | ** ** | **Number (#)** | ** ** | **Value(4) ($)** | ** ** |
| Fischer     |       | Dec. 14, 1999    |       | Dec. 13, 2009   |       | 6.8125             |       | 280,000                 |       | 280,000                                                                                   |       | 4,098,500                      |       | 280,000 |   | 4,098,500 |   |
|        |       | Dec. 12, 2000    |       | Dec. 11, 2010   |       | 9.0250             |       | 280,000                 |       | 280,000                                                                                   |       | 3,479,000                      |       | 280,000 |   | 3,479,000 |   |
|        |       | Dec. 7, 2004     |       | Dec. 6, 2009    |       | 12.7175            |       | 600,000                 |       | 600,000                                                                                   |       | 5,239,500                      |       | 600,000 |   | 5,239,500 |   |
|        |       | Dec. 6, 2005     |       | Dec. 5, 2010    |       | 27.2850            |       | 400,000                 |       | 400,000                                                                                   |       | —                         |       | 400,000 |   | — |   |
|        |       | Dec. 4, 2006     |       | Dec. 3, 2011    |       | 31.6000            |       | 550,000                 |       | 550,000                                                                                   |       | —                         |       | 368,500 |   | — |   |
|        |       | Dec. 3, 2007     |       | Dec. 2, 2012    |       | 28.3900            |       | 600,000                 |       | 600,000                                                                                   |       | —                         |       | 204,000 |   | — |   |
|        |       | Dec. 8, 2008     |       | Dec. 7, 2013    |       | 19.3600            |       | 400,000                 |       | 400,000                                                                                   |       | 836,000                        |       | — |   | — |   |
| **Total**   | ** ** | ** **            | ** ** | ** **           | ** ** | ** **         | ** ** | **3,110,000**           | ** ** | **3,110,000**                                                                             | ** ** | **13,653,000**                 | ** ** | **2,132,500** | ** ** | **12,817,000** |   |
| Romanow(5)  |       | Dec. 12, 2000    |       | Dec. 11, 2010   |       | 9.0250             |       | 200,000                 |       | 200,000                                                                                   |       | 2,485,000                      |       | 200,000 |   | 2,485,000 |   |
|        |       | Dec. 7, 2004     |       | Dec. 6, 2009    |       | 12.7175            |       | 228,000                 |       | 228,000                                                                                   |       | 1,991,010                      |       | 228,000 |   | 1,991,010 |   |
|        |       | Dec. 6, 2005     |       | Dec. 5, 2010    |       | 27.2850            |       | 124,000                 |       | 124,000                                                                                   |       | —                         |       | 124,000 |   | — |   |
|        |       | Dec. 4, 2006     |       | Dec. 3, 2011    |       | 31.6000            |       | 160,000                 |       | 160,000                                                                                   |       | —                         |       | 107,200 |   | — |   |
|        |       | Dec. 3, 2007     |       | Dec. 2, 2012    |       | 28.3900            |       | 180,000                 |       | 180,000                                                                                   |       | —                         |       | 61,200 |   | — |   |
|        |       | Dec. 8, 2008     |       | Dec. 7, 2013    |       | 19.3600            |       | 180,000                 |       | 180,000                                                                                   |       | 376,200                        |       | — |   | — |   |
|        |       | Jan. 2, 2009     |       | Jan. 1, 2014    |       | 21.4500            |       | 295,000                 |       | 295,000                                                                                   |       | —                         |       | — |   | — |   |
| **Total**   | ** ** | ** **            | ** ** | ** **           | ** ** | ** **         | ** ** | **1,367,000**           | ** ** | **1,367,000**                                                                             | ** ** | **4,852,210**                  | ** ** | **720,400** | ** ** | **4,476,010** |   |
| Murphy      |       | Dec. 7, 2004     |       | Dec. 6, 2009    |       | 12.7175            |       | 160,000                 |       | 52,800                                                                                    |       | 461,076                        |       | 52,800 |   | 461,076 |   |
|        |       | Dec. 6, 2005     |       | Dec. 5, 2010    |       | 27.2850            |       | 100,000                 |       | 100,000                                                                                   |       | —                         |       | 100,000 |   | — |   |
|        |       | Dec. 4, 2006     |       | Dec. 3, 2011    |       | 31.6000            |       | 130,000                 |       | 130,000                                                                                   |       | —                         |       | 87,100 |   | — |   |
|        |       | Dec. 3, 2007     |       | Dec. 2, 2012    |       | 28.3900            |       | 165,000                 |       | 165,000                                                                                   |       | —                         |       | 56,100 |   | — |   |
|        |       | Dec. 8, 2008     |       | Dec, 7, 2013         |       | 19.3600            |       | 170,000                 |       | 170,000                                                                                   |       | 355,300                        |       | — |   | — |   |
| **Total**   | ** ** | ** **            | ** ** | ** **           | ** ** | ** **         | ** ** | **725,000**             | ** ** | **617,800**                                                                               | ** ** | **816,376**                    | ** ** | **296,000** | ** ** | **461,076** |   |
| Thomas      |       | Dec. 7, 2004     |       | Dec. 6, 2009    |       | 12.7175            |       | 160,000                 |       | 160,000                                                                                   |       | 1,397,200                      |       | 160,000 |   | 1,397,200 |   |
|        |       | Dec. 6, 2005     |       | Dec. 5, 2010    |       | 27.2850            |       | 100,000                 |       | 100,000                                                                                   |       | —                         |       | 100,000 |   | — |   |
|        |       | Dec. 4, 2006     |       | Dec. 3, 2011    |       | 31.6000            |       | 130,000                 |       | 130,000                                                                                   |       | —                         |       | 87,100 |   | — |   |
|        |       | Dec. 3, 2007     |       | Dec. 2, 2012    |       | 28.3900            |       | 165,000                 |       | 165,000                                                                                   |       | —                         |       | 56,100 |   | — |   |
|        |       | Dec. 8, 2008     |       | Dec. 7, 2013    |       | 19.3600            |       | 170,000                 |       | 170,000                                                                                   |       | 355,300                        |       | — |   | — |   |
| **Total**   | ** ** | ** **            | ** ** | ** **           | ** ** | ** **         | ** ** | **725,000**             | ** ** | **725,000**                                                                               | ** ** | **1,752,500**                  | ** ** | **403,200** | ** ** | **1,397,200** |   |
| Nieuwenburg |       | Dec. 7, 2004     |       | Dec. 6, 2009    |       | 12.7175            |       | 120,000                 |       | 120,000                                                                                   |       | 1,047,900                      |       | 120,000 |   | 1,047,900 |   |
|        |       | Dec. 6, 2005     |       | Dec. 5, 2010    |       | 27.2850            |       | 80,000                  |       | 80,000                                                                                    |       | —                         |       | 80,000 |   | — |   |
|        |       | Dec. 4, 2006     |       | Dec. 3, 2011    |       | 31.6000            |       | 100,000                 |       | 100,000                                                                                   |       | —                         |       | 67,000 |   | — |   |
|        |       | Dec. 3, 2007     |       | Dec. 2, 2012    |       | 28.3900            |       | 100,000                 |       | 100,000                                                                                   |       | —                         |       | 34,000 |   | — |   |
|        |       | Dec. 8, 2008     |       | Dec. 7, 2013    |       | 19.3600            |       | 100,000                 |       | 100,000                                                                                   |       | 209,000                        |       | — |   | — |   |
| **Total**   | ** ** | ** **            | ** ** | ** **           | ** ** | ** **         | ** ** | **500,000**             | ** ** | **500,000**                                                                               | ** ** | **1,256,900**                  | ** ** | **301,000** | ** ** | **1,047,900** |   |

 

----

*(1)**      **Excludes grants that havebeen fully exercised.*

*(2)**      **The number and value ofunvested TOPs can be determined by subtracting the vested TOPs from the vestedand unvested TOPs. The value of unvested TOPs can be confirmed on page 156in the Change of Control Table.*

*(3)**      **Nexen common shares areissued for TOPs on a one-for-one basis.*

*(4)**      **The difference between themarket value of Nexen common shares on the TSX on December 31, 2008 of$21.45/share and the grant price of TOPs, times the number of TOPs. Where thegrant price exceeds the market price of $21.45/share, the value shown is zero.*

*(5)**      **On January 2, 2009, Mr. Romanowwas granted an additional 295,000 TOPs with an exercise price of $21.45/shareupon his appointment as President and CEO.*

 

152

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**EQUITY OWNERSHIP AND CHANGES IN 2008**

 

According to our shareownership guidelines, Mr. Fischer was required to hold three times his annualsalary. Mr. Romanow is required to hold two times his annual salary, and theother executives are required to hold one times their annual salary.

 
| ** **  | ** ** | ** **                      | ** ** | ** **                      | ** ** | ** **          | ** ** | **Equity at Risk** | ** ** |
|-------------|------------|---------------------------------|------------|---------------------------------|------------|---------------------|------------|------------------------------|------------|
| ** **  | ** ** | **December 31, 2007** | ** ** | **December 31, 2008** | ** ** | **Net Change** | ** ** | ** **                   | ** ** | **Multiple** | ** ** |
| **Name**    | ** ** | **Shares**                      | ** ** | **TOPs(1)**                     | ** ** | **Shares**          | ** ** | **TOPs(1)**                  | ** ** | **Shares** | ** ** | **TOPs(2)** | ** ** | **Value(3) ($)** | ** ** | **of Salary(4)** | ** ** |
| Fischer     |       | 183,426                         | (5)        | 2,215,000                       |       | 602,417             |       | 2,132,500                    |       | 418,991 |   | (82,500 | ) | 25,738,845 |   | 19 |   |
| Romanow     |       | 80,938                          |       | 785,480                         |       | 186,635             |       | 720,400                      |       | 105,697 |   | (65,080 | ) | 8,479,331 |   | 14 |   |
| Murphy      |       | 125,226                         |       | 164,000                         |       | 135,016             |       | 296,000                      |       | 9,790 |   | 132,000 |   | 3,357,169 |   | 6 |   |
| Thomas      |       | 16,297                          | (5)        | 399,200                         |       | 21,622              |       | 403,200                      |       | 5,325 |   | 4,000 |   | 1,860,992 |   | 3 |   |
| Nieuwenburg |       | 65,795                          |       | 265,600                         |       | 77,016              |       | 301,000                      |       | 11,221 |   | 35,400 |   | 2,699,893 |   | 6 |   |
| **Total**   | ** ** | **471,682**                     | ** ** | **3,829,280**                   | ** ** | **1,022,706**       | ** ** | **3,853,100**                | ** ** | **551,024** | ** ** | **23,820** | ** ** | **42,136,230** |   |   |   |

 

----

*(1)**      **Represents total TOPsgranted, vested and unexercised.*

*(2)**      **Reflects the number of TOPsthat vested, minus the number exercised or exchanged during 2008.*

*(3)**      **Equity at risk is the marketvalue of common shares and vested TOPs using the closing price of Nexen shareson the TSX on December 31, 2008 of $21.45/share.*

*(4)**      **Reflects the equity at risk,divided by the executive’s 2008 salary amount shown on page 148.*

*(5)**      **Includes accumulations underthe dividend reinvestment plan of ten common shares for Mr. Fischer and 70common shares for Mr. Thomas which were not previously reported.*

 

**PENSION PLAN TABLES**

 

All executives are members ofNexen’s registered defined benefit pension plan and executive benefit plan andaccrue pension benefit at a 2% accrual rate. With this option, they mustcontribute 5% of pensionable earnings up to the maximum allowed under theCanadian Income Tax Act. See pages 145 and 146 for details.

 

**Pension Value Earned and Benefit Obligation Changes in 2008**

 

Our reported values useactuarial assumptions and methods that are the same as those used to calculatepension obligations and the related annual expense disclosed in our consolidatedfinancial statements. As the assumptions reflect our best estimate of futureevents, our reported values may not be directly comparable to similar pensionliability values disclosed by other companies.

 

The board must approveadditional past service credits or accelerated service credits. No acceleratedservice credits were authorized in 2008. The notes to the table below showsadditional past service credits authorized by the board for the executives whoparticipate in the Canadian defined benefit pension plan and the executive benefitplan.

 

No benefit payments were madeto executives in the last fiscal year.

 

153

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**Defined Benefit Plan Table**

 
| ** **  | ** ** | **Years of**              | ** ** | **Annual  Benefits Payable** | ** ** | **Accrued**

**Obligation** | ** ** | ** **                | ** ** | **Non-**                        | ** ** | **Change  in**

**Obligation**  | ** ** | **Accrued**

**Obligation**   | ** ** |
|-------------|------------|---------------------------|------------|------------------------------|------------|-----------------------------|------------|---------------------------|------------|---------------------------------|------------|---------------------------------|------------|-------------------------------|------------|
| **Name**    | ** ** | **Credited**

**Service** | ** ** | **At**

**Year  End(1)**     | ** ** | **At**

**Age  65(2)**      | ** ** | **at Jan.  1,**

**2008** | ** ** | **Compensatory**

**Change(3)** | ** ** | **Compensatory**

**Change(4)** | ** ** | **since  Dec. 31,**

**2007** | ** ** | **at Dec.  31,**

**2008** | ** ** |
| Fischer     | ** ** | 24.58                     | (5)        | 904,792                      |       | 1,168,001                   |       | 12,660,000                |       | 938,800                         |       | (1,273,800                      | )          | (335,000                      | )          | 12,325,000 |   |
| Romanow     | ** ** | 21.50                     | (5)(6)     | 368,527                      |       | 572,458                     |       | 4,722,000                 |       | 317,800                         |       | (692,800                        | )          | (375,000                      | )          | 4,347,000 |   |
| Murphy      |       | 22.67                     |       | 299,475                      |       | 411,434                     |       | 4,041,000                 |       | 285,800                         |       | (390,800                        | )          | (105,000                      | )          | 3,936,000 |   |
| Thomas      | ** ** | 28.50                     | (5)        | 364,081                      |       | 496,656                     |       | 5,110,000                 |       | 265,800                         |       | (535,800                        | )          | (270,000                      | )          | 4,840,000 |   |
| Nieuwenburg | ** ** | 4.00                      | (7)        | 104,155                      |       | 260,298                     |       | 1,226,000                 |       | 141,800                         |       | (225,800                        | )          | (84,000                       | )          | 1,142,000 |   |
| **Total**   | ** ** |                      |       | **2,041,030**                | ** ** | **2,908,847**               | ** ** | **27,759,000**            | ** ** | **1,950,000**                   | ** ** | **(3,119,000**                  | **)**      | **(1,169,000**                | **)**      | **26,590,000** |   |

 

----

*(1)**      **All information is as ofDecember 31, 2008. Represents the sum of the benefits accrued under the definedbenefit and executive benefit pension plans.*

*(2)**      **Represents a value based onprojected years of credited service, a 2% accrual rate to age 65, and actualpensionable earnings used to calculate the benefit amount in the previouscolumn of defined contribution service.*

*(3)**      **Includes the 2008 current servicecost, less required member contributions to the plan, plus changes incompensation in excess of actuarial assumptions. Disclosure of the valuationmethod and significant assumptions used are found in the pension and otherpost-retirement benefits note 14 in our consolidated financial statements.*

*(4)**      **Reflects the impact ofinterest on prior year’s obligations, changes in discount rates used to measurethe obligations and the impact of assumption and employee demographic changes.*

*(5)**      **Ten years of additional pastservice credits were granted to each of Messrs. Fischer, Romanow andThomas by the board in 2001. This was a competitive practice to recognize thatthey were at a certain level in their career in 2001 when they were appointedto new positions.*

*(6)**      **Mr. Romanow joined thedefined benefit pension plan after 7.25 years in the defined contributionpension plan. A pension benefit, which is reflective of base salary, will bebased on his 21.50 years of defined benefit pension plan service. A pensionbenefit, which is reflective of pensionable bonus, will also be based on 28.75years of service, which includes the 7.25 years of defined contributionservice.*

*(7)**      **Mr. Nieuwenburg joinedthe defined benefit pension plan after 23.58 years in the defined contributionpension plan. A pension benefit, which is reflective of base salary, will bebased on his 4 years of defined benefit pension plan service. A pensionbenefit, which is reflective of pensionable bonus, will also be based on 27.58years of service, which includes the 23.58 years of defined contributionservice.*

 

The information in thefollowing table is a supplement to the previous table. The final averageearnings reported for each named executive are used in the respectivecalculations and are based on the:

 

·                  average base salary for the 36highest-paid consecutive months during the ten years up to December 31, 2008;plus

·                  annual cash incentive payments at thelesser of the target bonus or actual bonus paid, averaged over the final threeyears of participation up to December 31, 2008.

 
| ** **  | ** ** | ** **                            | ** ** | ** **                         | ** ** | **Accrued  Annual Pension Benefit(1)** | ** ** | **Estimated  Annual**              | ** ** |
|-------------|------------|---------------------------------------|------------|------------------------------------|------------|----------------------------------------|------------|------------------------------------|------------|
| ** **  | ** ** | **Years of  Credited Service**        | ** ** | **Final**                          | ** ** | ** **                             | ** ** | **Under  the**                     | ** ** | **Pension  Benefit at Age 60(2)** | ** ** |
| **Name**    | ** ** | **Up to**

**Dec. 31,**

**2004 (#)** | ** ** | **From**

**Jan.1,**

**2005 (#)** | ** ** | **Total  (#)**                         | ** ** | **Average**

**Earnings**

**($)** | ** ** | **Under  the**

**Defined  Benefit**

**Pension  Plan ($)** | ** ** | **Executive  Benefit**

**Plan ($)** | ** ** | **Under  the Defined Benefit Pension Plan ($)** | ** ** | **Under  the**

**Executive**

**Benefit  Plan ($)** | ** ** |
| Fischer     |       | 20.58                                 |       | 4.00                               |       | 24.58                                  |       | 2,113,250                          |       | 34,028 |   | 870,765 |   | 38,704 |   | 918,730 |   |
| Romanow     |       | 17.50                                 |       | 4.00                               |       | 21.50                                  |       | 881,567                            |       | 26,833 |   | 341,694 |   | 44,407 |   | 440,652 |   |
| Murphy      |       | 18.67                                 |       | 4.00                               |       | 22.67                                  |       | 762,361                            |       | 52,889 |   | 246,586 |   | 61,315 |   | 274,641 |   |
| Thomas      |       | 24.50                                 |       | 4.00                               |       | 28.50                                  |       | 742,000                            |       | 43,167 |   | 320,915 |   | 55,000 |   | 367,835 |   |
| Nieuwenburg |       | —                                |       | 4.00                               |       | 4.00                                   |       | 525,182                            |       | 9,333 |   | 94,822 |   | 34,426 |   | 174,112 |   |

 

----

*(1)**      **All information is as of December 31,2008.*

*(2)**      **Represents a value based onprojected years of credited service at a 2% accrual rate at age 60 and actualpensionable earnings used to calculate the accrued annual pension benefitvalues in the previous column. Age 60 is the earliest age an individual can receiveunreduced retirement benefits.*

 

154

----

 

**Defined Contribution Plan Table**

 

The following table representsthe value of accumulated pension assets within the registered definedcontribution pension plan. Under the terms of this plan, all benefits have beenfunded. The individuals were entitled to benefits under this registered planprior to being appointed to executive positions at Nexen. The individuals haveno entitlements under any supplemental defined contribution pension planarrangement and there is no above-market or preferential earnings provisions.

 

The two individuals are activeparticipants of the defined benefit pension plan and have not contributed to orreceived any company-provided benefits under the terms of this plan for morethan four years as indicated in the notes below.

 
| **Name**           | ** ** | **Accumulated Value at   Jan. 1, 2008** | ** ** | **Compensatory ****($)** | ** ** | **Non-Compensatory ****($)** | ** ** | **Accumulated Value at  Dec. 31, 2008** | ** ** |
|--------------------|------------|------------------------------------------------------------------|------------|-------------------------------|------------|-----------------------------------|------------|-------------------------------------------------------------|------------|
| **Romanow(1)**     |       | 437,608                                                          |       | —                        |       | (105,967                          | )          | 331,641                                                     |       |
| **Nieuwenburg(2)** |       | 542,061                                                          |       | —                        |       | (131,260                          | )          | 410,801                                                     |       |

 

----

*(1)**      **Mr. Romanow joined thedefined benefit pension plan in 1997 after 7.25 years in the definedcontribution pension plan.*

*(2)**      **Mr. Nieuwenburg joinedthe defined benefit pension plan in 2005 after 23.58 years in the definedcontribution pension plan.*

 

**ALL OTHER COMPENSATION**

 

The total value of perquisitesprovided to any executive was less than $50,000 and less than 10% of theexecutive’s annual salary in 2008. 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.

 
| ** **  | ** ** | ** **         | ** ** | **Other Compensation**   | ** ** | ** ** | ** ** |
|-------------|------------|--------------------|------------|-------------------------------|------------|------------|------------|
| ** **  | ** ** | **Perquisites**    | ** ** | **Life**                      | ** ** | ** ** | ** ** | **Amounts** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Name**    | ** ** | **Car  Allowance** | ** ** | **Other**

**Perquisites(1)** | ** ** | **Total**  | ** ** | **Insurance**

**Premiums(2)** | ** ** | **Savings  Plan  Contributions** | ** ** | **Paid by  Canexus(3)** | ** ** | **Total** | ** ** | **Total All Other  Compensation** | ** ** |
| Fischer     |       | 31,200             |       | 10,500                        |       | 41,700     |       | 1,620 |   | 80,925 |   | — |   | 82,545 |   | 124,245 |   |
| Romanow     |       | 19,200             |       | 7,100                         |       | 26,300     |       | 642 |   | 36,075 |   | 55,999 |   | 92,716 |   | 119,016 |   |
| Murphy      |       | 19,200             |       | 7,100                         |       | 26,300     |       | 1,433 |   | 32,775 |   | — |   | 34,208 |   | 60,508 |   |
| Thomas      |       | 19,200             |       | 7,100                         |       | 26,300     |       | 1,338 |   | 32,550 |   | — |   | 33,888 |   | 60,188 |   |
| Nieuwenburg |       | 19,200             |       | 7,100                         |       | 26,300     |       | 1,380 |   | 24,990 |   | — |   | 26,370 |   | 52,670 |   |

 

----

*(1)**      **Represents a maximumreimbursement amount for financial counselling, luncheon club memberships,medical exam and security monitoring. For the CEO, this also includes a maximumreimbursement amount for a golf club membership.*

*(2)**      **The life insurance premiumsprovided to the executive is made available to all employees.*

*(3)**      **Includes fees for serving asa director of Canexus of $34,000, deferred trust units of Canexus valued at$15,600 and distributions on his trust units of $6,399.*

 

**TERMINATION AND CHANGE OF CONTROL BENEFITS**

 

Nexen does not enter intoemployment service contracts. Depending on the conditions of termination, wetreat executives and employees fairly as follows:

 
| **Event**                  | ** ** | **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 premium continues in certain jurisdictions

· 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 one-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                                                                                                                                                           |

 

155

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**Payments on Resignation**

 

The following table disclosesthe lump sum value of pension benefits accrued under the defined benefitpension plan and executive benefit plan for our named executives had theyresigned effective December 31, 2008. If they are over the age of 55 and haveat least 10 years of Nexen service, they are deemed to have retired and a lumpsum benefit option is not available. Also included in this table is the valueof vested TOPs at December 31, 2008.

 
| **Name**    | ** ** | **Termination Scenario** | ** ** | **Pension ****($)** | ** ** | **Value of Vested  TOPs(1), (2) ****($)** | ** ** | **Total ****($)** | ** ** |
|-------------|------------|-------------------------------|------------|--------------------------|------------|---------------------------------------------------------------|------------|------------------------|------------|
| Fischer (3) |       | Retirement                    |       | —                   |       | 12,817,000                                                    |       | 12,817,000             |       |
| Romanow     |       | Resignation                   |       | 4,524,000                |       | 4,476,010                                                     |       | 9,000,010              |       |
| Murphy (4)  |       | Deemed retirement             |       | —                   |       | 461,076                                                       |       | 461,076                |       |
| Thomas (5)  |       | Deemed retirement             |       | —                   |       | 1,397,200                                                     |       | 1,397,200              |       |
| Nieuwenburg |       | Resignation                   |       | 1,072,000                |       | 1,047,900                                                     |       | 2,119,900              |       |

 

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*(1)**      **Does not include unvestedTOPs which will vest according to the TOPs plan over 18 months for deemedretirement or over 90 days for resignation.*

*(2)**      **The difference between themarket value of Nexen common shares at year end of $21.45/share and the grantprice of TOPs, times the number of vested TOPs.*

*(3)**      **With Mr. Fischer’sretirement on December 31, 2008, he began to receive a monthly pensionbenefit of $75,501.*

*(4)**      **Mr. Murphy would beeligible to receive a monthly pension benefit of $22,544 payable effective January 1,2009. The option to receive a lump sum pension benefit would not be available.*

*(5)**      **Mr. Thomas would beeligible to receive a monthly pension benefit of $25,486 payable effective January 1,2009. The option to receive a lump sum pension benefit would not be available.*

 

Mr. Fischer’s change of controlagreement terminated on December 31, 2008 when he retired. Mr. Romanow’s changeof control agreement was amended in January 2009 when he was appointedPresident and CEO. The nature of our time-vested TOPs ensures that retiringexecutives maintain a significant equity interest for at least 12 months (lastvesting period) after departure. Charlie Fischer maintains an equity interestthat exceeds three times his annual salary.

 

**Change of Control Agreements**

 

Nexen has entered into change of controlagreements with Messrs. Fischer, Romanow, Murphy, Thomas, Nieuwenburg and otherkey executives. The agreements were effective October 1999, amended in December2000, amended and restated in December 2001, and amended and restated inSeptember 2008. We recognize that these executives are critical to Nexen’songoing business. Therefore, it is vital we work to retain the executives,protect them from employment interruption caused by a change of control andtreat them in a fair and equitable manner. Consistent with industry standardsfor executives in similar circumstances, there are no restrictions on futureemployment or non-compete clauses in the agreements. Each year, theCompensation Committee reviews the estimated payments upon a change of controlincluding the termination value of pension benefits due under the definedbenefit pension plan and executive benefit plan.

 

Mr. Fischer’s change in controlagreement terminated on December 31, 2008 when he retired. Mr. Romanow’s changein control agreement was amended in January 2009 when he was appointedPresident and CEO. In the event of a change of control, and subsequenttermination of employment, Mr. Romanow would be deemed to retire and hispension would commence upon the later of the completion of the severance periodoutlined below and the attainment of age 55, without any applicable earlyretirement reduction. 

 

Under these agreements, achange of control includes any acquisition of common shares or other securitiesthat carries the right to cast more than 35% of the common share votes.Generally, it is any event that results in a person or group exercisingeffective control of Nexen.

 

If the executives terminate following a change of control, they areentitled to salary, target bonus and other compensatory benefits for theseverance period specified below.

 
| ** **  | ** ** | **Severance Period in Months on Change of Control** | ** ** |
|-------------|------------|----------------------------------------------------------------------------------------|------------|
| **Name**    | ** ** | **If Terminated**                                                                 | ** ** | **Upon  Resignation(1)** | ** ** |
| Fischer (2) |       | 36                                                                                     |       | 36 |   |
| Romanow     |       | 36                                                                                     |       | 30 |   |
| Murphy      |       | 30                                                                                     |       | — |   |
| Thomas      |       | 30                                                                                     |       | — |   |
| Nieuwenburg |       | 24                                                                                     |       | — |   |

 

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*(1)**      **Within 12 months afterchange of control and only if the CEO or CFO has remained an employee.*

*(2)**      **Mr. Fischer retired on December 31,2008 and no longer has these entitlements.*

 

The next table outlines theestimated incremental payments executives would be entitled to had a change ofcontrol and a subsequent termination of employment, occurred on December 31,2008. 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, 

 

156

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dental and life insurancecoverage. In addition, the agreement provides a payment for other employeebenefits and perquisites, including car allowance and savings plancontributions during the severance period, and an allowance for financialcounselling, security monitoring and career transition services.

 

Executives would also beentitled to an incremental pension benefit relating to their salary, serviceand annual incentive targets over the severance period. The pension valuereported below discloses the resulting lump sum payout determined according tothe executive’s employment arrangement. These additional pension benefits donot include any termination benefits that would be payable under the registereddefined benefit pension plan and executive benefit plan if a termination orretirement occurred that was not triggered by a change of control.

 

**Estimated Incremental Payment on Change of Control(1)**

 
| **Name**    | ** ** | **Severance  Period  (# of months)** | ** ** | **Base  Salary  ($)** | ** ** | **Bonus  Target Value  ($)** | ** ** | **Benefits  Uplift  ($)** | ** ** | **Other  Employee Benefits  ($)** | ** ** | **Additional    Lump Sum  Value of  Pension(2)**

**($)** | ** ** | **Accelerated  TOPs Value(3)   ($)** | ** ** | **Total  Incremental  Obligation ($)** | ** ** |
|-------------|------------|--------------------------------------|------------|-----------------------|------------|------------------------------|------------|---------------------------|------------|-----------------------------------|------------|----------------------------------------------------------------|------------|-------------------------------------------|------------|----------------------------------------|------------|
| Fischer     |       | 36                                   |       | 4,095,000             |       | 3,276,000                    |       | 532,350                   |       | 377,200                           |       | 10,269,000                                                     |       | 836,000                                   |       | 19,385,550                             |       |
| Romanow     |       | 36                                   |       | 1,830,000             |       | 1,098,000                    |       | 237,900                   |       | 205,300                           |       | 4,716,000                                                      |       | 376,200                                   |       | 8,463,400                              |       |
| Murphy      |       | 30                                   |       | 1,387,500             |       | 832,500                      |       | 180,375                   |       | 169,150                           |       | 3,780,000                                                      |       | 355,300                                   |       | 6,704,825                              |       |
| Thomas      |       | 30                                   |       | 1,375,000             |       | 825,000                      |       | 178,750                   |       | 168,400                           |       | 4,462,000                                                      |       | 355,300                                   |       | 7,364,450                              |       |
| Nieuwenburg |       | 24                                   |       | 844,000               |       | 379,800                      |       | 109,720                   |       | 126,940                           |       | 1,690,000                                                      |       | 209,000                                   |       | 3,359,460                              |       |
| **Total**   | ** ** | ** **                           | ** ** | **9,531,500**         | ** ** | **6,411,300**                | ** ** | **1,239,095**             | ** ** | **1,046,990**                     | ** ** | **24,917,000**                                                 | ** ** | **2,131,800**                             | ** ** | **45,277,685**                         |       |

 

----

*(1)**      **Assumes a triggering eventoccurred at December 31, 2008.*

*(2)**      **Does not include regulartermination pension values which are reported in Payments on Resignation on page 156.Benefits payable under the registered defined benefit pension plan are fundedfrom the pension trust and payable monthly if the executive is 55 or older.*

*(3)**      **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, 2008 of $21.45/share, less the exercise price. The incrementalvalue is not in addition to the value identified in the vesting provisionsection of the termination chart on page 156.*

 

**CORPORATE GOVERNANCE**

 

Nexen’s board takes its dutiesand responsibilities for good corporate governance seriously. Nexen supportsand conducts business according to the rules of the Toronto Stock Exchange(TSX), NYSE, National Policy 58-201—Corporate Governance Guidelines andMultilateral Instrument 52-110—Audit Committees. Except as noted below, Nexen’scorporate governance practices comply with those followed by domestic companiesunder NYSE listing standards.

 

Nexen has a DSU plan fornon-executive directors as described on page 137. For this plan, Nexen followsthe TSX rules which, unlike the NYSE rules, exempt plans from shareownerapproval where the common shares issued under the plan are purchased on theopen market rather than issuing new shares.

 

Annually, the CEO certifies tothe NYSE that he is unaware of any violation by Nexen of the NYSE’s corporategovernance listing standards. Nexen also provides the required Annual WrittenAffirmation to the NYSE. As well, our CEO and CFO have certified the quality ofNexen’s public disclosure to the SEC.

 

All Committee mandates,including those for the Audit, Compensation and Governance Committees, and ourcorporate governance policy and categorical standards are available atwww.nexeninc.com, and we intend to provide disclosure in this manner.Shareowners wishing to receive a copy of these documents may contact theGovernance Office by telephone at 403.699.4926, or by email atgovernance@nexeninc.com.

 

**GOVERNANCE COMMITTEE REPORT**

 

The Governance Committeeassists the board in overseeing implementation of our corporate governanceprograms. It recommends nominees for director appointments and manages theevaluation process of the board, its committees and individual directors andchairs. This oversight ensures we implement best-in-class governance practicesappropriate for Nexen.

 

All Committee members areindependent and knowledgeable on our corporate governance programs. Six membersare skilled or expert in governance and board experience or diversity—expertisemost relevant to the Committee’s mandate.

 

**Changes to Committee Membership in 2008**

 

TheCommittee membership did not change in 2008.

 

157

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**Key Activities in 2008**

 

·                  Recommended two new directors for appointmentto the board to replace two retiring directors;

·                  Recommended revised share ownership guidelinesfor directors;

·                  Reviewed our annual meeting vote results;

·                  Recommended updates to governance documentsincluding mandates for the board, individual directors and all boardcommittees, the external communications policy and the corporate governancepolicy;

·                  Received regular reports on management’sdialogue with governance-related stakeholders;

·                  Recommended a new online performanceevaluation process with updated questions; and

·                  Consulted with Dr. Richard Leblanc,Assistant Professor of Corporate Governance, York University, on the board’sperformance evaluations.

 

**The Board and Committees**

 

The Committee reviews board andcommittee memberships annually, considering director independence, skills andpreferences. The board is large enough to permit a diversity of views andprovide expertise in running the committees, without being so large as todetract from effectiveness. Each year, a skills matrix is compiled and reviewedby the Committee. This matrix sets out areas of expertise determined to beessential to ensure appropriate strategic direction and oversight by the board.It also assists with board recruitment. The Committee’s review of boardexperience indicates that the current mix of skills is appropriate.

 

**Nominating a New Director for Election**

 

The Committee identifies andassesses candidates for board appointment or nomination. Our forward-lookingskills matrix has identified skills with the greatest opportunity to strengthenthe board.

 

Before recommending a new boardcandidate, the Committee considers his or her performance, independence,competencies, skills and financial acumen. Character and behavioural qualities,including credibility, integrity and communication skills are considered. TheCommittee Chair and/or Board Chair meets with the candidate to discuss his or herinterest and ability to devote sufficient time and resources to the position.Prior to nomination, potential directors must disclose possible conflicts ofinterest with Nexen, and background checks, as appropriate, are completed.

 

Mr. Hentschel and Mr. Thomsonare retiring from the board at our annual meeting in April due to mandatoryretirement. To fill these vacancies, two directors have been appointed to theboard. Mr. Berry joined on December 8, 2008. He brings skills and expertise ininternational operations and business development, and health, safety andenvironment management. Mr. Bertram joined on January 1, 2009 and brings skillsand expertise in governance and board experience, managing and leading growth,and financial acumen.

 

The Committee maintains anevergreen list of potential directors whose skills complement the board andwhom the Committee recommends joining the board, if the individual is availablewhen an opening arises.

 

Mr. Fischer resigned from theboard effective December 31, 2008 upon his retirement as President and CEO, Mr.Romanow became a member of the board effective January 1, 2009 by virtue of hisappointment as President and CEO. He is not independent and does not sit on anycommittees.

 

The Committee will alsoconsider a board nominee recommended by a shareowner. See page 159 forinformation on communicating with the board.

 

**Performance Evaluations**

 

The board and management worktogether to foster continuous, open and honest communication, where concernsare brought forward and dealt with as they occur. In this spirit, the annualboard evaluation is seen as an opportunity to review the past year and considercontributions, successes and opportunities for improvement. Visitwww.nexeninc.com for a special report on our director evaluation process.

 

Our six-part performanceevaluation review is our primary tool for determining who should be on theboard. In light of this review, the board does not have a tenure policy and hasflexible term limits. Nexen’s average board tenure of director nominees is 8.5years. Our retirement age is 75.

 

The Committee recommended a newonline performance evaluation process in 2008. They also considered commentsfrom the last evaluation to further explore executive compensation and riskmanagement.

 

Theboard rates its overall effectiveness on a ten-point scale, where 10 is thebest. The average rating was 8.9 for 2008 and 9.23 for 2007. The decline in theaverage score is partly explained by a change in the rating scale fromfractional to whole numbers in 2008.

 

158

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**External Recognition and Verification**

 

Wereceived the following recognition for our governance practices during 2008:

 

·                  The Award of Excellence in CorporateGovernance Disclosure in the 2008 Corporate Reporting Awards from the CanadianInstitute of Chartered Accountants;

·                  Recognition from the Canadian Coalition forGood Governance for new best practices in shareholder communication andcompensation disclosure;

·                  Finalist for the Stakeholder CommunicationAward at the 2008 Petroleum Economist Awards in the UK;

·                  The Best Corporate Governance practices inNorth America by IR Global Rankings;

·                  Ranked 7th, with a score of 92 out of 100, inthe Report on Business 2008 corporate governance rankings; and

·                  Current global rating of 10 out of 10 fromGovernance Metrics International for governance practices and disclosure.

 

**Committee Approval**

 

The Committee has reviewed anddiscussed the governance disclosure in this document, including the informationin the Board of Directors section (pages 133 to 137). It has recommended to theboard that the disclosure be included in the proxy circular and, asappropriate, the Form 10-K.

 

**Submitted on behalf of the Governance Committee:**

 

DickThomson, Chair

KevinJenkins

AnneMcLellan

EricNewell

TomO’Neill

FrancisSaville

JohnWillson

 

**Ethics Policy**

 

Under our ethics policy, alldirectors, officers and employees must demonstrate ethical business practicesin all business relationships, within and outside of Nexen. Employees are notpermitted to commit an unethical, dishonest or illegal act or to instruct otheremployees to do so. Our ethics policy has been adopted as a code of ethics forour principal executive officer, principal financial officer and principalaccounting officer or controller.

 

Any waivers of, or changes to,our ethics policy must be board approved and disclosed. We have never waivedany provisions of the ethics policy. Our ethics policy provides for an externalintegrity helpline, in place since February1, 2005.

 

Nexen’s ethics policy isavailable at www.nexeninc.com. If we amend or waive any provision of it, wewill disclose this online. We also file our ethics policy and any amendments toit on SEDAR at www.sedar.com. To request a copy of the policy, contact theIntegrity Resource Centre by emailing integrity@nexeninc.com or calling403.699.6789.

 

**Reporting Concerns**

 

Pleasedirect any concerns about Nexen’s financial statements, accounting practices orinternal controls to either: 

 

·                  management or the Chair of the Audit andConduct Review Committee (Audit Committee) as set out in the ethics policy; or

·                  EthicsPoint, as set out below.

 

Employees,customers, suppliers, partners, shareowners and other external stakeholders whohave a concern are encouraged to raise it with our Integrity Resource Centre:

|       |                       |   |
|------------|----------------------------|--------|
| By  mail:  | Nexen  Inc.                |   |
|       | 801—7th  Avenue SW    |   |
|       | Calgary,  Alberta, Canada  |   |
|       | T2P  3P7                   |   |
| Attention: | Integrity  Resource Centre |   |
| By  email: | integrity@nexeninc.com     |   |
| By  phone: | 403.699.6789               |   |

 

Youmay also report concerns through our integrity helpline, which is a securereporting system, operated by EthicsPoint, an independent third-partyservice provider. To learn more about our integrity helpline and for toll-freenumbers for other countries, visit www.nexeninc.com and click on the “IntegrityHelpline” link at the top of the page or access the helpline directly:

 

| Online:    | www.ethicspoint.com                          |   |
|------------|----------------------------------------------|--------|
| By  phone: | 1.866.384.4277  (toll-free in North America) |   |

 

**Communicating with the Board**

 

Shareownersmay write to the board or any board member(s) at 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 inquiries on manysubjects daily. The board and management have developed a process to manageinquiries so that the appropriate personnel respond to them.

 

159

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Nexen reviews letters andemails addressed to the board, its members or the independent directors, todetermine if a board response is appropriate. While the board overseesmanagement, it does not participate in day-to-day operations and is notnormally in the best position to respond to inquiries on those matters. Thoseinquiries will be directed to appropriate personnel for response. The board hasinstructed the Governance Office to review all correspondence and, in itsdiscretion, not forward items that are:

 

·                  not relevant to Nexen’s operations, policiesor philosophies;

·                  commercial in nature; or

·                  not appropriate for the board to consider.

 

All inquiries will receive aresponse from the board or management. The Governance Office maintains a log ofall correspondence sent to board members. Directors may review the log at anytime and request copies of correspondence received.

 

**AUDIT COMMITTEE REPORT**

 

Seepage 161 for a full report on the Audit Committee.

 

ITEM 12.

 

Security Ownership of Certain Beneficial Owners and Management andRelated Stockholder Matters

 

**SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS**

 

Nexen’s common shares arethe only class of voting securities. Based on information known to Nexen, thefollowing table shows each person or group who beneficially owns (pursuant toSEC Regulations) more than 5% of Nexen’s voting securities as at the date notedbelow.

 
| **Name and Address of Beneficial Owner** | ** ** | **# of Shares Beneficially Owned** | ** ** | **% of Shares Outstanding** | ** ** | **Effective Date** | ** ** |
|-------------------------------------------------------------------|------------|--------------------------------------------------------|------------|--------------------------------------------|------------|-------------------------|------------|
| Jarislowsky, Fraser Limited(1)                                    |       | 47,739,443                                             |       | 9.19                                       | %          | January 31, 2009   |       |
| Suite 2005, 1010 Sherbrooke Street  West                     |       |                                                   |       |                                       |       |                    |       |
| Montreal, Quebec, Canada, H3A 2R7                                 |       |                                                   |       |                                       |       |                    |       |

 

----

*(1)**      **The beneficial owner hassole voting power over 41,087,027 shares, shared voting power over 6,652,416shares and sole power to dispose of all shares.*

 

**Security Ownership of Management**

 

At February 12, 2009,the following directors, certain executive officers, and all directors andexecutive officers as a group beneficially owned the following Nexen commonshares:

 
| **Name of Beneficial Owner**                     | ** ** | **Number of Shares(1)** | ** ** | **Exercisable TOPs(2)** | ** ** |
|-----------------------------------------------------------------|------------|-----------------------------------|------------|------------------------------|------------|
| William B. Berry                                                |       | —                            |       | —                       |       |
| Robert G. Bertram                                               |       | 16,000                            |       | —                       |       |
| Dennis G. Flanagan                                              |       | 31,264                            |       | 20,000                       |       |
| David A. Hentschel                                              |       | 70,925                            |       | 100,000                      |       |
| S. Barry Jackson                                                |       | 72,000                            |       | —                       |       |
| Kevin J. Jenkins                                                |       | 12,415                            |       | 60,000                       |       |
| A. Anne McLellan, P.C.                                          |       | 300                               |       | —                       |       |
| Eric P. Newell, O.C.                                            |       | 12,000                            |       | —                       |       |
| Thomas C. O’Neill                                          |       | 16,000                            |       | —                       |       |
| Marvin F. Romanow                                               |       | 187,432                           |       | 720,400                      |       |
| Francis M. Saville, Q.C.                                        |       | 48,860                            |       | 71,004                       |       |
| Richard M. Thomson, O.C.                                        |       | 92,004                            |       | 150,000                      |       |
| John M. Willson                                                 |       | 15,055                            |       | —                       |       |
| Victor J. Zaleschuk                                             |       | 63,152                            |       | 240,000                      |       |
| Kevin J. Reinhart                                               |       | 46,483                            |       | 330,800                      |       |
| Laurence Murphy                                                 |       | 135,528                           |       | 296,000                      |       |
| Roger D. Thomas                                                 |       | 22,097                            |       | 403,200                      |       |
| Gary H. Nieuwenburg                                             |       | 77,399                            |       | 301,000                      |       |
| **All Directors and Executive Officers as a Group**(25 persons) | ** ** | **1,058,205**                     | ** ** | **3,818,588**                | ** ** |

 

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*(1)**      **The number of shares heldand TOPs exercisable by each beneficial owner represents less than 1% of theshares outstanding.*

*(2)**      **Includes all TOPsexercisable within 60 days of February 12, 2009. All TOPs held bynon-executive directors are vested.*

 

160

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Underthe terms of our TOPs plan, the board may grant options to officers andemployees and, when previously allowed for, to directors. Nexen does notreceive any consideration when options are granted.

 
| **Plan Category**                                 | ** ** | **Number of Securities to  be Issued on Exercise of  Outstanding TOPs** | ** ** | **Weighted-Average  Exercise Price of  Outstanding TOPs** | ** ** | **Number of  Securities Remaining  Available for Future  Issuance under Equity  Compensation Plans** | ** ** |
|--------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------|------------|
| Equity compensation plans approved by  shareowners     |       | 24,622,290                                                                                                      |       | $22/option                                                               |       | 27,429,292                                                                                                                              |       |
| Equity compensation plans not approved by  shareowners |       | —                                                                                                          |       | —                                                                   |       | —                                                                                                                                  |       |
| **Total**                                              | ** ** | **24,622,290**                                                                                                  | ** ** | **$22/option**                                                           | ** ** | **27,429,292**                                                                                                                          | ** ** |

 

ITEM 13.

 

Certain Relationships andRelated Transactions, and Director Independence

 

**RELATEDPARTY TRANSACTION**

 

Asa Canadian foreign private issuer, Nexen provides the disclosure required underItem 7.B. of Form 20-F dealing with “related party transactions.” Nexendid not have any related party transactions in 2008 as defined under thatstandard. Certain other transactions described below which are not relatedparty transactions, involving Nexen and certain of our directors, were enteredinto in 2008.

 

**DIRECTORINDEPENDENCE**

 

Mr. Saville,was a senior partner of Fraser Milner Casgrain LLP (FMC), Barristers andSolicitors, Calgary, Alberta, until the end of January 2004. SinceFebruary 1, 2004, he has been counsel with the firm. FMC provided legalservices to us in each of the last five years. Mr. Saville does notsolicit or participate in these services and does not receive any portion ofthe fees we pay to FMC, nor is he a partner or an employee of the firm. He isindependent under our categorical standards.

 

Ms. McLellan,has been counsel with Bennett Jones (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, nor is shea partner or an employee of the firm. She is independent under our categoricalstandards.

 

Mr. Romanowis not independent as he is Nexen’s President and CEO.

 

Mr. Flanaganis not independent 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 has not been compromisedby this transaction and, accordingly, the board continues to include him intheir meetings without management.

 

ITEM 14.

 

Principal Accounting Fees andServices

 

**AUDITCOMMITTEE REPORT**

 

TheAudit Committee is responsible for appointing (subject to shareowner approval),compensating and overseeing the independent registered chartered accountants(IRCAs). The IRCAs are accountable to and report directly to the Committee, andunderstand that they must maintain an open and transparent relationship withthe Committee, which represents our shareowners.

 

AllCommittee members are independent and knowledgeable on our financial reportingcontrols, and internal and external audit processes. Five members are skilledor expert in financial acumen, particularly financial accounting, reporting andinternal controls—expertise most relevant to theCommittee’s mandate.

 

TheCommittee assists the board in overseeing Nexen’s system of internal accountingand financial reporting controls, internal and external audit processes, andimplementation of the ethics policy.

 

Managementis responsible for our internal controls and financial reporting process. TheIRCAs are responsible for independently auditing our: i) consolidated financialstatements according to Canadian and US generally accepted auditing standardsand the standards of the Public Company Accounting Oversight Board (UnitedStates); and, ii) internal control over financial reporting according to thestandards of the Public Company Accounting Oversight Board. The Committeemonitors and oversees these processes.

 

**Changes toCommittee Membership in 2008**

 

TheCommittee membership did not change in 2008.

 

161

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**KEYACTIVITIES FOR 2008**

 

·      Metseparately with management and the IRCAs to review the December 31, 2008consolidated financial statements;

·      Discussedmatters required by Canadian and US regulators with the IRCAs;

·      Receivedwritten disclosures from the IRCAs required by US regulators;

·      Discussedwith the IRCAs that firm’s independence;

·      Discussedthe scope and result of the audit with the IRCAs;

·      Oversawthe compliance activities by management to report on the effectiveness ofinternal control over financial reporting as at December 31, 2008;

·      Reviewedand approved the quarterly consolidated financial statements;

·      Recommendedto the board that the audited consolidated financial statements be included inNexen’s annual report on Form 10-K for the year ended December 31,2008, based on the reviews and discussions referred to above; and

·      ReviewedNexen’s progress on its planned transition to International Financial ReportingStandards.

 

**AuditPartner Rotation**

 

Tocomply with applicable law, the lead audit partner of our IRCAs is replacedevery five years.

 

**Sections302 and 404 of Sarbanes-Oxley**

 

Nexenis a voluntary filer of the Form 10-K in the US and has complied with therequirements of Sections 302 and 404 of Sarbanes-Oxley since December 31, 2004.Accordingly, Nexen is in compliance with *National Instrument 52-109*—*Certification of Disclosure in Issuers’ Annual andInterim Filings*. In 2008, management assessed our internal controlover financial reporting and concluded that it was effective as of December 31,2008. The integrated audit report for 2008 is included in this Form 10-K.

 

**IRCAsEngagement and Fees Billed**

 

BeforeNexen or any subsidiary engage the IRCAs for additional audit or non-auditservices, the Committee must approve the engagement. The Audit Committee hasthe discretion to delegate to the committee Chair, on an annual basis, theauthority to pre-approve the hiring of the IRCAs for minor, time-sensitiveaudit services, provided any pre-approvals are presented in writing to theCommittee at the next scheduled meeting. The Audit Committee has the discretionto annually delegate to one or more of its members the authority to grantpre-approvals for non-audit services provided any pre-approvals are presentedin writing to the Committee at the next scheduled meeting. Since May 6,2003, the Committee has approved all audit, audit-related, tax and otherservices provided by the IRCAs.

 
| **Type of Fee**                                                                                                       | ** ** | **Billed in 2007** | ** ** | **Billed in 2008** | ** ** | **Percentage of Total  Fees Billed in 2008** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|-----------------------------------------------------------------------|------------|
| **Audit Fees**                                                                                                                  | ** ** | ** **                   | ** ** | ** **                   | ** ** | ** **                                                            | ** ** |
| For the integrated audit of Nexen’s  consolidated financial statements included in our annual report on  Form 10-K    | ** ** | 2,966,000                    | (1)        | 2,812,000                    | (2)        |                                                                  |       |
| For the integrated audit of the  consolidated financial statements of Canexus(3)                                                |       | 145,000                      |       | 215,600                      | (4)        |                                                                  |       |
| For the first, second and third quarter  reviews of Nexen’s consolidated financial statements included in  Form 10-Qs |       | 90,000                       |       | 110,000                      |       |                                                                  |       |
| 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                                                                             |       | 153,500                      |       | 3,000                        |       |                                                                  |       |
| **Total Audit Fees**                                                                                                            | ** ** | **3,399,500**                | ** ** | **3,185,600**                | ** ** | **68**                                                                | **%**      |
| ** **                                                                                                                      | ** ** | ** **                   | ** ** | ** **                   | ** ** | ** **                                                            | ** ** |
| Audit-Related Fees — Nexen and Canexus(3)                                                                                  |       |                         |       |                         |       |                                                                  |       |
| For the annual audits and quarterly reviews  of subsidiary financial statements and employee benefit plans                      |       | 828,100                      |       | 1,144,700                    |       |                                                                  |       |
| **Total Audit-Related Fees**                                                                                                    | ** ** | **828,100**                  | ** ** | **1,144,700**                | ** ** | **24**                                                                | **%**      |
| ** **                                                                                                                      | ** ** | ** **                   | ** ** | ** **                   | ** ** | ** **                                                            | ** ** |
| Tax Fees — Nexen and Canexus(3)                                                                                            |       |                         |       |                         |       |                                                                  |       |
| For tax return preparation assistance and  tax-related consultation                                                             |       | 116,400                      |       | 139,800                      |       |                                                                  |       |
| **Total Tax Fees**                                                                                                              | ** ** | **116,400**                  | ** ** | **139,800**                  | ** ** | **3**                                                                 | **%**      |
| ** **                                                                                                                      | ** ** | ** **                   | ** ** | ** **                   | ** ** | ** **                                                            | ** ** |
| All Other Fees                                                                                                                  | ** ** | 110,600                      | (5)        | 216,300                      | (5)        | 5                                                                     | %          |
| **Total Annual Fees**                                                                                                           | ** ** | **4,454,600**                | ** ** | **4,686,400**                | ** ** | **100**                                                               | **%**      |

 

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*(1)**      **Consisting of $1,366,000 to complete the 2006 audit and$1,600,000 to commence the 2007 audit.*

*(2)**      **Consisting of $936,000 to complete the 2007 audit and$1,876,000 to commence the 2008 audit.*

*(3)**      **Includes fees for Canexus Income Fund, Canexus LimitedPartnership and its subsidiaries.*

*(4)**      **Consisting of $121,500 to complete the 2007 audit and$93,100 to commence the 2008 audit.*

*(5)**      **Annual renewal fees for an upstream information databaseused in our UK office.*

 

TheCommittee concludes that the services provided by the IRCAs as described in“All Other Fees” above maintains that firm’s independence.

 

162

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**ExternalRecognition and Verification**

 

Nexenwas recognized in 2008 with the Award of Excellence for Corporate Reporting inthe Oil and Gas category of the Corporate Reporting Awards from the CanadianInstitute of Chartered Accountants.

 

**CommitteeApproval**

 

Basedon the Committee’s discussions with management and the IRCAs, and its review ofboth their representations, the Committee recommended to the board that theaudited consolidated financial statements be included in Nexen’s annual reporton Form 10-K for the year ended December 31, 2008.

 

**Submittedon behalf of the Audit Committee:**

 

TomO’Neill, Chair

EricNewell

BarryJackson

DickThomson

KevinJenkins

JohnWillson

 

**PART IV**

 

ITEM15.

 

Exhibits,Financial Statement Schedules

 

**FINANCIALSTATEMENTS AND SCHEDULES**

 

Werefer you to the index to Financial Statements and Supplementary Data in Item 8of this report where these documents are listed.

 

Schedulesand separate financial statements of subsidiaries are omitted because they arenot required or applicable, or the required information is shown in theConsolidated Financial Statements or notes.

 

**EXHIBITS**

 

Exhibitsfiled as part of this report are listed below. Certain exhibits have beenpreviously filed with the Commission and are incorporated in thisForm 10-K by reference. Instruments defining the rights of holders of debtsecurities that do not exceed 10% of Nexen’s consolidated assets have not beenincluded. A copy of such instruments will be furnished to the Commission uponrequest.

 
| 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).                                             |

 

163

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| 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).  |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.55   | 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).                                                                                                                          |
| 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). |
| 4.57   | Amended and Restated Shareholder Rights Plan Agreement,  dated April 29, 2008 between the Registrant and CIBC Mellon Trust  Company, as Rights Agent (filed as Exhibit 4.57 to Form 8-K dated  April 30, 2008).                                                                                                                                      |
| 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).                                                                                                                                                                                            |
| 10.50  | 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).                                                                                                              |
| 10.52  | Amended and Restated Agreement Respecting Change of  Control and Executive Benefit Plan Entitlements with Executive Officers dated  during August and September, 2008 (filed as Exhibit 10.52 to  Form 10-Q for the quarterly period ended September 30, 2008).                                                                                      |
| 10.53  | Amended and Restated Agreement Respecting Change of  Control and Executive Benefit Plan Entitlements with Kevin J. Reinhart dated  as of September 16, 2008 (filed as Exhibit 10.53 to Form 8-K  dated November 21, 2008).                                                                                                                           |
| 10.54  | Form of Indemnification Agreement between the  Registrant and William B. Berry and Robert G. Bertram (filed as  Exhibit 10.54 to Form 8-K dated December 10, 2008).                                                                                                                                                                                  |
| 10.55  | Amending Agreement dated as of December 9, 2008 to  the Amended and Restated Agreement Respecting Change of Control and Executive  Benefit Plan Entitlements with Marvin F. Romanow dated as of  September 17, 2008 (filed as Exhibit 10.55 to Form 8-K dated  December 10, 2008).                                                              |
| 10.56* | Tandem Option Plan amended June 30, 2007.                                                                                                                                                                                                                                                                                                                           |
| 11.1*  | Statement regarding the Computation of Per Share Earnings  for the three years ended December 31, 2008.                                                                                                                                                                                                                                                             |
| 21.1*  | Subsidiaries of the Registrant.                                                                                                                                                                                                                                                                                                                                          |
| 23.1*  | Consent of Independent Registered Chartered Accountants.                                                                                                                                                                                                                                                                                                                 |
| 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.                                                                                                                                                                                                         |

 

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**Filed with this Form 10-K.*

 

164

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**SIGNATURES**

 

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the Company has duly caused this report to be signed on its behalfby the undersigned, thereunto duly authorized, on February 20, 2009.

 
|   |   | NEXEN INC.                                 |
|--------|--------|--------------------------------------------|
|   |   |                                       |
|   |   | By:                                        | /s/ Marvin F. Romanow |
|   |   | Marvin F. Romanow                          |
|   |   | President, Chief Executive Officer         |
|   |   | and Director (Principal Executive Officer) |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the registrant and inthe capacities indicated on February 20, 2009.

 
| /s/ Dennis G. Flanagan           |   | /s/ John M. Willson                               |
|----------------------------------|--------|---------------------------------------------------|
| Dennis G. Flanagan, Director     |   | John M. Willson, Director                         |
|                             |   |                                              |
| /s/ David A. Hentschel           |   | /s/ Victor J. Zaleschuk                           |
| David A. Hentschel, Director     |   | Victor J. Zaleschuk, Director                     |
|                             |   |                                              |
| /s/ S. Barry Jackson             |   | /s/ Marvin F. Romanow                             |
| S. Barry Jackson, Director       |   | Marvin F. Romanow                                 |
|                             |   | President, Chief Executive Officer                |
| /s/ Kevin J. Jenkins             |   | and Director (Principal Executive Officer)        |
| Kevin J. Jenkins, Director       |   |                                              |
|                             |   | /s/ Kevin J. Reinhart                             |
| /s/ A Anne McLellan, Director    |   | Kevin J. Reinhart                                 |
| A. Anne McLellan, Director       |   | Senior Vice President and Chief Financial Officer |
|                             |   | (Principal Financial Officer)                     |
| /s/ Eric P. Newell               |   |                                              |
| Eric P. Newell, Director         |   | /s/ Brendon T. Muller                             |
|                             |   | Brendon T. Muller                                 |
| /s/ Thomas C. O’Neill       |   | Controller                                        |
| Thomas C. O’Neill, Director |   | (Principal Accounting Officer)                    |
|                             |   |                                              |
| /s/ Francis M. Saville           |   | /s/ Eric B. Miller                                |
| Francis M. Saville, Director     |   | Eric B. Miller                                    |
|                             |   | Vice President, General Counsel                   |
| /s/ Richard M. Thomson           |   | and Secretary                                     |
| Richard M. Thomson, Director     |   |                                              |

 

165

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