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**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-K**

 

**ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OFTHE SECURITIES EXCHANGE ACT OF 1934**

 

**For the year endedDecember 31, 2009**

 

**Commission File Number 1-6702**

 

**NEXENINC.**

**Incorporated under the Laws of Canada**

 

 

**98-6000202**

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

 

**801 – 7th Avenue S.W.**

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

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

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

 

SECURITIES REGISTERED PURSUANT TOSECTION 12(B) OF THE ACT:

 

| **TITLE**                          | ** ** | **EXCHANGE  REGISTERED ON**                              |
|------------------------------------|------------|----------------------------------------------------------|
| Common  shares, no par value       |       | The  New York Stock Exchange  The Toronto Stock Exchange |
|                               |       |                                                     |
| Subordinated  Securities, due 2043 |       | The  New York Stock Exchange  The Toronto Stock Exchange |

 

SECURITIES REGISTERED PURSUANT TOSECTION 12(G) OF THE ACT: **NONE.**

 

Indicate by check mark if the registrant is awell-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes x  No o

 

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 orSection 15(d) of the Exchange Act. Yes o  No x

 

Indicate by check markwhether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filingrequirements for the past 90 days.  Yes x  No o

 

Indicate by check mark if disclosure of delinquent filerspursuant to Item 405 of Regulation S-K is not contained herein, and will not becontained, to the best of registrant’s knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of thisForm 10-K or any amendment to this Form 10-K.  x

 

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filer, a non-accelerated filer, or a smaller reporting company. Seethe definitions of “large accelerated filer”, “accelerated filer” and “smallerreporting company” in Rule 12b-2 of the Exchange Act.

 

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

 

Indicate by check mark whether the registrant is ashell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o  No x

 

OnJune 30, 2009, the aggregate market value of the voting shares held bynon-affiliates of the registrant was approximately Cdn$13 billion based on theToronto Stock Exchange closing price on that date. On January 31, 2010,there were 523,285,022 common shares issued and outstanding.

 

 

 

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**TABLE OFCONTENTS**

 
| **Part I**   | Items 1 and 2: Business and  Properties                                                                                         | 1   |
|-------------------|---------------------------------------------------------------------------------------------------------------------------------|-----|
| ** **        | Item 1A: Risk  Factors                                                                                                          | 40  |
| ** **        | Item 1B:  Unresolved Staff Comments                                                                                             | 48  |
| ** **        | Item 3: Legal  Proceedings                                                                                                      | 48  |
| ** **        | Item 4:  Submission of Matters to a Vote of Security Holders                                                                    | 48  |
| **Part II**  | Item 5: Market for the Registrant’s  Common Equity, Related Stockholder Matters and Issuer Purchases of Equity  Securities | 48  |
| ** **        | Item 6: Selected  Financial Data                                                                                                | 50  |
| ** **        | Item 7: Management’s Discussion and  Analysis of Financial Condition and Results of Operations                             | 51  |
| ** **        | Item 7A:  Quantitative and Qualitative Disclosures about Market Risk                                                            | 92  |
| ** **        | Item 8: Report  of Management                                                                                                   | 99  |
| ** **        | Item 9: Changes  in and Disagreements with Accountants on Accounting and Financial Disclosure                                   | 158 |
| ** **        | Item 9A:  Controls and Procedures                                                                                               | 158 |
| **Part III** | Items 10 and 11: Directors, Executive  Officers and Corporate Governance, and Executive Compensation                            | 161 |
| ** **        | Item 12:  Security Ownership of Certain Beneficial Owners and Management and Related  Stockholder Matters                       | 200 |
| ** **        | Item 13:  Certain Relationships and Related Transactions, and Director Independence                                             | 201 |
| ** **        | Item 14:  Principal Accounting Fees and Services                                                                                | 201 |
| **Part IV**  | Item 15: Exhibits, Financial Statement  Schedules                                                                               | 204 |

 

***Canadian investors torefer to the “*****Special Note to CanadianInvestors” set out on page 97 of this Form 10-K.**

 

**Unless we indicate otherwise,all dollar amounts ($) are in Canadian dollars, and oil and gas volumes,reserves and related performance measures are presented on a working interestbefore-royalties basis. Where appropriate, information on an after-royaltiesbasis is provided in tabular format.**

 

**Below is a list of terms specific to the oil andgas 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 CrudeTM           |
| 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 to oil and gas in common units calledbarrel of oil equivalent (boe). A boe is derived by converting six thousandcubic feet of gas to one barrel of oil (6 mcf/1 bbl). This conversion may bemisleading, particularly if used in isolation, as the 6mcf/1bbl ratio is basedon an energy equivalency at the burner tip and does not represent the valueequivalency at the wellhead.

 

The noon-day Canadian to US dollar exchange rates forCdn$1.00, as reported by the Bank of Canada, were:

 
| **(US$)** | ** ** | **December 31** | ** ** | **Average** | ** ** | **High** | ** ** | **Low** | ** ** |
|-----------|------------|----------------------|------------|-------------|------------|----------|------------|---------|------------|
| 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  |       |
| 2009      |       | 0.9555               |       | 0.8757      |       | 0.9716   |       | 0.7692  |       |

 

On January 29, 2010, the noon-day exchange rate wasUS$0.9390 for Cdn$1.00.

 

Electronic copies of our filings with the Securities ExchangeCommission (SEC) and the Ontario Securities Commission (OSC) (from November 8,2002 onward) are available, free of charge, on our website (www.nexeninc.com).Filings prior to November 8, 2002 are available free of charge, onrequest, by contacting our investor relations department at 403.699.5931. Assoon as reasonably practicable, our filings are made available on our websiteonce they are electronically filed with the SEC and/or the OSC. Alternatively,the SEC and the OSC each maintain a website (www.sec.gov and www.sedar.com)that contains our reports, proxy and information statements and other publishedinformation that have been filed or furnished with the SEC and the OSC. Theinformation on our website, is not, and shall not be deemed to be, a part ofthis Annual Report on Form 10-K.

 

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**Part I**

 
| Items 1 and 2: Business  and Properties                                                                                         |       |
|---------------------------------------------------------------------------------------------------------------------------------|------------|
| About Us                                                                                                                        | 1          |
| Strategy                                                                                                                        | 2          |
| Positioned for Success—Focused on Value                                                                                    | 3          |
| Oil and Gas                                                                                                                     | 4          |
| Understanding the Oil and Gas Business                                                                                          | 6          |
| Athabasca  Oil Sands                                                                                                            | 7          |
| Conventional Exploration and Development                                                                                        | 12         |
| Unconventional Gas                                                                                                              | 22         |
| Reserves, Production and Related Information                                                                                    | 23         |
| Energy Marketing                                                                                                                | 34         |
| Chemicals                                                                                                                       | 35         |
| Government and Environmental Regulations                                                                                        | 36         |
| Employees                                                                                                                       | 40         |
|                                                                                                                            |       |
| Item 1A: Risk  Factors                                                                                                          | 40         |
|                                                                                                                            |       |
| Item 1B:  Unresolved Staff Comments                                                                                             | 48         |
|                                                                                                                            |       |
| Item 3: Legal  Proceedings                                                                                                      | 48         |
|                                                                                                                            |       |
| Item 4:  Submission of Matters to a Vote of Security Holders                                                                    | 48         |
|                                                                                                                            |       |
| **Part II**                                                                                                                | ** ** |
|                                                                                                                            |       |
| Item 5: Market  for the Registrant’s Common Equity, Related Stockholder Matters and Issuer  Purchases of Equity Securities | 48         |
|                                                                                                                            |       |
| Item 6: Selected  Financial Data                                                                                                | 50         |

 

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**PART I**

 

**ITEMS 1. AND2.**

 

**Business and Properties**

 

*Certain statements inthese items 1 and 2 constitute “forward-looking statements” and the readershould refer to the “Special Note Regarding Forward-Looking Statements” set outon page 96 of this Form 10-K.*

 

**ABOUT US**

 

Nexen Inc. (Nexen, we or our) is an independent,Canadian-based, global energy company. We were formed in Canada in 1971 asCanadian Occidental Petroleum Ltd. when Occidental Petroleum Corporationcombined their Canadian crude oil, natural gas, sulphur and chemical operationsinto one company.

 

In the 1970s, we broadened ourwestern Canadian asset base and entered the US Gulf of Mexico. In the 1980s, wegrew our western Canadian and Gulf of Mexico assets through acquisitions andcaptured an interest in Syncrude. In the 1990s, we had two definingevents—first, we discovered the first of 17 fields at Masila in Yemen in 1990and commenced production in 1993. Second, we tripled our Canadian production in1997 by purchasing Wascana Energy Inc. We leveraged our success in Yemen andwestern Canada to fund our growth elsewhere and today we are focused on threestrategic growth areas: i) oil sands, including our 65% operated interest inthe Long Lake project and our interest in Syncrude; ii) conventionalexploration and development properties in our core areas including the NorthSea, US Gulf of Mexico, Canada, Yemen and offshore West Africa; and iii)unconventional gas focused on our shale gas play in northeastern BritishColumbia.

 

We’ve grown from producing10,700 boe/d before royalties with revenues of $26 million in 1971, toproducing over 240,000 boe/d before royalties and revenues of $5.8 billionin 2009. We achieved this growth through exploration success and strategicacquisitions. Operating for almost 40 years, we have been profitable everyyear, except one, and have been paying quarterly dividends consecutively since1975.

 

 

 

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**STRATEGY**

 

Choice—it’s what companies and investorsvalue. Whether it’s how we allocate capital, fund our growth, or invest inprojects that make the most sense over the long term, choice is key. Ourstrategy is to build a sustainable energy company focused on exploiting ourexisting three key growth areas: i) oil sands, ii) select conventionalexploration and development, and iii) unconventional gas.

 

**OIL SANDS**

 

Our oil sands investmentsinclude interests in the Long Lake project, the Syncrude joint venture and our735,000 undeveloped acres (gross) in the Athabasca oil sands in northernAlberta. Our oil sands strategy is designed to provide steady and predictablecash flow for decades.

 

We first entered the oil sandsby acquiring an interest in the Syncrude joint venture. Syncrude develops andproduces synthetic crude oil from mining bitumen.

 

In 2001, we formed a 50/50joint venture with OPTI Canada Inc. (OPTI) to develop, produce and upgradebitumen on our joint lands in the Athabasca oil sands. Production utilizes ourpatented OrCrudeTM technology, which we expect will ultimately result in atleast a $10/bbl margin advantage over conventional oil sands extraction andupgrading. Construction of the Long Lake project was completed in 2008 and webegan producing premium synthetic crude oil (PSCTM) in 2009. In early 2009, weacquired an additional 15% interest in the Long Lake project and joint venturelands from OPTI, increasing our ownership level to 65%. Following thisacquisition, we are now responsible for operating both thesteam-assisted-gravity-drainage (SAGD) bitumen extraction process and theupgrader for Phase 1 as well as for future phases.

 

**CONVENTIONAL EXPLORATION AND DEVELOPMENT**

 

Our conventional explorationand development is comprised of large acreage positions in select basinsincluding the North Sea, deep-water Gulf of Mexico and offshore West Africa.Strategically, we focus on these basins due to: i) past successes; ii) existinginfrastructure in place; iii) significant potential in remaining resource; andiv) attractive fiscal terms. Our global exploration team prioritizesinvestments in prospects that we expect will generate the highest returns inour selected basins of choice.

 

In the North Sea, we are asignificant regional player with concentrated assets, infrastructure andexploration potential for future growth. We operate the Buzzard field andplatform, which is the largest discovery in the UK North Sea in over a decade.We have since made several discoveries including Pink, Hobby and Golden Eaglein the Golden Eagle area; Blackbird; and Rochelle. We continue to activelyexplore the basin including relatively under-explored areas such as west of theShetland Islands and in Norway.

 

In the deep-water Gulf ofMexico, we made several significant discoveries including Gunnison, Aspen,Knotty Head, Wrigley and Longhorn. We accumulated a large inventory ofdeep-water acreage and are a significant leaseholder in the Gulf. Thedeep-water Gulf is near infrastructure and continental US markets, sodiscoveries can be brought on stream in a reasonable time.

 

We have several significantdiscoveries offshore West Africa, including Usan, Usan West and Ukot, as wellas our most recent success at Owowo South, offshore Nigeria. We are progressingthe Usan field development with a floating production and storage offloading(FPSO) vessel and subsea facilities for scheduled first production in 2012.

 

**UNCONVENTIONAL GAS**

 

Our unconventional gas strategyis currently focused primarily on the Horn River Basin in northeast BritishColumbia. The Horn River Basin is emerging as a significant shale gas play withhigh resource density and excellent well productivity. We have a substantialland position in the Horn River Basin, with approximately 90,000 acres in theDilly Creek area and 38,000 acres in the Cordova area, with a 100% workinginterest in each.

 

Shale gas complements our corporateportfolio which consists predominantly of large scale, and capital intensive,long cycle-time projects. It provides natural gas exposure and short cycle-timeprojects where we control the scale and pace of development.

 

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**POSITIONED FOR SUCCESS—FOCUSED ON VALUE**

 

Our goal is to grow long-term value for our shareholdersresponsibly. Key drivers to grow value are increasing reserves, production, cashflow and net income on a cost-effective basis over the long term. Success inour three strategic growth areas and existing producing properties deliversgrowth in long-term value. Today, we are building sustainable businesses in theNorth Sea, western Canada, Gulf of Mexico, and offshore West Africa,capitalizing on the following corporate strengths:

 

**RESOURCE INVENTORY**

 

·                  diversification—ourassets are geographically diverse and we produce oil and gas, onshore andoffshore. We have large conventional and unconventional legacy assets in ourportfolio which allows us to pursue value opportunities in varying economicenvironments;

·                  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 199 net sections in the emerging Horn River Basin shale gas playin northeast British Columbia, and we hold significant unexplored acreage inthe Gulf of Mexico, the North Sea, and offshore West Africa; and

·                  production weighted tocrude oil—current production is approximately 85% and proved reserves areapproximately 92% weighted to crude oil, respectively.

 

**STRUCTURAL GROWTH**

 

·                  focus ongrowth—significant production growth is expected to come from identifiedprojects currently under development. We are successful explorers withundeveloped discoveries at Knotty Head and Vicksburg in the Gulf of Mexico, theGolden Eagle area in the UK North Sea, and Usan and Owowo South, offshoreNigeria. We are ramping up production at Long Lake and continue to advance ourshale gas play in the Horn River Basin. Our production has grown at acompounded annual growth rate of over 10% for the last three years.

 

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**FINANCIAL STRENGTH**

 

·                  strong financialposition—we have access to over $3 billion of liquidity through cash andundrawn committed credit facilities that will allow us to proceed withinvestments at our pace and to take advantage of organic and otheropportunities as they arise; and

·                  industry-leading cashnetbacks—position us well to withstand lower commodity prices.

 

**SUPERIOR TALENT**

 

·                  internationalexpertise—we are an international operator with a proven track record ofsuccessful business ventures in Yemen, the United Kingdom, Nigeria, Colombiaand Australia;

·                  employer of choice—provenability to retain and attract talent (Hewitt Top 50 Employer in Canada); and

·                  skilled workforce—wesignificantly enhanced our technical skills over the last few years by hiringexperienced employees for our Long Lake, shale gas, and Gulf of Mexicobusinesses.

 

**HOW WE DO BUSINESS**

 

·                  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; and

·                  leadership—industryleader in governance, community relations and environmental stewardship.

 

Forfinancial reporting purposes, we report on three main segments:

 

·                  oil and gas;

·                  energy marketing; and

·                  chemicals.

 

Our oil and gas operations arebroken down geographically into the UK North Sea, Canada, Syncrude, US Gulf ofMexico, Yemen and Other International (currently Colombia, offshore West Africaand Norway). Results from our Long Lake project are included in Canada. EnergyMarketing includes our crude oil, natural gas, natural gas liquids and powermarketing businesses in North America, Europe and Asia. Chemicals includesoperations in North America and Brazil that manufacture, market and distributesodium chlorate, caustic soda, muriatic acid and chlorine through the CanexusIncome Fund.

 

Production, revenues, netincome, capital expenditures and identifiable assets for these segments appearin Note 20 to the Consolidated Financial Statements and in Management’sDiscussion and Analysis of Financial Condition and Results of Operations(MD&A) in this report. Reserves for our oil and gas operations appear on page 23.

 

**OIL AND GAS**

 

We have oil and gas operationsin the UK North Sea, US Gulf of Mexico, western Canada, Yemen, offshore WestAfrica, Colombia, and Norway. We also have operations in Canada’s Athabasca oilsands which produce synthetic crude oil. We operate most of our production andcontinue to develop new growth opportunities in each area by actively exploringand applying technology.

 

In this Form 10-K, weprovide estimates of remaining quantities of proved and probable oil, syntheticoil and natural gas reserves (oil and gas reserves) for our various properties.Our reserves estimates and related disclosures have been prepared in accordancewith the definitions and disclosure requirements prescribed by the UnitedStates Securities and Exchange Commission (SEC). Our reserve estimates anddisclosures may differ from other Canadian issuers who follow Canadiandisclosure standards as set-out in National Instrument 51-101—*Standards of Disclosure for Oil and Gas Activities*(NI 51-101). Significant differences between SEC and Canadian reservesestimates and disclosures are described on page 97 (see Special Note toCanadian Investors).

 

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OnDecember 31, 2008, the SEC issued final revised rules relating toreserve definitions and related disclosure requirements. These new rules areeffective for estimates and disclosures made on or after January 1, 2010,including those in this report. The primary impacts of changes on our reservesestimates resulting from the adoption of the new rules are as follows:

 

·                  our Syncrude oil sandsactivities are now considered an oil and gas activity rather than a miningactivity. This impacts the classification of the reserves but does not resultin a change in the estimate of reserves;

·                  reserves quantities arenow based on the final product sold after field upgrading rather than theproduct initially produced. This results in presenting our Long Lake oil sandsreserves as synthetic oil barrels rather than bitumen barrels. This results ina reduction in quantity reflecting the removal of the asphaltenes from thebitumen barrel, which we gasify for use as our internal fuel source in thesteam generation, upgrading and cogeneration power processes;

·                  prices underlying oureconomic assumptions used for reserves estimation are now based on the averagefirst-day-of-the-month prices during the year, rather than the prices on December 31each year; and

·                  we are voluntarilydisclosing probable reserves in addition to proved reserves in this Form 10-K.

 

Theimpact of the new rules on our reserves estimates also require us tomodify our reserves disclosures this year to transition our reserves estimatesfrom the old rules to the new rules. We have chosen to report ourtransition to the new rules in a manner that we believe best illustratesthe impact of the changes on our reserves estimates and allows us to clearlypresent how our reserves estimates changed during 2009 as a result of ouroperational activities separate from the adoption of the new rules.Accordingly, throughout this report, we have reported the impact of the new rules onour December 31, 2009 reserves estimates as follows:

 

·                  the impact of the new rules onour proved reserves estimates have been shown separately in each table in aline entitled “SEC Rule Transition”, except for the impact of the changein the pricing rule. The new pricing rule was used in the preparation ofthe 2009 reserves estimates so there is no separate adjustment for this change.The prices underlying the year-end reserves estimates under the old and new rules changeeach year, and are a key determinant of whether the reserves are economic.Given its pervasive impact on the reserves estimates for each property, we feltit was most efficient to use the new pricing rule;

·                  we have segregatedchanges in reserves estimates in transitioning from the old rules to thenew rules between those which pertains to the prior year’s estimates andthose pertaining to changes in reserves during the year. We feel thisadditional information is helpful in understanding the impact of the changes onthe current year’s activities;

·                  since we reported certaininformation with respect to Syncrude’s proved reserves in our prior Form 10-Ks,we included such information in our prior years’ reserves balances as if it wasalways an oil and gas activity. We have also presented a portion of thepreviously reported mining reserves as proved undeveloped reserves at December 31,2008, by applying the oil and gas definitions. We feel this improves theconsistency of reserves reporting, eliminates confusion that may arise byincluding the prior years’ information in a different place in this report andallows for better presentation of the activities during 2009; and

·                  since we reportedprobable reserves estimates in other disclosure documents in prior years, wehave presented a continuity schedule as if they had been reported in our Form 10-Klast year. This allows the probable reserves information to be presentedconsistently in our various reporting documents and provides for disclosure ofchanges in our probable reserves during 2009. Probable reserves estimates inprior years were prepared in accordance with NI 51-101 and the Canadian Oil andGas Evaluation Handbook standards. Similar to the manner in which we havepresented the impact of the new SEC rules on our proved reservesestimates, the impact of converting our 2008 probable reserves estimates to thenew SEC rules is shown separately in each probable reserves table on thelines entitled “SEC Rule Conversion”, except for the impact of the newpricing rule which was used in preparation of the 2009 reserves estimates.See page 27 for a description of probable reserves.

 

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Our proved and probable reserveestimates are internally prepared. We had 98% of our proved reserves beforeroyalties (98% after royalties) assessed (either evaluated or audited asdescribed on page 29) by independent reserves consultants. Theirassessment of the proved reserves are performed at varying levels of propertyaggregation, and we work with them to reconcile the difference on the portfolioof properties to within 10% in the aggregate. Estimates pertaining toindividual properties within the portfolio may differ by more than 10%, eitherpositively or negatively; however, we believe such differences are not materialrelative to our total proved reserves.

 

We also had 98% of our provedplus probable oil and gas reserves before royalties (98% after royalties)assessed by independent reserves consultants. By definition, probable reservesmust be determined together with proved reserves (see definition on page 27).As such, the independent reserves consultants’ assessments are prepared on acombined proved plus probable basis. Like proved reserves, their assessment ofthe proved plus probable reserves are performed at varying levels of propertyaggregation, and we work with them to reconcile the difference on the portfolioof properties to within an acceptable tolerance for the aggregate. Estimatespertaining to individual properties within the portfolio may differ by morethan the acceptable tolerance, either positively or negatively; however, webelieve such differences are not material relative to our total proved plusprobable reserves.

 

Refer to the section on Basisof Reserves Estimates on page 29 for a description of our internalreserves process and the nature and scope of the independent assessmentsperformed on our proved and probable reserves estimates and the resultsthereof.

 

**UNDERSTANDING THE 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. We have captured an inventory ofsignificant opportunities in our core growth areas and our goal is to extractthe maximum value from each barrel of oil equivalent so that every dollar ofcapital we invest generates 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 generate positivereturns at relatively low commodity prices. We maintain liquidity that providesus with the ability to invest in high-quality projects that we believe willgenerate value over the long term.

 

The prices we receive for ouroil and gas products are determined by global crude oil and natural gas marketsand regional dynamics, all of which can be volatile. With many alternativecustomers, the loss of any one customer is not expected to have a significantlyadverse effect on the price of our products or revenues. Oil and gas producingoperations are generally not seasonal. However, demand for some of our productscan fluctuate season to season, which impacts price. In particular, natural gasis generally in higher demand in the winter for heating. We manage ouroperations on a country-by-country basis, reflecting differences in theregulatory regime, and competitive environments and risk factors associatedwith each country.

 

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**Nexen Consolidated Reserves andProduction**

 

In the charts below, ourconsolidated proved and probable reserves as at December 31, 2009 arepresented, along with our oil and gas production for the year ended December 31, 2009.

 

 

 

**ATHABASCA OIL SANDS**

 

·                  We made significant progress in the year proving that we cangasify the bottom of the bitumen barrel for internal fuel and upgrade theresidual to a premium synthetic crude oil

 

·                  We have significant undeveloped acreage in the Athabasca oilsands, totalling over 700,000 acres (gross)

 

·                  Syncrude, which mines the oil sands and produces syntheticcrude oil, has been operating for almost 35 years

 

The Athabasca oil sands depositin northeast Alberta is a key growth area for us. Our strategy is toeconomically develop our bitumen resource in phases to provide low-risk,stable, future growth over the long term. Our Long Lake project involvesintegrating SAGD bitumen production with field upgrading technology to producepremium synthetic crude for sale, and synthetic gas which significantly reducesour need to purchase natural gas for operations. We also have a 7.23%investment in the Syncrude oil sands operation.

 

**Synthetic (Insitu Long Lake)**

 

 

 

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In 2001, we formed a 50/50joint venture with OPTI to develop the Long Lake lease using SAGD for bitumenproduction and proprietary OrCrudeTM technology for the first stage ofupgrading. OPTI has the exclusive Canadian license for the OrCrudeTM technology.We acquired the exclusive right to use this technology with OPTI withinapproximately 100 miles of Long Lake, and the right to use the technologyelsewhere in Canada and the rest of the world (excluding Israel) subject tocertain rights of OPTI to participate.

 

SAGD bitumen operations startedmid 2008 and we began producing PSCTM from the upgrader in January 2009. Earlyin 2009, we acquired an additional 15% interest in the Long Lake project andthe joint venture lands from OPTI, increasing our ownership level to 65%.Following this acquisition, we are now responsible for operating both the SAGDbitumen extraction process and the upgrader for Phase 1 as well as for futurephases.

 

**SAGD AND UPGRADER INTEGRATION**

 

The SAGD process involvesdrilling two parallel horizontal wells, generally between 2,300 and 3,300 feetlong, with about 16 feet of vertical separation. Steam is injected into theshallower well where it heats the bitumen that then flows by gravity to thedeeper producing well. The OrCrudeTM technology, using conventionaldistillation, solvent de-asphalting and thermal cracking, separates theproduced bitumen into partially upgraded sour crude oil and liquid asphaltenes.By coupling the OrCrudeTM process with commercially available hydrocracking andgasification technologies, sour crude oil is upgraded to light (39° API)premium synthetic sweet crude oil, and the asphaltenes are converted to alow-energy, synthetic fuel gas. This gas is available as a low-cost fuel forgenerating steam and as a source of hydrogen for the hydrocracking process. Thegas is also burned in a cogeneration plant to produce electricity for on-siteuse and sale to the provincial electricity grid. The energy conversionefficiency for our Long Lake upgrader is about 90%, compared to 75% for atypical bitumen-fed coker, which we expect will provide us with an approximate$10/bbl margin advantage in the long term.

 

 

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**OUR STRATEGIC ADVANTAGE**

 

Our integrated SAGD andupgrading process addresses three main economic hurdles of SAGD bitumenproduction: i) the potential high cost of natural gas; ii) the cost andavailability of diluent; and iii) the typically lower realized price ofbitumen. With synthetic gas from the asphaltenes as fuel, we expect to purchaseconsiderably less natural gas. With the upgrading facilities on site, diluentis not required to transport the bitumen to market. By upgrading the bitumeninto a highly desirable refinery feedstock or diluent supply, the end productcommands light, sweet crude oil premium pricing.

 

**PHASE 1**

 

The Long Lake project receivedregulatory approval in 2003 and was sanctioned in 2004. Field construction ofthe SAGD and upgrader facilities began in 2004. In 2006, we substantiallycompleted module and site construction of the SAGD facilities and in late 2007,we began injecting steam into the well pads. We continued to steam the SAGDwell pairs and began turning wells over to SAGD production in 2008. Our steamgeneration was initially restricted by our ability to treat water duringramp-up as most of the water we inject into the reservoir is recycled andtreated. In response to this, we implemented a number of low cost changes tothe water treating system, which include adding supplementary heat to the hotlime softeners and improvements to our filtration system. This work wascompleted in 2009 at which time we also completed work to remove deposits whichtypically build up in water treatment facilities. Later in 2009, we replacedvalves, cleaned out the hot lime softeners and isolated the water treatmenttrains. We also took the opportunity to perform a number of other maintenanceactivities to improve reliability and operability including installing electricsubmersible pumps (ESPs) in a number of our SAGD wells. This allows us toimprove pressure control in the wells and should ultimately reduce our overallsteam-to-oil ratio (SOR). The first several months of steam injection in a wellpair largely involves heating the reservoir, followed by a ramp up of bitumenproduction to peak rates over 12 to 24 months. Our ramp-up has been slower thaninitially anticipated but still within industry experience. At the start ofproduction, steam-to-oil ratios are high but will decline as bitumen productionramps up to our target rates. We expect the steam-to-oil ratio to reachapproximately 3.0 over the long term.

 

We completed construction ofthe upgrader in 2008 and began commissioning for commercial operations. Initialproduction of premium synthetic crude oil from the upgrader began in January 2009.As the upgrader ramps up to capacity, we expect that there will be periods ofdowntime as we work through the various stages of commissioning and ramp-up.This periodic downtime is normal following initial facility start-up andconsistent with industry experience. During the bitumen ramp-up period, we are purchasingthird-party bitumen to assist with upgrader start-up. Production capacity forthe first phase of Long Lake is approximately 60,000 bbls/d (39,000 net at a65% working interest) of PSCTM. Weexpect to maintain production over the project’s life, estimated at 40 years,by periodically drilling additional SAGD well pairs.

 

 

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Bitumen production for 2009 averaged7,900 bbls/d (12,200 gross). We are currently producing approximately 18,000bbls/d of bitumen (11,700 bbls/d, net to us) following maintenance anddebottlenecking work completed late in 2009. Late in the year, we wereprocessing about 90% of our produced bitumen along with 9,000 bbls/d ofpurchased third-party bitumen in the upgrader, yielding about 16,000 bbls/dayof PSCTM.

 

We expect to achieve positiveeconomic returns which benefit from a significant operating cost advantage.Combined SAGD, cogeneration and upgrading operating costs are expected toaverage about $25/bbl, substantially lower than coking or other upgradingprocesses as a result of the reduced need to purchase natural gas. We expectongoing 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 thosefor surface mining and coking upgrading on a barrel-of-daily production basis.Our technology will however add at least a $10/bbl margin advantage as weextract energy (for steam generation and power) and hydrogen (for upgrading)from a portion of the barrel others (cokers) discard.

 

**FUTURE PHASES**

 

We have approximately 309,000net acres of bitumen-prone lands in the Athabasca region. We plan to continuedeveloping our bitumen lands in phases using our integrated SAGD and upgradingstrategy. In 2009, we invested $100 million on land acquisition,additional drilling, seismic and engineering to develop our leases and advanceregulatory applications for future phases.

 

Federal government climatechange legislation has not yet been finalized. Due to this regulatoryuncertainty and the ongoing ramp up of Phase 1, we are delaying certainplanned expenditures on Phase 2. Phase 2 is expected to be followedby additional phases every three or four years. Each phase will leverage theknowledge and experience gained from successfully developing Long Lake andsubsequent projects are expected to be similar in size and design. By keepingthe core team in place and repeating and improving on existing designs andimplementation plans, we expect to gain efficiencies in engineering, modularfabrication and on-site construction. We also anticipate enhanced operatingefficiencies as we can train and move people easily between the various plants.

 

**Syncrude**

 

We hold a 7.23% participatinginterest in the Syncrude joint venture. This joint venture was established in1975 to mine shallow oil sand deposits using open-pit mining methods, extractthe bitumen and upgrade it to a high-quality, light (32° API), sweet, syntheticcrude oil. Syncrude’s operating strategy is to develop this resource, focusingon safe, reliable and profitable operations.

 

 

 

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Syncrude exploits a portion ofthe Athabasca oil sands that contains bitumen in the unconsolidated sands ofthe McMurray formation. Ore bodies are buried beneath 50 to 150 feet ofover-burden, have bitumen grades ranging from 4 to 14% by weight and orebearing sand thickness of 100 to 160 feet. Syncrude’s operations are on eightleases (10, 12, 17, 22, 29, 30, 31, and 34) covering 248,300 hectares, 40 kmnorth of Fort McMurray in northeast Alberta. Syncrude currently mines oil sandsat two mines: Mildred Lake North and Aurora North. These locations are readilyaccessible by public road. Trucks and shovels are used to collect the oil sandsin the open pit mines. The oil sands are transferred for processing using ahydro-transport system.

 

The extraction facilities,which separate bitumen from oil sands, are capable of processing more than310 million tons of oil sands per year and between 140 to 160 millionbarrels of bitumen per year depending on the average bitumen ore grade. Toextract bitumen, the oil sands are mixed with water to form a slurry. Air andchemicals are added to separate bitumen from the sand grains. The process at theMildred Lake North Mine uses hot water, steam and caustic soda to create aslurry, while at the Aurora North Mine, the oil sands are mixed with warmwater. Close to 90% of the water used in operations is recycled from theupgrader and mine sites. Incremental water is drawn from the Athabasca River inaccordance with existing licenses.

 

 

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

 

The high quality of Syncrude’ssynthetic crude oil allows it to be sold at prices approximating WTI. In 2009,about 50% of the synthetic crude oil was sold to Edmonton area refineries, andthe remaining 50% was sold to refineries in eastern Canada and the mid-westernUnited States. Electricity is provided to Syncrude from two generating plantson site: a 270 MW plant and an 80 MW plant.

 

Since operations started in1978, Syncrude has shipped more than two billion barrels of syntheticcrude oil to Edmonton by Alberta Oil Sands Pipeline Ltd. The pipeline wasexpanded in 2004 and again in 2009, to accommodate increased Syncrudeproduction.

 

At December 31, 2009,our total net book value of property, plant and equipment, including surfacemining facilities, transportation equipment, and upgrading facilities, wasapproximately $1.2 billion. Based on development plans, our share offuture expansion and equipment replacement costs over the next 35 years isexpected to be about $5.7 billion.

 

In 1999, the Alberta Energy andUtilities Board (AEUB) extended Syncrude’s operating license for the eight oilsands leases through to 2035. The license permits Syncrude to mine oil sandsand produce synthetic crude oil from approved development areas on the oilsands leases. The leases are automatically renewable as long as oil sandsoperations are ongoing or the leases are part of an approved development plan.All eight leases are included in a development plan approved by the AEUB. Therewere no known commercial operations on these leases prior to the start-up ofoperations in 1978.

 

In 1999, the AEUB approved anincrease in Syncrude’s production capacity to 465,700 bbls/d. At the end of2001, Syncrude increased its synthetic crude oil capacity to 246,500 bbls/dwith the development of the Aurora North Mine, which involved extending miningoperations to a new location about 25 miles north of the main Syncrude site.The next expansion of Syncrude came on stream in 2006,

 

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increasing capacity to 360,000bbls/d with the completion of the Stage 3 project.

 

Syncrude pays a royalty to theAlberta government. As of January 2002, this royalty was equal to thegreater of 1% of gross revenue or 25% of net synthetic-based profit afterdeducting new capital expenditures. In connection with the provincialgovernment’s review of Alberta royalty rates in 2007, the Syncrude ownersnegotiated revised royalty terms at the request of the government. Effective January 1, 2009,and consistent with other oil sands producers, Syncrude began paying royaltiesbased on bitumen, rather than paying royalties calculated on fully upgradedsynthetic crude oil. As a part of this conversion, the Alberta government willrecapture upgrader capital expenses of about $5 billion (gross) that werededucted against prior royalties from future production. The $5 billionroyalty deductions previously received by the Syncrude owners will be recapturedby the Alberta government over a 25 year period. In addition, the Province ofAlberta and Syncrude reached an agreement to establish new transitional royaltyterms. Under the terms of the agreement, until December 31, 2015,Syncrude will continue to pay base royalty rates (being the greater of 25% ofnet bitumen-based revenues, or 1% of gross bitumen-based revenues) plus anincremental royalty of up to $975 million (our share $70.5 million).The incremental royalty is subject to certain minimum bitumen productionthresholds and is to be paid in six annual payments.

 

This agreement is in lieu ofthe Syncrude owners converting to the Province of Alberta’s new royaltyframework announced in October 2007, that become effective January 1, 2009.After January 1, 2016, the rates under the new royalty framework willapply to the Syncrude project. See Canada fiscal terms on page 16.

 

**CONVENTIONAL EXPLORATION AND DEVELOPMENT**

 

**United Kingdom (UK)**

 

·                  We are the second largest oil producer in the UK North Sea

 

·                  We have recent exploration success in the Golden Eagle area,with potential development sanctioning in late 2010/early 2011

 

·                  We continue to actively explore the North Sea, with eightexploration and appraisal wells planned for 2010

 

 

 

The UK North Sea is a keyproducing area for Nexen. Our primary assets here include a 43.2% operatedinterest in the Buzzard field and facilities, a 41.9% operated interest in theScott field and production platform, a 71.8% operated interest in the Telfordfield, and a 79.7% operated interest in the Ettrick field, along with interestsin several undeveloped 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 operations have high-margin reserves and production, diversify our globalportfolio with strong assets in a stable jurisdiction, and complement our otherlonger cycle-time projects.

 

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Our UK strategy is to grow andsustain our existing North Sea production and identify new production sourceswith exploration and exploitation opportunities near existing infrastructure.We have a number of exploitation opportunities in our existing fields andundeveloped discoveries near infrastructure. Most of our unexplored acreage isnear Scott/Telford, Buzzard or Ettrick and can be tied-in in a short timeperiod.

 

**BUZZARD**

 

Buzzard is the largestdiscovery in the UK North Sea in over a decade. It was discovered in 2001 andcame on stream in early 2007.

 

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 initially is comprised ofthree platforms capable of processing at least 200,000 bbls/d of oil and 60mmcf/d of gas. Oil from Buzzard is exported via the Forties pipeline to theKinneil Terminal in Scotland. Gas is exported via the Frigg system to the St.Fergus Gas Terminal in northeast Scotland.

 

Initial development drillingresulted in more well-to-well variability in the concentration of hydrogensulphide than was originally expected. To address this, we are constructing afourth platform with production sweetening facilities to handle higher levelsof hydrogen sulphide. The fourth platform jacket was installed during 2009. In2010, we plan to install the deck of the fourth platform and tie it in to theexisting platforms. At the current levels of hydrogen sulphide being producedwe expect to require the oil sweetening equipment in 2011.

 

We expect to produce theBuzzard field through 30 production wells and maintain reservoir pressure withan active water-flood program. We have drilled 21 of these wells, of which 16are available for production. Our share of production in 2009 was 81,400 boe/d.We expect to drill six additional development wells in 2010.

 

**SCOTT/TELFORD**

 

Scott and Telford are producingfields with additional exploitation opportunities and both tie back to theScott platform. Scott was discovered in 1987 and began producing in September 1993,while Telford was discovered in 1991 and came on stream in 1996. Oil and gasfrom the fields is produced through subsea wells tied back to the Scottplatform. Oil is delivered to the third-party Kinneil Terminal in Scotland viathe Forties pipeline, while gas is exported via the SAGE pipeline to the St.Fergus Gas Terminal in northeast Scotland. In recent years, the Scott platformhas

 

 

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undergone several significantmaintenance turnarounds and facilities upgrades to improve reliability andextend facility life. In 2009, we drilled the TAB well at Telford and threedevelopment wells at Scott. The TAB well exceeded our expectations and extendedthe field’s proved reserves. Scott/Telford produced 13,500 boe/d in 2009. Weare currently reviewing technical subsurface work to support drilling anotherdevelopment well at Telford and potentially install an additional Telfordflowline back to the Scott platform.

 

**ETTRICK**

 

The Ettrick subsea facilitiesand the majority of the leased floating production, storage and offloadingvessel’s (FPSO) systems were successfully commissioned in 2009 and the Ettrickdevelopment produced first oil in August 2009. We have successfully testedthe FPSO up to its design rates. Commissioning of the water injection and gassystems was largely completed in 2009. Our 2009 share of production was 4,300boe/d and we expect this to increase to between 11,000 and 15,000 boe/d in 2010as we continue to ramp up the facility. The FPSO is designed to handle 30,000bbls/d of oil, 35 mmcf/d of gas and to re-inject 55,000 bbls/d of water.

 

**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 a third-party platform.

 

**EXPLORATION AND UNDEVELOPED ASSETS**

 

We continue to actively explorein the UK North Sea and hold several undeveloped discoveries on operated blocksnear Scott, Buzzard and Ettrick as follows:

 
| **Field**        | ** ** | **Interest (%)** | ** ** | **Operator Status** | ** ** | **Comments**                                                      |
|------------------|------------|------------------|------------|---------------------|------------|-------------------------------------------------------------------|
| Blackbird        |       | 80               |       | operated            |       | discovery near Ettrick;  appraisal well planned for 2010          |
| Black Horse      |       | 50               |       | operated            |       | discovery near Scott;  evaluating development alternatives        |
| Bugle            |       | 41               |       | operated            |       | discovery near Scott;  appraisal well planned for 2010            |
| Ferret (Polecat) |       | 40               |       | operated            |       | discovery near Buzzard;  appraisal well planned for 2010          |
| Golden Eagle     |       | 34               |       | operated            |       | discovery near Buzzard;  evaluating development alternatives      |
| Hobby            |       | 34               |       | operated            |       | discovery near Golden  Eagle; evaluating development alternatives |
| Kildare          |       | 50               |       | operated            |       | discovery near Scott;  evaluating development alternatives        |
| Pink             |       | 46               |       | operated            |       | discovery near Golden  Eagle; evaluating development alternatives |
| Rochelle         |       | 44               |       | non-operated        |       | discovery near Scott;  evaluating development alternatives        |

 

In 2007, we discoveredhydrocarbons at Golden Eagle, followed by Pink in 2008, and early in 2009 wemade a discovery at Hobby. During 2009, we successfully pursued a comprehensiveappraisal program of the discoveries which included drilling nine appraisalwells, two drill-stem tests and one injection test. With this success, weexpect the Golden Eagle area will become a significant development over thenext few years. In 2010, we will continue to complete the appraisal of thefield and evaluate our development options. We also expect to complete thetechnical work necessary for project sanction in early 2011.

 

In 2010, we plan to drill anappraisal well at Blackbird, which we could tie back to the Ettrick FPSO ifsuccessful. Elsewhere in the UK North Sea, we plan to drill three explorationand two appraisal wells in 2010.

 

**FISCAL TERMS**

 

In the UK, new discoveries payno royalties and result in cash netbacks that are higher than our companyaverage. The Scott field is subject to Petroleum Revenue Tax (PRT), although noPRT is payable until available oil allowances have been fully utilized, whichis not expected before 2011. Once payable, PRT is levied at 50% of cash flowafter capital expenditures, operating costs and an oil allowance for the field.PRT is applicable to fields receiving development consent prior to March 1993.Our other fields in the UK North Sea 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 oil and gas activity is alsosubject to a 20% supplemental charge.

 

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**Canada**

 

**·****                **Our shale gas land position in the Horn River Basin providesopportunities to significantly expand our gas reserves and production

 

·                  Legacy assets provide steady and predictable cash flow tofund new growth initiatives

 

 

 

In addition to our developmentsin the Athabasca oil sands, our strategy in Canada is three fold: i) establishthe Horn River Basin as a key growth area and continue to create value byexploring and developing the play; ii) generate new material resource playopportunities; and iii) optimize value from our producing assets.

 

Our Canadian conventionalproducing assets include heavy oil production in east-central Alberta andwest-central Saskatchewan, and natural gas near Calgary and in southern Albertaand Saskatchewan. Our coalbed methane (CBM) assets in the upper Mannville andHorseshoe Canyon coals are located in Alberta with commercial production at ourFort Assiniboine development over 50 mmcf/d in 2009. We operate most of ourproducing properties and hold almost one million net acres of undevelopedland across western Canada (excluding Athabasca oil sands). These assetsprovide predictable production volumes and cash flow.

 

In 2009, we invested$295 million in Canada including $203 million on our shale gas growthinitiative. Our 2010 capital programs are focused on progressing our shale gasopportunities and evaluating material resource plays.

 

**HEAVY OIL**

 

Approximately 45% of ourCanadian production (excluding Athabasca oil sands) is from our heavy oilproperties. Heavy oil is characterized by high specific gravity or weight andhigh viscosity or resistance to flow. Therefore, heavy oil is more difficultand expensive to extract, transport and refine than other types of oil. Heavyoil typically receives a lower price than light oil, as more expensive andcomplex refineries are required to refine heavy crude into higher-valuepetroleum products. To maximize heavy oil returns, it is important to managecapital and operating costs. Our large production base and existinginfrastructure are advantageous in managing these costs. As part of an ongoingstrategic review of our assets, we announced in late 2009 that we identified anumber of non-core assets for possible disposal, including some or all of ourheavy oil assets in Western Canada.

 

 

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**NATURAL GAS**

 

Approximately 32% of ourCanadian conventional production is natural gas extracted primarily fromshallow sweet reservoirs in southern Alberta and Saskatchewan and from sour gasreservoirs near Calgary. Generally, shallow gas targets are cheaper to drilland produce, but have relatively smaller reserves and lower productivity perwell. Sour gas is natural gas that contains hydrogen sulphide which requiresadditional processing. Our Balzac field, northeast of Calgary, has beenproducing sour natural gas since 1961. This sour gas is processed through ouroperated Balzac plant, which went through a maintenance upgrade in 2008.

 

In southern Alberta and Saskatchewan,Colorado shale gas re-completions have the potential to add production on ourexisting acreage. As incremental production comes from existing wells andfacilities, the economics are attractive.

 

**COALBED METHANE (CBM)**

 

Approximately 23% of ourCanadian conventional production is from our 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. We have limited activity planned here currently as a result of lowernatural gas prices.

 

**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 and our Horn Rivershale gas project. The second type is a Gross Royalty system whereby we payroyalties ranging from 5% to 40% depending upon drilling date, production rateand product sales price.

 

During 2008, the Albertagovernment legislated a new royalty framework for NPI and Gross Royaltystructures effective January 1, 2009. The new NPI royalty rates foroil sands projects range from 1% to 9% of gross revenue for projects that arepre-payout of costs, and 25% to 40% of net profit for projects that arepost-payout. These royalty rates vary depending on the Canadian dollarequivalent of WTI (Cdn$55/bbl to Cdn$120/ bbl). The amended Gross Royaltysystem increases the upper royalty rate limit to 50% and reduces the lowerlimit for conventional oil to nil, depending on production rates and salesprice. Most of our conventional Alberta production qualifies for lower ratesand we expect royalties on our production to range between 5% and 25%.

 

In 2009, the Alberta Governmentcommissioned a “Competitiveness Review” which included a review of the provincialroyalty system. Results of this review are not known at this time.

 

In addition to royalties, someprovinces impose taxes on production from lands where they do not own themineral rights. The Saskatchewan government assesses a resource surcharge ongross Saskatchewan resource sales that are subject to crown royalties, rangingfrom 1.7% to 3.0%. In Alberta, we are subject to a freehold mineral tax ofapproximately 4%.

 

Profits earned in Canada fromresource properties are subject to federal and provincial income taxes. Theserates ultimately fall to 15% by 2012. In 2009, federal taxable income is taxedat 19% and will be taxed at 18% in 2010. Provincial income tax rates vary fromapproximately 10% to 16%.

 

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**United States (US)—Gulf of Mexico**

 

·                  We are a significant leaseholder in the deep-water Gulf ofMexico which provides for future growth through exploration

 

·                  We are appraising discoveries at Knotty Head and Vicksburg

 

·                  Production from past discoveries provides liquidity forfuture exploration

 

 

 

The Gulf of Mexico is anintegral part of our longer-term growth strategy. Existing productioninfrastructure, the potential for large discoveries 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 typically higher,deep-water prospects generally have multiple sands and higher productionrates—factors which enhance economics. The technology to find, drill, anddevelop deep-water discoveries is rapidly progressing and becoming more costeffective. The deep-water Gulf is near infrastructure and continental USmarkets, so discoveries can be brought on stream in reasonable time frames.

 

We focus our explorationprogram on three strategic play types:

 

·                  deep-water prospects nearexisting infrastructure;

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

·                  deep-water, Norphlettargets in the eastern Gulf of Mexico.

 

The shorter cycle-times fordeep-water prospects near infrastructure complement the longer cycle-times fordeep-water sub-salt and Norphlet plays. Over the past few years, we have builtour resources and capabilities to explore in the deep water by accumulating alarge inventory of deep-water acreage to high-grade prospects, hired newemployees with significant Gulf of Mexico oil and gas experience, and gainedaccess to two new-build deep-water drilling rigs over the next few years.

 

Our Gulf production andreserves are primarily concentrated in five deep-water and five shallow-water(shelf) areas. Most of the production impacted by the 2008 hurricane season wasrestored early in 2009, with the exception of Wrigley which was delayed for acouple of months. The only production that remains shut in is at Green Canyon6/50/137 where the third-party production facilities were destroyed by the hurricane.

 

**DEEP WATER**

 

Most of our deep-waterproduction comes from our 30% non-operated Gunnison field, our 100% operatedAspen field, our 50% non-operated Wrigley field, our 25% non-operated Longhornfield and our 30% non-operated Mississippi Canyon 72 field.

 

Gunnison is in 3,100 feet ofwater and includes Garden Banks Blocks 667, 668 and 669. Gunnison beganproduction in late 2003 through a truss SPAR platform that can handle 40,000bbls/d of oil and 200 mmcf/d of gas. Our Gunnison

 

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SPAR facility has excesscapacity, leaving room for growth from regional exploration and processing ofthird-party volumes. We achieved payout on Gunnison in December 2005, justtwo years after first production. We plan to drill two sidetrack wells in 2010as we look to utilize some of the Gunnison SPAR excess capacity and increaseproduction.

 

Aspen is on Green Canyon Block243 in 3,150 feet of water. The project was developed using subsea wells tiedback to the Shell-operated Bullwinkle platform 16 miles away and beganproducing in late 2002. Our share of 2009 production before royalties wasapproximately 4,300 boe/d (3,900 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 andbegan gas production in 2007.

 

 

Mississippi Canyon 72 islocated in 1,700 feet of water and is a single subsea well tied back to theBP-operated Pompano platform, five miles north of the field. First productionwas in September 2009.

 

Our Longhorn property is onMississippi Canyon Block 502 and 546 in 2,400 feet of water. The project is anon-operated four-well subsea tie-back to the Corral platform located 19 milesnorth of the field. Longhorn came on stream in late 2009 and is approachingpeak production of approximately 200 mmcf/d gross (50 mmcf/d, net to us), withhigher than expected oil rates. Current production is 37,000 boe/d gross (9,300boe/d, net to us).

 

In 2007, we acquired threedeep-water producing fields: i) Garden Banks Block 205; ii) Green Canyon 137;and iii) 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 assessing our optionsto restore field production, which may include building our own processingplatform or potentially divesting the asset.

 

**SHELF**

 

Our shelf producing assets areoffshore Louisiana, primarily in five 100%-owned field areas: Eugene Island255/257/258/259, Eugene Island 295, Vermilion 320/321/339/340, Vermilion 76(consisting of Blocks 65, 66 and 67) and West Delta. We continue to look foropportunities to optimize these assets. In 2010, our shelf development programis expected to include up to 12 workovers across four fields to accessnon-producing proved reserves.

 

**EXPLORATION AND UNDEVELOPED ASSETS**

 

We hold approximately 205blocks in the Gulf of Mexico and expect this acreage and future explorationopportunities to position us well for continued growth. Our undeveloped deep-waterdiscoveries include:

 
| **Well**    | ** ** | **Interest (%)** | ** ** | **Operator Status** | ** ** | **Comments**                                                           |
|-------------|------------|------------------|------------|---------------------|------------|------------------------------------------------------------------------|
| Knotty Head |       | 25               |       | operated            |       | discovery; further  appraisal required; currently drilling second well |
| Vicksburg   |       | 25               |       | non-operated        |       | discovery; further  appraisal required                                 |

 

During the year, we drilled anunsuccessful exploratory well in deep water at Antietam, about three miles westof our Shiloh discovery. Later in 2009, we began drilling an exploration wellat Appomattox which is approximately six miles west of our Vicksburg discovery.Operations at Appomattox are ongoing and we are currently drilling a side trackwell to further evaluate the prospect. We have a 20% interest in this well.Elsewhere in 2009, we accepted the first Ensco rig and commenced drilling asecond appraisal well at Knotty Head. We expect to complete the well andappraise the results in 2010.

 

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In 2010, we expect firstproduction from our Tobago field. We are currently completing the subseagathering system and the regional host facility, as well as drilling asidetrack well. Elsewhere in 2010, we plan to drill up to four explorationwells in the deep-water Gulf of Mexico. We are targeting working interests of25% in these wells and expect to operate three of them. We also expect to takereceipt of the second Ensco deep-water drilling rig by mid 2010 to drillseveral of our exploration prospects.

 

**FISCAL TERMS**

** **

In 2009, royalty rates on ourUS production averaged 16.3% for shelf volumes and 6.7% for deep-water volumes.The US government increased royalty rates from 12.5% to 16.7% for newdeep-water leases awarded after July 2007. Our deep-water Aspen andGunnison fields are not subject to royalties on the first 87.5 mmboe ofproduction. US taxable income is subject to federal income tax of 35% and statetaxes ranging from 0% to 12%.

 

**Other International**

 

·                  The Usan development is currently under construction. We haveseveral discoveries and additional exploration prospects beyond Usan, offshoreNigeria

 

·                  Our entry into Yemen started our international expansion inthe early 1990s, which provided us with other significant internationalopportunities

 

·                  We are leveraging international exploration and operatingsuccess with unconventional resource experience to enter new regions

 

**Offshore West Africa**

 

Offshore West Africa is a corearea where we have several discoveries. It offers prolific reservoirs andmultiple opportunities to invest in this oil-rich region. Our strategy here isto complete development of the Usan discovery and continue to explore ourportfolio to provide 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.

 

The Nigerian governmentapproved converting OPL-222 into two Oil Mining Leases (OMLs) 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.

 

Development of the Usan fieldis underway. The field development plan includes a FPSO vessel with a storagecapacity of two million barrels of oil. During the year, we progressed thedetailed engineering and procurement, commenced development drilling of thefield, and continued construction of the FPSO hull and subsea facilities. TheUsan project is approximately 50% complete. The Usan field is expected to comeon stream in 2012, ramping up to peak

 

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production rates of 180,000bbls/d (36,000 bbls/d net to us). We expect that our investment in the Usandevelopment will be approximately $2 billion (net to Nexen).

 

In 2008, we acquired an 18%non-operated interest in Block OPL-223, covering 230,000 acres, which providesus with future exploration potential on the adjacent block. In 2009, we completeddrilling an exploration well in the southern portion of Block OPL-223. TheOwowo South B-1 well was drilled in a water depth of 670 metres and is located20 kilometers northeast of the Usan field. We are analyzing the drillingresults with recently processed new 3-D seismic data to confirm a number offollow on prospects. Under the Production Sharing Contract governing OPL-223,the Nigerian National Petroleum Corporation is the concessionaire of thelicence, which is operated by Total Exploration & Production NigeriaLtd.

 

As is typical in manyjurisdictions, the Nigerian Government is reviewing its existing petroleumfiscal terms, the impact of which is not yet known.

 

**Middle East—Yemen**

 

 

 

Yemen has been a significantinternational region for us since we first began production at Masila in 1993.We operate the country’s largest oil project and have developed strongrelationships with the government and local communities. Our strategy in Yemenis to maximize the value from our two existing producing blocks: Masila (Block14) and East Al Hajr (Block 51).

 

 

**MASILA BLOCK (BLOCK 14)**

** **

We operate the Masila projectwith a 52% working interest. The Masila fields are mature and the PSA expiresat the end of 2011, but significant value still remains.

 

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.Masila crude oil averages 32° API at very low gas-oil ratios. Most of the oil isproduced from the Upper Qishn formation, but we also produce from deeperformations including the Lower Qishn, Upper Saar, Saar, Madbi, Basal Sand andBasement formations. Production is collected at our Central Processing Facility(CPF) where water is separated for reinjection and oil is pumped to the AshShihr export terminal on the Indian Ocean and shipped to customers, primarilyin Asia.

 

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Under the Masila PSA betweenthe Government of Yemen and the Masila joint venture partners (MasilaPartners), we have the right to produce oil from Masila to December 2011.We are negotiating a five-year extension but there is no assurance that we willobtain an extension to operate the Masila field and CPF beyond 2011.

 

Production is divided into costrecovery oil 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 2009, theMasila Partners’ share of production, including recovery of costs, wasapproximately 45%.

 

**EAST AL HAJR BLOCK (BLOCK 51)**

** **

The first successfulexploratory well was drilled in 2003 and development of the block began in 2004which included a CPF, gathering system and a 22 km tie-back to our Masilaexport pipeline. Production commenced in November 2004.

 

We operate Block 51, which isgoverned by a PSA between the Government of Yemen and the East Al Hajr partners(EAH Partners): The Yemen Company (TYCO) (12.5% carried working interest) andNexen (87.5% working interest). Under the PSA, TYCO has no obligation to fundcapital or operating expenditures and therefore, our effective interest is 100%and for purposes of accounting and reserves recognition, we treat TYCO’s 12.5%participating interest as a royalty interest. We recognize both the Government’sshare and TYCO’s share of profit oil under the PSA as royalties and taxesconsistent with our treatment of our Masila operations. Under the PSA, the EAHPartners pay a royalty ranging from 3% to 10% to the Government depending onproduction volumes. The remaining production is divided into cost recovery oiland profit oil. Cost recovery oil provides for the recovery of all of theproject’s exploration, development and operating costs, funded solely by Nexen.Costs are recovered from a maximum of 50% of production each year afterroyalties, 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 2009, the EAH Partners’ share of Block 51 production, including recovery ofpast costs, was approximately 53%.

 

**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. Under terms of our license, ourworking interest in Guando decreased from 20% to 10% during the second quarterof 2009, as cumulative production from the field reached 60 millionbarrels of oil. Our share of 2009 production averaged 3,500 bbls/d beforeroyalties (3,200 after royalties), about 1% of our total production.

 

In 2009, we acquired twoadditional exploration blocks in Colombia and now hold five exploration blocksin the Upper Magdalena Basin that we are assessing for future growth opportunities.Production from Guando is subject to a royalty between 5% and 25% depending ondaily production. In 2009, the royalty payable to the Colombian governmentaveraged 8%. Colombian taxable income is subject to federal income tax of 33%.

 

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**NORWAY**

** **

Norway is an extension of ourconventional offshore growth strategy in the North Sea. The Norwegiancontinental shelf is characterized by well developed infrastructure andpotentially significant hydrocarbon resources. The Norwegian government createdincentives for the oil and gas industry to explore this area by providing a 78%cash tax refund on qualifying exploration expenditures to companies that do notyet have a taxable income base.

 

At December 31, 2009,we hold working interests in nine exploration licenses in the Norwegian NorthSea. In 2009, we acquired almost 1,500 km(2) of 3D seismic and 250 km(2) of2D seismic. We are optimizing and adding to our portfolio through participationin annual bid rounds and through farm-ins. In 2010, we expect to participate inthe Norwegian Government licensing rounds, and further mature our existingprospects.

 

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

 

**UNCONVENTIONAL GAS**

 

As part of our growth strategyin unconventional Canadian resource plays, we have 199 net sections ofundeveloped land in an emerging Devonian shale gas play in the Horn River Basinin northeast 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. In this Form 10-K, our shale gas operationsin northeast British Columbia are reported with our conventional operations inCanada.

 

Shale gas complements ourcorporate oil and gas portfolio which consists predominately of large scale,capital intensive, long cycle-time projects. It provides natural gas exposureand relatively short cycle-time projects, where we control the scale and paceof development of the resource. In addition, the time required to evaluatedrilling and testing results is relatively short. Once our commercial welldesign is established we can match the pace of drilling to prevailing economicconditions.

 

The Horn River Basin is asignificant shale gas play in North America with high resource density andexcellent well productivity. We have approximately 90,000 acres in the DillyCreek area and 38,000 acres in the Cordova area in northeast British Columbiawith a 100% working interest in each. To date, we have invested approximately$480 million in land, infrastructure and wells in the Horn River Basin toprogress our shale gas strategy toward development and reserve recognition. Wehave recognized minimal reserves as we are investing primarily to gainunderstanding of the optimal commercial development and the resourcecharacteristics.

 

We have drilled eighthorizontal wells with six wells completed to date. Initial production testresults are meeting expectations in terms of resource, initial production anddecline profile. With five shale gas wells on-stream at various times, wereached production of over 15 mmcf/d during the year before declining asexpected. Our land position here could support between 500 to 700 wells.Substantial cost savings and productivity improvements were realized in our2009 drilling and completion program. We took advantage of learnings from prioractivities to improve equipment utilization, drill longer wells and initiatemore fracs per well. All 26 fracs put into the last three wells weresuccessful.

 

Primary tenure in the HornRiver Basin is four years and drilling activity and extensions increases thisup to 18 years. Our drilling activity to date has allowed us to secure tenure for10 more years on the majority of our Dilly Creek lands. Only two more wells arerequired to secure the remainder. With tenure secured, we have the ability toslow the pace of drilling during periods of low gas prices.

 

In 2010, we plan to continueour drilling, completions and fracing program, expand infield facilities and startinvesting in long-term infrastructure. We will continue to build on oursuccess, which we expect will lead to further cost savings and productivityimprovements. In late 2009, we began work on an eight well test program whichis expected to start providing results and production in late 2010. The HornRiver Basin is an early-stage potential shale gas play that has not beendeveloped on a commercial scale. Many of our peers are also working to developthe future potential of the area.

 

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Limited gas pipelineinfrastructure and processing capacity in the Horn River Basin couldpotentially constrain early development of the play. To ensure sufficientgathering, processing and transportation capacity for our early developmentprograms, we have contracted gas pipeline capacity of 96 mmcf/d and associatedtreating capacity at the Spectra operated Fort Nelson plant. We entered intoadditional agreements that will allow us to participate in projects that areexpanding infrastructure in the region.

 

**FISCAL TERMS**

 

In British Columbia, within adesignated area, a 2% royalty on gross revenue is payable to the provincialgovernment until capital costs from our Horn River shale gas project arerecovered or ten years pass, whichever is sooner. After that point, royaltiesare calculated on net revenue as defined by the province using progressiverates of 15%, 20% and 35%, with a minimum royalty payable of 5% on grossrevenue.

 

**RESERVES, PRODUCTION AND RELATED INFORMATION**

 

In addition to the informationbelow, we refer you to the Supplementary Data in Item 8 of this Form 10-Kfor information on our oil and gas producing activities. Nexen has not filedwith nor included in reports to any other United States federal authority oragency, any estimates of its total proved oil or gas reserves since thebeginning of the last fiscal year.

 

**Oil and Gas Reserves**

 

The process of estimating reservesrequires complex judgments and decision-making. Reserves are categorized by theconfidence that they will be economically recoverable. Probable reserves areless certain to be recovered than proved reserves. Refer to the Basis ofReserves Estimates on page 29 for a description of probable reserves andour process for estimating proved and probable reserves.

 

On December 31, 2008,the SEC issued final revised rules relating to reserve definitions andrelated disclosure requirements. These new rules are effective forestimates and disclosures made on or after January 1, 2010. Theprimary impacts of the changes on our reserves estimates resulting from theadoption of the new rules are discussed on page 5 of this Form 10-K.

 

At December 31, 2009under the new SEC rules, we had 1,011 mmboe of proved reserves (920 afterroyalties) and 1,217 mmboe of probable reserves (1,057 after royalties). Underthe old rules and including Syncrude, we would have had 1,082 mmboe ofproved reserves (1,003 after royalties) and 1,397 mmboe of probable reserves(1,215 after royalties) at December 31, 2009.

 

The following is a summary ofour proved and probable reserves as at December 31, 2009 under thenew SEC rules:

 
| ** **          | ** ** | **Reserves**         | ** ** |
|---------------------|------------|----------------------|------------|
| ** **          | ** ** | **Before Royalties** | ** ** | **After Royalties** | ** ** |
| ** **          | ** ** | **Synthetic  Oil**   | ** ** | **Oil** | ** ** | **Gas** | ** ** | **Synthetic  Oil** | ** ** | **Oil** | ** ** | **Gas** | ** ** |
| ** **          | ** ** | **(mmbbl)**          | ** ** | **(mmbbl)** | ** ** | **(bcf)** | ** ** | **(mmbbl)** | ** ** | **(mmbbl)** | ** ** | **(bcf)** | ** ** |
| Developed           |       | 265                  |       | 219 |   | 418 |   | 240 |   | 203 |   | 379 |   |
| Undeveloped         |       | 377                  |       | 75 |   | 35 |   | 339 |   | 69 |   | 32 |   |
| **Total Proved**    | ** ** | **642**              | ** ** | **294** | ** ** | **453** | ** ** | **579** | ** ** | **272** | ** ** | **411** | ** ** |
| Developed           |       | 39                   |       | 115 |   | 176 |   | 36 |   | 110 |   | 158 |   |
| Undeveloped         |       | 895                  |       | 127 |   | 71 |   | 759 |   | 114 |   | 68 |   |
| **Total  Probable** | ** ** | **934**              | ** ** | **242** | ** ** | **247** | ** ** | **795** | ** ** | **224** | ** ** | **226** | ** ** |

 

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**PROVED RESERVES**

** **

In 2009, before adjusting forthe new SEC rules, we added 184 mmboe of proved reserves (155 after royalties)and produced 90 mmboe (78 after royalties). Under the new SEC rules, we added166 mmboe of proved reserves (123 after royalties) during the year and reducedour bitumen reserves by 53 mmboe (51 after royalties) to reflect the impact ofconverting from bitumen to synthetic oil barrels on our December 31, 2008Long Lake reserves estimates. The significant difference in the respectiveroyalty rates reflects the impact of higher oil prices on oil sands royaltiesin 2009.

 

The following table provides asummary of the changes in our proved oil and gas reserves before royaltiesduring 2009, including the impact of the adoption of the new SEC rules. Referto pages 152 and 153 for proved reserves information on an after-royaltiesbasis.

 
| ** **                  | ** ** | **Canada**   | ** ** | ** **            | ** ** | ** ** | ** ** | ** **          | ** ** | ** **         | ** ** | ** ** | ** ** |
|-----------------------------|------------|--------------|------------|-----------------------|------------|------------|------------|---------------------|------------|--------------------|------------|------------|------------|
| **(mmboe)**                 | ** ** | **Syncrude** | ** ** | **Long Lake  Insitu** | ** ** | **Other**  | ** ** | **United  Kingdom** | ** ** | **United  States** | ** ** | **Yemen**  | ** ** | **Other** | ** ** | **Total** | ** ** |
| December 31, 2008 |       | 324          |       | 285                   |       | 90         |       | 175                 |       | 49                 |       | 31         |       | 34 |   | 988 |   |
| Extension and discoveries   |       | 7            |       | 25                    |       | 4          |       | 20                  |       | 3                  |       | —     |       | 8 |   | 67 |   |
| Revisions—technical    |       | —       |       | (4                    | )          | 1          |       | 5                   |       | 2                  |       | 11         |       | — |   | 15 |   |
| Revisions—economic     |       | —       |       | —                |       | —     |       | 9                   |       | 4                  |       | 1          |       | 2 |   | 16 |   |
| Acquisitions                |       | —       |       | 86                    |       | —     |       | —              |       | —             |       | —     |       | — |   | 86 |   |
| Divestments                 |       | —       |       | —                |       | —     |       | —              |       | —             |       | —     |       | — |   | — |   |
| Production                  |       | (7           | )          | (3                    | )          | (14        | )          | (37                 | )          | (8                 | )          | (20        | )          | (1 | ) | (90 | ) |
|                        |       | 324          |       | 389                   |       | 81         |       | 172                 |       | 50                 |       | 23         |       | 43 |   | 1,082 |   |
| SEC Rule Transition    |       |         |       |                  |       |       |       |                |       |               |       |       |       |   |   |   |   |
| Synthetic—current year |       | —       |       | (18                   | )          | —     |       | —              |       | —             |       | —     |       | — |   | (18 | ) |
| Synthetic—prior years  |       | —       |       | (53                   | )          | —     |       | —              |       | —             |       | —     |       | — |   | (53 | ) |
| **December 31,  2009** | ** ** | **324**      | ** ** | **318**               | ** ** | **81**     | ** ** | **172**             | ** ** | **50**             | ** ** | **23**     | ** ** | **43** | ** ** | **1,011** | ** ** |

 

Extensions and discoveries of67 mmboe (63 after royalties) relate primarily to ongoing Long Lake reservoirdelineation and development drilling at Buzzard, Usan and Telford.

 

Technical revisions of 15 mmboe(9 after royalties) relate primarily to positive production performance andproduction optimization activities in Yemen, and continued analysis of theproved area at Long Lake, partially offset by a reduction of reserves at LongLake to reflect lease set-back agreements.

 

Positive economic revisions of16 mmboe (negative 2 after royalties) reflect the differences between the oiland gas prices on December 31, 2008 and the average prices in 2009,and differences in costs. Higher oil prices, particularly for heavy oil,resulted in positive economic revisions of 31 mmboe (11 after royalties).Approximately half of these positive economic revisions occurred in ourCanadian heavy oil properties, with the rest in other areas such as Buzzard andthe Gulf of Mexico. During 2009, gas prices continued to decline and reached aneight year low. Our gas properties had negative economic revisions of 15 mmboe(13 after royalties), with 75% occurring in our Canadian conventional gasproperties and the remainder in our Canadian CBM properties. The positiveeconomic revision before royalties became negative after royalties due toincreased oil sands royalties related to higher oil prices.

 

The acquisition occurred atLong Lake where we acquired an additional 15% working interest from our partnerearly in the year.

 

The SEC Rule Transitionrepresents changes in reserves quantities resulting from implementing the newSEC rules on the December 31, 2009 quantities. The revisionrelates to our oil sands reserves at Long Lake where we produce bitumen and upgradeit to a premium synthetic crude in the field. As part of the process, we removethe asphaltenes from the bitumen and use it as our internal fuel source in thesteam generation, upgrading and cogeneration power processes. This results in areduction in the quantity of reserves available for sale; however, thesesynthetic barrels are expected to have a higher value over the long term.

 

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The following provides asummary of the changes in our proved oil and gas reserves before royaltiesduring the past three years. Refer to pages 152 and 153 for provedreserves information on an after-royalty basis for each of the past threeyears.

 
| ** **                  | ** ** | **Canada**   | ** ** | ** **            | ** ** | ** ** | ** ** | ** **          | ** ** | ** **         | ** ** | ** ** | ** ** |
|-----------------------------|------------|--------------|------------|-----------------------|------------|------------|------------|---------------------|------------|--------------------|------------|------------|------------|
| **(mmboe)**                 | ** ** | **Syncrude** | ** ** | **Long Lake  Insitu** | ** ** | **Other**  | ** ** | **United  Kingdom** | ** ** | **United  States** | ** ** | **Yemen**  | ** ** | **Other** | ** ** | **Total** | ** ** |
| December 31, 2006      |       | 324          |       | 246                   |       | 118        |       | 182                 |       | 73                 |       | 66         |       | 40 |   | 1,049 |   |
| Extension and discoveries   |       | 23           |       | 44                    |       | 20         |       | 35                  |       | 8                  |       | 3          |       | 8 |   | 141 |   |
| Revisions—technical    |       | —       |       | 18                    |       | 7          |       | 63                  |       | (8                 | )          | 23         |       | — |   | 103 |   |
| Revisions—economic     |       | —       |       | —                |       | (23        | )          | (4                  | )          | (4                 | )          | 1          |       | — |   | (30 | ) |
| Acquisitions                |       | —       |       | 86                    |       | —     |       | 1                   |       | 11                 |       | —     |       | — |   | 98 |   |
| Divestments                 |       | —       |       | —                |       | —     |       | —              |       | (2                 | )          | —     |       | — |   | (2 | ) |
| Production                  |       | (23          | )          | (5                    | )          | (41        | )          | (105                | )          | (28                | )          | (70        | )          | (5 | ) | (277 | ) |
|                        |       | 324          |       | 389                   |       | 81         |       | 172                 |       | 50                 |       | 23         |       | 43 |   | 1,082 |   |
| SEC Rule Transition    |       |         |       |                  |       |       |       |                |       |               |       |       |       |   |   |   |   |
| Synthetic—current year |       | —       |       | (18                   | )          | —     |       | —              |       | —             |       | —     |       | — |   | (18 | ) |
| Synthetic—prior years  |       | —       |       | (53                   | )          | —     |       | —              |       | —             |       | —     |       | — |   | (53 | ) |
| **December 31,  2009** | ** ** | **324**      | ** ** | **318**               | ** ** | **81**     | ** ** | **172**             | ** ** | **50**             | ** ** | **23**     | ** ** | **43** | ** ** | **1,011** | ** ** |

 

Since 2006, we added 312 mmboe(326 after royalties), sold 2 mmboe (2 after royalties) and produced 277 mmboe(233 after royalties). Extensions and discoveries of 141 mmboe (132 afterroyalties) occurred primarily at Long Lake, Syncrude, Buzzard, Canadian CBM,and the deep-water Gulf of Mexico. The technical revisions of 103 mmboe (89after royalties) include 63 mmboe (63 after royalties) of positive revisions inthe UK related to better production performance at Buzzard, 23 mmboe (11 afterroyalties) from better than expected production performance at Yemen, andongoing analysis of the reservoir at Long Lake. Negative technical revisionsoccurred primarily from lower than expected production performance from variousdeep water and shelf properties in the US Gulf of Mexico. Negative economicrevisions of 30 mmboe (positive 10 after royalties) are primarily related tochanges in prices and costs, primarily in our gas areas in Canada and the US,and to a lesser extent at our Canadian heavy oil properties. The positive economicrevision after royalties reflects the change in royalty regulations for oilsands projects which make them oil price sensitive and causes them to be lowerat the prices used in the reserves estimates.

 

**PROVED DEVELOPED AND UNDEVELOPED RESERVES**

 

The following table providesproved undeveloped reserves (PUDs) before royalties at December 31, 2009and the changes during 2009. We have included Syncrude in the table andpresented a portion of the previously reported mining reserves as PUDs at December 31,2008 as if it was always an oil and gas activity. We believe this allows forbetter presentation of the changes during 2009.

 
| ** **                  | ** ** | **Canada**   | ** ** | ** **            | ** ** | ** ** | ** ** | ** **          | ** ** | ** **         | ** ** | ** ** | ** ** |
|-----------------------------|------------|--------------|------------|-----------------------|------------|------------|------------|---------------------|------------|--------------------|------------|------------|------------|
| **(mmboe)**                 | ** ** | **Syncrude** | ** ** | **Long Lake  Insitu** | ** ** | **Other**  | ** ** | **United  Kingdom** | ** ** | **United  States** | ** ** | **Yemen**  | ** ** | **Other** | ** ** | **Total** | ** ** |
| December 31, 2008      |       | 105          |       | 232                   |       | 4          |       | 40                  |       | 11                 |       | 3          |       | 28 |   | 423 |   |
| Extension and discoveries   |       | 11           |       | 25                    |       | 1          |       | —              |       | —             |       | —     |       | 8 |   | 45 |   |
| Revisions                   |       | —       |       | (4                    | )          | (2         | )          | —              |       | 1                  |       | (1         | )          | 2 |   | (4 | ) |
| Conversions                 |       | —       |       | (4                    | )          | —     |       | (12                 | )          | (1                 | )          | (1         | )          | — |   | (18 | ) |
| Acquisitions                |       | —       |       | 70                    |       | —     |       | —              |       | —             |       | —     |       | — |   | 70 |   |
|                        |       | 116          |       | 319                   |       | 3          |       | 28                  |       | 11                 |       | 1          |       | 38 |   | 516 |   |
| SEC Rule Transition    |       |         |       |                  |       |       |       |                |       |               |       |       |       |   |   |   |   |
| Synthetic—current year |       | —       |       | (16                   | )          | —     |       | —              |       | —             |       | —     |       | — |   | (16 | ) |
| Synthetic—prior years  |       | —       |       | (42                   | )          | —     |       | —              |       | —             |       | —     |       | — |   | (42 | ) |
| **December 31,  2009** | ** ** | **116**      | ** ** | **261**               | ** ** | **3**      | ** ** | **28**              | ** ** | **11**             | ** ** | **1**      | ** ** | **38** | ** ** | **458** | ** ** |
| PUD %1                      |       | 36           | %          | 82                    | %          | 3          | %          | 16                  | %          | 23                 | %          | 4          | %          | 88 | % | 45 | % |

 

----

*1*                 Determined as apercentage of total proved reserves for that area.

 

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In 2009, our PUDs increased by35 mmboe (7 after royalties). Extensions and discoveries of 45 mmboe (41 afterroyalties) relate to the ongoing Long Lake reservoir delineation and theaddition of another year of production at Syncrude which will come from anundeveloped mine. We had negative revisions of 4 mmboe (15 after royalties)primarily at Long Lake due to lease set-back agreements, and in our Canadianand US gas areas where low gas prices have made developments at average 2009prices uneconomic. After-royalty changes reflect the impact of higherprice-sensitive royalties from our oil sands properties at Long Lake andSyncrude. We converted 18 mmboe (18 after royalties) with the start-up of ourEttrick field in the North Sea, the drilling of an additional SAGD well pad atLong Lake, and ongoing development of various other properties.

 

At Syncrude, PUDs of 116 mmboe(103 after royalties) relate to a new mine that will be required to providebitumen feedstock to the upgrading facility. The mine is part of the Syncrudedevelopment plan and was contemplated in conjunction with the Stage 3 expansioncompleted in 2005. We do not consider this mine to be developed as theextraction equipment to access the reserves has not yet been installed. We areproceeding with planning for the development of the mine and expect to initiatefield construction in 2012.

 

At Long Lake, PUDs of 261 mmboe(236 after royalties) relate to ongoing drilling to offset declines from theinitial SAGD wells. They are expected to be converted to developed over thenext 27 years as we drill additional wells to provide bitumen feedstock to runthe upgrader at capacity. These wells were part of the field development planand were included in the project investment decision.

 

In the United Kingdom, about90% of the 28 mmboe (28 after royalties) relate to Buzzard while the remainderrelate to Ettrick. The Buzzard PUDs are expected to be converted to proved overthe next few years with the expected completion of the addition of the H2S handling facilities in2010 and as we drill additional development wells. We expect to convert themajority of Ettrick PUDs to producing within a year.

 

In our other internationalcountries, PUDs of 38 mmboe (33 after royalties) relate primarily to offshoreWest Africa.

 

Excluding Long Lake, we expectto convert over 90% of our PUDs to producing in the next four years. Long LakePUDs will be converted over the next 27 years as new wells are drilled tooffset declines from the initial SAGD wells. We expect our ongoing explorationand development activities to continue to add new PUDs.

 

During the year, we spent$625 million on our PUDs. The amount relates to PUDs converted to proveddeveloped reserves in the year and to those which will be converted in futureyears.

 

We have reviewed our PUDs anddetermined there are no material amounts in individual fields which haveremained undeveloped for five years or more after they were initiallyrecognized as proved reserves.

 

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Following is a summary of ourdeveloped and undeveloped proved oil and gas reserves by country and product atDecember 31, 2009:

 
| ** **       | ** ** | **Before Royalties** | ** ** | **After Royalties** | ** ** |
|------------------|------------|----------------------|------------|---------------------|------------|
| ** **       | ** ** | **Synthetic  Oil**   | ** ** | **Oil**             | ** ** | **Gas** | ** ** | **Synthetic  Oil** | ** ** | **Oil** | ** ** | **Gas** | ** ** |
| ** **       | ** ** | **(mmbbl)**          | ** ** | **(mmbbl)**         | ** ** | **(bcf)** | ** ** | **(mmbbl)** | ** ** | **(mmbbl)** | ** ** | **(bcf)** | ** ** |
|             |       |                 |       |                |       |   |   |   |   |   |   |   |   |
| Canada           |       | 265                  |       | 35                  |       | 260 |   | 240 |   | 29 |   | 241 |   |
| United Kingdom   |       | —               |       | 142                 |       | 13 |   | — |   | 142 |   | 13 |   |
| United States    |       | —               |       | 15                  |       | 145 |   | — |   | 13 |   | 125 |   |
| Yemen            |       | —               |       | 22                  |       | — |   | — |   | 14 |   | — |   |
| Other Countries  |       | —               |       | 5                   |       | — |   | — |   | 5 |   | — |   |
| **Developed**    | ** ** | **265**              | ** ** | **219**             | ** ** | **418** | ** ** | **240** | ** ** | **203** | ** ** | **379** | ** ** |
| Canada           |       | 377                  |       | 2                   |       | 4 |   | 339 |   | 2 |   | 3 |   |
| United Kingdom   |       | —               |       | 27                  |       | 4 |   | — |   | 27 |   | 4 |   |
| United States    |       | —               |       | 7                   |       | 27 |   | — |   | 6 |   | 25 |   |
| Yemen            |       | —               |       | 1                   |       | — |   | — |   | 1 |   | — |   |
| Other Countries  |       | —               |       | 38                  |       | — |   | — |   | 33 |   | — |   |
| **Undeveloped**  | ** ** | **377**              | ** ** | **75**              | ** ** | **35** | ** ** | **339** | ** ** | **69** | ** ** | **32** | ** ** |
| **Total Proved** | ** ** | **642**              | ** ** | **294**             | ** ** | **453** | ** ** | **579** | ** ** | **272** | ** ** | **411** | ** ** |

 

**PROBABLE RESERVES**

 

Probable reserves are thoseadditional reserves that are less certain to be recovered than proved reservesbut which, together with proved reserves, are as likely as not to be recovered.Therefore, probable reserves have a higher degree of uncertainty than provedreserves. In prior years, information on probable reserves was reported outsideof our Form 10-K and was prepared in accordance with Canadian NI 51-101and the Canadian Oil and Gas Evaluation Handbook standards. We have presented acontinuity schedule as if they had been reported in our Form 10-K lastyear.

 

At December 31, 2009,we had 1,217 mmboe (1,057 after royalties) of probable oil and gas reserves.During the year, we added 349 mmboe (250 after royalties), representing a 33%(26% after royalties) increase to our estimate the prior year. The conversionof bitumen to PSCTM in accordance with SEC requirements reducedour quantities by 180 mmboe (158 after royalties), of which 41 mmboe (50 afterroyalties) reflect the current year and the remainder to prior years. Theafter-royalties reserves estimates did not increase as significantly due to theimpact of higher prices. Including the effects of reconciliation to the new SECrules our probable reserves have increased by 169 mmboe (92 afterroyalties).

 

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The following provides asummary of the changes in our probable oil and gas reserves before royaltiesduring 2009, including the impact of converting to the new SEC rules.

 
| ** **                       | ** ** | **Canada**   | ** ** | ** **                 | ** ** | ** ** | ** ** | ** **          | ** ** | ** **         | ** ** | ** ** | ** ** |
|----------------------------------|------------|--------------|------------|----------------------------|------------|------------|------------|---------------------|------------|--------------------|------------|------------|------------|
| **(mmboe)**                      | ** ** | **Syncrude** | ** ** | **Long Lake  Insitu****2** | ** ** | **Other**  | ** ** | **United  Kingdom** | ** ** | **United  States** | ** ** | **Yemen**  | ** ** | **Other** | ** ** | **Total** | ** ** |
| **December 31,  2008****1** | ** ** | **46**       | ** ** | **732**                    | ** ** | **36**     | ** ** | **136**             | ** ** | **24**             | ** ** | **13**     | ** ** | **61** | ** ** | **1,048** | ** ** |
| Extension and discoveries        |       | 7            |       | 152                        |       | 8          |       | 48                  |       | 3                  |       | —     |       | 6 |   | 224 |   |
| Revisions—technical         |       | —       |       | (10                        | )          | 3          |       | 5                   |       | (2                 | )          | (3         | )          | (10 | ) | (17 | ) |
| Revisions—economic          |       | —       |       | (26                        | )          | (5         | )          | (2                  | )          | 1                  |       | 1          |       | (2 | ) | (33 | ) |
| Conversions                      |       | (7           | )          | —                     |       | (1         | )          | (18                 | )          | (2                 | )          | (7         | )          | (10 | ) | (45 | ) |
| Acquisitions                     |       | —       |       | 220                        |       | —     |       | —              |       | —             |       | —     |       | — |   | 220 |   |
|                             | ** ** | **46**       |       | 1,068                      |       | 41         |       | 169                 |       | 24                 |       | 4          |       | 45 |   | 1,397 |   |
| SEC Rule Conversion         |       |         |       |                       |       |       |       |                |       |               |       |       |       |   |   |   |   |
| Synthetic—current year      |       | —       |       | (41                        | )          | —     |       | —              |       | —             |       | —     |       | — |   | (41 | ) |
| Synthetic–prior years       |       | —       |       | (139                       | )          | —     |       | —              |       | —             |       | —     |       | — |   | (139 | ) |
| **December 31,  2009**      | ** ** | **46**       | ** ** | **888**                    | ** ** | **41**     | ** ** | **169**             | ** ** | **24**             | ** ** | **4**      | ** ** | **45** | ** ** | **1,217** | ** ** |

 

----

*1*                 Information on probablereserves was previously reported outside of our Form 10-K and was preparedin accordance with Canadian NI 51-101 and the Canadian Oil and Gas EvaluationHandbook standards. The estimates at December 31, 2008 and changesduring 2009 were prepared under those standards. The conversion to the new SEC rules isshown separately.

*2*                 The insitu oil sandsreflect our share of the probable reserves for phases 1 and 2 at Long Lake.

* *

The following provides asummary of the changes in our probable oil and gas reserves after royaltiesduring 2009, including the impact of converting to the new rules.

 
| ** **                       | ** ** | **Canada**   | ** ** | ** **                 | ** ** | ** ** | ** ** | ** **          | ** ** | ** **         | ** ** | ** ** | ** ** |
|----------------------------------|------------|--------------|------------|----------------------------|------------|------------|------------|---------------------|------------|--------------------|------------|------------|------------|
| **(mmboe)**                      | ** ** | **Syncrude** | ** ** | **Long Lake  Insitu****2** | ** ** | **Other**  | ** ** | **United  Kingdom** | ** ** | **United  States** | ** ** | **Yemen**  | ** ** | **Other** | ** ** | **Total** | ** ** |
| **December 31,  2008****1** | ** ** | **43**       | ** ** | **677**                    | ** ** | **31**     | ** ** | **136**             | ** ** | **20**             | ** ** | **8**      | ** ** | **50** | ** ** | **965** | ** ** |
| Extension and discoveries        |       | 7            |       | 121                        |       | 7          |       | 48                  |       | 2                  |       | —     |       | 5 |   | 190 |   |
| Revisions—technical         |       | —       |       | (9                         | )          | 3          |       | 5                   |       | (1                 | )          | (1         | )          | (8 | ) | (11 | ) |
| Revisions—economic          |       | (2           | )          | (80                        | )          | (6         | )          | (2                  | )          | 1                  |       | (1         | )          | (3 | ) | (93 | ) |
| Conversions                      |       | (7           | )          | —                     |       | —     |       | (18                 | )          | (2                 | )          | (3         | )          | (9 | ) | (39 | ) |
| Acquisitions                     |       | —       |       | 203                        |       | —     |       | —              |       | —             |       | —     |       | — |   | 203 |   |
| ** **                       | ** ** | **41**       | ** ** | **912**                    | ** ** | **35**     | ** ** | **169**             | ** ** | **20**             | ** ** | **3**      | ** ** | **35** | ** ** | **1,215** | ** ** |
| SEC Rule Conversion         |       |         |       |                       |       |       |       |                |       |               |       |       |       |   |   |   |   |
| Synthetic—current year      |       | —       |       | (50                        | )          | —     |       | —              |       | —             |       | —     |       | — |   | (50 | ) |
| Synthetic—prior years       |       | —       |       | (108                       | )          | —     |       | —              |       | —             |       | —     |       | — |   | (108 | ) |
| **December 31,  2009**      | ** ** | **41**       | ** ** | **754**                    | ** ** | **35**     | ** ** | **169**             | ** ** | **20**             | ** ** | **3**      | ** ** | **35** | ** ** | **1,057** | ** ** |

 

----

*1*                 Information on probablereserves was previously reported outside of our Form 10-K and was preparedin accordance with Canadian NI 51-101 and the Canadian Oil and Gas EvaluationHandbook. The estimates at December 31, 2008 and changes during 2009were prepared under those standards. The conversion to the new SEC rules isshown separately.

*2*                 The insitu oil sandsreflect our share of the probable reserves for phase 1 and 2 at Long Lake.

* *

Extensions and discoveries of224 mmboe (190 after royalties) relate primarily to ongoing Long Lake reservoirdelineation, successful development drilling at Telford, and explorationsuccesses in the Golden Eagle area and Rochelle in the UK and at Owowo,offshore West Africa. Negative technical revisions of 17 mmboe (11 afterroyalties) relate primarily to a reduction at Long Lake to reflect leaseset-back agreements. Negative economic revisions of 33 mmboe (93 afterroyalties) primarily reflect higher oil prices, changes in the economicassumptions at Long Lake Phase 2 and lower gas prices. The larger negativerevisions after royalties reflects increased oil sands royalties related tohigher oil prices. Conversions reflect probable reserves converted to proved asa result of increased confidence in producing the reserves based on productionperformance and drilling results. The acquisition reflects the additionalworking interest acquired in Long Lake Phases 1 and 2.

 

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**PROBABLE DEVELOPED AND UNDEVELOPED RESERVES**

 

Following is a summary of our developed and undevelopedprobable oil and gas reserves by country and product at December 31, 2009:

 
| ** **          | ** ** | **Before Royalties** | ** ** | **After Royalties** | ** ** |
|---------------------|------------|----------------------|------------|---------------------|------------|
| ** **          | ** ** | **Synthetic   Oil**  | ** ** | **Oil**             | ** ** | **Gas** | ** ** | **Synthetic   Oil** | ** ** | **Oil** | ** ** | **Gas** | ** ** |
| ** **          | ** ** | **(mmbbl)**          | ** ** | **(mmbbl)**         | ** ** | **(bcf)** | ** ** | **(mmbbl)** | ** ** | **(mmbbl)** | ** ** | **(bcf)** | ** ** |
|                |       |                 |       |                |       |   |   |   |   |   |   |   |   |
| Canada              |       | 39                   |       | 18                  |       | 75 |   | 36 |   | 14 |   | 69 |   |
| United Kingdom      |       | —               |       | 88                  |       | 18 |   | — |   | 88 |   | 18 |   |
| United States       |       | —               |       | 5                   |       | 83 |   | — |   | 4 |   | 71 |   |
| Yemen               |       | —               |       | 3                   |       | — |   | — |   | 3 |   | — |   |
| Other Countries     |       | —               |       | 1                   |       | — |   | — |   | 1 |   | — |   |
| **Developed**       | ** ** | **39**               | ** ** | **115**             | ** ** | **176** | ** ** | **36** | ** ** | **110** | ** ** | **158** | ** ** |
| Canada              |       | 895                  |       | 10                  |       | 9 |   | 759 |   | 8 |   | 8 |   |
| United Kingdom      |       | —               |       | 70                  |       | 46 |   | — |   | 70 |   | 46 |   |
| United States       |       | —               |       | 2                   |       | 16 |   | — |   | 2 |   | 14 |   |
| Yemen               |       | —               |       | 1                   |       | — |   | — |   | — |   | — |   |
| Other Countries     |       | —               |       | 44                  |       | — |   | — |   | 34 |   | — |   |
| **Undeveloped**     | ** ** | **895**              | ** ** | **127**             | ** ** | **71** | ** ** | **759** | ** ** | **114** | ** ** | **68** | ** ** |
| **Total  Probable** | ** ** | **934**              | ** ** | **242**             | ** ** | **247** | ** ** | **795** | ** ** | **224** | ** ** | **226** | ** ** |

 

Developed probable reserves reflect increased recoveryfactors and recompletions of other zones on producing wells. Undevelopedprobable reserves reflect reserves that have not yet been drilled or theproduction facilities completed.

 

Approximately 85% of our probable reserves before royalties(84% after royalties) are undeveloped. This reflects the incremental reservesrelated to the ongoing drilling required to keep the upgrader full for Phase 1at Long Lake and the reserves related to the expected development of Phase 2 atLong Lake. The remaining undeveloped reserves principally relate to: completionof the H2Sfacilities at Buzzard; undeveloped discoveries at the Golden Eagle area andRochelle in the UK and Usan and Owowo, offshore West Africa; and the extensionof the plant life and expected higher future yields at Syncrude.

 

**BASIS OF RESERVES ESTIMATES**

 

The process of estimating reserves requires complex judgmentsand decision-making based on available geological, geophysical, engineering andeconomic data. To estimate the economically recoverable oil and gas reservesand related future net cash flows, we consider many factors and make variousassumptions including:

 

·                  expected reservoircharacteristics based on geological, geophysical and engineering assessments;

·                  future production rates basedon historical performance and expected future operating and investment activities;

·                  future oil and gas prices andquality differentials;

·                  assumed effects of regulationby governmental agencies; and

·                  future development andoperating costs.

 

We believe these factors and assumptions are reasonable basedon the information available to us at the time we prepared our estimates.However, these estimates may change substantially as additional data fromongoing development activities and production performance becomes available andas economic conditions impacting oil and gas prices and costs change.

 

Reserve estimates are categorized by the confidence they willbe economically recoverable. Proved reserves are those quantities of oil andgas, which, by analysis of geoscience and engineering data, can be estimatedwith reasonable certainty to be economically producible from a given dateforward, from known reservoirs, and under existing economic conditions,operating conditions, and government regulations. Probable reserves are thoseadditional reserves that are less certain to be recovered than proved reserves 

 

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but which, together with proved reserves, areas likely as not to be recovered. Therefore, probable reserves have a higherdegree of uncertainty than proved reserves.

 

Management is responsible for the estimates of oil and gasreserves and for preparing related disclosures. Estimates and relateddisclosures are prepared in accordance with SEC requirements, generallyaccepted industry practices in the US and the standards of the Canadian Oil andGas Evaluation Handbook modified to reflect SEC requirements. Our reserveestimates and disclosures may differ from other Canadian issuers who followCanadian NI 51-101. Significant differences between SEC and Canadian reserveestimates and disclosures are described on page 97 (see Special Note toCanadian Investors).

 

Reserve estimates for each property are internally preparedat least annually by the property’s reservoir engineer and geoscientists. Theyare reviewed by engineers familiar with the property and by divisionalmanagement. An Executive Reserves Committee, including our CEO, CFO andinternal qualified reserves evaluator, meet with divisional reserves personnelto review the estimates and any changes from previous estimates.

 

The internal qualified reserves evaluator (IQRE) isresponsible for estimating reserves data and related disclosures. Thisposition, required under Canadian NI 51-101, was appointed by the Board in December 2003.The IQRE is a professional engineer and meets all professional and statutoryrequirements in regards to experience, education and professional membershipassociated with the role. With over 27 years of experience, he has an in-depthknowledge of reserves estimation techniques and professional guidelines, andSEC and Canadian reserves regulations and related reporting requirements. Hisprimary duty includes assessing whether the reserves estimates and related disclosureshave been prepared in accordance with applicable regulatory requirements. Heprovides a report on Canadian NI 51-101 Form F-2 stating that the reservesinformation has, in all material respects, been prepared and reported inaccordance with our reserves standards. This report is included as an exhibitto this Form 10-K.

 

Our reserves estimates are based on internal analysis. Wehave at least 80% of our oil and gas reserves either evaluated or auditedannually by independent qualified reserves consultants to increase ourconfidence in our estimates. Given that reserve estimates are based on numerousassumptions, interpretations and judgments, differences frequently arisebetween the estimates prepared by different qualified estimators. When the initialestimate of proved reserves on the portfolio of properties differs by greaterthan 10%, we work with the independent reserves consultant to reconcile thedifference to within 10%. Estimates pertaining to individual properties withinthe portfolio may differ by more than 10%, either positively or negatively. Wedo not attempt to resolve each property to within 10% as it would be time andcost prohibitive given the number of wells in which we have an interest. Wefollow a similar process in connection with our probable reserves estimates toreconcile any differences on a proved plus probable basis to be within anacceptable tolerance, and as such, probable reserves for individual propertieswithin the portfolio may differ significantly. The nature and extent of theindependent evaluations and audits, and the results thereof, are providedbelow.

 

The board of directors has a Reserves Review Committee(Reserves Committee) to assist the board and the Audit Committee to oversee theannual review of our oil and gas reserves and related disclosures. The ReservesCommittee is comprised of three or more directors, the majority of whom areindependent and familiar with estimating oil and gas reserves and disclosurerequirements. The Reserves Committee meets with management periodically toreview the reserves process, the portfolio of properties selected by managementfor independent assessment, results and related disclosures. The ReservesCommittee appoints and meets with the IQRE and independent reserves consultants,independent of management, to review the scope of their work, whether they havehad access to sufficient information, the nature and satisfactory resolution ofany material differences of opinion, and in the case of the independentreserves consultants, their independence. In the event of a proposed change tothe areas of responsibility of either an independent reserves consultant or theIQRE, the Reserves Committee inquires whether there have been disputes betweenthe respective party and management.

 

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The Reserves Committee has reviewed our procedures forpreparing the reserves estimates and related disclosures and the propertiesselected by management for independent assessment. It reviewed the informationwith management, and met with the IQRE and the independent qualified reservesconsultants. As a result, the Reserves Committee is satisfied that the internally-estimatedreserves are reliable and free of material misstatement. Based on therecommendation of the Reserves Committee, the board has approved the reservesestimates and related disclosures in this Form 10-K.

 

The following provides an overview of the nature and scope ofthe independent evaluations and audits that we have performed. An independentevaluation is a process whereby we request a third-party engineering firm toprepare an estimate of our proved and probable reserves by assessing andinterpreting all available data on a reservoir. An independent audit is aprocess whereby we request a third party engineering firm to prepare anestimate of our reserves by reviewing our estimates, supporting working papersand other data as they feel is necessary. The primary difference is that anauditor reviews our work and estimate in preparing their estimate whereas anevaluator uses the reservoir data to prepare their own estimate.

 

In each case, we request their estimates to be prepared usingstandard geological and engineering methods generally accepted by the petroleumindustry. Generally accepted methods for estimating reserves include volumetriccalculations, material balance techniques, production and pressure declinecurve analysis, analogy with similar reservoirs, and reservoir simulation. Themethod or combination of methods used is based on their professional judgementand experience. In preparing their estimates, they obtain information from uswith respect to property interests, production from such properties, currentcosts of operations, expected future development and abandonment costs, currentprices for production, agreements relating to current and future operations andsale of production, and various other information and data. They may rely onthe information 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 ourestimates of the proved and probable reserves for that portfolio of propertiesis, in aggregate, reasonable relative to the criteria set forth in the SEC andFinancial Accounting Standards Board rules.

 

We engaged DeGolyer and MacNaughton (D&M) to evaluate100% of our proved and 100% of our proved plus probable reserves for the UnitedKingdom and Yemen Masila. They also reviewed 100% of our proved and 88% of ourproved plus probable reserves for Nigeria. A separate opinion was provided oneach of these areas. D&M provided opinions that the proved and proved plusprobable reserves for the reviewed properties are reasonable within anacceptable tolerance based upon a detailed evaluation and comparison of theiraggregate estimates to ours.

 

We engaged McDaniel & Associates Consultants Ltd.(McDaniel) to evaluate 98% of our proved and 99% of our proved plus probablereserves for our Canadian conventional, CBM and insitu oil sands properties.They also audited 100% of our proved and proved plus probable reserves for ourSyncrude interest. Separate opinions were provided for the evaluation and forthe audit. McDaniel provided opinions that the proved and proved plus probablereserves for the reviewed properties are reasonable within an acceptabletolerance based upon a detailed evaluation and comparison of their aggregateestimates to ours.

 

We engaged Ryder Scott Company (Ryder Scott) to evaluate 93%of our proved and 95% of our proved plus probable US Gulf of Mexico deep waterand shelf properties. Ryder Scott provided an opinion that the proved andproved plus probable reserves for the reviewed properties are reasonable withinan acceptable tolerance based upon a detailed evaluation and comparison oftheir aggregate estimates to ours.

 

For each opinion, a Report of Third Party has been preparedwhich summarizes the work undertaken, the assumptions, data, methods andprocedures they used, and concludes with their opinion. The reports areincluded as exhibits to this Form 10-K.

 

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** **

**Net Sales by Product from Oil and Gas Operations**

 
| **(Cdn$ millions)**                              | ** ** | **2009** | ** ** | **2008**  | ** ** | **2007**  | ** ** |
|-------------------------------------------------------|------------|----------|------------|-----------|------------|-----------|------------|
| Conventional Crude Oil and Natural Gas Liquids (NGLs) |       | 3,605    |       | 5,534     |       | 4,077     |       |
| Synthetic Crude Oil                                   |       | 480      |       | 691       |       | 545       |       |
| Natural Gas                                           |       | 316      |       | 652       |       | 499       |       |
| **Total**                                             | ** ** | 4,401    | ** ** | **6,877** | ** ** | **5,121** | ** ** |

 

Crude oil (including synthetic crude oil) and NGLs representapproximately 93% of our oil and gas net sales, while natural gas representsthe remaining 7%.

 

**Sales Prices and Production Costs**

 
|                              |       | **Average  Sales Price****1** | ** ** | **Average  Production Cost****1** |       |
|-----------------------------------|------------|-------------------------------|------------|-----------------------------------|------------|
| ** **                        | ** ** | **2009**                      | ** ** | **2008**                          | ** ** | **2007** | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
| **Crude  Oil and NGLs**(Cdn$/bbl) |       |                          |       |                              |       |   |   |   |   |   |   |   |   |
| United Kingdom                    |       | 67.70                         |       | 96.23                             |       | 76.30 |   | 6.87 |   | 6.75 |   | 6.94 |   |
| Canada                            |       | 53.04                         |       | 74.51                             |       | 44.07 |   | 20.82 |   | 22.16 |   | 18.67 |   |
| Syncrude                          |       | 70.96                         |       | 105.47                            |       | 79.76 |   | 39.09 |   | 42.04 |   | 30.32 |   |
| United States                     |       | 65.01                         |       | 104.94                            |       | 69.83 |   | 14.10 |   | 13.48 |   | 9.69 |   |
| Yemen                             |       | 68.49                         |       | 99.87                             |       | 76.29 |   | 18.34 |   | 15.88 |   | 12.00 |   |
| Other Countries                   |       | 59.05                         |       | 98.98                             |       | 71.29 |   | 6.53 |   | 4.91 |   | 3.76 |   |
| **Natural  Gas**(Cdn$/mcf)        |       |                          |       |                              |       |   |   |   |   |   |   |   |   |
| United Kingdom                    |       | 3.95                          |       | 6.78                              |       | 4.71 |   | 1.15 |   | 1.12 |   | 1.16 |   |
| Canada                            |       | 3.78                          |       | 7.73                              |       | 6.32 |   | 1.92 |   | 2.09 |   | 2.28 |   |
| United States                     |       | 4.67                          |       | 10.07                             |       | 7.80 |   | 2.35 |   | 2.25 |   | 1.61 |   |
| **Corporate Average (Cdn$/boe)**  |       | 60.02                         |       | 89.78                             |       | 68.46 |   | 13.33 |   | 13.18 |   | 11.63 |   |

 

----

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

* *

**Oil and Gas Acreage**

 
| ** **               | ** ** | **Developed** | ** ** | **Undeveloped****1** | ** ** | **Total** | ** ** |
|--------------------------|------------|---------------|------------|----------------------|------------|-----------|------------|
| **(thousands of acres)** | ** ** | **Gross**     | ** ** | **Net**              | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| United Kingdom           |       | 220           |       | 104                  |       | 1,303     |       | 917 |   | 1,523 |   | 1,021 |   |
| Canada                   |       | 810           |       | 625                  |       | 1,081     |       | 683 |   | 1,891 |   | 1,308 |   |
| Synthetic                |       | 10            |       | 6                    |       | 735       |       | 303 |   | 745 |   | 309 |   |
| Syncrude                 |       | 84            |       | 6                    |       | 264       |       | 19 |   | 348 |   | 25 |   |
| United States            |       | 220           |       | 125                  |       | 1,200     |       | 592 |   | 1,420 |   | 717 |   |
| Yemen2                   |       | 50            |       | 29                   |       | 756       |       | 629 |   | 806 |   | 658 |   |
| Colombia4                |       | 1             |       | —               |       | 788       |       | 611 |   | 789 |   | 611 |   |
| Nigeria2, 3         |       | —        |       | —               |       | 678       |       | 131 |   | 678 |   | 131 |   |
| Norway                   |       | —        |       | —               |       | 753       |       | 426 |   | 753 |   | 426 |   |
| **Total**5               |       | 1,395         |       | 895                  |       | 7,558     |       | 4,311 | ** ** | **8,953** | ** ** | **5,206** | ** ** |

 

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

*2*                 The acreage is covered byproduction sharing contracts.

*3*                 The acreage is covered bya joint venture agreements.

*4*                 The acreage is covered byan association contract.

*5*                 Approximately 25% of ournet oil and gas acreage is scheduled to expire within three years if productionis not established or we take no other action to extend the terms. We plan tocontinue the terms of many of these licences.

 

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**Producing Oil and Gas Wells**

 
| ** **            | ** ** | **Oil**        | ** ** | **Gas**      | ** ** | **Total**      | ** ** |
|-----------------------|------------|----------------|------------|--------------|------------|----------------|------------|
| **(number of wells)** | ** ** | **Gross****1** | ** ** | **Net****2** | ** ** | **Gross****1** | ** ** | **Net****2** | ** ** | **Gross****1** | ** ** | **Net****2** | ** ** |
| United Kingdom        |       | 61             |       | 29           |       | —         |       | — |   | 61 |   | 29 |   |
| Canada                |       | 2,033          |       | 1,448        |       | 3,087          |       | 2,713 |   | 5,120 |   | 4,161 |   |
| Synthetic             |       | 91             |       | 59           |       | 21             |       | 14 |   | 112 |   | 73 |   |
| United States         |       | 180            |       | 91           |       | 208            |       | 144 |   | 388 |   | 235 |   |
| Yemen                 |       | 555            |       | 336          |       | —         |       | — |   | 555 |   | 336 |   |
| Colombia              |       | 112            |       | 11           |       | —         |       | — |   | 112 |   | 11 |   |
| **Total**             |       | 3,032          |       | 1,974        |       | 3,316          |       | 2,871 | ** ** | **6,348** | ** ** | **4,845** | ** ** |

 

----

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

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

* *

**Drilling Activity**

 
| ** **                 | ** ** | **2009**            | ** ** |
|----------------------------|------------|---------------------|------------|
| ** **                 | ** ** | **Net Exploratory** | ** ** | **Net Development** | ** ** | ** ** | ** ** |
| **(number  of net wells)** | ** ** | **Productive**      | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Productive** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Total** | ** ** |
| United Kingdom             |       | 3.1                 |       | 1.3 |   | 4.4 |   | 5.7 |   | 0.8 |   | 6.5 |   | 10.9 |   |
| Canada                     |       | 8.1                 |       | — |   | 8.1 |   | 50.3 |   | — |   | 50.3 |   | 58.4 |   |
| Synthetic1                 |       | —              |       | — |   | — |   | 6.5 |   | — |   | 6.5 |   | 6.5 |   |
| United States              |       | 0.7                 |       | 0.2 |   | 0.9 |   | 1.0 |   | — |   | 1.0 |   | 1.9 |   |
| Yemen                      |       | —              |       | — |   | — |   | 12.4 |   | — |   | 12.4 |   | 12.4 |   |
| Nigeria                    |       | 0.2                 |       | — |   | 0.2 |   | 1.6 |   | — |   | 1.6 |   | 1.8 |   |
| **Total**                  |       | 12.1                |       | 1.5 |   | 13.6 |   | 77.5 |   | 0.8 |   | 78.3 | ** ** | **91.9** | ** ** |

 
| ** **                 | ** ** | **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 |   |
| Canada                     |       | 9.2                 |       | — |   | 9.2 |   | 216.4 |   | — |   | 216.4 |   | 225.6 |   |
| Synthetic1                 |       | —              |       | — |   | — |   | — |   | — |   | — |   | — |   |
| United States              |       | 0.5                 |       | 1.0 |   | 1.5 |   | 1.3 |   | — |   | 1.3 |   | 2.8 |   |
| Yemen                      |       | —              |       | 1.0 |   | 1.0 |   | 17.4 |   | — |   | 17.4 |   | 18.4 |   |
| 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 |   |
| Canada                     |       | 23.2                |       | 0.6 |   | 23.8 |   | 295.6 |   | 3.2 |   | 298.8 |   | 322.6 |   |
| Synthetic1                 |       | —              |       | — |   | — |   | — |   | — |   | — |   | — |   |
| United States              |       | 0.8                 |       | 2.9 |   | 3.7 |   | 8.6 |   | 1.0 |   | 9.6 |   | 13.3 |   |
| Yemen                      |       | 1.0                 |       | 1.0 |   | 2.0 |   | 28.0 |   | — |   | 28.0 |   | 30.0 |   |
| 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** | ** ** |

 

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*1*                 Synthetic productivedevelopment wells are SAGD producer and injector wells pairs. In addition tothese wells we have drilled a further 34.8 net wells during 2009 (2008—88.5 netwells; 2007—105.0 net wells).

* *

**Wells in Progress**

 

At December 31, 2009, we were drilling two wells inthe United Kingdom (1.1 net), one well in Canada (one net), two wells in theUnited States (0.5 net), one well in Yemen (0.5 net), two wells in Nigeria(0.4 net) and one well in Norway (0.5 net). There were no wells drilling inColombia at December 31, 2009.

 

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**ENERGYMARKETING**

 

Our energy marketing group currently sells proprietary andthird-party natural gas, crude oil, natural gas liquids, and power in certainregional global markets. We use financial and derivative contracts, includingfutures, forwards, swaps and options for hedging purposes.

 

Our marketing strategy isto:

 

·                  obtain competitive pricing onthe sale of our oil and gas production;

·                  provide market intelligence insupport of our oil and gas operations;

·                  provide superior customerservice to producers and consumers;

·                  capitalize on crude oil marketopportunities through physical trading; and

·                  optimize physical assets orcontracts to which we have access.

 

This strategy aligns with our corporate focus on realizingthe full value from our assets and provides us with the market intelligenceneeded to deliver oil and gas production to market at competitive pricing.

 

In 2009, we announced that we were reviewing strategicalternatives for our natural gas and power marketing businesses, which mayinclude the sale of all or part of these businesses. At this time, the reviewis underway and is expected to conclude in 2010.

 

**North American Crude Oil Marketing**

 

Our crude oil business in North America markets physicalcrude oil to end-use refiners, as well as buying and selling natural gasliquids (NGLs). The crude oil group markets Nexen’s proprietary production andthird-party production. Our team leverages regional knowledge, retains capacityon key North American infrastructure and maintains solid customerrelationships. In addition to physical marketing, we take advantage of quality,time and location spreads to generate returns.

 

Our North American operations focus on key regions supportedby our offices in Calgary, Houston and Denver. In western Canada, our producerservices group concentrates on purchasing from a diversified supply base, whileour commercial team seeks to optimize sales to refiners. At the end of 2009, wehad access to 3.0 mmbbls of crude oil storage and over the course of the year,marketed approximately 852 mbbls per day.

 

**North American Gas Marketing**

 

The North Americannatural gas team focuses on key regional markets where we have a strategicpresence, equity production, solid customer relationships, in-depthunderstanding of the market or established physical assets. We capture regionalopportunities by managing supply, transportation and storage assets forproducers and end users. In addition to the fee-for-service income we realizefrom managing these assets, we generate further revenue by:

 

·                  capitalizing on differences inprices between locations using our transportation assets;

·                  offering customized service toour customers that bundle our assets with the commodity;

·                  utilizing our storage assetswhere we optimize forward and seasonal pricing differences; and

·                  leveraging regional knowledgewe gain through optimizing our assets.

 

At the end of 2009, we held 1.5 bcf/d of pipeline capacity,primarily between western Canada and the eastern US. We also use storagecapacity to store normally cheaper summer gas in the ground until the winterheating season arrives. We had access to 32 bcf of natural gas storagefacilities at the end of 2009.

 

**North American Power Marketing**

 

The power team is responsible for optimizing our 50% interestin a 120 MW gas-fired, combined-cycle power generation facility at Balzac,Alberta, as well as our 50% interest in the 70 MW Soderglen wind poweroperation in southern Alberta. The Balzac facility began operations in 2001 andSoderglen began operations in 2006. We also market the surplus power from the170 MW cogeneration facility at Long Lake, in which Nexen has a 65% interest,which commenced operations in 2008. We market power to larger commercial,industrial and municipal clients.

 

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**Europe**

 

Our European operations include a UK-based European gas andpower marketing business. At the end of 2009, we had access to 0.1 bcf/dtransportation capacity and 4.2 bcf of storage capacity. Our European marketingoperations also market most of our international crude oil proprietaryproduction.

 

**Asia**

 

Our international team in Asia continues to focus on thephysical marketing of Masila crude oil. In order to meet customer needs, weoccasionally market other regional crude qualities. In addition to our owncrude, we sell production for our partners and third parties in the Yemenregion.

 

**CHEMICALS**

 

In 2005, we monetized part of our chemicals business throughan initial public offering of the Canexus Income Fund. We currently hold a65.7% interest in our chemicals business, and continue to fully consolidatechemicals in our Consolidated Financial Statements.

 

Our chemicals business manufactures sodium chlorate andchlor-alkali products (chlorine, caustic soda and muriatic acid) in Canada andBrazil. This production is sold in North and South America, with some sodiumchlorate distributed in Asia. Our manufacturing system is reliable, low-costand strategically located to capitalize on competitive electricity costs andtransportation infrastructure to minimize production and delivery costs.

 

 

Electricity is the most significant operating cost inproducing sodium chlorate and chlor-alkali products. At the end of December 2009,electricity costs were approximately 40% of total cash costs. Therefore, ourfacilities are strategically located to take advantage of economic powersources. Our second highest cost is transportation. The proximity of ourmanufacturing plants to major customers and competitive freight rates minimizeour transportation costs. Labour is also a significant manufacturing cost.Approximately 55% of our workforce is unionized with collective agreements inplace at all of our unionized plants.

 

To grow value in our chemicals business, we focus on reducingour costs while maintaining market share, building a sustainable North Americancustomer base and capturing new offshore opportunities.

 

**North America**

 

The North American pulp and paper industry consumesapproximately 92% of the continent’s sodium chlorate production. We market oursodium chlorate production to numerous pulp and paper mills under multi-yearcontracts that contain price and volume adjustment provisions. Approximately29% of this production is sold in Canada, 66% in the US, and the rest ismarketed offshore.

 

We are the third-largest manufacturer of sodium chlorate inNorth America with three Canadian facilities: Nanaimo, British Columbia;Brandon, Manitoba; and Beauharnois, Quebec.

 

In 2008, we completed an expansion of our Brandon plant,increasing capacity to over 290,000 tonnes per year. Brandon is the world’slargest sodium chlorate facility and has one of the lowest cost structures inthe industry, significantly enhancing our competitive position in NorthAmerica.

 

Our chlor-alkali facility at North Vancouver, BritishColumbia, manufactures caustic soda, chlorine and muriatic acid. Approximately70% of our caustic soda is consumed by local pulp and paper mills with thebalance consumed in water treatment, oil and gas industry applications andgeneral chemical industry applications in the region. Approximately 25% of thechlorine that we produced was sold in the region as hydrochloric acid,primarily to oil and gas, mining/metal fabrication and general industryaccounts. The balance of our chlorine is sold to various customers in thepolyvinyl, chloride, water purification and petrochemicals industries,primarily in the United States. A technology 

 

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conversion project is currently underway at the NorthVancouver plant that will replace existing diaphragm technology and assets withnewer, proven membrane technology that is expected to be more cost effectiveand will expand productive capacity by 35%. This project is progressing withcommitted financing in place through to August 2011. The project isexpected to start up in the second quarter of 2010 and should lower our coststructure and solidify our low-cost position in this regional market.

 

**Average Annual Production Capacity**

 
| **(short tons)**     | ** ** | **2009**    | ** ** | **2008**    | ** ** | **2007**    | ** ** |
|----------------------|------------|-------------|------------|-------------|------------|-------------|------------|
| **Sodium  Chlorate** |       |        |       |        |       |        |       |
| North America        |       | 431,900     |       | 484,800     |       | 450,055     |       |
| Brazil               |       | 68,563      |       | 68,563      |       | 68,563      |       |
| **Total**            | ** ** | **500,463** | ** ** | **553,363** | ** ** | **518,618** | ** ** |
| **Chlor-alkali**     |       |        |       |        |       |        |       |
| North America        |       | 364,500     |       | 364,500     |       | 364,500     |       |
| Brazil               |       | 109,430     |       | 109,430     |       | 109,430     |       |
| **Total**            | ** ** | **473,930** | ** ** | **473,930** | ** ** | **473,930** | ** ** |

 

**Brazil**

 

We entered Brazil in 1999 by acquiring a sodium chlorateplant and a chlor-alkali plant from Aracruz Celulose S.A. (Aracruz), theleading manufacturer of pulp in Brazil. The majority of the sodium chlorateproduction is sold to Aracruz under a long-term sales agreement that expires in2024. Most of the chlorine and about 8% of the sodium chlorate production issold in the merchant market under short-term contracts. In 2002, we completedan expansion at both facilities to meet Aracruz’s growing needs. A 2,000 tonneincremental sodium chlorate expansion project at our Brazil plant was completedin early 2009, with a further 4,400 tonne expansion planned to begin in early2010. The majority of our electricity needs in Brazil are supplied by along-term supply contract, which expires in February 2013.

 

**GOVERNMENTAND ENVIRONMENTAL REGULATIONS**

 

Our operations are subject to various levels of governmentcontrols and regulations in the countries where we operate. These laws andregulations include matters relating to exploration, production practices,occupational health and safety, environmental protection, midstream andmarketing activities. These laws and regulations may increase the cost of doingbusiness and, accordingly, affect profitability. We participate in manyindustry and professional associations through which our interests in newregulation and legislation are represented, and we monitor the progress ofproposed legislation and regulatory amendments.

 

Laws and regulations change frequently and sometimesunpredictably and we are unable to predict the future costs or impact ofcompliance. However, we do not expect that any of these laws and regulationswill affect our operations materially different than they would any other oiland gas company of similar size and financial strength. We believe ouroperations comply, in all material respects, with applicable laws andregulations in the various jurisdictions where we operate.

 

The types of laws and regulation that affect our businessmost significantly fall into two categories: i) Operational, and ii) Health,Safety and Environment.

 

**OPERATIONAL REGULATIONS**

 

Our oil and gasexploration and production activities are subject to various federal, state,provincial, territorial, local and international laws and regulations. Thoselaws and regulations affect a number of operational activities including:

 

·                  land access;

·                  acquisition of seismic data;

·                  location of wells;

·                  drilling, completion and wellservicing;

·                  transportation, storage anddisposal of waste products arising from oil and gas operations;

·                  land restoration and wellabandonment;

·                  pricing policies;

·                  royalties;

·                  various taxes and leviesincluding income tax; and

·                  foreign trade and investment.

 

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The implications of these laws and regulations to ourbusiness include direct costs in the form of: tariffs; fees; taxes; rent; androyalties; and other direct charges measured by the type, region or intensityof activity. Indirect costs also arise from restricted access to certain areasof operation; restrictions on the type, frequency or conduct of permittedoilfield operations; limitations on production rates from certain oil and gaswells; forced pooling of oil and gas interests with third parties; changes indrill spacing units or well densities; infrastructure development; satisfactionof local content obligations for international projects; carried governmentparticipation in certain projects; and community consultation.

 

**HEALTH, SAFETY AND ENVIRONMENTAL REGULATIONS**

 

Our oil, gas and chemicaloperations are subject to various federal, state, provincial, territorial,local and international laws and regulations designed to regulate the impact ofhuman activity on the natural environment and the safety of our worksites.These laws and regulations relate to:

 

·                  the types and quantities ofsubstances and waste materials that can be discharged into the environment;

·                  use or removal of naturalresources (such as water and timber) in exploration and production activities;

·                  abandonment, reclamation andremediation of worksites (including sites of former operations);

·                  development of emergency andcommunity response plans; and

·                  implementation of safe workpractices for employees and contractors.

 

We are committed to operating within these laws andregulations and to conducting our business in a safe and environmentallyresponsible manner.

 

Environmental regulation is becoming more complex andincreasingly stringent. To reduce our risk of non-compliance with these laws,we apply industry standards, codes and best practices that meet or exceed ourlegal obligations. We conduct activities in countries where environmentalregulatory frameworks are in various stages of development. Where regulationsdo not exist, or where we consider them to be insufficiently developed, weobserve Canadian standards where applicable, as well as internationallyaccepted industry environmental management practices.

 

Our health, safety, environment and social responsibilitygroup (HSE&SR) helps ensure 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. Nexen’s overallHSE&SR program is guided by our corporate HSE&SR management system thatincorporates the Responsible Care continual improvement model of Plan, Do,Check, Act and our own 12 guiding elements for divisional performance. For moreinformation on Nexen’s HSE&SR management system refer to our sustainabilityreport available at www.nexeninc.com. For more information on Responsible Careplease refer to our sustainability report and www.ccpa.ca.

 

Our performance against this system is reviewed by anexternal auditor every three years and we have been recognized by the GoldmanSachs Sustain Report and Dow Jones Sustainability Index (North America) as asustainability leader. Our progress is publicly reported in our sustainabilityreport.

 

**Environmental Responsibilities and Climate Change**

 

A growing awareness of possible causes and effects of climatechange has increased concern over ways the world produces and consumes energy.Government and investor expectations continue to converge on sustainableresource development and responsible operating practices, including the preservationof air, water and land. Some jurisdictions in which we operate have alreadyformalized these expectations into regulation while others move closer to doingso. Regardless of how the jurisdictions in which we operate ultimately definetheir emissions regulation, we expect that our regulatory obligations and theassociated cost of compliance will increase. Due to the uncertainty surroundingthe future implementation of emissions regulations, we are unable to estimateour costs of compliance in the future.

 

As a result of our commitment to sustainable development andresponsible operating practices, we believe we are well positioned to meet thechallenges of environmental regulation and climate change. 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.

 

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**Air**

 

Canada has signed the Copenhagen Accord (Accord) which shouldallow Canada to set a new base year and further achieve alignment with theUnited States. The Accord aims to cut emissions so as to maintain projectedworld temperature increases at less than 2°C. Specific greenhouse gas (GHG)targets are not stipulated, however, developed nations were required to submittargets for 2020 by January 31, 2010. A commitment was made to raiseUS$30 billion over three years beginning in 2010 and US$100 billionannually starting in 2020 to fund climate change mitigation and adaptationmeasures in the developing world. The Accord does not include compliancemechanisms and it remains to be seen whether this agreement will become legallybinding on participating nations.

 

Notwithstanding the Accord, obligations under the KyotoProtocol remain in place. The Kyoto Protocol came into force in 2005 and wasratified by Canada in December 2002. Kyoto provides for a cap-and-tradesystem which requires participating nations to reduce GHG emissions. Canadacommitted to an emission reduction of 6% below 1990 levels during the FirstCommitment period from 2008 to 2012. True-up to Kyoto commitments will not takeplace until sometime later in 2014.

 

The Canadian federal government has yet to pass climatechange legislation. In 2007, the Canadian federal government introduced a papertitled *Regulatory Framework for Air Emissions*which proposed that the federal government regulate GHGs and air pollutantsbeginning as early as 2010, with progressively more stringent reductionsapplied through 2050. Draft regulations have yet to be released. The federalgovernment’s recent announcements respecting a Clean Energy Dialogue with theUnited States and their expressed interest in pursuing a bi-lateral cap andtrade system with the United States have created further uncertainty about theimplementation of the *Regulatory Framework for Air Emissions*.

 

In June 2009, the Canadian federal government introducedthe *Offset System for Greenhouse Gases*.Under this program, the Government of Canada will issue offset credits for GHGemission reductions. Companies that are subject to GHG regulations will be ableto purchase these credits in order to comply with regulated targets. Finalversions of the offset system guidelines have yet to be published.

 

The Canadian federal government also indicated their intentto regulate air pollutants concurrent with GHGs, but their schedule andlong-term objectives remain unclear. In recent months, work has progressed on afederal *Comprehensive Air Management System*.One of the key features of this system is implementing minimum emissionstandards for new and existing equipment. We could face technical challenges inmeeting these minimum emission standards for certain pollutants. Any requiredreductions in the GHGs emitted from our operations (without an allowed offsetcompliance mechanism) could result in increases to our capital or operatingexpense, or reduced operating rates, especially at the Long Lake project, whichcould have an adverse effect on our results of operations and financialcondition. As a “new facility”, Long Lake will have three years to establish anemissions baseline before having a reduction obligation assigned. In 2009, ourCanadian operations, including Syncrude, accounted for 27% of our productionbefore royalties.

 

Alberta became the first jurisdiction in Canada to enact andimplement binding emission reductions (a one-time from base, 12% reduction incarbon intensity) 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 2007entitled the *Greenhouse Gas Reduction Targets Act*which targets a 33% reduction in current provincial GHG emissions by 2020.British Columbia is actively engaged in the Western Climate Initiative andrecently enacted a GHG reporting regulation. For oil and gas operations, thefacility emission reporting threshold is zero (i.e., all facilities must reportregardless of size). The province also applied a carbon tax to all hydrocarbonfuels sold in the province. The tax started at $10/tonne CO2 in 2008 and will increase $5 per year until itreaches $30 per tonne.

 

It remains to be seen if the federal and provincialgovernments will harmonize their compliance regimes in Canada.

 

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In 2008, the European Union(EU) introduced Phase II of the Emissions Trading Scheme (ETS), which will rununtil 2012. Under the ETS, member states are required to establish a nationalallocation plan approved by the EU. The system only covers CO2 from some combustion and flaring activitiesand member states are allowed to manage allocation across their industrial baseas they see fit. Installations have the option of purchasing allowances fromother participants in order to meet the cap.

 

Several regulatory initiatives have recentlybeen introduced in the United States. The proposed bills contemplate aneconomy-wide cap-and-trade regime to reduce GHG creation. Based on comments bythe Canadian government we anticipate that any Canadian climate changeregulations will be closely modeled on the United States scheme in both timingand substance. The US Environmental Protection Agency (EPA) has announced itsfindings that GHGs pose a threat to public health. This finding may lead tofurther regulations by the EPA under the *Clean AirAct*. It is unclear if and when these legislativeproposals will be passed. To meet our current greenhouse gas (GHG) emissionsobligations, we adhere to a four point emissions management strategy:

 

·                  reduce direct GHGemissions at our facilities;

·                  self-generate carboncredits from wind power;

·                  acquire carbon creditsthrough qualified projects and authorized agencies; and

·                  participate in eligibleinternational and domestic offset projects.

 

**Water**

 

Wehave developed a water strategy designed to minimize water use in ourexploration and production operations. This strategy is embodied by thefollowing four principles:

 

·                  optimize water useefficiency;

·                  minimize our impacts onecosystem functions and ensure public health and safety are not affected by ouractivities;

·                  engage with stakeholdersto promote responsible watershed management and evaluate opportunities toprovide water management benefits to stakeholders; and

·                  measure and communicateour water management performance.

 

This strategy was implementedin 2009 with an emphasis on compliance and early adoption of best practices,incorporating water assessment tools in our investment decision-making process,developing water management systems to enhance water tracking and reporting,and seeking water re-use opportunities.

 

**Land and Biodiversity**

 

Our land use practices arebased upon principles of minimal disturbance and a commitment to return land toits natural state after responsibly producing oil and gas resources. We alsorecognize our ability to effectively access land directly linked to the way inwhich we manage potential environmental effects and in how we cooperate withlocal communities, stakeholders, regulators, and other industries to reduce thecumulative impact of our projects throughout their lifecycle.

 

For many stakeholders, acompany’s ability to meet environmental expectations is a significant criteriaupon which their decision to invest or conduct business is based. A failure tomeet those expectations can limit access to exploration, development andpartnership opportunities. Therefore, we believe that superior environmentaland social responsibility performance is directly linked to economicperformance.

 

We have outlined and more fullydiscussed our environmental practices and policies in our sustainabilityreport, available on our website at www.nexeninc.com.

 

**Environmental Provisions  and Expenditures**

 

Meeting the challenges ofclimate change and environmental regulation and our commitment to sustainableresource development affects all stages of our operations and generallyincreases their cost. Environmental commitments and regulation can increase theoperational or capital cost of operations, delay requisite permits or approvalsfrom issuing authorities, and result in unprofitable or unfavourable operatingconditions. During 2009 we incurred both capital and operational expenses,including expenses related to environmental control facilities. Those costswere not material and did not impair our ability to execute our business oroperating strategy. We will continue to incur these costs in the future andexpect they will be manageable. At December 31, 2009,$1,053 million ($2,341 million, undiscounted, adjusted for inflation)has been provided in our Consolidated Financial Statements for asset retirementobligations.

 

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**EMPLOYEES**

 

We had 4,594 employees on December 31, 2009,of which 323 were employed under collective bargaining schemes. Information onour executive officers is presented in Item 10 of this report.

 

**ITEM 1A.**

 

**RISK FACTORS**

 

Our operations are exposed tovarious risks, some of which are common to others in the oil and gas industryand some of which are unique to our operations. Certain risks set out belowconstitute “forward-looking statements” and the reader should refer to the “SpecialNote Regarding Forward-Looking Statements” set out on page 96 of this10-K.

 

**Our profitability and liquidityare highly dependent on the price of crude oil and natural gas.**

 

Our financial performancedepends significantly on the price of crude oil and natural gas. Crude oil andnatural gas are commodities which are sensitive to numerous worldwide factors,many of which are beyond our control and are generally sold at contract orposted prices. Historically, these prices have been very volatile, and arelikely to remain volatile in the future. A shortage of crude oil in 2007 andearly 2008 drove oil prices to record highs. Recent worldwide economicconditions depressed demand for commodities and caused commodity prices toweaken significantly in late 2008 and early 2009. These swings in prices significantlyaffected our results of operations and revenue generated from our oil and gasproducing assets. Periods of lower commodity prices may reduce our level ofspending for oil and gas exploration and development, and materially andadversely affect our results of operations.

 

Crude oil prices we receive arebased on various reference prices, which generally track the movement of Brentand WTI. Adjustments are made to the reference price to reflect qualitydifferentials and transportation costs. Brent, WTI and other internationalreference prices are affected by numerous and complex worldwide factors such assupply and demand fundamentals, economic outlooks, production quotas set by theOrganization of Petroleum Exporting Countries and geopolitical events.

 

**Weak global economic activity andfragile credit markets may negatively impact our liquidity.**

 

While we generally rely uponcash flow from operations to fund our activities, a sustained reduction in theprices of crude oil and natural gas may require us to rely upon existing creditfacilities or issue new debt or equity to satisfy our funding needs. The mostrecent economic crisis resulted in a tightening of the credit markets, a lowerlevel of liquidity in many financial markets, and volatility in world-widefixed income, credit, currency and equity markets. There could be follow-oneffects as a result of the credit crisis on our business which could negativelyimpact our liquidity and operations, and which may materially affect ourbusiness, including: a reduced ability to access credit markets or issue newpublic or private debt; higher borrowing costs; lower returns on invested cash;and, a negative change to our ratings outlook or a reduction of our creditratings by one or more credit-rating agencies. A credit rating downgrade couldlimit our access to private and public credit markets and increase the costs ofborrowing under existing facilities. In addition, if our credit ratings weredowngraded, we could be required to provide additional liquidity to support ourenergy marketing division as further collateral may be required by ourcounterparties, or we may also be required to reduce some of our energymarketing activities.

 

**The inability of counterpartiesand joint operating partners to fulfill their obligations to us could adverselyimpact our results of operations.**

 

Credit risk arises from thesale of production and products our energy marketing group buys for resale,from financial contracts we acquire for hedging and trading purposes and fromour joint venture partners for their share of capital and operating costs wherewe operate. There is the risk of loss and additional burden for amounts inexcess of available remedies if counterparties or joint venture partners do notor cannot fulfill their contractual obligations. The recent credit crisis in2008 and 2009 that impacted world financial 

 

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markets and depressed oil andgas prices caused some of our counterparties to restructure, declare bankruptcyor sell assets to fund liquidity requirements. We incurred some losses in 2008from counterparties facing such difficulties, as described in our financialstatements. In the future, we may experience similar losses. Most of ourreceivables and partners are with counterparties in the energy industry and aresubject to normal industry credit risk. The inability of any one or more ofthese parties to fulfill their obligations to us may adversely impact ourresults of operations.

 

**Increased environmentalregulation could increase our operating costs and affect profitability.**

 

Ouroil, gas and chemical operations are subject to various federal, state,provincial, territorial, local and international laws and regulations designedto regulate the impact of human activity on the natural environment. Those lawsand regulations govern, amongst other things:

 

·                  the types and quantitiesof substances and waste materials that may be discharged into the environment;

·                  the use or removal ofnatural resources (such as water and timber) in exploration and productionactivities;

·                  the release of greenhousegases, such as carbon dioxide and methane, into the atmosphere;

·                  the protection ofendangered species;

·                  the abandonment,reclamation and remediation of worksites (including sites of formeroperations); and

·                  the issuance of permitsand other regulatory approvals in connection with exploration, drilling andproduction activities.

 

These laws and regulations mayimpose significant liabilities on a failure to comply with their requirements.Significant changes in the environmental laws and regulations governing ourcurrent operations, including many of the proposed initiatives to regulategreenhouse gas emissions, may have an adverse effect on the oil and gasindustry. The cost of meeting new environmental and climate change regulationsmay have an adverse effect on the viability of future projects, our results ofoperations, cash flows, and financial condition.

 

**Competitive forces may limit ouraccess to natural resources, and create labour and equipment shortages.**

 

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

 

·                  gaining access to areas orcountries known to have available resources;

·                  searching for anddeveloping new sources of crude oil and natural gas reserves;

·                  constructing andoperating crude oil and natural gas pipelines and facilities; and

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

 

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

 

Competitive forces may resultin shortages of; i) prospects to drill; ii) labour; iii) drilling rigs andother equipment to carry out exploration, development or operating activities;and iv) shortages of infrastructure to produce and transport production. It mayalso result in an oversupply of crude oil and natural gas. Each of thesefactors could negatively impact our costs and prices and, therefore, ourfinancial results.

 

**We operate in harsh andunpredictable climates and locations where our access is regulated which couldadversely impact our operations.**

 

Some of our facilities arelocated in harsh and unpredictable climates and locations which can experienceextreme weather conditions and natural disasters such as: sustained ambienttemperatures above 40°C or below -35°C, flooding, droughts, wind and duststorms, difficult terrain, high seas, monsoons and hurricanes. These conditionsare difficult to anticipate and cannot be controlled. In these conditions,operations can become difficult or unsafe and are often suspended. Some of ourfacilities and those which our facilities rely upon (such as pipelines, power,communications and oil field equipment) are vulnerable to these types of 

 

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extreme weather conditions andmay suffer extensive damage as a result. If any such extreme weather were tooccur, our ability to operate certain facilities and proceed with explorationor development 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 conducted during limited times of the yeardue to weather or government regulation. These adverse conditions can limit ourability to operate in those areas and can intensify competition during periodsof good weather for oil field equipment, services and qualified personnel,which may lead to periodic shortages. These constraints and the resultingshortages or high costs could delay our operations and materially increase ouroperating and capital costs, and could have a material adverse effect on ourbusiness, financial condition and results of operations. Changing weatherpatterns may increase the frequency, intensity or duration of these weatherconditions, and accordingly exacerbate their impacts on our operations.

 

**Exploration, development andproduction activities may not be successful and carry a risk of loss.**

 

Acquiring,developing and exploring for oil and natural gas involves many risks. There isa risk that we will not encounter commercially productive oil or gasreservoirs, and that the wells we drill may not be productive, or notsufficiently productive to recover a portion or all of our investment. Seismicdata and other exploration technologies we use do not provide conclusive proofprior to drilling a well that crude oil or natural gas is present or may beproduced economically. The costs of drilling, completing and operating wellsare often uncertain, and drilling operations may be extended, curtailed, delayedor canceled as a result of a variety of factors, including:

 

·                  encountering unexpectedformations or pressures;

·                  blow-outs, well borecollapse, equipment failures and other accidents;

·                  craterings and sour gasreleases;

·                  accidents and equipmentfailures;

·                  uncontrollable flows ofoil, natural gas or well fluids; and

·                  environmental risks.

 

We may not achieve productiontargets should our reservoir production decline sooner than expected. Also, weoperate two facilities that are located in close proximity to populated areas,and each processes materials of potential harm to the local populations. We maynot be fully insured against all of these risks. Losses resulting from theoccurrence of these risks may materially impact our operational activities andfinancial results.

 

**Unconventional gas resource playscarry additional risks and uncertainties.**

 

Part of Nexen’s growthstrategy is to invest in unconventional Canadian gas resource plays, such asCBM and shale gas. Exploitation techniques and practices for these resources inCanada generally remain in the early stages of development and it is difficultto determine whether or not these resource plays will prove commerciallyviable, to what degree or when.

 

CBMis commonly referred to as an unconventional form of natural gas because it isprimarily stored through adsorption by the coal itself rather than in the porespace of the rock like most conventional gas. The gas is released in responseto a drop in pressure in the coal seam. Some of the uncertainties associatedwith development of CBM resources are as follows:

 

·                  if the coalbed is watersaturated, such as the Mannville coals in the Fort Assiniboine region ofAlberta, water generally needs to be extracted to reduce the pressure and allowgas production to occur. A significant period of time may be required to dewaterthese wet coals and determine if commercial production is feasible. We may alsohave to invest significant capital in these assets before they achievecommercial rates of production, if ever;

·                  some coalbeds may nothave sufficient natural permeability in the coalbed to recover the gas in placeand can therefore require more extensive, and expensive, completiontechnologies which can increase the cost of drilling and production or whichmay not be successful;

·                  the public may reactnegatively to certain water disposal practices related to water-saturated CBMprojects, even though these water disposal practices are regulated to 

 

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ensure public safety and waterconservation. Negative public perception around water-saturated CBM productioncould impede our access to the resource;

·                  CBM wells typically havelower producing rates and reserves per well than conventional gas wells,although this varies by area; and

·                  regulatory approval isrequired to drill more than one well per section. As a result, the timing ofdrilling programs and land development can be uncertain.

 

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

 

·                  shale gas wells typicallyhave higher initial production decline rates and lower producing rates, andreserves per well than conventional gas wells, although this varies by area;

·                  regulatory approval isrequired to drill more than one well per section. As a result, the timing ofdrilling programs and land development can be uncertain;

·                  shales are typically lesspermeable than conventional gas reservoirs, and can therefore require moreextensive, and expensive, completion technologies which can increase costs orwhich may not be successful;

·                  seasonal access tocertain areas may limit activities or increase competition for equipment and/orqualified personnel;

·                  lack of access toregional infrastructure for the sale of production; and

·                  significant capitalexpenditures are required before establishing commerciality of a particularplay.

 

**Our heavy oil production is moreexpensive and yields lower prices than light oil.**

 

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

 

·                  additional costs may beincurred to purchase diluent to transport heavy oil;

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

·                  the market for heavy oilis more limited than for light oil making it more susceptible to supply anddemand fundamentals which may cause the price to decline.

 

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

 

**Without reserve additions, ourreserves and production will decline over time and we require capital toproduce remaining reserves.**

 

Our future crude oil andnatural gas reserves and production, and therefore our future operating cashflows and results of operations, are highly dependent upon our success inexploiting our current reserves and acquiring or discovering additionalreserves in the future. Without reserve additions through exploration,development or acquisitions, our reserves and production will decline over timeas reserves are produced. The business of exploring for, developing oracquiring reserves is capital intensive. To the extent cash flows fromoperations are insufficient and external sources of capital become limited orunavailable, our ability to make the necessary capital investments to maintainand expand our oil and natural gas reserves and production may be impaired.

 

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Discovered oil and natural gasaccumulations are generally only produced when they are economicallyrecoverable. As such, oil and gas prices, and capital and operating costs havean impact on whether accumulations will ultimately be produced. As required bySEC rules, our reserves represent the quantities that we expect to economicallyrecover using existing prices and costs held constant. Reserves can increase ordecrease under different price and cost scenarios.

 

**Our reserves include undevelopedproperties that require additional capital to bring them on stream.**

 

Under SEC rules, proved andprobable oil and gas reserves include undeveloped reserves that are expected tobe recovered from new wells on undrilled acreage or from existing wells where arelatively major expenditure is still required before such wells beginproduction. Reserves may be recognized when plans are in place to make therequired investments to convert these undeveloped reserves to producing.Circumstances such as a sustained decline in commodity prices or poorer thanexpected results from initial activities could cause a change in the investmentor development plans which could result in a material change in our reservesestimates. At December 31, 2009, 45% of our proved reserves beforeroyalties (45% after royalties) were undeveloped largely reflecting oil sandsreserves which will be developed as required to keep the related upgrader full.

 

**Our oil sands projects faceadditional risks compared to conventional oil and gas production.**

 

Phase 1 of our Long Lake oilsands development is a fully integrated production, upgrading and cogenerationfacility. We are using SAGD technology to recover bitumen from oil sands. Thebitumen is partially upgraded using our proprietary OrCrudeTM process, followedby conventional hydrocracking to produce a sweet, light, premium syntheticcrude oil. The OrCrudeTM process also yields liquid asphaltenes that aregasified into synthetic gas. This gas is used as fuel for the SAGD process, asource of hydrogen in the upgrading process, and to generate electricitythrough a cogeneration facility.

 

We have a 65% working interestin this project. Given the initial investment and operating costs to produceand upgrade bitumen, the payout period for the project is longer and theeconomic return is lower than a conventional light oil project with an equalvolume of reserves.

 

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

 

**APPLICATIONOF RELATIVELY NEW SAGD BITUMEN RECOVERY PROCESS**

 

SAGD has been used in westernCanada to increase recoveries from conventional heavy oil reservoirs for over adecade; however, application of SAGD to the insitu recovery of bitumen from oilsands is relatively new. Some of the SAGD oil sands applications to date havebeen pilot projects, although several commercial SAGD projects have been inoperation for over seven years.

 

Our estimates for performanceand recoverable volumes for the Long Lake project are based primarily on ourthree well-pair SAGD pilot, the initial performance of our first commercialwell phase, and industry performance from SAGD operations in similar reservoirsin the McMurray formation in the Athabasca oil sands. Using this data, ourdevelopment assumptions included average well-pair productivity of 900 bbls/dof bitumen and a long-term steam-to-oil ratio within a plant capacity of 3.3.While some of our wells have achieved these levels to date, there can be nocertainty that these wells will maintain these levels or that our overall SAGDoperation will produce bitumen at the expected levels or steam-to-oil ratio. Ifthe assumed production rates or steam-to-oil ratio are not achieved, we mighthave to drill additional wells to maintain optimal production levels, constructadditional steam generating capacity, purchase natural gas for additional steamgeneration, and/or make short-term bitumen purchases. These could have anadverse impact on the future activities and economic return of the Long Lakeproject.

 

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**APPLICATIONOF NEW BITUMEN UPGRADING PROCESS**

 

Theproprietary OrCrudeTM process we are using to upgrade raw bitumen to syntheticcrude is the first commercial application of the process although we haveoperated it in a 500 bbls/d demonstration plant. Initial upgrader operationsbegan in January 2009. There is no certainty that the commercial upgraderat Long Lake will sustain or achieve the results which are now being seen orforecast. If we are unable to continue to upgrade the bitumen for any reason,we may decide to sell the bitumen directly to third parties without upgrading,which would expose us to the following risks:

 

·                  the market for bitumenmay be limited;

·                  additional costs would beincurred to purchase diluent for blending and transporting bitumen;

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

·                  the market price forbitumen is relatively low reflecting its quality differential;

·                  the market price forbitumen fluctuates; and

·                  additional costs would beincurred to purchase natural gas for use in generating steam for the SAGDprocess since we would not be producing syngas from the upgrading process.

 

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

 

If any of these factors arise,our operating costs would increase and our revenues would decrease from thosewe have assumed. This would materially decrease expected earnings from theproject and the project may not be profitable under these conditions.

 

**DEPENDENCEUPON PROPRIETARY TECHNOLOGY**

 

The success of the Long Lakeproject and our investment depends highly on the proprietary technology of OPTIand proprietary technology of third parties that has been, or is required tobe, licensed for the project. OPTI and Nexen rely on intellectual propertyrights and other contractual or proprietary rights, including (withoutlimitation) copyright, trademark laws, trade secrets, confidentialityprocedures, contractual provisions, licenses and patents, to secure the rightsto utilize OPTI’s proprietary technology and the proprietary technology ofthird parties. OPTI and Nexen may have to engage in litigation to protect thevalidity of its patents or other intellectual property rights, or to determinethe validity or scope of patents or proprietary rights of third parties.Litigation can be time-consuming and expensive, whether successful or not. Theprocess of seeking patent protection can itself be long and expensive, with noassurance that any pending or future patent applications of OPTI or such thirdparties will actually result in issued patents, or that, if patents are issued,they will be of sufficient scope or strength to provide meaningful protectionor any commercial advantage to OPTI. Others may develop technologies that aresimilar or superior to: i) the technology of OPTI or third parties; or ii) thedesign around the patents owned by OPTI and/or third parties.

 

**OPERATIONALHAZARDS**

 

The operation of the project issubject to the customary hazards of recovering, transporting and processinghydrocarbons, such as fires, explosions, gaseous leaks, migration of harmfulsubstances, blowouts and oil spills. A casualty occurrence might result in theloss of equipment or life, as well as injury or property damage. We may notcarry insurance with respect to all potential casualty occurrences anddisruptions, and our insurance may not sufficiently cover casualty occurrencesor disruptions that occur. The Long Lake project could be interrupted bynatural disasters or other events beyond our control. Losses and liabilitiesarising from uninsured or under-insured events could have a material adverseeffect on the Long Lake project and on our business, financial condition andresults of operations.

 

Recovering bitumen from oilsands and upgrading the recovered bitumen into synthetic crude oil and otherproducts involve particular risks and uncertainties. The Long Lake project issusceptible to loss of production, slowdowns or restrictions on its ability toproduce higher-value products due to the interdependence of its componentsystems. Severe climatic conditions can cause reduced production and in somesituations result in higher costs. SAGD bitumen recovery facilities anddevelopment and expansion of production can entail significant capital outlays.The costs associated with synthetic crude oil production are largely fixed and,as a result, operating costs per unit depend largely on production levels.

 

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

 

Certain components of the LongLake project produce sour gas, which is gas containing hydrogen sulphide andcarbon monoxide. Sour gas is a colourless, corrosive gas that is toxic atrelatively low levels to plants and animals, including humans. Carbon monoxideis a colourless, odorless and tasteless gas which is toxic at relatively lowlevels to humans and animals. The project includes integrated facilities forhandling and treating the sour gas and for consuming the carbon monoxide as afuel, 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 shutdown of operations.

 

The Long Lake project producescarbon dioxide emissions. Risk factors relating to environmental regulation areprovided separately in this document.

 

**ABORIGINALCLAIMS**

 

Aboriginal peoples have claimedaboriginal title and rights to a substantial portion of western Canada. Certainaboriginal peoples have filed a claim against the Government of Canada, theProvince of Alberta, certain governmental entities and the regionalmunicipality of Wood Buffalo (which includes the city of Fort McMurray,Alberta) claiming, among other things, aboriginal title to large areas of landssurrounding Fort McMurray, including the lands on which the Long Lake projectand most of the other oil sands operations in Alberta are located. Such claims,if successful, could have a significant adverse effect on the Long Lake projectand on us.

 

**PUBLICPERCEPTION OF OIL SANDS DEVELOPMENT**

 

Developmentof the Athabasca oil sands has figured prominently in recent political, mediaand activist commentary on the subject of climate change and greenhouse gasemissions. Public perceptions of greenhouse gas emissions, and water and landuse practices in oil sands developments may directly or indirectly impair theprofitability of our current oil sands projects and the viability of future oilsands projects in a number of ways, including:

 

·                  creating significantregulatory uncertainty that challenges economic modeling of future projects anddelays sanctioning;

·                  motivating extraordinaryenvironmental and emissions regulation of those projects by governmental authoritiesthat could result in changes to facility design and operating requirements,thereby potentially increasing the cost of construction, operation andabandonment; and

·                  compelling legislation orpolicy that limits the purchase of crude oil produced from the Athabasca oilsands by governments or other institutional consumers that, in turn, limits theworld market for this crude oil and reduces its price.

 

These perceptions may alsoimpair our corporate reputation and limit our ability to access land and jointventure opportunities in other jurisdictions throughout the world.

 

**Some of our production isconcentrated in a few producing assets.**

 

Asignificant portion of our current and future production is generated fromhighly productive individual wells or central production facilities. Examplesinclude:

 

·                  Buzzard and Scottproduction platforms in the North Sea;

·                  central processingfacilities, oil pipelines, and export terminal at our Yemen operations;

·                  our Long Lake syntheticcrude oil operation in the Athabasca oil sands; and

·                  upgrading facilities atSyncrude in the Athabasca oil sands.

 

As significant production isgenerated from each asset, any single event that interrupts one of theseoperations could result in the loss of production.

 

**Our energy marketing operationsexpose us to the risk of trading losses and liquidity constraints.**

 

Our marketing operations exposeus to the risk of financial losses from various sources which may have amaterial adverse effect on our financial performance. The commodity markets inwhich we trade have experienced unanticipated volatility relative to historicalvariances in the last 18 months, resulting in unusual and significant pricingchanges, and 

 

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deviations from anticipatedseasonal pricing trends and pricing levels. Our energy marketing team maintainsa portfolio comprised of long and short physical and financial positions, whichmay be significant in size or number at any time. This portfolio of positionsis managed based on a trading thesis for expected future pricing levels andtrends in forward or regional markets. Unanticipated volatility in commodityprice levels and trends upon which those positions are based may cause aposition to decrease in value. The transportation and storage assets andcontracts undertaken by our energy marketing business may decrease in value dueto changes in temporal and regional commodity pricing.

 

Significant changes in thecommodities and financial markets could require us to provide additionalliquidity if additional collateral is required to be placed withcounterparties, or we may also be required to reduce some of our energy marketingactivities. Adverse credit-related events such as a downgrade of our creditrating to non-investment grade could require additional collateral to be placedwith counterparties. Adverse broad-based industry credit-related events couldalso negatively affect trading counterparties who fail to fulfill theircontractual obligations.

 

**Use of marine transportation mayexpose us to the risk of financial loss and damaged reputation.**

 

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

 

**We operate in countries withpolitical, economic and security risks.**

 

Weoperate in numerous countries, some of which may be considered politically andeconomically unstable. A portion of our revenue is derived from operations inthese countries. As a result, our financial condition and operating resultscould be significantly affected by risks associated with internationalactivities, including:

 

·                  civil unrest and generalstrikes;

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

·                  taxation policies,including royalty and tax increases and retroactive tax claims, and investmentrestrictions;

·                  expropriation or forcedrenegotiation or modification of existing contracts;

·                  exchange controls,currency fluctuations, devaluation or other activities that limit or disruptmarkets and restrict payments or the movement of funds;

·                  the possibility of beingsubject to exclusive jurisdiction of foreign courts in connection with legaldisputes relating to licenses to operate and concession rights in countrieswhere we currently operate; and

·                  difficulties in enforcingour rights against a governmental agency because of the doctrine of sovereignimmunity and foreign sovereignty over international operations.

 

The impact that futurepotential terrorist attacks or regional hostilities may have on the oil and gasindustry, and on our operations in particular, is not known at this time.Uncertainty surrounding military strikes or a sustained military campaign mayaffect operations in unpredictable ways, including disruptions of fuel suppliesand markets, particularly crude oil, and the possibility that infrastructurefacilities, including pipelines, production facilities, processing plants andrefineries, could be direct targets of, or indirect casualties of, an act ofterror or war. We may be required to incur significant costs in the future tosafeguard our assets against terrorist activities or to remediate potentialdamage to our facilities. There can be no assurance that we will be successfulin protecting ourselves against these risks and the related financialconsequences.

 

**We may be affected by changes ingovernment rules and regulations.**

 

Our operations are subject tovarious levels of government controls and regulations in the countries where weoperate. These laws and regulations include matters relating to land tenure,drilling, production practices, environmental protection (as discussed above),marketing and pricing policies, royalties, various taxes and levies includingincome tax, and foreign trade and investment, that are subject to change fromtime to time. Current legislation is generally a matter of public record, andwe cannot predict what additional legislation or amendments may be proposedthat will affect our operations or when any such proposals, if enacted, mightbecome effective. Changes in government laws and regulations could adverselyaffect our results of operations and financial condition.

 

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**ITEM 1B.**

 

**Unresolved Staff Comments**

 

There are no unresolved staffcomments with the SEC.

 

**ITEM 3.**

 

**Legal Proceedings**

 

There are lawsuits and claimspending against Nexen, the ultimate results of which cannot be ascertained atthis time. Management is of the opinion that any amounts assessed against uswould not have a material adverse effect on our consolidated financial positionor results of operations. We believe we have made adequate provisions for suchlawsuits and claims.

 

Certain of our US oil and gasoperations have received, over the years, notices and demands from the USEnvironmental Protection Agency (EPA), state environmental agencies, andcertain third parties for certain sites seeking to require investigation and remediationunder federal or state environmental statutes. In addition, notices, demands,and lawsuits have been received for certain sites related to historicaloperations and activities in the US for which, although no assurances can bemade, we believe that certain assumption and indemnification agreements protectour US operations from any present or future material liabilities that mayarise from these particular sites.

 

**ITEM 4.**

 

**Submission of Matters to a Voteof Security Holders**

 

No matters were submitted to avote of Nexen’s security holders during the fourth quarter of 2009.

 

**PART II**

 

**ITEM 5.**

 

**Market for the Registrant’sCommon Equity, Related Stockholder Matters and Issuer Purchases of EquitySecurities**

 

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

 

On December 31, 2009,there were 1,725 registered holders of common shares and 522,915,843 commonshares outstanding. The number of registered holders of common shares is calculatedexcluding individual participants in securities positions listings. During theyear, we made no purchases of our own equity securities.

 

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

 
| ** **     | ** ** | **TSX (Cdn$)** | ** ** | **NYSE (US$)** | ** ** |
|----------------|------------|----------------|------------|----------------|------------|
| **($/share)**  | ** ** | **High**       | ** ** | **Low**        | ** ** | **High** | ** ** | **Low** | ** ** |
| **2009**       |       |           |       |           |       |   |   |   |   |
| First Quarter  |       | 24.24          |       | 14.86          |       | 20.61 |   | 11.89 |   |
| Second Quarter |       | 28.54          |       | 20.65          |       | 26.25 |   | 16.33 |   |
| Third Quarter  |       | 25.94          |       | 20.70          |       | 24.43 |   | 18.68 |   |
| Fourth Quarter |       | 27.31          |       | 22.26          |       | 26.05 |   | 20.66 |   |
| **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 |   |

 

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**Quarterly Dividends Declared on Common Shares**

 
| **(Cdn$/share)** | ** ** | **First  Quarter** | ** ** | **Second  Quarter** | ** ** | **Third  Quarter** | ** ** | **Fourth  Quarter** | ** ** |
|------------------|------------|--------------------|------------|---------------------|------------|--------------------|------------|---------------------|------------|
| 2009             |       | 0.050              |       | 0.050               |       | 0.050              |       | 0.050               |       |
| 2008             |       | 0.025              |       | 0.050               |       | 0.050              |       | 0.050               |       |

 

Payment date for dividends wasthe first day of the next quarter. All dividends paid to holders of commonshares in 2009 have been designated as “eligible dividends” for Canadian taxpurposes. This designation will apply to all such dividends paid in the futureunless otherwise notified by us.

 

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

 

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

 

The following is a table ofsecurities authorized for issuance under equity compensation plans as of December 31,2009.

 
| **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 shareholders     |       | 23,130,414                                                               |       | $25/option                                                 |       | 26,283,536                                                                                              |       |
| Equity compensation plans not approved by shareholders |       | —                                                                   |       | —                                                     |       | —                                                                                                  |       |
| **Total**                                              |       | 23,130,414                                                               |       | $25/option                                                 |       | 26,283,536                                                                                              |       |

 

See page 178 for a graphshowing the change in a $100 investment in Nexen common shares over the pastfive years, compared to the S&P/TSX Composite Index, the S&P/TSX EnergySector Index and the S&P/TSX Oil & Gas Exploration &Production Index as at December 31, 2009.

 

On February 3, 2000,at a Special Meeting of Shareholders, a Shareholder Rights Plan was approved.On May 2, 2002, at the Annual General and Special Meeting ofShareholders, an Amended and Restated Shareholder Rights Plan (Plan) wasapproved. According to the Plan, a right is attached to each present and futureoutstanding common share, entitling the holder to acquire additional commonshares during the term of the right. Prior to the separation date, the rightsare not separable from the common shares, and no separate certificates areissued. The separation date would typically occur at the time of an unsolicitedtakeover bid, but our board can defer the separation date.

 

Rights created under the Plan,which can only be exercised when a person acquires 20% or more of our commonshares (a Flip-In Event), entitle each shareholder, other than the 20% buyer,to acquire additional common shares at one-half of the market price at the timeof exercise. The Plan must be reapproved by shareholders on or before our annualgeneral meeting in 2011 to remain effective past that date. A copy of the Planis available on our website at www.nexeninc.com.

 

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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)**                  | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| ** **                                                             |       |     |       |     |       |     |       |     |       |     |       |
| **Oil &  Gas Production**                                     |       |     |       |     |       |     |       |     |       |     |       |
| Production before Royalties (mboe/d)1                                  |       | 243      |       | 250      |       | 254      |       | 212      |       | 242      |       |
| Production after Royalties (mboe/d)1                                   |       | 213      |       | 210      |       | 207      |       | 156      |       | 173      |       |
| ** **                                                             |       |     |       |     |       |     |       |     |       |     |       |
| **Results of  Operations**                                             |       |     |       |     |       |     |       |     |       |     |       |
| Revenue                                                                |       |     |       |     |       |     |       |     |       |     |       |
| Oil & Gas2                                                    |       | 4,447    |       | 6,907    |       | 5,174    |       | 3,656    |       | 3,535    |       |
| Marketing                                                              |       | 967      |       | 522      |       | 926      |       | 1,373    |       | 864      |       |
| Chemicals                                                              |       | 508      |       | 427      |       | 447      |       | 413      |       | 413      |       |
| Other                                                                  |       | (130     | )          | 364      |       | (26      | )          | (47      | )          | (193     | )          |
| Total Revenue                                                          |       | 5,792    |       | 8,220    |       | 6,521    |       | 5,395    |       | 4,619    |       |
|                                                                   |       |     |       |     |       |     |       |     |       |     |       |
| Net Income from Continuing Operations                                  |       | 507      |       | 1,704    |       | 1,012    |       | 579      |       | 658      |       |
| Basic Earnings per Common Share from Continuing Operations ($/share)   |       | 0.97     |       | 3.24     |       | 1.92     |       | 1.10     |       | 1.26     |       |
| Diluted Earnings per Common Share from Continuing Operations ($/share) |       | 0.97     |       | 3.20     |       | 1.88     |       | 1.08     |       | 1.23     |       |
| Net Income                                                             |       | 507      |       | 1,704    |       | 1,012    |       | 579      |       | 1,110    |       |
| Basic Earnings per Common Share ($/share)                              |       | 0.97     |       | 3.24     |       | 1.92     |       | 1.10     |       | 2.13     |       |
| Diluted Earnings per Common Share ($/share)                            |       | 0.97     |       | 3.20     |       | 1.88     |       | 1.08     |       | 2.08     |       |
| ** **                                                             |       |     |       |     |       |     |       |     |       |     |       |
| **Financial  Position**                                                |       |     |       |     |       |     |       |     |       |     |       |
| Total Assets                                                           |       | 22,781   |       | 22,048   |       | 17,982   |       | 17,079   |       | 14,493   |       |
| Long-Term Debt3                                                        |       | 7,251    |       | 6,578    |       | 4,610    |       | 4,618    |       | 3,630    |       |
| Equity                                                                 |       | 7,420    |       | 6,998    |       | 5,449    |       | 4,614    |       | 3,961    |       |
| Capital Investment, including Acquisitions                             |       | 3,497    |       | 3,066    |       | 3,401    |       | 3,408    |       | 2,638    |       |
| Dividends per Common Share ($/share)4                                  |       | 0.20     |       | 0.175    |       | 0.10     |       | 0.10     |       | 0.10     |       |
| Common Shares Outstanding (thousands)5                                 |       | 522,916  |       | 519,449  |       | 528,305  |       | 525,026  |       | 522,281  |       |

 

----

*1*                 In 2005, we sold producingproperties in Canada. In early 2007, the Buzzard field came on stream andoffset declines from Masila in Yemen.

*2*                 In the third quarter of 2005,we sold Canadian conventional oil and gas properties in Saskatchewan, BritishColumbia and Alberta producing 18,300 bbls/d. The results of these operationswere shown as discontinued operations.

*3*                 Our North Sea asset acquisitioncredit facility was repaid in 2005 with proceeds from the issuance ofUS$1.04 billion in senior notes in the first quarter and from assetdispositions in the third quarter. Our long-term debt increased in 2006 as aresult 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 maturingin 10 years and US$1,250 million maturing in 30 years. In June 2009,we filed a universal base shelf prospectus in the US and Canada allowing us topotentially raise US$3.5 billion of debt, equity or other hybridsecurities, should the need arise. In July 2009, we issuedUS$1 billion of senior notes with US$300 million maturing in 10 yearsand US$700 million maturing in 30 years.

*4*                 Quarterly dividends wereincreased to 5¢ per share in the second quarter of 2008.

*5*                 During the third quarter of2008, we received approval from the TSX for a Normal Course Issuer Bid thatallowed us to repurchase up to a maximum of 52,914,046 common shares for theperiod of August 6, 2008 to August 5, 2009. In 2008, werepurchased and cancelled 12,136,900 common shares for $338 million.

 

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Table of Contents

 
| **Part II (continued)**                                                                   | ** **                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|-----------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                                                                                |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| 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 21 to  the Consolidated Financial Statements. The date of this discussion is  February 17, 2010. Unless otherwise noted, tabular amounts are in millions of  Canadian dollars. 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. |
|                                                                                                |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|                                                                                                     |
|                                                                                                | *1*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         | *Investors  should read the Special Note Regarding Forward-Looking Statements on page 96.* |
|                                                                                                | *2*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         | *Canadian  investors should read the Special Note to Canadian Investors on page 97 which  highlights differences between our reserve estimates and related disclosures  that are otherwise required by Canadian regulatory authorities.* |
|                                                                                                |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |   |   |
|                                                                                                | Executive Summary                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           | 51 |
|                                                                                                | Capital Investment                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          | 53 |
|                                                                                                | Financial Results                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |   |
|                                                                                                | Year-to-Year  Change in Net Income                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          | 58 |
|                                                                                                | Oil &  Gas                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |   |
|                                                                                                | Production                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | 59 |
|                                                                                                | Commodity  Prices                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           | 62 |
|                                                                                                | Operating  Expenses                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         | 65 |
|                                                                                                | Depreciation, Depletion, Amortization and Impairment  (DD&A)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            | 67 |
|                                                                                                | Exploration  Expense                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        | 69 |
|                                                                                                | Oil &  Gas Netbacks                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                | 70 |
|                                                                                                | Energy  Marketing                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           | 72 |
|                                                                                                | Chemicals                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   | 75 |
|                                                                                                | Corporate  Expenses                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         | 76 |
|                                                                                                | Outlook  for 2010                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           | 79 |
|                                                                                                | Liquidity and Capital Resources                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             | 80 |
|                                                                                                | Critical Accounting Estimates                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               | 87 |
|                                                                                                | New Accounting Pronouncements                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               | 89 |
|                                                                                                |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |   |
| Item 7A:  Quantitative and Qualitative Disclosures about Market Risk                                |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|                                                                                                | Non-Trading                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 | 92 |
|                                                                                                | Trading                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     | 94 |
|                                                                                                | Credit Risk                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 | 95 |
|                                                                                                | Special Note Regarding Forward-looking Statements                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           | 96 |
|                                                                                                | Special Note to Canadian Investors                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          | 97 |

 

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**PART II**

**ITEM 7.****Management’s Discussion and Analysis of FinancialCondition and Results of Operations**

* *

*The following should be read inconjunction with the Consolidated Financial Statements included in this report.The Consolidated Financial Statements have been prepared in accordance withgenerally accepted accounting principles (GAAP) in Canada. The impact ofsignificant differences between Canadian and United States (US) accountingprinciples on the financial statements is disclosed in Note 21 to theConsolidated Financial Statements. The date of this discussion is February 17,2010. Unless otherwise noted, tabular amounts are in millions of Canadiandollars. Oil and gas volumes, reserves and related performance measures arepresented on a working interest before royalties basis. We measure ourperformance in this manner consistent with other Canadian oil and gascompanies. Where appropriate, we have provided information on an after royaltybasis in tabular format.*

* *

*Investors should read the Special NoteRegarding Forward-Looking Statements on page 96. Canadian investors shouldread the Special Note to Canadian Investors on page 97 which highlightsdifferences between our reserve estimates and related disclosures that areotherwise required by Canadian regulatory authorities.*

 

**EXECUTIVESUMMARY**

 

**2009 Results**

 
| **(Cdn$ millions, except as  stated)** | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Production before Royalties (mboe/d)1       |       | 243      |       | 250      |       | 254      |       |
| Production after Royalties (mboe/d)         |       | 213      |       | 210      |       | 207      |       |
| Cash Flow from Operating Activities         |       | 1,886    |       | 4,354    |       | 2,830    |       |
| Net Income                                  |       | 536      |       | 1,715    |       | 1,086    |       |
| Earnings per Common Share, Basic ($/share)  |       | 1.03     |       | 3.26     |       | 2.06     |       |
| Net Debt2                                   |       | 5,551    |       | 4,575    |       | 4,404    |       |

 

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*1*      Production before royaltiesreflects our working interest before royalties. We have presented our workinginterest before royalties as we measure our performance on this basisconsistent with other Canadian oil and gas companies.

*2*      Long-term debt and short-termborrowings less cash and cash equivalents.

 

In 2009, we generated cash flow from operating activities of$1.9 billion and net income of $536 million. The decline from the prior yearwas primarily due to lower commodity prices as WTI averaged US$61.80/bbl forthe year, down 38% from 2008. WTI started the year at approximately US$46/bblbefore recovering to almost US$80/bbl by the end of 2009. Dated Brent decreased37% to average US$61.51/bbl over the same period. The impact of lower commodityprices was partially offset by changes in the US/Canadian foreign exchangerate, which averaged 88 cents in 2009 as compared to 94 cents last year.

 

Production before royalties averaged 243,000 boe/d in 2009,3% below last year’s volumes. At Buzzard, planned downtime reduced ourproduction, while in Yemen our fields continued to mature. These decreases werepartially offset by the start-up of the Ettrick field in the UK North Sea, theLonghorn field in the US Gulf of Mexico and higher bitumen production at LongLake. Our production after royalties increased slightly over last year as aresult of lower royalty rates on our Canadian gas production and higher LongLake bitumen volumes. Production after royalties increased slightly to average 213,000boe/d, as higher margin barrels displaced higher royalty barrels. Our productionin the fourth quarter averaged 265,000 boe/d, 24% higher than the third quarteras Buzzard returned to full rates during the quarter and we brought Longhornand Ettrick on stream. In 2010, we expect production to range between 230,000and 280,000 boe/d before royalties. Over the last three years, our productionafter royalties has grown at an average compounded rate of 11%.

 

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Despite lower commodity prices, our cash netbacks remainstrong. Much of our production has low operating costs and royalties, resultingin annual cash netbacks of $38.55/boe (before royalties).

 

Our net debt increased by $976 million as capitalinvestments, including costs to acquire an additional 15% working interest inLong Lake early in the year, exceeded our cash flow from operating activitiesby $1.6 billion. This increase was partially offset by the weaker US dollar,which reduced our US-dollar denominated debt and cash by approximately $900million.

 

Our financial position is strong. For the past several years,we invested significant capital in a number of major development projects suchas Buzzard and Long Lake. With the investment in these projects behind us andproduction ramping up at Ettrick, Longhorn and Long Lake, we expect to fund ournext generation of new growth projects from operating cash flows. Theseprojects include Golden Eagle in the UK North Sea, Usan offshore West Africa,future phases of Long Lake and shale gas in the Horn River Basin in northeastBritish Columbia, as well as several exploration prospects.

 

Our available liquidity is currently $3.3 billion, comprisedof cash and undrawn committed credit facilities, most of which are availableuntil 2012. In response to improving credit markets, we issued US$1 billion ofsenior notes during the year, which were used to repay a portion of ouroutstanding term credit facilities as well as for general corporate purposes.Issuing this debt increased the average term-to-maturity of our debt to 17years.

 

**Strategy Progress**

 
| **(Cdn$ millions)**                              | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Capital Investment, including Acquisitions            |       | 3,497    |       | 3,066    |       | 3,401    |       |
| Proved Oil and Gas Reserves before Royalties (mmboe)1 |       | 1,011    |       | 988      |       | 1,058    |       |
| Proved Oil and Gas Reserves after Royalties (mmboe)1  |       | 920      |       | 926      |       | 917      |       |

 

----

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

 

Our strategy is to builda sustainable energy company focused in three growth areas: oil sands,conventional exploration and exploitation, and unconventional gas. Ourinvestment in these areas generated the following results in 2009:

 

·      oil sands—we acquired anadditional 15% interest in the Long Lake project and joint venture lands fromOPTI, increasing our ownership level to 65%. Following this acquisition, we arenow responsible for operating both the SAGD bitumen extraction process and theupgrader for Phase 1, as well as future phases. During the year, we confirmedthat our Long Lake design gasifies the bottom of the bitumen barrel and that wecan upgrade bitumen to premium synthetic oil. Bitumen production ramped up aswe increased our steam availability;

·      conventional exploration and development—ourconventional exploration program was focused in the UK and Norwegian North Sea,deep-water Gulf of Mexico and offshore West Africa. We were successful bybringing Ettrick and Longhorn on stream during the year, and from advancing thedevelopments of Usan and the Buzzard H2Sprocessing facilities. We had exploration success during the year at GoldenEagle and Owowo; and

·      unconventional gas—we have asignificant land position in the Horn River Basin in northeast BritishColumbia. Our 2009 drilling and completion program realized substantial costsavings, productivity improvements and demonstrated that we could successfullyfrac the shale to allow the gas to flow. We now have five shale gas wellson-stream and achieved peak rates of over 15 mmcf/d during the year.

 

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During 2009, our proved oil and gas reserves additions replaced205% of our oil and gas production (198% after royalties) before the year-endtransition to new SEC reserves rules. Excluding economic revisions, we replaced187% of our oil and gas production (202% after royalties). The difference ineconomic revisions between before and after royalties reflects an increase inoil sands royalties related to higher oil prices.

 
| ** **                                       | ** ** | **Oil and Gas**       | ** ** |
|--------------------------------------------------|------------|-----------------------|------------|
| **(mmboe)**                                      | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** |
| **Production**                                   |       | 90                    |       | 78 |   |
| ** **                                       |       |                  |       |   |   |
| **Proved  Reserve Changes excluding Production** |       |                  |       |   |   |
| Net Additions                                    |       | 168                   |       | 157 |   |
| Economic Revisions                               |       | 16                    |       | (2 | ) |
|                                             |       | 184                   |       | 155 |   |

 

The majority of our additions before economic revisionsrelate to our Long Lake acquisition, successful exploitation of our North Seafields at Buzzard and Telford, and elsewhere at Long Lake, offshore WestAfrica, Syncrude and Masila. Economic revisions are largely related to positiverevisions from oil price increases, somewhat offset by negative revisions fromdecreases in gas prices.

 

**Outlook**

 

In 2010, we expect our annual production to growapproximately 4% to 6%, assuming the midpoint of our guidance, and range from230,000 to 280,000 boe/d (200,000 to 250,000 boe/d after royalties). Thisgrowth reflects a full year of production from Ettrick and Longhorn, andincreasing volumes from Long Lake. At the high end of our guidance, ourproduction growth would be as high as 15%. The low end includes the possibilityof advancing the start-up of the fourth platform at Buzzard which is currentlyscheduled for 2011. Advancement to 2010 would only be required if we see higherthan expected levels of hydrogen sulphide. The downtime associated withadvancing the start-up could reduce annual volumes by 10,000 to 15,000 boe/d.

 

Our capital investment plans for 2010 total $2.5 billion. Weplan to finance this investment through cash flow from operating activities andexisting cash and cash equivalents. Our capital program will advance our futuregrowth areas as we move forward with developing several major identifiedprojects including Buzzard, Usan, Golden Eagle and Horn River shale gas. Wealso plan to spend approximately $575 million drilling 14 wells to advance ournew growth exploration and appraisal opportunities, primarily in the North Seaand the Gulf of Mexico. We continue to monitor economic conditions andcommodity prices and are prepared to adjust our capital investment programaccordingly.

 

At December 31, 2009, we had $1.7 billion of cash onhand, and $1.6 billion of undrawn committed credit facilities. The primary debtmaturity in the next few years is our $3.2 billion term credit facility whichmatures in 2012, of which $1.6 billion was drawn at December 31, 2009 and$407 million was utilized to support outstanding letters of credit. We alsohave $492 million in undrawn uncommitted credit facilities at December 31,2009, of which $86 million was utilized to support outstanding letters ofcredit. The average term-to-maturity of our debt is approximately 17 years.

 

**CAPITALINVESTMENT**

 
| **(Cdn$ millions)**                         | ** ** | **Estimated 2010** | ** ** | **2009**  | ** ** | **2008**  | ** ** |
|--------------------------------------------------|------------|--------------------|------------|-----------|------------|-----------|------------|
| Major Development                                |       | 700                |       | 726       |       | 1,437     |       |
| Early Stage Development                          |       | 300                |       | 100       |       | 167       |       |
| New Growth Exploration                           |       | 575                |       | 582       |       | 582       |       |
| Core Asset Development                           |       | 825                |       | 1,814     |       | 731       |       |
| Total Oil & Gas1                        |       | 2,400              |       | 3,222     |       | 2,917     |       |
| Energy Marketing, Corporate, Chemicals and Other |       | 100                |       | 275       |       | 149       |       |
| **Total Capital**                                | ** ** | **2,500**          | ** ** | **3,497** | ** ** | **3,066** | ** ** |

 

----

*1*      Includes capital related tocapitalized interest and the Long Lake upgrader, but excludes cash flowsrelated to geological and geophysical expenditures.

 

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

 

·      core assets for short-termproduction and free cash flow to fund capital programs and repay debt;

·      development projects thatconvert our discoveries into new production and cash flow in the medium term;and

·      exploration and new growthprojects for longer-term growth.

 

As conventional basins in North America mature, we have beentransitioning toward less mature basins and unconventional resource plays. Keyfocus areas include Athabasca oil sands, Canadian unconventional gas plays, theNorth Sea, deep-water Gulf of Mexico, and offshore West Africa—areas we believehave attractive fiscal terms, significant remaining opportunity, and where wehave a competitive advantage.

 

**2009 Capital****1**

 
| **(Cdn$ millions)**              | ** ** | **Major  Development** | ** ** | **Early Stage  Development** | ** ** | **New Growth  Exploration** | ** ** | **Core Asset  Development** | ** ** | **Total**  | ** ** |
|---------------------------------------|------------|------------------------|------------|-----------------------------------|------------|----------------------------------|------------|----------------------------------|------------|------------|------------|
| Oil and Gas                           |       |                   |       |                              |       |                             |       |                             |       |       |       |
| United Kingdom                        |       | 128                    |       | —                            |       | 143                              |       | 355                              |       | 626        |       |
| Canada                                |       | —                 |       | —                            |       | 214                              | 2          | 81                               |       | 295        |       |
| Synthetic                             |       | —                 |       | 100                               |       | 1                                |       | 1,202                            | 3          | 1,303      |       |
| Syncrude                              |       | —                 |       | —                            |       | —                           |       | 87                               |       | 87         |       |
| United States                         |       | 112                    |       | —                            |       | 157                              |       | 16                               |       | 285        |       |
| Yemen                                 |       | —                 |       | —                            |       | —                           |       | 69                               |       | 69         |       |
| Nigeria                               |       | 486                    |       | —                            |       | 20                               |       | —                           |       | 506        |       |
| Other Countries                       |       | —                 |       | —                            |       | 47                               |       | 4                                |       | 51         |       |
| ** **                            | ** ** | **726**                | ** ** | **100**                           | ** ** | **582**                          | ** ** | **1,814**                        | ** ** | **3,222**  | ** ** |
| Chemicals                             |       | 144                    |       | —                            |       | —                           |       | 70                               |       | 214        |       |
| Energy Marketing, Corporate and Other |       | —                 |       | —                            |       | —                           |       | 61                               |       | 61         |       |
| **Total Capital**                     | ** ** | **870**                | ** ** | **100**                           | ** ** | **582**                          | ** ** | **1,945**                        | ** ** | **3,497**  | ** ** |
| ** **                            | ** ** | ** **             | ** ** | ** **                        | ** ** | ** **                       | ** ** | ** **                       | ** ** | ** ** | ** ** |
| As a % of Total Capital               |       | 25                     | %          | 3                                 | %          | 16                               | %          | 56                               | %          | 100        | %          |

 

----

*1*      Excludes geological andgeophysical expenditures of $81 million.

*2*      Includes shale gas in northeastBritish Columbia.

*3*      Includes $755 million toacquire an additional 15% working interest at Long Lake.

 

We invested $2.8 billion on oil and gas activities and added184 mmboe of proved reserves and 349 mmboe of probable reserves (beforeroyalties), before the year-end transition to new SEC reserve rules. We are notcarrying any proved or probable reserves for our discoveries in the EasternGulf of Mexico, at Knotty Head or for our shale gas lands. A summary of our2009 capital investment program and reserve additions are shown in the tablebelow. In this section, production and reserves are before royalties.Additional information on our oil and gas reserves can be found in Items 1 and2 *Business and Properties* (pages 23to 31) and in Item 8 *Consolidated *FinancialStatements and Supplementary Data** (pages 150to 158).

 
| ** **                              | ** ** | **Capital  Investment****1****(Cdn$ millions)** | ** ** | **Production****2****(mmboe)** | ** ** | **Proved  Reserve  Additions****2****(mmboe)** | ** ** | **Probable  Reserve  Additions****2****(mmboe)** | ** ** |
|-----------------------------------------|------------|------------------------------------------------------|------------|--------------------------------|------------|------------------------------------------------|------------|--------------------------------------------------|------------|
| Conventional Exploration and Production |       | 1,649                                                |       | 80                             |       | 70                                             |       | 13                                               |       |
| Unconventional—Oil Sands           |       | 942                                                  |       | 10                             |       | 114                                            |       | 336                                              |       |
| Unconventional—Shale Gas           |       | 216                                                  |       | —                         |       | —                                         |       | —                                           |       |
| **Total Oil and  Gas**                  | ** ** | **2,807**                                            | ** ** | **90**                         | ** ** | **184**                                        | ** ** | **349**                                          | ** ** |

 

----

*1*      Oil and gas capital investmentexcludes amounts related to capitalized interest, Long Lake upgrader,marketing, corporate, chemicals and other.

*2*      Before royalties and theadoption of the new SEC rules.

 

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**2010 Estimated Capital**

 
| **(Cdn$ millions)**              | ** ** | **Major  Development** | ** ** | **Early Stage  Development** | ** ** | **New Growth  Exploration** | ** ** | **Core Asset  Development** | ** ** | **Total**  | ** ** |
|---------------------------------------|------------|------------------------|------------|------------------------------|------------|-----------------------------|------------|-----------------------------|------------|------------|------------|
| Oil and Gas                           |       |                   |       |                         |       |                        |       |                        |       |       |       |
| United Kingdom                        |       | 75                     |       | —                       |       | 250                         |       | 425                         |       | 750        |       |
| Canada                                |       | —                 |       | 200                          |       | —                      |       | 20                          |       | 220        |       |
| Synthetic                             |       | —                 |       | 100                          |       | —                      |       | 200                         |       | 300        |       |
| Syncrude                              |       | —                 |       | —                       |       | —                      |       | 100                         |       | 100        |       |
| United States                         |       | 50                     |       | —                       |       | 125                         |       | 50                          |       | 225        |       |
| Yemen                                 |       | —                 |       | —                       |       | —                      |       | 30                          |       | 30         |       |
| Nigeria                               |       | 575                    |       | —                       |       | 50                          |       | —                      |       | 625        |       |
| Other Countries                       |       | —                 |       | —                       |       | 150                         |       | —                      |       | 150        |       |
| ** **                            | ** ** | **700**                | ** ** | **300**                      | ** ** | **575**                     | ** ** | **825**                     | ** ** | **2,400**  | ** ** |
| Chemicals                             |       | 55                     |       | —                       |       | —                      |       | 10                          |       | 65         |       |
| Energy Marketing, Corporate and Other |       | —                 |       | —                       |       | —                      |       | 35                          |       | 35         |       |
| **Total Capital**                     | ** ** | **755**                | ** ** | **300**                      | ** ** | **575**                     | ** ** | **870**                     | ** ** | **2,500**  | ** ** |
| ** **                            | ** ** | ** **             | ** ** | ** **                   | ** ** | ** **                  | ** ** | ** **                  | ** ** | ** ** | ** ** |
| As a % of Total Capital               |       | 30                     | %          | 12                           | %          | 23                          | %          | 35                          | %          | 100        | %          |

 

**SYNTHETIC**

 

In 2009, we invested $755 million on the acquisition of anadditional 15% interest in the Long Lake project and joint venture lands. Thisadded 86 mmboe of proved and 220 mmboe of probable bitumen reserves (beforeroyalties). In addition, core-hole delineation activities on the first phase ofLong Lake added 21 mmboe of proved bitumen reserves (before royalties), whilelease delineation work on Phase 2 added 116 mmboe of probable bitumen reserves(before royalties).

 

With the completion of the turnaround at Long Lake, steamreliability has improved significantly and steam rates are at an all-time highof over 105,000 bbls/d and increasing. As a result, we are injecting more steaminto more wells than ever before with 57 well pairs now on production and steamcirculating in an additional 19 pairs. These circulating wells will beconverted to production over the next few months.

 

The reservoir is responding to consistent steaming andbitumen production levels are increasing. Prior to the turnaround which wascompleted late last year, we were only providing meaningful steam to about onethird of our 91 wells. These wells are providing the majority of our bitumenproduction which averaged 13,600 bbls/d (gross) in the fourth quarter. Theremaining wells have been cold for about a year and need to go through thecirculation and ramp-up cycle.

 

We are currently producing approximately 18,000 bbls/d(gross) at an all-in steam-to-oil ratio (SOR) of approximately 6.0. This SORincludes steam to the wells that are in the steam circulation stage and not yetproducing bitumen, and wells early in their ramp-up cycle. As our circulatingwells start producing, we expect to see an increase in bitumen production rateswith a corresponding decrease in SOR. The SOR of our producing wells is approximately5.0, and includes well pairs recently converted to production that are in theearly stages of ramp-up. We continue to expect a long-term SOR of 3.0 over thelife of the project.

 

 

----

*1**     **MainlyLong Lake.*

*2**     **EnergyMarketing, Corporate and Other.*

 

 

----

*1**     **MainlyLong Lake.*

*2**     **EnergyMarketing, Corporate and Other.*

 

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We have achieved a number of major milestones at Long Lakeover the past year. The facility is running as designed. The gasificationprocess is working, creating a low cost fuel source which reduces our need topurchase natural gas for operations. Post turnaround, the upgrader hasprocessed approximately 90% of bitumen feedstock into the highest qualitysynthetic crude oil in North America. We continue to expect that we will rampup to full rates and generate a significant margin advantage over our peers,even at current gas prices.

 

**UNITED KINGDOM**

 

We invested $626 million in the UK North Sea last yearincluding $143 million on exploration activities. Our exploration program inthe Golden Eagle area has generated discoveries at Golden Eagle, Pink andHobby. To date, we have booked 50 mmboe of probable reserves (before royalties)for this area. We expect to book proved reserves as we advance the fielddevelopment plan, which is progressing. We expect development will supportstandalone facilities and be economic with oil prices significantly lower thanthey are currently. We have a 34% interest in both Golden Eagle and Hobby, anda 46% interest in Pink, and operate all three.

 

At Buzzard, we invested $232 million of which $104 millionrelated to the construction of the fourth platform, with the rest relating toongoing development drilling. During the year, we added 22 mmboe of provedreserves here (before royalties). 14 mmboe are attributable to successfuldrilling and production performance which resulted in increases in bothreservoir size and recovery factor. The remaining eight mmboe relate topositive economic revisions associated with improved oil prices. In 2010,Buzzard will continue to be a significant contributor to our cash flow andproduction volumes. 

 

At Ettrick, production was brought on stream last year and isexpected to ramp up to approximately 20,000 boe/d (gross) in 2010. We also havea discovery at Blackbird which could be a future tie-back to Ettrick, and planto drill an appraisal well here later this year. We have no proved reservesbooked for Blackbird. We operate both Ettrick and Blackbird, with a 79.73%working interest in each.

 

At Scott/Telford, we added 12 mmboe of proved reserves(before royalties) largely as a result of successful development drilling atTelford which allowed us to almost double our production from the Scottplatform. We see further upside in the area with opportunities for quicktiebacks and additional drilling is planned for 2010.

 

**NIGERIA**

 

Development of the Usan field, offshore West Africa, is progressingwell with first production expected in 2012. The development includes a FPSOwith the ability to process 180,000 bbls/d (36,000 bbls/d net to us) and storeup to two million barrels of oil. In 2009, our capital investment here focusedon fabrication of the FPSO hull and topside facilities, subsea equipment,development drilling and completion of detailed engineering and procurement. In2010, we expect to complete fabrication of the FPSO hull and most of thetopsides. In addition, we will continue fabrication of subsea components,development drilling and well completion activities. We have a 20% interest inexploration and development on this block and Total Exploration &Production Nigeria Limited is the operator.

 

We continue to explore offshore West Africa and during thefourth quarter announced a successful exploration well at Owowo in the southernportion of Oil Prospecting License (OPL) 223. The Owowo South B-1 well wasdrilled in a water depth of 670 metres and is located 20 kilometres northeastof the Usan field. The well reached a total depth of 2,227 metres anddiscovered several oil bearing reservoirs containing light oil according tologs and other analysis. Under the production sharing contract governing OPL223, the Nigerian National Petroleum Corporation (NNPC) is concessionaire ofthe license, which is operated by Total Exploration & ProductionNigeria Ltd. We have an 18% interest in the discovery.

 

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**CANADA SHALE GAS**

 

As conventional basins in Canada mature, we are focusing ourinvestment on unconventional resource plays such as shale gas. In northeastBritish Columbia, we have a material shale gas position in the Horn River Basinwith a 100% working interest. This play has the potential to be one of the mostsignificant shale gas plays in North America. In 2009, we investedapproximately $214 million to drill, frac, complete and test wells, and buildinfrastructure. Substantial cost savings and productivity improvements wererealized with this drilling and completion program. We took advantage ofimproved equipment utilization, drilled longer wells, initiated more fracs perwell and maintained an industry-leading frac pace this summer of 26 fracs in 15days while achieving a 100% success rate on our frac program.

 

In 2010, we plan to build on this success by drilling aneight-well pad which will have longer horizontal wells with more fracs (18fracs per well) than our earlier programs. The wells will be drilled thiswinter and then fraced and completed with production commencing in the secondhalf of the year. We expect to achieve shale gas volumes from this program ofapproximately 50 mmcf/d in 2011. This program sets up a potential capitalinvestment plan consisting of an 18-well pad which could commence drillinglater in 2010. Further appraisal activity is required before we can establishcommerciality and book reserves.

 

**SYNCRUDE**

 

At Syncrude, we invested $87 million in 2009 and convertedseven mmboe of probable reserves to proved reserves. In 2010, a cokerturnaround is scheduled in the third quarter and we expect annual production ofbetween 19,000 and 24,000 bbls/d before royalties.

 

**UNITED STATES**

 

In the Gulf of Mexico, our capital program is focused onthe deep water and in 2009, we invested approximately $64 million on our baseshelf and deep-water producing assets.

 

We invested $91 million to complete the development ofLonghorn which includes four subsea wells tied in to the ENI-operated Corralplatform. Production is approaching peak rates in excess of 200 mmcf/d gross(50 mmcf/d net to us). In 2009, we added two mmboe of proved reserves (beforeroyalties). We have a 25% non-operated working interest in Longhorn and ENI isthe operator.

 

In the Eastern Gulf, we invested $62 million on ourexploration activities which includes the Antietam and Appomattox wells. TheAntietam well encountered thick, good quality sand, but was non-commercial.Operations at Appomattox are ongoing and we are currently drilling a sidetrackwell to further evaluate the prospect. Appomattox is located six miles west ofour Vicksburg discovery. We have a 25% interest in Vicksburg and a 20% interestin Appomattox and Shiloh, an earlier discovery. To date, we have not booked anyproved or probable reserves for these two discoveries. Shell Offshore Inc.operates all these Eastern Gulf wells.

 

Elsewhere in the deep water, we are drilling an appraisalwell at Knotty Head with our contracted Ensco 8501 rig. The well spud in December andwe expect results in the second quarter. To date, we have not booked any provedor probable reserves here. A second deep-water drilling rig is expected toarrive in mid–2010 which will allow us to start drilling more of our identifiedprospects.

 

**YEMEN**

 

Yemen is an important asset for us and continues to generatecash flow in excess of capital requirements. In 2009, we invested $69 millionand added 12 mmboe of proved reserves (before royalties). We will continue tomaximize the value of these assets over the remaining life of the contract andexpect our 2010 annual production to average between 32,000 and 37,000 boe/d,before royalties. We are currently working with the Yemen government on a possiblecontract extension.

 

**CHEMICALS**

 

We continued with the development of our technologyconversion project (TCP) at our north Vancouver chlor-alkali plant. The TCP is providingtechnology and assets that are more cost efficient and environmentally friendlythan our current infrastructure. Project benefits are expected to includeincremental annual operating cash flow of approximately $40 million as a resultof decreased production costs and increased plant capacity. The project isexpected to start up in the second quarter of 2010 and should lower our coststructure and solidify our low-cost position in this regional market.

 

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**FINANCIALRESULTS**

 

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

 
| **(Cdn$ millions)**                                   | ** ** | **2009 vs 2008** | ** ** | **2008 vs 2007** | ** ** |
|------------------------------------------------------------|------------|------------------|------------|------------------|------------|
| **Net Income  for 2008 and 2007**                          | ** ** | **1,715**        | ** ** | **1,086**        | ** ** |
| Favourable (unfavourable) variances:1                      |       |             |       |             |       |
| Production Volumes, After Royalties                        |       |             |       |             |       |
| Crude Oil                                                  |       | (137             | )          | 40               |       |
| Natural Gas                                                |       | 36               |       | (22              | )          |
| Change in Crude Oil Inventory                              |       | (80              | )          | 13               |       |
| Total Volume Variance                                      |       | (181             | )          | 31               |       |
| Realized Commodity Prices                                  |       |             |       |             |       |
| Crude Oil                                                  |       | (1,871           | )          | 1,495            |       |
| Natural Gas                                                |       | (313             | )          | 119              |       |
| Total Price Variance                                       |       | (2,184           | )          | 1,614            |       |
| Oil & Gas Operating Expense                       |       | 9                |       | (121             | )          |
| Depreciation, Depletion, Amortization and Impairment       |       |             |       |             |       |
| Oil & Gas                                         |       | 241              |       | (228             | )          |
| Other                                                      |       | (8               | )          | (19              | )          |
| Total DD&A                                             |       | 233              |       | (247             | )          |
| Exploration Expense                                        |       | 100              |       | (76              | )          |
| Energy Marketing Revenue, Net                              |       | 610              |       | (424             | )          |
| Chemicals Contribution                                     |       | 73               |       | (76              | )          |
| General and Administrative Expense                         |       | (240             | )          | 117              |       |
| Interest Expense                                           |       | (218             | )          | 74               |       |
| Current Income Taxes                                       |       | 83               |       | (425             | )          |
| Future Income Taxes                                        |       | 1,114            |       | (240             | )          |
| Other                                                      |       |             |       |             |       |
| Increase (Decrease) in Fair Value of Crude Oil Put Options |       | (454             | )          | 246              |       |
| Other                                                      |       | (124             | )          | 156              |       |
|                                                       |       |             |       |             |       |
| **Net Income  for 2009 and 2008**                          | ** ** | **536**          | ** ** | **1,715**        | ** ** |

 

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*1*      All amounts are presentedbefore provision for income taxes.

 

Significant variances in net income are explained in thesections that follow.

 

 

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**OIL &GAS**

 

**Production**

 
| ** **                   | ** ** | **2009**                   | ** ** | **2008**             | ** ** | **2007**                   | ** ** |
|------------------------------|------------|----------------------------|------------|----------------------|------------|----------------------------|------------|
| ** **                   | ** ** | **Before  Royalties****1** | ** ** | **After  Royalties** | ** ** | **Before  Royalties****1** | ** ** | **After  Royalties** | ** ** | **Before  Royalties****1** | ** ** | **After  Royalties** | ** ** |
| **Oil and Liquids**(mbbls/d) |       |                       |       |                 |       |                       |       |   |   |   |   |   |   |
| United Kingdom               |       | 98.0                       |       | 98.0                 |       | 99.7                       |       | 99.7 |   | 81.2 |   | 81.2 |   |
| Canada                       |       | 14.6                       |       | 11.4                 |       | 16.2                       |       | 12.3 |   | 17.1 |   | 13.4 |   |
| Long Lake Bitumen2           |       | 7.9                        |       | 7.9                  |       | 3.9                        |       | 3.9 |   | — |   | — |   |
| Syncrude                     |       | 20.2                       |       | 18.6                 |       | 20.9                       |       | 18.2 |   | 22.1 |   | 18.8 |   |
| United States                |       | 10.5                       |       | 9.5                  |       | 9.3                        |       | 8.1 |   | 16.4 |   | 14.5 |   |
| Yemen                        |       | 49.9                       |       | 29.8                 |       | 56.6                       |       | 30.6 |   | 71.6 |   | 39.8 |   |
| Other Countries              |       | 3.5                        |       | 3.2                  |       | 5.8                        |       | 5.3 |   | 6.2 |   | 5.7 |   |
|                         |       | 204.6                      |       | 178.4                |       | 212.4                      |       | 178.1 |   | 214.6 |   | 173.4 |   |
| ** **                   |       |                       |       |                 |       |                       |       |   |   |   |   |   |   |
| **Natural Gas**(mmcf/d)      |       |                       |       |                 |       |                       |       |   |   |   |   |   |   |
| United Kingdom               |       | 24                         |       | 24                   |       | 18                         |       | 18 |   | 16 |   | 16 |   |
| Canada                       |       | 139                        |       | 128                  |       | 131                        |       | 109 |   | 118 |   | 98 |   |
| United States                |       | 65                         |       | 57                   |       | 78                         |       | 66 |   | 101 |   | 86 |   |
|                         |       | 228                        |       | 209                  |       | 227                        |       | 193 |   | 235 |   | 200 |   |
|                         |       |                       |       |                 |       |                       |       |   |   |   |   |   |   |
| **Total**(mboe/d)            | ** ** | **243**                    | ** ** | **213**              | ** ** | **250**                    | ** ** | **210** | ** ** | **254** | ** ** | **207** | ** ** |

 

----

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

*2*      We report bitumen as productionuntil we are consistently operating the upgrader and producing premiumsynthetic crude.

 

**2009 VS 2008—LOWER VOLUMES DECREASED INCOMEBY $181 MILLION**

 

Production before royalties was down 3% from 2008. Buzzardproduction was lower due to planned downtime for pipeline maintenance and toinstall the jacket of the fourth platform, as well as downtime to reinstall theGalaxy III drilling rig on location. This was partially offset by the start-upof the Ettrick field in the UK North Sea and Longhorn in the Gulf of Mexico.Bitumen production at Long Lake continues to ramp up as we increase steam tothe field and bring on more wells. Our mature Yemen fields declined as expectedbut our after-royalty production volumes were consistent with the prior year aslower prices increased our share of net production under the cost recoveryarrangement.

 

Production after royalties increased slightlyto average 213,000 boe/d, as higher margin barrels displaced higher royaltybarrels.

 

The following table summarizes our production changes yearover year:

 
| **(mboe/d)**         | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** |
|----------------------|------------|-----------------------|------------|----------------------|------------|
| 2008 Production      |       | 250                   |       | 210                  |       |
| Production Changes   |       |                  |       |                 |       |
| United Kingdom       |       | (1                    | )          | (1                   | )          |
| Canada               |       | —                |       | 2                    |       |
| Long Lake Bitumen    |       | 4                     |       | 4                    |       |
| Syncrude             |       | (1                    | )          | 1                    |       |
| United States        |       | (1                    | )          | —               |       |
| Yemen                |       | (6                    | )          | (1                   | )          |
| Other Countries      |       | (2                    | )          | (2                   | )          |
| **2009  Production** | ** ** | **243**               | ** ** | **213**              | ** ** |

 

Fourth quarter production averaged 265,000 boe/d (235,000after royalties), 51,000 boe/d higher than the third quarter and 35,000 boe/dhigher than the fourth quarter of 2008. The increase reflects resuming fullproduction at Buzzard after successfully completing planned maintenance duringthe summer, ramping up of our new facilities at Ettrick and Longhorn, asuccessful step-out well at Telford, and the ramp-up of Long Lake.

 

Production volumes discussed in this section represent ourworking interest before royalties.

 

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**United Kingdom**

 

UK production for the year decreased slightly from 2008 toaverage 102,000 boe/d. Our share of Buzzard production averaged 81,400 boe/d(188,000 boe/d gross), down 8% from the prior year due to planned maintenancedowntime midway through the year. In the second quarter, Buzzard production wasshut-in for a week while the Galaxy III drilling rig was reinstalled on theplatform. There were also four weeks of planned downtime in the third quarter,coinciding with a six week slowdown of the Forties pipeline for routinemaintenance. During this period, we successfully installed the jacket for thefourth platform and prepared the tie-ins. This platform will allow us to handlehigher levels of hydrogen sulphide and maintain peak production until at least2013. In the second quarter of 2010, we expect to install the topsidefacilities relating to the fourth platform onto the jacket. Based on ourproduction experience to date, we anticipate that start up of the platform willnot be required until 2011. If advanced to 2010, downtime associated with thestart-up could reduce annual volumes in 2010 by 10,000 to 15,000 boe/d.

 

 

 

At Scott/Telford, we averaged 13,500 boe/d, 29% higher than2008 as a result of a successful step-out development well at Telford. Thiswell was completed in the third quarter and is tied back to our Scott platform.Production from our non-operated fields at Duart and Farragon averaged 2,700boe/d in 2009.

 

Production from the Ettrick field commenced in the thirdquarter, contributing 4,300 boe/d to our annual average volumes. Wesuccessfully produced at rates that allowed us to test the design capacity ofthe floating production, storage and offloading vessel (FPSO). Ettrick continuesto ramp up as we complete safe commissioning of all systems. Our share ofproduction averaged 11,400 boe/d in the fourth quarter. We have a nearbydiscovery at Blackbird which could be a future tie-back to Ettrick, furtherenhancing the economics of this development.

 

In 2010, we expect to drill an additional development well atTelford which should add production volumes in the field. Additionaldevelopment drilling is also planned at Ettrick, along with appraisal drillingat Blackbird. We expect production from the North Sea to average between100,000 and 130,000 boe/d in 2010, taking into account expected downtime.Increases are expected to come from higher rates at Buzzard, ramp-up of Ettrickand additional successful development drilling at Telford.

 

On February 16th, we identified an item requiring repairto the separator unit on the Buzzard platform, which temporarily reducedproduction volumes to 30,000 to 50,000 boe/d (gross). Subsequently, productionwas restored to full rates of between 200,000 and 220,000 boe/d (86,000 and95,000 boe/d, net to us).

 

**Canada**

 

Production in Canada (excluding oil sands) remainedconsistent with the prior year. Slightly lower conventional production from ourheavy oil properties was offset somewhat by higher coalbed methane (CBM)production rates. CBM production increased 20% from 2008 and averaged 51mmcf/d. Natural declines on our heavy oil properties resulted in productiondecreasing 11% in 2009. Our natural gas production in the Medicine Hat regionand Balzac was comparable with the previous year. In 2010, we expect our shareof production from Canada to average between 28,000 and 34,000 boe/d. Werecently identified a number of non-core assets for possible disposal,including our heavy oil assets in Western Canada. Production from our heavy oilproperties averaged 16,800 boe/d in 2009.

 

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**Long Lake**

 

Bitumen production at Long Lake doubled from the prior yearand averaged 7,900 boe/d (net to us) during 2009. The higher productionrepresents the continued ramp-up of production in response to increased steamvolumes and more well pairs on production. During the year, the facility soldapproximately 2,400 boe/d (net to us) of bitumen and 3,200 boe/d (net to us) ofPSCTM.

 

Our capital investment program in 2010 includes convertingmore existing wells from gas lift to electrical submersible pumping anddrilling two sustaining well pads in accordance with our full field resourcedevelopment plan. These pads are expected to be available to come on streamstarting in late 2011. In 2010, annual bitumen production at Long Lake isexpected to average between 20,000 and 30,000 boe/d (net to us).

 

**Syncrude**

 

Syncrude production decreased 3% to average 20,200 boe/dduring the year. Production in 2009 has been impacted by several factorsincluding: i) a scheduled turnaround on Coker 8-3; ii) maintenance work onCoker 8-1; iii) fewer shipments of synthetic crude as a result of outages onthe Pembina pipeline; and iv) unscheduled maintenance on both the vacuumdistillation unit and the diluent recovery unit. In 2010, we expect to have onecoker turnaround for routine maintenance and our share of production is expectedto average between 19,000 and 24,000 boe/d.

 

**United States**

 

Gulf of Mexico production volumes were 21,300 boe/d, 4% lowerthan 2008 due to declines in our mature shelf production. In the deep-water,production remained consistent with the prior year. Production was higher atAspen this year as production was shut-in during the fourth quarter of 2008 dueto Hurricane Ike. When Aspen was brought back on stream, production rates werehigher as a result of installing additional water-handling facilities on thethird-party platform. Our non-operated Longhorn development commencedproduction late in 2009 and is approaching peak production of approximately 200mmcf/d gross (50 mmcf/d, net to us). Current production is 37,000 boe/d gross(9,300 boe/d, net to us). Higher production volumes at Aspen and Longhorn wereoffset by Green Canyon 6, 50 and 137, which remain shut-in following HurricaneIke. The third-party processing platform was destroyed during the hurricanelast year and we are currently reviewing options to maximize the value of thesefields.

 

Our shelf production decreased 1,200 boe/d, 12% below 2008rates as a result of natural declines. During the year, we completed severalsuccessful recompletions and workovers to enhance performance, however, we areminimizing the capital invested in our mature shelf assets.

 

In 2010, we expect our share of production from the Gulf ofMexico to average between 20,000 and 28,000 boe/d.

 

**Yemen**

 

In 2009, production from our Masila field declined 14%compared to last year and averaged 39,400 boe/d. This decline is consistentwith our expectations as the field matures. We continue to target select infilldevelopment drilling opportunities due to the maturity of the field. During theyear, we drilled 20 development wells as we concentrated our drilling programon maximizing reserve recoveries and economic returns, prior to the 2011 expiryof our contract. In 2010, we plan to drill up to 10 development wells. We areworking with the Yemen government and our partners to potentially extend ourproduction sharing agreement for an additional five years beyond 2011. There isno assurance that this extension will be received.

 

Production at our East Al Hajr field on Block 51 decreasedslightly from the prior year and averaged 10,500 boe/d for 2009. Successfulwell optimization and pressure maintenance somewhat offset natural declines.

 

Our oil and gas operations have operated as usual during therecent unrest in Yemen. Our production facilities are remote and located asignificant distance from major population centres. We remain committed tooperating in Yemen, focusing on the safety of our employees, contractors andfacilities.

 

We expect our share of Yemen production to average between32,000 and 37,000 boe/d in 2010.

 

**Other Countries**

 

Production from Guando in Colombia decreased 40% to average3,500 boe/d in 2009. The lower volumes reflect the reduced working interest inthe Guando field effective in the second quarter of 2009. Under the terms ofour license, our working interest in the Guando field decreased from 20% to 10%in May 2009 after cumulative production from the field reached 60 millionbarrels. We expect our share of production to average 2,000 boe/d in 2010.

 

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**2008 VS 2007—HIGHER NET PRODUCTION INCREASEDINCOME BY $31 MILLION**

 

Production after royalties in 2008 was slightly higher than2007. A full year of Buzzard production and increasing bitumen production atLong Lake offset declines at our maturing Yemen fields and hurricaneinterruptions in the US Gulf of Mexico. UK production was 22% higher than 2007due primarily to a full year of production from Buzzard, which averaged 88,200boe/d. This was offset somewhat by lower production at Scott/Telford resultingfrom higher than expected natural declines and increased downtime formaintenance.

 

Production in Canada (excluding oil sands) increased slightlyin 2008, primarily as a result of increasing CBM volumes, offset somewhat by adecline in heavy oil production. Bitumen production at Long Lake averaged 3,900boe/d (net to us) during 2008.

 

Our US production fell 33%, or about 11,000 boe/d from 2007,as hurricanes in the Gulf of Mexico temporarily shut-in production in theregion. Prior to Hurricanes Gustav and Ike, we were producing approximately30,000 boe/d. Production was reduced to 6,000 boe/d immediately after thehurricanes. Our properties at Gunnison, West Cameron and Eugene Island cameback on stream during the fourth quarter, while production at Aspen, Wrigleyand Green Canyon 6, 50 and 137 deep-water fields remained shut-in for theremainder of 2008. We exited 2008 producing approximately 12,000 boe/d.

 

At Syncrude, production decreased 5% from 2007 due to severalfactors including: (i) two planned coker turnarounds and othermaintenance; (ii) shut down of the sulphur plant for maintenance; (iii) reductionin shipments of synthetic crude from outages in the Pembina pipeline; and (iv) shortageof bitumen supply as a result of production challenges in the mines.

 

**CommodityPrices**

 
| ** **                                                     | ** ** | **2009**   | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|----------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| **Crude Oil**                                                  |       |       |       |       |       |       |       |
| West Texas Intermediate (WTI) (US$/bbl)                        |       | 61.80      |       | 99.65      |       | 72.31      |       |
| Dated Brent (Brent) (US$/bbl)                                  |       | 61.51      |       | 96.99      |       | 72.52      |       |
| Benchmark Differentials1 (US$/bbl)                        |       |       |       |       |       |       |       |
| Heavy Oil                                                      |       | 9.91       |       | 20.27      |       | 23.44      |       |
| Mars                                                           |       | 1.48       |       | 6.21       |       | 5.67       |       |
| Masila                                                         |       | 0.39       |       | 4.31       |       | 0.50       |       |
| Realized Prices from Producing Assets (Cdn$/bbl)               |       |       |       |       |       |       |       |
| United Kingdom                                                 |       | 67.70      |       | 96.23      |       | 76.30      |       |
| Canada                                                         |       | 53.04      |       | 74.51      |       | 44.07      |       |
| Syncrude                                                       |       | 70.96      |       | 105.47     |       | 79.76      |       |
| United States                                                  |       | 65.01      |       | 104.94     |       | 69.83      |       |
| Yemen                                                          |       | 68.49      |       | 99.87      |       | 76.29      |       |
| Other Countries                                                |       | 59.05      |       | 98.98      |       | 71.29      |       |
|                                                           |       |       |       |       |       |       |       |
| Corporate Average (Cdn$/bbl)                                   |       | 66.85      |       | 96.92      |       | 73.43      |       |
| **Natural Gas**                                                |       |       |       |       |       |       |       |
| New York Mercantile Exchange (US$/mmbtu)                       |       | 4.16       |       | 8.90       |       | 7.12       |       |
| AECO (Cdn$/mcf)                                                |       | 3.92       |       | 7.71       |       | 6.26       |       |
| Realized Prices from Producing Assets (Cdn$/mcf)               |       |       |       |       |       |       |       |
| United Kingdom                                                 |       | 3.95       |       | 6.78       |       | 4.71       |       |
| Canada                                                         |       | 3.78       |       | 7.73       |       | 6.32       |       |
| United States                                                  |       | 4.67       |       | 10.07      |       | 7.80       |       |
|                                                           |       |       |       |       |       |       |       |
| Corporate Average (Cdn$/mcf)                                   |       | 4.06       |       | 8.44       |       | 6.81       |       |
|                                                           |       |       |       |       |       |       |       |
| **Nexen’s  Average Realized Oil and Gas Price**(Cdn$/boe) | ** ** | **60.02**  | ** ** | **89.78**  | ** ** | **68.46**  | ** ** |
| ** **                                                     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Average Foreign Exchange Rate—Canadian to US Dollar       |       | 0.8757     |       | 0.9381     |       | 0.9304     |       |

 

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

 

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**2009 VS 2008—LOWER REALIZED PRICES DECREASEDNET INCOME $2,184 MILLION**

 

Crude oil prices steadily increased during 2009, afterfalling dramatically in the fourth quarter of 2008 due to the economic crisis.WTI averaged US$61.80/bbl for the year, down 38% from 2008, while Dated Brentdecreased 37% to average US$61.51/bbl over the same period. Gas prices fluctuatedduring the year with NYMEX averaging US$4.16/mmbtu and AECO averaging$3.92/mcf, decreases of 53% and 49% from 2008, respectively. The impact oflower average commodity prices was partially offset by foreign exchangesavings. Our corporate average crude oil price fell 31% to $66.85/bbl, whileour corporate average natural gas price was 52% lower, averaging $4.06/mcf.

 

In 2009, the average annual US dollar was stronger than theCanadian dollar as compared to 2008. This reduced the impact of lower benchmarkcommodity prices, increasing net sales by approximately $295 million. Thisimpact on sales increased our realized crude oil and natural gas prices byapproximately $4.45/bbl and $0.27/mcf, respectively.

 

**Crude Oil Reference Prices**

 

During 2009, WTI prices were volatile and ranged from a lowof US$32.70/bbl to a high of US$82.00/bbl, while averaging US$61.80/bbl. WTIreached its low in February, recovering to US$60/bbl by May and tradedbetween US$60/bbl and US$80/bbl for the remainder of the year. Prices at thebeginning of the year were driven by a weak global economy but increased laterin the year as world economies responded to monetary and fiscal stimuli. Themain drivers supporting crude oil prices were macro-related, including acontinuing rally in US equity markets, positive investment flows into commoditymarkets in response to the weakening US dollar and more optimistic outlooks forglobal economic recovery.

 

Near-term demand/supply fundamentals have been slow torecover, with inventory levels and spare capacity remaining high. However,increases in oil demand from China and emerging markets has taken crude oil outof the Atlantic basin and is helping to balance the market and reduce inventorylevels. Future demand growth is expected to come from these markets. A colderthan normal winter also reduced inventory levels at the end of the year, whichsupported higher oil prices.

 

Economic indicators continue to be mixed and uncertaintyremains about the sustainability of the recovery over the next few years.Coordinated monetary and fiscal policies have ended the recession in mostcountries although much of the improvement in employment and GDP is beingdriven by unsustainable levels of public spending. A lasting global economicrecovery is dependent on growth in Asia and the developing world and increasedconsumer spending in developed countries, which will be challenging due to highlevels of unemployment, lower property values and a need to reduce consumerdebt. The pace of the global recovery may be helped by China, which hassignificant cash reserves, low consumer debt and a high personal savings ratethat could be reduced. China’s growth may be slowed by government efforts toavoid creating a credit bubble.

 

Geopolitical events during the year such as concerns overIran’s nuclear enrichment program, military action in Nigeria, the ongoing warsin Iraq and Afghanistan, and requests for greater regulation of energy marketsand futures trading seemed to have little impact on price due to spare capacityand high inventory levels. However, a much tighter supply/demand environment isexpected to emerge in 2010. With minimal growth forecast in non-OPEC supply,oil demand growth is expected to reduce inventory levels and OPEC sparecapacity. This will increase price sensitivity to geopolitical events.

 

**Crude Oil Differentials**

 

In Canada, heavy crude oil differentials averaged US$9.91/bbl(16% of WTI) for the year, compared to US$20.27/bbl (20% of WTI) in 2008. Theheavy oil differential continued to be narrower than historic levels due tocuts in low/medium quality crude oil production quotas by OPEC, strong fuel oilprices and lower heavy oil supply from Mexico and Venezuela. Excess refinerycapacity increased the demand for heavy oil and also contributed to thenarrower differential.

 

The Brent/WTI differential strengthened during 2009, withBrent trading at a discount of only US$0.29/bbl compared to US$2.66/bbl in2008. The Brent/WTI differential was volatile during the year. Initially, Brentwas at a premium to WTI due to depressed WTI pricing caused by high inventorylevels at Cushing and reduced supply in the North Sea due to maintenancedowntime. However, as US inventories decreased through the year, thedifferential reverted to a discount.

 

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The US Gulf Coast Mars differential narrowed during the yearaveraging US$1.48/bbl in 2009 compared with US$6.21/bbl in 2008. This was dueto high inventory levels at Cushing as a portion of production from the Gulf ofMexico was sent overseas, rather than into an oversupplied onshore market. Thedifferential also narrowed due to OPEC cuts in medium crude.

 

The Yemen Masila differential narrowed during the yearaveraging US$0.39/bbl in 2009 compared with US$4.31/bbl in 2008. The Masilaprice strengthened relative to both WTI and Brent, reflecting strong demandfrom China and other Asian countries that are the primary buyers of MasilaCrude. High Cushing inventory levels also contributed to the narrower YemenMasila differential to WTI.

 

**Natural Gas Reference Prices**

 

Low NYMEX natural gas prices were driven by declines inindustrial and power demand and high inventory levels as natural gas producershave been slow to respond to lower prices by reducing supply. Market fears ofreaching maximum gas storage well before the withdrawal season resulted in lowprices for most of the year. Supply in North America has been impacted by the growthin unconventional gas and increased productivity through technological advancesin horizontal drilling and fracturing techniques. Cold weather in late 2009increased prices and reduced a portion of the inventory surplus. However,continuing weak gas prices are forecasted as strong supply additions areexpected from shale gas, tight gas and new LNG volumes imported from Russia andthe Middle East.

 

 

 

**2008 VS 2007—HIGHER REALIZED PRICES INCREASEDNET INCOME $1,614 MILLION**

 

In 2008, commodity prices reached record highs but declinedsignificantly in the fourth quarter. WTI averaged US$99.65/bbl for the year,38% higher than 2007, while Dated Brent increased 34% over the same period. Ouraverage realized crude oil price increased 32% from $73.43/bbl to $96.92/bbl.During the year, NYMEX gas price increased 25% and AECO increased 23%,averaging US$8.90/mmbtu and $7.71/mcf, respectively. During the same period,our corporate 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.

 

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**Operating Expenses**

 
| ** **                    | ** ** | **2009**                   | ** ** | **2008**             | ** ** | **2007**                   | ** ** |
|-------------------------------|------------|----------------------------|------------|----------------------|------------|----------------------------|------------|
| **(Cdn$/boe)**                | ** ** | **Before  Royalties****1** | ** ** | **After  Royalties** | ** ** | **Before  Royalties****1** | ** ** | **After  Royalties** | ** ** | **Before  Royalties****1** | ** ** | **After  Royalties** | ** ** |
| **Conventional  Oil and Gas** | ** ** |                       | ** ** |                 | ** ** |                       | ** ** |   | ** ** |   | ** ** |   | ** ** |
| United Kingdom                |       | 6.87                       |       | 6.87                 |       | 6.75                       |       | 6.75 |   | 6.94 |   | 6.94 |   |
| Canada                        |       | 12.76                      |       | 14.80                |       | 13.12                      |       | 16.38 |   | 12.91 |   | 15.93 |   |
| United States                 |       | 12.58                      |       | 14.10                |       | 11.57                      |       | 13.48 |   | 8.43 |   | 9.69 |   |
| Yemen                         |       | 10.69                      |       | 18.34                |       | 8.51                       |       | 15.88 |   | 6.56 |   | 12.00 |   |
| Other Countries               |       | 6.03                       |       | 6.53                 |       | 4.52                       |       | 4.91 |   | 3.45 |   | 3.76 |   |
| Average Conventional          |       | 9.34                       |       | 10.76                |       | 8.68                       |       | 10.40 |   | 7.89 |   | 9.75 |   |
| **Synthetic  Crude Oil**      |       |                       |       |                 |       |                       |       |   |   |   |   |   |   |
| Syncrude                      |       | 35.92                      |       | 39.09                |       | 36.53                      |       | 42.04 |   | 25.80 |   | 30.32 |   |
| **Average Oil  and Gas**      |       | 11.66                      |       | 13.33                |       | 11.04                      |       | 13.18 |   | 9.45 |   | 11.63 |   |

 

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*1      Operating expenses per boe are our total oil and gas operatingcosts divided by our working interest production before royalties. We useproduction before royalties to monitor our performance consistent with otherCanadian oil and gas companies.*

 

 

**2009 VS 2008—LOWER OPERATING EXPENSESINCREASED NET INCOME BY $9 MILLION**

 

Our average oil and gas operating cost increased $0.62/boefrom 2008 as lower costs in Canada and Syncrude were only partially offset bythe impact of a stronger US dollar in other areas. US-dollar denominatedoperating costs were higher when translated to Canadian dollars, increasing ourcorporate average by $0.63/boe for 2009.

 

Changes in our production profile during the year increasedour corporate average by $0.47/boe. Buzzard, a lower cost area, contributed asmaller percentage of our total production compared to higher cost areas suchas Scott/Telford and Ettrick.

 

In the UK North Sea, lower production rates at Buzzard weremore than offset by reduced operating costs due to higher planned downtime andlower production tariffs and logistics costs. This reduced our corporateaverage by $0.21/boe. The impact of other areas in the UK North Sea reduced ourcorporate average by $0.38/boe. At Scott/Telford, total costs decreased while productionwas higher due to additional Telford production. This was somewhat offset bythe start-up of the Ettrick field and FPSO where operating costs per barrel arehigher than our corporate average.

 

In Yemen, we continue to incur costs to maintain existingwell productivity to maximize reserve recoveries and slow the natural declineof the field. These costs, combined with production declines, increased ourcorporate average operating cost by $0.20/boe. In the US Gulf of Mexico,slightly higher operating costs combined with lower shelf production, increasedour corporate average by $0.02/boe.

 

Canada reduced our corporate average by $0.06/boe as lowerheavy oil and CBM costs were substantially offset by increased operating costsat Balzac. Our heavy oil properties experienced improved run times and lessdowntime, which reduced downhole workover costs. This, combined with lowerutility costs, reduced operating costs by 14%. CBM costs increased as webrought more wells on stream, however, the incremental production volumesreduced our average cost per barrel. This was partially offset by increased perunit cost at Balzac where the impact of declining production has only partiallybeen offset by lower operating costs.

 

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At Syncrude, operating costs decreased as lower natural gascosts were partially offset by higher maintenance costs. The lower operatingcosts reduced our corporate average by $0.05/boe. Costs at Long Lake arecapitalized as development costs until we reach commercial operations which isexpected to occur in the first quarter of 2010.

 

**2008 VS 2007—HIGHER OPERATING EXPENSESDECREASED NET INCOME BY $121 MILLION**

 

Overall, operating costs increased 14% from 2007, primarilydue to the low-cost Buzzard field being on-stream for the full year and higherexpenditures at Syncrude. Our production mix also changed from the previousyear as additional Buzzard volumes were 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, operating costs increased 19%. The increasewas attributable to a full year’s production at Buzzard, compared to 2007 whenwe were ramping up production. In addition, transportation costs increased fromhigher volumes and increased tariff charges. Elsewhere in the UK North Sea,operating costs increased while production declined, increasing our corporateaverage by $0.45/boe. The majority of the cost increase was due to platformmaintenance at Scott/Telford, including: i) additional diesel costs for turbinerepairs; ii) maintenance on our water injection and power generationfacilities; and iii) subsea maintenance.

 

In Yemen, Masila and Block 51 increased our corporate averageby $0.32/boe and $0.21/boe, respectively, as a result of lower productionrates. Our operating costs were focused on service rig activity and maintenanceprograms for existing wells. In the US Gulf of Mexico, operating costs were 8%lower than 2007; however, lower production as a result of the hurricanesincreased the average unit cost by $0.30/boe.

 

Operating costs in Canada were marginally higher than in2007. Costs in our heavy oil operations increased as a result of highersalaries, utilities and trucking costs. While CBM costs were slightly higher asthe number of producing wells increased, the incremental volumes reduced ouraverage cost per barrel. At our natural gas properties, a combination ofincreased downhole activity and surface maintenance resulted in higheroperating costs. These increases were offset by lower costs at our Balzac gasplant, which had a turnaround in the previous year.

 

Syncrude operating costs were $72 million or 35% higher than2007 and increased our corporate average by $0.91/ boe. A number offactors contributed to the higher operating costs including: i) highercontracting costs to increase the mineable ore inventory for bitumen supply;ii) purchasing additional third-party bitumen to upgrade; iii) higher naturalgas prices in the first half of 2008; and iv) unscheduled and extendedmaintenance.

 

US-dollar denominated operating costs were lower whentranslated to Canadian dollars as a result of the weaker US dollar for themajority of 2008. This decreased our corporate average by $0.23/boe.

 

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

 
| ** **                         | ** ** | **2009**                   | ** ** | **2008**              | ** ** | **2007**                   | ** ** |
|------------------------------------|------------|----------------------------|------------|-----------------------|------------|----------------------------|------------|
| **(Cdn$/boe)**                     | ** ** | **Before  Royalties****1** | ** ** | **After   Royalties** | ** ** | **Before  Royalties****1** | ** ** | **After   Royalties** | ** ** | **Before  Royalties****1** | ** ** | **After  Royalties** | ** ** |
| **Conventional  Oil and Gas****2** | ** ** |                       | ** ** |                  | ** ** |                       | ** ** |   | ** ** |   | ** ** |   | ** ** |
| United Kingdom                     |       | 22.42                      |       | 22.42                 |       | 17.72                      |       | 17.72 |   | 19.59 |   | 19.59 |   |
| Canada                             |       | 18.12                      |       | 21.03                 |       | 14.99                      |       | 18.71 |   | 12.46 |   | 15.37 |   |
| United States                      |       | 37.64                      |       | 42.18                 |       | 27.46                      |       | 31.97 |   | 22.64 |   | 26.03 |   |
| Yemen                              |       | 5.75                       |       | 9.87                  |       | 7.75                       |       | 14.45 |   | 8.15 |   | 14.92 |   |
| Other Countries                    |       | 11.16                      |       | 12.08                 |       | 7.90                       |       | 8.58 |   | 3.68 |   | 4.06 |   |
| Average Conventional               |       | 19.16                      |       | 22.09                 |       | 15.48                      |       | 18.54 |   | 14.94 |   | 18.47 |   |
| **Synthetic  Crude Oil**           |       |                       |       |                  |       |                       |       |   |   |   |   |   |   |
| Syncrude                           |       | 8.46                       |       | 9.20                  |       | 6.39                       |       | 7.35 |   | 6.59 |   | 7.74 |   |
| **Average Oil  and Gas**           |       | 18.23                      |       | 20.90                 |       | 14.71                      |       | 17.56 |   | 14.21 |   | 17.49 |   |

 

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*1*                 DD&A per boe is ourDD&A for oil and gas operations divided by our working interest productionbefore royalties. We use production before royalties to monitor our performanceconsistent with other Canadian oil and gas companies.

*2*                 DD&A per boe excludesthe impairment charges described in Note 4 of our Consolidated FinancialStatements.

 

 

**2009 VS 2008—LOWER OIL AND GAS DD&AINCREASED NET INCOME BY $241 MILLION**

 

Our corporate average DD&A cost per barrel increased$3.52/boe from 2008. The stronger US dollar increased our corporate average by$1.41/boe as depletion of our international and US assets is denominated in USdollars, while changes in our production profile also increased our corporateaverage by $0.63/boe. The change in our production mix was primarily a resultof: i) slightly lower Buzzard production, where our DD&A rate is low; andii) higher production volumes at Scott/Telford and Ettrick where we have higherthan average DD&A rates. We incurred non-cash impairment charges of $78million in the fourth quarter at three natural gas properties in Canada and theUS. Our year-end natural gas proved reserves at these properties were lower asa result of weak natural gas prices.

 

In the UK North Sea, our Buzzard depletion rate decreasedfrom the same period last year as successful development drilling increased ourproved reserve estimates at the end of 2008. This lower depletion rate reducedour total corporate average by $0.16/boe. Elsewhere in the UK, higher depletionrates at Ettrick and Scott/Telford increased our corporate average by$0.97/boe. The Ettrick depletion rate is higher than our average as a result ofhigher development costs. The Scott/Telford fields’ depletion rate increasedcompared to 2008 as a result of downward price-related reserve revisions at theend of 2008. Our DD&A expense also includes $49 million for our Perthprospect in the North Sea where we expensed allocated acquisition costs as weare unlikely to proceed with development of this prospect.

 

Lower depletion rates in Yemen, due to lower capitalexpenditures from drilling fewer development wells and higher reserveestimates, reduced our corporate average by $0.61/boe. In the Gulf of Mexico,higher estimates for future abandonment costs and downward price-relatedreserve revisions at the end of 2008 resulted in higher depletion rates,increasing our corporate average rate by $0.61/boe.

 

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Canadian depletion increased our corporate average by$0.49/boe. Depletion rates at our heavy oil properties increased due todownward price-related revisions to our proved reserves at the end of 2008.This was partially offset by lower depletion rates at our CBM properties whereadditional proved reserves were recognized through improved recovery rates.

 

Syncrude incurred an additional depletion expense of $14million in the fourth quarter related to the replacement of an asset that waspreviously damaged at the upgrading facilities. This increased Syncrude’sDD&A rate by $1.95/boe for the year and increased our corporate average by$0.18/boe. Excluding the impact of the additional depletion expense, SyncrudeDD&A rate was consistent with prior year.

 

**2008 VS 2007—HIGHER OIL AND GAS DD&ADECREASED NET INCOME BY $228 MILLION**

 

During the fourth quarter of 2008, we recorded non-cashimpairment charges of $568 million primarily related to properties in the UKNorth Sea and the Gulf of Mexico. In the North Sea, we recognized an impairmentcharge of $318 million relating to our Selkirk and Ettrick properties. AtSelkirk, we expensed $62 million of allocated acquisition costs as we had nofirm development plans. At Ettrick, the impairment charge largely reflectedhigher costs and lower reserve estimates. In the Gulf of Mexico, our impairmentcharge related to four shelf properties ($143 million) and our Green Canyon 6deep-water property ($107 million). The shelf properties that wereimpaired were late-life, mature assets that were sensitive to near-termcommodity prices. At Green Canyon 6, the impairment expense reflected highercosts after Hurricane Ike destroyed a third-party production platform in the thirdquarter of 2008. This resulted in unexpected costs to construct new productionfacilities.

 

In the UK, our DD&A expense increased 14% over 2007 as aresult of additional production from Buzzard. The impact of higher productionwas offset by a lower DD&A rate at Buzzard with the addition of newreserves at the beginning of 2008. The lower depletion rate at Buzzarddecreased our corporate average rate by $0.74/boe. Elsewhere in the UK, ourdepletion rate increased at our mature Scott/Telford and smaller Farragonfields, increasing our corporate average by $0.47/boe.

 

In the Gulf of Mexico, reserve revisions at the end of 2007resulted in higher depletion rates in 2008 and increased our corporate averageunit cost by $0.59/boe.

 

Depletion of our Canadian assets increased our corporateaverage rate by $0.38/boe and was primarily due to our CBM projects in centralAlberta. During 2008, we invested capital in new wells and facilities. Adifference exists between the timing of capital expenditures and the recognitionof the reserves. This delay resulted in high initial depletion rates for ourCBM projects.

 

In Colombia, our depletion rate doubled from 2007, a resultof increased capital costs and lower reserve estimates. This increased ourcorporate average rate by $0.10/boe.

 

The stronger Canadian dollar relative to the US dollardecreased our corporate average DD&A rate by $0.45/boe as our US andinternational depletion is denominated in US dollars.

 

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**ExplorationExpense**

 
| **(Cdn$ millions)**                               | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Seismic                                                |       | 81       |       | 137      |       | 123      |       |
| Unsuccessful Drilling                                  |       | 115      |       | 203      |       | 126      |       |
| Other                                                  |       | 106      |       | 62       |       | 77       |       |
| **Total  Exploration Expense**                         | ** ** | **302**  | ** ** | **402**  | ** ** | **326**  | ** ** |
|                                                   |       |     |       |     |       |     |       |
| New Growth Exploration                                 |       | 582      |       | 582      |       | 573      |       |
| Geological and Geophysical Costs                       |       | 81       |       | 137      |       | 123      |       |
| **Total  Exploration Expenditures**                    | ** ** | **663**  | ** ** | **719**  | ** ** | **696**  | ** ** |
|                                                   |       |     |       |     |       |     |       |
| Exploration Expense as a % of Exploration Expenditures |       | 46       | %          | 56       | %          | 47       | %          |

 

**2009 VS 2008—LOWER EXPLORATION EXPENSEINCREASED NET INCOME BY $100 MILLION**

 

Exploration expenditures decreased $56 million from lastyear as we focused our capital on the US Gulf of Mexico, the North Sea andshale gas in Canada. Exploration expense decreased 25% over the same period dueto more successful exploration wells in 2009 and lower seismic data acquisitioncosts.

 

In the UK, we had significant exploration success in theGolden Eagle area, which includes our 34% operated interest in Golden Eagle andHobby, and our 46% operated interest in Pink. In total, we have drilled threeexploration and eleven appraisal wells here. We are evaluating developmentoptions for the Golden Eagle area as we continue project appraisal.

 

We drilled a successful exploration well in the southernportion of Oil Prospecting License (OPL) 223, offshore West Africa. The OwowoSouth B-1 well was drilled in a water depth of 670 metres and is located 20kilometres east of the Usan field, currently under development. The wellreached a total depth of 2,227 metres and discovered several oil bearingreservoirs.

 

In the Eastern Gulf of Mexico, operations at Appomattox areongoing and we are currently drilling a sidetrack well to further evaluate theprospect. Appomattox is located six miles west of our Vicksburg discovery. Weare also currently drilling an appraisal well at Knotty Head and results areexpected in 2010. The well is being drilled by our first contracted deep-waterrig, the Ensco 8501.

 

We continue to make significant progress on our shale gasproject in the Dilly Creek area of the Horn River Basin in northeast BritishColumbia, where we have approximately 90,000 acres with a 100% workinginterest. During the year, we completed a drilling and completion program andrealized substantial cost savings and productivity improvements. We now havefive shale gas wells on-stream and achieved first month average rates of over15 mmcf/d in 2009.

 

Unsuccessful drilling expense during the year includesexpensing CBM drilling costs in Canada and unsuccessful wells in the EasternGulf of Mexico and UK North Sea. 

 

In Canada, we expensed costs of $49 million related toour CBM exploration activities in central Alberta on properties where wecurrently have no future firm development plans. In the Eastern Gulf of Mexico,the Antietam well encountered thick, good quality sand, but was non-commercialand subsequently plugged and abandoned, resulting in expensing costs of$31 million. We also chose not to proceed with the development of a smalldiscovery at Green Canyon 448 and accordingly expensed $14 million.

 

During 2009, seismic data acquisition costs were $56 millionlower than 2008 when we purchased significant seismic data associated withnewly acquired blocks in the Norwegian North Sea. Seismic data costs willfluctuate depending on the level of our evaluation activities stage.

 

**2008 VS 2007—HIGHER EXPLORATION EXPENSEREDUCED NET INCOME BY $76 MILLION**

 

Our total exploration expenditures increased $23 million from2007. In 2008, we focused our investment on exploratory drilling in the US Gulfof Mexico, UK North Sea and CBM in Canada, and on acquiring seismic data inNorway. Exploration expense increased 23% over the same period due to higherseismic data acquisitions and unsuccessful exploration wells.

 

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In the Gulf of Mexico, we drilled a successful deep-waterexploration well early in 2008 at Mississippi Canyon 72. Elsewhere in the deepwater, we drilled two unsuccessful wells. At Fredericksburg, we drilled to adepth of 24,560 feet but failed to encounter commercial hydrocarbons. This wellwas subsequently abandoned and $24 million in exploration costs were writtenoff. Our unsuccessful exploration well at Sapphire resulted in a $28 millionexpense.

 

In the UK North Sea, we had successes at Blackbird, Pink,Bugle and Rochelle. Blackbird is located 6 km south of Ettrick and productioncould be tied in to the Ettrick FPSO, following additional appraisal drillingand development evaluation. At Pink, we drilled a successful exploration welland sidetrack. Early in 2009, we completed drilling a successful appraisal wellat Rochelle where we have a 44% non-operated interest. Rochelle is locatedapproximately 20 km south of the Scott/Telford fields. During 2008, we drilled adry hole at Full Moon which cost $16 million and we expensed $32 million ofdrilling costs for our Selkirk prospect which we do not plan to develop.

 

In Canada, we expensed $67 million for unsuccessful CBMexploration in Alberta. The costs related to our CBM exploration activities incentral Alberta where we have no future development plans.

 

During 2008, seismic data acquisition costs were 11% higherthan 2007. Norway seismic acquisitions increased 47% during 2008 as we obtaineddata on newly acquired blocks in the Norwegian North Sea. In the US Gulf ofMexico, our seismic investment decreased from 2007 as we focused on analyzingseismic data acquired in previous years. Elsewhere, we acquired seismic data inthe UK North Sea, Nigeria and Colombia.

 

 

 

**OIL &GAS NETBACKS**

 

Netbacks are the cash margins, before general andadministrative expenses, we receive for every equivalent barrel sold. Ourmargins improved 26% over the last five years. Our cash netbacks are 64% ofrealized sales prices in 2009. This is caused by transitioning our productionto lower royalty jurisdictions.

 
| ** **                                | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| Realized Sales Price                      |       | 60.02    |       | 89.78    |       | 68.46    |       | 62.92    |       | 57.97    |       |
| Cash Netback                              |       | 38.55    |       | 60.64    |       | 43.22    |       | 32.75    |       | 30.57    |       |
| Cash Netback as % of Realized Sales Price |       | 64       | %          | 68       | %          | 63       | %          | 52       | %          | 53       | %          |

 

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The following table lists the sales prices, per-unit costsand netbacks for our producing assets, calculated using our working interestproduction before and after royalties.

 

**Before Royalties****1**

 
| ** **              | ** ** | **2009**  | ** ** |
|-------------------------|------------|-----------|------------|
| **($/boe)**             | ** ** | **UK**    | ** ** | **Canada** | ** ** | **Syncrude** | ** ** | **US** | ** ** | **Yemen** | ** ** | **Other** | ** ** | **Total** | ** ** |
| Sales                   |       | 65.93     |       | 34.58 |   | 70.96 |   | 46.27 |   | 68.49 |   | 59.05 |   | 60.02 |   |
| Royalties and Other     |       | —    |       | (5.75 | ) | (6.04 | ) | (4.89 | ) | (28.94 | ) | (4.52 | ) | (8.06 | ) |
| Operating Expenses      |       | (6.87     | )          | (12.76 | ) | (35.92 | ) | (12.58 | ) | (10.69 | ) | (6.03 | ) | (11.66 | ) |
| In-country Taxes2  |       | —    |       | — |   | — |   | — |   | (8.31 | ) | — |   | (1.75 | ) |
| **Cash Netback**        | ** ** | **59.06** | ** ** | **16.07** | ** ** | **29.00** | ** ** | **28.80** | ** ** | **20.55** | ** ** | **48.50** | ** ** | **38.55** | ** ** |

 
| ** **              | ** ** | **2008**  | ** ** |
|-------------------------|------------|-----------|------------|
| **($/boe)**             | ** ** | **UK**    | ** ** | **Canada** | ** ** | **Syncrude** | ** ** | **US** | ** ** | **Yemen** | ** ** | **Other** | ** ** | **Total** | ** ** |
| Sales                   |       | 94.45     |       | 58.34 |   | 105.47 |   | 79.02 |   | 99.87 |   | 98.98 |   | 89.78 |   |
| Royalties and Other     |       | —    |       | (12.25 | ) | (15.11 | ) | (11.03 | ) | (46.94 | ) | (7.88 | ) | (15.06 | ) |
| Operating Expenses      |       | (6.75     | )          | (13.12 | ) | (36.53 | ) | (11.57 | ) | (8.51 | ) | (4.52 | ) | (11.04 | ) |
| In-country Taxes2  |       | —    |       | — |   | — |   | — |   | (13.31 | ) | — |   | (3.04 | ) |
| **Cash Netback**        | ** ** | **87.70** | ** ** | **32.97** | ** ** | **53.83** | ** ** | **56.42** | ** ** | **31.11** | ** ** | **86.58** | ** ** | **60.64** | ** ** |

 
| ** **              | ** ** | **2007**  | ** ** |
|-------------------------|------------|-----------|------------|
| **($/boe)**             | ** ** | **UK**    | ** ** | **Canada** | ** ** | **Syncrude** | ** ** | **US** | ** ** | **Yemen** | ** ** | **Other** | ** ** | **Total** | ** ** |
| Sales                   |       | 74.79     |       | 40.79 |   | 79.76 |   | 58.16 |   | 76.29 |   | 71.29 |   | 68.46 |   |
| Royalties and Other     |       | —    |       | (7.81 | ) | (12.02 | ) | (7.45 | ) | (34.69 | ) | (5.90 | ) | (13.10 | ) |
| Operating Expenses      |       | (6.94     | )          | (12.91 | ) | (25.80 | ) | (8.43 | ) | (6.56 | ) | (3.45 | ) | (9.45 | ) |
| In-country Taxes2  |       | —    |       | — |   | — |   | — |   | (9.52 | ) | — |   | (2.69 | ) |
| **Cash Netback**        | ** ** | **67.85** | ** ** | **20.07** | ** ** | **41.94** | ** ** | **42.28** | ** ** | **25.52** | ** ** | **61.94** | ** ** | **43.22** | ** ** |

 

**After Royalties****1**

 
| ** **              | ** ** | **2009**      | ** ** |
|-------------------------|------------|---------------|------------|
| **($/boe)**             | ** ** | **UK**        | ** ** | **Canada** | ** ** | **Syncrude** | ** ** | **US** | ** ** | **Yemen** | ** ** | **Other** | ** ** | **Total** | ** ** |
| Sales                   |       | 65.93         |       | 34.58 |   | 70.96 |   | 46.27 |   | 68.49 |   | 59.05 |   | 60.02 |   |
| Operating Expenses      |       | (6.87         | )          | (14.80 | ) | (39.09 | ) | (14.10 | ) | (18.34 | ) | (6.53 | ) | (13.33 | ) |
| In-country Taxes2  |       | —        |       | — |   | — |   | — |   | (14.26 | ) | — |   | (2.00 | ) |
| **Cash Netback******    | ** ** | **59.06****** | ** ** | **19.78****** | ** ** | **31.87****** | ** ** | **32.17****** | ** ** | **35.89****** | ** ** | **52.52****** | ** ** | **44.69** | ** ** |

 
| ** **              | ** ** | **2008**      | ** ** |
|-------------------------|------------|---------------|------------|
| **($/boe)**             | ** ** | **UK**        | ** ** | **Canada** | ** ** | **Syncrude** | ** ** | **US** | ** ** | **Yemen** | ** ** | **Other** | ** ** | **Total** | ** ** |
| Sales                   |       | 94.45         |       | 58.34 |   | 105.47 |   | 79.02 |   | 99.87 |   | 98.98 |   | 89.78 |   |
| Operating Expenses      |       | (6.75         | )          | (16.38 | ) | (42.04 | ) | (13.48 | ) | (15.88 | ) | (4.91 | ) | (13.18 | ) |
| In-country Taxes2  |       | —        |       | — |   | — |   | — |   | (24.83 | ) | — |   | (3.63 | ) |
| **Cash Netback******    | ** ** | **87.70****** | ** ** | **41.96****** | ** ** | **63.43****** | ** ** | **65.54****** | ** ** | **59.16****** | ** ** | **94.07****** | ** ** | **72.97** | ** ** |

 
| ** **              | ** ** | **2007**      | ** ** |
|-------------------------|------------|---------------|------------|
| **($/boe)**             | ** ** | **UK**        | ** ** | **Canada** | ** ** | **Syncrude** | ** ** | **US** | ** ** | **Yemen** | ** ** | **Other** | ** ** | **Total** | ** ** |
| Sales                   |       | 74.79         |       | 40.79 |   | 79.76 |   | 58.16 |   | 76.29 |   | 71.29 |   | 68.46 |   |
| Operating Expenses      |       | (6.94         | )          | (15.93 | ) | (30.32 | ) | (9.69 | ) | (12.00 | ) | (3.76 | ) | (11.63 | ) |
| In-country Taxes2  |       | —        |       | — |   | — |   | — |   | (17.42 | ) | — |   | (3.31 | ) |
| **Cash Netback******    | ** ** | **67.85****** | ** ** | **24.86****** | ** ** | **49.44****** | ** ** | **48.47****** | ** ** | **46.87****** | ** ** | **67.53****** | ** ** | **53.52** | ** ** |

 

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*1*                 Before royalty cash netbacks are calculatedby dividing sales, royalties and other, operating expenses and in-country taxesby production before royalties. After royalty cash netbacks are calculated bydividing sales, operating expenses and in-country taxes by production after royalties.

*2*                 Comprisesincome taxes payable in Yemen that are included in the Government’s share ofprofit oil.

 

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**ENERGYMARKETING**

 
| **(Cdn$ millions)**                                  | ** ** | **2009**   | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|-----------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Physical Sales1                                           |       | 41,093     |       | 54,772     |       | 34,358     |       |
| Physical Purchases1                                  |       | (40,145    | )          | (54,047    | )          | (33,417    | )          |
| Net Financial Transactions1, 2                  |       | (171       | )          | (142       | )          | (61        | )          |
| Change in Fair Market Value of Inventory1            |       | 166        |       | (116       | )          | 79         |       |
| Marketing Revenue                                         |       | 943        |       | 467        |       | 959        |       |
| Transportation Expense                                    |       | (600       | )          | (751       | )          | (806       | )          |
| Other                                                     |       | 5          |       | 27         |       | 14         |       |
| **Net Marketing  Revenue**                                | ** ** | **348**    | ** ** | **(257**   | **)**      | **167**    | ** ** |
| ** **                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Contribution  to Net Marketing Revenue by Region:**     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| North America                                             |       | 318        |       | (284       | )          | 151        |       |
| Asia                                                      |       | 23         |       | 13         |       | 11         |       |
| Europe                                                    |       | 7          |       | 14         |       | 5          |       |
| **Net Marketing  Revenue**                                | ** ** | **348**    | ** ** | **(257**   | **)**      | **167**    | ** ** |
| Depreciation, Depletion, Amortization and Impairment      |       | (27)       |       | (19        | )          | (13        | )          |
| General and Administrative                                |       | (91)       |       | (79        | )          | (87        | )          |
| Allowance for Doubtful Receivables                        |       | 5          |       | (54        | )          | —     |       |
|                                                      |       |       |       |       |       |       |       |
| **Marketing  Contribution to Income before Income Taxes** | ** ** | **235**    | ** ** | **(409**   | **)**      | **67**     | ** ** |
| ** **                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **North America**                                         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Natural Gas**                                           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Physical Sales Volumes3 (bcf/d)                      |       | 4.9        |       | 6.7        |       | 5.8        |       |
| Transportation Capacity (bcf/d)                           |       | 1.5        |       | 1.8        |       | 2.0        |       |
| Storage Capacity4 (bcf)                              |       | 32         |       | 38         |       | 39         |       |
| Financial Volumes5 (bcf/d)                           |       | 10.1       |       | 16.8       |       | 21.9       |       |
| **Crude Oil**                                             |       |       |       |       |       |       |       |
| Physical Sales Volumes3 (mbbls/d)                    |       | 852        |       | 656        |       | 655        |       |
| Storage Capacity4 (mbbls)                            |       | 3,030      |       | 2,578      |       | 2,734      |       |
| Financial Volumes5 (mbbls/d)                         |       | 730        |       | 1,591      |       | 2,134      |       |
| **Power**                                                 |       |       |       |       |       |       |       |
| Physical Sales Volumes3 (GWhrs/d)                    |       | 10         |       | 5          |       | 5          |       |
| Generation Capacity (MW/hr)                               |       | 87         |       | 87         |       | 87         |       |
| ** **                                                |       |       |       |       |       |       |       |
| **Asia**                                                  |       |       |       |       |       |       |       |
| Physical Sales Volumes3 (mbbls/d)                    |       | 94         |       | 99         |       | 120        |       |
| Financial Volumes5 (mbbls/d)                         |       | 384        |       | 349        |       | 256        |       |
|                                                      |       |       |       |       |       |       |       |
| **Europe**                                                |       |       |       |       |       |       |       |
| Financial Volumes5 (mbbls/d)                         |       | 378        |       | 787        |       | 529        |       |
|                                                      |       |       |       |       |       |       |       |
| **Value-at-Risk**                                         |       |       |       |       |       |       |       |
| Year End                                                  |       | 11         |       | 25         |       | 26         |       |
| High                                                      |       | 24         |       | 40         |       | 38         |       |
| Low                                                       |       | 9          |       | 19         |       | 24         |       |
| Average                                                   |       | 15         |       | 30         |       | 30         |       |

 

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*1*                 Energy Marketing’sphysical sales, physical purchases, net financial transactions and changes infair market value of inventory are reported net on the Consolidated Statementof Income as marketing and other income.

*2*                 Net financialtransactions include all gains and losses on financial derivatives and theunrealized portion of gains and losses on physical purchase and sale contracts.

*3*                 Excludes inter-segmenttransactions. Physical volumes represent amounts delivered during the year.

*4*                 Energy Marketing’sstorage capacity reflects volumes contracted but not necessarily used at alltimes.

*5*                 Financial volumesrepresent amounts largely acquired to economically hedge physical transactionsduring the year.

 

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**2009 VS 2008—HIGHER CONTRIBUTIONS FROM ENERGYMARKETING INCREASED NET INCOME BY $610 MILLION**

 

Energy marketing generated $348 million in net revenue in2009, with all businesses contributing positive results. We renewed focus onthe physical producer/marketer model which involves buying, selling, andholding physical commodities, and holding the rights to physical transportationand storage assets.

 

During the fourth quarter, energy marketing continued tooptimize its trading around physical assets resulting in gains on physicalpositions and commodity inventory, together with gains from blending in ourcrude oil business. During the latter part of 2009, gas prices increased as aresult of cold weather across North America resulting in unrealized gains oninventory which is carried at fair value. We also had gains on derivatives usedto hedge our transportation assets.

 

The largest contribution in 2009 came from our global crudeoil business, which generated gains by inventory management and physicalbusiness as a result of contango in the forward price curve. These gains wererecognized largely in the first quarter of 2009. This contango, combined withnarrowing crude oil differentials, enabled us to capture both realized andunrealized gains on our relatively low-risk physical trading strategies.

 

Similar to 2008, the natural gas business faced a challengingeconomic environment. Gas prices remained suppressed while location spreadsbetween markets continued to narrow throughout the year. Early in the year, thegas business incurred losses as a result of exiting the last of its tradingpositions from 2008 and from selling natural gas inventory where the offsettinggains on the financial instruments hedging the inventory were recognized inprior periods. Weakness in gas markets reduced the value of holdingtransportation capacity. Any losses associated with the transportation andstorage capacity contracts will be recognized when the contracts are used orsold.

 

During the year, we initiated a strategic review of ourenergy marketing natural gas and power businesses. This review continues toalign our marketing activities with our upstream oil and gas businesses. Inearly 2010, we entered into an agreement to sell our European gas and powermarketing business.

 

**2008 VS 2007—REDUCED ENERGY MARKETING NETREVENUE DECREASED NET INCOME BY $424 MILLION**

 

Our 2008 results were impacted by the significant volatilityin commodity markets, the dramatic decrease in commodity prices, and marketswhich operated outside normal historical fundamentals. Losses in 2008 werelargely from our North America gas team who were positioned to take advantageof differentials between locations and capture value between summer and winterprices. The rapidly deteriorating economic environment resulted in dramaticdemand destruction. In mid 2008, we refocused on optimizing the physicalbusiness and the team began to exit positions thereby incurring losses due tothe lack of liquidity in the market and falling commodity prices.

 

The credit crisis that impacted financial markets caused someof our counterparties 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 of 2008 although we continue to pursue recoveryof these amounts. We also provided an additional $15 million for credit riskwith our counterparties. The majority of our counterparties are integrated oilcompanies, crude oil refiners and marketers, and large utilities.

 

Results from our marketing group vary between periods andhistorical results are not necessarily indicative of future results. Marketingresults depend on a variety of factors such as market volatility, changes intime and location spreads, the manner in which we use our storage andtransportation assets and the change in value of the financial instruments weuse to economically hedge these assets.

 

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**COMPOSITION OF NET MARKETING REVENUE**

 
| **(Cdn$ millions)**                    | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Trading Activities (Physical and Financial) |       | 339      |       | (287     | )          | 147      |       |
| Other Activities                            |       | 9        |       | 30       |       | 20       |       |
| **Total Net  Marketing Revenue**            | ** ** | **348**  | ** ** | **(257** | **)**      | **167**  | ** ** |

 

**TRADING ACTIVITIES**

 

In our energy marketing group, we enter into contracts topurchase and sell crude oil and natural gas. We also use financial andderivative contracts, including futures, forwards, swaps and options for hedgingand trading purposes. We account for all derivative contracts using fair valueaccounting and record the net gain or loss from their revaluation in marketingand other income. 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 totransportation and storage of third-party oil and gas. In addition, we earnincome from our power generation facilities at Balzac and Soderglen.

 

**Fair Value of Derivative Contracts**

 

For purposes of estimating the fair value of our derivativecontracts, wherever possible, we utilize quoted market prices and if notavailable, estimates from third-party brokers. These broker estimates arecorroborated with multiple sources and/or other observable market datautilizing assumptions that market participants would use when pricing the assetor liability, including assumptions about risk and market liquidity. Inputs tofair valuations may be readily observable, market-corroborated, or generallyunobservable. We utilize valuation techniques that seek to maximize the use ofobservable inputs and minimize the use of unobservable inputs. To value longer-termtransactions and transactions in less active markets for which pricinginformation is not generally available, unobservable inputs may be used.

 

As a basis for establishing fair value, we utilize amid-market pricing convention between bid and ask and then adjust our pricingto the ask price when we have a net short position and the bid price when wehave a net long position. This adjustment reflects an estimated exit price andincorporates the impact of liquidity when the bid-ask spread widens in lessliquid markets. We incorporate the credit risk associated with counterpartydefault, as well as Nexen’s own credit risk, into our estimates of fair value.

 

We classify the fair value of our derivatives according tothe following hierarchy based on the amount of observable inputs used to valuethe instruments.

 

·                  Level 1—Quoted prices areavailable in active markets for identical assets or liabilities as of thereporting date. Active markets are those in which transactions occur insufficient frequency and volume to provide pricing information on an ongoingbasis. Level 1 consists of financial instruments such as exchange-tradedderivatives and we use information from markets such as the New York MercantileExchange.

·                  Level 2—Pricing inputs areother than quoted prices in active markets included in Level 1. Prices in Level2 are either directly or indirectly observable as of the reported date. Level 2valuations are based on inputs, including quoted forward prices forcommodities, time value, volatility factors, and broker quotations, which canbe substantially observed or corroborated in the marketplace. Instruments inthis category include non-exchange traded derivatives such as over-the-counterphysical forwards and options, including those which have prices similar toquoted market prices. We obtain information from sources such as the NaturalGas Exchange, independent price publications and over-the-counter brokerquotes.

·                  Level 3—Valuations in thislevel are those with inputs which are less observable, unavailable or where theobservable data does not support the majority of the instrument’s fair value.Level 3 instruments may include items based on pricing services or brokerquotes where we are unable to verify the observability of inputs into theirprices. Level 3 instruments include longer-term transactions, transactions inless active markets or transactions at locations for which pricing informationis not available. In these instances, internally developed methodologies areused to determine fair value which primarily includes extrapolation ofobservable future prices to similar locations, similar instruments or latertime periods.

 

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At December 31, 2009, the fair value of our derivativecontracts in our energy marketing trading activities totaled $23 million. Thisincludes contracts used to economically hedge our physical storage andtransportation contracts which cannot be carried at fair value until they areused. Below is a breakdown of the derivative fair value by valuation method andcontract maturity.

 
| ** **                                            | ** ** | **Maturity**    | ** ** |
|-------------------------------------------------------|------------|-----------------|------------|
| **(Cdn$ millions)**                              | ** ** | **< 1 year** | ** ** | **1-3 years** | ** ** | **4-5 years** | ** ** | **> 5 years** | ** ** | **Total** | ** ** |
| Level 1—Actively Quoted Markets                  |       | (68             | )          |   | (61 | ) |   | (14 | ) |   | — |   |   | (143 | ) |   |
| Level 2—Based on Other Observable Pricing Inputs |       | 56              |       |   | 52 |   |   | 10 |   |   | 6 |   |   | 124 |   |   |
| Level 3—Based on Unobservable Pricing Inputs     |       | 22              |       |   | 20 |   |   | — |   |   | — |   |   | 42 |   |   |
| **Fair Value at  December 31, 2009**                  | ** ** | **10**          |       | ** ** | **11** |   | ** ** | **(4** | **)** | ** ** | **6** |   | ** ** | **23** |   | ** ** |

 

**Changes in Fair Value of Derivative Contracts**

 
| **(Cdn$ millions)**                         | ** ** | **Total** | ** ** |
|--------------------------------------------------|------------|-----------|------------|
| Fair Value at December 31, 2008                  |       | 63        |       |   |
| Change in Fair Value of Contracts                |       | 142       |       |   |
| Net Losses (Gains) on Contracts Closed           |       | (182      | )          |   |
| Changes in Valuation Techniques and Assumptions1 |       | —    |       |   |
| **Fair Value at  December 31, 2009**             | ** ** | **23**    |       | ** ** |

 

----

*1*                 Our valuation methodologyhas been applied consistently each period.

 

The fair values of our derivative contracts will be realizedover time as the related contracts settle. Until then, the value of certaincontracts will vary with forward commodity prices and price differentials. Theaverage term of our derivative contracts is approximately 1.2 years.

 

**CHEMICALS**

 
| **(Cdn$ millions)**                              | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net Sales                                             |       | 458      |       |     | 477        |     |       | 414 |   |   |
| Sales Volumes (thousand short tons)                   |       |     |       |     |       |     |       |   |   |   |
| Sodium Chlorate                                       |       | 441      |       |     | 495        |     |       | 478 |   |   |
| Chlor-alkali                                          |       | 447      |       |     | 469        |     |       | 465 |   |   |
| Operating Profit1                                     |       | 143      |       |     | 125        |     |       | 118 |   |   |
| Operating Margin2                                     |       | 31       | %          |     | 26         | %        |       | 29 | % |   |
| Chemicals Contribution to Income Before Income Taxes3 |       | 79       |       |     | (14        | )        |       | 64 |   |   |
| Capacity Utilization                                  |       | 88       | %          |     | 92         | %        |       | 94 | % |   |

* *

----

*1*                 Net sales less operatingcosts, transportation and other.

*2*                 Operating profit dividedby net sales.

*3*                 Includes foreign exchangegains and losses on long-term debt.

 

**2009 VS 2008—HIGHER CHEMICALS CONTRIBUTIONINCREASED NET INCOME BY $73 MILLION**

 

North America chlorate revenue decreased 2% from 2008, as a13% reduction in sales volumes attributable to the global economic downturn waspartially offset by stronger pricing. North America chlor-alkali revenueincreased 2% from 2008 as weaker caustic prices somewhat offset higher volumes.In Brazil, lower caustic prices and a decline in sales volumes decreasedchlor-alkali revenues 32%. Chlor-alkali sales volumes decreased because wereduced sales of purchased product as this activity generates no gross margin.There was no impact on our returns in Brazil by eliminating this activity.Chlorate sales in Brazil increased 5% from the prior year as a result of higherprices.

 

The Canadian dollar strengthened compared to the prior yearend and chemicals contribution includes unrealized foreign exchange gains of$50 million on the Canexus US-dollar denominated debt. This compared to our2008 results which included unrealized foreign exchange losses of $54 million.

 

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**2008 VS 2007—LOWER CHEMICALS CONTRIBUTIONDECREASED NET INCOME BY $76 MILLION**

 

North America sodium chlorate revenues increased 14% in 2008as a result 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 werealized higher selling prices for caustic soda. These increases were 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 included foreign exchangelosses of $54 million in 2008, primarily from unrealized losses on therevaluation of US-dollar denominated long-term debt.

 

**CORPORATEEXPENSES**

 

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

 
| **(Cdn$ millions)**                                           | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| General and Administrative Expense before Stock-Based Compensation |       | 428      |       | 417      |       | 336      |       |
| Stock-Based Compensation1                                          |       | 69       |       | (160     | )          | 38       |       |
| **Total**                                                          | ** ** | **497**  | ** ** | **257**  | ** ** | **374**  | ** ** |

 

----

*1*                 Includes cash and non-cashexpenses related to our tandem option plan and stock appreciation rights plan.

 

**2009 VS 2008—HIGHER COSTS DECREASED NETINCOME BY $240 MILLION**

 

Higher stock-based compensation expense was the primaryreason for the 93% increase in G&A costs in 2009. Changes in our shareprice create volatility in our net income as we account for stock-basedcompensation using the intrinsic-value method. This method uses our share priceat the end of the reporting period to determine our stock-based compensationobligations and related expense. Our stock price fluctuated during the yearbefore closing at $25.22/share, up 18% from $21.45/share at the end of 2008.Cash payments made in connection with our stock-based compensation programs in2009 decreased 29% from 2008 to $79 million. Cash payments were higher in 2008as our stock price reached a high of $43.45/share during the year.

 

**2008 VS 2007—LOWER COSTS INCREASED NET INCOMEBY $117 MILLION**

 

During 2008, we recovered non-cash stock-based compensationcosts of $272 million as our stock price closed the year at $21.45/share,compared to $32.10/share the previous year. This recovery was partially offsetby cash payments for stock-based compensation programs of $112 million, 24%lower than 2007.

 

G&A expense before stock-based compensation increased $81million, primarily as a result of higher employee costs and cost inflation. Anintegral part of our strategy to expand our oil and gas operations has been toactively recruit highly experienced employees, positioning us for success inour core areas. We have been actively recruiting skilled individuals tostrengthen our teams in Norway and the US.

 

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**Interest**

 
| **(Cdn$ millions)**  | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|---------------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest                  |       | 389      |       | 334      |       | 341      |       |
| Less: Capitalized         |       | (77      | )          | (240     | )          | (173     | )          |
| **Net Interest  Expense** | ** ** | **312**  | ** ** | **94**   | ** ** | **168**  | ** ** |
|                      |       |     |       |     |       |     |       |
| Effective Interest Rate   |       | 5.0      | %          | 5.9      | %          | 6.2      | %          |

 

**2009 VS 2008—HIGHER NET INTEREST EXPENSEREDUCED NET INCOME BY $218 MILLION**

 

Financing costs increased $55 million from 2008. This 16%increase was a result of higher levels of debt, partially offset by lowerinterest rates. Our capital investment program, including the acquisition of anadditional 15% interest in Long Lake, exceeded our cash flow, causing us todraw down a portion of our term credit facility. In addition, we issued US$1billion of long-term notes in the third quarter, increasing interest costs by$32 million this year. The stronger US dollar increased our US-dollardenominated interest costs for the year by $32 million.

 

 

During the year, capitalized interest decreased $163 millionfrom 2008, as a result of completing major development projects. Long Lake capitalizedinterest in 2009 was $23 million, down $183 million from 2008, while Ettrickcapitalized interest decreased $7 million during the year. This was partiallyoffset by an increase in Usan capitalized interest of $16 million. In additionto our Usan development, we also continue to capitalize interest on theconstruction of the fourth platform at Buzzard and our Chemicals technicalconversion project in North Vancouver.

 

**2008 VS 2007—LOWER NET INTEREST EXPENSEINCREASED NET INCOME BY $74 MILLION**

 

Our financing costs are $7 million lower than the previousyear as our strong cash flow reduced our debt needs. Lower interest rates onour variable rate debt also reduced interest costs. In the third quarter, wecompleted an internal reorganization and financing of our assets in the UK.This required us to draw down approximately US$1 billion under our term creditfacilities. As a consequence, our financing costs increased in the fourthquarter of 2008.

 

Interest capitalized on our major development projects increased$67 million 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.

 

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**Income Taxes**

 
| **(Cdn$ millions)**              | ** ** | **2009** | ** ** | **2008**  | ** ** | **2007** | ** ** |
|---------------------------------------|------------|----------|------------|-----------|------------|----------|------------|
| Current                               |       | 776      |       | 859       |       | 434      |       |
| Future                                |       | (516     | )          | 598       |       | 358      |       |
| **Total  Provision for Income Taxes** | ** ** | **260**  | ** ** | **1,457** | ** ** | **792**  | ** ** |

 

**2009 VS 2008—LOWER TAXES INCREASED NET INCOMEBY $1,197 MILLION**

 

Our provision for income taxes decreased by $1,197 million ascompared to the prior year. Lower commodity prices and production, a reductionin Canadian tax rates, and a fair value unrealized loss on our crude oil putoptions contributed to lower tax expense in 2009. During the year, future taxexpense was reduced by the continued amortization of the deferred tax creditarising from the internal reorganization and financing of our North Sea assetscompleted in 2008. Our income tax provision includes current taxes in the UK,Yemen, Norway, Colombia and the US.

 

**2008 VS 2007—HIGHER TAXES DECREASED NETINCOME BY $665 MILLION**

 

Our provision for income taxes increased $665 million or 84%from the prior year. This increase was primarily due to record commodity pricesand strong production at Buzzard in the UK, which has a corporate tax rate onoil and gas activities of 50%. Current income taxes include cash taxes inYemen, the UK, Colombia, Norway and the US.

 

**Other**

 
| **(Cdn$ millions)**                                   | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Increase (Decrease) in Fair Value of Crude Oil Put Options |       | (251     | )          | 203      |       | (43      | )          |

 

In the fourth quarter of 2009, we purchased put options on90,000 bbls/d of our 2010 crude oil production. These options establish a WTIfloor price of US$50/bbl on these volumes and provide a base level of priceprotection without limiting our upside to higher prices. Options on 60,000bbls/d settle monthly, while the remaining options settle annually. Theseoptions are recorded at fair value throughout their term. As a result, changesin forward crude oil prices create gains or losses on these options at eachperiod end. The put options were purchased for $39 million and are carried atfair value. At December 31, 2009, higher crude oil prices reduced the fairvalue of the options to $17 million, and we recorded a fair value loss in 2009of $22 million.

 

In early 2008, we purchased put options on approximately70,000 bbls/d of our 2009 crude oil production. These options were purchasedfor $14 million and established a Dated Brent floor price of US$60/bbl on thesevolumes. At December 31, 2008, the put options had an estimated fair value of$233 million due to lower crude oil prices. Strengthening crude oil prices in2009 reduced the fair value of these options to nil and we recorded a fairvalue loss of $229 million in 2009.

 

In 2007, we purchased put options on approximately 100,000bbls/d of our 2008 crude oil production for $24 million. These optionsestablished an annual average Dated Brent floor price of US$50/bbl on thesevolumes. These put options expired out-of-the-money.

 

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**OUTLOOK FOR2010**

 

**Capital Investment**

 

In 2010, we plan toinvest $2.5 billion in capital activities on our oil and gas operations tosolidify growth beyond 2010 as follows:

 

·                  35% on our existing producingassets, including installation of the fourth platform at Buzzard;

·                  30% in development projects atUsan, offshore West Africa and progressing the sanctioning of the Golden Eaglearea;

·                  23% on exploration andappraisal opportunities in our key regions of the North Sea, Gulf of Mexico andoffshore West Africa; and

·                  12% on early stage developmentprojects expected to contribute future production and cash flow includingadvancement of our Horn River shale gas play and future phases of oil sands inthe Athabasca region.

 

The amount of this capital investment could be reduceddepending on the prevailing economic environment. Details of our 2010 capitalprogram are included in the Capital Investment section of the MD&A.

 

**Production**

 

In 2010, we expect our annual production to growapproximately 4% to 6%, assuming the midpoint of our guidance, and range from230,000 to 280,000 boe/d (200,000 to 250,000 boe/d after royalties). Thisgrowth reflects a full year of production from Ettrick and Longhorn, andincreasing volumes from Long Lake. At the high end of our guidance, ourproduction growth would be as high as 15%. The low end includes the possibilityof advancing the start-up of the fourth platform at Buzzard which is currentlyscheduled for 2011. Advancement to 2010 would only be required if we see higherthan expected levels of hydrogen sulphide. The downtime associated withadvancing the start-up could reduce annual volumes by 10,000 to 15,000 boe/d.

 
| ** **        | ** ** | **2010 Estimated Production** | ** ** | **2009 Production**  | ** ** |
|-------------------|------------|-------------------------------|------------|----------------------|------------|
| **(mboe/d)**      | ** ** | **Before  Royalties**         | ** ** | **After  Royalties** | ** ** | **Before  Royalties** | ** ** | **After  Royalties** | ** ** |
| United Kingdom    |       | 100–130                  |       | 100–130         |       | 102 |   | 102 |   |
| Canada            |       | 28–34                    |       | 19–25           |       | 38 |   | 32 |   |
| Long Lake Bitumen |       | 20–30                    |       | 18–28           |       | 8 |   | 8 |   |
| Syncrude          |       | 19–24                    |       | 18–23           |       | 20 |   | 19 |   |
| United States     |       | 20–28                    |       | 17–25           |       | 21 |   | 19 |   |
| Yemen             |       | 32–37                    |       | 19–23           |       | 50 |   | 30 |   |
| Other Countries   |       | 1–2                      |       | 1–2             |       | 4 |   | 3 |   |
| **Total**         | ** ** | **230–280**              | ** ** | **200–250**     | ** ** | **243** | ** ** | **213** | ** ** |

 

**Cash Flow and Sensitivities**

 

We expect cash flow from operating activities to fund ourcapital investments in 2010, assuming the following:

 
| WTI (US$/bbl)                       |   | $ | 70   |   |
|-------------------------------------|--------|---|------|--------|
| NYMEX Natural Gas (US$/mmbtu)       |   | $ | 5.50 |   |
| US to Canadian Dollar Exchange Rate |   | $ | 0.90 |   |

 

Changes in commodity prices and exchange rates impact ourannual cash flow from operating activities, after cash taxes, as follows:

 
| **(Cdn$ millions)**                  |   |   |   |
|-------------------------------------------|--------|--------|--------|
| WTI—US$1/bbl change above US$50      |   | 47     |   |
| WTI—US$1/bbl change below US$501     |   | 30     |   |
| NYMEX Natural Gas—US$0.50/mcf change |   | 28     |   |
| Exchange Rate—$0.01 US/Cdn change    |   | 35     |   |

 

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*1**                **Putoptions mitigate the impact of a price decline below US$50 WTI (based on 90,000puts).*

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**LIQUIDITY ANDCAPITAL RESOURCES**

 

**Capital Structure**

 
| **(Cdn$ millions)**        | ** ** | **December 31********2009** | ** ** | **December 31********2008** | ** ** |
|---------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| **Net Debt**1              |       |                        |       |                        |       |
| Bank Debt                       |       | 1,803                       |       | 1,448                       |       |
| Public Senior Notes             |       | 4,982                       |       | 4,582                       |       |
| Total Senior Debt               |       | 6,785                       |       | 6,030                       |       |
| Subordinated Debt               |       | 466                         |       | 548                         |       |
| Total Debt                      |       | 7,251                       |       | 6,578                       |       |
| Less: Cash and Cash Equivalents |       | (1,700                      | )          | (2,003                      | )          |
| **Total Net  Debt**             | ** ** | **5,551**                   | ** ** | **4,575**                   | ** ** |
| ** **                      | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| **Equity**2                     | ** ** | **7,646**                   | ** ** | **7,191**                   | ** ** |

 

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*1*                 Includes all of our debt and iscalculated as long-term debt and short-term borrowings less cash and cashequivalents.

*2*                 Equity is the historical issueprice of equity and accumulated retained earnings.

 

**Net Debt**

 

We use net debt as a key indicator of our leverage and tomonitor the strength of our balance sheet. Net debt is directly related to ouroperating cash flows and capital investment. We ended the year with net debt ofapproximately $5.6 billion, $976 million higher than 2008. The year-over-yearchange in our net debt results from:

 
| **(Cdn$ millions)**                                | ** ** | **2009** | ** ** | **2008** | ** ** |
|---------------------------------------------------------|------------|----------|------------|----------|------------|
| Capital Investment                                      |       | 2,742    |       | 3,066    |       |
| Acquisition of Additional Working Interest at Long Lake |       | 755      |       | —   |       |
| Cash Flow from Operating Activities                     |       | (1,886   | )          | (4,354   | )          |
| Deficiency (Excess)                                     |       | 1,611    |       | (1,288   | )          |
| Dividends on Common Shares                              |       | 104      |       | 92       |       |
| Issue of Common Shares                                  |       | (57      | )          | (64      | )          |
| Repurchase of Common Shares for Cancellation            |       | —   |       | 338      |       |
| Foreign Exchange Translation of US-dollar Debt and Cash |       | (897     | )          | 1,012    |       |
| Net Proceeds on Disposition of Assets                   |       | (17      | )          | (6       | )          |
| Other                                                   |       | 232      |       | 87       |       |
| **Increase in  Net Debt**                               | ** ** | **976**  | ** ** | **171**  | ** ** |

 

Our net debt increased from the prior year primarily due tocapital investment exceeding cash flow generated from operating activities.During the year, our capital investment included the acquisition of anadditional 15% working interest in Long Lake for $755 million and investmentsfocused on our three key growth areas of: oil sands, conventional explorationand exploitation, and unconventional gas. Cash flow from operating activitiesdecreased compared to the prior year mainly as a result of lower oil and gascommodity prices. This impact was partially offset as the Canadian dollarstrengthened relative to the US dollar, which reduced our US-dollar denominateddebt. We currently have liquidity of approximately $3.3 billion, which iscomprised of cash and undrawn committed credit facilities, most of which areavailable until July 2012.

 

Operating cash flows in the oil and gas industry can bevolatile as short-term commodity prices are driven by existing supply anddemand fundamentals and market volatility. We manage our investments throughthe lows of the commodity market to create future growth and value for ourshareholders over the long-term without putting our balance sheet under unduefinancial risk. Changes in our non-cash working capital can vary betweenperiods as our energy marketing net working capital position fluctuatesdepending on timing of settlement of outstanding positions, the movement incommodity prices and inventory cycles.

 

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The change in our net debt, combined with lower cash flow andearnings, increased our 2009 leverage as reflected in the following ratios:

 
| **(times)**                                            | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net Debt to Cash Flow from Operating Activities1  |       | 2.5      |       | 1.1      |       | 1.6      |       |
| Interest Coverage2                                |       | 8.5      |       | 15.6     |       | 12.1     |       |

 

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*1*                 For purposes of thiscalculation, cash flow from operating activities is before changes in non cashworking capital and other.

*2*                 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 cycle-timesrequiring significant amounts of capital prior to cash flow generation, we havesuccessfully leveraged our balance sheet many times in the past, including to:

 

·                  develop the Masila project inYemen in 1993;

·                  acquire Wascana in 1997;

·                  repurchase 20 million commonshares, representing 14% of our issued common shares, in 2000;

·                  acquire the remaining interestin Aspen in 2003;

·                  acquire the Buzzard project andother key assets in the North Sea in 2004;

·                  construct the first phase ofLong Lake beginning in 2004; and

·                  acquire an additional 15%in the Long Lake project and joint venture lands in 2009.

 

For the twelve months ended December 31, 2009, our net debtto cash flow from operating activities (before changes in non-cash workingcapital and other) ratio was 2.5 times compared to 1.1 times at December 31,2008. While we typically expect the target ratio to fluctuate between 1.0 and2.0 times under normalized commodity prices, this can be higher or lowerdepending on commodity price volatility or when we identify strategicopportunities requiring additional investment. Whenever we exceed our targetratio, we assess whether we need to develop a strategy to reduce our leverageand lower this ratio back to target levels over time.

 

**Change in Working Capital**

 
| **(Cdn$ millions)**                 | ** ** | **December 31******** 2009** | ** ** | **December 31********2008** | ** ** | **Increase******(Decrease)**** | ** ** |
|------------------------------------------|------------|-----------------------------------|------------|-----------------------------|------------|--------------------------------|------------|
| Cash and Cash Equivalents                |       | 1,700                             |       | 2,003                       |       | (303                           | )          |
| Restricted Cash                          |       | 198                               |       | 103                         |       | 95                             |       |
| Accounts Receivable                      |       | 2,788                             |       | 3,163                       |       | (375                           | )          |
| Inventories and Supplies                 |       | 680                               |       | 484                         |       | 196                            |       |
| Accounts Payable and Accrued Liabilities |       | (3,038                            | )          | (3,326                      | )          | 288                            |       |
| Other                                    |       | 70                                |       | 76                          |       | (6                             | )          |
| **Total**                                | ** ** | **2,398**                         | ** ** | **2,503**                   | ** ** | **(105**                       | **)**      |

 

Our working capital balances remained strong in 2009 as weweathered the economic downturn that began in late 2008. Our capitalexpenditures exceeded our cash flow from operating activities, which caused usto draw upon our available liquidity and issue US$1 billion of long-term debt.We currently have approximately $1.7 billion of cash and cash equivalents onhand as well as significant undrawn committed credit facilities available.

 

Accounts receivable and payable in our energy marketing groupdecreased during the year as we reduced our trading activity to focus onsupporting our core physical business as a producer/marketer. Commodityinventory increased since 2008 as our trading inventory is carried at fairvalue and was higher than last year as a result of stronger crude oil prices.

 

At December 31, 2009, our restricted cash consists of margindeposits of $198 million (2008—$103 million) related to exchange-tradedderivative financial contracts used by our energy marketing group toeconomically hedge physical commodities, storage, transportation and customersales contracts. We are required to maintain margin for net out-of-the-moneyderivative financial contracts. The increase in margin relates to derivativefinancial contracts protecting our

 

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natural gas and crude oil positions. Our physical gaspurchase contracts gained in value in a declining gas price environment, whileour physical crude sales contracts gained in value in a rising priceenvironment. The derivative financial contracts protecting these positionsdeclined in value. Additional margin was required to cover the increase in thenet out-of-the-money derivative financial contracts.

 

The weaker US dollar at the end of the year impacted ourUS-dollar denominated working capital by decreasing accounts receivable,inventories and accounts payable by approximately $215 million, $50 million and$210 million, respectively.

 

 

**Liquidity**

 

We generally rely on operating cash flows to fund capitalrequirements and provide liquidity. Given the long cycle-time of some of ourdevelopment projects and volatile commodity prices, it is not unusual forcapital expenditures to exceed our cash flow in any given year. We also requireliquidity for our energy marketing business. We believe that maintaining strongliquidity is critical during periods of uncertain economic markets. Wecurrently have liquidity of approximately $3.3 billion which is comprised ofcash and undrawn committed credit facilities, most of which are available until2012.

 

We maintain significant committed credit facilities. At December31, 2009, we had unsecured term credit facilities of $3.2 billion that areavailable until July 2012. Of these facilities, $1.6 billion was drawn and $407million was utilized to support letters of credit. We also had $492 million ofuncommitted, unsecured credit facilities, of which $86 million was supportingletters of credit outstanding at December 31, 2009. Canexus had $451 million ofcommitted, secured term credit facilities available until 2011 of which $233million was drawn at December 31, 2009.

 

From time to time, we access capital markets to meet ourfinancing needs. We also use financial instruments to minimize exposure tofluctuating commodity prices and foreign exchange. For example, we routinelypurchase WTI and Dated Brent put options to establish a minimum value for ourproduction. We manage our capital structure to maintain flexibility so we canfund our capital programs given the cyclical nature of the oil and gasbusiness.

 

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The following table shows how we financed our businessactivities. When our operating cash flows exceed our investment requirements,we generally pay down debt or return cash to shareholders. We borrow or issueequity to fund investment requirements that exceed our operating cash flow.

 
| **(Cdn$ millions)**            | ** ** | **2009** | ** ** | **2008**  | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------------|------------|----------|------------|-----------|------------|----------|------------|----------|------------|----------|------------|
| Cash Flow from Operating Activities |       | 1,886    |       | 4,354     |       | 2,830    |       | 2,374    |       | 2,143    |       |
| Cash Flow from Investing Activities |       | (3,743   | )          | (3,189    | )          | (3,281   | )          | (3,388   | )          | (1,864   | )          |
| Surplus (Deficiency)                |       | (1,857   | )          | 1,165     |       | (451     | )          | (1,014   | )          | 279      |       |
|                                |       |     |       |      |       |     |       |     |       |     |       |
| Cash Flow from Financing Activities |       | 1,821    |       | 322       |       | 677      |       | 1,081    |       | (274     | )          |
| **Net Cash  Generated (Used)**      | ** ** | **(36**  | **)**      | **1,487** | ** ** | **226**  | ** ** | **67**   | ** ** | **5**    | ** ** |

 

In 2005, we used cash flow and proceeds from assetdispositions to fund our capital program and repay debt. In 2006, we borrowedapproximately $1 billion under our committed term credit facilities and usedcash flow from operating activities to fund our capital program. In 2007, weissued US$1.5 billion in senior debt to repay outstanding term creditfacilities and $150 million in medium term notes, as well as to fund our 2007capital program.

 

In 2008, our cash flow from operating activities exceededcapital expenditures by approximately $1.3 billion and we used this excess to:i) build our cash balances; ii) repurchase approximately 12 million commonshares at a cost of $338 million; and iii) repay debt including maturing mediumterm notes of $125 million. We also borrowed approximately US$1 billion underour term credit facilities as a result of an internal reorganization andfinancing of our UK North Sea assets.

 

In 2009, our capital investment, including the acquisition ofan additional working interest in Long Lake, exceeded our cash flow fromoperating activities. The purchase of Long Lake was funded primarily fromaccumulating excess cash in 2008. In response to improving credit markets, wealso issued US$1 billion of senior notes during the year, with US$300 millionmaturing in 10 years and US$700 million maturing in 30 years. Proceeds from thedebt issue were used to repay a portion of our outstanding term creditfacilities as well as for general corporate purposes. The issuance of the newdebt increased the average term-to-maturity of our debt to 17 years.

 

Our marketing business also requires liquidity to support itsactivities. We require liquidity for working capital, cash or credit lines tofund collateral requirements and to absorb unexpected market or credit losses.The commercial agreements our marketing business enters into often includefinancial assurance provisions that allow Nexen and our counterparties toeffectively manage credit risk. These agreements typically require collateralto be posted if adverse credit-related events, such as reduced credit rating tonon-investment grade, occur. We have developed mitigation strategies tosignificantly reduce our overall exposure if such a downgrade were to occur. Webelieve our current liquidity is sufficient enough to fund this exposure, ifnecessary. Additionally, our exchange-traded contracts require that we providemargin based on daily fluctuations in the value of our contracts. The largestsingle day margin call we received during 2009 was $37 million. In evaluatingour liquidity requirements, we consider the current requirements of ourmarketing business as well as additional collateral or other payments thatcould be required if our credit ratings were reduced.

 

**Future Liquidity**

 

Our future liquidity depends upon cash flow generated fromour operations, existing committed credit facilities and our ability to accessdebt and equity markets. Our 2010 capital investment budget is approximately$2.5 billion, which we expect to finance from cash flow and existing cash. Wecontinue to monitor economic conditions and commodity prices and will adjustour capital investment program accordingly. We also continue to work withsuppliers and contractors to negotiate supply rates that reflect existingmarket conditions.

 

In 2010, we expect cash flow from operating activities tofund our capital investment program assuming:

 
| WTI (US$/bbl)                       |   | $ | 70   |   |
|-------------------------------------|--------|---|------|--------|
| NYMEX Natural Gas (US$/mmbtu)       |   | $ | 5.50 |   |
| US to Canadian Dollar Exchange Rate |   | $ | 0.90 |   |

 

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Changes in commodity prices and exchange rates will impactour cash flow and borrowing requirements. Refer to the Outlook for 2010 sectionon page 79 to see how changes in the above assumptions can impact our cashflow.

 

At December 31, 2009, we have $1.7 billion in cash, $1.6billion of undrawn committed credit facilities and $492 million of undrawnuncommitted credit facilities. The average term of our public debt isapproximately 17 years. The only debt maturity of significance in the next fewyears is our $3.2 billion term credit facility which matures in July 2012,although historically we have been able to negotiate an extension with ourlenders. At December 31, 2009, we had drawn $1.6 billion on this facility.Given the long term-to-maturity of a significant portion of our debt, webelieve we are well positioned to bring our near completion projects toproduction and pursue our next generation of growth while preserving ourliquidity.

 

Our debt maturities over the next five years are:

 
| **(Cdn$ millions)**          | ** ** | **2010**   | ** ** | **2011** | ** ** | **2012**  | ** ** | **2013** | ** ** | **2014** | ** ** |
|-----------------------------------|------------|------------|------------|----------|------------|-----------|------------|----------|------------|----------|------------|
| Term Credit Facilities1           |       | —     |       | —   |       | 1,570     |       | —   |       | —   |       |
| Long-Term Notes                   |       | —     |       | —   |       | —    |       | 523      |       | —   |       |
| Canexus LP Term Credit Facilities |       | —     |       | 233      |       | —    |       | —   |       | —   |       |
| Canexus LP Notes                  |       | —     |       | —   |       | —    |       | 52       |       | —   |       |
| Canexus Convertible Debt          |       | —     |       | —   |       | —    |       | —   |       | 46       |       |
| **Total**                         | ** ** | **—** | ** ** | **233**  | ** ** | **1,570** | ** ** | **575**  | ** ** | **46**   | ** ** |

 

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*1*                 $3.2 billion availableuntil July 2012.

 

For the past several years, we invested significant capitalin a number of major development projects including Buzzard, Long Lake andEttrick. The large capital investment required in these projects is behind usand we expect these assets will make significant contributions to our futurecash flows. Cash flows generated from these projects allow us to repay debt andinvest in our next generation of new growth projects such as: i) Usan, offshoreWest Africa; ii) shale gas in the Horn River Basin; and iii) the Golden Eaglearea in the UK North Sea. In 2010, we expect to invest $575 million to progressour Usan development, $200 million at Horn River and $50 million at GoldenEagle. While these development projects lack exploration risk, they are subjectto other risks including higher than anticipated capital costs or delayedstart-up. We maintain significant undrawn committed credit facilities to managethese risks. We also have a US$3.5 billion shelf prospectus filed in the US andCanada for sales of debt securities and common shares, under which we issuedUS$1 billion of debt securities in July.

 

We are well positioned with our current debt structure. Ouronly debt covenant requires us to maintain a long—term debt to EBITDA ratio ofless than 3.5. At December 31, 2009, this ratio was approximately 1.9 times. Wedo not expect to exceed 3.5 based on our current debt levels and plannedoperations.

 

With our expected cash flow streams, commodity price hedgingstrategies, current liquidity levels, access to debt and equity markets, andflexibility to reduce future capital expenditure programs, we expect to be ableto fund all planned capital, dividend distributions and debt repayments, andmeet other obligations that may arise from our oil and gas, chemicals andenergy marketing operations.

 

In 2009 and 2008, the board declared common share dividendsof $0.20 and $0.175, respectively. 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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**Contractual Obligations, Commitments and Guarantees**

 

We assume various contractual obligations and commitments inthe normal course of our operations and financing activities. We haveconsidered these obligations and commitments in assessing our cashrequirements, as noted in the above discussion of future liquidity. Theyinclude:

 
| ** **                                 | ** ** | **Payments** | ** ** |
|--------------------------------------------|------------|--------------|------------|
| **(Cdn$ millions)**                   | ** ** | **Total**    | ** ** | **< 1 year** | ** ** | **1-3 years** | ** ** | **4-5 years** | ** ** | **> 5 years** | ** ** |
| Long-Term Debt                             |       | 7,343        |       | — |   | 1,803 |   | 621 |   | 4,919 |   |
| Interest on Long-Term Debt1                |       | 8,052        |       | 361 |   | 721 |   | 688 |   | 6,282 |   |
| Operating Leases2                          |       | 647          |       | 117 |   | 185 |   | 179 |   | 166 |   |
| Capital Leases                             |       | 120          |       | 6 |   | 12 |   | 11 |   | 91 |   |
| Energy Commodity Contract Liabilities      |       | 694          |       | 482 |   | 180 |   | 32 |   | — |   |
| Transportation and Storage Commitments2    |       | 977          |       | 303 |   | 345 |   | 209 |   | 120 |   |
| Work Commitments and Purchase Obligations3 |       | 2,749        |       | 1,299 |   | 1,079 |   | 313 |   | 58 |   |
| Asset Retirement Obligations               |       | 2,341        |       | 35 |   | 79 |   | 162 |   | 2,065 |   |
| **Total**                                  | ** ** | **22,923**   | ** ** | **2,603** | ** ** | **4,404** | ** ** | **2,215** | ** ** | **13,701** | ** ** |

 

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*1*                 Excludes interest on termcredit facilities of $1.6 billion and Canexus term credit facilities of $233million as the amounts drawn on the facilities fluctuate. Based on amountsdrawn at December 31, 2009 and existing variable interest rates, we would berequired to pay $19 million per year until the outstanding amounts on the termcredit facilities are repaid.

*2*                 Payments for operating leasesand transportation and storage commitments are deducted from our cash flow fromoperating activities.

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

 

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

 

·                  Short-term and long-term debtamounts are included on our December 31, 2009 Consolidated Balance Sheet.

·                  Operating leases include theminimum lease payment obligations associated with leases for office space, railcars, vehicles and processing agreements that allow our production to flowthrough third-party processing facilities.

·                  Capital leases include pipelinecommitments primarily related to production at Long Lake.

·                  Energy commodity contractliabilities include the purchase and sale of physical quantities of oil andnatural gas, and financial derivatives used to manage our exposure to commodityprices. For certain contracts, we may net settle. These contracts are includedin our Consolidated Balance Sheet on a net basis at fair value.

·                  Work commitments includenon-discretionary capital spending for drilling, seismic, facilitiesconstruction and other development commitments in our international operations,and include commitments for the Usan development project in Nigeria over thenext five years ($585 million). Since the timing of certain payments isdifficult to determine with certainty, the table was prepared using our bestestimates. The majority of our 2010 capital investment is discretionary.

·                  We have included $998 millionin work commitments for drilling rigs we have contracted in the UK, Norway andthe Gulf of Mexico over the next five years.

·                  We have $2,341 million ofundiscounted asset retirement obligations after inflation. As of December 31,2009, the discounted value ($1,053 million) of these estimated obligations wasprovided for in our Consolidated Financial Statements (including $35 million ofestimated current obligations). Since timing of any payments is difficult todetermine with certainty, the table was prepared using our best estimates.

·     Wehave a net pension liability of $55 million for our defined benefit pensionplan. This includes a pension asset of $21 million from over contributing tothe defined benefit plan, offset by a liability of $76 million for supplementalpension benefits. Supplemental pension benefits are funded from our operatingcash flows and backed with an irrevocable letter of credit. Canexus hasunfunded pension obligations of $12 million and our share of the unfundedpension obligation for Syncrude is $56 million.

 

·                  We have excluded obligations onour tandem option and stock appreciation rights programs as the amount andtiming of cash payments are not determinable.

 

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·                  We have excluded our normalpurchase arrangements as they are discretionary and are reflected in ourexpected cash flow from operating activities and capital expenditures for 2010.

·                  We have excluded our futureincome tax liabilities as the amount and timing of any cash payment for incometaxes is based on taxable income for each fiscal year in the variousjurisdictions 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 enter into contracts that require us toindemnify parties against certain possible claims, particularly when these contractsrelate to the sale of assets. On occasion, we provide indemnifications to thepurchaser. Generally, a maximum obligation is not stated; therefore, theoverall maximum amount cannot be reasonably estimated. We have not made anysignificant payments related to these indemnifications. We believe existingindemnifications would not have a material adverse effect on our liquidity,financial condition or results of operations.

 

**Credit Ratings**

 

Currently, our senior debt is rated BBB by Dominion Bond RatingService (DBRS), Baa3 by Moody’s Investor Service, Inc. (Moody’s), and BBB- byStandard & Poor’s (S&P). DBRS, Moody’s and S&P all currently rateour outlook as stable. We believe our financial results, ample liquidity andfinancial flexibility continue to support our credit ratings.

 

**Financial Assurance Provisions in Commercial Contracts**

 

The commercial agreements our energy marketing group entersinto often include financial assurance provisions that allow Nexen and ourcounterparties to effectively manage credit risk. The agreements normallyrequire collateral to be posted if an adverse credit-related event, such as adrop in credit ratings, occurs. Based on contracts in place and commodityprices at December 31, 2009, if we were downgraded to non-investment grade wecould be required to post collateral of up to $962 million, which we expect wewould be able to manage down. These obligations are reflected on our balancesheet and are expected to decrease over the next couple of years with therationalization of our marketing business. The posting of collateral merelyaccelerates the payment of such amounts and lowers our available liquidity.Just as we may be required to post collateral if we were downgraded belowinvestment grade, we have similar provisions in many of our contracts thatallow us to demand certain counterparties post collateral for amounts they oweus if they are downgraded to non-investment grade.

 

**Off-Balance Sheet Arrangements**

 

We have no off-balance sheet arrangements that would have a materialadverse effect on our liquidity, consolidated financial position or results ofoperations. We use operating leases in the normal course of business asdisclosed in Contractual Obligations, Commitments and Guarantees in Note 15 tothe Consolidated Financial Statements, which is incorporated herein byreference.

 

At December 31, 2009, we had outstanding letters of creditsupported by $407 million (US$389 million) of unsecured term credit facilitiesand $86 million (US$82 million) of uncommitted unsecured credit facilities.

 

**Contingencies**

 

We have no contingencies that would have a material adverseeffect on our liquidity, consolidated financial position or results ofoperations. See Note 15 to the Consolidated Financial Statements, which isincorporated herein by reference for a discussion of our contingencies.

 

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**CRITICALACCOUNTING ESTIMATES**

 

We make estimates and assumptions that affect: i) thereported amounts of our assets and liabilities; ii) the disclosure ofcontingent assets and liabilities at the date of the Consolidated FinancialStatements; and iii) our revenues and expenses during the reporting period. Ourmanagement review these estimates, including those related to accruals,litigation, environmental and asset retirement obligations, recoverability ofassets, income taxes, fair values of derivative assets and liabilities, capitaladequacy, and the estimation of reserves on an ongoing basis. Changes in factsand circumstances may result in revised estimates and actual results may differfrom these estimates. Our critical accounting estimates are discussed below.

 

**Oil and Gas Accounting—Reserves Determination**

 

We follow the successful efforts method of accounting for ouroil and gas activities, as described in Note 1 to our Consolidated FinancialStatements. Successful efforts accounting depends on the estimated remainingreserves. The process of estimating reserves requires complex judgements anddecision-making based on available geological, geophysical, engineering andeconomic data. To estimate the economically recoverable oil and gas reservesand related future net cash flows, we consider many factors and make variousassumptions. Refer to the Basis of Reserves Estimates on page 29 for adescription of our process for estimating reserves.

 

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

 

·                  determining whether or not anexploratory well has found economically producible reserves. If successful, wecapitalize the costs of the well, and if not, we expense the costs immediately.In 2009, $115 million of our total $445 million spent on exploration drillingwas expensed. If none of our exploration drilling had been successful, our netincome would have decreased by $204 million, net of income tax;

·                  calculating ourunit-of-production depletion rates. Both proved and proved developed reservesestimates are used to determine rates that are applied to eachunit-of-production in calculating our depletion expense. Proved reserves areused where a property is acquired and proved developed reserves are used wherea property is drilled and developed. In 2009, oil and gas depletion of $1,425million (before impairments) was recorded in depletion, depreciation,amortization and impairment expense. If our proved reserves estimates changedby 10%, our depletion, depreciation, amortization and impairment expense wouldhave changed by approximately $143 million, assuming no other changes to ourreserves profiles; and

·                  assessing, when necessary, ouroil and gas assets for impairment. Estimated future undiscounted cash flows aredetermined using proved reserves. The critical estimates used to assessimpairment, including the impact of changes in reserves estimates, arediscussed below.

 

Since we do not have any loan covenants directly linked toreserves, it would take a significant decrease in our proved reserves to limitour ability to borrow money under our term credit facilities, as previouslydescribed in the Liquidity section of the MD&A.

 

**Impairments**

 

**PROPERTY, PLANT AND EQUIPMENT**

 

We evaluate our long-lived assets 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 assets to determine if they are impaired. If theundiscounted future cash flow for an asset is less than the carrying amount ofthat asset, we estimate its fair value using a discounted cash flow model.

 

Cash flow estimates for our impairment assessments requireassumptions about the following primary elements—future prices and costs,reserves and discount rates. Our estimates of future prices are based on ourassumptions of long-term prices and operating and development costs and requiresignificant judgments about highly uncertain future events. Historically, oiland gas prices have exhibited significant volatility—over the last five years,

 

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prices for WTI and NYMEX gas have ranged from US$32/bbl toUS$147/bbl and US$2.41/mmbtu to US$15.38/mmbtu, respectively. Our forecasts foroil and gas revenues are based on prices derived from a consensus of futureprice forecasts amongst industry analysts, our own assessments and existingfuture strip prices. Our estimates of discount rates include consideration ofthe marketplace and risk of the asset. Given the significant assumptionsrequired and the possibility that actual conditions will differ, we considerthe assessment of impairment to be a critical accounting estimate. A change inthese estimates would impact all our businesses with the exception of chemicalsand energy marketing.

 

It is difficult to determine and assess how a decrease inproved reserves impacts our impairment tests. The relationship between ourreserve estimate and the estimated undiscounted cash flows, and the nature ofthe property-by-property impairment test is complex. As a result, we are unableto provide a reasonable sensitivity analysis of the impact that a reserveestimate decrease would have on our assessment of impairment.

 

**GOODWILL**

 

We test goodwill for impairment whenever an event orcircumstance occurs that may reduce the fair value of a reporting unit belowits carrying amount and at least annually. Our goodwill impairment testcompares the estimated fair value of a reporting unit with its carrying amount,including goodwill. If the carrying amount of the reporting unit exceeds thefair value, the goodwill is considered impaired. To measure the amount ofimpairment, we allocate the estimated fair value to the underlying assets andliabilities, resulting in an implied fair value of goodwill. If the carryingamount of the goodwill exceeds the implied fair value, an impairment loss equalto the excess is included in net income.

 

The process of assessing goodwill for impairment requires usto estimate the fair values of our assets using one or more valuationtechniques including present value calculations of estimated future cash flows.This process involves making various assumptions and judgments about futurecommodity prices, future activity levels, operating costs and discount rates.Changes in any of these assumptions or judgments could result in an impairmentof all or a portion of goodwill.

 

**Asset Retirement Obligations**

 

We are required to remove or remedy the effect of ouractivities on the environment at our present and former operating sites bydismantling and removing production facilities and remediating any damagecaused. In estimating our future asset retirement obligations, we must makeestimates and judgments on activities that will occur many years into thefuture. Additionally, contracts and regulations are often vague and unclear asto what constitutes removal and remediation. Furthermore, the ultimatefinancial impact is not always clearly known and cannot be reasonably estimatedas asset removal and remediation techniques and costs are constantly changing,as are legal, regulatory, environmental, political, safety and other suchconsiderations.

 

We record asset retirement obligations in our ConsolidatedFinancial Statements by discounting the future value of the estimatedretirement obligations associated with our oil and gas wells and facilities andchemical plants. In arriving at amounts recorded, numerous assumptions andjudgments are made on ultimate settlement amounts, inflation factors,credit-adjusted discount rates, timing of settlement and expected changes inlegal, regulatory, environmental, political and safety environments. The assetretirement obligations we record increase the carrying cost of our property,plant and equipment and accretes with the passage of time.

 

A change in any one of our assumptions could impact our assetretirement obligations, the carrying value of our property, plant and equipmentand our DD&A expense.

 

**Income Taxes**

 

We follow the liability method of accounting for income taxeswhereby future income tax assets and liabilities are recognized based ontemporary differences in reported amounts for financial statement and incometax purposes. We carry on business in several countries and as a result, we aresubject to income taxes in numerous jurisdictions. The determination of currentincome tax is inherently complex, interpretations will vary and we are requiredto make certain judgments. Our income tax filings are subject to audits andreassessments and we believe we have adequately provided for all income taxobligations. However, changes

 

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in facts, circumstances and interpretations as a result ofincome tax audits, reassessments, jurisprudence and any new legislation mayresult in an increase or decrease in our provision for income taxes.

 

**Derivatives and Fair Value Measurements**

 

We enter into contracts to purchase and sell crude oil andnatural gas and use derivative contracts, including futures, forwards, swapsand options, for hedging and trading purposes (collectively derivatives). Wealso use derivatives to manage commodity price risk and foreign currency riskfor non-trading purposes.

 

The fair value of derivative contracts is estimated. Whereverpossible, this estimate is based on quoted market prices, and if not available,on estimates from third-party brokers. We classify the fair value of ourderivatives according to a three-level hierarchy based on the amount ofobservable inputs used to value the instruments. Inputs may be: i) readilyobservable; ii) market corroborated; or iii) generally unobservable. We utilizevaluation techniques that maximize the use of observable inputs whereverpossible and minimize the use of unobservable inputs. Another significantassumption that we use in determining the fair value of derivatives is marketdata or assumptions that market participants would use when pricing the assetor liability, including assumptions about risk. Additionally, we utilize amid-market pricing convention between bid and ask and then adjust our pricingto the ask price when we have a net open sell position and the bid price whenwe have a net open buy position. We incorporate the credit risk associated withcounterparty default into our estimates of fair value.

 

Our assessment of the significance of a particular input tothe fair value measurement may affect the valuation of fair value within thehierarchy. Also for derivative contracts, the time between inception andsettlement of the contract may affect fair value. The actual settlement ofderivatives could differ materially from the fair value recorded and could impactfuture operating results. We performed a sensitivity analysis of inputs used tocalculate the fair value of the instruments that are based on unobservableinputs. Using reasonably possible alternative assumptions, the fair value ofthese instruments would be change by $12 million (before tax).

 

**NEWACCOUNTING PRONOUNCEMENTS**

 

**International Financial Reporting Standards Adoption Plan**

 

We are required to adopt International Financial ReportingStandards (IFRS) for our interim and annual financial reporting purposesbeginning January 1, 2011. A project team, consisting of dedicated andexperienced personnel who have IFRS knowledge, has been set up to manage thistransition and to ensure successful implementation within the requiredtimeframe.

 

A steering committee comprised of senior management has beenestablished for project oversight. The steering committee has theresponsibility to ensure the project is adequately planned in sufficientdetail, appropriate resources are made available, necessary milestones areestablished and project progress is properly monitored. These senior leadersare also responsible for internal controls over financial reporting and ourdisclosure controls and procedures. The audit and conduct review committee ofthe board of directors regularly receives progress reporting on the status ofthe IFRS transition project and training of IFRS principles.

 

Our project consists of five phases: diagnostic, design andplan, develop solution, implementation, and closeout. We are currently in theImplementation phase where we are making the necessary changes to businessprocesses, financial reporting and supporting information technology systems toallow us to capture and report on IFRS financial information throughout 2010and onwards.

 

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Project activities and key milestones are documented in thefollowing chart:

 

| **Key Activity**                                                                                                                                                                                                                                                                                              | ** ** | **Key  Milestone**                                                                                                                                                                                                                        | ** ** | **Status**                                                                                                                                                                                                                                                                                                                       |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                                                                                                                                                                                                                                                                                          |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
| **Financial  Information**                                                                                                                                                                                                                                                                                    |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
|                                                                                                                                                                                                                                                                                                          |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
| ·  Identify  differences between Canadian GAAP and IFRS

·  Revise  accounting policies under IFRS

·  Identify  potential adjustments to initial IFRS financial statements

·  Develop IFRS  compliant financial statements, including transition period disclosures |       | ·  Comprehensive  analysis of IFRS differences identified in the diagnostics phase

·  Senior  management approval of IFRS accounting policies

·  Develop draft  IFRS financial statements and disclosures |       | ·  Comprehensive  analysis completed mid 2009

·  Received  senior management approval of IFRS accounting policies

·  Areas of  potential adjustment to opening balance sheet have been identified

·  Draft IFRS  financial statements and note disclosures are substantially complete |
|                                                                                                                                                                                                                                                                                                          |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
| **Training  and Communication**                                                                                                                                                                                                                                                                               |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
|                                                                                                                                                                                                                                                                                                          |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
| ·  Develop and  deliver targeted IFRS training to employees and management 

·  Ensure  internal and external stakeholders receive ongoing appropriate communications  

·  Develop and  deliver targeted IFRS training to senior management and board of directors             |       | ·  Delivery of training  in 2009 targeted to affected employees

·  Ongoing  communication with major internal and external stakeholders                                                                              |       | ·  Targeted  training completed in 2009 

·  Strategy for  follow-up training in 2010 developed

·  Regular  communication with Project Steering Committee, senior management and Audit  Committee throughout the year

·  Quarterly  disclosure of project status in MD&A           |
|                                                                                                                                                                                                                                                                                                          |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
| **Information  Technology**                                                                                                                                                                                                                                                                                   |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
|                                                                                                                                                                                                                                                                                                          |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
| ·  Ensure  systems are able to adequately support conversion to IFRS and ongoing  financial reporting                                                                                                                                                                                               |       | ·  Be IFRS data  capture ready January 1, 2010 

·  Ensure dual  GAAP reporting capability throughout 2010                                                                                                            |       | ·  System  testing for IFRS data capture complete

·  Dual GAAP  reporting capability testing complete                                                                                                                                                                                                       |
|                                                                                                                                                                                                                                                                                                          |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
| **Business  Process**                                                                                                                                                                                                                                                                                         |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
|                                                                                                                                                                                                                                                                                                          |       |                                                                                                                                                                                                                                      |       |                                                                                                                                                                                                                                                                                                                             |
| ·  Ensure business processes and control environment properly  support conversion to IFRS and ongoing financial reporting                                                                                                                                                                           |       | ·  Implement necessary business process and key control changes to  ensure adequate internal control over financial reporting                                                                                                   |       | ·  Necessary  changes to business process have been designed

·  Key controls  designed to ensure adequate internal control over financial reporting on IFRS  results throughout 2010                                                                                                                        |

 

**Summary of Accounting Differences between Canadian GAAP and IFRS**

 

We determined that the majority of our existing Canadian GAAPoil and gas accounting policies are acceptable under IFRS. However, detailedanalysis has identified differences, the most significant of which will impactcertain aspects of our accounting for property, plant and equipment, assetretirement obligations, impairments of assets and share-based payments.

 

**PROPERTY, PLANT AND EQUIPMENT**

 

Significant components of property, plant and equipment withdifferent useful lives must be accounted for and depreciated separately.Instances of major maintenance, turnarounds or inspections must also becapitalized and depreciated until the next scheduled major maintenanceactivity. Our current policy is to expense these items unless they result inimprovements that increase capacity or extend the useful life. We anticipatethat retrospective application of these concepts will have an affect on theaccumulated depreciation balance on transition for certain of our assets withlarge production and processing facilities.

 

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**ASSET RETIREMENT OBLIGATIONS**

 

There are differences in the calculation methodology fordetermining asset retirement obligations, which are expected to affect theobligations recorded in all of our operating areas. These obligations will berecalculated and asset retirement obligations and property, plant and equipmentbalances will be adjusted on the transition date.

 

**IMPAIRMENT OF ASSETS**

 

IFRS does not require a cost recoverability test when testinglong-lived assets for impairment. Consequently, it is possible that we may havemore impairments where carrying values of assets were previously supportedunder Canadian GAAP on an undiscounted cash flow basis, but could not besupported on a discounted cash flow basis under IFRS. However, the extent offuture impairments under IFRS may be partially offset by potential reversals ofprevious impairment losses where circumstances that gave rise to the impairmentreverses.

 

**SHARE-BASED PAYMENTS**

 

We currently use the intrinsic method to account for ourcash-settled stock-based compensation. We expect that the IFRS requirement tovalue stock-based compensation at fair value each reporting period may resultin less volatility in our reported earnings each period. We expect to use afair value model such as Black-Scholes to value our stock-based compensationeach period.

 

**ONE TIME ADJUSTMENTS ON TRANSITION TO IFRS**

 

IFRS allows certain adjustments to financial information ontransition where retrospective restatement would either be onerous or would notprovide more useful information. We expect to make one-time transitionaladjustments on January 1, 2010 to our defined benefit pension obligations toreflect previously unrecognized actuarial losses and to other comprehensiveincome to reclassify accumulated foreign exchange gains and losses directly toretained earnings.

 

At this time, we cannot quantify the impact that the adoptionof IFRS will have on our future results of operations or financial position.Additional disclosure of the key elements of our plan and progress on theproject will be provided as we move toward the changeover date.

 

We continue to monitor the development of new standards andany changes will be incorporated as required.

 

In recent years, the CICA has issued standards with theintent to converge with IFRS to facilitate the transition in 2011. As a result,the majority of our current Canadian GAAP accounting policies are acceptable underIFRS.

 

As a foreign private issuer in the US, we are permitted tofile financial statements prepared under IFRS without reconciliation to US GAAPwith the SEC. Effective January 1, 2011, we will adopt IFRS as our basis foraccounting. The impact of this change is that we will no longer prepare areconciliation of our results to US GAAP. It is possible that certain of ouraccounting policies under IFRS could be different from US GAAP, but we expectthat most accounting policies will remain consistent or converge with US GAAPas the International Accounting Standards Board (IASB) and the FinancialAccounting Standards Board (FASB) undertake joint projects.

 

**US Pronouncements**

 

In June 2009, FASB issued *Amendmentsto Consolidation of Variable Interest Entities.* Itretains the scope of the previous guidance with the addition of entitiespreviously considered qualifying special-purpose entities and eliminates theprevious quantitative approach for a qualitative analysis in determiningwhether the enterprise’s variable interest or interests give it a controllingfinancial interest in a variable interest entity. The statement is furtheramended to require ongoing reassessments of whether an enterprise is theprimary beneficiary of a variable interest entity and requires enhanceddisclosures about an enterprise’s involvement in a variable interest entity.The standard is effective at the

 

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beginning of the first annual reporting period after November15, 2009. We do not expect the adoption of this standard to have a materialimpact on our results of operations or financial position.

 

On January 6, 2010, FASB issued guidance for *Oil and Gas Reserve Estimation and Disclosure,*which is effective for the year ended December 31, 2009. The guidance expandsthe definition of oil and gas producing activities to include unconventionalsources such as oil sands, changes the price used in reserve estimation fromthe year-end December 31 price to the simple average of the first day of themonth price for the previous 12 months, and requires disclosures for geographicareas which represent 15% or more of proved reserves. The information requiredby this standard has been included in the unaudited supplementary data in item8.

 

We follow the successful efforts method of accounting for ouroil and gas activities, which depends on the estimated reserves we believe arerecoverable from our oil and gas properties. Specifically, reserves estimatesare used to calculate our unit-of-production depletion rates and to assess ouroil and gas assets for impairment, when necessary. Adoption of these amendmentsat December 31, 2009 did not have an impact on our results of operations orfinancial position.

 

**ITEM 7A.**

 

**Quantitative and Qualitative Disclosures aboutMarket Risk**

 

We are exposed to normal market risks inherent in the oil andgas, energy marketing and chemicals businesses, including commodity price risk,foreign-currency rate risk, interest rate risk and credit risk. We recognizethese risks and manage our operations to minimize our exposures to the extentpractical.

 

**NON-TRADING**

 

**Commodity Price Risk**

 

Commodity price risk related to conventional and syntheticcrude oil prices is our most significant market risk exposure. Crude oil andnatural gas prices are sensitive to numerous worldwide factors, including thecurrent global financial crisis, many of which are beyond our control, and aregenerally sold at contract or posted prices. Changes in world crude oil andnatural gas prices may significantly affect our results of operations and cashgenerated from operating activities. Consequently, such prices also may affectthe value of our oil and gas properties and our level of spending forexploration and development.

 

Our crude oil prices are based on various reference prices,primarily WTI and Brent and other prices which generally track the movement ofWTI and Brent. Adjustments are made to the reference prices to reflect qualitydifferentials and transportation. WTI, Brent and other international referenceprices are affected by numerous and complex worldwide factors such as supplyand demand fundamentals, economic outlooks, production quotas set by theOrganization of Petroleum Exporting Countries and political events. Qualitydifferentials are affected by local supply and demand factors.

 

We are also exposed to natural gas price movements. Naturalgas prices are generally influenced by oil prices and supply and demandfundamentals, and to a lesser extent local market conditions.

 

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In 2009, WTI averaged US$61.80/bbl, reaching a high ofUS$82/bbl and a low of US$32/bbl. Dated Brent, on which approximately 60% ofour production is priced, averaged US$61.51/bbl, reaching a high of US$78/bbland a low of US$39/bbl. NYMEX natural gas prices averaged US$4.16/mmbtu in2009, reaching a high of US$6.24/mmbtu and a low of US$2.41/mmbtu. Oursensitivities to commodity prices and the expected impact on our 2010 cash flowfrom operating activities and net income are as follows:

 
| **(Cdn$ millions)**                  | ** ** | **Cash  Flow** | ** ** | **Net  Income** | ** ** |
|-------------------------------------------|------------|----------------|------------|-----------------|------------|
| WTI—US$1/bbl change above US$50      |       | 47             |       | 45              |       |
| WTI—US$1/bbl change below US$501     |       | 30             |       | 27              |       |
| NYMEX Natural Gas—US$0.50/mcf change |       | 28             |       | 19              |       |

 

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*1**                **Putoptions mitigate the impact of a price decline below US$50 WTI (based on 90,000puts).*

 

These sensitivities are based on our estimated 2010 oil andgas production and assume a US/Canadian dollar exchange rate of $0.90. Ourestimated oil and gas production range for 2010 is between 230,000 and 280,000boe/d before royalties, of which approximately 15% is gas.

 

The majority of our oil and gas production is sold undershort-term contracts, exposing us to short-term price movements. Other energycontracts we enter into also expose us to commodity price risk between the timewe purchase and sell contracted volumes. From time to time, we actively managethese risks by using commodity futures, forwards, swaps and options.

 

In 2009, we purchased WTI put options to manage the commodityprice risk exposure on a portion of our oil production in 2010. These putoptions have established an annual average WTI floor price of US$50/bbl onabout 90,000 bbls/d of production.

 

**Foreign Currency Risk**

 

A substantial portion ofour activities are transacted in or referenced to US dollars including:

 

·                  sales of crude oil, natural gasand certain chemicals products;

·                  capital spending and expensesfor our oil and gas and chemicals operations; and

·                  short-term and long-termborrowings.

 

The US/Canadian dollar exchange rate averaged $0.88 in 2009,ranging from a low of $0.77 to a high of $0.97.

 

Our sensitivities to the US dollar and the expected impact ofa one cent change on our 2010 cash flow from operating activities, net income,capital expenditures and long-term debt are as follows:

 
| **(Cdn$ millions)**  | ** ** | **Cash  Flow** | ** ** | **Net  Income** | ** ** | **Capital  Expenditures** | ** ** | **Long-term  Debt** | ** ** |
|---------------------------|------------|----------------|------------|-----------------|------------|---------------------------|------------|---------------------|------------|
| $0.01 Change in US to Cdn |       | 35             |       | 20              |       | 20                        |       | 60                  |       |

 

Our sensitivities to changes in the US/Canadian dollarexchange rate are calculated based on projected revenues, expenses, capitalexpenditures and US-dollar denominated long-term debt for 2010. These estimatesare based on a WTI price of US$70/bbl, a NYMEX natural gas price ofUS$5.50/mmbtu and a US/Canadian dollar exchange rate of $0.90.

 

We manage our exposure to fluctuations between the US and Canadiandollar by matching our expected net cash flows and borrowings in the samecurrency. Net revenue from our foreign operations and our US-dollar borrowingsare generally used to fund US-dollar capital expenditures and debt repayments.We maintain revolving Canadian and US-dollar borrowing facilities that can beused or repaid depending on expected net cash flows. We designate most of ourUS-dollar borrowings as a hedge against our US-dollar net investment inself-sustaining foreign operations.

 

Our chemicals operationsare exposed to changes in the US-dollar exchange rate as part of their salesare denominated in US dollars. Canexus periodically purchases US-dollar calloptions to reduce this exposure and at December 31, 2009 had the followingoutstanding option contracts:

 

·                  the right to sell US$5 millionmonthly and purchase Canadian dollars at an exchange rate of US$0.9479 from January1, 2010 to March 31, 2010; and

·                  the right to sell US$5 millionmonthly and purchase Canadian dollars at an exchange rate of US$0.9302 from January1, 2010 to June 30, 2010.

 

We do not have any material exposure to highly inflationaryforeign currencies.

 

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**Interest Rate Risk**

 

We are exposed to fluctuations in interest rates on ourfloating-rate debt.

 

Our sensitivity to interest rates and the expected impact ofa 1% change in interest rates on our 2010 cash flow from operating activitiesand net income is as follows:

 
| **(Cdn$ millions)**               | ** ** | **Cash  Flow** | ** ** | **Net  Income** | ** ** |
|----------------------------------------|------------|----------------|------------|-----------------|------------|
| Interest Rates—1% change in rates |       | 16             |       | 12              |       |

 

Our sensitivity to changes in interest rates is based on 2010estimated average floating-rate debt of $1.6 billion and a US/Canadian dollarexchange rate of $0.90.

 

Our floating-rate debt exposes us to changes in interestpayments as interest rates fluctuate. To manage this exposure, we maintain acombination of fixed and floating-rate borrowings and facilities. At December 31,2009, fixed-rate borrowings comprised 75% (2008—78%) of our long-term debt atan effective average rate of 6.4% (2008—6.4%). During the year, we periodicallyborrow under our committed, unsecured, term credit facilities and at December 31,2009, floating-rate debt comprised 25% (2008—22%) of our long-term debt at aneffective average rate of 1.02% (2008—2.7%) ranging from a low of 0.91% to ahigh of 1.22% during 2009.

 

**TRADING**

 

**Commodity Price Risk**

 

Our marketing business is focused on providing services toour customers and suppliers to meet their energy commodity needs. We market andtrade physical energy commodities in selected regions of the globe includingcrude oil, natural gas, electricity and other commodities. We do this by buyingand selling physical commodities, by acquiring and holding rights to physicaltransportation and storage assets for these commodities, and by building strongrelationships with our customers and suppliers.

 

In order to manage the commodity and foreign exchange pricerisks that come from this physical business, we use financial derivativecontracts including energy-related futures, forwards, swaps and options, aswell as currency swaps or forwards.

 

We also seek to profit from our views on the future directionof energy commodity pricing relationships, primarily between differentlocations, time periods or qualities. We do this by holding open positions,where the terms of physical or financial contracts are not completely matchedto offsetting positions. We may also carry exposures to the absolute change incommodity prices based on our market views or as a consequence of managing ourphysical and financial positions on a day-to-day basis.

 

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

 

·                  changes in the prices ofcommodities at specific locations;

·                  changes in the relative levelof nearer term prices to future prices;

·                  changes in the relative valueof different qualities of a commodity;

·                  changes in the volatility ofcommodity prices;

·                  changes in the relationshipsbetween energy commodity prices and/or derivative instruments;

·                  changes in the operationalcosts of our physical transportation and storage contracts;

·                  physical or financial loss ofphysical product; and

·                  disputes over terms of dealsand contracts.

 

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In order to manage these risks we have risk managementsystems and processes including:

 

·                  reporting to the Board ofDirectors;

·                  reporting to the Executive RiskManagement Committee;

·                  oversight of activities byexperienced commercial management;

·                  a separate Risk ManagementOffice; 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 areeither normally or “T” distributed;

·                  price volatility remainsstable; and

·                  price correlation relationshipsremain stable.

 

We have defined VaR limits for different segments of ourbusiness. These limits are calculated on an economic basis and include physicaland financial derivatives, as well as physical transportation and storagecapacity contracts accounted for as executory contracts in our financialstatements. We monitor and report our positions against these VaR limits daily.Our year end, annual high, annual low and average VaR amounts are as follows:

 
| **(Cdn$ millions)** | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------|------------|----------|------------|----------|------------|----------|------------|
| **Value-at-Risk**        |       |     |       |     |       |     |       |
| Year End                 |       | 11       |       | 25       |       | 26       |       |
| High                     |       | 24       |       | 40       |       | 38       |       |
| Low                      |       | 9        |       | 19       |       | 24       |       |
| Average                  |       | 15       |       | 30       |       | 30       |       |

 

If a market shock occurred as in 2008, the key assumptionsunderlying our VaR estimate could be exceeded and the potential loss could begreater than our estimate. We perform stress tests on a regular basis tocomplement VaR and assess the impact of non-normal changes in prices on ourpositions.

 

Throughout the second half of 2008 and into 2009, werealigned our marketing strategies and positions to focus on physicalbusinesses which had been built around storage, blending and transportation. Tothis end, we reduced our trading levels in an orderly fashion recognizing thechallenging economic environment. We exited trading positions that do notsupport our physical business.

 

**CREDIT RISK**

 

Credit risk affects bothour trading and non-trading activities and is the risk of loss if counterpartiesdo not 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 72% 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 strengthof our counterparties through a formal credit process;

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

·                  routinely monitor credit riskexposures, including sector, geographic and corporate concentrations of credit,and report these to our Executive Risk Management Committee and the FinanceCommittee of the board;

·                  set credit limits based onrating agency credit ratings and internal assessments based on company andindustry analysis;

·                  review counterparty creditlimits regularly; and

·                  use standard agreements thatallow for the netting of exposures associated with a single counterparty.

 

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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 2008and 2009, we have taken the following specific actions for certaincounterparties deemed to be at higher risk of non-performance:

 

·                  ceased trading activities;

·                  significantly reduced and, insome 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 andmargining requirements where possible.

 

At December 31, 2009, only one counterparty individually madeup more than 10% of our credit exposure. This counterparty is a majorintegrated oil company with a strong investment grade rating. One othercounterparty made up more than 5% of our credit exposure. In addition, thefollowing table illustrates the composition of credit exposure by creditrating.

 
| **Credit Rating**    | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------|------------|----------|------------|----------|------------|
| A or Higher          |       | 67       | %          | 65       | %          |
| BBB                  |       | 26       | %          | 29       | %          |
| Non-investment Grade |       | 7        | %          | 6        | %          |

 

Our maximum counterparty credit exposure at the balance sheetdate consists primarily of the carrying amounts of non-derivative financialassets such as cash and cash equivalents, restricted cash, accounts receivable,as well as the fair value of derivative financial assets. We have provided anallowance of $54 million for credit risk with our counterparties. In addition,we incorporate the credit risk associated with counterparty default, as well asour own credit risk, into our estimates of fair value.

 

**SPECIAL NOTEREGARDING FORWARD-LOOKING STATEMENTS**

 

Certain statements inthis report, including those appearing in *Items 1 and2—Business and Properties* and *Item 7—Management’sDiscussion and Analysis of Financial Condition and Results of Operations*,constitute “forward-looking statements” (within the meaning of the UnitedStates *Private Securities Litigation Reform Act*of 1995, as amended) or “forward-looking information” (within the meaning ofapplicable Canadian securities legislation). Such statements or information(together “forward-looking statements”) are generally identifiable by theforward-looking terminology used such as “anticipate”, “believe”, “intend”, “plan”,“expect”, “estimate”, “budget”, “outlook”, “forecast” or other similar wordsand include statements relating to or associated with individual wells, regionsor projects. Any statements regarding the following are forward-lookingstatements:

 

·                  future crude oil, natural gasor chemical prices;

·                  future production levels;

·                  future capital expenditures andtheir allocation to exploration and development activities;

·                  future earnings;

·                  future asset acquisitions ordispositions;

·                  future sources of funding forour capital program;

·                  future debt levels;

·                  availability of committedcredit facilities;

·                  possible commerciality;

·                  development plans or capacityexpansions;

·                  future ability to executedispositions of assets or businesses;

·                  future sources of liquidity,cash flows and their uses;

·                  future drilling of new wells;

·                  ultimate recoverability ofcurrent and long-term assets;

·                  ultimate recoverability ofreserves or resources;

·                  expected finding anddevelopment costs;

·                  expected operating costs;

·                  future demand for chemicalproducts;

 

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·                  estimates on a per share basis;

·                  future foreign currencyexchange rates;

·                  future expenditures and futureallowances relating to environmental matters;

·                  dates by which certain areaswill be developed or will come on stream or reach expected operating capacity;and

·                  changes in any of theforegoing.

 

Statements relating to “reserves” or “resources” areforward-looking statements, as they involve the implied assessment, based onestimates and assumptions that the reserves and resources described exist inthe quantities predicted or estimated, and can be profitably produced in thefuture.

 

The forward-looking statements are subject to known and unknownrisks and uncertainties and other factors which may cause actual results,levels of activity and achievements to differ materially from those expressedor implied by such statements. Such factors include, among others:

 

·                  market prices for oil and gasand chemical products;

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

·                  ultimate effectiveness ofdesign or design modification to facilities;

·                  the results of exploration and developmentdrilling and related activities;

·                  volatility in energy tradingmarkets;

·                  foreign-currency exchangerates;

·                  economic conditions in thecountries and regions in which we carry on business;

·                  governmental actions includingchanges to taxes or royalties, changes in environmental and other laws andregulations;

·                  renegotiations of contracts;

·                  results of litigation,arbitration or regulatory proceedings; and

·                  political uncertainty,including actions by terrorists, insurgent or other groups, or other armedconflict, including conflict between states.

 

These risks, uncertainties and other factors and theirpossible impact are discussed more fully in the section titled *RiskFactors* in Item 1A and *Quantitativeand Qualitative Disclosures about Market Risk* in Item7A. The impact of any one risk, uncertainty or factor on a particularforward-looking statement is not determinable with certainty as these factorsare interdependent, and management’s future course of action would depend onour assessment of all information at that time.

 

Although we believe that the expectations conveyed by theforward-looking statements are reasonable based on information available to uson the date such forward-looking statements were made, no assurances can begiven as to future results, levels of activity and achievements. Undue relianceshould not be placed on the statements contained herein, which are made as ofthe date hereof and, except as required by law, we undertake no obligation toupdate publicly or revise any forward-looking statements, whether as a resultof new information, future events or otherwise. The forward-looking statementscontained herein are expressly qualified by this cautionary statement.

 

**SPECIAL NOTETO CANADIAN INVESTORS**

 

Nexen is an SEC registrantand a voluntary Form 10-K (and related forms) filer. Therefore, our reservesestimates and securities regulatory disclosures follow SEC requirements. InCanada, *NI 51-101*—*Standards of Disclosure for Oil and Gas Activities*prescribes that Canadian companies follow certain standards for the preparationand disclosure of reserves and related information. Nexen reserves disclosuresare made in reliance upon exemptions granted to Nexen by Canadian securitiesregulators from certain requirements of NI 51-101 which permits us to:

 

·                  prepare our reserves estimatesand related disclosures in accordance with SEC disclosure requirements,generally accepted industry practices in the US and the *Canadian Oiland Gas Evaluation Handbook* (COGE Handbook) standardsmodified to reflect SEC requirements;

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

·                  rely upon internally-generatedreserves estimates and the *Standardized Measure of Discounted FutureNet Cash Flows and Changes Therein*, included in theSupplementary Financial Information, without the requirement to have thoseestimates evaluated or audited by independent qualified reserves consultants.

 

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

·                  the SEC’s technical rulesin estimating reserves differ from NI 51-101 in areas such as the use ofreliable technology, aerial extent around a drilled location, quantities belowthe lowest known oil and quantities across an undrilled fault block;

·                  the SEC mandates disclosure ofproved reserves and the Standardized Measure of Discounted Future Net CashFlows and Changes Therein calculated using the year’s 12-month average pricesand costs held constant whereas NI 51-101 requires disclosure of reserves andrelated future net revenues using forecast prices;

·                  the SEC mandates disclosure ofreserves by geographic area whereas NI 51-101 requires disclosure of morereserve categories and product types;

·                  the SEC prescribes certaininformation about proved and probable undeveloped reserves and futuredevelopment costs whereas NI 51-101 requirements are different;

·                  the SEC does not requiredisclosure of finding and development (F&D) costs per boe of proved reservesadditions whereas NI 51-101 requires that various F&D costs per boe andadditional information be disclosed;

·                  the SEC leaves the engagementof independent qualified reserves consultants to the discretion of a company’sboard of directors whereas NI 51-101 requires issuers to engage suchevaluators;

·                  the SEC does not allow provedand probable reserves to be aggregated whereas NI 51-101 requires issuers todisclose such; and

·                  the reserves disclosures inthis document have not been reviewed by the independent qualified reservesconsultants whereas NI 51-101 requires them to review it.

 

The foregoing is a general description of the principaldifferences only. The differences between SEC requirements and NI 51-101 may bematerial.

 

NI 51-101 requires thatwe make the following disclosures:

 

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

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

 

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| Part II *(continued)*                                                               |   |
|-----------------------------------------------------------------------------------------------|--------|
|                                                                                          |   |
| Item 8                                                                                        |   |
| Report of  Management                                                                         | 99     |
| Report  of Independent Registered Chartered Accountants                                       | 100    |
| Consolidated Financial statements                                                             |   |
| Consolidated  Statement of Income                                                             | 101    |
| Consolidated  Balance Sheet                                                                   | 102    |
| Consolidated  Statement of Cash Flows                                                         | 103    |
| Consolidated  Statement of Equity                                                             | 104    |
| Consolidated  Statement of Comprehensive Income                                               | 105    |
| Notes to Consolidated Financial Statements                                                    | 106    |
| Supplementary Data (Unaudited)                                                                |   |
| Quarterly Financial Data in Accordance with Canadian  and US GAAP                             | 150    |
| Oil and Gas Producing Activities (Unaudited)                                                  | 151    |
|                                                                                          |   |
| Item 9: Changes in and Disagreements  with Accountants on Accounting and Financial Disclosure | 158    |
|                                                                                          |   |
| Item 9A:  Controls and Procedures                                                             |   |
| Evaluation of Disclosure Controls and Procedures                                              | 158    |
| Management’s Report on Internal Control Over Financial  Reporting                        | 159    |
| Changes in Internal Controls                                                                  | 159    |
| Report of Independent Registered Chartered Accountants                                        | 159    |

 

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**ITEM 8.**

 

**REPORT OFMANAGEMENT**

 

February 17, 2010

 

**To the Shareholders of Nexen Inc.**

 

We are responsible for the preparation and fair presentationof the Consolidated Financial Statements, as well as the financial reportingprocess that gives rise to such Consolidated Financial Statements. Thisresponsibility requires us to make significant accounting judgments andestimates. For example, we are required to choose accounting principles andmethods that are appropriate to the company’s circumstances, and we arerequired to make estimates and assumptions that affect amounts reported.Fulfilling this responsibility requires the preparation and presentation of ourConsolidated Financial Statements in accordance with generally acceptedaccounting principles in Canada with a reconciliation to generally acceptedaccounting principles in the US.

 

We also have responsibility for the preparation and fairpresentation of other financial information in this report and to ensure theconsistency of this information with the financial statements.

 

We are responsible for developing and implementing 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 establishedaccounting and reporting systems supported by internal controls over financialreporting and an internal audit program. We believe that our internal controlsover financial 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,internal controls over financial reporting and corporate-wide policies toensure that Nexen’s consolidated financial position, results of operations andcash flows are presented fairly. Our disclosure controls and procedures aredesigned to ensure timely disclosure and communication of all materialinformation required by regulators. We oversee, with assistance from ourDisclosure Review Committee, these controls and procedures and all requiredregulatory disclosures.

 

To ensure the integrity of our financial statements, wecarefully select and train qualified personnel. We also ensure ourorganizational structure provides appropriate delegation of authority anddivision of responsibilities. Our policies and procedures are communicatedthroughout the organization and include a written ethics and integrity policythat applies to all employees, including the Chief Executive Officer, ChiefFinancial Officer and Chief Accounting Officer or Controller.

 

Our Board of Directors is responsible for reviewing andapproving the Consolidated Financial Statements and for overseeing management’sperformance of its financial reporting responsibilities. Their financialstatement related responsibilities are fulfilled mainly through the Audit andConduct Review Committee (Audit Committee), with assistance from the ReservesReview Committee regarding the annual review of our crude oil and natural gasreserves, and the Finance Committee regarding the assessment and mitigation offinancial 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 Chartered Accountantsand also considers their independence, reviews their fees and (subject toapplicable securities laws), pre-approves their retention for any permittednon-audit services and their fee for such services. The internal auditors andindependent registered Chartered Accountants have full and unlimited access tothe Audit Committee, with and without the presence of management.

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

 

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**REPORT OFINDEPENDENT REGISTERED CHARTERED ACCOUNTANTS**

** **

**To the Board of Directors and Shareholders of Nexen Inc.**

 

We have audited the accompanying Consolidated Balance Sheetsof Nexen Inc. and subsidiaries (the “Company”) as of December 31, 2009 and2008, and the related Consolidated Statements of Income, Cash Flows, Equity andComprehensive Income for each of the years in the three year period ended December 31,2009. These financial statements are the responsibility of the Company’smanagement. Our responsibility is to express an opinion on these financialstatements based on our audits.

 

We conducted our audits in accordance with Canadian generallyaccepted auditing standards and the standards of the Public Company AccountingOversight Board (United States). These standards require that we plan andperform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement. An audit includes examining, on atest basis, evidence supporting the amounts and disclosures in the financialstatements. An audit also includes assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overallfinancial statement presentation. We believe that our audits provide areasonable basis for our opinion.

 

In our opinion, these Consolidated Financial Statementspresent fairly, in all material respects, the financial position of Nexen Inc.and subsidiaries as of December 31, 2009 and 2008, and the results oftheir operations and their cash flows for each of the years in the three yearperiod ended December 31, 2009 in accordance with Canadian generallyaccepted accounting principles.

 

We have also audited, in accordance with the standards of thePublic Company Accounting Oversight Board (United States), the Company’sinternal control over financial reporting as of December 31, 2009, basedon the criteria established in Internal Control—Integrated Framework issued bythe Committee of Sponsoring Organizations of the Treadway Commission and ourreport dated February 17, 2010 expressed an unqualified opinion on theCompany’s internal control over financial reporting.

 

(signed) “Deloitte &Touche LLP”

Independent RegisteredChartered Accountants

Calgary, Canada

February 17, 2010

 

**COMMENTS BY INDEPENDENT REGISTERED CHARTEREDACCOUNTANTS ON CANADA-UNITED STATES OF AMERICA REPORTING DIFFERENCE**

 

The standards of the Public Company Accounting OversightBoard (United States) require the addition of an explanatory paragraph whenthere are changes in accounting principles that have a material effect on thecomparability of the Company’s financial statements, such as the changesdescribed in Notes 1(U) and 21 to the Consolidated Financial Statements.Although our audits were conducted in accordance with Canadian generallyaccepted auditing standards and the standards of the Public Company AccountingOversight Board (United States), our report to the Board of Directors andshareholders on the Consolidated Financial Statements of the Company dated February 17,2010, 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 17, 2010

 

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**NEXEN INC.**

**CONSOLIDATEDSTATEMENT OF INCOME**

**FOR THE THREEYEARS ENDED DECEMBER 31, 2009**

 
| **Cdn$ millions, except per share  amounts**                          | ** ** | **2009**    | ** ** | **2008**      | ** ** | **2007**   | ** ** |
|----------------------------------------------------------------------------|------------|-------------|------------|---------------|------------|------------|------------|
|                                                                       |       |        |       |          |       |       |       |
| Revenues and Other Income                                                  |       |        |       |          |       |       |       |
| Net Sales                                                                  |       | 4,895       |       | 7,424         |       | 5,583      |       |
| Marketing and Other (Note 16)                                              |       | 909         |       | 813           |       | 1,021      |       |
|                                                                       |       | 5,804       |       | 8,237         |       | 6,604      |       |
|                                                                       |       |        |       |          |       |       |       |
| Expenses                                                                   |       |        |       |          |       |       |       |
| Operating                                                                  |       | 1,280       |       | 1,335         |       | 1,165      |       |
| Depreciation, Depletion, Amortization and Impairment (Note 4)              |       | 1,802       |       | 2,014         |       | 1,767      |       |
| Transportation and Other                                                   |       | 795         |       | 967           |       | 908        |       |
| General and Administrative                                                 |       | 497         |       | 257           |       | 374        |       |
| Exploration                                                                |       | 302         |       | 402           |       | 326        |       |
| Interest (Note 9)                                                          |       | 312         |       | 94            |       | 168        |       |
|                                                                       |       | 4,988       |       | 5,069         |       | 4,708      |       |
|                                                                       |       |        |       |          |       |       |       |
| Income before Provision for Income Taxes                                   |       | 816         |       | 3,168         |       | 1,896      |       |
|                                                                       |       |        |       |          |       |       |       |
| Provision for (Recovery of) Income Taxes (Note 17)                         |       |        |       |          |       |       |       |
| Current                                                                    |       | 776         |       | 859           |       | 434        |       |
| Future                                                                     |       | (516        | )          | 598           |       | 358        |       |
|                                                                       |       | 260         |       | 1,457         |       | 792        |       |
|                                                                       |       |        |       |          |       |       |       |
| Net Income                                                                 |       | 556         |       | 1,711         |       | 1,104      |       |
| Less: Net Income (Loss) Attributable to Canexus Non-Controlling  Interests |       | 20          |       | (4            | )          | 18         |       |
|                                                                       |       |        |       |          |       |       |       |
| **Net Income  Attributable to Nexen Inc.**                                 | ** ** | **536****** | ** ** | **1,715****** | ** ** | **1,086**  | ** ** |
| ** **                                                                 | ** ** | ** **  | ** ** | ** **    | ** ** | ** ** | ** ** |
| **Earnings Per  Common Share**($/share)  (Note 18)                         |       |        |       |          |       |       |       |
| Basic                                                                      |       | 1.03        |       | 3.26          |       | 2.06       |       |
| Diluted                                                                    |       | 1.01        |       | 3.22          |       | 2.02       |       |

* *

*See accompanying notes to Consolidated Financial Statements.*

 

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**NEXEN INC.**

**CONSOLIDATEDBALANCE SHEET**

**DECEMBER 31,2009 AND 2008**

 
| **Cdn$ millions, except share  amounts**                | ** **                   | **2009**   | ** ** | **2008**   | ** ** |
|--------------------------------------------------------------|------------------------------|------------|------------|------------|------------|
| ** **                                                   |                         |       |       |       |       |
| **ASSETS**                                                   |                         |       |       |       |       |
| Current Assets                                               |                         |       |       |       |       |
| Cash and Cash Equivalents                                    |                         | 1,700      |       | 2,003      |       |
| Restricted Cash                                              |                         | 198        |       | 103        |       |
| Accounts Receivable (Note 2)                                 |                         | 2,788      |       | 3,163      |       |
| Inventories and Supplies (Note 3)                            |                         | 680        |       | 484        |       |
| Other                                                        |                         | 185        |       | 169        |       |
| Total Current Assets                                         |                         | 5,551      |       | 5,922      |       |
|                                                         |                         |       |       |       |       |
| Property, Plant and Equipment (Note 4)                       |                         | 15,492     |       | 14,922     |       |
| Goodwill                                                     |                         | 339        |       | 390        |       |
| Future Income Tax Assets (Note 17)                           |                         | 1,148      |       | 351        |       |
| Deferred Charges and Other Assets (Note 5)                   |                         | 370        |       | 570        |       |
|                                                         |                         |       |       |       |       |
| **TOTAL ASSETS**                                             | ** **                   | **22,900** | ** ** | **22,155** | ** ** |
| ** **                                                   | ** **                   | ** ** | ** ** | ** ** | ** ** |
| **LIABILITIES**                                              | ** **                   | ** ** | ** ** | ** ** | ** ** |
| Current Liabilities                                          |                         |       |       |       |       |
| Accounts Payable and Accrued Liabilities (Note 8)            |                         | 3,038      |       | 3,326      |       |
| Accrued Interest Payable                                     |                         | 89         |       | 67         |       |
| Dividends Payable                                            |                         | 26         |       | 26         |       |
| Total Current Liabilities                                    |                         | 3,153      |       | 3,419      |       |
|                                                         |                         |       |       |       |       |
| Long-Term Debt (Note 9)                                      |                         | 7,251      |       | 6,578      |       |
| Future Income Tax Liabilities (Note 17)                      |                         | 2,811      |       | 2,619      |       |
| Asset Retirement Obligations (Note 11)                       |                         | 1,018      |       | 1,024      |       |
| Deferred Credits and Other Liabilities (Note 12)             |                         | 1,021      |       | 1,324      |       |
| **EQUITY** (Note 14)                                         |                         |       |       |       |       |
| Nexen Inc. Shareholders’ Equity                         |                         |       |       |       |       |
| Common Shares, no par value                                  |                         |       |       |       |       |
| Authorized:                                                  | Unlimited                    |       |       |       |       |   |
| Outstanding:                                                 | 2009—522,915,843 shares |       |       |       |       |   |
|                                                         | 2008—519,448,590 shares |       | 1,049      |       | 981        |   |
| Contributed Surplus                                          |                         | 1          |       | 2          |       |
| Retained Earnings                                            |                         | 6,722      |       | 6,290      |       |
| Accumulated Other Comprehensive Loss                         |                         | (190       | )          | (134       | )          |
| Total Nexen Inc. Shareholders’ Equity                   |                         | 7,582      |       | 7,139      |       |
| Canexus Non-Controlling Interests                            |                         | 64         |       | 52         |       |
| **Total Equity**                                             |                         | 7,646      |       | 7,191      |       |
| Commitments, Contingencies and Guarantees (Notes  15 and 17) |                         |       |       |       |       |
| **TOTAL  LIABILITIES AND EQUITY**                            | ** **                   | **22,900** | ** ** | **22,155** | ** ** |

 

*See accompanying notes to Consolidated Financial Statements.*

 

Approved on behalf of the Board:

 

| (signed) “Marvin F.  Romanow” |   | (signed) “Thomas C.  O’Neill” |   |
|-----------------------------------------|--------|----------------------------------------------|--------|
| Director                                |   | Director                                     |   |

 

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**NEXEN INC.**

**CONSOLIDATEDSTATEMENT OF CASH FLOWS**

**FOR THE THREEYEARS ENDED DECEMBER 31, 2009**

 
| **Cdn$ millions**                                                       | ** ** | **2009**   | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                                   |       |       |       |       |       |       |       |
| **Operating  Activities**                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net Income                                                                   |       | 556        |       | 1,711      |       | 1,104      |       |
| Charges and Credits to Income not Involving Cash (Note 19)                   |       | 1,371      |       | 2,140      |       | 2,055      |       |
| Exploration Expense                                                          |       | 302        |       | 402        |       | 326        |       |
| Changes in Non-Cash Working Capital (Note 19)                                |       | (25        | )          | 119        |       | (348       | )          |
| Other                                                                        |       | (318       | )          | (18        | )          | (307       | )          |
|                                                                         |       | 1,886      |       | 4,354      |       | 2,830      |       |
|                                                                         |       |       |       |       |       |       |       |
| **Financing  Activities**                                                    |       |       |       |       |       |       |       |
| Proceeds from Long-Term Notes                                                |       | 1,081      |       | —     |       | 1,660      |       |
| Repayment of Medium-Term Notes and Debentures                                |       | —     |       | (125       | )          | (150       | )          |
| Proceeds from (Repayment of) Term Credit Facilities, Net                     |       | 728        |       | 803        |       | (697       | )          |
| Proceeds from (Repayment of) Short-Term Borrowings, Net                      |       | (1         | )          | (4         | )          | (150       | )          |
| Proceeds from Canexus Debentures                                             |       | 46         |       | —     |       | —     |       |
| Proceeds from Canexus Notes                                                  |       | —     |       | 51         |       | —     |       |
| Proceeds from (Repayment of) Canexus Term Credit Facilities of  Canexus, Net |       | 48         |       | (20        | )          | 60         |       |
| Dividends on Common Shares                                                   |       | (104       | )          | (92        | )          | (53        | )          |
| Distributions Paid to Canexus Non-Controlling Interests                      |       | (14        | )          | (17        | )          | (28        | )          |
| Issue of Common Shares and Exercise of Tandem Options for Shares  (Note 14)  |       | 57         |       | 64         |       | 56         |       |
| Repurchase of Common Shares for Cancellation (Note 14)                       |       | —     |       | (338       | )          | —     |       |
| Other                                                                        |       | (20        | )          | —     |       | (21        | )          |
|                                                                         |       | 1,821      |       | 322        |       | 677        |       |
| ** **                                                                   |       |       |       |       |       |       |       |
| **Investing  Activities**                                                    |       |       |       |       |       |       |       |
| Capital Expenditures                                                         |       |       |       |       |       |       |       |
| Exploration and Development                                                  |       | (2,467     | )          | (2,895     | )          | (3,132     | )          |
| Proved Property Acquisitions                                                 |       | (755       | )          | (22        | )          | (151       | )          |
| Energy Marketing, Chemicals, Corporate and Other                             |       | (275       | )          | (149       | )          | (118       | )          |
| Proceeds on Disposition of Assets                                            |       | 17         |       | 6          |       | 4          |       |
| Changes in Non-Cash Working Capital (Note 19)                                |       | (110       | )          | (124       | )          | 130        |       |
| Changes in Restricted Cash                                                   |       | (140       | )          | 106        |       | (16        | )          |
| Other                                                                        |       | (13        | )          | (111       | )          | 2          |       |
|                                                                         |       | (3,743     | )          | (3,189     | )          | (3,281     | )          |
|                                                                         |       |       |       |       |       |       |       |
| Effect of Exchange Rate Changes on Cash and Cash Equivalents                 |       | (267       | )          | 310        |       | (121       | )          |
|                                                                         |       |       |       |       |       |       |       |
| Increase (Decrease) in Cash and Cash Equivalents                             |       | (303       | )          | 1,797      |       | 105        |       |
|                                                                         |       |       |       |       |       |       |       |
| Cash and Cash Equivalents, Beginning of Year                                 |       | 2,003      |       | 206        |       | 101        |       |
|                                                                         |       |       |       |       |       |       |       |
| **Cash and Cash  Equivalents, End of Year**                                  | ** ** | **1,700**  | ** ** | **2,003**  | ** ** | **206**    | ** ** |

 

*Cash and cash equivalents at December 31,2009 consists of cash of $210 million (2008—$355 million; 2007—$62 million) andshort-term investments of $1,490 million (2008—$1,648 million; 2007—$144million).*

* *

*See accompanying notes to Consolidated Financial Statements.*

 

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**NEXEN INC.**

**CONSOLIDATEDSTATEMENT OF EQUITY**

**FOR THE THREEYEARS ENDED DECEMBER 31, 2009**

 
| **Cdn$ millions**                                                                                               | ** ** | **2009**   | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                                                                           |       |       |       |       |       |       |       |
| **Common  Shares,** Beginning of Year                                                                                |       | 981        |       | 917        |       | 821        |       |
| Issue of Common Shares                                                                                               |       | 45         |       | 41         |       | 32         |       |
| Exercise of Tandem Options for Shares                                                                                |       | 12         |       | 23         |       | 24         |       |
| Accrued Liability Relating to Tandem Options Exercised for Common  Shares                                            |       | 11         |       | 22         |       | 40         |       |
| Repurchased Under Normal Course Issuer Bid (Note 14)                                                                 |       | —     |       | (22        | )          | —     |       |
| **End of Year**                                                                                                      | ** ** | **1,049**  | ** ** | **981**    | ** ** | **917**    | ** ** |
| ** **                                                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Contributed  Surplus,******Beginning of Year                                                                       |       | 2          |       | 3          |       | 4          |       |
| Stock-Based Compensation Expense                                                                                     |       | —     |       | —     |       | 1          |       |
| Exercise of Tandem Options                                                                                           |       | (1         | )          | (1         | )          | (2         | )          |
| **End of Year**                                                                                                      | ** ** | **1**      | ** ** | **2**      | ** ** | **3**      | ** ** |
| ** **                                                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Retained  Earnings,******Beginning of Year                                                                         |       | 6,290      |       | 4,983      |       | 3,972      |       |
| Net Income Attributable to Nexen Inc.                                                                                |       | 536        |       | 1,715      |       | 1,086      |       |
| Dividends on Common Shares                                                                                           |       | (104       | )          | (92        | )          | (53        | )          |
| Transition Adjustment on Adoption of New Inventory Standard                                                          |       | —     |       | —     |       | (22        | )          |
| Repurchase of Common Shares for Cancellation (Note 14)                                                               |       | —     |       | (316       | )          | —     |       |
| **End of Year**                                                                                                      | ** ** | **6,722**  | ** ** | **6,290**  | ** ** | **4,983**  | ** ** |
| ** **                                                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Accumulated  Other Comprehensive Loss**, Beginning of Year                                                         |       | (134       | )          | (293       | )          | (161       | )          |
| Opening Derivatives Designated as Cash Flow Hedges                                                                   |       | —     |       | —     |       | 61         |       |
| Other Comprehensive Income (Loss) Attributable to Nexen Inc.                                                         |       | (56        | )          | 159        |       | (193       | )          |
| **End of Year****1**                                                                                                 | ** ** | **(190**   | **)**      | **(134**   | **)**      | **(293**   | **)**      |
| ** **                                                                                                           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Canexus  Non-Controlling Interests,******Beginning of  Year                                                        |       | 52         |       | 67         |       | 75         |       |
| Net Income Attributable to Non-Controlling Interests                                                                 |       | 27         |       | (5         | )          | 26         |       |
| Distributions Declared to Non-Controlling Interests                                                                  |       | (18        | )          | (20        | )          | (28        | )          |
| Issue of Partnership Units to Non-Controlling Interests under Distribution  Reinvestment Plan                        |       | 4          |       | 3          |       | —     |       |
| Estimated Fair Value of Conversion Feature of Convertible Debenture Issue  Attributable to Non-Controlling Interests |       | 4          |       | —     |       | —     |       |
| Other Comprehensive Income (Loss) Attributable to Canexus  Non-Controlling Interests                                 |       | (5         | )          | 7          |       | (6         | )          |
| **End of Year**                                                                                                      | ** ** | **64**     | ** ** | **52**     | ** ** | **67**     | ** ** |

 

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*1  Comprised of unrealized foreign currencytranslation adjustment.*

 

*See accompanying notes to Consolidated Financial Statements.*

 

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**NEXEN INC.**

**CONSOLIDATEDSTATEMENT OF COMPREHENSIVE INCOME**

**FOR THE THREEYEARS ENDED DECEMBER 31, 2009**

 
| **Cdn$ millions**                                                                        | ** ** | **2009** | ** ** | **2008**  | ** ** | **2007** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|----------|------------|-----------|------------|----------|------------|
| ** **                                                                                    |       |     |       |      |       |     |       |
| **Net Income  Attributable to Nexen Inc.**                                                    | ** ** | 536      |       | 1,715     |       | 1,086    | ** ** |
| Other Comprehensive Income (Loss), Net of Income Taxes:                                       |       |     |       |      |       |     |       |
| Foreign Currency Translation Adjustment:                                                      |       |     |       |      |       |     |       |
| Net Gains (Losses) on Investment in Self-Sustaining Foreign  Operations                       |       | (810     | )          | 1,228     |       | (867     | )          |
| Net Gains (Losses) on Foreign-Denominated Debt Hedges of Self-Sustaining  Foreign Operations1 |       | 757      |       | (1,062    | )          | 738      |       |
|                                                                                          |       |     |       |      |       |     |       |
| Realized Translation Adjustments Recognized in Net Income                                     |       | (3       | )          | (7        | )          | (3       | )          |
| Cash Flow Hedges:                                                                             |       |     |       |      |       |     |       |
| Realized Mark-to-Market Gains Recognized in Net Income                                        |       | —   |       | —    |       | (61      | )          |
| Other Comprehensive Income (Loss) Attributable to Nexen Inc.                                  |       | (56      | )          | 159       |       | (193     | )          |
|                                                                                          |       |     |       |      |       |     |       |
| **Comprehensive  Income Attributable to Nexen Inc.**                                          | ** ** | **480**  | ** ** | **1,874** | ** ** | **893**  | ** ** |

 

----

*1*                 Net of income tax expense forthe year ended December 31, 2009 of $109 million (2008—$145 millionrecovery; 2007—$97 million expense).

 

*See accompanying notes to Consolidated Financial Statements.*

 

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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 21. As at February 17, 2010, there are no materialsubsequent events requiring additional disclosure in or amendment to thesefinancial statements.

 

**(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 65.7% interest inCanexus represented by 64.8 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-Nexenownership interests in Canexus are shown as non-controlling interests.

 

We proportionately consolidateour undivided interests in our oil and gas exploration, development andproduction activities conducted under joint venture arrangements. We alsoproportionately consolidate our 7.23% undivided interest in the Syncrude jointventure. While the joint ventures under which these activities are carried outdo not comprise distinct legal entities, they are operating entities. Thesignificant operating policies of which are, by contractual arrangement,jointly controlled by all working 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 provedreserves. Changes in facts and circumstances may result in revised estimates,and actual results 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 approximates fairvalue.

 

**(D)  RESTRICTEDCASH**

 

Restricted cash includes margindeposits relating to our exchange-traded derivative contracts used in ourenergy marketing business.

 

**(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.

 

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**(F)  INVENTORIESAND SUPPLIES**

 

Inventories and supplies, otherthan inventory held for trading purposes, are stated at the lower of cost andnet realizable value. Cost is determined using the first-in, first-out method.Inventory costs include expenditures and other costs, including depletion anddepreciation, directly or indirectly incurred in bringing the inventory to itsexisting condition.

 

Commodity inventories in ourenergy marketing operations that are held for trading purposes are carried atfair value, as measured by the one-month forward price, less any costs to sell.Any changes in fair value are included as gains or losses in marketing andother 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 incurred. Improvements that increase capacity or extend the usefullives of the related assets are capitalized to PP&E. Major spare parts andstandby equipment whose useful life is expected to last longer than one year areincluded 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, exploration drillingcosts 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 of a potentialdevelopment. All other exploration costs, including geological and geophysicaland annual lease rentals, are expensed to earnings as incurred. All developmentcosts are capitalized as proved property costs. General and administrativecosts that directly relate to acquisition, exploration and developmentactivities are capitalized to PP&E.

 

We engage in research anddevelopment activities to develop or improve processes and techniques toextract oil and gas. Research involves investigating new knowledge. Developmentinvolves translating that knowledge into a new technology or process. Researchcosts are expensed as incurred. Development costs are deferred once technicalfeasibility is established, and we intend to proceed with development. We deferthese costs in PP&E until the asset is substantially complete and ready forproductive use. Otherwise, development costs are expensed as incurred.

 

**(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. DD&A 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 reserves within developed areas of interest.

 

We depreciate other plant andequipment costs using the straight-line method based on the estimated usefullives of the assets, which range from 3 to 30 years. Unproved property costsand major projects that are under construction or development are notdepreciated, depleted or amortized.

 

We evaluate the carrying valueof our PP&E whenever events or conditions occur that indicate that thecarrying value of properties on our balance sheet may not be recoverable fromfuture cash flows. These events or conditions occur periodically. If carryingvalue exceeds the sum of estimated undiscounted future cash flows, the property’svalue is impaired. The property is then assigned a fair value equal to itsestimated future discounted net cash flows, and we expense the excess carryingvalue to DD&A. Our cash flow estimates require assumptions about futurecommodity prices, ultimate recoverability of oil and gas reserves, operatingcosts and other factors. Actual results can differ from these estimates.

 

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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)    CAPITALIZED INTEREST**

 

We capitalize interest on majordevelopment projects until construction is complete using the weighted-averageinterest rate on all of our borrowings. Capitalized interest cannot exceed theactual interest incurred.

 

**(J)   CARRIED INTEREST**

 

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.

 

**(K)  GOODWILL**

 

Our goodwill is attributable toour 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 may be impaired. Webase our test on the estimated fair value of the reporting unit. If goodwill isimpaired, we reduce the carrying value to estimated fair value and animpairment loss is recorded in net income.

 

**(L)  FINANCIAL INSTRUMENTS 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 the followingcategories: financial assets and financial liabilities held for trading; loansor receivables; financial assets held to maturity; financial assets availablefor sale; and other financial liabilities. The classification depends on thecharacteristics and the purpose for which the financial instruments wereacquired. Except in limited circumstances, the classification of financialinstruments is not subsequently changed.

 

Financial instruments carriedat 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 gains andlosses arise. Transaction costs related to these financial assets andliabilities are included in net income when incurred.

 

Financial instruments we carryat cost or amortized cost include our accounts receivable, accounts payable andaccrued liabilities, accrued interest payable, dividends payable, short-termborrowings and long-term debt. Transaction costs are included in net incomewhen incurred for these types of financial instruments except for short-termborrowings and long-term debt. These transaction costs are included with theinitial fair value and the instrument is carried at amortized cost using theeffective interest rate method. Gains and losses on financial assets andliabilities carried at cost or amortized cost are recognized in net income whenthese assets or liabilities settle.

 

**Derivatives related to non-trading activities**

** **

We may 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 6and 7). We record these instruments at fair value at the balance sheet date andrecord changes in fair value as net gains or losses in marketing and otherincome during the period of change unless the requirements for hedge accountingare met.

 

**Derivatives related to trading activities**

** **

Our energy marketing operationuses derivative instruments for marketing and trading natural gas, crude oil,natural gas liquids and power including: commodity contracts settled withphysical delivery; exchange-traded futures and options; and non-exchange tradedforwards, swaps and options.

 

We record these instruments atfair 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 

 

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

 

For fair value hedges, both thefinancial 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 or fairvalue hedges in place at December 31, 2009 or 2008.

 

For hedges of net investments,gains and losses resulting from foreign exchange translation of our netinvestments in self-sustaining foreign operations and the effective portion ofthe hedging items are recorded in other comprehensive income. Amounts includedin accumulated other comprehensive income are reclassified to income whenrealized.

 

**(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 outflows to settle the asset retirementobligation using a weighted-average, credit-adjusted risk-free interest rate.Nexen recognizes period-to-period changes due to the passage of time andrevisions to either the timing or the amount of the original estimate ofundiscounted cash outflows. 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 assets forwhich the fair value of the asset retirement obligations cannot be reasonablydetermined because the assets currently have an indeterminate life and wecannot determine when remediation activities would take place. These assetsinclude our interest in Syncrude’s upgrader and sulphur pile, and our interestin the Long Lake upgrader. The estimated future recoverable reserves atSyncrude and Long Lake are significant and given the long life of these assets,we are unable to determine when asset retirement activities would take place. Furthermore,the Syncrude plant and the Long Lake upgrader can both continue to runindefinitely with ongoing maintenance activities. The retirement obligationsfor these assets will be recorded in the first year in which the obligation toremediate becomes determinable.

 

**(N)  PENSION AND 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 benefit plans,we provide benefits to retirees based on their length of service and finalaverage earnings. The cost of pension benefits earned by employees in ourdefined benefit pension plans is actuarially determined using the projected-benefitmethod prorated on service and our best estimate of the plans’ investmentperformance, salary escalations and retirement ages of employees. To calculatethe plans’ expected returns, assets are measured at fair value. Past servicecosts arising from plan amendments, and net actuarial gains and losses thatexceed 10% of the 

 

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greater of the accrued benefitobligation and the fair value of plan assets, are expensed in equal amountsover the expected average remaining service life of the employee group.Benefits paid out of Nexen’s defined benefit plan are indexed to 75% of theannual rate of inflation less 1% to a maximum increase of 5%.

 

In 2008, we changed ourmeasurement 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-retirement benefitsinclude group life and supplemental health insurance for eligible employees andtheir dependants. Costs are accrued as compensation in the period employeeswork; however, these future obligations are not funded.

 

**(O)  REVENUE RECOGNITION**

 

**Oil and gas**

** **

Revenue from the production ofcrude oil and natural gas is recognized when title passes to the customer. InCanada and the US, our customers primarily take title when the crude oil ornatural gas reaches the end of the pipeline. For our other internationaloperations, our customers generally take title when the crude oil is loadedonto tankers. When we produce or sell more or less oil or natural gas than ourshare, production overlifts and underlifts occur. We record overlifts asliabilities and underlifts as assets. We settle these over time as liftings areequalized or in cash when production ends.

 

Revenue represents Nexen’sshare and is recorded net of royalty 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.We record any change in fair value as a gain or loss in marketing and otherincome unless requirements for hedge accounting are met.

 

Any margin earned by our energymarketing operation on the sale of our proprietary oil and gas production isincluded in marketing and other income. Sales of our proprietary production arerecorded at monthly average market-based prices and reported in our oil and gassegments. Intercompany profits and losses between segments are eliminated.

 

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)   FOREIGN CURRENCY TRANSLATION**

 

Our foreign operations, whichare considered financially and operationally independent, are translated fromtheir 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 ourUS-dollar debt (excluding debt related to Canexus) as a hedge against our netinvestment in US-dollar self-sustaining foreign operations. Gains and lossesresulting from the translation of the designated US-dollar debt are included inother comprehensive income. 

 

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If our US-dollar debt, net ofincome taxes, exceeds our US-dollar investment in foreign operations, then thegains or losses attributable to such excess are included in marketing and otherincome in the Consolidated Statement of Income.

 

Monetary balances denominatedin a currency other than a functional currency are translated into thefunctional currency using exchange rates at the balance sheet dates. Gains andlosses arising from this translation are included in marketing and other incomein the Consolidated Statement of Income.

 

**(Q)  TRANSPORTATION**

 

We pay to transport the crudeoil, natural gas and chemical products that we have sold, and often 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 entered intoas either capital or operating leases. Leases that transfer substantially allof 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-BASED COMPENSATION**

 

Our stock-based compensationconsists of tandem option (TOPs) and stock appreciation right (STARs) plans.

 

Tandem options to purchasecommon shares are granted to officers and employees at the discretion of theBoard of Directors. Each tandem option gives the holder a right to eitherpurchase one Nexen common share at the exercise price or to receive a cashpayment equal to the excess of the market value of the common share over theexercise price. Options granted prior to February 2001 vest over fouryears and are exercisable on a cumulative basis over 10 years. Options grantedafter 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 for thetandem 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, employeesare entitled to cash payments equal to the excess of market price of the commonshare over the exercise price of the right. The vesting period and other termsof the plan are similar to the tandem option plan. At the time of grant, theexercise price equals market value. We account for stock appreciation rights toemployees on the same basis as our tandem options. Obligations are accrued ascompensation expense over the graded vesting period of the stock appreciationrights.

 

**(T)  INCOME TAXES**

 

We follow the liability methodof accounting for income taxes. This method recognizes income tax assets andliabilities at current rates, based on temporary differences in reportedamounts for financial statement and tax purposes. The effect of a change inincome tax rates on future income tax assets and future income tax liabilitiesis recognized in income when substantively enacted.

 

We do not provide for foreignwithholding taxes on the undistributed earnings of our foreign subsidiaries, aswe intend to invest such earnings indefinitely in foreign operations.

 

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**(U)  CHANGES IN ACCOUNTING PRINCIPLES**

 

**Goodwill and Intangible Assets**

** **

On January 1, 2009, weretrospectively adopted the Canadian Institute of Chartered Accountants (CICA)section 3064, *Goodwill and Intangible Assets*issuedby the Accounting Standards Board (AcSB). This section clarifies the criteriafor the recognition of assets, intangible assets and internally developedintangible assets. Adoption of this standard did not have a material impact onour results of operations or financial position.

 

**Business Combinations**

** **

On January 1, 2009, weprospectively adopted CICA Section 1582, *BusinessCombinations*issued by the AcSB. This sectionestablishes principles and requirements of the acquisition method for businesscombinations and related disclosures. Adoption of this statement did not have amaterial impact on our results of operations or financial position.

 

**Consolidated Financial Statements and Non-Controlling Interests**

** **

On January 1, 2009, weprospectively adopted CICA Sections 1601, *ConsolidatedFinancial Statements*, and 1602, *Non-ControllingInterests* issued by the AcSB. Section 1601establishes standards for the preparation of Consolidated Financial Statements.Section 1602 provides guidance on accounting for non-controlling interestsin Consolidated Financial Statements subsequent to a business combination.Adoption of these sections did not have a material impact on our results ofoperations or financial position. The presentation changes have been includedin the Consolidated Financial Statements as applicable.

 

**Financial Instruments**

** **

In June 2009, the AcSBamended CICA Section 3862, *FinancialInstruments—Disclosures*, to improve fair value and liquidity riskdisclosures. Section 3862 now requires disclosure of the relativereliability of inputs into fair value estimates of financial instruments anddisclosure of a three-level hierarchy based on the observability of inputs. Theamendments are effective for fiscal years ending after September 30, 2009.Adoption of these amendments did not have an impact on our results ofoperations or financial position.

 

**Oil and Gas Reserve Estimates**

** **

On January 6, 2010, theFinancial Accounting Standards Board issued guidance for *Oil and Gas Reserve Estimation and Disclosure*,which is effective for years ended December 31, 2009. The guidance expandsthe definition of oil and gas producing activities to: i) includeunconventional sources such as oil sands, ii) change the price used in reserveestimation from the year-end price to the simple average of the first-day-of-the-monthprice for the previous 12 months, and iii) requires disclosures for geographicareas which represent 15% or more of proved reserves. The information requiredby this standard has been included in the Supplementary Data (Unaudited).

 

We follow the successfulefforts method of accounting for our oil and gas activities, which depends onthe estimated reserves we believe are recoverable from our oil and gasproperties. Specifically, reserves estimates are used to calculate ourunit-of-production depletion rates and to assess, when necessary, our oil andgas assets for impairment. Adoption of these amendments at December 31,2009 did not have an impact on our results of operations or financial position.

 

**New accounting pronouncements**

** **

All Canadian publiclyaccountable enterprises will be required to adopt International FinancialReporting Standards (IFRS) for interim and annual reporting purposes for fiscalyears beginning on or after January 1, 2011. A project team, consisting ofdedicated personnel who have the experience and IFRS knowledge, has been set upto manage this transition and to ensure successful implementation within therequired timeframe.

 

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**2****.       ACCOUNTSRECEIVABLE**

 
| ** **                                     | ** ** | **2009**  | ** ** | **2008**  | ** ** |
|------------------------------------------------|------------|-----------|------------|-----------|------------|
| Trade                                          |       |      |       |      |       |
| Energy Marketing                               |       | 1,410     |       | 1,501     |       |
| Energy Marketing Derivative Contracts (Note 6) |       | 466       |       | 755       |       |
| Oil and Gas                                    |       | 823       |       | 639       |       |
| Chemicals and Other                            |       | 44        |       | 68        |       |
|                                           |       | 2,743     |       | 2,963     |       |
| Non-Trade                                      |       | 99        |       | 270       |       |
|                                           |       | 2,842     |       | 3,233     |       |
| Allowance for Doubtful Receivables             |       | (54       | )          | (70       | )          |
|                                           |       |      |       |      |       |
| **Total**                                      | ** ** | **2,788** | ** ** | **3,163** | ** ** |

 

**3****.       INVENTORIESAND SUPPLIES**

 
| ** **          | ** ** | **2009** | ** ** | **2008** | ** ** |
|---------------------|------------|----------|------------|----------|------------|
| Finished Products   |       |     |       |     |       |
| Energy Marketing    |       | 548      |       | 384      |       |
| Oil and Gas         |       | 25       |       | 17       |       |
| Chemicals and Other |       | 12       |       | 16       |       |
|                |       | 585      |       | 417      |       |
| Work in Process     |       | 7        |       | 6        |       |
| Field Supplies      |       | 88       |       | 61       |       |
|                |       |     |       |     |       |
| **Total**           | ** ** | **680**  | ** ** | **484**  | ** ** |

 

**4****.       PROPERTY,PLANT AND EQUIPMENT**

 
| ** **                  | ** ** | **2009**   | ** ** | **2008**                  | ** ** |
|-----------------------------|------------|------------|------------|---------------------------|------------|
| ** **                  | ** ** | **Cost**   | ** ** | **Accumulated  DD&A** | ** ** | **Net Book  Value** | ** ** | **Cost** | ** ** | **Accumulated  DD&A** | ** ** | **Net Book  Value** | ** ** |
| Oil and Gas                 |       |       |       |                      |       |   |   |   |   |   |   |   |   |
| UK                          |       | 6,115      |       | 2,664                     |       | 3,451 |   | 6,532 |   | 2,159 |   | 4,373 |   |
| Canada1                     |       | 9,664      |       | 2,038                     |       | 7,626 |   | 8,134 |   | 1,786 |   | 6,348 |   |
| Syncrude                    |       | 1,463      |       | 270                       |       | 1,193 |   | 1,372 |   | 236 |   | 1,136 |   |
| US                          |       | 3,900      |       | 2,529                     |       | 1,371 |   | 4,398 |   | 2,702 |   | 1,696 |   |
| Yemen                       |       | 800        |       | 728                       |       | 72 |   | 899 |   | 781 |   | 118 |   |
| Yemen—Carried Interest |       | 1,662      |       | 1,594                     |       | 68 |   | 1,909 |   | 1,829 |   | 80 |   |
| Other Countries2            |       | 930        |       | 99                        |       | 831 |   | 554 |   | 113 |   | 441 |   |
|                        |       | 24,534     |       | 9,922                     |       | 14,612 |   | 23,798 |   | 9,606 |   | 14,192 |   |
| Energy Marketing            |       | 259        |       | 83                        |       | 176 |   | 246 |   | 76 |   | 170 |   |
| Chemicals                   |       | 1,135      |       | 562                       |       | 573 |   | 940 |   | 507 |   | 433 |   |
| Corporate and Other         |       | 371        |       | 240                       |       | 131 |   | 331 |   | 204 |   | 127 |   |
|                        |       |       |       |                      |       |   |   |   |   |   |   |   |   |
| **Total**                   | ** ** | **26,299** | ** ** | **10,807**                | ** ** | **15,492** | ** ** | **25,315** | ** ** | **10,393** | ** ** | **14,922** | ** ** |

 

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*1*                 Includes capitalizedcosts related to our insitu oil sands (Long Lake and future phases) of $6,045million (2008—$4,742 million).

*2*                 Includes capitalizedcosts related to Usan development, offshore west Africa of $779 million (2008—$364million).

 

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Capitalized costs includes$8,740 million (2008—$7,386 million) relating to unproved properties andprojects under construction or development and includes start-up costs, net ofincidental revenues. These costs are currently not being depreciated, depletedor amortized, however, we will begin amortizing the capitalized costs of LongLake Phase 1 in 2010.

 

**DEPRECIATION,DEPLETION, AMORTIZATION AND IMPAIRMENT**

 

Our DD&A expense in 2009includes non-cash impairment charges of $78 million at three small natural gasproperties in Canada and the US Gulf of Mexico. Year-end natural gas provedreserves at these properties were lower as a result of weak natural gas pricesthroughout 2009. These properties were written down to their estimated fairvalue based on their estimated future discounted net cash flows. The estimatedfuture cash flows incorporate a risk-adjusted discount rate and management’sestimates of future prices, capital expenditures and production. Based on thesesignificant unobservable inputs, the measurements are considered Level 3 withinthe fair value hierarchy. DD&A expense also includes $49 million for ourPerth discovery in the North Sea where we expensed allocated acquisition costs aswe are unlikely to proceed with development of this prospect.

 

Our DD&A expense in 2008included $568 million of impairment expense relating to oil and gas propertiesin the US Gulf of Mexico and UK North Sea. These properties were written downto their estimated fair value based on their estimated total future discountednet cash flows.

 

In the US Gulf of Mexico, wereduced the carrying value of four shelf properties by $143 million in 2008,primarily as a result of low oil and gas prices and higher estimated assetremediation costs. These late-life, mature properties have a shorter productionhorizon, and therefore are sensitive to near-term commodity prices and 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 as the original third-party production platform was not replaced bythe operator.

 

In the UK North Sea, we reducedthe carrying value of our Ettrick project by $256 million in 2008, primarilydue to higher costs and lower reserve estimates following drilling and testingactivities. We also expensed costs of $62 million in 2008 related to ourSelkirk discovery as we are unlikely to proceed with development.

 

**SUSPENDEDEXPLORATION WELL COSTS**

 

The following table shows thechanges in capitalized exploratory well costs during the years ended December 31,2009 and 2008, and does not include amounts that were initially capitalized andsubsequently expensed in the same period. Suspended exploration well costs areincluded in property, plant and equipment.

 
| ** **                                                                              | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-----------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Beginning of Year                                                                       |       | 518      | ** ** | **326**  | ** ** | **226**  | ** ** |
| Exploratory Well Costs Capitalized Pending the Determination of  Proved Reserves        |       | 396      |       | 254      |       | 215      |       |
| Capitalized Exploratory Well Costs Charged to Expense                                   |       | (56      | )          | (81      | )          | (10      | )          |
| Transfers to Wells, Facilities and Equipment Based on Determination  of Proved Reserves |       | (21      | )          | (29      | )          | (74      | )          |
| Effects of Foreign Exchange Rate Changes                                                |       | (43      | )          | 48       |       | (31      | )          |
| **End of Year**                                                                         | ** ** | **794**  | ** ** | **518**  | ** ** | **326**  | ** ** |

 

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The following table provides anaging 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.

 
| ** **                                                                                          | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| Capitalized for a Period of One Year or Less                                                        |       | 383        |       | 239        |       |
| Capitalized for a Period of Greater than One Year                                                   |       | 411        |       | 279        |       |
| **Total**                                                                                           | ** ** | **794**    | ** ** | **518**    | ** ** |
| ** **                                                                                          | ** ** | ** ** | ** ** | ** ** | ** ** |
| Number of Projects that have Exploratory Well Costs Capitalized for a  Period Greater than One Year |       | 12         |       | 7          |       |

 

As at December 31, 2009,we have exploratory costs that have been capitalized for more than one yearrelating to our interests in six exploratory blocks in the UK North Sea ($138million), certain coalbed methane and shale gas exploratory activities inCanada ($138 million), two exploratory blocks in the Gulf of Mexico ($116million) and our interest in two exploratory blocks offshore Nigeria ($19million). These costs relate to projects with successful exploration wells forwhich we have not been able to recognize proved reserves. We are assessing allof these wells and projects, and are working with our partners to preparedevelopment plans, drill additional appraisal wells or otherwise assesscommercial viability.

 
| **Aging of Suspended Exploration  Wells Greater Than 1  Year** | ** ** | **United  Kingdom** | ** ** | **Canada** | ** ** | **United  States** | ** ** | **Nigeria** | ** ** | **Total** | ** ** |
|----------------------------------------------------------------|------------|---------------------|------------|------------|------------|--------------------|------------|-------------|------------|-----------|------------|
| 1–3 years                                                 |       | 138                 |       | 138        |       | 43                 |       | —      |       | 319       |       |
| 4–5 years                                                 |       | —              |       | —     |       | 73                 |       | —      |       | 73        |       |
| Greater than 5 years                                           |       | —              |       | —     |       | —             |       | 19          |       | 19        |       |
| **Total**                                                      | ** ** | **138**             | ** ** | **138**    | ** ** | **116**            | ** ** | **19**      | ** ** | **411**   | ** ** |

 

**5****.       DEFERREDCHARGES AND OTHER ASSETS**

 
| ** **                                               | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------------------------------------------|------------|----------|------------|----------|------------|
| Long-Term Energy Marketing Derivative Contracts (Note 6) |       | 225      |       | 217      |       |
| Crude Oil Put Options and Natural Gas Swaps (Note 6)     |       | 4        |       | 234      |       |
| Defined Benefit Pension Asset (Note 13)                  |       | 60       |       | 2        |       |
| Long-Term Capital Prepayments                            |       | 27       |       | 61       |       |
| Other                                                    |       | 54       |       | 56       |       |
| **Total**                                                | ** ** | **370**  | ** ** | **570**  | ** ** |

 

**6****.       FINANCIALINSTRUMENTS**

 

Financial instruments carriedat 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,accrued interest payable, dividends payable, short-term borrowings andlong-term debt are carried at cost or amortized cost. The carrying value of ourshort-term receivables and payables approximates their fair value because theinstruments are near maturity.

 

In our energy marketing group,we enter into contracts to purchase and sell crude oil, natural gas and otherenergy commodities, and use derivative contracts, including futures, forwards,swaps and options, for hedging and trading purposes (collectively derivatives).We also use derivatives to manage commodity price risk and foreign currencyrisk for non-trading purposes. We categorize our derivative instruments astrading or non-trading activities and carry the instruments at fair value onour balance sheet. The fair values are included with amounts receivable orpayable and are classified as long-term or short-term based on anticipatedsettlement date. Any change in fair value is included in marketing and otherincome.

 

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We carry our long-term debt atamortized cost using the effective interest rate method. At December 31,2009, the estimated fair value of our long-term debt was $7,594 million (December 31,2008—$5,686 million) as compared to the carrying value of $7,251 million (December 31,2008—$6,578 million). The fair value of long-term debt is estimated based onprices provided by quoted markets and third-party brokers. The economic crisisin 2008 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.

 

**Derivatives**

** **

**(A)  DERIVATIVE CONTRACTS RELATED TO TRADINGACTIVITIES**

 

Our energy marketing groupengages in various activities including the purchase and sale of physicalcommodities and the use of financial instruments such as commodity and foreignexchange futures, forwards and swaps to economically hedge exposures andgenerate revenue. These contracts are accounted for as derivatives and, where applicable,are presented net on the balance sheet in accordance with netting arrangements.The fair value and carrying amounts related to derivative instruments held byour energy marketing operations are as follows:

 
| ** **                                        | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|---------------------------------------------------|------------|------------|------------|------------|------------|
| Commodity Contracts                               |       | 463        |       | 742        |       |
| Foreign Exchange Contracts                        |       | 3          |       | 13         |       |
| Accounts Receivable (Note 2)                      |       | 466        |       | 755        |       |
|                                              |       |       |       |       |       |
| Commodity Contracts                               |       | 225        |       | 213        |       |
| Foreign Exchange Contracts                        |       | —     |       | 4          |       |
| Deferred Charges and Other Assets (Note 5)1       |       | 225        |       | 217        |       |
|                                              |       |       |       |       |       |
| **Total Trading  Derivative Assets**              | ** ** | **691**    | ** ** | **972**    | ** ** |
|                                              |       |       |       |       |       |
| Commodity Contracts                               |       | 410        |       | 585        |       |
| Foreign Exchange Contracts                        |       | 46         |       | 30         |       |
| Accounts Payable and Accrued Liabilities (Note 8) |       | 456        |       | 615        |       |
|                                              |       |       |       |       |       |
| Commodity Contracts                               |       | 212        |       | 248        |       |
| Foreign Exchange Contracts                        |       | —     |       | 46         |       |
| Deferred Credits and Other Liabilities (Note 12)1 |       | 212        |       | 294        |       |
|                                              |       |       |       |       |       |
| **Total Trading  Derivative Liabilities**         | ** ** | **668**    | ** ** | **909**    | ** ** |
| ** **                                        | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Total Net  Trading Derivative Contracts**       | ** ** | **23**     | ** ** | **63**     | ** ** |

 

----

*1*                 These derivativecontracts settle beyond 12 months and are considered non-current; oncesettlement is within 12 months, they are included in accounts receivable oraccounts payable.

* *

Excluding the impact of nettingarrangements, the fair value of derivative instruments is as follows:

 
| ** **                                  | ** ** | **2009** | ** ** | **2008** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|
| Current Trading Assets                      |       | 2,625    |       | 3,945    |       |
| Non-Current Trading Assets                  |       | 716      |       | 694      |       |
| Total Trading Derivative Assets             |       | 3,341    |       | 4,639    |       |
|                                        |       |     |       |     |       |
| Current Trading Liabilities                 |       | 2,615    |       | 3,805    |       |
| Non-Current Trading Liabilities             |       | 703      |       | 771      |       |
| Total Trading Derivative Liabilities        |       | 3,318    |       | 4,576    |       |
|                                        |       |     |       |     |       |
| **Total Net  Trading Derivative Contracts** | ** ** | **23**   | ** ** | **63**   | ** ** |

 

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Trading revenues generated byour energy marketing group include gains and losses on derivative instrumentsand non-derivative instruments such as physical inventory. During 2009, thefollowing trading revenues were recognized in marketing and other income:

 
| ** **                       | ** ** | **2009** | ** ** |
|----------------------------------|------------|----------|------------|
| Commodity                        |       | 1,011    |       |
| Foreign Exchange                 |       | (68      | )          |
| Marketing Revenue, Net (Note 16) | ** ** | **943**  | ** ** |

 

As an energy marketer, we mayundertake several transactions during a period to execute a single sale ofphysical product. Each transaction may be represented by one or more derivativeinstruments including a physical buy, physical sell, and in many cases,numerous financial instruments for economically hedging and trading purposes.The absolute notional volumes associated with our derivative instrumenttransactions are as follows:

 
| ** **                        | ** ** | **2009** | ** ** |
|-----------------------------------|------------|----------|------------|
| Natural Gas (bcf/d)               |       | 21.1     |       |
| Crude Oil (mmbbls/d)              |       | 3.5      |       |
| Power (GWh/d)                     |       | 217.3    |       |
| Foreign Exchange (USD  millions)  |       | 2,981    |       |
| Foreign Exchange (Euro  millions) |       | 376      |       |

 

**(B)  DERIVATIVE CONTRACTS RELATED TO NON-TRADINGACTIVITIES**

 

The fair value and carryingamounts of derivative instruments related to non-trading activities are asfollows:

 
| ** **                                        | ** ** | **2009** | ** ** | **2008** | ** ** |
|---------------------------------------------------|------------|----------|------------|----------|------------|
| Accounts Receivable                               |       | 13       |       | 6        |       |
| Deferred Charges and Other Assets (Note 5)1       |       | 4        |       | 234      |       |
| **Total  Non-Trading Derivative Assets**          |       | 17       |       | 240      |       |
| ** **                                        |       |     |       |     |       |
| Accounts Payable and Accrued Liabilities          |       | 26       |       | 21       |       |
| Deferred Credits and Other Liabilities (Note 12)1 |       | —   |       | 26       |       |
| **Total  Non-Trading Derivative Liabilities**     |       | 26       |       | 47       |       |
| ** **                                        |       |     |       |     |       |
| **Total  Net Non-Trading Derivative Contracts**2  | ** ** | **(9**   | **)**      | **193**  | ** ** |

 

----

*1*                 These derivativecontracts settle beyond 12 months and are considered non-current.

*2*                 The net fair value ofthese derivatives is equal to the gross fair value before consideration of nettingarrangements and collateral posted or received with counterparties.

* *

***Crude oil putoptions***

 

In the fourth quarter of 2009,we purchased put options on 90,000 bbls/d of our 2010 crude oil production.These options establish a WTI floor price of US$50/bbl on these volumes andprovide a base level of price protection without limiting our upside to higherprices. Options on 60,000 bbls/d settle monthly, while the remaining optionssettle annually. These options are recorded at fair value throughout their term.As a result, changes in forward crude oil prices create gains or losses onthese options at each period end. The put options were purchased for $39million and are carried at fair value. At December 31, 2009, higher crudeoil prices reduced the fair value of the options to $17 million, and werecorded a fair value loss in 2009 of $22 million.

 

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In early 2008, we purchased putoptions on approximately 70,000 bbls/d of our 2009 crude oil production. Theseoptions were purchased for $14 million and established a Dated Brent floorprice of US$60/bbl on these volumes. At December 31, 2008, the put optionshad an estimated fair value of $233 million due to lower crude oil prices.Strengthening crude oil prices in 2009 reduced the fair value of these optionsto nil and we recorded a fair value loss of $229 million in 2009.

 

The crude oil put options arecarried at fair value and are classified as long-term or short-term based ontheir anticipated settlement date. Fair value of the put options is supportedby multiple quotes obtained from third-party brokers, which were validated withobservable market data to the extent possible. Any change in fair value isincluded in marketing and other income.

 
| ** **                          | ** ** | **December 31,  2009**   | ** ** |
|-------------------------------------|------------|-------------------------------|------------|
| ** **                          | ** ** | **Notional  Volumes(bbls/d)** | ** ** | **Term** | ** ** | **Average  Floor Price(US$/bbl)** | ** ** | **Fair Value(Cdn$ millions)** | ** ** | **Change in Fair  Value(Cdn$ millions)** | ** ** |
| WTI Crude Oil Put Options (monthly) |       | 60,000                        |       | 2010 |   | 50 |   | 13 |   | (12 | ) |
| WTI Crude Oil Put Options (annual)  |       | 30,000                        |       | 2010 |   | 50 |   | 4 |   | (10 | ) |
|                                |       |                          |       |   |   |   |   | 17 |   | (22 | ) |

 
| ** **                                 | ** ** | **December 31,  2008**   | ** ** |
|--------------------------------------------|------------|-------------------------------|------------|
| ** **                                 | ** ** | **Notional  Volumes(bbls/d)** | ** ** | **Term** | ** ** | **Average  Floor Price(US$/bbl)** | ** ** | **Fair Value(Cdn$ millions)** | ** ** | **Change in Fair Value(Cdn$ millions)** | ** ** |
| Dated Brent Crude Oil Put Options (annual) |       | 70,000                        |       | 2009 |   | 60 |   | 233 |   | 233 |   |

 

**Fixed-price natural gas contracts and natural gas swaps**

** **

We have fixed-price natural gassales 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 short-term based on their anticipated settlement date.Any change in fair value is included in marketing and other income.

 
| ** **                                  | ** ** | **December 31,  2009** | ** ** |
|---------------------------------------------|------------|-----------------------------|------------|
| ** **                                  | ** ** | **Notional  Volumes(Gj/d)** | ** ** | **Term** | ** ** | **Average  Floor Price($/Gj)** | ** ** | **Fair Value(Cdn$ millions)** | ** ** | **Change in Fair Value(Cdn$ millions)** | ** ** |
| Fixed-Price Natural Gas Contracts (monthly) |       | 15,514                      |       | 2010 |   | 2.28 |   | (14 | ) | 12 |   |
| Natural Gas Swaps (monthly)                 |       | 15,514                      |       | 2010 |   | 7.60 |   | (12 | ) | (13 | ) |
|                                        |       |                        |       |   |   |   |   | (26 | ) | (1 | ) |

 
| ** **                                  | ** ** | **December 31,  2008** | ** ** |
|---------------------------------------------|------------|-----------------------------|------------|
| ** **                                  | ** ** | **Notional  Volumes(Gj/d)** | ** ** | **Term** | ** ** | **Average  Floor Price($/Gj)** | ** ** | **Fair Value(Cdn$ millions)** | ** ** | **Change in Fair Value(Cdn$ millions)** | ** ** |
| Fixed-Price Natural Gas Contracts (monthly) |       | 15,514                      |       | 2009 |   | 2.28 |   | (21 | ) | 3 |   |
|                                        |       | 15,514                      |       | 2010 |   | 2.28 |   | (26 | ) | (2 | ) |
| Natural Gas Swaps (monthly)                 |       | 15,514                      |       | 2009 |   | 7.60 |   | 6 |   | 8 |   |
|                                        |       | 15,514                      |       | 2010 |   | 7.60 |   | 1 |   | 2 |   |
|                                        |       |                        |       |   |   |   |   | (40 | ) | 11 |   |

 

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**(C)  FAIR VALUE OF DERIVATIVES**

** **

For purposes of estimating thefair value of our derivative contracts, wherever possible, we utilize quotedmarket prices, and if not available, estimates from third-party brokers. Thesebroker estimates are corroborated with multiple sources and/or other observablemarket data utilizing assumptions that market participants would use whenpricing the asset or liability, including assumptions about risk and marketliquidity. 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.

 

Weclassify the fair value of our derivatives according to the following hierarchybased on the amount of observable inputs used to value the instruments.

 

·                  Level 1—Quoted prices areavailable in active markets for identical assets or liabilities as of thereporting date. Active markets are those in which transactions occur insufficient frequency and volume to provide pricing information on an ongoingbasis. Level 1 consists of financial instruments such as exchange-tradedderivatives and we use information from markets such as the New York MercantileExchange.

·                  Level 2—Pricing inputsare other than quoted prices in active markets included in Level 1. Prices inLevel 2 are either directly or indirectly observable as of the reported date.Level 2 valuations are based on inputs, including quoted forward prices forcommodities, time value, volatility factors and broker quotations, which can besubstantially observed or corroborated in the marketplace. Instruments in thiscategory include non-exchange traded derivatives such as over-the-counterphysical forwards and options, including those which have prices similar toquoted market prices. We obtain information from sources such as the NaturalGas Exchange, independent price publications and over-the-counter brokerquotes.

·                  Level 3—Valuations inthis level are those with inputs which are less observable, unavailable orwhere the observable data does not support the majority of the instrument’sfair value. Level 3 instruments may include items based on pricing services orbroker quotes where we are unable to verify the observability of inputs intotheir prices. Level 3 instruments include longer-term transactions,transactions in less active markets or transactions at locations for whichpricing information is not available. In these instances, internally developedmethodologies are used to determine fair value which primarily includesextrapolation of observable future prices to similar locations, similarinstruments or later time periods.

 

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The following table includes ourderivatives that are carried at fair value for our trading and non-tradingactivities as at December 31, 2009 and 2008. Financial assets andliabilities are classified in the fair value hierarchy in their entirety basedon the least observable input that is significant to the fair valuemeasurement. Assessment of the significance of a particular input to the fairvalue measurement requires judgment and may affect placement within the fairvalue hierarchy levels.

 
| **Net Derivatives at December 31,  2009** | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|-----------|------------|
| Commodity Contracts                            |       | (143        | )          | 167         |       | 42          |       | 66        |       |
| Foreign Exchange Contracts                     |       | —      |       | (43         | )          | —      |       | (43       | )          |
| Trading Derivatives                            |       | (143        | )          | 124         |       | 42          |       | 23        |       |
| Non-Trading Derivatives                        |       | —      |       | (9          | )          | —      |       | (9        | )          |
| **Total**                                      | ** ** | **(143**    | **)**      | **115**     | ** ** | **42**      | ** ** | **14**    | ** ** |

 
| **Net Derivatives at December 31,  2008** | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|-----------|------------|
| Trading Derivatives                            |       | 13          |       | 132         |       | (82         | )          | 63        |       |
| Non-Trading Derivatives                        |       | —      |       | 193         |       | —      |       | 193       |       |
| **Total**                                      | ** ** | **13**      | ** ** | **325**     | ** ** | **(82**     | **)**      | **256**   | ** ** |

 

A reconciliation of changes inthe fair value of our derivatives classified as Level 3 for the year ended December 31,2009 is provided below:

 
| **Level  3 Net Derivatives at January 1, 2009**                                      | ** ** | **(82**    | **)**      |
|-------------------------------------------------------------------------------------------|------------|------------|------------|
| Realized and unrealized gains (losses)                                                    |       | 74         |       |
| Purchases                                                                                 |       | 4          |       |
| Settlements                                                                               |       | 54         |       |
| Transfers into Level 3                                                                    |       | —     |       |
| Transfers out of Level 3                                                                  |       | (8         | )          |
| **Level  3 Net Derivatives at December 31, 2009**                                    | ** ** | **42**     | ** ** |
| ** **                                                                                | ** ** | ** ** | ** ** |
| Unsettled gains (losses) relating to instruments  still held as of December 31, 2009 |       | 66         |       |

 

A reconciliation of changes inthe fair value of our derivatives classified as Level 3 for the year ended December 31,2008 is provided below:

 
| **Level  3 Net Derivatives at January 1, 2008**                                      | ** ** | **(7**     | **)**      |
|-------------------------------------------------------------------------------------------|------------|------------|------------|
| Realized and unrealized gains (losses)                                                    |       | (64        | )          |
| Purchases, issuances and settlements                                                      |       | (9         | )          |
| Transfers in and/or out of Level 3                                                        |       | (2         | )          |
| **Level  3 Net Derivatives at December 31, 2008**                                    | ** ** | **(82**    | **)**      |
| ** **                                                                                | ** ** | ** ** | ** ** |
| Unsettled gains (losses) relating to instruments  still held as of December 31, 2008 |       | 16         |       |

 

Items classified in Level 3 aregenerally economically hedged such that gains or losses on positions classifiedin Level 3 are often offset by gains or losses on positions classified in Level1 or 2. Transfers into or out of Level 3 represent existing assets andliabilities that were either previously categorized as a higher level for whichthe inputs became unobservable or assets and liabilities that were previouslyclassified as Level 3 for which the lowest significant input became observableduring the period. Fair values of instruments in Level 3 are determined usingbroker quotes, pricing services, and internally-developed inputs. We performeda sensitivity analysis of inputs used to calculate the fair value of Level 3instruments. Using reasonably possible alternative assumptions, the fair valueof Level 3 instruments would change by $12 million.

 

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**7****.       RISKMANAGEMENT**

** **

**(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 given that the majority of our debt is fixed rate.

 

**Commodity price 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 and gasproduction 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 contractedvolumes. We actively manage these risks by using derivative contracts such ascommodity put options.

 

Our energy marketing businessis focused on providing services to our customers and suppliers to meet theirenergy commodity needs. We market and trade physical energy commodities inselected regions of the world 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 from ourviews 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.

 

Ourrisk management activities make use of tools such as Value-at-Risk (VaR) andstress testing. VaR is a statistical estimate of the expected profit or loss ofa portfolio of positions assuming normal market conditions. We use a 95%confidence interval and an assumed two day holding period in our measure,although actual results can differ from this estimate in abnormal marketconditions, or if positions are held longer than two days based on market viewsor a lack of market liquidity to exit them, which is typical for long-termassets and may also apply to nearer term positions. We estimate VaR primarilyby using the Variance-Covariance method based on historical commodity 

 

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pricevolatility and correlation inputs where available, and by historical simulationin other situations. Our estimate is based upon the following key assumptions:

 

·                  changes in commodityprices are either normally or “T” distributed;

·                  price volatility remainsstable; and

·                  price correlationrelationships remain stable.

 

We have defined VaR limits fordifferent segments of our energy marketing business. These limits arecalculated on an economic basis and include physical and financial derivatives,as well as physical transportation and storage capacity contracts accounted foras executory 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)*** | ** ** | **2009** | ** ** | **2008** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|
| Year End                                    |       | 11       |       | 25       |       |
| High                                        |       | 24       |       | 40       |       |
| Low                                         |       | 9        |       | 19       |       |
| Average                                     |       | 15       |       | 30       |       |

 

If a 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 abnormal changesin prices on our positions.

 

**Foreign currency risk**

** **

Foreign currency risk iscreated by fluctuations in the fair values or cash flows of financialinstruments due to changes in foreign exchange rates. A substantial portion ofour activities are transacted in or referenced to US dollars including:

 

·                  sales of crude oil,natural gas and certain chemicals products;

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

·                  commodity derivativecontracts used primarily by our energy marketing group; and

·                  short-term borrowings andlong-term debt.

 

The foreign exchange gains orlosses related to the effective portion of our designated US-dollar debt areincluded in accumulated other comprehensive income in equity. Our netinvestment in self-sustaining foreign operations and our designated US-dollardebt at December 31, 2009 and 2008 are as follows:

 
| ***(US$ millions)***                            | ** ** | **December 31, 2009** | ** ** | **December 31, 2008** | ** ** |
|------------------------------------------------------|------------|----------------------------|------------|----------------------------|------------|
| Net Investment in Self-Sustaining Foreign Operations |       | 4,492                      |       | 4,662                      |       |
| Designated US-Dollar Debt                            |       | 4,492                      |       | 4,545                      |       |

 

In our oil and gas operations,we manage our exposure to fluctuations between the US and Canadian dollar bymaintaining our expected net cash flows and borrowings in the same currency.Cash inflows generated by our foreign operations and borrowings on ourUS-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. For the yearended December 31, 2009, the undesignated portion of our US-dollar debtresulted in a net foreign exchange gain of $151 million ($132 million, net of incometax expense) and is included in marketing and other income (2008—nil).

 

A one cent change in the USdollar to Canadian dollar exchange rate would increase or decrease ouraccumulated other comprehensive income by approximately $45 million, net of incometax, and would increase or decrease our net income by approximately $10million, net of 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 US dollars,British pounds and Euros. We actively manage significant currency exposuresusing forward contracts and swaps.

 

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**(B)  CREDIT RISK**

 

Creditrisk affects both our trading and non-trading activities and is the risk ofloss if counterparties do not fulfill their contractual obligations. Most ofour credit exposures are with counterparties in the energy industry, includingintegrated oil companies, refiners and utilities, and are subject to normalindustry credit risk. Approximately 72% of our exposure is with these largeenergy companies. This concentration of risk within the energy industry isreduced because of our broad base of domestic and international counterparties.We take the following measures to reduce this risk:

 

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

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

·                  routinely monitor creditrisk exposures, including sector, geographic and corporate concentrations ofcredit, and report these to our Executive Risk Management Committee and theFinance Committee of the board;

·                  set credit limits basedon rating agency credit ratings and internal assessments based on company andindustry analysis;

·                  review counterpartycredit limits regularly; and

·                  use standard agreementsthat allow for the netting of exposures associated with a single counterparty.

 

Webelieve these measures minimize our overall credit risk; however, there can beno assurance that these processes will protect us against all losses fromnon-performance. Since 2008, we have taken the following specific actions forcertain counterparties deemed to be at higher risk of non-performance:

 

·                  ceased tradingactivities;

·                  significantly reducedand, in some cases, revoked credit privileges;

·                  redirected business to:i) exchanges or clearing houses; and ii) entities with physical-basedoperations;

·                  increased “set off”arrangements with counterparties; and

·                  increased collateral andmargining requirements where possible.

 

At December 31, 2009, onlyone counterparty individually made up more than 10% of our credit exposure.This counterparty is a major integrated oil company with a strong investmentgrade rating. One other counterparty made up more than 5% of our creditexposure. The following table illustrates the composition of credit exposure bycredit rating.

 
| **Credit  Rating**   | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------|------------|----------|------------|----------|------------|
| A or higher          |       | 67       | %          | 65       | %          |
| BBB                  |       | 26       | %          | 29       | %          |
| Non-Investment Grade |       | 7        | %          | 6        | %          |
| **Total**            | ** ** | **100**  | **%**      | **100**  | **%**      |

 

Our maximum counterparty creditexposure at the balance sheet date consists primarily of the carrying amountsof non-derivative financial assets such as cash and cash equivalents,restricted cash, accounts receivable, as well as the fair value of derivativefinancial assets. We have provided an allowance of $54 million for credit riskwith our counterparties. In addition, we incorporate the credit risk associatedwith counterparty default, as well as Nexen’s own credit risk, into ourestimates of fair value.

 

Collateral received fromcustomers at December 31, 2009 includes $45 million of cash and $444million of letters of credit. The cash received is included in accounts payableand accrued liabilities.

 

**(C)  LIQUIDITY RISK**

 

Liquidity risk is the risk thatwe 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 our energy marketing business.We generally rely on operating cash flows to provide liquidity and we alsomaintain significant undrawn committed credit facilities. At December 31,2009, we had about $3.3 billion of cash and available undrawn committed linesof credit (US$3.2 billion). This includes $1.7 billion (US$1.6 billion) of cashand cash equivalents on hand and undrawn term credit facilities of $1.6 billion(US$1.6 billion), of which $407 million (US$389 million) was supporting lettersof credit at December 31, 2009. Our committed term credit facilities areavailable until 2012 unless extended. We also have $492 million (US$470million) of undrawn, uncommitted credit facilities, of which $86 million (US$82million) was supporting letters of credit at year end.

 

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The following table details thecontractual maturities for our non-derivative financial liabilities, including boththe principal and interest cash flows at December 31, 2009:

 
| ** **                  | ** ** | **December 31, 2009** | ** ** |
|-----------------------------|------------|----------------------------|------------|
| ** **                  | ** ** | **Total**                  | ** ** | **< 1 Year** | ** ** | **1–3 Years** | ** ** | **4–5 Years** | ** ** | **> 5 Years** | ** ** |
| Long-Term Debt (Note 9)     |       | 7,343                      |       | — |   | 1,803 |   | 621 |   | 4,919 |   |
| Interest on Long-Term Debt1 |       | 8,052                      |       | 361 |   | 721 |   | 688 |   | 6,282 |   |
| **Total**                   | ** ** | **15,395**                 | ** ** | **361** | ** ** | **2,524** | ** ** | **1,309** | ** ** | **11,201** | ** ** |

 

----

*1*                 Excludes interest ondrawn term credit facilities of $1.6 billion (US$1.5 billion) and Canexus termcredit facilities of $233 million (US$223 million) as the amounts drawn on thefacilities fluctuate. Based on amounts drawn at December 31, 2009 andexisting variable interest rates, we would be required to pay $19 million peryear 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.

 
| ** **                       | ** ** | **December 31, 2009** | ** ** |
|----------------------------------|------------|----------------------------|------------|
| ** **                       | ** ** | **Total**                  | ** ** | **< 1 Year** | ** ** | **1–3 Years** | ** ** | **4–5 Years** | ** ** | **> 5 Years** | ** ** |
| Trading Derivatives (Note 6)     |       | 668                        |       | 456 |   | 180 |   | 32 |   | — |   |
| Non-Trading Derivatives (Note 6) |       | 26                         |       | 26 |   | — |   | — |   | — |   |
| **Total**                        | ** ** | **694**                    | ** ** | **482** | ** ** | **180** | ** ** | **32** | ** ** | **—** | ** ** |

 

The commercial agreements ourenergy marketing group enters into often include financial assurance provisionsthat allow us and our counterparties to effectively manage credit risk. Theagreements 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 31,2009, we could be required to post collateral of up to $962 million 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, 2009,collateral we have posted with counterparties includes $17 million of cash and$279 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-traded derivativecontracts are also subject to margin requirements. We have margin deposits of$198 million (2008—$103 million), which have been included in restricted cash.

 

**8****.       ACCOUNTSPAYABLE AND ACCRUED LIABILITIES**

 
| ** **                                     | ** ** | **2009**  | ** ** | **2008**  | ** ** |
|------------------------------------------------|------------|-----------|------------|-----------|------------|
| Energy Marketing Payables                      |       | 1,366     |       | 1,302     |       |
| Energy Marketing Derivative Contracts (Note 6) |       | 456       |       | 615       |       |
| Accrued Payables                               |       | 619       |       | 878       |       |
| Trade Payables                                 |       | 210       |       | 252       |       |
| Income Taxes Payable                           |       | 179       |       | 69        |       |
| Stock-Based Compensation                       |       | 72        |       | 97        |       |
| Other                                          |       | 136       |       | 113       |       |
| **Total**                                      | ** ** | **3,038** | ** ** | **3,326** | ** ** |

 

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**9****.       SHORT-TERMBORROWINGS AND LONG-TERM DEBT**

 
| ** **                                                          | ** ** | **2009**  | ** ** | **2008**  | ** ** |
|---------------------------------------------------------------------|------------|-----------|------------|-----------|------------|
| Canexus Term Credit Facilities, due 2011 (US$223 million drawn) (A) |       | 233       |       | 223       |       |
| Term Credit Facilities, due 2012 (US$1.5 billion drawn) (B)         |       | 1,570     |       | 1,225     |       |
| Canexus Notes, due 2013 (US$50 million) (C)                         |       | 52        |       | 61        |       |
| Notes, due 2013 (US$500 million) (D)                                |       | 523       |       | 612       |       |
| Canexus Convertible Debentures, due 2014 (E)                        |       | 46        |       | —    |       |
| Notes, due 2015 (US$250 million) (F)                                |       | 262       |       | 306       |       |
| Notes, due 2017 (US$250 million) (G)                                |       | 262       |       | 306       |       |
| Notes, due 2019 (US$300 million) (H)                                |       | 314       |       | —    |       |
| Notes, due 2028 (US$200 million) (I)                                |       | 209       |       | 245       |       |
| Notes, due 2032 (US$500 million) (J)                                |       | 523       |       | 612       |       |
| Notes, due 2035 (US$790 million) (K)                                |       | 827       |       | 968       |       |
| Notes, due 2037 (US$1,250 million) (L)                              |       | 1,308     |       | 1,531     |       |
| Notes, due 2039 (US$700 million) (M)                                |       | 733       |       | —    |       |
| Subordinated Debentures, due 2043 (US$460 million) (N)              |       | 481       |       | 563       |       |
|                                                                |       | 7,343     |       | 6,652     |       |
| Unamortized Discount and Debt Issue Costs                           |       | (92       | )          | (74       | )          |
| **Total**                                                           | ** ** | **7,251** | ** ** | **6,578** | ** ** |

 

**(A)  CANEXUSTERM CREDIT FACILITIES**

 

Canexus has $451 million (US$431 million) of committed,secured term credit facilities, available until 2011. At December 31,2009, $233 million (US$223 million) was drawn on these facilities (2008—$223million (US$182 million)). Borrowings are available as Canadian bankers’acceptances, LIBOR-based loans, Canadian prime rate loans or US-dollar baserate loans. Interest is payable monthly at floating rates. The term creditfacilities are secured by a floating charge debenture over all of Canexus’assets. The credit facility also contains covenants with respect to certainfinancial ratios for Canexus. During 2009, the weighted-average interest rateon the Canexus term credit facilities was 2.2% (2008—4.4%).

 

**(B)  TERMCREDIT FACILITIES**

 

We have unsecured term credit facilities of $3.2 billion(US$3.1 billion) available until July 2012. At December 31, 2009,$1.6 billion (US$1.5 billion) was drawn on these facilities (2008—$1.2 billion(US$1 billion)). Borrowings are available as Canadian bankers’ acceptances,LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans orBritish pound call-rate loans. Interest is payable at floating rates. During2009, the weighted-average interest rate was 1.0% (2008—2.8%). At December 31,2009, $407 million (US$389 million) of these facilities were utilized tosupport outstanding letters of credit (December 31, 2008—$381 million(US$311 million)).

 

**(C)  CANEXUSNOTES, DUE 2013**

 

During May 2008, Canexus issued US$50 million of notes.Interest is payable quarterly at a rate of 6.57% and the principal is to berepaid in May 2013. Canexus may redeem part or all of the notes at anytime. The redemption price will be the greater of par and an amount thatprovides the same yield as a US Treasury security having a term-to-maturityequal to the remaining term of the notes plus 0.2%.

 

**(D)  NOTES,DUE 2013**

 

During November 2003, we issued US$500 million of notes.Interest is payable semi-annually at a rate of 5.05%, and the principal is tobe repaid in November 2013. We may redeem part or all of the notes at anytime. The redemption price will be the greater of par and an amount thatprovides the same yield as a US Treasury security having a term-to-maturityequal to the remaining term of the notes plus 0.2%.

 

**(E)   CANEXUSCONVERTIBLE DEBENTURES**

 

In August 2009, Canexus issued $46 million of unsecuredsubordinated convertible debentures to non-controlling interests. Interest ispayable semi-annually at a rate of 8.00%. These debentures mature on December 31,2014 and are convertible at the holder’s option at any time prior to the closeof business on the earlier of i) the maturity date and ii) the business dayimmediately preceding the date specified by Canexus for redemption of thedebentures into trust units. The conversion price is $5.10 per trust unit.

 

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Canexus has the option to redeem the debentures in whole orin part from time to time subject to the satisfaction of certain conditions,after December 31, 2012 but before maturity, at a redemption price equalto the principal amount and unpaid interest. Canexus may elect to satisfy itsobligation to pay interest or repay the principal by issuing trust units atmarket value.

 

The estimated fair value of the conversion feature of theconvertible debentures amounted to $4 million and was included innon-controlling interests in equity. The amount of the convertible debenturesallocated to long-term debt is accreted over the term of the debt using theeffective interest rate method.

 

Concurrent with the issuance of the $46 million of unsecuredsubordinated convertible debentures to non-controlling interests, we acquired$40 million of debentures from Canexus with substantially the same terms whichallow us to protect against dilution of our ownership interest at our option.These debentures are eliminated on consolidation.

 

**(F)   NOTES,DUE 2015**

 

During March 2005, we issued US$250 million of notes.Interest is payable semi-annually at a rate of 5.2%, and the principal is to berepaid in March 2015. We may redeem part or all of the notes at any time.The redemption price will be the greater of par and an amount that provides thesame yield as a US Treasury security having a term-to-maturity equal to theremaining term of the notes plus 0.15%.

 

**(G)  NOTES,DUE 2017**

 

During May 2007, we issued US$250 million of notes.Interest is payable semi-annually at a rate of 5.65%, and the principal is tobe repaid in May 2017. We may redeem part or all of the notes at any time.The redemption price will be the greater of par and an amount that provides thesame yield as a US Treasury security having a term-to-maturity equal to theremaining term of the notes plus 0.2%.

 

**(H)  NOTES,DUE 2019**

 

In July 2009, we issued US$300 million of notes.Interest is payable semi-annually at a rate of 6.2%, and the principal is to berepaid in July 2019. We may redeem part or all of the notes at any time.The redemption price will be the greater of par and an amount that provides thesame yield as a US Treasury security having a term-to-maturity equal to theremaining term of the notes plus 0.40%.

 

**(I)    NOTES,DUE 2028**

 

During April 1998, we issued US$200 million of notes.Interest is payable semi-annually at a rate of 7.4%, and the principal is to berepaid in May 2028. We may redeem part or all of the notes at any time.The redemption price will be the greater of par and an amount that provides thesame yield as a US Treasury security having a term-to-maturity equal to theremaining term of the notes plus 0.25%.

 

**(J)   NOTES,DUE 2032**

 

During March 2002, we issued US$500 million of notes.Interest is payable semi-annually at a rate of 7.875%, and the principal is tobe repaid in March 2032. We may redeem part or all of the notes at anytime. The redemption price will be the greater of par and an amount thatprovides the same yield as a US Treasury security having a term-to-maturityequal to the remaining term of the notes plus 0.375%.

 

**(K)  NOTES,DUE 2035**

 

During March 2005, we issued US$790 million of notes.Interest is payable semi-annually at a rate of 5.875%, and the principal is tobe repaid in March 2035. We may redeem part or all of the notes at anytime. The redemption price will be the greater of par and an amount thatprovides the same yield as a US Treasury security having a term-to-maturityequal to the remaining term of the notes plus 0.2%.

 

**(L)   NOTES,DUE 2037**

 

During May 2007, we issued US$1,250 million of notes.Interest is payable semi-annually at a rate of 6.4%, and the principal is to berepaid in May 2037. We may redeem part or all of the notes at any time.The redemption price will be the greater of par and an amount that provides thesame yield as a US Treasury security having a term-to-maturity equal to theremaining term of the notes plus 0.35%.

 

**(M)  NOTES,DUE 2039**

 

In July 2009, we issued US$700 million of notes.Interest is payable semi-annually at a rate of 7.5%, and the principal is to berepaid in July 2039. We may redeem part or all of the notes at any time.The redemption price will be the greater of par and an amount that provides thesame yield as a US Treasury security having a term-to-maturity equal to theremaining term of the notes plus 0.45%.

 

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**(N)  SUBORDINATEDDEBENTURES, DUE 2043**

 

During November 2003, we issued US$460 million ofunsecured subordinated debentures. Interest is payable quarterly at a rate of7.35%, and the principal is to be repaid in November 2043. We may redeempart or all of the debentures at any time on or after November 8, 2008.The redemption price is equal to the par value of the principal amount plus anyaccrued and unpaid interest to the redemption date. We may choose to redeem theprincipal amount with either cash or common shares.

 

**(O)  LONG-TERMDEBT REPAYMENTS**

 

 
| 2010       |       | —    |       |
|------------|------------|-----------|------------|
| 2011       |       | 233       | 1          |
| 2012       |       | 1,570     |       |
| 2013       |       | 575       |       |
| 2014       |       | 46        |       |
| Thereafter |       | 4,919     |       |
| **Total**  | ** ** | **7,343** | ** ** |

 

----

*1*                 Canexus term credit facility.

* *

**(P)   DEBTCOVENANTS**

 

Some of our debt instruments contain covenants with respectto certain financial ratios and our ability to grant security. At December 31,2009 and 2008, we were in compliance with all covenants.

 

**(Q)  SHORT-TERMBORROWINGS**

 

Nexen has uncommitted, unsecured credit facilities ofapproximately $492 million (US$470 million), none of which were drawn at December 31,2009 (2008—nil). We utilized $86 million (US$82 million) of these facilities tosupport outstanding letters of credit at December 31, 2009 (2008—$29million (US$24 million)). Interest is payable at floating rates. During2009, the weighted-average interest rate on our short-term borrowings was 2.1%(2008—3.2%).

 

**(R)  INTERESTEXPENSE**

 

 
| ** **        | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-------------------|------------|----------|------------|----------|------------|----------|------------|
| Long-Term Debt    |       | 372      |       | 315      |       | 323      |       |
| Other             |       | 17       |       | 19       |       | 18       |       |
| Total             |       | 389      |       | 334      |       | 341      |       |
| Less: Capitalized |       | (77      | )          | (240     | )          | (173     | )          |
| **Total**         | ** ** | **312**  | ** ** | **94**   | ** ** | **168**  | ** ** |

 

Capitalized interest relates to and is included as part ofthe cost of oil and gas properties. The capitalization rates are based on ourweighted-average cost of borrowings. In 2009, we ceased capitalizing intereston Phase 1 of Long Lake.

 

**10****.     CAPITALDISCLOSURE**

 

Our objective formanaging our capital structure is to ensure that we have the financialcapacity, liquidity and flexibility to fund our investment in full-cycleexploration and development of conventional and unconventional resources andfor energy marketing activities. We generally rely on operating cash flows tofund capital investments. However, given the long cycle-time of some of ourdevelopment projects which require significant capital investment prior to cashflow generation and volatile commodity prices, it is not unusual for capitalexpenditures to exceed our cash flow from operating activities in any givenperiod. As such, our financing needs depend on the timing of expected net cashflows in a particular development or commodity cycle. This requires us tomaintain financial flexibility and liquidity. Our capital management policiesare aimed at:

 

·                  maintaining an appropriatebalance between short-term borrowings, long-term debt and equity;

·                  maintaining sufficient undrawncommitted credit capacity to provide liquidity;

·                  ensuring ample covenant roompermitting us to draw on credit lines as required; and

·                  ensuring we maintain a creditrating that is appropriate for our circumstances.

 

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We have the ability to make adjustments to our capitalstructure by issuing additional equity or debt, returning cash to shareholdersand making adjustments to our capital investment programs. Our capital consistsof equity, short-term borrowings, long-term debt, and cash and cash equivalentsas follows:

 

 
| **Net  Debt****1**              | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|---------------------------------|------------|------------|------------|------------|------------|
| Long-Term Debt                  |       | 7,251      |       | 6,578      |       |
| Less: Cash and Cash Equivalents |       | (1,700     | )          | (2,003     | )          |
| **Total**                       | ** ** | **5,551**  | ** ** | **4,575**  | ** ** |
| ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Equity****2**                 | ** ** | **7,646**  | ** ** | **7,191**  | ** ** |

 

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*1*                 Includes all of our borrowingsand is calculated as long-term debt and short-term borrowings less cash andcash equivalents.

*2*                 Equity is the historical issueof equity and accumulated retained earnings.

* *

We monitor the leverage in our capital structure by reviewingthe ratio of net debt to cash flow from operating activities and interestcoverage ratios at various commodity prices.

 

We use the ratio of net debt to cash flow from operatingactivities as a key indicator of our leverage and to monitor the strength ofour balance sheet. Net debt is a non-GAAP measure that does not have anystandard meaning prescribed by GAAP and is therefore unlikely to be comparableto similar measures presented by others. We calculate net debt using the GAAPmeasures of long-term debt and short-term borrowings less cash and cashequivalents (excluding restricted cash).

 

For the twelve months ended December 31, 2009, the netdebt to cash flow from operating activities ratio (before changes in non cashworking capital and other) was 2.5 times compared to 1.1 times at December 31,2008. While we typically expect the target ratio to fluctuate between 1.0 and2.0 times under normalized commodity prices, this can be higher or lowerdepending on commodity price volatility or when we identify strategicopportunities requiring additional investment. Whenever we exceed our targetratio, we assess whether we need to develop a strategy to reduce our leverageand lower this ratio back to target levels over time.

 

Our interest coverage ratio monitors our ability to fund theinterest requirements associated with our debt. Our interest coverage decreasedfrom 15.6 times at the end of 2008 to 8.5 times at December 31, 2009.Interest coverage is calculated by dividing our twelve-month trailing earningsbefore interest, taxes, DD&A (adjusted EBITDA) by interest expense beforecapitalized interest. Adjusted EBITDA is a non-GAAP measure which is calculatedusing net income excluding interest expense, provision for income taxes,exploration expenses, DD&A, impairment and other non-cash expenses. Thecalculation of adjusted EBITDA is set out in the following table and isunlikely to be comparable to similar measures presented by others.

 
| ** **                                           | ** ** | **2009**  | ** ** | **2008**  | ** ** |
|------------------------------------------------------|------------|-----------|------------|-----------|------------|
| Net Income Attributable to Nexen Inc.                |       | 536       |       | 1,715     |       |
| Add:                                                 |       |      |       |      |       |
| Interest Expense                                     |       | 312       |       | 94        |       |
| Provision for Income Taxes                           |       | 260       |       | 1,457     |       |
| Depreciation, Depletion, Amortization and Impairment |       | 1,802     |       | 2,014     |       |
| Exploration Expense                                  |       | 302       |       | 402       |       |
| Recovery of Non-Cash Stock-Based Compensation        |       | (10       | )          | (272      | )          |
| Change in Fair Value of Crude Oil Put Options        |       | 251       |       | (203      | )          |
| Other Non-Cash Expenses                              |       | (136      | )          | (1        | )          |
| **Adjusted  EBITDA**                                 | ** ** | **3,317** | ** ** | **5,206** | ** ** |

 

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**11****.     ASSETRETIREMENT OBLIGATIONS**

 

Changes in carrying amounts of the asset retirementobligations associated with our PP&E are as follows:

 
| ** **                                       | ** ** | **2009**  | ** ** | **2008**  | ** ** |
|--------------------------------------------------|------------|-----------|------------|-----------|------------|
| Asset Retirement Obligations, Beginning of Year  |       | 1,059     |       | 832       |       |
| Obligations Incurred with Development Activities |       | 27        |       | 32        |       |
| Obligations Settled                              |       | (42       | )          | (45       | )          |
| Accretion Expense                                |       | 70        |       | 58        |       |
| Revisions to Estimates                           |       | 13        |       | 159       |       |
| Effects of Changes in Foreign Exchange Rate      |       | (74       | )          | 23        |       |
| **End of Year****1, 2**                          | ** ** | **1,053** | ** ** | **1,059** | ** ** |

 

----

*1*                 Obligations due within twelvemonths of $35 million (2008—$35 million) have been included in accounts payableand accrued liabilities.

*2*                 Obligations relating to our oiland gas activities amount to $1,002 million (2008—$1,009 million) andobligations relating to our chemicals business amount to $51 million (2008—$50million).

* *

Our total estimated undiscounted inflated asset retirementobligations amount to $2,341 million (2008—$2,393 million). We discounted thetotal estimated asset retirement obligations using a weighted-average,credit-adjusted risk-free rate of 5.9% (2008—5.9%). Approximately $276 millionincluded in our asset retirement obligations will be settled over the next fiveyears. The remaining obligations settle beyond five years and will be funded byfuture cash flows from our operations.

 

**12****.     DEFERREDCREDITS AND OTHER LIABILITIES**

 
| ** **                                           | ** ** | **2009**  | ** ** | **2008**  | ** ** |
|------------------------------------------------------|------------|-----------|------------|-----------|------------|
| Deferred Tax Credit                                  |       | 503       |       | 709       |       |
| Long-Term Marketing Derivative Contracts (Note 6)    |       | 212       |       | 294       |       |
| Defined Benefit Pension Obligations (Note 13)        |       | 76        |       | 67        |       |
| Capital Lease Obligations                            |       | 61        |       | 53        |       |
| Deferred Transportation Revenue                      |       | 55        |       | 69        |       |
| Fixed-Price Natural Gas Contracts and Swaps (Note 6) |       | —    |       | 26        |       |
| Other                                                |       | 114       |       | 106       |       |
| **Total**                                            | ** ** | **1,021** | ** ** | **1,324** | ** ** |

 

During 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 a thirdparty or depletion through use. At December 31, 2009, we deferredrecognizing $503 million (2008 — $709 million) of tax credits in ourConsolidated Statement of Income.

 

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**13****.     PENSIONAND OTHER POST-RETIREMENT BENEFITS**

 

Nexen and Canexus have contributory and non-contributorydefined benefit and defined contribution pension plans, as well as otherpost-retirement benefit programs, which cover substantially all employees.Syncrude has a defined benefit plan for its employees, and we disclose only ourproportionate share of this plan.

 

**(A)  DEFINEDBENEFIT PENSION PLANS**

 

The cost of pension benefits earned by employees isdetermined using the projected-benefit method prorated on employment servicesand is expensed as services are rendered. We fund these plans according tofederal and provincial government regulations by contributing to trust fundsadministered by an independent trustee. These funds are invested primarily inequities and bonds. As at December 31, 2009, Nexen’s registered definedbenefit pension plan was overfunded by $21 million. Nexen’s supplementalbenefit plan is funded from our operating cash flows and the year end obligationof $76 million is backed by an irrevocable letter of credit.

 
| ** **                                                   | ** ** | **2009**   | ** ** | **2008**    | ** ** |
|--------------------------------------------------------------|------------|------------|------------|-------------|------------|
| ** **                                                   | ** ** | **Nexen**  | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** | **Nexen** | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** |
| **Change in  Projected Benefit Obligation (PBO)**            |       |       |       |        |       |   |   |   |   |   |   |   |   |
| Beginning of Year                                            |       | 265        |       | 59          |       | 107 |   | 272 |   | 62 |   | 125 |   |
| Service Cost                                                 |       | 18         |       | 3           |       | 5 |   | 23 |   | 4 |   | 4 |   |
| Interest Cost                                                |       | 18         |       | 4           |       | 7 |   | 17 |   | 4 |   | 7 |   |
| Plan Participants’ Contributions                        |       | 6          |       | 1           |       | 1 |   | 5 |   | 1 |   | 1 |   |
| Actuarial Loss/(Gain)                                        |       | 24         |       | 5           |       | 10 |   | (39 | ) | (11 | ) | (25 | ) |
| Benefits Paid                                                |       | (12        | )          | (4          | )          | (5 | ) | (13 | ) | (1 | ) | (5 | ) |
| **End of Year****1,**** ****2**                         | ** ** | **319**    | ** ** | **68**      | ** ** | **125** | ** ** | **265** | ** ** | **59** | ** ** | **107** | ** ** |
| **Change in  Fair Value of Plan Assets**                     |       |       |       |        |       |   |   |   |   |   |   |   |   |
| Beginning of Year                                            |       | 153        |       | 50          |       | 57 |   | 200 |   | 55 |   | 74 |   |
| Actual Return on Plan Assets                                 |       | 40         |       | 6           |       | 9 |   | (54 | ) | (9 | ) | (19 | ) |
| Employer’s Contribution                                 |       | 77         |       | 3           |       | 7 |   | 15 |   | 4 |   | 6 |   |
| Plan Participants’ Contributions                        |       | 6          |       | 1           |       | 1 |   | 5 |   | 1 |   | 1 |   |
| Benefits Paid                                                |       | (12        | )          | (4          | )          | (5 | ) | (13 | ) | (1 | ) | (5 | ) |
| **End of Year**                                              | ** ** | **264**    | ** ** | **56**      | ** ** | **69** | ** ** | **153** | ** ** | **50** | ** ** | **57** | ** ** |
| **Reconciliation  of Funded Status**                         |       |       |       |        |       |   |   |   |   |   |   |   |   |
| Funded Status1                                               |       | (55        | )          | (12         | )          | (56 | ) | (112 | ) | (9 | ) | (50 | ) |
| Unamortized Prior Service Costs                              |       | 1          |       | —      |       | — |   | 1 |   | — |   | — |   |
| Unamortized Net Actuarial Loss                               |       | 55         |       | 10          |       | 39 |   | 60 |   | 8 |   | 35 |   |
| **Net  Recognized Pension Asset (Liability)**                | ** ** | **1**      | ** ** | **(2**      | **)**      | **(17** | **)** | **(51** | **)** | **(1** | **)** | **(15** | **)** |
| **Pension  Liability******                                   | ** ** | ** ** | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Deferred Charges and Other Assets (Note 5)                   |       | 60         |       | —      |       | — |   | 2 |   | — |   | — |   |
| Accounts Payable and Accrued Liabilities                     |       | (2         | )          | —      |       | — |   | (2 | ) | — |   | — |   |
| Deferred Credits and Other Liabilities (Note 12)             |       | (57        | )          | (2          | )          | (17 | ) | (51 | ) | (1 | ) | (15 | ) |
| **Net  Recognized Pension Asset (Liability)**                | ** ** | **1**      | ** ** | **(2**      | **)**      | **(17** | **)** | **(51** | **)** | **(1** | **)** | **(15** | **)** |
| Assumptions (%)                                              |       |       |       |        |       |   |   |   |   |   |   |   |   |
| Accrued Benefit Obligation at December 31 Discount Rate |       | 6.00       |       | 6.00        |       | 6.00 |   | 6.50 |   | 6.50 |   | 6.50 |   |
| 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 Discount Rate   |       | 6.50       |       | 6.50        |       | 6.00 |   | 5.25 |   | 5.25 |   | 6.50 |   |
| 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               |       | 7.00       |       | 6.50        |       | 8.50 |   | 7.00 |   | 6.50 |   | 8.50 |   |

 

----

*1*                 Includes self-fundedobligations for supplemental benefits to the extent that the benefit is limitedby statutory guidelines. At December 31, 2009, the PBO for Nexen’ssupplemental benefits plan was $76 million (2008—$62 million) and $1 millionfor Canexus (2008—$1 million). The self-funded obligations for supplementalbenefits are backed by an irrevocable letter of credit.

*2*                 The accumulated benefitobligations (the projected benefit obligation excluding future salaryincreases) of the Nexen and Canexus plans were $211 million and $52 million at December 31,2009, respectively (2008—$179 million and $46 million, respectively). Nexen’ssupplemental pension plan’s accumulated benefit obligation was $65 million at December 31,2009 (2008—$49 million). Nexen’s share of Syncrude’s employee pension plan’saccumulated benefit obligation was $96 million at December 31, 2009(2008—$82 million).

 

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**Net Pension Expense Recognized Under Our Defined Benefit Pension Plans**

 
| ** **                                                                                    | ** ** | **2009**   | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|-----------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| **Nexen**                                                                                     |       |       |       |       |       |       |       |
| Cost of Benefits Earned by Employees                                                          |       | 18         |       | 23         |       | 18         |       |
| Interest Cost on Benefits Earned                                                              |       | 18         |       | 17         |       | 13         |       |
| Actual (Return) Loss on Plan Assets                                                           |       | (40        | )          | 54         |       | (18        | )          |
| Actuarial (Gains)/Losses                                                                      |       | 24         |       | (39        | )          | (2         | )          |
| Pension Expense Before Adjustments for the Long-Term Nature of  Employee Future Benefit Costs |       | 20         |       | 55         |       | 11         |       |
| Difference Between Actual and Expected Return on Plan Assets                                  |       | 26         |       | (71        | )          | 5          |       |
| Difference Between Actual and Recognized Actuarial Losses                                     |       | (21        | )          | 41         |       | 3          |       |
| Difference Between Actual and Recognized Past Service Costs                                   |       | —     |       | 1          |       | 1          |       |
| **Net Pension  Expense**                                                                      | ** ** | **25**     | ** ** | **26**     | ** ** | **20**     | ** ** |
| ** **                                                                                    |       |       |       |       |       |       |       |
| **Canexus**                                                                                   |       |       |       |       |       |       |       |
| Cost of Benefits Earned by Employees                                                          |       | 3          |       | 4          |       | 3          |       |
| Interest Cost on Benefits Earned                                                              |       | 4          |       | 4          |       | 3          |       |
| Actual (Return) Loss on Plan Assets                                                           |       | (6         | )          | 9          |       | (2         | )          |
| Actuarial (Gains)/Losses                                                                      |       | 5          |       | (11        | )          | (3         | )          |
| Pension Expense Before Adjustments for the Long-Term Nature of  Employee Future Benefit Costs |       | 6          |       | 6          |       | 1          |       |
| Difference Between Actual and Expected Return on Plan Assets                                  |       | 3          |       | (13        | )          | (1         | )          |
| Difference Between Actual and Recognized Actuarial Gains                                      |       | (5         | )          | 11         |       | 3          |       |
| **Net Pension  Expense**                                                                      | ** ** | **4**      | ** ** | **4**      | ** ** | **3**      | ** ** |
| ** **                                                                                    |       |       |       |       |       |       |       |
| **Syncrude****1**                                                                        |       |       |       |       |       |       |       |
| Cost of Benefits Earned by Employees                                                          |       | 5          |       | 4          |       | 5          |       |
| Interest Cost on Benefits Earned                                                              |       | 7          |       | 7          |       | 6          |       |
| Actual (Return) Loss on Plan Assets                                                           |       | (9         | )          | 19         |       | (2         | )          |
| Actuarial (Gains)/Losses                                                                      |       | 10         |       | (25        | )          | 1          |       |
| Pension Expense Before Adjustments for the Long-Term Nature of  Employee Future Benefit Costs |       | 13         |       | 5          |       | 10         |       |
| Difference Between Actual and Expected Return on Plan Assets                                  |       | 4          |       | (26        | )          | (4         | )          |
| Difference Between Actual and Recognized Actuarial Losses                                     |       | (8         | )          | 27         |       | 1          |       |
| **Net Pension  Expense**                                                                      | ** ** | **9**      | ** ** | **6**      | ** ** | **7**      | ** ** |
| ** **                                                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Total Net  Pension Expense**                                                                | ** ** | **38**     | ** ** | **36**     | ** ** | **30**     | ** ** |

 

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*1*                 Nexen’s share of Syncrude’splan.

 

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**(B)  PLANASSET ALLOCATION AT DECEMBER 31**

 

Our investment goal for the assets in our defined benefitpension plans is to preserve capital and earn a long-term rate of return onassets, net of all management expenses, in excess of the inflation rate.Investment funds are managed by external fund managers based on policiesapproved by the Board of Directors and Pension Committees of Nexen and Canexus.Nexen’s and Canexus’ investment strategy is to diversify plan assets betweendebt and equity securities of Canadian and non-Canadian corporations that aretraded on recognized stock exchanges. Allowable and prohibited investment typesare also prescribed in Nexen’s and Canexus’ investment policies.

 

Nexen’s investment strategy is to ensure appropriatediversification between and within asset classes in order to optimize thereturn/risk trade-off. Nexen’s policy allows investment in equities, fixedincome, cash and real estate assets. Derivative instruments can be utilized asdeemed appropriate by the Pension Committee. Nexen’s expected long-term annualrate of return on plan assets assumption is based on a mix of historical marketreturns for debt and equity securities. The returns that are used as the basisfor future expectations are derived from the major asset categories that Nexenis currently invested in.

 

The target allocations for plan assets are identified in thetable below. Equity securities primarily include investments in large-capcompanies, both Canadian and foreign, and debt securities primarily includecorporate bonds of companies from diversified industries and Canadian Treasuryissuances. The Canadian fixed income pooled funds invest in low-cost fixed incomeindex funds that track the DEX Universe Bond Index. The Canadian equity pooledfunds invest in low-cost equity index funds that track the S&P/TSXComposite Index. The foreign equity pooled funds are invested one-third in alow-cost equity index fund that tracks the S&P 500 and the balanceprimarily in large-cap US and international companies.

 

Nexen also has an unregistered self-funded supplementalbenefits pension plan that covers obligations that are limited by statutoryguidelines. These benefits are backed by an irrevocable letter of credit andpayments are made from Nexen’s general operating revenues.

 

Because Canexus is a separate and publicly traded company,its pension plan is governed and administered separately from Nexen. Its assetsare subject to similar investment goals, policies and strategies.

 

Syncrude’s pension plans are governed and administeredseparately from Nexen’s and Canexus’. Syncrude’s investment assets are subjectto similar investment goals, policies and strategies.

 
| **Plan Asset  Allocation****(%)** | ** ** | **Expected 2010** | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|-----------------------------------|------------|-------------------|------------|------------|------------|------------|------------|
| **Nexen**                         |       |              |       |       |       |       |       |
| Equity Securities                 |       | 65                |       | 62         |       | 55         |       |
| Debt Securities                   |       | 35                |       | 38         |       | 45         |       |
| **Total**                         | ** ** | **100**           | ** ** | **100**    | ** ** | **100**    | ** ** |
| ** **                        | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Canexus**                       | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** |
| Equity Securities                 |       | 50                |       | 50         |       | 50         |       |
| Debt Securities                   |       | 50                |       | 50         |       | 50         |       |
| **Total**                         | ** ** | **100**           | ** ** | **100**    | ** ** | **100**    | ** ** |
| ** **                        | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Syncrude**                      |       |              |       |       |       |       |       |
| Equity Securities                 |       | 70                |       | 71         |       | 68         |       |
| Debt Securities                   |       | 30                |       | 29         |       | 32         |       |
| **Total**                         | ** ** | **100**           | ** ** | **100**    | ** ** | **100**    | ** ** |

 

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The fair values of Nexen’s defined benefit pension planassets at December 31, 2009 by asset category are as follows:

 
| ** **            | ** ** | **Fair Value Measurements at  December 31, 2009** | ** ** |
|-----------------------|------------|--------------------------------------------------------|------------|
| ** **            | ** ** | **Total**                                              | ** ** | **Quoted Prices in  Active Markets  for Identical  Assets (Level 1)** | ** ** | **Significant  Observable  Inputs********(Level  2)** | ** ** | **Significant  Unobservable  Inputs********(Level  3)** | ** ** |
| **Asset  Category**   |       |                                                   |       |   |   |   |   |   |   |
| Cash                  |       | 9                                                      |       | 9 |   | — |   | — |   |
| Equity Securities     |       |                                                   |       |   |   |   |   |   |   |
| Canadian Equity       |       | 36                                                     |       | 36 |   | — |   | — |   |
| Pooled Funds          |       |                                                   |       |   |   |   |   |   |   |
| Canadian Fixed Income |       | 90                                                     |       | — |   | 90 |   | — |   |
| Canadian Equity       |       | 30                                                     |       | — |   | 30 |   | — |   |
| Foreign Equity        |       | 99                                                     |       | — |   | 99 |   | — |   |
| **Total**             | ** ** | **264**                                                | ** ** | **45** | ** ** | **219** | ** ** | **—** | ** ** |

 

The fair values of Canexus’s defined benefit pension planassets at December 31, 2009 by asset category are as follows:

 
| ** **            | ** ** | **Fair Value Measurements at  December 31, 2009** | ** ** |
|-----------------------|------------|--------------------------------------------------------|------------|
| ** **            | ** ** | **Total**                                              | ** ** | **Quoted Prices in  Active Markets  for Identical  Assets (Level 1)** | ** ** | **Significant  Observable  Inputs********(Level  2)** | ** ** | **Significant  Unobservable  Inputs********(Level  3)** | ** ** |
| **Asset  Category**   |       |                                                   |       |   |   |   |   |   |   |
| Pooled Funds          |       |                                                   |       |   |   |   |   |   |   |
| Canadian Fixed Income |       | 29                                                     |       | — |   | 29 |   | — |   |
| Canadian Equity       |       | 16                                                     |       | — |   | 16 |   | — |   |
| Foreign Equity        |       | 11                                                     |       | — |   | 11 |   | — |   |
| **Total**             | ** ** | **56**                                                 | ** ** | **—** | ** ** | **56** | ** ** | **—** | ** ** |

 

The fair values of Syncrude’s defined benefit pension planassets at December 31, 2009 by asset category are as follows:

 
| ** **                | ** ** | **Fair Value Measurements at  December 31, 2009** | ** ** |
|---------------------------|------------|--------------------------------------------------------|------------|
| ** **                | ** ** | **Total**                                              | ** ** | **Quoted Prices in  Active Markets  for Identical  Assets (Level 1)** | ** ** | **Significant  Observable  Inputs********(Level  2)** | ** ** | **Significant  Unobservable  Inputs********(Level  3)** | ** ** |
| **Asset  Category**       |       |                                                   |       |   |   |   |   |   |   |
| Cash                      |       | 1                                                      |       | 1 |   | — |   | — |   |
| Pooled Funds              |       |                                                   |       |   |   |   |   |   |   |
| Canadian Fixed Income     |       | 17                                                     |       | — |   | 17 |   | — |   |
| Canadian Equity           |       | 19                                                     |       | — |   | 19 |   | — |   |
| Foreign Equity            |       | 30                                                     |       | — |   | 30 |   | — |   |
| Other Types of Investment |       |                                                   |       |   |   |   |   |   |   |
| Other                     |       | 2                                                      |       | — |   | — |   | 2 |   |
| **Total**                 | ** ** | **69**                                                 | ** ** | **1** | ** ** | **66** | ** ** | **2** | ** ** |

 

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**(C)  DEFINEDCONTRIBUTION PENSION PLANS**

 

Under these plans, pension benefits are based on plancontributions. During 2009, Canadian pension expense for these plans was $9million (2008—$7 million; 2007—$6 million). During 2009, US pension expense forthese plans was $7 million (2008—$4 million; 2007—$4 million) and UK pensionexpense for these plans was $6 million (2008—$6 million; 2007—$5 million).

 

**(D)  POST-RETIREMENTBENEFITS**

 

Nexen provides certain post-retirement benefits, includinggroup life and supplemental health insurance, to eligible employees and theirdependants. The present value of Nexen employees’ future post-retirementbenefits at December 31, 2009 was $14 million (2008—$15 million) and $2million for Canexus (2008—$2 million).

 

**(E)   EMPLOYERFUNDING CONTRIBUTIONS AND BENEFIT PAYMENTS**

 

Canadian regulators have prescribed funding requirements forNexen and Canexus’ defined benefit plans. Funding contributions over the lastthree years have met these requirements and also included additionaldiscretionary contributions permitted by law to ensure the plans are adequatelyfunded. For our defined contribution plans, we make contributions on behalf ofour employees and no further obligation exists. Funding contributions for thedefined benefit plans are:

 
| ** **                               | ** ** | **Expected 2010** | ** ** | **2009** | ** ** | **2008** | ** ** |
|------------------------------------------|------------|-------------------|------------|----------|------------|----------|------------|
| Nexen                                    |       | 8                 |       | 77       |       | 15       |       |
| Canexus                                  |       | 3                 |       | 3        |       | 4        |       |
| Syncrude                                 |       | 7                 |       | 7        |       | 6        |       |
| **Total Defined  Benefit Contributions** | ** ** | **18**            | ** ** | **87**   | ** ** | **25**   | ** ** |

 

Our most recent funding valuation was prepared as of June 30,2008. Our next funding valuation is required by June 30, 2011. Canexus’most recent funding valuation was prepared as of December 31, 2007 andtheir next funding valuation is required by December 31, 2010. Syncrude’smost recent funding valuation was prepared as of December 31, 2006. Theirnext funding valuation is required as at December 31, 2009 and is expectedto be completed in 2010.

 

Our total benefit payments in 2009 were $12 million for Nexen(2008—$13 million) and $4 million for Canexus (2008 —$1 million). Our share ofSyncrude’s total benefit payments in 2009 was $5 million (2008—$5 million). Ourestimated future payments are as follows:

 
| ** **     | ** ** | **Defined Benefit** | ** ** | **Other**   | ** ** |
|----------------|------------|---------------------|------------|-------------|------------|
| ** **     | ** ** | **Nexen**           | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** | **Nexen** | ** ** | **Canexus** | ** ** | **Syncrude** | ** ** |
| 2010           |       | 11                  |       | 1           |       | 4 |   | 3 |   | — |   | — |   |
| 2011           |       | 12                  |       | 2           |       | 5 |   | 3 |   | — |   | — |   |
| 2012           |       | 13                  |       | 2           |       | 5 |   | 4 |   | — |   | — |   |
| 2013           |       | 14                  |       | 3           |       | 6 |   | 4 |   | — |   | — |   |
| 2014           |       | 16                  |       | 3           |       | 6 |   | 4 |   | — |   | — |   |
| 2015–2019 |       | 103                 |       | 23          |       | 39 |   | 30 |   | — |   | 2 |   |

 

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**14****.     EQUITY**

 

**(A)  AUTHORIZEDCAPITAL**

 

Authorized share capital consists of an unlimited number ofcommon shares of no par value, and an unlimited number of Class Apreferred shares of no par value, issuable in series.

 

**(B)  ISSUEDCOMMON SHARES AND DIVIDENDS**

 
| **(thousands of shares)**                                  | ** ** | **2009**    | ** ** | **2008**    | ** ** | **2007**    | ** ** |
|------------------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|
| Issued Common Shares, Beginning of Year                    |       | 519,449     |       | 528,305     |       | 525,026     |       |
| Issue of Common Shares for Cash Exercise of Tandem Options |       | 1,146       |       | 1,911       |       | 2,257       |       |
| Dividend Reinvestment Plan                                 |       | 1,328       |       | 871         |       | 523         |       |
| Employee Flow-through Shares                               |       | 993         |       | 499         |       | 499         |       |
| Repurchased under Normal Course Issuer Bid                 |       | —      |       | (12,137     | )          | —      |       |
| **End of Year**                                            | ** ** | **522,916** | ** ** | **519,449** | ** ** | **528,305** | ** ** |
| ** **                                                 | ** ** | ** **  | ** ** | ** **  | ** ** | ** **  | ** ** |
| **Dividends  Declared per Common Share**($/share)          | ** ** | **0.20**    | ** ** | **0.18**    | ** ** | **0.10**    | ** ** |
| ** **                                                 | ** ** | ** **  | ** ** | ** **  | ** ** | ** **  | ** ** |
| **Cash  Consideration**(Cdn$ millions)                |       |        |       |        |       |        |       |
| Exercise of Tandem Options                                 |       | 12          |       | 23          |       | 24          |       |
| Dividend Reinvestment Plan                                 |       | 29          |       | 25          |       | 16          |       |
| Employee Flow-through Shares                               |       | 16          |       | 16          |       | 16          |       |
| **Total**                                                  | ** ** | **57**      | ** ** | **64**      | ** ** | **56**      | ** ** |

 

During the year, 1,328,497 common shares were issued underthe Dividend Reinvestment Plan leaving a balance of 2,275,344 common shares(2008—3,603,841; 2007—4,475,095) reserved for issuance at December 31,2009. Dividends paid to holders of common shares have been designated as “eligibledividends” for Canadian tax purposes.

 

During 2008, we received approval from the Toronto StockExchange (TSX) for a Normal Course Issuer Bid to repurchase up to a maximum of52,914,046 common shares between August 6, 2008 and August 5, 2009.Under this authorization, we repurchased and cancelled 12,136,900 common sharesacquired on the open market through the TSX in 2008 at an average price of$27.85 per common share, totalling $338 million. Of the amount paid, $22million reduced the book value of our common shares and the excess of$316 million reduced retained earnings. We did not repurchase any commonshares in 2009.

 

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**(C)  TANDEMOPTIONS**

 

We grant tandem options to purchase common shares to 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. The following tandem optionshave been granted:

 
| ** **                                                        | ** ** | **2009**               | ** ** | **2008**                                         | ** ** | **2007**               | ** ** |
|-------------------------------------------------------------------|------------|------------------------|------------|--------------------------------------------------|------------|------------------------|------------|
| (thousands of shares)                                             | ** ** | **Options**(thousands) | ** ** | **Weighted  Average  Exercise  Price**($/option) | ** ** | **Options**(thousands) | ** ** | **Weighted  Average  Exercise  Price**($/option) | ** ** | **Options******(thousands) | ** ** | **Weighted********Average********Exercise  Price******($/option) | ** ** |
| Outstanding Tandem Options, Beginning of Year                     |       | 24,622                 |       | 22                                               |       | 27,403                 |       | 20 |   | 30,485 |   | 17 |   |
| Granted                                                           |       | 4,350                  |       | 24                                               |       | 3,534                  |       | 19 |   | 4,007 |   | 28 |   |
| Exercised for Stock                                               |       | (1,146                 | )          | 10                                               |       | (1,911                 | )          | 13 |   | (2,257 | ) | 10 |   |
| Surrendered for Cash                                              |       | (4,116                 | )          | 12                                               |       | (3,839                 | )          | 13 |   | (4,414 | ) | 11 |   |
| Cancelled                                                         |       | (560                   | )          | 28                                               |       | (552                   | )          | 30 |   | (418 | ) | 22 |   |
| Expired                                                           |       | (20                    | )          | 12                                               |       | (13                    | )          | 11 |   | — |   | — |   |
| **End of Year**                                                   | ** ** | **23,130**             | ** ** | **25**                                           | ** ** | **24,622**             | ** ** | **22** | ** ** | **27,403** | ** ** | **20** | ** ** |
| ** **                                                        | ** ** | ** **             | ** ** | ** **                                       | ** ** | ** **             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Tandem Options Exercisable at End of Year                         |       | 15,282                 |       | 25                                               |       | 17,087                 |       | 21 |   | 18,216 |   | 16 |   |
| Common Shares Reserved for Issuance Under the  Tandem Option Plan |       | 26,283                 |       |                                             |       | 27,429                 |       |   |   | 29,430 |   |   |   |

 

The range of exercise prices of tandem options outstandingand exercisable at December 31, 2009 is as follows:

 
| ** **       | ** ** | **Outstanding Tandem Options**    | ** ** | **Exercisable Tandem Options**                  | ** ** |
|------------------|------------|-----------------------------------|------------|-------------------------------------------------|------------|
| ** **       | ** ** | **Number of  Options**(thousands) | ** ** | **Weighted  Average  Exercise Price**($/option) | ** ** | **Weighted  Average Years  to Expiry**(years) | ** ** | **Number of  Options**(thousands) | ** ** | **Weighted  Average  Exercise Price**($/option) | ** ** |
| $5.00 to $9.99   |       | 2,288                             |       | 9                                               |       | 1 |   | 2,288 |   | 9 |   |
| $10.00 to $14.99 |       | 50                                |       | 14                                              |       | 1 |   | 50 |   | 14 |   |
| $15.00 to $19.99 |       | 3,606                             |       | 19                                              |       | 4 |   | 1,247 |   | 19 |   |
| $20.00 to $24.99 |       | 4,818                             |       | 25                                              |       | 4 |   | 604 |   | 25 |   |
| $25.00 to $29.99 |       | 8,528                             |       | 28                                              |       | 2 |   | 7,290 |   | 28 |   |
| $30.00 to $34.99 |       | 3,815                             |       | 32                                              |       | 2 |   | 3,788 |   | 32 |   |
| $35.00 to $39.99 |       | 20                                |       | 36                                              |       | 2 |   | 13 |   | 36 |   |
| $40.00 to $44.99 |       | 5                                 |       | 40                                              |       | 3 |   | 2 |   | 40 |   |
| **Total**        | ** ** | **23,130**                        | ** ** | ** **                                      | ** ** | ** ** | ** ** | **15,282** | ** ** | ** ** | ** ** |

 

**(D)  STOCKAPPRECIATION RIGHTS**

 

Our STARs plan entitlesemployees to cash payments equal to the excess of the market price of thecommon shares over the exercise price of the right. The following stockappreciation rights have been granted:

 
| ** **                           | ** ** | **2009**             | ** ** | **2008**                                       | ** ** | **2007**             | ** ** |
|--------------------------------------|------------|----------------------|------------|------------------------------------------------|------------|----------------------|------------|
| (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 |       | 16,986               |       | 25                                             |       | 15,435               |       | 24 |   | 13,890 |   | 21 |   |
| Granted                              |       | 5,273                |       | 25                                             |       | 4,917                |       | 19 |   | 4,195 |   | 29 |   |
| Exercised for Cash                   |       | (2,079               | )          | 13                                             |       | (2,837               | )          | 15 |   | (2,349 | ) | 12 |   |
| Cancelled                            |       | (700                 | )          | 28                                             |       | (529                 | )          | 31 |   | (301 | ) | 26 |   |
| **End of Year**                      | ** ** | **19,480**           | ** ** | **25**                                         | ** ** | **16,986**           | ** ** | **25** | ** ** | **15,435** | ** ** | **24** | ** ** |
| ** **                           | ** ** | ** **           | ** ** | ** **                                     | ** ** | ** **           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| STARs Exercisable at End of Year     |       | 9,812                |       | 28                                             |       | 8,119                |       | 25 |   | 7,525 |   | 19 |   |

 

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The range of exercise prices of STARs outstanding and exercisableat December 31, 2009 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   |       | 103                             |       | 8                                             |       | 1 |   | 103 |   | 8 |   |
| $10.00 to $14.99 |       | 9                               |       | 13                                            |       | 4 |   | 1 |   | 13 |   |
| $15.00 to $19.99 |       | 4,718                           |       | 19                                            |       | 4 |   | 1,585 |   | 19 |   |
| $20.00 to $24.99 |       | 5,292                           |       | 25                                            |       | 5 |   | 62 |   | 23 |   |
| $25.00 to $29.99 |       | 5,970                           |       | 28                                            |       | 2 |   | 4,762 |   | 28 |   |
| $30.00 to $34.99 |       | 3,305                           |       | 32                                            |       | 2 |   | 3,256 |   | 32 |   |
| $35.00 to $39.99 |       | 72                              |       | 37                                            |       | 3 |   | 39 |   | 37 |   |
| $40.00 to $44.99 |       | 11                              |       | 40                                            |       | 3 |   | 4 |   | 40 |   |
| **Total**        | ** ** | **19,480**                      | ** ** | ** **                                    | ** ** | ** ** | ** ** | **9,812** | ** ** | ** ** | ** ** |

 

**15****.     COMMITMENTS,CONTINGENCIES AND GUARANTEES**

 

We assume various contractual obligations and commitments inthe normal course of our operations. Our operating leases and transportation,storage and drilling rig commitments as at December 31, 2009 are comprisedof the following:

 
| ** **                             | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** | **2013** | ** ** | **2014** | ** ** | **Thereafter** | ** ** |
|----------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|
| Operating Leases                       |       | 117      |       | 96       |       | 89       |       | 87       |       | 92       |       | 166            |       |
| Transportation and Storage Commitments |       | 303      |       | 189      |       | 156      |       | 123      |       | 86       |       | 120            |       |
| Drilling Rig Commitments               |       | 403      |       | 362      |       | 289      |       | 170      |       | 55       |       | 1              |       |

 

We have a number of lawsuits and claims pending includingincome tax reassessments (see Note 17), for which we currently cannot determinethe ultimate result. We record costs as they are incurred or becomedeterminable. We believe the resolution of these matters would not have amaterial adverse effect on our liquidity, consolidated financial position orresults of operations.

 

During 2009, total rental expense under operating leases was$62 million (2008—$59 million; 2007—$53 million).

 

From time to time, we enter into contracts that require us toindemnify parties against certain types of possible third-party claims,particularly when these contracts relate to divestiture transactions. Onoccasion, we may provide routine indemnifications. The terms of suchobligations vary, and generally, a maximum is not explicitly stated. Becausethe obligations in these agreements are often not explicitly stated, the overallmaximum amount of the obligations cannot be reasonably estimated. Historically,we have not been obligated to make significant payments for these obligations.We believe that payments, if any, related to existing indemnities, would nothave a material adverse effect on our liquidity, financial condition or resultsof operations.

 

**16****.     MARKETINGAND OTHER INCOME**

 
| ** **                                             | ** ** | **2009** | ** ** | **2008** | ** ** | **2007**  | ** ** |
|--------------------------------------------------------|------------|----------|------------|----------|------------|-----------|------------|
| Marketing Revenue, Net (Note 6)                        |       | 943      |       | 467      |       | 959       |       |
| Change in Fair Value of Crude Oil Put Options (Note 6) |       | (251     | )          | 203      |       | (43       | )          |
| Interest                                               |       | 7        |       | 28       |       | 39        |       |
| Foreign Exchange Gains (Losses)                        |       | 128      |       | 128      |       | (22       | )          |
| Gains on Disposition of Assets                         |       | —   |       | 3        |       | 2         |       |
| Other                                                  |       | 82       |       | (16      | )          | 86        |       |
| **Total**                                              | ** ** | **909**  | ** ** | **813**  | ** ** | **1,021** | ** ** |

 

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**17****.     INCOMETAXES**

 

**(A)  TEMPORARYDIFFERENCES**

 
| ** **                         | ** ** | **2009**                       | ** ** | **2008**                            | ** ** |
|------------------------------------|------------|--------------------------------|------------|-------------------------------------|------------|
| ** **                         | ** ** | **Future  Income Tax  Assets** | ** ** | **Future  Income Tax  Liabilities** | ** ** | **Future  Income Tax  Assets** | ** ** | **Future  Income Tax  Liabilities** | ** ** |
| Property, Plant and Equipment, Net |       | 36                             |       | 2,762                               |       | 27 |   | 2,543 |   |
| Tax Losses Carried Forward         |       | 1,092                          |       | —                              |       | 300 |   | — |   |
| Deferred Income                    |       | —                         |       | 49                                  |       | — |   | 76 |   |
| Recoverable Taxes                  |       | 20                             |       | —                              |       | 24 |   | — |   |
| **Total**                          | ** ** | **1,148**                      | ** ** | **2,811**                           | ** ** | **351** | ** ** | **2,619** | ** ** |

 

**(B)  CANADIANAND FOREIGN INCOME TAXES**

 
| ** **                             | ** ** | **2009** | ** ** | **2008**  | ** ** | **2007** | ** ** |
|----------------------------------------|------------|----------|------------|-----------|------------|----------|------------|
| **Income (Loss)  before Income Taxes** |       |     |       |      |       |     |       |
| Canadian                               |       | (484     | )          | (100      | )          | (33      | )          |
| Foreign                                |       | 1,300    |       | 3,268     |       | 1,929    |       |
|                                   |       | 816      |       | 3,168     |       | 1,896    |       |
| ** **                             |       |     |       |      |       |     |       |
| **Provision for  Income Taxes**        |       |     |       |      |       |     |       |
| Current                                |       |     |       |      |       |     |       |
| Canadian                               |       | 1        |       | 1         |       | 1        |       |
| Foreign                                |       | 775      |       | 858       |       | 433      |       |
|                                   |       | 776      |       | 859       |       | 434      |       |
|                                   |       |     |       |      |       |     |       |
| Future                                 |       |     |       |      |       |     |       |
| Canadian                               |       | (160     | )          | 22        |       | 12       |       |
| Foreign                                |       | (356     | )          | 576       |       | 346      |       |
|                                   |       | (516     | )          | 598       |       | 358      |       |
|                                   |       |     |       |      |       |     |       |
| **Total**                              | ** ** | **260**  | ** ** | **1,457** | ** ** | **792**  | ** ** |

 

The Canadian and foreign components of the provision forincome taxes are based on the jurisdiction in which income is taxed. Foreigntaxes relate mainly to Yemen, Colombia, UK, US and Norway.

 

**(C)  RECONCILIATIONOF EFFECTIVE TAX RATE TO THE CANADIAN STATUTORY TAX RATE**

 
| ** **                                                         | ** ** | **2009** | ** ** | **2008**  | ** ** | **2007** | ** ** |
|--------------------------------------------------------------------|------------|----------|------------|-----------|------------|----------|------------|
| Income before Provision for Income Taxes                           |       | 816      |       | 3,168     |       | 1,896    |       |
|                                                               |       |     |       |      |       |     |       |
| Provision for Income Taxes Computed at the Canadian Statutory Rate |       | 205      |       | 893       |       | 537      |       |
| Add (Deduct) the Tax Effect of:                                    |       |     |       |      |       |     |       |
| Foreign Tax Rate Differential                                      |       | 96       |       | 525       |       | 233      |       |
| Higher (Lower) Tax Rates on Capital Gains                          |       | (42      | )          | 9         |       | (5       | )          |
| Federal and Provincial Capital Tax                                 |       | 1        |       | 2         |       | 1        |       |
| Effect of Changes in Tax Rates                                     |       | (22      | )          | —    |       | (15      | )          |
| Non-Deductible Expenses and Other                                  |       | 22       |       | 28        |       | 41       |       |
| **Provision for  Income Taxes**                                    | ** ** | **260**  | ** ** | **1,457** | ** ** | **792**  | ** ** |
| **Effective Tax  Rate**                                            | ** ** | **32%**  | ** ** | **46%**   | ** ** | **42%**  | ** ** |

 

In 2007, the federal government and some provincial governmentsin Canada reduced statutory corporate income tax rates. This reduced ourliability and provision for future income taxes by $15 million in 2007 and $22million in 2009.

 

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**(D)  AVAILABLEUNUSED TAX LOSSES AND TAX CONTINGENCIES**

 

At December 31, 2009, we had unused tax losses totalling$4,219 million (2008—$954 million; 2007—$820 million). The majority of theselosses are in Canada and the US and will expire between 2015 and 2028.

 

Nexen’s income tax filings are subject to audit by taxationauthorities. There are audits in progress and items under review, some of whichmay increase our tax liability. In addition, we have filed notices of objectionwith respect to certain issues. While the results of these items cannot beascertained at this time, we believe we have an appropriate provision forincome taxes based on available information.

 

**18****.     EARNINGSPER COMMON SHARE**

 

We calculate basic earnings per common share using net incomedivided by the weighted-average number of common shares outstanding. Wecalculate diluted earnings per common share in the same manner as basic, exceptwe use the weighted-average number of diluted common shares outstanding in thedenominator.

 
| **(millions of shares)**                                          | ** ** | **2009**  | ** ** | **2008**  | ** ** | **2007**  | ** ** |
|-------------------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Weighted-Average Number of Common Shares, Basic                   |       | 521.4     |       | 526.1     |       | 527.1     |       |
| Shares Issuable Pursuant to Tandem Options                        |       | 10.1      |       | 18.8      |       | 26.6      |       |
| Shares to be Notionally Purchased from Proceeds of Tandem Options |       | (7.0      | )          | (12.7     | )          | (15.7     | )          |
| **Weighted-Average  Number of Common Shares, Diluted**            | ** ** | **524.5** | ** ** | **532.2** | ** ** | **538.0** | ** ** |

 

In calculating the weighted-average number of diluted commonshares outstanding for the year ended December 31, 2009, we excluded13,485,465 tandem options (2008—5,694,055; 2007—49,333), because their exerciseprice was greater than the annual average common share market price in thoseperiods. During the last three years, outstanding tandem options were the onlypotential dilutive instruments.

 

**19****.     CASHFLOWS**

 

**(A)  CHARGESAND CREDITS TO INCOME NOT INVOLVING CASH**

 
| ** **                                              | ** ** | **2009**  | ** ** | **2008**  | ** ** | **2007**  | ** ** |
|---------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Depreciation, Depletion, Amortization and Impairment    |       | 1,802     |       | 2,014     |       | 1,767     |       |
| Stock-Based Compensation                                |       | (10       | )          | (272      | )          | (109      | )          |
| Gains on Disposition of Assets                          |       | —    |       | (3        | )          | (2        | )          |
| Provision for (Recovery of) Future Income Taxes         |       | (516      | )          | 598       |       | 358       |       |
| Change in Fair Value of Crude Oil Put Options (Note 16) |       | 251       |       | (203      | )          | 43        |       |
| Foreign Exchange                                        |       | (177      | )          | (4        | )          | 18        |       |
| Other                                                   |       | 21        |       | 10        |       | (20       | )          |
| **Total**                                               | ** ** | **1,371** | ** ** | **2,140** | ** ** | **2,055** | ** ** |

 

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**(B)  CHANGESIN NON-CASH WORKING CAPITAL**

 
| ** **                               | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Accounts Receivable                      |       | 92       |       | 950      |       | (797     | )          |
| Inventories and Supplies                 |       | (236     | )          | 246      |       | (97      | )          |
| Other Current Assets                     |       | 9        |       | 5        |       | (15      | )          |
| Accounts Payable and Accrued Liabilities |       | (23      | )          | (1,232   | )          | 691      |       |
| Other Current Liabilities                |       | 23       |       | 26       |       | —   |       |
| **Total**                                | ** ** | **(135** | **)**      | **(5**   | **)**      | **(218** | **)**      |
| Relating to:                             |       |     |       |     |       |     |       |
| Operating Activities                     |       | (25      | )          | 119      |       | (348     | )          |
| Investing Activities                     |       | (110     | )          | (124     | )          | 130      |       |
| **Total**                                | ** ** | **(135** | **)**      | **(5**   | **)**      | **(218** | **)**      |

 

**(C)  OTHERCASH FLOW INFORMATION**

 
| ** **        | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest Paid     |       | 335      |       | 319      |       | 328      |       |
| Income Taxes Paid |       | 483      |       | 1,055    |       | 408      |       |

 

Cash flow from other operating activities includes cashoutflows related to geological and geophysical expenditures of $81 million(2008—$137 million; 2007—$123 million).

 

**20****.     OPERATINGSEGMENTS AND RELATED INFORMATION**

 

Nexen has the following operating segments in variousindustries and geographic locations:

 

Oil and Gas: We explore for, develop and produce crude oil,natural gas and related products around the world. We manage our operations toreflect differences in the regulatory environments and risk factors for eachcountry. Our core operations are onshore in Yemen and Canada, and offshore inthe US Gulf of Mexico and the UK North Sea. Our other operations are primarilyin Colombia, offshore West Africa and Norway. We also own 7.23% of the Syncrudejoint venture, which develops and produces synthetic crude oil from miningbitumen in the Athabasca oil sands in northern Alberta.

 

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). We use financial and derivative contracts,including futures, forwards, swaps and options for economic hedging and tradingpurposes. Our energy marketing group also uses physical commoditytransportation and storage capacity contracts to capture regional opportunitiesas well as to take advantage of seasonal pricing differences. Weakness in gasmarkets has reduced the value of holding transportation contracts. Any lossesassociated with the transportation and storage capacity contracts will be recognizedwhen the contracts are used or sold. In 2009, we initiated a strategic reviewof our energy marketing natural gas and power businesses. This review continuesto align our marketing activities with our upstream oil and gas businesses.

 

In early 2010, we entered into an agreement to sell ourEuropean gas and power marketing business. These operations are not material toour results of operations. While net assets (total assets less totalliabilities) of the business are not material, current assets and currentliabilities in these operations comprise approximately 7% and 12% of ourconsolidated amounts, respectively.

 

Chemicals: Through our investment in Canexus, we manufacture,market and distribute industrial chemicals, principally sodium chlorate, chlorine,muriatic acid and caustic soda. We produce sodium chlorate at three 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 thesame as those described in Note 1. Net income of our operating segmentsexcludes interest income, interest expense, unallocated corporate expenses andforeign exchange gains and losses with the exception of Chemicals. Identifiableassets are those used in the operations of the segments.

 

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**2009 Operating and Geographic Segments**

 
| ** **                                             | ** ** | **Oil and  Gas**    | ** ** | ** **    | ** ** | ** **   | ** ** | ** **         | ** ** | ** ** | ** ** |
|--------------------------------------------------------|------------|---------------------|------------|---------------|------------|--------------|------------|--------------------|------------|------------|------------|
| **(Cdn$ millions)**                               | ** ** | **United  Kingdom** | ** ** | **Canada**    | ** ** | **Syncrude** | ** ** | **United  States** | ** ** | **Yemen**  | ** ** | **Other  Countries****1** | ** ** | **Energy  Marketing** | ** ** | **Chemicals** | ** ** | **Corporate  and Other** | ** ** | **Total** | ** ** |
| Net Sales2                                             |       | 2,430               |       | 395           |       | 480          |       | 321                |       | 705        |       | 70 |   | 36 |   | 458 | 3 | — |   | 4,895 |   |
| Marketing and  Other                                   |       | 18                  |       | 1             |       | 7            |       | —             |       | 14         |       | 6 |   | 943 |   | 50 |   | (130 | )4 | 909 |   |
|                                                   |       | 2,448               |       | 396           |       | 487          |       | 321                |       | 719        |       | 76 |   | 979 |   | 508 |   | (130 | ) | 5,804 |   |
| Less:  Expenses                                        |       |                |       |          |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| Operating                                              |       | 253                 |       | 171           |       | 265          |       | 98                 |       | 191        |       | 8 |   | 27 |   | 267 |   | — |   | 1,280 |   |
| Depreciation,  Depletion, Amortization and Impairment5 |       | 875                 |       | 301           |       | 63           |       | 312                |       | 102        |       | 14 |   | 27 |   | 65 |   | 43 |   | 1,802 |   |
| Transportation  and Other                              |       | 17                  |       | 27            |       | 28           |       | 22                 |       | 30         |       | — |   | 599 |   | 48 |   | 24 |   | 795 |   |
| General and  Administrative6                           |       | 18                  |       | 67            |       | 1            |       | 60                 |       | 6          |       | 35 |   | 91 |   | 42 |   | 177 |   | 497 |   |
| Exploration                                            |       | 50                  |       | 84            |       | —       |       | 104                |       | —     |       | 64 | 7 | — |   | — |   | — |   | 302 |   |
| Interest                                               |       | —              |       | —        |       | —       |       | —             |       | —     |       | — |   | — |   | 7 |   | 305 |   | 312 |   |
| Income (Loss)  before Income Taxes                     |       | 1,235               |       | (254          | )          | 130          |       | (275               | )          | 390        |       | (45 | ) | 235 |   | 79 |   | (679 | ) | 816 |   |
| Less: Provision  for (Recovery of) Income Taxes8       |       | 487                 |       | (64           | )          | 33           |       | (95                | )          | 141        |       | (23 | ) | 96 |   | 18 |   | (333 | ) | 260 |   |
| Less:  Non-Controlling Interests                       |       | —              |       | —        |       | —       |       | —             |       | —     |       | — |   | — |   | 20 |   | — |   | 20 |   |
| **Net Income (Loss)**                                  | ** ** | **748**             | ** ** | **(190**      | **)**      | **97**       | ** ** | **(180**           | **)**      | **249**    | ** ** | **(22** | **)** | **139** | ** ** | **41** | ** ** | **(346** | **)** | **536** | ** ** |
|                                                   |       |                |       |          |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| **Identifiable Assets**                                | ** ** | **4,866**           | ** ** | **7,809****** | **9**      | **1,287**    | ** ** | **1,715**          | ** ** | **229**    | ** ** | **1,090** | ** ** | **3,050** | **10** | **693** | ** ** | **2,161** | ** ** | **22,900** | ** ** |
|                                                   |       |                |       |          |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| Capital  Expenditures                                  |       |                |       |          |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| Development and  Other                                 |       | 483                 |       | 628           |       | 87           |       | 128                |       | 69         |       | 490 |   | 28 |   | 214 |   | 33 |   | 2,160 |   |
| Exploration                                            |       | 143                 |       | 215           |       | —       |       | 157                |       | —     |       | 67 |   | — |   | — |   | — |   | 582 |   |
| Proved Property  Acquisitions                          |       | —              |       | 755           |       | —       |       | —             |       | —     |       | — |   | — |   | — |   | — |   | 755 |   |
| **Total**                                              | ** ** | **626**             | ** ** | **1,598**     | ** ** | **87**       | ** ** | **285**            | ** ** | **69**     | ** ** | **557** | ** ** | **28** | ** ** | **214** | ** ** | **33** | ** ** | **3,497** | ** ** |
|                                                   |       |                |       |          |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| PP&E                                               |       |                |       |          |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| Cost                                                   |       | 6,115               |       | 9,664         |       | 1,463        |       | 3,900              |       | 2,462      |       | 930 |   | 259 |   | 1,135 |   | 371 |   | 26,299 |   |
| Less: Accumulated  DD&A                            |       | 2,664               |       | 2,038         |       | 270          |       | 2,529              |       | 2,322      |       | 99 |   | 83 |   | 562 |   | 240 |   | 10,807 |   |
| **Net Book Value****2**                                | ** ** | **3,451**           | ** ** | **7,626****** | **9**      | **1,193**    | ** ** | **1,371**          | ** ** | **140**    | ** ** | **831** | ** ** | **176** | ** ** | **573** | ** ** | **131** | ** ** | **15,492** | ** ** |
|                                                   |       |                |       |          |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| **Goodwill****11**                                     | ** ** | **292**             | ** ** | **—**    | ** ** | **—**   | ** ** | **—**         | ** ** | **—** | ** ** | **—** | ** ** | **47** | ** ** | **—** | ** ** | **—** | ** ** | **339** | ** ** |

 

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*1*                           Includes results of operationsfrom producing activities in Colombia.

*2*                           Net sales made from allsegments originating in Canada: $1,063 million PP&E located in Canada:$9,610 million

*3*                           Net sales for our chemicalsoperations include:

 
| ***($ millions)*** |         |      |         |
|-------------------------|--------------|-----------|--------------|
| *Canada*                | * *     | *152*     | * *     |
| *US*                    | * *     | *204*     | * *     |
| *Brazil*                | * *     | *102*     | * *     |
| ***Total***             | *** *** | ***458*** | *** *** |

* *

*4*                           Includes interest income of $7million, foreign exchange gains of $128 million, decrease in the fair value ofcrude oil put options of $251 million and other losses of $14 million.

*5*                           Includes an impairment chargerelated to gas properties in Canada and the US Gulf of Mexico of $58 millionand $20 million, respectively.

*6*                           Includes stock-based compensationexpense of $69 million.

*7*                           Includes exploration activitiesprimarily in Norway, Nigeria and Colombia.

*8*                           The provision for (recovery of)income taxes for foreign locations is based on in-country taxes on foreignincome. For oil and gas locations with no operating activities, the provisionis based on the tax jurisdiction of the entity performing the activity.

*9*                           Includes costs of $6,045million related to our insitu oil sands (Long Lake and future phases).

*10*                    78% of Marketing’s identifiableassets are accounts receivable and inventories.

*11*                    Goodwill decreased in the UKand Energy Marketing by $49 million and $2 million, respectively, as a resultof changes in foreign exchange rates.

 

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**2008 Operating and Geographic Segments**

 
| ** **                                             | ** ** | **Oil and  Gas**    | ** ** | ** ** | ** ** | ** **   | ** ** | ** **         | ** ** | ** ** | ** ** |
|--------------------------------------------------------|------------|---------------------|------------|------------|------------|--------------|------------|--------------------|------------|------------|------------|
| **(Cdn$ millions)**                               | ** ** | **United  Kingdom** | ** ** | **Canada** | ** ** | **Syncrude** | ** ** | **United  States** | ** ** | **Yemen**  | ** ** | **Other  Countries****1** | ** ** | **Energy  Marketing** | ** ** | **Chemicals** | ** ** | **Corporate  and Other** | ** ** | **Total** | ** ** |
| Net Sales2                                             |       | 3,580               |       | 656        |       | 691          |       | 665                |       | 1,093      |       | 192 |   | 70 |   | 477 | **3** | — |   | 7,424 |   |
| Marketing and  Other                                   |       | 5                   |       | 3          |       | 6            |       | 4                  |       | 12         |       | — |   | 467 |   | (50 | ) | 366 | **4** | 813 |   |
|                                                   |       | 3,585               |       | 659        |       | 697          |       | 669                |       | 1,105      |       | 192 |   | 537 |   | 427 |   | 366 |   | 8,237 |   |
| Less:  Expenses                                        |       |                |       |       |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| Operating                                              |       | 253                 |       | 182        |       | 280          |       | 94                 |       | 176        |       | 10 |   | 43 |   | 297 |   | — |   | 1,335 |   |
| Depreciation,  Depletion, Amortization and Impairment5 |       | 999                 |       | 208        |       | 49           |       | 475                |       | 160        |       | 17 |   | 19 |   | 44 |   | 43 |   | 2,014 |   |
| Transportation  and Other                              |       | 19                  |       | 12         |       | 16           |       | 3                  |       | 9          |       | — |   | 805 |   | 55 |   | 48 |   | 967 |   |
| General and  Administrative6                           |       | (8                  | )          | 20         |       | 1            |       | 38                 |       | (7         | )          | 13 |   | 79 |   | 33 |   | 88 |   | 257 |   |
| Exploration                                            |       | 86                  |       | 79         |       | —       |       | 109                |       | 5          |       | 123 | **7** | — |   | — |   | — |   | 402 |   |
| Interest                                               |       | —              |       | —     |       | —       |       | —             |       | —     |       | — |   | — |   | 12 |   | 82 |   | 94 |   |
| Income (Loss)  before Income Taxes                     |       | 2,236               |       | 158        |       | 351          |       | (50                | )          | 762        |       | 29 |   | (409 | ) | (14 | ) | 105 |   | 3,168 |   |
| Less: Provision  for (Recovery of) Income Taxes8       |       | 1,126               |       | 45         |       | 99           |       | (19                | )          | 264        |       | (4 | ) | (102 | ) | 2 |   | 46 |   | 1,457 |   |
| Less:  Non-Controlling Interests                       |       | —              |       | —     |       | —       |       | —             |       | —     |       | — |   | — |   | (4 | ) | — |   | (4 | ) |
| **Net Income (Loss)**                                  | ** ** | **1,110**           | ** ** | **113**    | ** ** | **252**      | ** ** | **(31**            | **)**      | **498**    | ** ** | **33** | ** ** | **(307** | **)** | **(12** | **)** | **59** | ** ** | **1,715** | ** ** |
|                                                   |       |                |       |       |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| **Identifiable Assets**                                | ** ** | **6,632**           | ** ** | **6,643**  | **9**      | **1,198**    | ** ** | **2,044**          | ** ** | **342**    | ** ** | **701** | ** ** | **3,280** | **10** | **573** | ** ** | **742** | ** ** | **22,155** | ** ** |
|                                                   |       |                |       |       |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| Capital  Expenditures                                  |       |                |       |       |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| Development and  Other                                 |       | 545                 |       | 1,180      |       | 55           |       | 251                |       | 92         |       | 190 |   | 8 |   | 88 |   | 53 |   | 2,462 |   |
| Exploration                                            |       | 146                 |       | 225        |       | —       |       | 154                |       | 9          |       | 48 |   | — |   | — |   | — |   | 582 |   |
| Proved Property  Acquisitions                          |       | —              |       | 22         |       | —       |       | —             |       | —     |       | — |   | — |   | — |   | — |   | 22 |   |
| **Total**                                              | ** ** | **691**             | ** ** | **1,427**  | ** ** | **55**       | ** ** | **405**            | ** ** | **101**    | ** ** | **238** | ** ** | **8** | ** ** | **88** | ** ** | **53** | ** ** | **3,066** | ** ** |
| ** **                                             | ** ** | ** **          | ** ** | ** ** | ** ** | ** **   | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| PP&E                                               |       |                |       |       |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| Cost                                                   |       | 6,532               |       | 8,134      |       | 1,372        |       | 4,398              |       | 2,808      |       | 554 |   | 246 |   | 940 |   | 331 |   | 25,315 |   |
| Less: Accumulated  DD&A                            |       | 2,159               |       | 1,786      |       | 236          |       | 2,702              |       | 2,610      |       | 113 |   | 76 |   | 507 |   | 204 |   | 10,393 |   |
| **Net Book Value****2**                                | ** ** | **4,373**           | ** ** | **6,348**  | **9**      | **1,136**    | ** ** | **1,696**          | ** ** | **198**    | ** ** | **441** | ** ** | **170** | ** ** | **433** | ** ** | **127** | ** ** | **14,922** | ** ** |
|                                                   |       |                |       |       |       |         |       |               |       |       |       |   |   |   |   |   |   |   |   |   |   |
| **Goodwill**                                           | ** ** | **341**             | ** ** | **—** | ** ** | **—**   | ** ** | **—**         | ** ** | **—** | ** ** | **—** | ** ** | **49** | ** ** | **—** | ** ** | **—** | ** ** | **390** | ** ** |

 

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*1*                           Includes results of operationsfrom producing activities in Colombia.

*2*                           Net sales made from allsegments originating in Canada: $1,570 million PP&E located in Canada:$8,121 million

*3*                           Net sales for our chemicalsoperations include:

 
| ***($ millions)*** |         |      |         |
|-------------------------|--------------|-----------|--------------|
| *Canada*                | * *     | *153*     | * *     |
| *US*                    | * *     | *214*     | * *     |
| *Brazil*                | * *     | *110*     | * *     |
| ***Total***             | *** *** | ***477*** | *** *** |

 

*4*                           Includes interest income of $28million, foreign exchange gains of $128 million, increase in the fair value ofcrude oil put options of $203 million and other income of $7 million.

*5*                           Includes an impairment chargerelated to oil and gas properties in the UK North Sea and the US Gulf of Mexicoof $318 million and $250 million, respectively.

*6*                           Includes recovery ofstock-based compensation expense of $160 million.

*7*                           Includes exploration activitiesprimarily in Norway, Nigeria and Colombia.

*8*                           The provision for (recovery of)income taxes for foreign locations is based on in-country taxes on foreignincome. For oil and gas locations with no operating activities, the provisionis based on the tax jurisdiction of the entity performing the activity.

*9*                           Includes costs of $4,742million related to our insitu oil sands (Long Lake and future phases).

*10*                    79% of Marketing’s identifiableassets are accounts receivable and inventories.

 

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**2007 Operating and Geographic Segments**

 
| ** **                                             | ** ** | **Oil and  Gas**    | ** ** | ** **     | ** ** | ** **     | ** ** | ** **         | ** ** | ** **     | ** ** |
|--------------------------------------------------------|------------|---------------------|------------|----------------|------------|----------------|------------|--------------------|------------|----------------|------------|
| **(Cdn$ millions)**                               | ** ** | **United  Kingdom** | ** ** | **Canada**     | ** ** | **Syncrude**   | ** ** | **United  States** | ** ** | **Yemen**      | ** ** | **Other  Countries****1** | ** ** | **Energy  Marketing** | ** ** | **Chemicals** | ** ** | **Corporate  and Other** | ** ** | **Total** | ** ** |
| Net Sales2                                        |       | 2,285               |       | 441            |       | 545            |       | 616                |       | 1,086          |       | 148 |   | 48 |   | 414 | 3 | — |   | 5,583 |   |
| Marketing and  Other                                   |       | 39                  |       | 6              |       | —         |       | —             |       | 10             |       | — |   | 959 |   | 33 |   | (26 | )4 | 1,021 |   |
|                                                   |       | 2,324               |       | 447            |       | 545            |       | 616                |       | 1,096          |       | 148 |   | 1,007 |   | 447 |   | (26 | ) | 6,604 |   |
| Less:  Expenses                                        |       |                |       |           |       |           |       |               |       |           |       |   |   |   |   |   |   |   |   |   |   |
| Operating                                              |       | 212                 |       | 173            |       | 208            |       | 102                |       | 171            |       | 8 |   | 34 |   | 257 |   | — |   | 1,165 |   |
| Depreciation,  Depletion, Amortization and Impairment  |       | 599                 |       | 166            |       | 53             |       | 641                | 5          | 213            |       | 8 |   | 13 |   | 45 |   | 29 |   | 1,767 |   |
| Transportation  and Other                              |       | —              |       | 22             |       | 17             |       | —             |       | 8              |       | — |   | 806 |   | 39 |   | 16 |   | 908 |   |
| General and  Administrative6                      |       | 3                   |       | 50             |       | 1              |       | 38                 |       | (6             | )          | 40 |   | 87 |   | 31 |   | 130 |   | 374 |   |
| Exploration                                            |       | 69                  |       | 27             |       | —         |       | 134                |       | 5              |       | 91 | 7 | — |   | — |   | — |   | 326 |   |
| Interest                                               |       | —              |       | —         |       | —         |       | —             |       | —         |       | — |   | — |   | 11 |   | 157 |   | 168 |   |
| Income (Loss)  before Income Taxes                     |       | 1,441               |       | 9              |       | 266            |       | (299               | )          | 705            |       | 1 |   | 67 |   | 64 |   | (358 | ) | 1,896 |   |
| Less: Provision  for (Recovery of) Income Taxes8  |       | 712                 |       | 3              |       | 75             |       | (103               | )          | 248            |       | — |   | 21 |   | 18 |   | (182 | ) | 792 |   |
| Less:  Non-Controlling Interests                       |       | —              |       | —         |       | —         |       | —             |       | —         |       | — |   | — |   | 18 |   | — |   | 18 |   |
| **Net Income (Loss)******                              | ** ** | **729******         | ** ** | **6******      | ** ** | **191******    | ** ** | **(196**           | **)**      | **457******    | ** ** | **1****** | ** ** | **46****** | ** ** | **28****** | ** ** | **(176** | **)** | **1,086** | ** ** |
| ** **                                             | ** ** | ** **          | ** ** | ** **     | ** ** | ** **     | ** ** | ** **         | ** ** | ** **     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Identifiable Assets**                                | ** ** | **4,642******       | ** ** | **5,379**      | **9**      | **1,212******  | ** ** | **1,640******      | ** ** | **359******    | ** ** | **317****** | ** ** | **3,663** | **10** | **487****** | ** ** | **376****** | ** ** | **18,075** | ** ** |
|                                                   |       |                |       |           |       |           |       |               |       |           |       |   |   |   |   |   |   |   |   |   |   |
| Capital  Expenditures                                  |       |                |       |           |       |           |       |               |       |           |       |   |   |   |   |   |   |   |   |   |   |
| Development and  Other                                 |       | 551                 |       | 1,381          |       | 36             |       | 414                |       | 124            |       | 53 |   | 4 |   | 62 |   | 52 |   | 2,677 |   |
| Exploration                                            |       | 119                 |       | 123            |       | —         |       | 275                |       | 12             |       | 44 |   | — |   | — |   | — |   | 573 |   |
| Proved Property  Acquisitions                          |       | 46                  | **12**     | 1              |       | —         |       | 104                | **11**     | —         |       | — |   | — |   | — |   | — |   | 151 |   |
| **Total******                                          | ** ** | **716******         | ** ** | **1,505******  | ** ** | **36******     | ** ** | **793******        | ** ** | **136******    | ** ** | **97****** | ** ** | **4****** | ** ** | **62****** | ** ** | **52****** | ** ** | **3,401** | ** ** |
| ** **                                             | ** ** | ** **          | ** ** | ** **     | ** ** | ** **     | ** ** | ** **         | ** ** | ** **     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| PP&E                                               |       |                |       |           |       |           |       |               |       |           |       |   |   |   |   |   |   |   |   |   |   |
| Cost                                                   |       | 4,723               |       | 6,736          |       | 1,332          |       | 3,069              |       | 2,178          |       | 263 |   | 246 |   | 831 |   | 315 |   | 19,693 |   |
| Less: Accumulated  DD&A                            |       | 908                 |       | 1,597          |       | 205            |       | 1,765              |       | 1,950          |       | 77 |   | 62 |   | 463 |   | 168 |   | 7,195 |   |
| **Net Book Value****2**** **                      | ** ** | **3,815******       | ** ** | **5,139**      | **9**      | **1,127******  | ** ** | **1,304******      | ** ** | **228******    | ** ** | **186****** | ** ** | **184****** | ** ** | **368****** | ** ** | **147****** | ** ** | **12,498** | ** ** |
|                                                   |       |                |       |           |       |           |       |               |       |           |       |   |   |   |   |   |   |   |   |   |   |
| **Goodwill**                                           | ** ** | **276******         | ** ** | **—****** | ** ** | **—****** | ** ** | **—******     | ** ** | **—****** | ** ** | **—****** | ** ** | **50****** | ** ** | **—****** | ** ** | **—****** | ** ** | **326** | ** ** |

 

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*1*                           Includes results of operationsfrom producing activities in Colombia.

*2*                           Net sales made from allsegments originating in Canada: $1,188 million PP&E located in Canada:$6,893 million

*3*                           Net sales for our chemicalsoperations include:

 
| ***($ millions)*** |         |      |         |
|-------------------------|--------------|-----------|--------------|
| *Canada*                | * *     | *154*     | * *     |
| *US*                    | * *     | *169*     | * *     |
| *Brazil*                | * *     | *91*      | * *     |
| ***Total***             | *** *** | ***414*** | *** *** |

 

*4*                           Includes interest income of $39million, foreign exchange losses of $22 million and decrease in the fair valueof crude oil put options of $43 million.

*5*                           Includes an impairment chargeof $366 million related to oil and gas properties in the Gulf of Mexico.

*6*                           Includes stock-based compensationexpense of $38 million.

*7*                           Includes exploration activitiesprimarily in Nigeria, Norway and Colombia.

*8*                           The provision for (recovery of)income taxes for foreign locations is based on in-country taxes on foreignincome. For oil and gas locations with no operating activities, the provisionis based on the tax jurisdiction of the entity performing the activity.

*9*                           Includes costs of $3,695million related to our insitu oil sands (Long Lake and future phases).

*10*                    84% of Marketing’s identifiableassets are accounts receivable and inventories.

*11*                    Includes acquisition ofproducing properties in the Gulf of Mexico.

*12*                    Includes acquisition ofadditional interests in the Scott and Telford fields.

 

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**21****.****             ****DIFFERENCES BETWEEN CANADIAN AND USGENERALLY ACCEPTED ACCOUNTING PRINCIPLES**

 

The Consolidated Financial Statements have been prepared inaccordance with Canadian GAAP. US GAAP Consolidated Financial Statements andsummaries of differences from Canadian GAAP are as follows:

 

**Consolidated Statement of Income—US GAAP for theThree Years ended December 31, 2009**

 
| **(Cdn$ millions, except per  share amounts)**               | ** ** | **2009**   | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|-------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Revenues and Other Income                                         |       |       |       |       |       |       |       |
| Net Sales                                                         |       | 4,895      |       | 7,424      |       | 5,583      |       |
| Marketing and Other (i); (vi); (vii)                              |       | 897        |       | 796        |       | 938        |       |
|                                                              |       | 5,792      |       | 8,220      |       | 6,521      |       |
| Expenses                                                          |       |       |       |       |       |       |       |
| Operating (ii)                                                    |       | 1,280      |       | 1,335      |       | 1,167      |       |
| Depreciation, Depletion, Amortization and Impairment              |       | 1,802      |       | 2,014      |       | 1,767      |       |
| Transportation and Other (vi)                                     |       | 795        |       | 964        |       | 906        |       |
| General and Administrative (v)                                    |       | 532        |       | 263        |       | 401        |       |
| Exploration                                                       |       | 302        |       | 402        |       | 326        |       |
| Interest                                                          |       | 312        |       | 94         |       | 168        |       |
|                                                              |       | 5,023      |       | 5,072      |       | 4,735      |       |
|                                                              |       |       |       |       |       |       |       |
| Income before Provision for Income Taxes                          |       | 769        |       | 3,148      |       | 1,786      |       |
|                                                              |       |       |       |       |       |       |       |
| Provision for Income Taxes                                        |       |       |       |       |       |       |       |
| Current                                                           |       | 776        |       | 859        |       | 434        |       |
| Deferred (i); (ii); (v); (vii); (viii)                            |       | (534       | )          | 589        |       | 322        |       |
|                                                              |       | 242        |       | 1,448      |       | 756        |       |
|                                                              |       |       |       |       |       |       |       |
| Net Income                                                        |       | 527        |       | 1,700      |       | 1,030      |       |
| Less: Net Income (Loss) Attributable to Non-Controlling Interests |       | 20         |       | (4         | )          | 18         |       |
|                                                              |       |       |       |       |       |       |       |
| **Net Income  Attributable to Nexen Inc.—US GAAP****1**      | ** ** | **507**    | ** ** | **1,704**  | ** ** | **1,012**  | ** ** |
| ** **                                                        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Earnings Per  Common Share******($/share) (Note 18)             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic                                                             |       | 0.97       |       | 3.24       |       | 1.92       |       |
| Diluted                                                           |       | 0.97       |       | 3.20       |       | 1.88       |       |

 

----

*1*                           Reconciliation of Canadian andUS GAAP Net Income

 
| **(Cdn$ millions)**                                        | ** **   | **2009**  | ** **   | **2008**    | ** **   | **2007**    | ** **   |
|-----------------------------------------------------------------|--------------|-----------|--------------|-------------|--------------|-------------|--------------|
| *Net Income Attributable to Nexen Inc.— Canadian GAAP*     | * *     | *536*     | * *     | *1,715*     | * *     | *1,086*     | * *     |
| *Impact of US Principles, Net of  Income Taxes:*                |         |      |         |        |         |        |         |
| *Ineffective Portion of Cash Flow Hedges (i)*                   | * *     | *—*  | * *     | *—*    | * *     | *(2*        | *)*          |
| *Development Costs (ii)*                                        | * *     | *—*  | * *     | *—*    | * *     | *(1*        | *)*          |
| *Stock-based Compensation (v)*                                  | * *     | *(26*     | *)*          | *(4*        | *)*          | *(19*       | *)*          |
| *Inventory Valuation (vii)*                                     | * *     | *(10*     | *)*          | *(7*        | *)*          | *(52*       | *)*          |
| *Deferred Taxes (viii)*                                         | * *     | *7*       | * *     | *—*    | * *     | *—*    | * *     |
| ***Net Income Attributable to Nexen Inc.****— **US GAAP*** | *** *** | ***507*** | *** *** | ***1,704*** | *** *** | ***1,012*** | *** *** |

 

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**Consolidated Balance Sheet—US GAAP December 31,2009 and 2008**

 
| **(Cdn$ millions, except share  amounts)**                                                                                      | ** **                   | **2009**   | ** ** | **2008**   | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------|------------------------------|------------|------------|------------|------------|
| ** **                                                                                                                           |                         |       |       |       |       |
| **ASSETS**                                                                                                                           | ** **                   | ** ** | ** ** | ** ** | ** ** |
| Current Assets                                                                                                                       |                         |       |       |       |       |
| Cash and Cash Equivalents                                                                                                            |                         | 1,700      |       | 2,003      |       |
| Restricted Cash                                                                                                                      |                         | 198        |       | 103        |       |
| Accounts Receivable                                                                                                                  |                         | 2,788      |       | 3,163      |       |
| Inventories and Supplies (vii)                                                                                                       |                         | 610        |       | 426        |       |
| Other                                                                                                                                |                         | 185        |       | 169        |       |
| Total Current Assets                                                                                                                 |                         | 5,481      |       | 5,864      |       |
|                                                                                                                                 |                         |       |       |       |       |
| Property, Plant and Equipment                                                                                                        |                         |       |       |       |       |
| Net of Accumulated Depreciation, Depletion, Amortization and  Impairment of $11,200 (December 31, 2008—$10,786) (ii); (iv) |                         | 15,443     |       | 14,873     |       |
| Goodwill                                                                                                                             |                         | 339        |       | 390        |       |
| Deferred Income Tax Assets                                                                                                           |                         | 1,148      |       | 351        |       |
| Deferred Charges and Other Assets                                                                                                    |                         | 370        |       | 570        |       |
|                                                                                                                                 |                         |       |       |       |       |
| **TOTAL ASSETS**                                                                                                                     | ** **                   | **22,781** | ** ** | **22,048** | ** ** |
| ** **                                                                                                                           | ** **                   | ** ** | ** ** | ** ** | ** ** |
| **LIABILITIES**                                                                                                                      |                         |       |       |       |       |
| Current Liabilities                                                                                                                  |                         |       |       |       |       |
| Accounts Payable and Accrued Liabilities (v)                                                                                         |                         | 3,131      |       | 3,384      |       |
| Accrued Interest Payable                                                                                                             |                         | 89         |       | 67         |       |
| Dividends Payable                                                                                                                    |                         | 26         |       | 26         |       |
| Total Current Liabilities                                                                                                            |                         | 3,246      |       | 3,477      |       |
|                                                                                                                                 |                         |       |       |       |       |
| Long-Term Debt                                                                                                                       |                         | 7,251      |       | 6,578      |       |
| Deferred Income Tax Liabilities (ii); (iii); (v); (vii); (viii)                                                                      |                         | 2,720      |       | 2,543      |       |
| Asset Retirement Obligations                                                                                                         |                         | 1,018      |       | 1,024      |       |
| Deferred Credits and Other Liabilities (iii)                                                                                         |                         | 1,126      |       | 1,428      |       |
|                                                                                                                                 |                         |       |       |       |       |
| **Equity**                                                                                                                           |                         |       |       |       |       |
| Nexen Inc. Shareholders’ Equity                                                                                                 |                         |       |       |       |       |
| Common Shares, no par value                                                                                                          |                         |       |       |       |       |
| Authorized:                                                                                                                          | Unlimited                    |       |       |       |       |   |
| Outstanding:                                                                                                                         | 2009—522,915,843 shares |       |       |       |       |   |
|                                                                                                                                 | 2008—519,448,590 shares |       | 1,049      |       | 981        |   |
| Contributed Surplus                                                                                                                  |                         | 1          |       | 2          |       |
| Retained Earnings (i); (ii); (iv); (v); (vii); (viii)                                                                                |                         | 6,575      |       | 6,172      |       |
| Accumulated Other Comprehensive Loss (i); (iii)                                                                                      |                         | (269       | )          | (209       | )          |
| Total Nexen Inc. Shareholders’ Equity                                                                                           |                         | 7,356      |       | 6,946      |       |
| Canexus Non-Controlling Interest                                                                                                     |                         | 64         |       | 52         |       |
| Total Equity                                                                                                                         |                         | 7,420      |       | 6,998      |       |
| Commitments, Contingencies and Guarantees                                                                                            |                         |       |       |       |       |
| **TOTAL LIABILITIES  AND EQUITY**                                                                                                    | ** **                   | **22,781** | ** ** | **22,048** | ** ** |

 

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**Consolidated Statement of Comprehensive Income—USGAAP for the Three Years ended December 31, 2009**

 
| **(Cdn$ millions)**                                           | ** ** | **2009** | ** ** | **2008**  | ** ** | **2007** | ** ** |
|--------------------------------------------------------------------|------------|----------|------------|-----------|------------|----------|------------|
| Net Income Attributable to Nexen Inc.—US GAAP                 |       | 507      |       | 1,704     |       | 1,012    |       |
| Other Comprehensive Income (Loss), Net of Income  Taxes:           |       |     |       |      |       |     |       |
| Foreign Currency Translation Adjustment                            |       | (56      | )          | 159       |       | (132     | )          |
| Change in Mark to Market on Cash Flow Hedges                       |       | —   |       | —    |       | (61      | )          |
| Unamortized Defined Benefit Pension Plan Costs (iii)               |       | (4       | )          | (21       | )          | 2        |       |
| **Comprehensive  Income Attributable to Nexen Inc.— US GAAP** | ** ** | **447**  | ** ** | **1,842** | ** ** | **821**  | ** ** |

 

**Consolidated Statement of Accumulated Other ComprehensiveLoss—US GAAP December 31, 2009 and 2008**

 
| **(Cdn$ millions)**                             | ** ** | **2009** | ** ** | **2008** | ** ** |
|------------------------------------------------------|------------|----------|------------|----------|------------|
| Foreign Currency Translation Adjustment              |       | (190     | )          | (134     | )          |
| Unamortized Defined Benefit Pension Plan Costs (iii) |       | (79      | )          | (75      | )          |
| **Accumulated  Other Comprehensive Loss (AOCL)**     | ** ** | **(269** | **)**      | **(209** | **)**      |

 

**Notes to the Consolidated US GAAP Financial Statements:**

 

i.                              Under US GAAP, all derivativeinstruments are recognized on the balance sheet as either an asset or aliability measured at fair value. Changes in the fair value of derivatives arerecognized in earnings unless specific hedge criteria are met. On January 1,2007, we adopted the equivalent Canadian standard for derivative instrumentsand hedging.

 

In 2006, our US GAAP net incomeincluded gains of $2 million ($2 million, net of income taxes) for theineffective portion of certain cash flow hedges. Under Canadian GAAP, thesegains were recognized in 2007.

 

ii.                           UnderCanadian GAAP, we defer certain development costs to PP&E. Under US GAAP,these costs have been included in operating expenses. As a result:

 

·                  in 2007, US GAAP operatingexpenses included development costs of $2 million ($1 million, net of incometaxes)); and

 

·                  PP&E is lower under US GAAPby $30 million (December 31, 2008—lower by $30 million) and deferredincome tax liabilities is $11 million lower (December 31, 2008—lower by$11 million).

 

iii.                        US GAAP requires therecognition of the over-funded and under-funded status of defined benefitpension plans on the balance sheet as an asset or liability. At year end, theunfunded amount of our defined benefit pension plans that was not included inthe pension liability under Canadian GAAP was $105 million (2008—$104 million).This amount has been included in deferred credits and other liabilities and $79million, net of income taxes (2008—$75 million, net of income taxes) hasbeen included in AOCI.

 

iv.                       On January 1, 2003, weadopted A*ccounting for Asset RetirementObligations* for US GAAP reporting purposes. We adopted theequivalent Canadian standard for asset retirement obligations on January 1,2004. These standards are consistent, except for the adoption date, whichresulted in our PP&E under US GAAP being lower by $19 million.

 

v.                          UnderCanadian principles, we record obligations for liability-based stockcompensation plans using the intrinsic-value method of accounting. Under USprinciples, obligations for liability-based stock compensation plans arerecorded using the fair-value method of accounting. As a result:

 

·                  general and administrativeexpense is higher by $35 million ($26 million, net of income taxes) forthe year ended December 31, 2009 (2008—higher by $6 million ($4 million,net of income taxes); 2007—higher by $27 million ($19 million, net of incometaxes)); and

 

·                  accounts payable and accruedliabilities are higher by $93 million at December 31, 2009 (2008—higher by$58 million) and deferred income tax liabilities are $26 million lower(2008—lower by $17 million).

 

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vi.                       Under US GAAP, assetdisposition gains and losses are included with transportation and otherexpense. In 2009, we had net asset disposition gains and losses of nil and havenot reclassified from marketing and other income to transportation and otherexpense (2008—$3 million; 2007—$2 million).

 

vii.                    Under Canadian GAAP, wecarry our commodity inventory held for trading purposes at fair value, less anycosts to sell. Under US GAAP, we are required to carry this inventory at thelower of cost or net realizable value. As a result:

 

·                  marketing and other income islower by $12 million ($10 million, net of income taxes) for the year ended December 31,2009 (2008 lower by $14 million, ($7 million, net of income taxes); 2007 lowerby $79 million, ($52 million, net of income taxes)); and

 

·                  inventories are lower by $70million at December 31, 2009 (2008—lower by $58 million) and deferredincome tax liabilities are $23 million lower (2008—lower by $21 million).

 

viii.                 Under US GAAP, we are requiredto apply FIN48 Accounting for Uncertainty in Income Taxes regarding accountingand disclosure for uncertain tax positions.

 

As at December 31, 2009,the total amount of our unrecognized tax benefits was approximately $277million, all of which, if recognized, would affect our effective tax rate. Tothe extent interest and penalties may be assessed by taxing authorities on anyunderpayment of income tax, such amounts have been accrued and are classifiedas a component of income taxes in the Consolidated Statement of Income. As at December 31,2009, the total amount of interest and penalties related to uncertain taxpositions recognized in deferred income tax liabilities in the USGAAP—Consolidated Balance Sheet was approximately $8 million. We had nointerest or penalties included in the US GAAP—Consolidated Statement of Incomefor the year ended December 31, 2009.

 

Our income tax filings aresubject to audit by taxation authorities and as at December 31, 2009, thefollowing tax years remained subject to examination, (i) Canada—1985 todate, (ii) United Kingdom—2008 to date and (iii) United States—2005to date. We do not anticipate any material changes to the unrecognized taxbenefits previously disclosed within the next twelve months.

 

**Reconciliation of Unrecognized Tax Benefits**

 
| **(Cdn$ millions)**                                |   |   |   |
|---------------------------------------------------------|--------|--------|--------|
| Balance at January 1, 2009                         |   | 249    |   |
| Additions for tax positions related to the current year |   | 22     |   |
| Additions for tax positions related to prior years      |   | 52     |   |
| Reductions for tax positions related to prior years     |   | (46    | )      |
| **Balance at  December 31, 2009**                  |   | 277    |   |

 

**US GAAP STOCK-BASED COMPENSATION**

 

Under US GAAP, our stock-based compensation expense isaccounted for by applying FASB Statement 123 (revised) *Share-BasedPayments*. Under this guidance, our tandem options andstock appreciation rights (STARs) are considered liability-based stockcompensation plans. Obligations for liability-based stock compensation plansare measured at the estimated fair value and remeasured in each subsequentreporting period.

 

**Assumptions**

 

We use the Generalized Black-Scholes option pricing model toestimate the fair value of our stock-based compensation, with the followingassumptions:

 
| Expected Annual Dividends per Common Share ($/share)               |   | 0.20           |   |
|--------------------------------------------------------------------|--------|----------------|--------|
| Expected Volatility                                                |   | 56%            |   |
| Risk-Free Interest Rate                                            |   | 0.7%–3.1% |   |
| Weighted-Average Expected Life of Compensation Instruments (years) |   | 3.1–3.3   |   |

 

These assumptions are based on multiple factors, includinghistorical exercise patterns of employees in relatively homogenous groups withrespect to exercise and post-vesting employment termination behaviors, expectedfuture exercising patterns for those same homogenous groups, the impliedvolatility of our stock price, our expected future dividend levels and theinterest rate for Government of Canada bonds.

 

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**Tandem 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, 2009                      |       | 23,130                |       | 25                                              |       | 2.6                                                     |       | 62                                                 |       | 7                                           |       |
| Outstanding at December 31, 2009 and Expected to Vest |       | 22,877                |       | 25                                              |       | 2.6                                                     |       | 61                                                 |       | 7                                           |       |
| Exercisable at December 31, 2009                      |       | 15,282                |       | 25                                              |       | 1.8                                                     |       | 45                                                 |       | 6                                           |       |

 

The total intrinsic value of stock options exercised duringthe year ended December 31, 2009 was $66 million (2008—$88 million;2007—$149 million). As at December 31, 2009, we had $55 million ofunrecognized compensation expense related to stock options which we expect torecognize over a weighted-average period of 1.6 years.

 

**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, 2009                      |       | 19,480                |       | 25                                             |       | 3.3                                                     |       | 35                                                 |       | 6                                          |       |
| Outstanding at December 31, 2009 and Expected to Vest |       | 18,857                |       | 25                                             |       | 3.3                                                     |       | 33                                                 |       | 6                                          |       |
| Exercisable at December 31, 2009                      |       | 9,812                 |       | 28                                             |       | 2.3                                                     |       | 12                                                 |       | 4                                          |       |

 

The total intrinsic value of stock appreciation rightsexercised during the year ended December 31, 2009 was $26 million(2008—$52 million; 2007—$50 million). As at December 31, 2009, we had $64million of unrecognized compensation expense related to stock appreciationrights which we expect to recognize over a weighted-average period of 1.6years.

 

**Stock-Based Compensation Expense and Payments**

** **

For the year ended December 31, 2009, stock-basedcompensation recovery of $104 million (2008—$154 million recovery; 2007—$65million expense) was included in general and administrative expense in theConsolidated Statement of Income—US GAAP.

 

For the year ended December 31, 2009, cash proceeds of$12 million were received related to the exercise of stock options(2008—$23 million; 2007—$24 million). For the year ended December 31,2009, $81 million was paid related to the exercise of stock options and stockappreciation rights (2008—$121 million; 2007—$149 million). The income taxbenefit recorded from the exercise of stock options and stock appreciationrights was $20 million (2008—$34 million; 2007—$42 million) for theperiod.

 

**Stock-Based Compensation Expense for Retired and Retirement EligibleEmployees**

 

We recognize stock-based compensation expense for our retiredand retirement-eligible employees over an accelerated graded vesting period inaccordance with the provisions of *Share—BasedPayments* for stock-based awards granted to employeeson or after January 1, 2006. For stock-based awards granted prior to theadoption of this guidance, 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 the new guidance tostock-based awards granted to our retired and retirement-eligible employeesprior to the its adoption, our stock-based compensation expense would remainunchanged for the year ended December 31, 2009 (2008—$2 million;2007—$9 million).

 

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** **

**Changes in Accounting Policies—US GAAP**

 

**BUSINESS COMBINATIONS**

 

On January 1, 2009, we prospectively adopted *BusinessCombinations*, which establishes principles andrequirements of the acquisition method for business combinations and relateddisclosures. The adoption of this standard did not impact our results ofoperations or financial position.

 

**NON-CONTROLLING INTERESTS**

 

On January 1, 2009, we prospectively adopted *Non-controllingInterests in Consolidated Financial Statements*. Thisstandard clarifies that a non-controlling interest in a subsidiary is anownership interest in the consolidated entity that should be reported as equityin the Consolidated Financial Statements. The adoption of this standard did nothave a material impact on our results of operation or financial position. Thepresentation changes have been included in the Consolidated FinancialStatements, as applicable.

 

**DERIVATIVE AND HEDGING ACCOUNTING AND DISCLOSURES**

 

On January 1, 2009, we prospectively adopted *Disclosuresabout Derivative Instruments and Hedging Activities*.The standard requires qualitative disclosures about the objectives andstrategies for using derivatives, quantitative data about the fair value ofgains and losses on derivative contracts and details of credit-risk-relatedcontingent features in those derivative contracts. The standard also requiresthe disclosure of the location and amounts of derivative instruments in thefinancial statements. The disclosures required by this standard are provided inNotes 6 and 7.

 

On April 1, 2009, we prospectively adopted three changesto FASB guidance intended to improve guidance and disclosures on fair valuemeasurement and impairments. The positions clarify fair value accountingspecifically regarding: inactive markets and distressed transactions,other-than-temporary impairments, and expanded fair value disclosures forfinancial instruments in interim periods. The adoption of these positions didnot have a material impact on our results of operations or financial position.

 

**SUBSEQUENT EVENTS**

 

On April 1, 2009, we prospectively adopted *SubsequentEvents*. The new standard reflects the existingprinciples of current subsequent events accounting guidance and retains thenotion and definition of “available to be issued” financial statements. The newstandard requires disclosure of the date through which subsequent events havebeen evaluated and clarifies that original issuance of financial statementsmeans both “issued” or “available to be issued”. The adoption of this standarddid not have a material impact on our results of operations or financialposition.

 

**POST-RETIREMENT BENEFIT PLAN ASSETSDISCLOSURES**

 

In December 2008, FASB issued *EmployersDisclosures about Postretirement Benefit Plan Assets*. Thisstandard provides guidance on disclosures about plan assets of a definedbenefit pension or other post-retirement plans and has been adopted for ourannual disclosures provided in Note 13. The adoption of this statement did nothave a material impact on our results of operations or financial position.

 

**New Accounting Pronouncement—US GAAP**

 

In June 2009, FASB issued *Amendments to Consolidation of Variable Interest Entities*.It retains the scope of the previous guidance with the addition of entitiespreviously considered qualifying special-purpose entities and replaces theprevious quantitative approach with a qualitative analysis in determiningwhether the enterprise’s variable interest or interests give it a controllingfinancial interest in a variable interest entity. The Statement is furtheramended to require ongoing reassessments of whether an enterprise is theprimary beneficiary of a variable interest entity and requires enhanceddisclosures about an enterprise’s involvement in a variable interest entity.The standard is effective at the beginning of the first annual reporting periodafter November 15, 2009. We do not expect the adoption of this standard tohave a material impact on our results of operations or financial position.

 

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** **

**SUPPLEMENTARYDATA (UNAUDITED)**

 

**Quarterly Financial Data inAccordance with Canadian and US GAAP**

 
| ** **                                         | ** ** | **Quarter Ended** | ** ** |
|----------------------------------------------------|------------|-------------------|------------|
| ** **                                         | ** ** | **March 31** | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| **(Cdn$ millions)**                           | ** ** | **2009**          | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Net Sales                                          |       | 1,048             |       | 1,870 |   | 1,200 |   | 2,071 |   | 1,097 |   | 2,213 |   | 1,550 |   | 1,270 |   |
|                                               |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Income (Loss) before Income Taxes is Comprised of: |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Oil and Gas1                                       |       | 196               |       | 1,128 |   | 282 |   | 1,073 |   | 250 |   | 1,503 |   | 453 |   | (218 | ) |
| Energy Marketing                                   |       | 83                |       | 14 |   | 25 |   | (183 | ) | 18 |   | (79 | ) | 109 |   | (161 | ) |
| Chemicals                                          |       | 10                |       | (4 | ) | 15 |   | 11 |   | 41 |   | 5 |   | 13 |   | (26 | ) |
| Corporate and Other                                |       | (120              | )          | (38 | ) | (323 | ) | (208 | ) | (66 | ) | 77 |   | (170 | ) | 274 |   |
| ** **                                         | ** ** | **169**           | ** ** | **1,100** | ** ** | **(1** | **)** | **693** | ** ** | **243** | ** ** | **1,506** | ** ** | **405** | ** ** | **(131** | **)** |
|                                               | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Net  Income (Loss)—Canadian GAAP**          | ** ** | **135**           | ** ** | **630** | ** ** | **20** | ** ** | **380** | ** ** | **122** | ** ** | **886** | ** ** | **259** | ** ** | **(181** | **)** |
| US GAAP Adjustments                                |       | 21                |       | (13 | ) | (32 | ) | (62 | ) | 53 |   | 120 |   | (71 | ) | (56 | ) |
| **Net  Income (Loss)****—****US GAAP**        | ** ** | **156**           | ** ** | **617** | ** ** | **(12** | **)** | **318** | ** ** | **175** | ** ** | **1,006** | ** ** | **188** | ** ** | **(237** | **)** |
| ** **                                         | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Earnings  (Loss) per Common Share**($/share)     | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Canadian GAAP—Basic                           |       | 0.26              |       | 1.19 |   | 0.04 |   | 0.72 |   | 0.23 |   | 1.68 |   | 0.50 |   | (0.35 | ) |
| Canadian GAAP—Diluted                         |       | 0.26              |       | 1.17 |   | 0.04 |   | 0.70 |   | 0.23 |   | 1.66 |   | 0.49 |   | (0.35 | ) |
| US GAAP—Basic                                 |       | 0.30              |       | 1.17 |   | (0.02 | ) | 0.60 |   | 0.34 |   | 1.91 |   | 0.36 |   | (0.46 | ) |
| US GAAP—Diluted                               |       | 0.30              |       | 1.15 |   | (0.02 | ) | 0.59 |   | 0.33 |   | 1.89 |   | 0.36 |   | (0.46 | ) |
|                                               |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Dividends  Declared****2**                       |       | 0.050             |       | 0.025 |   | 0.050 |   | 0.050 |   | 0.050 |   | 0.050 |   | 0.050 |   | 0.050 |   |
| ** **                                         |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Common  Share Prices****3**** **($/share)   |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Toronto Stock Exchange—High                   |       | 24.24             |       | 34.20 |   | 28.54 |   | 43.45 |   | 25.94 |   | 41.47 |   | 27.31 |   | 29.10 |   |
| Toronto Stock Exchange—Low                    |       | 14.86             |       | 26.00 |   | 20.65 |   | 29.69 |   | 20.70 |   | 21.12 |   | 22.26 |   | 13.33 |   |
| New York Stock Exchange—High (US$)            |       | 20.61             |       | 34.57 |   | 26.25 |   | 42.71 |   | 24.43 |   | 40.99 |   | 26.05 |   | 23.99 |   |
| New York Stock Exchange—Low (US$)             |       | 11.89             |       | 25.11 |   | 16.33 |   | 28.87 |   | 18.68 |   | 20.56 |   | 20.66 |   | 10.81 |   |

 

----

*1*                 The fourth quarter of2009 includes an impairment charge of $78 million relating to oil and gasproperties in Canada and the US Gulf of Mexico. The fourth quarter of 2008includes an impairment charge of $568 million relating to oil and gasproperties in the US Gulf of Mexico and the UK North Sea.

*2*                 In February 2010,the Board of Directors declared a quarterly dividend of $0.05 per common share,payable April 1, 2010, to shareholders of record on March 10, 2010.

*3*                 At December 31,2009, there were 1,725 registered holders of common shares and 522,915,843common shares outstanding.

 

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**Oil and Gas Producing Activities (Unaudited)**

 

The following oil and gasinformation is provided in accordance with the Financial Accounting StandardsBoard (FASB) Topic 932 *Extractive Activities—Oil and Gas.*

 

OnDecember 31, 2008, the SEC issued new rules relating to reservedefinitions and related disclosure requirements. The new rules areeffective for estimates and disclosures made on or after January 1, 2010.FASB amended their oil and gas disclosure rules in January 2010 toalign with the new SEC rules. The primary impacts of changes on our reservesestimates and disclosures resulting from the adoption of the new SEC and FASB rules areas follows:

 

·                  our Syncrude oil sandsactivities are now considered an oil and gas activity rather than a miningactivity. This impacts the classification of the reserves but does not resultin a change in the estimate of reserves, except that under oil and gas reservesdefinitions we consider a portion of the previously reported mining reserves tobe proved undeveloped reserves;

 

·                  reserves quantities arenow based on the final product sold after field upgrading rather than theproduct initially produced. This results in presenting our Long Lake oil sandsreserves as synthetic oil barrels rather than bitumen barrels. The reduction inquantity reflects the removal of the asphaltenes from the bitumen barrel, whichwe gasify for use as our internal fuel source in the steam generation,upgrading and cogeneration power processes. The adjustment from bitumen tosynthetic reserves estimates upon adoption of the new rules is shownseparately on pages 152 to 153; and

 

·                  prices underlying oureconomic assumptions used for reserves estimation are now based on the averagefirst-day-of-the-month prices during the year, rather than the prices on December 31each year. The average prices were used in preparing the 2009 reservesestimates and changes therein so there is no separate adjustment for thischange in methodology. Based on a high level sensitivity analysis, had wepresented our proved reserves estimates based on December 31, 2009 prices,our proved reserves would have been 14 mmboe higher which would then have beenreversed upon adoption of the new rules.

 

Please refer to pages 4 to6 of this report for more information on the impact of the new SEC rules onour reserves estimates and disclosures.

 

**A.    RESERVE QUANTITY INFORMATION**

 

Our net proved reserves andchanges in those reserves for our oil and gas operations are disclosed on pages 152to 153.

 

The net proved reservesrepresent management’s best estimate of remaining proved oil and gas reservesafter royalties. Reserve estimates for each property are prepared internallyeach year, and at least 80% of the proved reserves have been assessed byindependent qualified reserves consultants.

 

Estimates of proved oil and gasreserves are determined through analysis of geological and engineering data,and demonstrate reasonable certainty that they are recoverable from knownreservoirs under existing economic and operating conditions based on the12-month average prices for 2009 and year-end prices for prior years. See Basisof Reserves Estimates on page 29 for a description of our oil and gasreserves estimation process.

 

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| ** **                               | ** ** | **Total—by  Product** | ** ** | **Canada**                  | ** ** |
|------------------------------------------|------------|----------------------------|------------|-----------------------------|------------|
| ** **                               | ** ** | **Total  (mmboe)**         | ** ** | **Synthetic  Oil  (mmbbl)** | ** ** | **Bitumen  (mmbbl)** | ** ** | **Oil  (mmbbl)** | ** ** | **Gas  (bcf)** | ** ** | **Syncrude  Synthetic Oil****1****(mmbbl)** | ** ** | **Long  Lake  Synthetic Oil****2****(mmbbl)** | ** ** | **Long  Lake  Bitumen****2****(mmbbl)** | ** ** | **Oil  (mmbbl)** | ** ** | **Gas  (bcf)** | ** ** |
| **Proved Reserves after Royalties****6** | ** ** | ** **                 | ** ** | ** **                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **December 31, 2006**               | ** ** | **912**                    | ** ** | **274**                     | ** ** | **219** | ** ** | **330** | ** ** | **532** | ** ** | **274** | ** ** | **—** | ** ** | **219** | ** ** | **48** | ** ** | **314** | ** ** |
| Extensions &  Discoveries       |       | 29                         |       | 7                           |       | — |   | 13 |   | 51 |   | 7 |   | — |   | — |   | 1 |   | 31 |   |
| Revisions—Technical                 |       | 53                         |       | —                      |       | 19 |   | 34 |   | — |   | — |   | — |   | 19 |   | (1 | ) | 11 |   |
| Revisions—Economic                  |       | (9                         | )          | (7                          | )          | (4 | ) | 4 |   | (11 | ) | (7 | ) | — |   | (4 | ) | 4 |   | (4 | ) |
| Acquisitions                             |       | 10                         |       | —                      |       | — |   | 3 |   | 42 |   | — |   | — |   | — |   | — |   | 1 |   |
| Divestments                              |       | (2                         | )          | —                      |       | — |   | — |   | (10 | ) | — |   | — |   | — |   | — |   | — |   |
| Production                               |       | (76                        | )          | (7                          | )          | — |   | (57 | ) | (72 | ) | (7 | ) | — |   | — |   | (5 | ) | (35 | ) |
| **December 31, 2007**               | ** ** | **917**                    | ** ** | **267**                     | ** ** | **234** | ** ** | **327** | ** ** | **532** | ** ** | **267** | ** ** | **—** | ** ** | **234** | ** ** | **47** | ** ** | **318** | ** ** |
| Extensions &  Discoveries       |       | 40                         |       | 7                           |       | 19 |   | 7 |   | 39 |   | 7 |   | — |   | 19 |   | 1 |   | 34 |   |
| Revisions—Technical                 |       | 27                         |       | —                      |       | — |   | 20 |   | 40 |   | — |   | — |   | — |   | (3 | ) | 54 |   |
| Revisions—Economic                  |       | 21                         |       | 28                          |       | 31 |   | (34 | ) | (21 | ) | 28 |   | — |   | 31 |   | (19 | ) | (16 | ) |
| Acquisitions                             |       | —                     |       | —                      |       | — |   | — |   | — |   | — |   | — |   | — |   | — |   | — |   |
| Divestments                              |       | —                     |       | —                      |       | — |   | — |   | — |   | — |   | — |   | — |   | — |   | — |   |
| Production                               |       | (79                        | )          | (7                          | )          | (2 | ) | (58 | ) | (71 | ) | (7 | ) | — |   | (2 | ) | (4 | ) | (40 | ) |
| **December 31, 2008**               | ** ** | **926**                    | ** ** | **295**                     | ** ** | **282** | ** ** | **262** | ** ** | **519** | ** ** | **295** | ** ** | **—** | ** ** | **282** | ** ** | **22** | ** ** | **350** | ** ** |
| Extensions &  Discoveries       |       | 63                         |       | 7                           |       | 23 |   | 28 |   | 33 |   | 7 |   | — |   | 23 |   | 1 |   | 16 |   |
| Revisions—Technical                 |       | 9                          |       | —                      |       | (4 | ) | 10 |   | 16 |   | — |   | — |   | (4 | ) | (1 | ) | 12 |   |
| Revisions—Economic3                 |       | (2                         | )          | (7                          | )          | (9 | ) | 27 |   | (81 | ) | (7 | ) | — |   | (9 | ) | 13 |   | (87 | ) |
| Acquisitions                             |       | 85                         |       | —                      |       | 85 |   | — |   | — |   | — |   | — |   | 85 |   | — |   | — |   |
| Divestments                              |       | —                     |       | —                      |       | — |   | — |   | — |   | — |   | — |   | — |   | — |   | — |   |
|  Production                         |       | (78                        | )          | (7                          | )          | (3 | ) | (55 | ) | (76 | ) | (7 | ) | — |   | (3 | ) | (4 | ) | (47 | ) |
|                                     |       | 1,003                      |       | 288                         |       | 374 |   | 272 |   | 411 |   | 288 |   | — |   | 374 |   | 31 |   | 244 |   |
| SEC  Rule Transition2               |       |                       |       |                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Synthetic—Current  Year             |       | (32                        | )          | 60                          |       | (92 | ) | — |   | — |   | — |   | 60 |   | (92 | ) | — |   | — |   |
| Synthetic—Prior  Years              |       | (51                        | )          | 231                         |       | (282 | ) | — |   | — |   | — |   | 231 |   | (282 | ) | — |   | — |   |
| **December 31, 2009**               | ** ** | **920**                    | ** ** | **579**                     | ** ** | **—** | ** ** | **272** | ** ** | **411** | ** ** | **288** | ** ** | **291** | ** ** | **—** | ** ** | **31** | ** ** | **244** | ** ** |
| ** **                               | ** ** | ** **                 | ** ** | ** **                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Proved Undeveloped**                   | ** ** | ** **                 | ** ** | ** **                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| December 31,  2008                  |       | 406                        |       | 96                          |       | 230 |   | 70 |   | 55 |   | 96 |   | — |   | 230 |   | — |   | 21 |   |
| **December 31, 2009**               | ** ** | **413**                    | ** ** | **339**                     | ** ** | **—** | ** ** | **69** | ** ** | **32** | ** ** | **103** | ** ** | **236** | ** ** | **—** | ** ** | **2** | ** ** | **3** | ** ** |
| ** **                               | ** ** | ** **                 | ** ** | ** **                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Proved Developed****7**                | ** ** | ** **                 | ** ** | ** **                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| December 31,  2008                  |       | 520                        |       | 199                         |       | 52 |   | 192 |   | 464 |   | 199 |   | — |   | 52 |   | 22 |   | 329 |   |
| **December 31, 2009**               | ** ** | **507**                    | ** ** | **240**                     | ** ** | **—** | ** ** | **203** | ** ** | **379** | ** ** | **185** | ** ** | **55** | ** ** | **—** | ** ** | **29** | ** ** | **241** | ** ** |

 

Continued on following page.

----

| *1* | *As described on page 5,  our Syncrude oil sands activities are now considered an oil and gas activity  rather than a mining activity. This impacts the classification of the  reserves but does not result in a change in the estimate of reserves. For  simplicity of understanding, we have included the Syncrude reserves in our  prior years’ reserves balances and changes therein as the information was  previously presented in our 2008 Form 10-K.*      |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *2* | *As described on page 5,  our Long Lake oil sands reserves are now presented as synthetic oil barrels  rather than bitumen barrels.*                                                                                                                                                                                                                                                                                                                                         |
| *3* | *As described on page 5, prices  underlying our economic assumptions used for reserve estimation in 2009 are  based on the average first-day-of-the-month prices during the year, rather  than the year-end prices. The average prices were used in preparing the 2009  reserves estimates and changes therein so there is no separate adjustment for  this change in methodology. Our reserve estimates in 2008 and 2007 were  prepared using the December 31 prices.* |

 

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| ** **                                | ** ** | **United Kingdom**     | ** ** | **United States**    | ** ** | **Yemen****4**         | ** ** | **Other Countries****5** | ** ** |
|-------------------------------------------|------------|------------------------|------------|----------------------|------------|------------------------|------------|--------------------------|------------|
| ** **                                | ** ** | **Oil********(mmbbl)** | ** ** | **Gas********(bcf)** | ** ** | **Oil********(mmbbl)** | ** ** | **Gas********(bcf)**     | ** ** | **Oil********(mmbbl)** | ** ** | **Oil********(mmbbl)** | ** ** |
| **Proved  Reserves after Royalties****6** | ** ** | ** **             | ** ** | ** **           | ** ** | ** **             | ** ** | ** **               | ** ** | ** ** | ** ** | ** ** |   |
| **December 31,  2006**               | ** ** | **179**                | ** ** | **23**               | ** ** | **30**                 | ** ** | **195**                  | ** ** | **38** | ** ** | **35** | ** ** |
| Extensions & Discoveries         |       | 10                     |       | 2                    |       | 1                      |       | 18                       |       | 1 |   | — |   |
| Revisions—Technical                  |       | 39                     |       | 8                    |       | (4                     | )          | (19                      | )          | — |   | — |   |
| Revisions—Economic                   |       | 4                      |       | (2                   | )          | (2                     | )          | (5                       | )          | (2 | ) | — |   |
| Acquisitions                              |       | 1                      |       | —               |       | 2                      |       | 41                       |       | — |   | — |   |
| Divestments                               |       | —                 |       | —               |       | —                 |       | (10                      | )          | — |   | — |   |
| Production                                | ** ** | (30                    | )          | (6                   | )          | (6                     | )          | (31                      | )          | (14 | ) | (2 | ) |
| **December 31,  2007**               | ** ** | **203**                | ** ** | **25**               | ** ** | **21**                 | ** ** | **189**                  | ** ** | **23** | ** ** | **33** | ** ** |
| Extensions & Discoveries         |       | 5                      |       | —               |       | —                 |       | 5                        |       | 1 |   | — |   |
| Revisions—Technical                  |       | 17                     |       | —               |       | 2                      |       | (14                      | )          | 6 |   | (2 | ) |
| Revisions—Economic                   |       | (16                    | )          | —               |       | (3                     | )          | (5                       | )          | 2 |   | 2 |   |
| Acquisitions                              |       | —                 |       | —               |       | —                 |       | —                   |       | — |   | — |   |
| Divestments                               |       | —                 |       | —               |       | —                 |       | —                   |       | — |   | — |   |
| Production                                |       | (37                    | )          | (7                   | )          | (3                     | )          | (24                      | )          | (12 | ) | (2 | ) |
| **December 31,  2008**               | ** ** | **172**                | ** ** | **18**               | ** ** | **17**                 | ** ** | **151**                  | ** ** | **20** | ** ** | **31** | ** ** |
| Extensions & Discoveries         |       | 19                     |       | 6                    |       | 1                      |       | 11                       |       | — |   | 7 |   |
| Revisions—Technical                  |       | 5                      |       | 2                    |       | 1                      |       | 2                        |       | 5 |   | — |   |
| Revisions—Economic3                  |       | 9                      |       | —               |       | 3                      |       | 6                        |       | 1 |   | 1 |   |
| Acquisitions                              |       | —                 |       | —               |       | —                 |       | —                   |       | — |   | — |   |
| Divestments                               |       | —                 |       | —               |       | —                 |       | —                   |       | — |   | — |   |
| Production                                |       | (36                    | )          | (9                   | )          | (3                     | )          | (20                      | )          | (11 | ) | (1 | ) |
|                                      |       | 169                    |       | 17                   |       | 19                     |       | 150                      |       | 15 |   | 38 |   |
| SEC Rule Transition2                 |       |                   |       |                 |       |                   |       |                     |       |   |   |   |   |
| Synthetic—Current Year               |       | —                 |       | —               |       | —                 |       | —                   |       | — |   | — |   |
| Synthetic—Prior Years                |       | —                 |       | —               |       | —                 |       | —                   |       | — |   | — |   |
| **December 31,  2009**               | ** ** | **169**                | ** ** | **17**               | ** ** | **19**                 | ** ** | **150**                  | ** ** | **15** | ** ** | **38** | ** ** |
| ** **                                | ** ** | ** **             | ** ** | ** **           | ** ** | ** **             | ** ** | ** **               | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Proved  Undeveloped**                   | ** ** | ** **             | ** ** | ** **           | ** ** | ** **             | ** ** | ** **               | ** ** | ** ** | ** ** | ** ** | ** ** |
| December 31, 2008                    |       | 39                     |       | 7                    |       | 5                      |       | 27                       |       | 1 |   | 25 |   |
| **December 31,  2009**               | ** ** | **27**                 | ** ** | **4**                | ** ** | **6**                  | ** ** | **25**                   | ** ** | **1** | ** ** | **33** | ** ** |
| ** **                                | ** ** | ** **             | ** ** | ** **           | ** ** | ** **             | ** ** | ** **               | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Proved  Developed****7**                | ** ** | ** **             | ** ** | ** **           | ** ** | ** **             | ** ** | ** **               | ** ** | ** ** | ** ** | ** ** | ** ** |
| December 31, 2008                    |       | 133                    |       | 11                   |       | 12                     |       | 124                      |       | 19 |   | 6 |   |
| **December 31,  2009**               | ** ** | **142**                | ** ** | **13**               | ** ** | **13**                 | ** ** | **125**                  | ** ** | **14** | ** ** | **5** | ** ** |

* *

----

| *4* | *Under the terms of the Masila  and the Block 51 production sharing contracts, production is divided into  cost recovery oil and profit oil. 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.* |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *5* | *Represents reserves in Nigeria  and Colombia.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| *6* | *Proved reserves are those  quantities of oil and gas, which, by analysis of geoscience and engineering  data, can be estimated with reasonable certainty to be economically producible  from a given date forward, from known reservoirs, and under existing economic  conditions, operating conditions, and government regulations.*                                                                                                                                                                                                                                                                                                                                                                                                                                |
| *7* | *Proved developed oil and gas  reserves are expected to be recovered through existing wells with existing equipment  and operating methods.*                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |

 

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**B.    CAPITALIZED COSTS**

 

In 2009, as a result of changes to oil and gas disclosure rules issuedby FASB, Syncrude activities and field upgrading operations at Long Lake areconsidered oil and gas activities effective December 31, 2009. Informationfor Syncrude and Long Lake upgrading for 2009 has been provided. As the changein the rules is to be applied prospectively, information for prior yearshas not been restated. The impact of the changes result in includingcapitalized costs for our share of Syncrude and the Long Lake upgrader at December 31,2009 of $1,193 million and $2,463 million, respectively.

 
| **(Cdn$ millions)**     | ** ** | **Proved   Properties** | ** ** | **Unproved   Properties** | ** ** | **Accumulated   DD&A** | ** ** | **Capitalized  Costs** | ** ** |
|------------------------------|------------|-------------------------|------------|---------------------------|------------|----------------------------|------------|------------------------|------------|
| **December 31,  2009**  |       |                    |       |                      |       |                       |       |                   |       |
| United Kingdom               |       | 4,995                   |       | 1,120                     |       | (2,664                     | )          | 3,451                  |       |
| Canada                       |       | 3,383                   |       | 573                       |       | (2,424                     | )          | 1,532                  |       |
| Long Lake1                   |       | 5,223                   |       | 829                       |       | (7                         | )          | 6,045                  |       |
| Syncrude                     |       | 1,463                   |       | —                    |       | (270                       | )          | 1,193                  |       |
| United States                |       | 3,665                   |       | 235                       |       | (2,529                     | )          | 1,371                  |       |
| Yemen                        |       | 2,462                   |       | —                    |       | (2,322                     | )          | 140                    |       |
| Other Countries              |       | 878                     |       | 52                        |       | (99                        | )          | 831                    |       |
| **Total  Capitalized Costs** | ** ** | **22,069**              | ** ** | **2,809**                 | ** ** | **(10,315**                | **)**      | **14,563**             | ** ** |
| **December 31,  2008**  |       |                    |       |                      |       |                       |       |                   |       |
| United Kingdom               |       | 5,954                   |       | 578                       |       | (2,159                     | )          | 4,373                  |       |
| Canada                       |       | 3,166                   |       | 566                       |       | (2,175                     | )          | 1,557                  |       |
| Long Lake1              |       | 1,921                   |       | 501                       |       | (4                         | )          | 2,418                  |       |
| United States                |       | 4,152                   |       | 246                       |       | (2,702                     | )          | 1,696                  |       |
| Yemen                        |       | 2,808                   |       | —                    |       | (2,610                     | )          | 198                    |       |
| Other Countries              |       | 509                     |       | 45                        |       | (113                       | )          | 441                    |       |
| **Total  Capitalized Costs** | ** ** | **18,510**              | ** ** | **1,936**                 | ** ** | **(9,763**                 | **)**      | **10,683**             | ** ** |
| **December 31,  2008**  | ** ** | ** **              | ** ** | ** **                | ** ** | ** **                 | ** ** | ** **             |       |
| United Kingdom               |       | 4,318                   |       | 405                       |       | (908                       | )          | 3,815                  |       |
| Canada                       |       | 3,057                   |       | 326                       |       | (1,988                     | )          | 1,395                  |       |
| Long Lake1                   |       | 1,307                   |       | 408                       |       | (2                         | )          | 1,713                  |       |
| United States                |       | 2,931                   |       | 138                       |       | (1,765                     | )          | 1,304                  |       |
| Yemen                        |       | 2,178                   |       | —                    |       | (1,950                     | )          | 228                    |       |
| Other Countries              |       | 105                     |       | 158                       |       | (77                        | )          | 186                    |       |
| **Total  Capitalized Costs** | ** ** | **13,896**              | ** ** | **1,435**                 | ** ** | **(6,690**                 | **)**      | **8,641**              | ** ** |

 

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*1*                 Capitalized costs in 2008and 2007 reflect bitumen production activities only; 2009 amounts reflectupgrading activities to produce synthetic barrels.

 

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**C.    COSTS INCURRED**

 

In 2009, as a result of changes to oil and gas disclosure rules issuedby FASB, Syncrude activities and field upgrading operations at Long Lake areconsidered oil and gas activities effective December 31, 2009. Informationfor 2009 for Syncrude and Long Lake upgrading has been provided. As the changein the rules is to be applied prospectively, information for prior yearshas not been restated. The impact of the changes result in including costsincurred at Syncrude and the Long Lake upgrader during 2009 of $114 million and$424 million, respectively.

 
| ** **                             | ** ** | ** **             | ** ** | **Oil and Gas**     | ** ** |
|----------------------------------------|------------|------------------------|------------|---------------------|------------|
| **(Cdn$ millions)**               | ** ** | **Total  Oil and Gas** | ** ** | **United  Kingdom** | ** ** | **Canada Other** | ** ** | **Long Lake****1** | ** ** | **Syncrude** | ** ** | **United  States** | ** ** | **Yemen** | ** ** | **Other** | ** ** |
| **Year Ended  December 31, 2009** |       |                   |       |                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Property Acquisition Costs             |       |                   |       |                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved                                 |       | 755                    |       | —              |       | — |   | 755 |   | — |   | — |   | — |   | — |   |
| Unproved                               |       | 13                     |       | —              |       | 3 |   | — |   | — |   | 10 |   | — |   | — |   |
| Exploration Costs                      |       | 650                    |       | 155                 |       | 224 |   | 1 |   | — |   | 183 |   | — |   | 87 |   |
| Development Costs                      |       | 1,923                  |       | 457                 |       | 115 |   | 549 |   | 114 |   | 120 |   | 69 |   | 499 |   |
| **Total Costs  Incurred****2**         | ** ** | **3,341**              | ** ** | **612**             | ** ** | **342** | ** ** | **1,305** | ** ** | **114** | ** ** | **313** | ** ** | **69** | ** ** | **586** | ** ** |
| **Year Ended  December 31, 2008** |       |                   |       |                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Property Acquisition Costs             |       |                   |       |                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved                                 |       | 22                     |       | —              |       | 2 |   | 20 |   | — |   | — |   | — |   | — |   |
| Unproved                               |       | 69                     |       | —              |       | 6 |   | — |   | — |   | 63 |   | — |   | — |   |
| Exploration Costs                      |       | 650                    |       | 157                 |       | 220 |   | 2 |   | — |   | 132 |   | 9 |   | 130 |   |
| Development Costs                      |       | 1,983                  |       | 555                 |       | 205 |   | 537 |   | — |   | 404 |   | 92 |   | 190 |   |
| **Total Costs  Incurred**              | ** ** | **2,724**              | ** ** | **712**             | ** ** | **433** | ** ** | **559** | ** ** | **—** | ** ** | **599** | ** ** | **101** | ** ** | **320** | ** ** |
| **Year Ended  December 31, 2007** | ** ** | ** **             | ** ** | ** **          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Property Acquisition Costs             |       |                   |       |                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved                                 |       | 151                    |       | 46                  |       | 1 |   | — |   | — |   | 104 |   | — |   | — |   |
| Unproved                               |       | 59                     |       | 1                   |       | 29 |   | 5 |   | — |   | 24 |   | — |   | — |   |
| Exploration Costs                      |       | 637                    |       | 128                 |       | 92 |   | 1 |   | — |   | 311 |   | 15 |   | 90 |   |
| Development Costs                      |       | 1,986                  |       | 636                 |       | 296 |   | 427 |   | — |   | 444 |   | 130 |   | 53 |   |
| **Total Costs  Incurred**              | ** ** | **2,833**              | ** ** | **811**             | ** ** | **418** | ** ** | **433** | ** ** | **—** | ** ** | **883** | ** ** | **145** | ** ** | **143** | ** ** |

 

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| *1* | *Costs incurred in 2008 and 2007  reflect bitumen production activities only; 2009 amounts reflect upgrading  activities to produce synthetic barrels.*                                                                  |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *2* | *Total costs incurred include  asset retirement costs of $38 million, geological and geophysical costs of  $81 million and excludes costs related to chemicals, energy marketing,  corporate and other of $275 million.* |

 

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**D.    RESULTS OF OPERATIONS FOR PRODUCINGACTIVITIES**

 

In 2009, as a result of changes to oil and gas disclosure rules issuedby FASB, Syncrude activities and field upgrading operations at Long Lake areconsidered oil and gas activities effective December 31, 2009. Informationfor 2009 for Syncrude and Long Lake upgrading has been provided. As the changein the rules is to be applied prospectively, information for prior yearshas not been restated.

 
| ** **                                           | ** ** | ** **             | ** ** | **Oil and Gas**     | ** ** |
|------------------------------------------------------|------------|------------------------|------------|---------------------|------------|
| **(Cdn$ millions)**                             | ** ** | **Total  Oil and Gas** | ** ** | **United  Kingdom** | ** ** | **Canada  Other** | ** ** | **Syncrude** | ** ** | **United  States** | ** ** | **Yemen** | ** ** | **Other  Countries** | ** ** |
| **Year Ended  December 31, 2009**               |       |                   |       |                |       |   |   |   |   |   |   |   |   |   |   |
| Net Sales                                            |       | 4,401                  |       | 2,430               |       | 395 |   | 480 |   | 321 |   | 705 |   | 70 |   |
| Production Costs                                     |       | 986                    |       | 253                 |       | 171 |   | 265 |   | 98 |   | 191 |   | 8 |   |
| Exploration Expense                                  |       | 302                    |       | 50                  |       | 84 |   | — |   | 104 |   | — |   | 64 |   |
| Depreciation, Depletion, Amortization and Impairment |       | 1,667                  |       | 875                 |       | 301 |   | 63 |   | 312 |   | 102 |   | 14 |   |
| Other Expenses (Income)                              |       | 265                    |       | 17                  |       | 93 |   | 22 |   | 82 |   | 22 |   | 29 |   |
|                                                 |       | 1,181                  |       | 1,235               |       | (254 | ) | 130 |   | (275 | ) | 390 |   | (45 | ) |
| Income Tax Provision (Recovery)                      |       | 479                    |       | 487                 |       | (64 | ) | 33 |   | (95 | ) | 141 |   | (23 | ) |
| **Results of  Operations**                           | ** ** | **702**                | ** ** | **748**             | ** ** | **(190** | **)** | **97** | ** ** | **(180** | **)** | **249** | ** ** | **(22** | **)** |
| **Year Ended  December 31, 2008**               |       |                   |       |                |       |   |   |   |   |   |   |   |   |   |   |
| Net Sales                                            |       | 6,186                  |       | 3,580               |       | 656 |   | — |   | 665 |   | 1,093 |   | 192 |   |
| Production Costs                                     |       | 715                    |       | 253                 |       | 182 |   | — |   | 94 |   | 176 |   | 10 |   |
| Exploration Expense                                  |       | 402                    |       | 86                  |       | 79 |   | — |   | 109 |   | 5 |   | 123 |   |
| Depreciation, Depletion, Amortization and Impairment |       | 1,859                  |       | 999                 |       | 208 |   | — |   | 475 |   | 160 |   | 17 |   |
| Other Expenses (Income)                              |       | 75                     |       | 6                   |       | 29 |   | — |   | 37 |   | (10 | ) | 13 |   |
|                                                 |       | 3,135                  |       | 2,236               |       | 158 |   | — |   | (50 | ) | 762 |   | 29 |   |
| Income Tax Provision (Recovery)                      |       | 1,412                  |       | 1,126               |       | 45 |   | — |   | (19 | ) | 264 |   | (4 | ) |
| **Results of  Operations**                           | ** ** | **1,723**              | ** ** | **1,110**           | ** ** | **113** | ** ** | **—** | ** ** | **(31** | **)** | **498** | ** ** | **33** | ** ** |
| **Year Ended  December 31, 2007**               | ** ** | ** **             | ** ** | ** **          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net Sales                                            |       | 4,576                  |       | 2,285               |       | 441 |   | — |   | 616 |   | 1,086 |   | 148 |   |
| Production Costs                                     |       | 668                    |       | 212                 |       | 175 |   | — |   | 102 |   | 171 |   | 8 |   |
| Exploration Expense                                  |       | 326                    |       | 69                  |       | 27 |   | — |   | 134 |   | 5 |   | 91 |   |
| Depreciation, Depletion, Amortization and Impairment |       | 1,627                  |       | 599                 |       | 166 |   | — |   | 641 |   | 213 |   | 8 |   |
| Other Expenses (Income)                              |       | 100                    |       | (36                 | )          | 66 |   | — |   | 38 |   | (8 | ) | 40 |   |
|                                                 |       | 1,855                  |       | 1,441               |       | 7 |   | — |   | (299 | ) | 705 |   | 1 |   |
| Income Tax Provision (Recovery)                      |       | 859                    |       | 712                 |       | 2 |   | — |   | (103 | ) | 248 |   | — |   |
| **Results of  Operations**                           | ** ** | **996**                | ** ** | **729**             | ** ** | **5** | ** ** | **—** | ** ** | **(196** | **)** | **457** | ** ** | **1** | ** ** |

 

**E.    STANDARDIZED MEASURE OF DISCOUNTED FUTURENET CASH FLOWS AND CHANGES THEREIN**

 

The following disclosure isbased on estimates of net proved reserves and the period during which they areexpected to be produced. Future cash inflows are computed by applying averageannual prices to our after-royalty share of estimated annual future productionfrom proved oil and gas reserves. As a result of amended FASB oil and gasdisclosure rules, future cash inflows at December 31, 2009 were computedusing the average first-day-of-the-month prices for the year held constant.Future cash inflows at December 31, 2008 and 2007 were computed using theyear-end prices held constant. Future development, production and abandonmentcosts to be incurred in producing and further developing the proved reservesare based on existing cost indicators. Future income taxes are computed byapplying year-end statutory tax rates. These rates reflect allowable deductionsand tax credits, and are applied to the estimated pre-tax future net cashflows.

 

Discounted future net cashflows are calculated using 10% mid-period discount factors. The calculationsassume the continuation of existing economic, operating and contractualconditions. However, such arbitrary assumptions have not proved to be the casein the past. Other assumptions could give rise to substantially different results.

 

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We believe thisinformation does not in any way reflect the current economic value of our oiland gas producing properties or the present value of their estimated futurecash flows as:

 

·      no economic value is attributed to probable and possiblereserves;

·      use of a 10% discount rate is arbitrary; and

·      prices change constantly from the prices used.

 

In 2009, as a result of changes to oil and gas disclosure rules issuedby FASB, Syncrude and field upgrading operations are considered oil and gasactivities. Information for Syncrude and Long Lake upgrading for 2009 has beenprovided. As the change in the rules is to be applied prospectively,information for prior years has not been restated.

 
| ** **                                           | ** ** | ** ** | ** ** | **Canada**   | ** ** | **United**         | ** ** | **United** | ** ** | ** **  | ** ** | **Other**  | ** ** |
|------------------------------------------------------|------------|------------|------------|--------------|------------|--------------------|------------|------------|------------|-------------|------------|------------|------------|
| **(Cdn$ millions)**                             | ** ** | **Total**  | ** ** | **Syncrude** | ** ** | **Long Lake****1** | ** ** | **Other**  | ** ** | **Kingdom** | ** ** | **States** | ** ** | **Yemen** | ** ** | **Countries** | ** ** |
| **December 31,  2009**                          |       |       |       |         |       |               |       |       |       |        |       |       |       |   |   |   |   |
| Future Cash Inflows                                  |       | 59,427     |       | 21,290       |       | 20,294             |       | 2,597      |       | 10,366      |       | 1,708      |       | 829 |   | 2,343 |   |
| Future Production Costs                              |       | 33,180     |       | 14,480       |       | 12,306             |       | 1,702      |       | 3,160       |       | 688        |       | 280 |   | 564 |   |
| Future Development Costs                             |       | 5,384      |       | 1,170        |       | 2,563              |       | 41         |       | 433         |       | 107        |       | 14 |   | 1,056 |   |
| Future Dismantlement and Site Restoration Costs, Net |       | 1,660      |       | 166          |       | 189                |       | 246        |       | 541         |       | 391        |       | 20 |   | 107 |   |
| Future Income Tax                                    |       | 3,727      |       | 249          |       | 238                |       | 28         |       | 3,017       |       | —     |       | 158 |   | 37 |   |
| Future Net Cash Flows                                |       | 15,476     |       | 5,225        |       | 4,998              |       | 580        |       | 3,215       |       | 522        |       | 357 |   | 579 |   |
| 10% Discount Factor                                  |       | 9,183      |       | 4,217        |       | 3,633              |       | 24         |       | 725         |       | 95         |       | 27 |   | 462 |   |
| **Standardized  Measure**                            | ** ** | **6,293**  | ** ** | **1,008**    | ** ** | **1,365**          | ** ** | **556**    | ** ** | **2,490**   | ** ** | **427**    | ** ** | **330** | ** ** | **117** | ** ** |
| ** **                                           | ** ** | ** ** | ** ** | ** **   | ** ** | ** **         | ** ** | ** ** | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **December 31,  2008**                          | ** ** | ** ** | ** ** | ** **   | ** ** | ** **         | ** ** | ** ** | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Future Cash Inflows                                  |       | 25,305     |       | —       |       | 9,276              |       | 2,984      |       | 8,753       |       | 1,809      |       | 904 |   | 1,579 |   |
| Future Production Costs                              |       | 10,847     |       | —       |       | 5,013              |       | 1,606      |       | 2,616       |       | 765        |       | 424 |   | 423 |   |
| Future Development Costs                             |       | 3,008      |       | —       |       | 1,350              |       | 138        |       | 564         |       | 33         |       | 51 |   | 872 |   |
| Future Dismantlement and Site Restoration Costs, Net |       | 1,421      |       | —       |       | 89                 |       | 243        |       | 558         |       | 446        |       | 20 |   | 65 |   |
| Future Income Tax                                    |       | 2,653      |       | —       |       | —             |       | —     |       | 2,467       |       | —     |       | 141 |   | 45 |   |
| Future Net Cash Flows                                |       | 7,376      |       | —       |       | 2,824              |       | 997        |       | 2,548       |       | 565        |       | 268 |   | 174 |   |
| 10% Discount Factor                                  |       | 2,953      |       | —       |       | 1,802              |       | 186        |       | 505         |       | 84         |       | 24 |   | 352 |   |
| **Standardized  Measure**                            | ** ** | **4,423**  | ** ** | **—**   | ** ** | **1,022**          | ** ** | **811**    | ** ** | **2,043**   | ** ** | **481**    | ** ** | **244** | ** ** | **(178** | **)** |
| ** **                                           |       |       |       |         |       |               |       |       |       |        |       |       |       |   |   |   |   |
| **December 31,  2007**                          |       |       |       |         |       |               |       |       |       |        |       |       |       |   |   |   |   |
| Future Cash Inflows                                  |       | 43,888     |       | —       |       | 12,496             |       | 4,869      |       | 17,977      |       | 3,207      |       | 1,952 |   | 3,387 |   |
| Future Production Costs                              |       | 11,988     |       | —       |       | 4,845              |       | 2,384      |       | 3,347       |       | 539        |       | 468 |   | 405 |   |
| Future Development Costs                             |       | 3,229      |       | —       |       | 864                |       | 93         |       | 778         |       | 328        |       | 22 |   | 1,144 |   |
| Future Dismantlement and Site Restoration Costs, Net |       | 1,143      |       | —       |       | 72                 |       | 201        |       | 595         |       | 197        |       | 16 |   | 62 |   |
| Future Income Tax                                    |       | 8,793      |       | —       |       | 856                |       | 279        |       | 6,589       |       | 437        |       | 452 |   | 180 |   |
| Future Net Cash Flows                                |       | 18,735     |       | —       |       | 5,859              |       | 1,912      |       | 6,668       |       | 1,706      |       | 994 |   | 1,596 |   |
| 10% Discount Factor                                  |       | 7,606      |       | —       |       | 3,661              |       | 575        |       | 1,561       |       | 441        |       | 111 |   | 1,257 |   |
| **Standardized  Measure**                            | ** ** | **11,129** | ** ** | **—**   | ** ** | **2,198**          | ** ** | **1,337**  | ** ** | **5,107**   | ** ** | **1,265**  | ** ** | **883** | ** ** | **339** | ** ** |

 

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*1*                 Standardized measureamounts in 2008 and 2007 reflect bitumen production activities only; 2009amounts reflect upgrading activities to produce synthetic barrels.

 

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**Changes in the Standardized Measure of Discounted Future Net Cash Flows**

 

The following are the principal sources of change in thestandardized measure of discounted future net cash flows:

 
| **(Cdn$ millions)**                                                                  | ** ** | **2009**  | ** ** | **2008**  | ** ** | **2007**   | ** ** |
|-------------------------------------------------------------------------------------------|------------|-----------|------------|-----------|------------|------------|------------|
| Beginning of Year                                                                         |       | 4,423     |       | 11,129    |       | 8,373      |       |
| Sales and Transfers of Oil and Gas Produced, Net of Production Costs                      |       | (2,306    | )          | (4,387    | )          | (3,010     | )          |
| Net Changes in Prices and Production Costs Related to Future  Production                  |       | (306      | )          | (9,756    | )          | 3,385      |       |
| Extensions, Discoveries and Improved Recovery, Less Related Costs                         |       | 1,091     |       | 376       |       | 758        |       |
| Changes in Estimated Future Development and Dismantlement Costs                           |       | 561       |       | (676      | )          | (443       | )          |
| Previous Estimated Future Development and Dismantlement Costs  Incurred During the Period |       | 884       |       | 1,343     |       | 1,102      |       |
| Revisions of Previous Quantity Estimates                                                  |       | 607       |       | 615       |       | 2,189      |       |
| Accretion of Discount                                                                     |       | 655       |       | 1,730     |       | 1,191      |       |
| Purchases of Reserves in Place                                                            |       | 330       |       | —    |       | 272        |       |
| Sales of Reserves in Place                                                                |       | (2        | )          | —    |       | (49        | )          |
| Net Change in Income Taxes                                                                |       | (596      | )          | 4,049     |       | (2,639     | )          |
| ** **                                                                                | ** ** | **5,341** | ** ** | **4,423** | ** ** | **11,129** | ** ** |
| Inclusion of Syncrude as Oil and Gas Activity                                             |       | 1,008     |       | —    |       | —     |       |
| Conversion of Long Lake Bitumen to Synthetic Reserves                                     |       | (56       | )          | —    |       | —     |       |
| **End of Year**                                                                           | ** ** | **6,293** | ** ** | **4,423** | ** ** | **11,129** | ** ** |

 

**ITEM 9.**

 

**Changes in and Disagreements with Accountants onAccounting and Financial Disclosure**

 

There were no disagreements with accountants on accountingand financial disclosure.

 

**ITEM 9A.**

** **

**Controls and Procedures**

 

**EVALUATION OFDISCLOSURE CONTROLS AND PROCEDURES**

 

The Company’s Chief Executive Officer and Chief FinancialOfficer have designed disclosure controls and procedures (as defined in Rules 13(a)-15(e) and15(d)-15(e) under the Securities Exchange Act of 1934), or caused suchdisclosure controls and procedures to be designed under their supervision, toensure that material information relating to the Company is made known to them,particularly during the period in which this report is prepared. They haveevaluated the effectiveness of such disclosure controls and procedures as ofthe end of the period covered by this report (Evaluation Date). Based upon thatevaluation, the Chief Executive Officer and Chief Financial Officer concludedthat, as of the Evaluation Date, the Company’s disclosure controls andprocedures are effective (i) to ensure that information required to bedisclosed by us in reports that the Company files or submits under the ExchangeAct is recorded, processed, summarized and reported within the time periodsspecified in the Securities and Exchange Commission rules and forms; and (ii) toensure that information required to be disclosed in the reports that theCompany files or submits under the Exchange Act is accumulated and communicatedto our management, including the Company’s Chief Executive Officer and ChiefFinancial Officer, to allow timely decisions regarding required disclosure.

 

The Company’s management, including its Chief ExecutiveOfficer and Chief Financial Officer, does not expect that the Company’sdisclosure controls and procedures or internal controls will prevent allpossible error and fraud. The Company’s disclosure controls and procedures are,however, designed to provide reasonable assurance of achieving theirobjectives, and the Company’s Chief Executive Officer and Chief FinancialOfficer have concluded that the Company’s financial controls and procedures areeffective at that reasonable assurance level.

 

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**MANAGEMENT’SREPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING**

 

Our management is responsible for establishing andmaintaining adequate internal control over financial reporting (as defined inExchange Act Rules 13(a)-15(f)). Under the supervision and with theparticipation of our management, including our principal executive officer(CEO) and principal financial officer (CFO), we conducted an evaluation of theeffectiveness of our internal control over financial reporting based on theInternal Control-Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission. Based on our evaluation, we concludedthat our internal control over financial reporting is effective as of December 31,2009. We have documented this assessment and made this assessment available toour independent registered Chartered Accountants. We recognize that allinternal control systems, no matter how well designed, have inherentlimitations. Therefore, even those systems determined to be effective canprovide only reasonable assurance with respect to financial statementpreparation and presentation.

 

Deloitte & Touche LLP audited our ConsolidatedFinancial Statements as stated in their report which is on page 159 ofthis Form 10-K and has issued an attestation report on our internal controlover financial reporting.

 

**CHANGES ININTERNAL CONTROLS**

 

We have continually had in place systems of internal controlsover financial reporting. There have not been any changes in the Company’sinternal control over financial reporting during the last quarter that havematerially affected, or are reasonably likely to materially affect, ourinternal control over financial reporting. As well, no material weaknessesrequiring corrective action were identified in the conduct of our evaluation ofinternal control over financial reporting. As a result, no such correctiveactions were taken.

 

**REPORT OFINDEPENDENT REGISTERED CHARTERED ACCOUNTANTS**

 

**To the Board of Directors and Shareholders of Nexen Inc.**

 

We have audited the internal control over financial reportingof Nexen Inc. and subsidiaries (the “Company”) as of December 31, 2009,based on criteria established in Internal Control—Integrated Framework issuedby the Committee of Sponsoring Organizations of the Treadway Commission. TheCompany’s management is responsible for maintaining effective internal controlover financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting, included in the accompanyingManagement’s Report on Internal Control over Financial Reporting. Ourresponsibility is to express an opinion on the Company’s internal control overfinancial reporting based on our audit.

 

We conducted our audit in accordance with the standards ofthe Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether effective internal control over financial reporting was maintained inall material respects. Our audit included obtaining an understanding ofinternal control over financial reporting, assessing the risk that a materialweakness exists, testing and evaluating the design and operating effectivenessof internal 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.

 

A company’s internal control over financial reporting is aprocess designed by, or under the supervision of, the company’s principalexecutive and principal financial officers, or persons performing similarfunctions, and effected by the Company’s Board of Directors, management, andother personnel to provide reasonable assurance regarding the reliability offinancial reporting and the preparation of financial statements for externalpurposes in accordance

 

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with generally accepted accounting principles. A company’sinternal control over financial reporting includes those policies andprocedures that (1) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (2) provide reasonableassurance that transactions are recorded as necessary to permit preparation offinancial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being madeonly in accordance with authorizations of management and directors of thecompany; and (3) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

 

Because of the inherent limitations of internal control overfinancial reporting, including the possibility of collusion or impropermanagement override of controls, material misstatements due to error or fraudmay not be prevented or detected on a timely basis. Also, projections of anyevaluation of the effectiveness of the internal control over financialreporting to future periods are subject to the risk that the controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

 

In our opinion, the Company maintained, in all materialrespects, effective internal control over financial reporting as of December 31,2009, based on the criteria established in Internal Control—IntegratedFramework issued by the Committee of Sponsoring Organizations of the TreadwayCommission.

 

We have also audited, in accordance with Canadian generallyaccepted auditing standards and the standards of the Public Company AccountingOversight Board (United States), the Consolidated Financial Statements of theCompany as of and for the year ended December 31, 2009, and our reportdated February 17, 2010, expressed an unqualified opinion on thosefinancial statements and includes a separate report titled Comments byIndependent Registered Chartered Accountants on Canada—United States of AmericaReporting Difference referring to changes in accounting principles that have amaterial effect on the comparability of the Company’s Consolidated FinancialStatements.

 

(signed) “Deloitte &Touche LLP”

Independent RegisteredChartered Accountants

Calgary, Canada

February 17, 2010

 

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| **PART III**                                                                                         |   |
|-----------------------------------------------------------------------------------------------------------|--------|
|                                                                                                      |   |
| Items 10 and 11:  Directors, Executive Officers and Corporate Governance, and Executive  Compensation     |   |
| Directors                                                                                                 | 161    |
| Independence and Board Committees                                                                         | 165    |
| Meeting Attendance                                                                                        | 166    |
| Director  Compensation                                                                                    | 167    |
| Compensation Committee Report                                                                             | 170    |
| Compensation Committee Interlocks and Insider  Participation                                              | 172    |
| Compensation Discussion and Analysis                                                                      | 172    |
| Compensation  Philosophy                                                                                  | 172    |
| Compensation  Objectives                                                                                  | 174    |
| Compensation Approval Process                                                                             | 175    |
| Base Salaries                                                                                             | 175    |
| Annual  Cash Incentives                                                                                   | 175    |
| Share  Performance Graph                                                                                  | 177    |
| Share  Ownership Guidelines                                                                               | 178    |
| Long-Term  Incentives                                                                                     | 179    |
| Benefit and Pension  Plans                                                                                | 181    |
| Executive Officers                                                                                        | 184    |
| CEO Compensation and 2009 Objectives and Achievements                                                     | 186    |
| CEO Look-Back                                                                                             | 187    |
| Incentive  Plan Awards                                                                                    | 188    |
| Equity Ownership and Changes in 2009                                                                      | 190    |
| Pension  Plan Benefits                                                                                    | 190    |
| All  Other Compensation                                                                                   | 192    |
| Termination and Change of Control Benefits                                                                | 193    |
| Corporate  Governance                                                                                     | 195    |
| Governance Committee Report                                                                               | 196    |
| Audit  Committee Report                                                                                   | 199    |
|                                                                                                      |   |
| Item 12:  Security Ownership of Certain Beneficial Owners and Management and Related  Stockholder Matters | 200    |
|                                                                                                      |   |
| Item 13:  Certain Relationships and Related Transactions, and Director Independence                       | 201    |
|                                                                                                      |   |
| Item 14:  Principal Accounting Fees and Services                                                          | 201    |
|                                                                                                      |   |
| Part IV                                                                                              |   |
|                                                                                                      |   |
| Item 15: Exhibits, Financial Statement Schedules                                                          | 204    |

 

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Table of Contents

 

**PART III**

 

**ITEMS 10 AND 11.**

 

**Directors, Executive Officers and CorporateGovernance, and Executive Compensation**

 

**DIRECTORS**

 

According to our Articles, Nexen must have between three and15 directors. On February 11, 2009, the board set the size at 12 directorseffective April 28, 2009.

 

Our By-Laws provide that directors will be elected at theannual general meeting (AGM) each year and will hold office until theirsuccessors are elected.

 
| **Name**(Age)                           | ** ** | **Principal  Occupation**                                                                                                                                                                                                                                                                                                                      | ** ** | **Other  Directorships**                                                                                                | ** ** | **Nexen  Director  Since** |   |
|-----------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------|------------|----------------------------|--------|
| William  B. Berry1, 3 (57)         |       | Retired oil executive.   Formerly: Executive Vice President of ConocoPhillips.                                                                                                                                                                                                                                                                 |       | Willbros Group, Inc.                                                                                               |       | 2008                       |   |
| Robert  G. Bertram1 (65)           |       | Retired pension investment  executive.   Formerly: Executive Vice President of Ontario Teachers Pension Plan Board.                                                                                                                                                                                                                            |       | Mulvihill Capital Management  Funds 2   The Cadillac Fairview Corporation Maple Leaf Sports and Entertainment Ltd. |       | 2009                       |   |
| Dennis G. Flanagan (70)                 |       | Retired oil executive.                                                                                                                                                                                                                                                                                                                         |       | Canexus Income Fund (Chair)                                                                                             |       | 2000                       |   |
| S. Barry Jackson1** **(57)         |       | Retired oil executive.   Formerly: Chair of Resolute Energy Inc. and Chair of Deer Creek Energy  Limited.                                                                                                                                                                                                                                      |       | TransCanada Corporation (Chair)  TransCanada PipeLines Limited (Chair) WestJet Airlines Ltd.                       |       | 2001                       |   |
| Kevin J. Jenkins1, 3 (53)          |       | President and Chief Executive  Officer of World Vision International.   Formerly: Managing Director of TriWest Capital Partners.                                                                                                                                                                                                               |       | —                                                                                                                  |       | 1996                       |   |
| A. Anne McLellan, P.C.1 (59)            |       | Counsel with Bennett Jones  LLP, Barristers and Solicitors, and Distinguished Scholar in Residence at the  University of Alberta in the Institute for United States Policy Studies.   Formerly: Member of Parliament for Edmonton Centre, Deputy Prime Minister,  Minister of Public Safety and Emergency Preparedness and Minister of Health. |       | Agrium Inc.  Cameco Corporation                                                                                         |       | 2006                       |   |
| Eric P. Newell,O.C.1 (65)          |       | Retired oil executive.                                                                                                                                                                                                                                                                                                                         |       | —                                                                                                                  |       | 2004                       |   |
| Thomas C. O’Neill1, 3 (64)    |       | Retired chartered accountant.                                                                                                                                                                                                                                                                                                                  |       | Adecco S.A.  BCE Inc.  Loblaw Companies Limited  The Bank of Nova Scotia                                                |       | 2002                       |   |
| Marvin F. Romanow (54)                  |       | President and CEO of Nexen. Formerly:  Executive Vice President and CFO of Nexen.                                                                                                                                                                                                                                                              |       | Canexus Income Fund                                                                                                     |       | 2009                       |   |
| Francis M. Saville, Q.C.1** **(71) |       | Chair of Nexen.   Formerly: Counsel with Fraser Milner Casgrain LLP, Barristers and Solicitors.                                                                                                                                                                                                                                                |       | —                                                                                                                  |       | 1994                       |   |
| John M. Willson1** **(70)          |       | Retired mining executive.                                                                                                                                                                                                                                                                                                                      |       | Finning International Inc.                                                                                              |       | 1996                       |   |
| Victor J. Zaleschuk4** **(66)      |       | Retired oil executive.                                                                                                                                                                                                                                                                                                                         |       | Agrium Inc.  Cameco Corporation (Chair)                                                                                 |       | 1997                       |   |

 

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*1*                 All members of the Audit andConduct Review (Audit), Corporate Governance and Nominating (Governance), andCompensation and Human Resources (Compensation) Committees are independent. Allmembers of the Audit Committee are independent under additional regulations foraudit committee members.

*2*                 An investment management fundorganization managing a series of closed end funds listed on the Toronto StockExchange. Mr. Bertram is an audit committee member for each of thesefunds.

*3*                 Financial Experts on Nexen’sAudit Committee.

*4*                 Mr. Zaleschuk wasPresident and CEO of Nexen from 1997 to 2001.

 

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**PREVIOUS DIRECTORSHIPS**

 

The information in the following table represents previousdirectorships held by our directors over the last five years at public andregistered investment companies.

 
| **Name**     | ** ** | **Company**                                                           |
|--------------|------------|-----------------------------------------------------------------------|
| Flanagan     |       | NAL Oil and Gas Trust                                                 |
| Jackson      |       | Cordero Energy Inc.,  Resolute Energy Inc., Deer Creek Energy Limited |
| Newell       |       | Canfor Corporation                                                    |
| O’Neill |       | Dofasco Inc., Ontario  Teachers’ Pension Plan Board              |
| Saville      |       | Mullen Transport Inc.                                                 |
| Willson      |       | Pan American Silver Corp.,  Harry Winston Diamond Corp.               |

 

**EXPERIENCE AND QUALIFICATIONS**

 

The experience and qualifications of our board memberscontribute to our success. The wealth of knowledge and depth of understandingof their role and our industry has a profound impact on the way we conduct business.The following chart illustrates the expertise that our directors have indicatedthey possess in each area.

 
| ** **   | ** ** | **Managing/  Leading Growth** | ** ** | **International** | ** ** | **CEO/Senior  Officer** | ** ** | **Exploration** | ** ** | **Compensation** | ** ** | **Oil and  Gas** | ** ** | **Governance/  Board** | ** ** | **Financial  Acumen** | ** ** | **Health, Safety,  Environment  and Social  Responsibility** | ** ** | **Diversity** | ** ** | **Marketing** | ** ** |
|--------------|------------|-------------------------------|------------|-------------------|------------|-------------------------|------------|-----------------|------------|------------------|------------|------------------|------------|------------------------|------------|-----------------------|------------|--------------------------------------------------------------|------------|---------------|------------|---------------|------------|
| Berry        |       | √                       |       | √           |       | √                 |       | √         |       | √          |       | √          |       | √                |       | √               |       | √                                                      |       | √       |       |          |       |
| Bertram      |       | √                       |       |              |       |                    |       |            |       | √          |       |             |       | √                |       | √               |       |                                                         |       | √       |       |          |       |
| Flanagan     |       | √                       |       | √           |       | √                 |       | √         |       | √          |       | √          |       | √                |       | √               |       | √                                                      |       | √       |       |          |       |
| Jackson      |       | √                       |       |              |       | √                 |       | √         |       | √          |       | √          |       | √                |       | √               |       | √                                                      |       | √       |       | √       |       |
| Jenkins      |       | √                       |       | √           |       | √                 |       |            |       | √          |       |             |       | √                |       | √               |       | √                                                      |       |          |       |          |       |
| McLellan     |       | √                       |       | √           |       | √                 |       |            |       |             |       |             |       | √                |       |                  |       | √                                                      |       | √       |       |          |       |
| Newell       |       | √                       |       | √           |       | √                 |       |            |       | √          |       | √          |       | √                |       | √               |       | √                                                      |       | √       |       |          |       |
| O’Neill |       | √                       |       | √           |       | √                 |       |            |       | √          |       | √          |       | √                |       | √               |       | √                                                      |       | √       |       | √       |       |
| Romanow      |       | √                       |       | √           |       | √                 |       | √         |       | √          |       | √          |       | √                |       | √               |       | √                                                      |       | √       |       | √       |       |
| Saville      |       | √                       |       | √           |       | √                 |       |            |       | √          |       | √          |       | √                |       |                  |       | √                                                      |       | √       |       |          |       |
| Willson      |       | √                       |       | √           |       | √                 |       | √         |       | √          |       |             |       | √                |       |                  |       | √                                                      |       | √       |       |          |       |
| Zaleschuk    |       | √                       |       | √           |       | √                 |       | √         |       | √          |       | √          |       | √                |       | √               |       | √                                                      |       | √       |       | √       |       |
| **Total**    | ** ** | **12**                        | ** ** | **10**            | ** ** | **11**                  | ** ** | **6**           | ** ** | **11**           | ** ** | **8**            | ** ** | **12**                 | ** ** | **9**                 | ** ** | **11**                                                       | ** ** | **11**        | ** ** | **4**         | ** ** |

 

Mr. Berry brings over 35 years of oil and gasexploration experience to his role, including expertise in internationalaffairs from his work overseas and in his capacity as an executive of a globalenergy company. Mr. Berry has Bachelor and Masters of Science degrees inPetroleum Engineering. Mr. Berry was responsible for understanding thefinancial reporting of exploration and production and finance managers reporteddirectly to him on a functional basis. This executive level experience and hisstanding committee membership on the Compensation Committee at WillbrosGroup, Inc. give him an extensive background in compensation matters.

 

Mr. Bertram has a proven track record for managing andleading growth as an executive for a large pension fund. He has a Masters ofBusiness Administration, a chartered financial analyst designation and isconsidered a financial expert with almost 40 years experience in financialroles. As Chair of the Strategic Committee of a leading independent governanceanalysis and proxy voting firm and a recipient of the ICD.D designation,Mr. Bertram brings considerable knowledge to his role in the areas ofgovernance and board. Mr. Bertram has been involved at the board level ofnon-public companies and not-for-profit organizations for several years. Hisstanding committee service on these boards and as a 

 

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member of our Compensation and Human Resources Committee,provide him with substantial experience on compensation matters.

 

Mr. Flanagan has been a member of the board for the past10 years. He brings over 40 years of oil and gas and exploration experience,including several years in senior executive roles, including Chief FinancialOfficer, Chief Executive Officer and Executive Chair. During his career he wasinvolved in all phases of several overseas projects. Mr. Flanagan’seducation and experience in the areas of accounting and finance qualify him asa financial expert. He has served on several standing committees giving himextensive experience in the areas of compensation, governance, board andhealth, safety, environment and social responsibility issues. Mr. Flanaganbrings a diverse background through his international work and varied skillsand experience at the board level for both for-profit and not-for-profitsectors.

 

Mr. Jackson has been a member of the board for the pastnine years. He brings over 35 years of oil and gas experience to his role andheld several senior executive and board positions, including President andChair of the Board. In this capacity, he was exposed to a broad range ofbusiness issues and developed expertise in marketing, governance and boardmatters. He has a Bachelor of Science degree in Engineering. Mr. Jackson’sboard and standing committee memberships at Nexen and other public companiesgive him expertise in the areas of compensation, governance and board.Mr. Jackson has been a member of our Compensation Committee and AuditCommittee since 2001.

 

Mr. Jenkins has served as a board member since 1996. Hebrings a wealth of knowledge and practical experience to his role on the boardand standing committees. He received his Bachelor of Laws from the Universityof Alberta and is a graduate of the Harvard Graduate School of BusinessAdministration. Mr. Jenkins held several senior executive positions inlarge corporations over the past 25 years and is currently President and ChiefExecutive Officer of World Vision International. He served as a member of theFinance and Audit Committees for the past 10 years and 11 years, respectively,and has chaired both committees during his tenure. Mr. Jenkins’ educationand experience qualify him as a financial expert. He has been an active memberof the board and standing committees providing him with extensive experience inthe areas of compensation, governance, board and health, safety, environmentand social responsibility.

 

Ms. McLellan brings diverse, senior executive experienceto her role through her tenures as a law school professor and associate dean,Deputy Prime Minister of Canada, Attorney General of Canada, Member ofParliament, counsel for a leading Canadian law firm and as a board member ofpublic companies. Ms. McLellan has Bachelor of Arts and Bachelor andMasters of Laws degrees. Her board and standing committee memberships at Nexenand other public companies give her a solid background in the areas ofgovernance, board and safety, health and environment.

 

Dr. Newell is a proven corporate and community leader.He holds a Masters of Science in Management Studies, is an Officer of the Orderof Canada, a member of the Alberta Order of Excellence and has HonoraryDoctorates degrees from three Canadian universities and one from the NorthernAlberta Institute of Technology. He has also been honoured by many otherorganizations whose interests lie in business leadership, education, youthdevelopment and public policy. Dr. Newell brings several years of oil andgas experience to his role including 14 years as Chief Executive Officer of theworld’s largest producer of crude oil from oil sands. Under his leadership, thecompany became an increasingly significant source of energy supply for theentire nation, and a model of a reliably operated, environmentally efficient,socially responsible corporation. As President of the Alberta Chamber ofResources in the mid 1990s, Dr. Newell was instrumental in developing acomprehensive new energy vision for Canada, which led to the large-scaleexpansion now underway in the oil sands industry. Dr. Newell’s storiedcareer has given him extensive experience in the areas of compensation andfinancial acumen.

 

Mr. O’Neill has a proven track record for managing andleading growth as a senior executive and Chair for a large global accountingfirm. Mr. O’Neill has a Bachelor of Commerce degree, is a charteredaccountant, a Fellow of the Institute of Chartered Accountants of Ontario andis considered a financial expert with over 40 years experience in financialroles. He worked in Brussels to broaden his international experience andserviced numerous 

 

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multinational companies. As a member of the board andstanding committee memberships at Nexen and other public companies, he brings awealth of knowledge to his role in the areas of governance, board,compensation, oil and gas, and marketing.

 

Mr. Romanow brings a wealth of knowledge and practicalexperience to his role on the board. He has a Bachelor of Engineering degree,with great distinction, and a Masters of Business Administration. He heldseveral senior executive positions and leadership roles in corporate finance,planning, business development, marketing, exploration and development, andreservoir engineering, and is currently the President and Chief ExecutiveOfficer of Nexen. Mr. Romanow has a proven track record for managing andleading growth and was the recipient of Canada’s “CFO of the Year” for 2007 and“Energy Executive of the Year” for 2006. Mr. Romanow’s service on twopublic boards and one private board and his varied career has given him a solidbackground in the areas of governance, board, compensation, and health, safety,environment, social responsibility and enabled him to bring a broad, diverseperspective.

 

Mr. Saville has served as a board member since 1994. Histenure as senior partner and counsel for a large national law firm, leadershiproles at the law firm, and over 40 years of energy and environmental regulatorylaw experience, gives him considerable knowledge and leadership for his role onthe board and its standing committees. He has Bachelor of Arts and Bachelor ofLaws degrees and is a recipient of the ICD.D designation. Mr. Saville is arecognized leader in corporate governance, and a frequent speaker and author oncorporate governance, international and Canadian resources law and on integrityin law, business and government. His past board and standing committee membershipon the Governance and Compensation Committee of a public company coupled withhis participation on Nexen’s Corporate Governance and Nominating Committee andCompensation and Human Resources Committee for the past 11 years and 7 years,respectively, give him a solid background in the areas of governance, board andcompensation. Mr. Saville was Chair of the Governance Committee for fouryears during this time and has also been a member of the Health, Safety,Environment and Social Responsibility Committee for the past 15 years.

 

Mr. Willson has served as a board member for the past 13years and brings a wealth of knowledge and practical experience to his role onthe board and standing committees. He was educated in Portugal and Englandreceiving a Masters degree in Mining Engineering. Mr. Willson held severalsenior executive positions in the mining business over the past 40 years andhis work has taken him to Ghana, the United States, Canada and Greenland. Heserved as a member of the Finance Committee for eight years and has served onthe Audit Committee for the past four years, giving him a sound understandingof accounting and financial matters. His board and committee service over theyears at Nexen and other public companies, including 10 years on ourCompensation Committee—seven years as the Chair, give him a solid background inthe areas of governance, board and compensation. Mr. Willson’s career as amining executive and his participation as a member of the Health, Safety,Environment and Social Responsibility Committee for 10 years has provided himwith extensive experience in these areas. He is also the Chair of the ReservesCommittee of which he has been a member for the past 10 years.

 

Mr. Zaleschuk brings over 30 years of oil and gas andfinancial experience to his role. He has a Bachelor of Commerce degree, is achartered accountant and held several senior executive positions at globalenergy companies, including his position as President and Chief ExecutiveOfficer of Nexen from 1997 to 2001. These leadership roles provide him withsignificant knowledge in the areas of finance, exploration and marketing.Mr. Zaleschuk is Chair of the Audit Committee for a public company, Chairof Nexen’s Finance Committee and is considered a financial expert. His boardand standing committee memberships at Nexen and other public companies give hima solid background in the areas of governance, board, compensation and health,safety, environment, and social responsibility.

 

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**INDEPENDENCEAND BOARD COMMITTEES**

 

The board affirmed director independence under ourcategorical standards for director independence (categorical standards), whichwere adopted in 2003 and most recently amended on February 17, 2010.Our categorical standards meet or exceed the requirements in SEC rules andregulations, the Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley), the NYSE rules, *NationalPolicy 58-201*—*CorporateGovernance Guidelines*,*Multilateral Instrument 52-110*—*AuditCommittees*, and applicable provisions of *NationalInstrument 51-101*—*Standards ofDisclosure for Oil and Gas Activities*.

 

Mr. Romanow is not independent as he is Nexen’sPresident and CEO.

 

Ms. McLellan has been counsel with Bennett Jones LLP(BJ), Barristers and Solicitors, Edmonton, Alberta since June 27, 2006. BJprovided legal services to us in each of the last five years. Legal fees paidto BJ represent less than 6% of all legal fees paid by Nexen in 2009.Ms. McLellan does not solicit or participate in those services, does notreceive any fees we pay to BJ, nor is she a partner or an employee of the firm.She is independent under our categorical standards.

 

Mr. Saville was counsel with Fraser Milner Casgrain LLP(FMC), Barristers and Solicitors, Calgary, Alberta fromFebruary 1, 2004 to January 31, 2010. 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.

 

We have not had an executive committee of the board sinceJuly 11, 2000.

 
| ** **                                    | ** ** | **Committees (Number of Members)** | ** ** |
|-----------------------------------------------|------------|------------------------------------|------------|
| ** **                                    | ** ** | **Audit****1, 2****(6)**           | ** ** | **Compensation****1****(7)** | ** ** | **Governance****1****(8)** | ** ** | **Finance****1****(6)** | ** ** | **HSE & SR****1****(6)** | ** ** | **Reserves****1****(7)** | ** ** |
| **Management  Director—Not Independent** |       |                               |       |   |   |   |   |   |   |   |   |   |   |
| Marvin F. Romanow                             |       |                               |       |   |   |   |   |   |   |   |   |   |   |
| **Independent  Outside Directors**            |       |                               |       |   |   |   |   |   |   |   |   |   |   |
| William Berry3                                |       | √                            |       |   |   |   |   |   |   | √ |   | √ |   |
| Robert G. Bertram                             |       |                               |       | √ |   | √ |   | √ |   |   |   |   |   |
| Dennis G. Flanagan4                           |       |                               |       |   |   |   |   | √ |   | √ |   | √ |   |
| S. Barry Jackson                              |       | √                            |       | √ |   | Chair |   |   |   |   |   | √ |   |
| Kevin J. Jenkins3                             |       | √                            |       | Chair |   | √ |   | √ |   |   |   |   |   |
| A. Anne McLellan, P.C.                        |       |                               |       | √ |   | √ |   | √ |   | √ |   |   |   |
| Eric P. Newell, O.C.                          |       | √                            |       |   |   | √ |   |   |   | Chair |   | √ |   |
| Thomas C. O’Neill3, 5                    |       | Chair                              |       | √ |   | √ |   |   |   |   |   | √ |   |
| Francis M. Saville,  Q.C.                     |       |                               |       | √ |   | √ |   | √ |   | √ |   |   |   |
| John M. Willson                               |       | √                            |       | √ |   | √ |   |   |   |   |   | Chair |   |
| Victor J. Zaleschuk                           |       |                               |       |   |   |   |   | Chair |   | √ |   | √ |   |

 

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*1*                 All members are independent.All Audit Committee members are independent under additional regulatoryrequirements applicable to them.

*2*                 Experience of the members ofthe Audit Committee that indicates an understanding of the accountingprinciples we use to prepare our financial statements is shown on page 166.

*3*                 Audit committee financialexpert under US regulatory requirements.

*4*                 Last year, Mr. Flanaganwas not regarded as independent because of a family member who was an officerof a company with which Nexen did business beyond the prescribed independencelimits. Effective December 15, 2009, this company was acquired andthe family member ceased to be an officer. Accordingly, Mr. Flanagan hasbeen independent since that date.

*5*                 The board determined thatMr. O’Neill’s service on the audit committees of four other public companiesand one not-for-profit organization does not impair his ability to serve asChair of Nexen’s Audit Committee. The board considered that Mr. O’Neillhas over 30 years of experience as a chartered accountant and, since retiringas Chair of PwC Consulting in 2002, his only business commitments are to theboards and committees on which he serves.

 

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**MEETING ATTENDANCE**

 

Directors are expected to attend the AGM. All directors wereat the 2009 AGM.

 

Directors strive for attendance at all board and committeemeetings and are expected to attend at least 75% of meetings held in the year.In 2009, the board and committee attendance rate averaged 98.5%. The followingtable shows the number of committee meetings held by each committee during 2009and the number of sessions held without management.

 
| ** **                  | ** ** | **Sessions Without Management in 2009/Meetings Held** | ** ** |
|-----------------------------|------------|-------------------------------------------------------|------------|
| **Board/Committee**         | ** ** | **Regular**                                           | ** ** | **Special** | ** ** | **Overall** | ** ** |
| Board                       |       | 5/5                                                   |       | — |   | 5/5 |   |
| Audit Committee             |       | 5/5                                                   |       | — |   | 5/5 |   |
| Compensation Committee      |       | 5/5                                                   |       | — |   | 5/5 |   |
| Governance Committee        |       | 5/5                                                   |       | — |   | 5/5 |   |
| Finance Committee           |       | 5/5                                                   |       | — |   | 5/5 |   |
| HSE & SR Committee |       | 5/5                                                   |       | — |   | 5/5 |   |
| Reserves Committee          |       | 3/3                                                   |       | 1/1 |   | 4/4 |   |
| **Total**                   | ** ** | **33/33**                                             | ** ** | **1/1** | ** ** | **34/34** | ** ** |

 

**AUDIT COMMITTEE FINANCIAL EXPERT EXPERIENCE**

 
| **Name**   | ** ** | **Berry**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            | ** ** | **Jenkins**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    | ** ** | **O’Neill**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Experience |       | William Berry, 57, is a  retired oil and gas executive. He was formerly Executive Vice President of  ConocoPhillips from 2003 to 2008. He also held other senior executive  positions with Phillips Petroleum Co., including as Senior Vice President,  Exploration and Production. His career in the oil and gas industry began in  1976 and includes experience working in Africa, the North Sea, Asia, Russia,  the Caspian Sea and North America.

 

Mr. Berry has Bachelor  and Masters of Science degrees in Petroleum Engineering from Mississippi  State University. He was responsible for understanding the financial  reporting of exploration and production at ConocoPhillips and had finance  managers report directly to him on a functional basis. He held various  management roles, including as Manager, Corporate Planning and Budgeting.

 

He is a director of Willbros  Group, Inc. Mr. Berry serves on the Dean’s Advisory Council at  Mississippi State University. He also serves on the Advisory Board   of Teach for America in Houston. |       | Kevin Jenkins, 53, is  President and Chief Executive Officer of World Vision International. He was  formerly a Managing Director of TriWest Capital Partners, an independent  private equity firm, from 2003 to 2009. 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  Bachelor’s Degree in Law from the University of Alberta and a Master 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. |       | Tom O’Neill, 64, 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 lead  partner for numerous multinational companies, 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 Chair of BCE Inc., the  Vice Chair of Adecco S.A. and a director of Loblaw Companies Limited and The  Bank of Nova Scotia. 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. |

 

**DIRECTOR AND OFFICER LIABILITY INSURANCE**

 

Nexen indemnifies directors and officers to the full extentpermitted by law. We maintain a director and officer liability insurancepolicy. The policy covers costs to defend and settle claims against Nexen’sdirectors and officers and certain named officers to an annual limit of US$150million. It includes a US$12.5 million deductible for an indemnifiableoccurrence and no deductible for a non-indemnifiable occurrence. The cost ofcoverage for 2009 was approximately US$951,000. Directors and officers do notpay premiums and no indemnity claims were made or paid in 2009.

 

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**DIRECTOR AND OFFICER FIDUCIARY INSURANCE**

 

Nexen maintains a fiduciary liability insurance policy. Itcovers costs to defend and settle claims against Nexen, our directors, officersand employees for breach of fiduciary duty related to company-sponsored plans,such as pension and savings plans. The policy has an annual limit of US$25million with a US$2.5 million deductible for an indemnifiable occurrence and nodeductible for a non-indemnifiable occurrence. The cost of coverage for 2009was approximately US$27,600. Directors, officers and employees do not paypremiums and no claims were made or paid in 2009.

 

**LOANS TO DIRECTORS**

 

As set out in the corporate governance policy, we do not makeloans to our directors. There are no loans outstanding from Nexen to ourdirectors.

 

**DIRECTORCOMPENSATION**

 

Nexen provides all non-executive directors with acomprehensive compensation package of annual cash retainers, meeting fees andequity-based awards in the form of deferred share units (DSUs). This packageprovides competitive remuneration for the increasing responsibilities, timecommitments and accountability of board members. The CEO is the only managementdirector and he receives no director compensation. Management, the CompensationCommittee and the board regularly review the compensation for competitivenessagainst a peer group of major Canadian-based oil and gas and integratedpipeline companies. This director peer group is a subset of our executive peergroup, which focuses on the independent Canadian companies. See pages 173to 174 for details. Our directors compensation philosophy is consistent withour philosophy for employees, and targets compensation between the 50th and75th percentile to attract, engage and retain qualified talent to our board.

 

Non-executive directors may choose certain benefits coverageat Nexen’s expense, including basic life insurance, extended health care,dental, business travel accident insurance and reimbursement of provincialhealth care premiums (in certain jurisdictions). Mr. Zaleschuk, a formerCEO of Nexen, is a retiree in Nexen’s pension plan. His pension benefit is forprevious employee service.

 

Eligible directors may elect to receive all or part of theirfees in DSUs. See page 169 for more information on DSUs.

 

**DIRECTOR COMPENSATION TABLE**

 
| **Name**     | ** ** | **Total  Fees Earned****1****($)** | ** ** | **DSU  Awards****2****($)** | ** ** | **All Other  Compensation****3****($)** | ** ** | **Total  Compensation  ($)** | ** ** |
|--------------|------------|------------------------------------|------------|-----------------------------|------------|-----------------------------------------|------------|------------------------------|------------|
| Berry        |       | 85,900                             |       | 124,750                     |       | 882                                     |       | 211,532                      |       |
| Bertram      |       | 85,900                             |       | 124,750                     |       | 859                                     |       | 211,509                      |       |
| Flanagan4    |       | 102,800                            |       | 124,750                     |       | 145,409                                 |       | 372,959                      |       |
| Hentschel5   |       | 38,167                             |       | —                      |       | 2,874                                   |       | 41,041                       |       |
| Jackson      |       | 119,300                            |       | 124,750                     |       | 9,906                                   |       | 253,956                      |       |
| Jenkins      |       | 127,700                            |       | 124,750                     |       | 9,827                                   |       | 262,277                      |       |
| McLellan     |       | 119,400                            |       | 124,750                     |       | 5,559                                   |       | 249,709                      |       |
| Newell       |       | 122,933                            |       | 124,750                     |       | 11,845                                  |       | 259,528                      |       |
| O’Neill |       | 143,600                            |       | 124,750                     |       | 9,191                                   |       | 277,541                      |       |
| Romanow      |       | —                             |       | —                      |       | —                                  |       | —                       |       |
| Saville      |       | 256,000                            |       | 199,600                     |       | 9,291                                   |       | 464,891                      |       |
| Thomson5     |       | 46,567                             |       | —                      |       | 7,266                                   |       | 53,833                       |       |
| Willson      |       | 129,200                            |       | 124,750                     |       | 9,946                                   |       | 263,896                      |       |
| Zaleschuk    |       | 104,800                            |       | 124,750                     |       | 7,547                                   |       | 237,097                      |       |
| **Total**    | ** ** | **1,482,267**                      | ** ** | **1,447,100**               | ** ** | **230,402**                             | ** ** | **3,159,769**                | ** ** |

 

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*1*                 Includes all retainers, travelallowance and meeting fees, including those paid in DSUs.

*2*                 The grant date fair value ofDSUs granted on December 7, 2009, based on the closing market priceof Nexen common shares on the TSX on December 4, 2009, of $24.95 pershare.

*3*                 The total value of perquisitesprovided to each non-executive director is less than both $50,000 or 10% oftotal fees, and is not included in this column. Amounts reflect life insurancepremiums paid by Nexen, reinvested dividends earned in 2009 valued at theclosing market price of Nexen common shares on the TSX on the payment dates andCanexus fees as set out in note 4.

*4*                 Mr. Flanagan is the BoardChair of Canexus and was paid fees of $84,000, received deferred trust units ofCanexus valued at $36,330 and distributions on his trust units of $17,923 in2009. The total is included in this column.

*5*                 Mr. Hentschel andMr. Thomson retired from the board on April 28, 2009.

 

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***RETAINERS AND FEES***

* *

Annual board and committee retainers are paid in quarterlyinstallments and pro-rated for partial service. The same fees are paid forattending meetings in person or by conference call. A travel allowance of$1,500 is paid when a non-executive director travels outside his or her homeprovince or state, or travels more than three hours, round trip, to attend aNexen meeting or site visit. Nexen also reimburses them for out-of-pockettravel expenses. There were no increases to director retainers or fees approvedfor 2010.

 
| ** **                                              | ** ** | **2009** | ** ** | **2010** | ** ** |
|---------------------------------------------------------|------------|----------|------------|----------|------------|
| 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    |       |

 

----

*1*                 The Board Chair is paid onlythis retainer and the travel allowance, where applicable. He does not receiveany other retainers or meetings fees.

* *

**2009 Retainers and Fees**

 
| ** **   | ** ** | ** **   | ** ** | ** **    | ** ** | **Annual**    | ** ** | ** **  | ** ** | ** **    | ** ** | ** **    | ** ** | ** **      | ** ** | ** **                       | ** ** | ** **  | ** ** | **Total  Fees** | ** ** |
|--------------|------------|--------------|------------|---------------|------------|---------------|------------|-------------|------------|---------------|------------|---------------|------------|-----------------|------------|----------------------------------|------------|-------------|------------|-----------------|------------|
| ** **   | ** ** | **Annual**   | ** ** | **Annual**    | ** ** | **Committee** | ** ** | **Board**   | ** ** | **Committee** | ** ** | ** **    | ** ** | ** **      | ** ** | **Total  Fees**                  | ** ** | **Earned**  | ** ** |
| ** **   | ** ** | **Board**    | ** ** | **Committee** | ** ** | **Chair**     | ** ** | **Meeting** | ** ** | **Meeting**   | ** ** | **Travel**    | ** ** | **Total  Fees** | ** ** | **Credited  in  DSUs****1** | ** ** | **in Cash** | ** ** |
| **Name**     | ** ** | **Retainer** | ** ** | **Retainers** | ** ** | **Retainer**  | ** ** | **Fees**    | ** ** | **Fees**      | ** ** | **Allowance** | ** ** | **Earned**      | ** ** | **$**                            | ** ** | **%**       | ** ** | **($)**         | ** ** |
| Berry        |       | 35,000       |       | 18,200        |       | —        |       | 9,000       |       | 16,200        |       | 7,500         |       | 85,900          |       | —                           |       | —      |       | 85,900          |       |
| Bertram      |       | 35,000       |       | 18,200        |       | —        |       | 9,000       |       | 16,200        |       | 7,500         |       | 85,900          |       | 78,400                           |       | 91          | %          | 7,500           |       |
| Flanagan     |       | 35,000       |       | 27,300        |       | —        |       | 9,000       |       | 27,000        |       | 4,500         |       | 102,800         |       | —                           |       | —      |       | 102,800         |       |
| Hentschel2   |       | 11,667       |       | 9,100         |       | —        |       | 3,600       |       | 10,800        |       | 3,000         |       | 38,167          |       | —                           |       | —      |       | 38,167          |       |
| Jackson      |       | 35,000       |       | 36,400        |       | 5,300         |       | 9,000       |       | 30,600        |       | 3,000         |       | 119,300         |       | 116,300                          |       | 97          | %          | 3,000           |       |
| Jenkins      |       | 35,000       |       | 36,400        |       | 5,300         |       | 9,000       |       | 36,000        |       | 6,000         |       | 127,700         |       | —                           |       | —      |       | 127,700         |       |
| McLellan     |       | 35,000       |       | 36,400        |       | —        |       | 9,000       |       | 36,000        |       | 3,000         |       | 119,400         |       | 81,400                           |       | 68          | %          | 38,000          |       |
| Newell       |       | 35,000       |       | 36,400        |       | 3,533         |       | 9,000       |       | 36,000        |       | 3,000         |       | 122,933         |       | 119,933                          |       | 98          | %          | 3,000           |       |
| O’Neill |       | 35,000       |       | 36,400        |       | 19,700        | 3          | 9,000       |       | 36,000        |       | 7,500         |       | 143,600         |       | —                           |       | —      |       | 143,600         |       |
| Romanow      |       | —       |       | —        |       | —        |       | —      |       | —        |       | —        |       | —          |       | —                           |       | —      |       | —          |       |
| Saville      |       | 250,000      |       | —        |       | —        |       | —      |       | —        |       | 6,000         |       | 256,000         |       | —                           |       | —      |       | 256,000         |       |
| Thomson2     |       | 11,667       |       | 12,133        |       | 1,767         |       | 3,600       |       | 14,400        |       | 3,000         |       | 46,567          |       | 43,567                           |       | 94          | %          | 3,000           |       |
| Willson      |       | 35,000       |       | 36,400        |       | 5,300         |       | 9,000       |       | 36,000        |       | 7,500         |       | 129,200         |       | 121,700                          |       | 94          | %          | 7,500           |       |
| Zaleschuk    |       | 35,000       |       | 27,300        |       | 5,300         |       | 9,000       |       | 25,200        |       | 3,000         |       | 104,800         |       | —                           |       | —      |       | 104,800         |       |
| **Total**    | ** ** | **623,334**  | ** ** | **330,633**   | ** ** | **46,200**    | ** ** | **97,200**  | ** ** | **320,400**   | ** ** | **64,500**    | ** ** | **1,482,267**   | ** ** | **561,300**                      | ** ** | ** **  | ** ** | **920,967**     | ** ** |

 

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*1*                 Details of DSU holdings are setout in the table on page 169.

*2*                 Mr. Hentschel andMr. Thomson retired from the board on April 28, 2009.

*3*                 Mr. O’Neill is the AuditCommittee Chair.

 

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**SHARE OWNERSHIP GUIDELINE**

 

One way our directors demonstrate their commitment to Nexen’ssuccess is through share ownership. On February 17, 2010, the boardamended the level of the guideline to reflect the change in share value sincemid-2008. This results in an ownership requirement of 18,000 shares. Shareownership includes DSUs accumulated from the annual DSU grant and received inlieu of fees. Directors must accumulate these shares or DSUs within three yearsof their appointment. The amount they are required to own or control isintended to represent at least three times both the base annual board retainerof $35,000 and the value of the base annual DSU grant. The guideline will bereviewed every three years by the Corporate Governance and Nominating Committeeto determine if an increase is needed, and compliance with the guidelines willbe reviewed annually. New directors will be advised if they are on track tomeet the guideline.

 

New directors, if eligible, are required to take their annualretainer in DSUs until the guideline 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 an increase in the guideline which resultsin a director falling out of compliance with the requirement, he or she willhave 18 months to meet the threshold again.

 

*All directors appointed priorto January 1, 2007 surpass this guideline and directors appointed in thelast three years are on track to meet the guideline.*

 

**DEFERRED SHARE UNITS**

 

Nexen has two DSU plans. Under the first plan, eligibledirectors may elect annually to receive all or part of their fees in DSUs,rather than cash. The second plan was implemented in 2003 and replaced stockoptions as the equity-based vehicle to align director and shareholderinterests.

 

DSUs provide directors with a stake in Nexen while they serveon the board. DSUs do not have voting rights as there are no shares underlyingthe plans. A DSU is a bookkeeping entry that tracks the value of one Nexencommon share. When cash dividends are paid on our common shares, eligibledirectors are credited DSUs equal to the dividend. All DSUs vest at the time ofgrant; however, they accumulate over a director’s term of service and are only paidwhen the director leaves the board. Then, at Nexen’s option, payments may bemade in cash or in Nexen common shares purchased on the open market.

 
| **Name**     | ** ** | **DSUs Held as of  December 31, 2009****1** | ** ** |
|--------------|------------|-------------------------------------------------------|------------|
| Berry        |       | 10,044                                                |       |
| Bertram      |       | 13,335                                                |       |
| Flanagan     |       | 40,972                                                |       |
| Jackson      |       | 58,644                                                |       |
| Jenkins      |       | 54,215                                                |       |
| McLellan     |       | 35,766                                                |       |
| Newell       |       | 68,546                                                |       |
| O’Neill |       | 51,016                                                |       |
| Romanow      |       | —                                                |       |
| Saville      |       | 54,520                                                |       |
| Willson      |       | 58,920                                                |       |
| Zaleschuk    |       | 42,756                                                |       |

 

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*1*                 Number of DSUs has beenadjusted to account for Nexen’s share splits that occurred in May 2005 andMay 2007.

 

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**TOPS EXERCISED OR EXCHANGED AND AWARDS VESTEDDURING 2009**

 

In 2009, 111,004 tandem options (TOPs) were exercised orexchanged by non-executive directors and all exercises or exchanges of TOPsoccurred within six months of expiry. We ceased awarding TOPs to non-executivedirectors in 2003. In 2010, all remaining outstanding TOPs held bynon-executive directors will reach their expiry periods. Non-executivedirectors are granted share-based awards under the DSU plan. The DSUs vest atthe time of grant. We do not award directors non-equity incentive plancompensation under other long-term incentive plans, as these terms are used inapplicable disclosure requirements.

 
| ** **   | ** ** | **TOPs Awards**                  | ** ** | **DSU Awards**                  | ** ** | **Non-Equity Annual Incentive  Plan Compensation** | ** ** |
|--------------|------------|----------------------------------|------------|---------------------------------|------------|----------------------------------------------------|------------|
| **Name**     | ** ** | **Exercised or  Exchanged  (#)** | ** ** | **Value  Realized****1****($)** | ** ** | **Vested  in 2009  (#)**                           | ** ** | **Value Vested  in 2009****2****($)** | ** ** | **Value Earned  During the Year  ($)** | ** ** |
| Berry        |       | —                           |       | —                          |       | 5,000                                              |       | 124,750 |   | — |   |
| Bertram      |       | —                           |       | —                          |       | 5,000                                              |       | 124,750 |   | — |   |
| Flanagan     |       | —                           |       | —                          |       | 5,000                                              |       | 124,750 |   | — |   |
| Hentschel    |       | 40,000                           |       | 669,500                         |       | —                                             |       | — |   | — |   |
| Jackson      |       | —                           |       | —                          |       | 5,000                                              |       | 124,750 |   | — |   |
| Jenkins      |       | —                           |       | —                          |       | 5,000                                              |       | 124,750 |   | — |   |
| McLellan     |       | —                           |       | —                          |       | 5,000                                              |       | 124,750 |   | — |   |
| Newell       |       | —                           |       | —                          |       | 5,000                                              |       | 124,750 |   | — |   |
| O’Neill |       | —                           |       | —                          |       | 5,000                                              |       | 124,750 |   | — |   |
| Saville      |       | 11,004                           |       | 175,376                         |       | 8,000                                              |       | 199,600 |   | — |   |
| Thomson      |       | 60,000                           |       | 1,050,501                       |       | —                                             |       | — |   | — |   |
| Willson      |       | —                           |       | —                          |       | 5,000                                              |       | 124,750 |   | — |   |
| Zaleschuck   |       | —                           |       | —                          |       | 5,000                                              |       | 124,750 |   | — |   |
| **Total**    | ** ** | **111,004**                      | ** ** | **1,895,377**                   | ** ** | **58,000**                                         | ** ** | **1,447,100** | ** ** | **—** | ** ** |

 

----

*1*                 Reflects the closing marketprice at the time of the exercise or exchange, minus the exercise price, timesthe number of TOPs exercised or exchanged.

*2*                 Reflects the grant date fairvalue of DSUs granted on December 7, 2009. Mr. Hentschel andMr. Thomson were not on the board at the time of grant.

* *

**COMPENSATIONCOMMITTEE REPORT**

 

The Compensation Committee assists the board in overseeingkey compensation and human resource policies, CEO and executive compensation,and executive management succession and development. The Committee reports tothe board, as set out in its mandate, and the board or independent directorsgive final approval on compensation matters.

 

All Committee members are independent and knowledgeable inour compensation programs and their long-term implications. Six members areskilled or expert in compensation—expertise most relevant to the Committee’smandate.

 

**CHANGES TO COMMITTEE MEMBERSHIP IN 2009**

 

Mr. Thomson left the Committee upon his retirement fromthe board and Mr. Bertram joined in April 2009.

 

**COMMITTEE WORK PLAN / KEY ACTIVITIES IN 2009**

 

The Committee held five meetings and sessions withoutmanagement present in 2009. Additional meetings are held, when required, toaccomplish business objectives and the Committee’s mandate. We have an existingmandate with a 12-month rolling work plan in place for the Committee. Theactivities of the Committee are managed in the context of a five-year businessstrategic plan that is reviewed and approved annually by the board. To someextent, the work plan of the committee is structured around compensationactivities that occur in the market (e.g. compensation 

 

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survey releases) and business activities. The 12-month workplan allows us to effectively deliver the Committee’s responsibilities with theflexibility to respond to market events that may arise from time to time. In reviewingNexen’s compensation philosophy, the Committee expressly included theassessment of risk in determining compensation policies and practices.

 

While each meeting agenda is subject to change as businessneeds arise, the timing of the Committee’s main activities, reviews andrecommendations for 2009 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 targets, compensation program and budget

Reviewed CEO’s prior  year accountabilities, short-term and long-term results, and provided a bonus  recommendation to the independent directors of the board

Reviewed CEO’s current  year objectives and provided a salary recommendation to the independent  directors of the board

Reviewed executives’  compensation and provided bonus and salary increase recommendations

Recommended appointing  the new Treasurer and ratification of the appointment of the new Vice  President, Corporate Planning and Business Development

Reviewed impact of  current compensation on change of control agreements |   | February 2009

  |
| Recommended  appointments for the Executive Vice President, Canada and Assistant Secretary  positions and reviewed a new executive position of Vice President, Global  Exploration

Reviewed competitive  analysis and design of the annual bonus program                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |   | April 2009

     |
| Reviewed competitive  analysis and design of the long-term incentive program

Recommended appointing  the new Senior Vice President, Synthetic Crude

Reviewed retention  programs for key business initiatives                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |   | July 2009

      |
| Reviewed market  activity updates and forecasts

Reviewed workforce plan

Reviewed  competitiveness of individual compensation programs and total compensation  offering

Discussed future  introduction of performance features into the long-term incentive plan

Reviewed mandate and  performance of outside consultant

Reviewed say-on-pay  policy                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |   | October 2009

   |
| Recommended long-term  incentive grants

Reviewed and  recommended Directors’ compensation, including DSU grants

Approved revised  evaluation framework for annual bonus program

Discussed future  introduction of performance features into long-term incentive program

Reviewed competitive  analysis and recommended enhancement of executive share ownership guidelines

Reviewed draft CGGG  say-on-pay initiative                                                                                                                                                                                                                                                                                                                                                                                                                                                          |   | December 2009

  |
| In camera meetings                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |   | At each meeting            |

** **

**SUCCESSION PLAN AND EXECUTIVE DEVELOPMENT**

 

Our succession planning involves a detailed, documentedprocess for identifying and developing successors from our most talentedindividuals for the CEO, senior management and other positions deemed criticalfor the success of the company. Each year, the CEO reviews with the Committeethe internal talent pool considered for these positions. The Committee assistswith candidate selection, development and performance evaluation as well asplanning for illness, disability and other unscheduled absences.

 

**OUTSIDE CONSULTANT**

 

The Committee engaged Mercer (Canada) Limited (Mercer) toconfidentially report and analyze market data on the compensation of the CEOand a select group of executives, in light of our operations and compensationprograms. Mercer also provided other consulting services, as required. Thereports included competitive information from a list of peer companiesrecommended by Mercer. The Committee’s decisions are its responsibility and mayreflect factors other than the information and recommendations provided byMercer and management.

 

Mercer did not provide compensation consulting services tomanagement in 2009. We participated in compensation surveys in Canada andinternationally, and purchased select published results. Management must obtainCommittee approval before retaining Mercer for consulting services.

 

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**FEES BILLED BY OUTSIDE CONSULTANT (MERCER)**

 
| **Type of Fee**                                                  | ** ** | **Billed in 2008** | ** ** | **Billed in 2009** | ** ** | **Percentage of Total  Fees Billed in 2009** | ** ** |
|------------------------------------------------------------------|------------|--------------------|------------|--------------------|------------|----------------------------------------------|------------|
| Committee Work—assessment of CEO and executive compensation |       | 58,900             |       | 83,636             |       | 100                                          | %          |
| Management Work—consulting services                         |       | —             |       | —             |       | —                                       |       |
| **Total Annual  Fees**                                           | ** ** | **58,900**         | ** ** | **83,636**         | ** ** | **100**                                      | **%**      |

 

**EXTERNAL RECOGNITION AND VERIFICATION**

 

We received recognitionfor our human resources practices during 2009.

 

·                  One of the 50 Best Employers inCanada by Hewitt Associates.

·                  One of the Best Employers forNew Canadians and one of Canada’s Best Diversity Employers by Mediacorp CanadaInc.

 

**COMMITTEE APPROVAL**

 

The Committee reviewed and discussed with management thecompensation disclosure in this document, including the information in theDirectors section (pages 161 to 170), the Compensation Discussion and Analysissection (pages 172 to 183) and the Executive Compensation section(pages 184 to 195). It has recommended to the board that the disclosure beincluded in the proxy circular and, as appropriate, the Form 10-K.

 

**Submitted on behalf of the Compensation Committee:**

 

Kevin Jenkins, Chair, Robert Bertram, Barry Jackson, AnneMcLellan, Tom O’Neill, Francis Saville, John Willson

 

**COMPENSATIONCOMMITTEE INTERLOCKS AND INSIDER PARTICIPATION**

 

The members of the Compensation Committee are set out onpage 165. Mr. Saville and Ms. McLellan had a relationship requiringdisclosure, the details of which are set out under “Certain Relationships andRelated Transactions, and Director Independence” on page 201. There are noCompensation Committee interlocks during 2009.

 

**COMPENSATIONDISCUSSION AND ANALYSIS**

 

Our compensation disclosure complies with the requirements ofthe Canadian Securities Administrators. As a foreign private issuer listed inthe US, we are not required to disclose compensation according to the SECrules, but we attempt to comply with the spirit of those rules wherepossible, without compromising required Canadian disclosure.

 

**COMPENSATIONPHILOSOPHY**

 

Our policies andpractices for executive compensation are linked to strategic businessobjectives, which focus on increasing shareholder returns in the long term. Ourphilosophy is to compensate executives:

 

·                  based on performance;

·                  at a level competitive with ourpeers; and

·                  in a manner designed toattract, engage and retain talented leadership focused on managing Nexen’soperations, finances and assets for long-term value creation.

 

All of our compensation programs are designed to meetpay-for-performance and competitiveness objectives. Actual rewards are directlylinked to the results of Nexen. The objective and subjective performancemeasures are aligned with shareholder interests, and financial andnon-financial goals. Measures set each year represent improvements and growthto our operations relative to prior years.

 

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Our programs are responsive to market changes. We aim forsimplicity in our compensation programs to help employees understand the valueof the various components and how they can contribute to business results.Executive programs are generally consistent with employee programs in the samelocation. Where certain programs, such as perquisites, are only provided toexecutives or senior management, they reflect competitive practice andparticular business needs and objectives.

 

**ASSESSMENT OF RISK IN COMPENSATION POLICIESAND PRACTICES**

 

Nexen’s compensationpolicies and practices encourage behaviours which align with the long-terminterests of the company and its shareholders. While our programs and practicesare not structured to reward excessive risk-taking, we recognize that somelevel of risk-taking is necessary in order to achieve outcomes in shareholders’best interests. However, we have a number of mitigating strategies to limitrisks within our policies and practices that are described below.

 

·                  Total direct compensation fornamed executive officers (named executives) reflects an appropriate balancebetween base salary and variable or “at risk” compensation. Typically, 75% ofour named executives’ total direct compensation is variable based on companyand individual performance with the remaining 25% comprised of base pay; thevariable pay portion is greater for the CEO. Approximately 20% of this variablecompensation is provided as an annual cash incentive and 80% in long-termincentives. This weighting toward long-term incentives mitigates the risk ofencouraging achievement of short-term goals at the expense of long-termsustainability and shareholder value. Refer to page 174 for more detail onthe named executives’ pay mix.

·                  The design of our annual cashincentive program, applicable to all employees, also inherently limits risk.The cash pool available for bonus payments is determined based on a balancedscorecard of measures, including net income, operating cash flow and acombination of other qualitative and quantitative measures. This approachdiversifies the risk associated with any one single performance indicator. Inaddition, the nature of the primary financial measures used in cash pooldetermination (net income and operating cash flow) effectively ensures thecompany will have the ability to pay bonuses required under the program. TheCompensation Committee exercises a considerable amount of discretion inassessing overall performance and can ensure that bonus payouts are not undulyinfluenced by an unusual result in any one given area. Finally, the total cashpool available is limited to a maximum of 200% of target.

·                  Our long-term incentives,applicable to eligible employees, vest over a three year period and have a fiveyear term, thereby enhancing executive (and employee) focus on long-termcompany success and shareholder interests.

·                  Compensation levels arebenchmarked and scenario tested to ensure a strong pay-for-performancerelationship.

·                  Named executives and othersenior leaders are subject to share ownership guidelines, which are describedon page 178. In December 2009, ownership requirements were increasedand expanded to include a greater number of employees.

 

**BENCHMARK REVIEW**

 

We use third-party compensation surveys to compare our paylevels and practices, including base pay, annual cash incentives and long-termincentives, to our peers. These surveys are used by management to formulatecompensation recommendations to the Compensation Committee. We look atCanadian-based oil and gas and integrated pipeline companies with whom wecompete for talent. Given similar positions across the industry, the surveyseffectively represent competitive pay levels. It should be noted, however, wedo not know if our peers benchmark each position. The peer groups are modifiedover time to reflect: i) geographical location; ii) a particular business line;iii) a more comparable position; or, iv) industry mergers and acquisitions.

 

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Our peer groups arereviewed annually by third-party consultants and the Compensation Committee forcontinued relevance. In 2009, our executive peer group for named executivesbased in Canada consisted of the following 16 major oil and gas and integratedpipeline companies:

 
| 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 |

 

For the CEO, the peer group is a subset of the 16 peercompanies. This peer group focuses on the major Canadian-based and independentoil and gas companies that have more comparable CEO positions. For the SeniorVP, US Oil and Gas, market data are based on comparable positions from mid andlarge cap US oil and gas companies.

 

**COMMITTEE OVERSIGHT**

 

The Compensation Committee reviews all programs to ensure wecontinue to attract, engage and retain the high-performing employees needed toachieve our business objectives, while demonstrating long-term fiscalresponsibility to shareholders.

 

**COMPENSATIONOBJECTIVES**

 

Our compensation programs include three elements: basesalary, annual cash incentive and long-term incentive. At least once a year, weassess the competitiveness of these individual components and the overallcompensation levels. Our goal is to provide total compensation forfully-qualified employees between the 50th and 75th percentile of our peers.Top-performing employees will approach the 75th percentile if they continue toaccumulate knowledge and experience, which is accompanied by sustained highperformance.

 

**KEY ELEMENTS OF COMPENSATION**

 
| **Element**           | ** ** | **Component** | ** ** | **Form**       | ** ** | **Performance Period** |
|-----------------------|------------|---------------|------------|----------------|------------|------------------------|
| Base salary           |       | Fixed         |       | Cash           |       | 1 year                 |
| Annual cash incentive |       | Variable      |       | Cash           |       | 1 year                 |
| Long-term incentive   |       | Variable      |       | TOPs and STARs |       | Greater than 1 year    |

 

**PAY MIX**

 

The information in the following table represents thepercentage of total compensation, excluding benefits, pension and perquisites,averaged over a three year period. Actual pay mix will vary from year to yearas our compensation programs are designed to meet both performance andcompetitiveness objectives. In general, the programs are designed to providemost executive compensation in the form of at-risk pay to ensure alignment withshareholders interests. Base salary provides a competitive foundationconsidering both internal comparability and external market data. Annual cashincentives reward the delivery of results against objective and subjectivemeasures within a one-year period. Long-term incentives reward Nexen’ssustained performance as seen in share price appreciation. The actual mixbetween the compensation elements varies, depending on the named executives’ability to influence short and long-term business results and competitive localmarket practices.

 
| ** **    | ** ** | ** **      | ** ** | **At-Risk Compensation**  | ** ** |
|---------------|------------|-----------------|------------|---------------------------|------------|
| **Position**  | ** ** | **Base Salary** | ** ** | **Annual Cash Incentive** | ** ** | **Long-Term Incentive** | ** ** |
| CEO           |       | 20              | %          | 15                        | %          | 65 | % |
| CFO           |       | 25              | %          | 15                        | %          | 60 | % |
| Executive VPs |       | 25              | %          | 15                        | %          | 60 | % |
| Senior VPs    |       | 25              | %          | 15                        | %          | 60 | % |

 

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**COMPENSATIONAPPROVAL PROCESS**

 

****

 

In determining our executives’ base salary, annual cash andlong-term incentives, the Compensation Committee considers a comprehensiveanalysis, including a tally sheet prepared by management with input from anexecutive compensation consultant. The analysis includes market data forsimilar positions within the peer group, CEO recommendations for his directreports, including all of the other named executives, and information on prioryear annual cash and long-term incentives. Before approving management’scompensation recommendations, the Committee discusses a variety of potentialperformance scenarios, including analysis of various annual cash incentivepayout factors and the impact of share price variation on our long-termincentive program (i.e. scenario tested). For pension, management provides theCommittee with a sensitivity analysis that considers the pension costimplications for each 1% of incremental pensionable earnings.

 

The Committee reviews the three compensation elements bothindividually, and in total, to ensure they align with the program objectives.In addition, the Committee retains the services of its own executivecompensation consultant, Mercer, to provide external market data and commentaryon the relative positioning of executives, particularly the CEO. The Committeethen makes recommendations on all executive payments and long-term incentivegrants to the board or, in the case of the CEO, the independent directors forapproval. Typically, this process begins in the fall and concludes with totalcompensation being approved the following February.

 

**BASE SALARIES**

 

To determine base salaries, a framework of job levels basedon internal comparability and external market data is used. We also considerthe individual’s current and sustained performance, skills and potential.

 

**ANNUAL CASHINCENTIVES**

 

The program provides an opportunity for competitive bonuscompensation that reflects Nexen’s overall performance and that of theindividual. Consistent with our pay-for-performance philosophy, variablecompensation links Nexen’s business results and the named executives’performance. The decrease in the named executives’ annual cash incentives in2009 reflects the board’s assessment of our company performance as describedbelow.

 

**2009 ANNUAL INCENTIVE MEASURES**

 

After assessing Nexen’s objective and subjective performancemeasures, the board, at the recommendation of the Compensation Committee,approves the payout factor. The payout factor determines the cash poolavailable for annual cash incentives and may range from 0 to 200% of the targetincentive opportunity. The factors used were 88% in 2007, 120% in 2008 and 65%in 2009.

 

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**2009 Objective Performance Assessment (50%)**

 

These key financial measures are consistent with our annualoperating plan. Operating cash flow measures our ability to generate cash fromour ongoing operations. It includes taxes and financing costs, but excludesone-time items such as gains on dispositions.

 
| **Measure**               | ** ** | **Target** | ** **     | **Results** | ** ** | **Results  versus  Target** | ** ** |
|---------------------------|------------|------------|----------------|-------------|------------|-----------------------------|------------|
| Operating cash flow (25%) |       | $          | 2,706  million |        | $          | 2,215  million              |       | 82 | % |
| Net income (25%)          |       | $          | 852  million   |        | $          | 536  million                |       | 63 | % |

 

**2009 Subjective Performance Assessment (50%)**

 

The Compensation Committee subjectively considers acombination of quantitative and qualitative measures. The individual measuresare not assigned a fixed weighting. This allows the Committee to exercise itsdiscretion and increase or decrease the payout factor when assessing overallperformance. Its discretion ensures that the award is not unduly positively ornegatively impacted by an unusual result in any one area. The business measuresthat the Committee considers are commonly used in our industry. They include,among other measures, annual share performance against peers, productionvolumes, safety and environmental incidents, and reserve-related metrics. TheCommittee also assesses how costs are managed, including finding anddevelopment, operating and administrative. The business measures are assessedagainst objectives in light of our external environment and current businesscircumstances, including key projects and initiatives critical to Nexen’ssuccess. The Committee also considers management’s assessment of Nexen’sperformance and progress on the strategic plan.

 

**Overall Performance Assessment**

 

If Nexen does not achieve the minimum pre-determinedperformance level of any component of the objective measures, no allocationwill be made for that component in the overall assessment of the payout factor.The Committee’s assessment of the subjective measures could also result in adecrease of the payout factor. Alternatively, exceptional performance in ourobjective and subjective measures may be rewarded with a 200% payout factor,which is the maximum allowed under the annual incentive plan. Exceptionalperformance means that we exceeded our objective measure targets by at least25%. For 2009, the Committee used its discretion and considered that while manyof Nexen’s core assets performed well, delays related to the ramp-up of LongLake and delays at Ettrick in the North Sea had significant impacts on ourability to achieve certain financials and production targets, resulting in a payoutfactor of 65% for the annual cash incentive program.

 

**Annual Cash Incentive Payout**

 

The cash pool available for annual incentives is allocated toemployees and executives based on individual incentive target levels andperformance. The targets for individual awards increase as job responsibilitiesgrow so that the ratio of at-risk compensation is greater for higher levels inthe organization. Individual performance is assessed by the supervisor and a recommendationis made that reflects performance against pre-determined objectives. Award recommendationsfor all senior employees are then reviewed by the executive management team.The Compensation Committee assesses the CEO’s performance in the context ofpredetermined objectives which are described in more detail on pages 186 to187. The CEO’s final incentive award is approved by the independent directors.

 

The CEO assesses the performance of the other namedexecutives and discusses the recommendations with the Compensation Committeeprior to approval by the board. The actual incentive award received by theindividual may be more or less than target level. Typically, annual incentiveawards range from 0 to 200% of the target for that position.

 

**2009 ANNUAL INCENTIVE TARGETS**1

 
| **Position**  | ** ** | **Minimum** | ** ** | **Target** | ** ** | **Maximum** | ** ** |
|---------------|------------|-------------|------------|------------|------------|-------------|------------|
| CEO           |       | 0           | %          | 75         | %          | 150         | %          |
| CFO2          |       | 0           | %          | 55         | %          | 110         | %          |
| Executive VPs |       | 0           | %          | 60         | %          | 120         | %          |
| Senior VPs    |       | 0           | %          | 45         | %          | 90          | %          |

 

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*1*                 Reflects percentage of basesalary on December 31, 2009.

*2*                 To ensure competitivecompensation, the board increased the bonus target from 50% to 55% effectiveJanuary 1, 2009.

 

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**Revised Subjective Performance Assessment**

 

Beginning in 2010, the Committee has adopted a slightlymodified framework to evaluate subjective performance for the annual bonusprogram. Under this framework, the Committee is given the opportunity to assigngreater or less emphasis to certain measurement areas depending on thestrategic focus for the coming year. The subjective performance assessment willbe organized into six key areas of focus outlined below.

 
| **Key Performance Area**                        | ** ** | **Objective**                                                                                          |
|-------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------|
| Strategic performance and other key initiatives |       | Demonstration of our core growth strategies in action and assessment  of various other key initiatives |
| Capital efficiency (investment value creation)  |       | Creating full cycle value from our capital investments                                                 |
| Operating efficiency                            |       | Meeting our shorter-term operational targets                                                           |
| Competitive assessment                          |       | Assessing our performance and strategies relative to our industry  peers                               |
| How we do business                              |       | Building and maintaining our social license to operate                                                 |
| People and talent                               |       | Ensuring we have the talent and engagement to support our initiatives                                  |

 

At the end of the annual performance assessment cycle, theCommittee will assess company performance with special consideration for thekey performance areas previously determined.

 

**REIMBURSEMENT**

 

If, as a result of misconduct, Nexen’s performance resultswere restated in a way that would have resulted in lower incentive awards, theCEO and CFO would reimburse Nexen proportionately as required by law.

 

While Nexen is aligned and committed to the US requirementsfor clawbacks, we are consulting with industry leaders and shareholder advisorygroups to better understand the development of clawback policy models inCanada. Identified barriers to implementation include employment law,enforcement and tax issues. Nexen is working to implement a more formalsolution that effectively addresses alignment of shareholder and executiveinterests by ensuring that compensation is not increased as a result of willfulmisconduct.

 

**SHAREPERFORMANCE GRAPH**

 

There is no inherent connection between base salary levelsand Nexen share performance as salary determination is based on marketcompetitiveness and internal relativity, as well as individual performance andpotential. There is some correlation between our annual cash incentive programpayouts and share performance, as relative share price performance is a measureincluded in determining the payout factor. In addition, the annual incentiveprogram payout reflects an assessment of overall company performance which isalso directly or indirectly assessed by current or potential investors whoultimately determine our share price. 

 

The sharp increase to our share price from 2004 to 2005 partiallyreflects the company’s strong performance year in 2005 which resulted in apayout factor of 200% for the annual incentive program. Our share price leveledin subsequent years and at the same time our payout factors were reduced to120% in 2006 and 88% in 2007. At the end of 2008, turbulence in the globalfinancial markets and slumping commodity prices had a significant impact onNexen’s share price, not unlike that of other public companies. Despite thisdecline, we achieved record financial results and strong relative share priceperformance in 2008 leading to a program which exceeded target resulting in apayout factor of 120%. During 2009, we experienced some recovery in our shareprice. While many of Nexen’s core assets performed well, delays related to theramp-up of Long Lake and delays at Ettrick in the North Sea had significantimpacts on our ability to achieve certain financials and production targetsresulting in a payout factor of 65% for the annual cash incentive program.

 

With respect to our long-term incentive program, a directcorrelation exists between our share price performance and the actual gainsrealized by participating employees. The significant drop in our share price in2008 resulted in a number of our earlier long-term incentive grants moving intoan out-of-the money position offering zero value to 

 

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participating employees. Some of the value of these long-termincentive grants has been re-gained with the rise in our share price in 2009,but many outstanding long-term incentive grants remain out of the money. Ourlong-term incentive plan does not allow for repricing of grants.

 

The following graph shows the change in a $100 investment inNexen common shares over the past five years, compared to the S&P/TSXComposite Index, the S&P/TSX Energy Sector Index and the S&P/TSX Oil& Gas Exploration & Production Index as at December 31, 2009. Ourcommon shares are included in each of these indices.

 

 

**Total Return Index Values****1**

 
| ** ** | ** **                                                              | ** ** | **2004/12** | ** ** | **2005/12** | ** ** | **2006/12** | ** ** | **2007/12** | ** ** | **2008/12** | ** ** | **2009/12** | ** ** |
|------------|-------------------------------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|-------------|------------|
|            | Nexen Inc.                                                              |       | 100.00      |       | 228.69      |       | 265.80      |       | 266.65      |       | 179.29      |       | 212.36      |       |
|            | S&P/TSX Oil & Gas Exploration & Production  Index |       | 100.00      |       | 173.65      |       | 175.95      |       | 193.77      |       | 134.13      |       | 190.75      |       |
|            | S&P/TSX Energy Sector Index                                         |       | 100.00      |       | 163.43      |       | 173.34      |       | 187.61      |       | 116.00      |       | 173.00      |       |
|            | S&P/TSX Composite Index                                             |       | 100.00      |       | 124.13      |       | 145.55      |       | 159.86      |       | 107.10      |       | 144.65      |       |

 

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*1*                 Assuming an investment of $100and the reinvestment of dividends.

* *

The Compensation Committee reviews a detailed analysis of thetotal compensation earned by the CEO during his tenure in this role as itrelates to shareholder value creation. This analysis includes a comparison oftotal CEO compensation earned related to the increase in Nexen’s marketcapitalization, as well as a comparison to the value created in excess of arelevant peer group.

 

**SHARE OWNERSHIPGUIDELINES**

 

All executives are expected to demonstrate their commitmentto Nexen by holding more shares than required under our board-approvedguidelines. The guidelines, and compliance with them, are reviewed annually bythe Compensation Committee and the board. See page 190 for the currentshare ownership of each named executive.

 

In December 2009, the Committee amended the level andscope of the share ownership guidelines to enhance the alignment between allexecutives and shareholders. The enhanced guidelines include: i) increasedlevels of share ownership; ii) greater number of employees covered by theguidelines; and iii) removal of the net value of exercisable options or TOPsfrom the share ownership calculation. Share ownership is limited to sharespurchased and held within the Nexen employee savings plan and any otherpersonal holdings. Under these guidelines, there is a specified timeframe forcompliance, which is three years from the date of the amendment(December 2009) or five years from the date of their appointment,whichever is later.

 
| **Position**                              | ** ** | **Required Share Ownership** |
|-------------------------------------------|------------|------------------------------|
| CEO                                       |       | 4 times annual salary        |
| CFO and executive vice  presidents        |       | 2.5 times annual salary      |
| Senior vice presidents                    |       | 2 times annual salary        |
| Vice presidents and other  senior leaders |       | 1 times annual salary        |

 

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**LONG-TERMINCENTIVES**

 

Nexen’s long-term incentive programs, the TOPs and STARsplans, provide employees with a long-term incentive to sustain highperformance, demonstrate commitment to Nexen and, most importantly, align theirinterests with those of our shareholders. As Nexen’s share price rises, grantsincrease in value. TOPs or STARs are granted to employees, based on internalorganization levels, whose actions can most directly impact our businessresults. Named executives are granted TOPs, with the exception of the SeniorVP, US Oil and Gas who was granted STARs in 2009.

 

In determining the number of TOPs and STARs to grant eachyear, Nexen considers the program’s dilutive impact on shareholders and marketinformation on the value of stock options and other forms of long-termincentives. Market information also determines the extent to which employees atdifferent levels participate in the program. The Compensation Committee reviewsand recommends TOPs plan amendments for the board to approve. In determiningthe type of long-term incentives to award, management and the CompensationCommittee also consider alternative long-term incentive programs used by ourpeers. As a result of a regular review of the competitiveness and design of ourlong-term incentive plans, in 2009 the Compensation Committee approvedintroducing a performance-based long-term incentive vehicle for implementationin 2010. This incentive vehicle will be introduced only for those employees whoare critical to the strategic success of the company (senior management leveland above) with 25% of the TOPs or STARs granted to these employees to includea performance vesting feature. The number of performance-based TOPs or STARsthat vest for payout will be subject to the attainment of market, operationaland/or financial performance measures. The specific performance range(s) willbe ultimately determined by the Committee at the time of each annual grant.

 

**TOPS PLAN**

 

Our TOPs plan has been inplace since 2004. It allows employees to either:

 

·                  exchange their vested TOPs fora cash payment equal to the difference between the exercise price and theclosing market price of our common shares on the date the TOPs are exchanged;or

·                  exercise their TOPs for sharesupon payment of the exercise price. Nexen common shares are issued for TOPs ona one-for-one basis.

 

When employees exchange their TOPs for cash: i) no shares areissued, which prevents further shareholder dilution over time; and, ii) Nexenreceives a Canadian income tax deduction.

 

**2009 TOPs Plan Exercises and Exchanges**

 
| **Total Exercised  or Exchanged** | ** ** | **Exercised  for Shares** | ** ** | **Exchanged  for Cash** | ** ** |
|-----------------------------------|------------|---------------------------|------------|-------------------------|------------|
| 5,262,226                         |       | 1,145,756  (22%           | )          | 4,116,470  (78%)        |       |

 

TOPs do not provide employees with the right to vote theunderlying shares. The TOPs plan is Nexen’s only equity-based compensationarrangement.

 

The board, on the recommendation of the CompensationCommittee, may grant TOPs to Nexen officers and employees. TOPs granted beforeFebruary 2001 have a term of ten years; 20% of the grant vested after sixmonths and 20% vested each year for four years on the grant’s anniversary. TOPsgranted after February 2001 have a term of five years and vest one-thirdeach year for three years. The board has the discretion to set vesting periodswithin the five-year term.

 

Generally, if a change of control event occurs (as defined inthe TOPs plan), all issued but unvested options will vest.

 

**STARs PLAN**

 

The STARs plan, introduced in 2001, provides a cash paymentto participants equal to the appreciation in Nexen’s share price between thedate the STARs are granted and the date they are exercised. STARs are typicallygranted to participating employees below mid-level department manager in Canadaand to all levels of participating employees in the US and UK. They have afive-year term and vest one-third each year for three years.

 

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**GRANT DATE AND EXERCISE PRICE**

 

TOPs and STARs are granted during the annual grant processand at the time of hiring key positions. Since 1998, the annual grants havebeen approved at the December board meeting. According to our plans, theCEO can approve grants to key new hires, and typically, they occur shortlyafter the hire date. Under the plans, the exercise price is the closing marketprice of Nexen’s common shares on the relevant stock exchange (TSX forCanadian-based employees or NYSE for US-based employees) on the day before thegrant is approved. Accordingly, backdating is not allowed. Nexen’s grants areintentionally timed so that they do not occur immediately prior to the releaseof material information (i.e. spring-loaded). The exercise price of existingTOPs or STARs may not be reduced except for automatic adjustments, such as ashare split, or according to TSX rules. Accordingly, repricing is not allowed.

 

**OPTIONS OUTSTANDING AND SHARES RESERVED FORISSUE**

 

We limit the combined annual grants of TOPs and STARs (eventhough STARs are not dilutive) to less than 2% of total outstandingshares (on a non-diluted basis). The total TOPs granted, plus shares reservedfor future issue under equity-based compensation programs, will not exceed 10%of our total outstanding shares (on a non-diluted basis). Since the inceptionof the TOPs plan in 2004 through December 31, 2009, 11,126,192 TOPs have beenexercised for common shares. This represents a dilution of 2.13%.

 

**GRANTS IN THE LAST THREE YEARS**

 

Our 2009 long-term incentives recognized employees for futurepotential within Nexen, sustained high performance and retention risk. The TOPsgranted in 2009 represent 0.83% of total outstanding shares.

 
| **Year** | ** ** | **Granted to  Executive Officers** | ** ** | **Granted  to Employees** | ** ** | **Percentage of Employees  Receiving Grants** | ** ** | **Total Number  Granted** | ** ** |
|----------|------------|------------------------------------|------------|---------------------------|------------|-----------------------------------------------|------------|---------------------------|------------|
| TOPs     |       |                               |       |                      |       |                                          |       |                      |       |
| 2009     |       | 1,772,000                          |       | 2,577,700                 |       | 5                                             | %          | 4,349,700                 |       |
| 2008     |       | 1,526,000                          |       | 2,008,100                 |       | 6                                             | %          | 3,534,100                 |       |
| 2007     |       | 1,735,000                          |       | 2,272,100                 |       | 7                                             | %          | 4,007,100                 |       |
| STARs    |       |                               |       |                      |       |                                          |       |                      |       |
| 2009     |       | 100,000                            |       | 5,172,500                 |       | 46                                            | %          | 5,272,500                 |       |
| 2008     |       | —                             |       | 4,917,200                 |       | 53                                            | %          | 4,917,200                 |       |
| 2007     |       | —                             |       | 4,194,600                 |       | 54                                            | %          | 4,194,600                 |       |

 

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**BENEFIT ANDPENSION PLANS**

 

Our benefit and pension plans support the health andwell-being of our employees and encourage retirement savings. The plans arereviewed periodically to ensure they remain competitive and continue to meetour objectives. Market survey data is reviewed to ensure the plans providebenefits between the 50th and 75th percentile of plans within our peer group.Named executives participate in the same plans provided to all employees in thesame location.

 

Disclosure in this document is specific to the Canadian andUS plans in which the named executives participate. Nexen provides a variety ofother benefit and pension plans outside of North America that reflect localmarket practices.

 

**HEALTH AND WELFARE BENEFITS**

 

Our benefit plans are designed to help protect employees’health and that of their dependants, and help cover them in the event ofdisability or death. Under the flexible benefit plans, employees choose thelevel of coverage that best fits their needs. Those who select enhancedcoverage levels are required to contribute to the cost of that coverage.

 

**EMPLOYEE SAVINGS PLAN**

 

To help employees save for their future andencourage ownership in the company, Nexen provides the incentive andopportunity to accumulate savings through an employee savings plan. In theplan, all eligible Canadian employees may contribute, through payrolldeduction, any percentage of their base salary to purchase Nexen common shares,mutual fund units or a combination of both. Nexen matches employeecontributions up to 6% of base salary, depending on the investment option andhow long the employee has participated in the plan. Nexen contributions areinvested in our common shares purchased on the open market and vestimmediately. All contributions may be allocated to registered or non-registeredaccounts. Employees may vote the Nexen common shares they hold in the employeesavings plan.

 

For US-based employees, savings plan benefits are a componentof the US defined contribution pension plan described on page 182.

 

**FLOW-THROUGH SHARES**

 

Named executives are able to participate inour internal offerings of Nexen flow-through shares, which are periodicallymade available to all employees resident in Canada. Flow-through shares are atax effective vehicle which provide an additional opportunity to invest in thefuture of Nexen.

 

**DEFINED BENEFIT PENSION PLAN**

 

Canadian employees ofNexen elect, upon hire, to participate in either the defined contributionpension plan or the defined benefit pension plan, both of which are registered.All Canadian-based named executives participated in the defined benefit pensionplan in 2009. Features of the defined benefit pension 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 36highest-paid consecutive months during the 10 years before retirement,multiplied by the years of credited service;

·                  plan participants may annuallyelect to increase their defined benefit accrual formula from 1.8% to 2%.Employees electing this option must contribute an additional 2% of pensionableearnings up to an allowable maximum under the Canadian Income Tax Act. Themaximum employee contribution allowed in 2009 was $11,700;

·                  integration with Canada PensionPlan (CPP) to provide a maximum offset of one-half of the current CPP benefit,pro-rated by years of credited service to a maximum of 35 years;

·                  members who retire after 10years of service are eligible for an early retirement benefit at age 55 with a4% reduction per year of early retirement for each year that benefits commenceprior to age 60; and

·                  ability for participants toperiodically switch prospectively between the defined benefit pension plan anddefined contribution pension plan at different stages in their career.

 

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Benefits on retirement are generally paid monthly for thelife of the retiree, subject to standard payment elections. The normal form ofbenefit paid is a joint life and survivor benefit with a five-year guarantee. Ifelected, it is payable for the participant’s lifetime and provides the spousewith a survivor benefit of 662⁄3% of the monthly payment.If the participant dies before receiving 60 monthly payments, the five-yearguarantee allows the surviving spouse to receive the balance of the 60 monthlypayments first and then the reduced survivor pension of 662⁄3%.

 

Pension benefits earnedprior to January 1, 1993 may be indexed at the discretion of management’spension committee, considering increases in the consumer price index. Pensionbenefits earned after December 31, 1992 are indexed annually between 0 and 5%based on the greater of:

 

·                  75% of the increase in theconsumer price index, less 1%; and

·                  25% of the increase in theconsumer price index.

 

**Pension Benefit Obligation**

 

At December31, 2009, as indicated in the notes to our Consolidated FinancialStatements, the:

 

·                  registered defined benefitpension plan’s accumulated benefit obligation (the projected benefitobligation, excluding future salary increases) was $211 million, which includesall active and inactive plan participants; and

·                  projected defined benefitobligation was $243 million.

 

The projected benefitobligation is an accounting-based value of the contractual entitlements thatwill change over time. The method used to determine this estimate will not beidentical to those used by others and, as a result, the estimate may not bedirectly comparable across companies. The key assumptions used for theprojected benefit obligation were:

 

·                  a discount rate of 6.5% peryear as at December 31, 2008;

·                  a discount rate of 6.0% peryear as at December 31, 2009;

·                  a long-term compensation rateincrease of 4% per year; and

·                  an assumed rate of inflation of2.5% per year.

 

To enhance the funded status of the registered definedbenefit pension plan, we contributed $52 million in special payments to theplan in 2009. As of December 31, 2009, the plan had a $21 million surplus.

 

**DEFINED CONTRIBUTION PENSION PLAN (US)**

 

Under this qualified retirement plan, Nexen providesparticipants with a profit sharing contribution equal to 6% of eligiblecompensation up to the Social Security taxable wage base and 11.5% of eligiblecompensation that exceeds the Social Security taxable wage base. For 2009, themaximum profit sharing contribution under the plan was $22,301. In addition, amatching contribution equal to 100% of employee contributions, to a maximum of6% of eligible compensation, is also available under the plan.Mr. Reinsborough defers compensation and receives an employer matchingcontribution to the full extent available under the plan.

 

The profit sharing contributions are subject to a two yearvesting schedule while the matching contributions vest immediately. Investmentdecisions are made by the plan participant from a variety of investmentoptions. The plan is intended to be an Employee Retirement Income Security Act(ERISA) 404(c) plan. One named executive (Mr. Reinsborough)participated in the plan during 2009.

 

**NON-QUALIFIED RESTORATION PLAN (US)**

 

This plan is intended to be an unfunded and non-qualifieddeferred compensation arrangement that provides deferred compensation benefitsto a select group of management or highly compensated employees. The plan isestablished and maintained for the purpose of providing benefits in excess ofapplicable legislative limits. The plan complies with Section 409A of theInternal Revenue Code.

 

Under the plan provisions, a maximum of 50% of base salaryand 100% of annual cash incentives may be deferred. Elections for the futuredistribution of benefits are required to be entered into upon the date of planparticipation. Any changes to distribution or deferral elections must becompliant with Section 409A of the Internal Revenue Code. Investmentdecisions are made by the plan participant from a variety of investmentoptions. During 2009, there were no distributions of assets toMr. Reinsborough.

 

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**EXECUTIVE BENEFIT PLAN**

 

The executive benefit plan is available to all Canadianemployees. It provides supplemental retirement benefits for either definedbenefit or defined contribution participants who have earned a retirement benefitin excess of the statutory limits, which varies by employees’ pensionelections. This allows employees to fully accrue a pension that is aligned withtheir earnings level and is competitive within our market. For defined benefitplan participants, any supplemental benefits will accrue and be paid monthly ina similar manner to the underlying defined benefit pension plan set out aboveon pages 181 to 182. For executives, the average of the annual cashincentive payments during the last three years of plan participation areincluded for benefit accrual purposes, based on the lesser of target bonus oractual bonus paid.

 

**Pension Benefit Obligation**

 

At December31, 2009, as indicated in the notes to our Consolidated FinancialStatements, the:

 

·                  projected benefit obligation forthe executive benefit plan was $76 million (which, consistent with accountingstandards, includes an assumption for future salary increases) for all activeand inactive plan participants; and

·                  accumulated benefit obligation(the projected benefit obligation, excluding future salary increases) for thedefined benefit plan was $65 million.

 

The key assumptions used for determining the projectedbenefit obligation under the executive benefit plan are the same as those usedfor the registered pension plan.

 

As of January 1, 2005, theexecutive benefit plan was amended to provide a supplemental pension allocationfor defined contribution pension plan participants who are impacted by annualstatutory contribution limits. In 2009, the sum of all supplemental allocationsfor eligible participants was $42,276 and is estimated to be $45,000 in 2010.

 

**Pension Benefit Security**

 

The pension expense for the executive benefit plan isaccounted for annually. Benefits are paid from Nexen’s cash flows and reducethe related pension liability. As liabilities under this plan are unfunded, alevel of protection is provided to participants through an irrevocable letterof credit. The letter of credit allows the plan to turn to the issuing bank forfunding the pension obligation if the company fails to meet its obligations.The cost of obtaining the letter of credit in 2009 for all plan participantswas $1,368,230.

 

**RETIREMENT BENEFITS**

 

All Nexen retirees are provided with retirement benefits thatconsist of a $5,000 life insurance policy and reimbursement for provincialhealth care premiums, if applicable.

 

**LOANS TO OFFICERS**

 

As set out in the corporate governance policy, we do not makeloans to officers. There are no loans outstanding from Nexen to any of its officers.

 

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**EXECUTIVEOFFICERS**

 

The board determines the term of office for each executiveofficer. Below are Nexen’s executive officers and significant employees,including prior offices and non-executive positions for each of them during thepast five years. Start dates with Nexen are indicated for officer and othersignificant employee positions.

 
| **Officer**(Age)           | ** ** | **Current  and Past Position(s)**                                                                                                                                                                                                                                                                                                                                                                                                                                                                         | ** ** | **Effective  Date of  Current Position** | ** ** | **Executive    Officer Since** | ** ** |
|----------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------|------------|--------------------------------|------------|
| Marvin F. Romanow (54)     |       | President and CEO and a  director.

Formerly: Executive VP and  CFO since June 1, 2001.                                                                                                                                                                                                                                                                                                                                                                                                         |       | January 1, 2009                |       | 1997                           | ** ** |
| Kevin J. Reinhart (51)     |       | 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                           | ** ** |
| Gary H. Nieuwenburg (51)   |       | Executive VP, Canada.

Formerly: Senior VP,  Synthetic Crude since November 1, 2007; VP, Synthetic Crude since  July 11, 2002.                                                                                                                                                                                                                                                                                                                                                        |       | May 1, 2009                    |       | 2001                           | ** ** |
| James T. Arnold  (50)      |       | Senior VP, Synthetic Crude.

Formerly: Division VP  Operations and Projects, Synthetic Oil since February 1, 2009;  Chief Operating Officer at OPTI Canada Inc. since October 13, 2005;  VP, Development at OPTI Canada Inc. since January 1, 2000.                                                                                                                                                                                                                         |       | July 16, 2009                  |       | 2009                           | ** ** |
| Brian C. Reinsborough (48) |       | 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                           | ** ** |
| Catherine J. Hughes (47)   |       | VP, Operational Services,  Technology and Human Resources.

Formerly: Division VP,  Operational Services, Technology and Human Resources since December 1,  2009; Division VP, Operational Services and Technology since  September 1, 2009; VP Oil Sands at Husky Oil Operations Ltd. since  October 1, 2007; VP Exploration and Production Services at Husky Oil Operations  Ltd. since September 1, 2005; President at Schlumberger Canada Ltd.  since February 1, 2001. |       | February 17, 2010                   |       | 2010                           | ** ** |
| Kim D. McKenzie (61)       |       | VP and Chief Information  Officer.

Formerly: Division VP,  Information Technology since January 1, 1992.                                                                                                                                                                                                                                                                                                                                                                                            |       | November 1, 2007               |       | 2007                           | ** ** |
| Kevin J. McLachlan (46)    |       | VP, Global Exploration.

Formerly: Division VP, Global  Exploration since July 1, 2009; Division VP, International Exploration  since August 1, 2008; Manager, Exploration, since  January 1, 2006; East Coast Exploration Manager at Imperial Oil  Resources since April 1, 2005; Planning Manager at ExxonMobil  Canada West, Production, since June 1, 2004.                                                                                              |       | February 17, 2010                   |       | 2010                           | ** ** |
| Eric B. Miller (47)        |       | 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 (45)          |       | VP, Corporate Planning and  Business Development.

Formerly: Treasurer since  July 11, 2002.                                                                                                                                                                                                                                                                                                                                                                                                    |       | January 16, 2009               |       | 1998                           | ** ** |
| Brendon T. Muller (41)     |       | Controller.

Formerly: Manager, Corporate  External Reporting since November 1, 2003.                                                                                                                                                                                                                                                                                                                                                                                                           |       | April 9, 2007                  |       | 2007                           | ** ** |
| J.  Michael Backus (39)    |       | 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                           | ** ** |
| Richard G. Jensen (56)     |       | Chief Operating Officer,  International Operations.

Formerly: Division VP,  International Production and Development since December 1, 2005;  Division VP, International Production and Operations since  October 1, 2004.                                                                                                                                                                                                                                                           |       | July 1, 2008                   |       | 20081                          | ** ** |

** **

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*1*                 While he is not an executiveofficer, he is an employee who is expected to make significant contributions tothe business of Nexen and, therefore, is considered a significant employee.

 

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**COMPENSATION EXCHANGE RATE**

 

The exchange rate used to convert US dollars to Canadiandollars is the 2009 average rate of 1.1568. Unless otherwise noted, all figuresare in Canadian dollars.

 

**SHARE SPLITS**

 

All grant prices and numbers granted have been adjusted toaccount for the May 2005 and May 2007 share splits.

 

**SUMMARY COMPENSATION TABLE**

 

To determine the next three highest paid officers after theCEO and CFO, we total their salary, estimated option-based award value,non-equity incentive plan compensation and all other compensation as shownbelow. Grants of TOPs and STARs are considered option-based awards underapplicable disclosure requirements. We do not award share-based awards ornon-equity incentive plan compensation under long-term incentive plans, asthese terms are used in applicable disclosure requirements.

 
| ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** | **Option-Based** | ** ** | ** **     | ** ** | ** **               | ** ** | ** **     | ** ** | ** **            | ** ** |
|---------------------------------|------------|------------|------------|------------|------------|------------------|------------|----------------|------------|--------------------------|------------|----------------|------------|-----------------------|------------|
| ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** | **TOPs/**        | ** ** | **Estimated**  | ** ** | **Non-Equity**           | ** ** | ** **     | ** ** | ** **            | ** ** | ** ** | ** ** |
| ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** | **STARs**        | ** ** | **TOPs/**      | ** ** | **Annual Incentive**     | ** ** | ** **     | ** ** | ** **            | ** ** | ** ** | ** ** |
| **Name and**                    | ** ** | ** ** | ** ** | ** ** | ** ** | **Awards****1**  | ** ** | **STARs**      | ** ** | **Plan**                 | ** ** | **Pension**    | ** ** | **All Other**         | ** ** | **Total** | ** ** |
| **Principal Position**          | ** ** | **Year**   | ** ** | **Salary** | ** ** | **(#)**          | ** ** | **Value****2** | ** ** | **Compensation****3, 4** | ** ** | **Value****5** | ** ** | **Compensation****6** | ** ** | **Compensation** | ** ** |
|                            |       |       |       |       |       |             |       |           |       |                     |       |           |       |                  |       |   |   |
| Marvin F.  Romanow,7       |       | 2009       |       | 1,100,000  |       | 550,000          |       | 5,351,775      |       | 429,000                  |       | 3,949,300      |       | 179,978               |       | 11,010,053 |   |
| President and CEO               |       | 2008       |       | 601,250    |       | 475,000          |       | 2,747,514      | 8          | 700,000                  |       | 317,800        |       | 119,016               |       | 4,485,580 |   |
|                            |       | 2007       |       | 566,250    |       | 180,000          |       | 1,533,060      |       | 330,000                  |       | 323,300        |       | 118,150               |       | 2,870,760 |   |
|                            |       |       |       |       |       |             |       |           |       |                     |       |           |       |                  |       |   |   |
| Kevin J.  Reinhart,9       |       | 2009       |       | 440,000    |       | 150,000          |       | 1,459,575      |       | 175,000                  |       | 381,300        |       | 124,438               |       | 2,580,313 |   |
| Senior VP and CFO               |       | 2008       |       | 365,000    |       | 130,000          |       | 733,964        | 10         | 300,000                  |       | 128,800        |       | 104,582               |       | 1,632,346 |   |
|                            |       | 2007       |       | 332,833    |       | 80,000           |       | 681,360        |       | 132,000                  |       | 190,300        |       | 103,922               |       | 1,440,415 |   |
|                            |       |       |       |       |       |             |       |           |       |                     |       |           |       |                  |       |   |   |
| Gary H.  Nieuwenburg,           |       | 2009       |       | 474,000    |       | 220,000          |       | 2,097,225      | 11         | 156,000                  |       | 624,300        |       | 56,552                |       | 3,408,077 |   |
| Executive VP,                   |       | 2008       |       | 416,500    |       | 100,000          |       | 542,080        |       | 365,000                  |       | 141,800        |       | 52,670                |       | 1,518,050 |   |
| Canada                          |       | 2007       |       | 360,667    |       | 100,000          |       | 851,700        |       | 191,000                  |       | 267,300        |       | 48,775                |       | 1,719,442 |   |
|                            |       |       |       |       |       |             |       |           |       |                     |       |           |       |                  |       |   |   |
| James T. Arnold,                |       | 2009       |       | 375,833    |       | 170,000          |       | 1,402,206      | 12         | 99,000                   |       | 87,300         |       | 238,747               | 13         | 2,203,086 |   |
| Senior VP,                      |       | 2008       |       | —     |       | —           |       | —         |       | —                   |       | —         |       | —                |       | — |   |
| Synthetic Crude                 |       | 2007       |       | —     |       | —           |       | —         |       | —                   |       | —         |       | —                |       | — |   |
|                            |       |       |       |       |       |             |       |           |       |                     |       |           |       |                  |       |   |   |
| Brian C.  Reinsborough,14  |       | 2009       |       | 416,453    |       | 100,000          |       | 1,069,242      |       | 113,368                  |       | 87,636         |       | 35,466                |       | 1,722,165 |   |
| Senior VP,                      |       | 2008       |       | 392,774    |       | 70,000           |       | 317,578        |       | 218,527                  |       | 77,589         |       | 29,342                |       | 1,035,810 |   |
| US Oil and Gas                  |       | 2007       |       | 324,465    |       | 70,000           |       | 641,015        |       | 130,052                  |       | 63,793         |       | 27,979                |       | 1,187,304 |   |

 

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*1*                 All named executives weregranted TOPs in 2009 with the exception of Mr. Reinsborough who receivedSTARs.

*2*                 Reflects the estimated fair valueunder the Black-Scholes pricing model of TOPs granted in the year. The keyassumptions of this valuation include current market price of Nexen’s stock,exercise price of the option, option term, risk-free interest rate, turnover,dividend yield of stock and volatility of stock return. The actual valuerealized will depend on the Nexen share price at the time of exercise. Theaccounting fair value is calculated using the intrinsic value method, which isthe difference between the current market price of the stock and the exerciseprice of the option. The difference between these valuation methods is the TOPsvalue included in this column as the intrinsic value was nil at year end.Management’s consultant provides the annual Black-Scholes value. There were noamendments to the exercise price of TOPs in 2009.

*3*                 Reflects the value of awardsearned in each year under Nexen’s annual cash incentive program. The awards arepaid in the following calendar year based on their salary on December 31of the previous year.

*4*                 For Mr. Romanow,Mr. Reinhart and Mr. Nieuwenburg, includes discretionary recognitionin 2008 for the acquisition of an additional interest in Long Lake from OPTI.

*5*                 Represents the current servicecost, plus changes in compensation in excess of actuarial assumptions, lessrequired member contributions to plan. Mr. Reinsborough’s value representsthe sum of company-provided contributions to the US qualified and non-qualifiedretirement plans.

*6*                 The total value of theperquisites portion of All Other Compensation provided to each named executiveis less than $50,000 and less than 10% of their annual salary. See the AllOther Compensation table on page 192 for details of these amounts.

*7*                 Mr. Romanow is a directorof Canexus and was paid fees of $34,000, received notional deferred trust unitsof Canexus valued at $25,950 and distributions on his trust units of $11,290 in2009. In 2008, he was paid fees of $34,000, received notional deferred trustunits of Canexus valued at $15,600 and distributions on his trust units of$6,399. In 2007, he was paid fees of $32,500, received notional deferred trustunits of Canexus valued at $19,560 and distributions on his trust units of$5,280. These amounts are included in the All Other Compensation table onpage 192.

*8*                 Reflects Mr. Romanow’sannual grant of 180,000 TOPs on December 8, 2008 with a grant date fairvalue of $975,744, and a grant of $295,000 TOPs he received upon appointment asPresident and CEO in January 2009 with a grant date fair value of $1,771,770.

*9*                 Mr. Reinhart is a directorof Canexus and was paid fees of $34,000, received notional deferred trust unitsof Canexus values at $25,950 and distributions on his trust units of $11,290 in2009. In 2008, he was paid fees of $34,000, received notional deferred trustunits valued at $15,600 and distributions on his trust units of $6,399. In2007, he was paid fees of $32,500, received notional deferred trust unitsvalued at $19,560 and distributions on his trust units of $5,280. These amountsare included in the All Other Compensation table on page 192.

*10*          Reflects Mr. Reinhart’sannual grant of 80,000 TOPs on December 8, 2008 with a grant date fairvalue of $433,664, and a grant of 50,000 TOPs he received upon appointment asSenior VP and CFO in January 2009 with a grant date fair value of$300,300.

*11*          Reflects Mr. Nieuwenburg’sannual grant of 170,000 TOPs on December 7, 2009 with a grant date fairvalue of $1,654,185, and a grant of 50,000 TOPs he received upon appointment asExecutive VP, Canada in May 2009 with a grant date fair value of $443,040.

*12*          Reflects Mr. Arnold’sannual grant of 100,000 TOPs on December 7, 2009 with a grant date fairvalue of $973,050, and a grant of 70,000 TOPs he received upon hire inFebruary 2009 with a grant date fair value of $429,156.

*13*          Mr. Arnold received a$200,000 special bonus upon hire.

*14*          Mr. Reinsborough’scompensation has been converted from US to Canadian dollars using the averageexchange rate for the applicable year; 1.1568 in 2009, 1.0660 in 2008 and1.0748 in 2007.

 

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**CHANGES IN COMPENSATION ARRANGEMENTS IN 2009**

 

We did not introduce any new compensation or benefit programin 2009 for Nexen’s named executives.

 

The compensation paid to named executives in 2009 isconsistent with our philosophy and objectives of targeting total compensationbetween the 50th and 75th percentile as detailed on pages 172 to 174.

 

**CHANGES IN PENSION OBLIGATIONS**

 

The Summary Compensation Table pension value reflects thecurrent service cost, less required member contributions to the plan, plus anychanges in obligations resulting from compensation increases in excess ofactuarial assumptions. Actual compensation changes may vary from the assumedrate of compensation increase and will vary among each executive from year toyear. These values differ from the termination values reported under the changeof control agreements on pages 194 to 195, which disclose additional lumpsum pension benefits provided if a change of control occurs.

 

**CEOCOMPENSATION AND 2009 OBJECTIVES AND ACHIEVEMENTS**

 

The CEO’s responsibility is to provide leadership in settingand achieving goals that create value for our shareholders in the short andlong term. Mr. Romanow’s 2009 annual cash incentive award was based on thecorporate results described on pages 175 to 176, which determined thetotal cash available for the awards. Cash incentive awards are determined fromthe available pool and distributed to individuals based on specific annualgoals. Based on the board’s assessment of Mr. Romanow’s achievement ofobjectives, and their assessment of his contribution to continued shareholdervalue growth and strategic plan execution, he was awarded an annual cashincentive of $429,000, which is his target bonus times 52%. Mr. Romanow’sobjectives for 2009 are outlined below, along with a summary of achievements ineach area.

 

**Executing our strategies**

 

In 2009, Mr. Romanow met this objective by refocusing onour key growth strategies, taking steps to streamline our portfolio andensuring that our core assets continued to perform well.

 

Our key growth strategies progressed well during 2009.

 

·                  At Long Lake, we demonstratedthat our technology works. The gasifier and upgrader are now producing thehighest quality synthetic crude in North America. We acquired an additional 15%of the project at 60% of sunk costs and assumed operatorship of the upgrader. 

·                  We achieved exploration successin the North Sea and offshore West Africa which positions us well for futureyears. We also were successful in bringing new production on stream in theNorth Sea and the Gulf of Mexico and in advancing development of Usan, offshoreWest Africa.

·                  Significant progress was madein our shale gas business by realizing significant cost savings andproductivity improvements through industry-leading completions.

 

**Enhancing financial capacity and maintaining ampleliquidity**

 

Our long standing belief in maintaining ample liquidity andfinancing long-term assets with long-term debt meant that we were wellpositioned when the economic recession started. As a result, we did notoverreact to the situation but continued to focus on advancing our corestrategies with a prudent capital program and ongoing cost managementpractices. Our crude oil put protection program provided us with protectionagainst falling oil prices without limiting our upside when prices rebounded. 

 

In July 2009, in the midst of ongoing market volatility,we successfully executed a US$1 billion bond issue to enhance our liquidity. Wegenerated strong operating cash flows during the year which, together withfinancing from our long-term credit facilities, were used to fund the purchaseof the Long Lake acquisition and our 2009 capital investment program.

 

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**Managing physical assets to achieve a balance ofshort-term returns and long-term sustainability.**

 

Under Mr. Romanow’s direction, we achieved strongperformance in our core assets including the UK, US, Yemen, Canada andColombia. While major milestones were achieved at Long Lake, challenges wereencountered that delayed the ramp up of the project. Difficulty in achievingconsistent steam production necessitated a turnaround in September, which hassince improved plant reliability and production.

 

**Attracting and retaining peopleto enhance our execution capabilities.**

 

We maintained a strong corporate culture underMr. Romanow’s leadership and has seen an increase in employee engagementduring the past year as measured by external benchmarking. Mr. Romanowalso focused on attracting world-class talent to our organization by hiringexperienced senior professionals with expertise in oil sands, shale gas anddeep water exploration.

 

**Achieving operational excellence and strongreturns from capital investment.**

 

Mr. Romanow led initiatives which resulted in excellencein safety performance, and operating and capital cost savings throughout thebusiness. In this context, our core producing assets continued to deliverstrong performance. Our capital investment program delivered strong resultswith proved reserve additions that were double our annual production (beforeroyalties and the adoption of the new SEC reserves rules).

 

**Ensuring Nexen’s continuingleadership position in “how we do business”.**

 

We remain fully committed to the highest standards of governance,integrity and social responsibility. Mr. Romanow’s personal involvementwith our various initiatives ensures these programs have broad visibility andare embedded into our corporate culture. 

 

**CEO LOOK-BACK**

 

In 2009, the Compensation Committee reviewed look-backinformation and analyzed Mr. Romanow’s total pay and shareholder valuecreated from the date he became CEO. In the analysis, dollar values wereassigned and tallied for each compensation component including salary, annualcash incentives, TOPs awards, benefits, pension and potential payments onchange of control. The Committee reviewed his total compensation relative toNexen’s market capitalization and that of industry peers for the CEO position.

 
| ** **                                        | ** ** | **2009**       | ** ** |
|---------------------------------------------------|------------|----------------|------------|
| **Cash**                                          |       |           |       |
| Base Salary                                       |       | 1,100,000      |       |
| Annual Cash Incentive                             |       | 429,000        |       |
| **Equity**                                        |       |           |       |
| Value of TOPs1                                    |       | 5,351,775      |       |
| **Total Direct  Compensation**                    | ** ** | **6,880,775**  | ** ** |
| All Other Compensation2                           |       | 179,978        |       |
| Pension Value3                                    |       | 3,949,300      |       |
| **Total  Compensation**                           | ** ** | **11,010,053** | ** ** |
| Total Market Capitalization Growth ($millions)    |       | 2,046          |       |
| Total Cost as a % of Market Capitalization Growth |       | 0.54           | %          |

 

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*1*                 Reflects the estimated fairvalue of TOPs using the Black-Scholes pricing model valued on the grant date.See note 2 on page 185 for details of this calculation.

*2*                 See page 192 for detailsof All Other Compensation.

*3*                 Represents the current servicecost, less required member contributions to the plan, plus changes incompensation in excess of actuarial assumptions.

 

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**INCENTIVEPLAN AWARDS**

 

To value incentive plan awards (TOPs/STARs), Nexen uses theBlack-Scholes pricing model, which is a generally accepted method for measuringthis type of long-term incentive. The actual value realized on exercises may behigher or lower depending on the Nexen share price at the time of exercise.

 

**INCENTIVE PLAN AWARDS GRANTED IN 2009**

 

The term for TOPs/STARs granted in 2009 is five years andvests one-third each year for three years starting one year after the grantdate. All named executives were granted TOPs in 2009 with the exception ofMr. Reinsborough who was granted STARs.

 
| ** **   | ** ** | ** **             | ** ** | **TOPs/  STARs**        | ** ** | **% of  Total TOPs**      | ** ** | **Exercise**   | ** ** | ** **          | ** ** | **Grant**             | ** ** | **Potential Realizable Value  at Assumed Annual Rates  of Share Price Appreciation  for 5 Year Term** | ** ** |
|--------------|------------|------------------------|------------|-------------------------|------------|---------------------------|------------|----------------|------------|---------------------|------------|-----------------------|------------|-------------------------------------------------------------------------------------------------------|------------|
| **Name**     | ** ** | **Grant Date**         | ** ** | **Granted****1****(#)** | ** ** | **Granted to  Employees** | ** ** | **Price  ($)** | ** ** | **Expiry Date**     | ** ** | **Value****3****($)** | ** ** | **5%  ($)**                                                                                           | ** ** | **10%  ($)** | ** ** |
| Romanow      |       | Dec. 7, 2009 |       | 550,000                 |       | 12.6                      | %          | 24.95          | 2          | Dec. 6, 2014   |       | 5,351,775             |       | 3,791,274                                                                                             |       | 8,377,723 |   |
| Reinhart     |       | Dec. 7, 2009      |       | 150,000                 |       | 3.4                       | %          | 24.95          | 2          | Dec. 6, 2014   |       | 1,459,575             |       | 1,033,984                                                                                             |       | 2,284,834 |   |
| Nieuwenburg  |       | May 1, 2009       | 4          | 50,000                  |       | 1.1                       | %          | 22.72          |       | April 30, 2014 |       | 443,040               |       | 313,856                                                                                               |       | 693,539 |   |
|         |       | Dec. 7, 2009      |       | 170,000                 |       | 3.9                       | %          | 24.95          | 2          | Dec. 6, 2014   |       | 1,654,185             |       | 1,171,848                                                                                             |       | 2,589,478 |   |
| Arnold       |       | Feb. 23, 2009     | 5          | 70,000                  |       | 1.6                       | %          | 15.72          |       | Feb. 22, 2014  |       | 429,156               |       | 304,020                                                                                               |       | 671,805 |   |
|         |       | Dec. 7, 2009      |       | 100,000                 |       | 2.3                       | %          | 24.95          | 2          | Dec. 6, 2014   |       | 973,050               |       | 689,322                                                                                               |       | 1,523,222 |   |
| Reinsborough |       | Dec. 7, 2009      |       | 100,000                 |       | —                    |       | US23.70        | 2          | Dec. 6, 2014   |       | 1,069,242             |       | 757,466                                                                                               |       | 1,673,803 |   |

 

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*1*                 All named executives weregranted TOPs in 2009, with the exception of Mr. Reinsborough who wasgranted STARs.

*2*                 Reflects the December 4,2009 closing market price of Nexen common shares on the TSX for TOPs grants andon the NYSE for the STARs grant.

*3*                 Reflects the estimated fairvalue of the TOPs/STARs at the time of grant using the Black-Scholes pricingmodel. See note 2 on page 185 for details.

*4*                 Mr. Nieuwenburg receivedthis grant upon his appointment as Executive VP, Canada. The exercise price isthe closing market price of Nexen common shares on the TSX on April 30,2009.

*5*                 Mr. Arnold received thisgrant upon hire. The exercise price is the closing market price of Nexen commonshares on the TSX on February 20, 2009.

* *

**INCENTIVE PLAN AWARDS—TOPS EXERCISED OREXCHANGED AND VALUE VESTED OR EARNED IN 2009**

 

The TOPs value realized in 2009 occurred within seven monthsof grant expiry, demonstrating that executives are holding TOPs for the longterm, in alignment with our long-term strategy. The TOPs value vested in 2009represents what could have been earned if named executives exercised TOPsimmediately upon vesting. As shown in the table, the TOPs awards vesting in2009 had some in-the-money value upon vesting. The actual value realized willdepend on the share price at the time of exercise. Grants of TOPs areconsidered option-based awards under applicable disclosure requirements. We donot award named executives share-based awards or non-equity incentive plancompensation under long-term incentive plans, as these terms are used inapplicable disclosure requirements.

 
| ** **   | ** ** | **TOPs Awards**                  | ** ** | **TOPs Awards**                 | ** ** | **Non-Equity Annual Incentive  Plan Compensation** | ** ** |
|--------------|------------|----------------------------------|------------|---------------------------------|------------|----------------------------------------------------|------------|
| **Name**     | ** ** | **Exercised or  Exchanged  (#)** | ** ** | **Value  Realized****1****($)** | ** ** | **Vested  in 2009  (#)**                           | ** ** | **Value Vested  in 2009****2****($)** | ** ** | **Value Earned  During the Year****3****($)** | ** ** |
| Romanow      |       | 228,000                          |       | 3,167,490                       |       | 173,400                                            |       | 294,984 |   | 429,000 |   |
| Reinhart     |       | 100,000                          |       | 1,275,750                       |       | 80,000                                             |       | 131,104 |   | 175,000 |   |
| Nieuwenburg  |       | 120,000                          |       | 1,377,900                       |       | 100,000                                            |       | 163,880 |   | 156,000 |   |
| Arnold       |       | —                           |       | —                          |       | —                                             |       | — |   | 99,000 |   |
| Reinsborough |       | 92,000                           |       | 1,057,145                       |       | 64,060                                             |       | 208,416 |   | 113,368 |   |
| **Total**    | ** ** | **540,000**                      | ** ** | **6,878,285**                   | ** ** | **417,460**                                        | ** ** | **798,384** | ** ** | **972,368** | ** ** |

 

----

*1*                 Reflects the closing marketprice at the time of the exercise or exchange, minus the exercise price, timesthe number of TOPs exercised or exchanged.

*2*                 Reflects the closing marketprice at the time of vesting, minus the exercise price, as defined in the TOPsplan. Most TOPs awards vesting in 2009 had an exercise price greater than themarket price. See table on page 189 for further details of the exercise pricesof TOPs vested.

*3*                 Represents compensation earnedin respect of 2009 and paid in 2010.

 

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**OUTSTANDING INCENTIVE PLAN AWARDS**

 
| ** **    | ** ** | ** **         | ** ** | ** **          | ** ** | ** **               | ** ** | ** **              | ** ** | **Vested and Unvested TOPs/  STARs at Dec. 31, 2009****1, 2**  | ** ** | **Vested TOPs/STARs  at Dec. 31, 2009****2** | ** ** |
|---------------|------------|--------------------|------------|---------------------|------------|--------------------------|------------|-------------------------|------------|---------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| **Name**      | ** ** | **Date Granted**   | ** ** | **Expiry Date**     | ** ** | **Exercise  Price  ($)** | ** ** | **Granted****3****(#)** | ** ** | **Number of  Securities  Underlying  Unexercised  TOPs/STARs  (#)** | ** ** | **Value of  Unexercised  TOPs/STARs****4****($)** | ** ** | **Number  (#)** | ** ** | **Value****4****($)** | ** ** |
| Romanow       |       | Dec. 12, 2000 |       | Dec. 11, 2010  |       | 9.025                    |       | 200,000                 |       | 200,000                                                             |       | 3,239,000                                         |       | 200,000 |   | 3,239,000 |   |
|          |       | Dec. 6, 2005  |       | Dec. 5, 2010   |       | 27.285                   |       | 124,000                 |       | 124,000                                                             |       | —                                            |       | 124,000 |   | — |   |
|          |       | Dec. 4, 2006  |       | Dec. 3, 2011   |       | 31.600                   |       | 160,000                 |       | 160,000                                                             |       | —                                            |       | 160,000 |   | — |   |
|          |       | Dec. 3, 2007  |       | Dec. 2, 2012   |       | 28.390                   |       | 180,000                 |       | 180,000                                                             |       | —                                            |       | 120,600 |   | — |   |
|          |       | Dec. 8, 2008  |       | Dec. 7, 2013   |       | 19.360                   |       | 180,000                 |       | 180,000                                                             |       | 1,054,800                                         |       | 61,200 |   | 358,632 |   |
|          |       | Jan. 2, 2009  |       | Jan. 1, 2014   |       | 21.450                   |       | 295,000                 |       | 295,000                                                             |       | 1,112,150                                         |       | — |   | — |   |
|          |       | Dec. 7, 2009  |       | Dec. 6, 2014   |       | 24.950                   |       | 550,000                 |       | 550,000                                                             |       | 148,500                                           |       | — |   | — |   |
| **Total**     | ** ** | ** **         | ** ** | ** **          | ** ** | ** **               | ** ** | **1,689,000**           | ** ** | **1,689,000**                                                       | ** ** | **5,554,450**                                     | ** ** | **665,800** | ** ** | **3,597,632** | ** ** |
| Reinhart      |       | Dec. 12, 2000 |       | Dec. 11, 2010  |       | 9.025                    |       | 80,000                  |       | 80,000                                                              |       | 1,295,600                                         |       | 80,000 |   | 1,295,600 |   |
|          |       | Dec. 6, 2005  |       | Dec. 5, 2010   |       | 27.285                   |       | 70,000                  |       | 70,000                                                              |       | —                                            |       | 70,000 |   | — |   |
|          |       | Dec. 4, 2006  |       | Dec. 3, 2011   |       | 31.600                   |       | 80,000                  |       | 80,000                                                              |       | —                                            |       | 80,000 |   | — |   |
|          |       | Dec. 3, 2007  |       | Dec. 2, 2012   |       | 28.390                   |       | 80,000                  |       | 80,000                                                              |       | —                                            |       | 53,600 |   | — |   |
|          |       | Dec. 8, 2008  |       | Dec. 7, 2013   |       | 19.360                   |       | 80,000                  |       | 80,000                                                              |       | 468,800                                           |       | 27,200 |   | 159,392 |   |
|          |       | Jan. 2, 2009  |       | Jan. 1, 2014   |       | 21.450                   |       | 50,000                  |       | 50,000                                                              |       | 188,500                                           |       | — |   | — |   |
|          |       | Dec. 7, 2009  |       | Dec. 6, 2014   |       | 24.950                   |       | 150,000                 |       | 150,000                                                             |       | 40,500                                            |       | — |   | — |   |
| **Total**     | ** ** | ** **         | ** ** | ** **          | ** ** | ** **               | ** ** | **590,000**             | ** ** | **590,000**                                                         | ** ** | **1,993,400**                                     | ** ** | **310,800** | ** ** | **1,454,992** | ** ** |
| Nieuwenburg   |       | Dec. 6, 2005  |       | Dec. 5, 2010   |       | 27.285                   |       | 80,000                  |       | 80,000                                                              |       | —                                            |       | 80,000 |   | — |   |
|          |       | Dec. 4, 2006  |       | Dec. 3, 2011   |       | 31.600                   |       | 100,000                 |       | 100,000                                                             |       | —                                            |       | 100,000 |   | — |   |
|          |       | Dec. 3, 2007  |       | Dec. 2, 2012   |       | 28.390                   |       | 100,000                 |       | 100,000                                                             |       | —                                            |       | 67,000 |   | — |   |
|          |       | Dec. 8, 2008  |       | Dec. 7, 2013   |       | 19.360                   |       | 100,000                 |       | 100,000                                                             |       | 586,000                                           |       | 34,000 |   | 199,240 |   |
|          |       | May 1, 2009   |       | April 30, 2014 |       | 22.720                   |       | 50,000                  |       | 50,000                                                              |       | 125,000                                           |       | — |   | — |   |
|          |       | Dec. 7, 2009  |       | Dec. 6, 2014   |       | 24.950                   |       | 170,000                 |       | 170,000                                                             |       | 45,900                                            |       | — |   | — |   |
| **Total**     | ** ** | ** **         | ** ** | ** **          | ** ** | ** **               | ** ** | **600,000**             | ** ** | **600,000**                                                         | ** ** | **756,900**                                       | ** ** | **281,000** | ** ** | **199,240** | ** ** |
| Arnold        |       | Feb. 23, 2009 |       | Feb. 22, 2014  |       | 15.720                   |       | 70,000                  |       | 70,000                                                              |       | 665,000                                           |       | — |   | — |   |
|          |       | Dec. 7, 2009  |       | Dec. 6, 2014   |       | 24.950                   |       | 100,000                 |       | 100,000                                                             |       | 27,000                                            |       | — |   | — |   |
| **Total**     | ** ** | ** **         | ** ** | ** **          | ** ** | ** **               | ** ** | **170,000**             | ** ** | **170,000**                                                         | ** ** | **692,000**                                       | ** ** | **—** | ** ** | **—** | ** ** |
| Reinsborough5 |       | Dec. 6, 2005  |       | Dec. 5, 2010   |       | US 23.605                |       | 50,000                  |       | 50,000                                                              |       | 18,799                                            |       | 50,000 |   | 18,798 |   |
|          |       | Dec. 4, 2006  |       | Dec. 3, 2011   |       | US 27.500                |       | 52,000                  |       | 52,000                                                              |       | —                                            |       | 52,000 |   | — |   |
|          |       | Dec. 3, 2007  |       | Dec. 2, 2012   |       | US 28.400                |       | 70,000                  |       | 70,000                                                              |       | —                                            |       | 46,900 |   | — |   |
|          |       | Dec. 8, 2008  |       | Dec. 7, 2013   |       | US 15.200                |       | 70,000                  |       | 70,000                                                              |       | 706,920                                           |       | 23,800 |   | 240,356 |   |
|          |       | Dec. 7, 2009  |       | Dec. 6, 2014   |       | US 23.700                |       | 100,000                 |       | 100,000                                                             |       | 26,606                                            |       | — |   | — |   |
| **Total**     | ** ** | ** **         | ** ** | ** **          | ** ** | ** **               | ** ** | **342,000**             | ** ** | **342,000**                                                         | ** ** | **752,325**                                       | ** ** | **172,700** | ** ** | **259,154** | ** ** |

 

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*1*                 Excludes grants that have beenfully exercised.

*2*                 The number and value ofunvested TOPs/STARs can be determined by subtracting the vested TOPs/STARs fromthe vested and unvested TOPs/STARs. The value of unvested TOPs/STARs can beconfirmed on page 195 in the Change of Control Table.

*3*                 Nexen common shares are issuedon exercise of TOPs on a one-for-one basis.

*4*                 The difference between theclosing market price of Nexen common shares on the TSX on December 31,2009 of $25.22 per share (US$23.93 on the NYSE) and the exercise price ofTOPs/STARs, times the number of TOPs/STARs. Where the exercise price exceedsthe market value per share, the value shown is zero.

*5*                 Mr. Reinsborough wasgranted STARs in 2009 and TOPs prior to 2009.

 

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**EQUITYOWNERSHIP AND CHANGES IN 2009**

 

The Compensation Committee approved revised share ownershipguidelines in December 2009. Share ownership under the new guidelines nolonger includes the net value of exercisable TOPs. Mr. Romanow’srequirement to hold three times his annual salary has been increased to fourtimes his annual salary under the new guidelines. Mr. Reinhart andMr. Nieuwenburg were required to hold two and a half times their annualsalary, and the remaining named executives are required to hold two times theirannual salary. Remaining vice presidents and other senior leaders are nowrequired to hold one times their annual salary.

 
| ** **   | ** ** | **December 31, 2008** | ** ** | **December 31, 2009** | ** ** | **Net Change** | ** ** | **Equity at Risk**    | ** ** |
|--------------|------------|----------------------------|------------|----------------------------|------------|----------------|------------|-----------------------|------------|
| **Name**     | ** ** | **Shares**                 | ** ** | **Shares**                 | ** ** | **Shares**     | ** ** | **Value****1****($)** | ** ** | **Multiple  of Salary****2** | ** ** |
| Romanow      |       | 186,635                    |       | 205,899                    |       | 19,264         |       | 5,192,773             |       | 5 |   |
| Reinhart3    |       | 46,040                     |       | 65,855                     |       | 19,815         |       | 1,660,863             |       | 4 |   |
| Nieuwenburg  |       | 77,016                     |       | 99,750                     |       | 22,734         |       | 2,515,695             |       | 5 |   |
| Arnold       |       | —                     |       | 5,319                      |       | —         |       | 134,145               |       | — | 4 |
| Reinsborough |       | 7,573                      |       | 17,793                     |       | 10,220         |       | 492,549               |       | 1 | 5 |
| **Total**    | ** ** | **317,264**                | ** ** | **394,616**                | ** ** | **72,033**     | ** ** | **9,996,025**         | ** ** | ** ** | ** ** |

 

----

*1*                 Equity at risk is the marketvalue of common shares using the closing market price of Nexen shares on theTSX on December 31, 2009 of $25.22 per share (US$23.93 on the NYSE).

*2*                 Reflects the equity at risk,divided by the named executive’s 2009 salary amount shown on page 185.

*3*                 Includes 1,581 shares held byspouse.

*4*                 Mr. Arnold became anofficer on July 16, 2009 and has five years to meet the guideline.

*5.*              Mr. Reinsborough met theprevious guideline and has three years to meet the revised guideline.

* *

**PENSION PLANBENEFITS**

 

All named executives, except Brian Reinsborough, are membersof Nexen’s registered defined benefit pension plan and executive benefit planand accrue a pension benefit at a 2% accrual rate. With this option, they mustcontribute 5% of pensionable earnings up to the maximum allowed under the *Canadian Income Tax Act*. See pages 181to 183 for details.

 

**PENSION VALUE EARNED AND BENEFIT OBLIGATIONCHANGES IN 2009**

 

Our reported values use actuarial assumptions and methodsthat are the same as those used to calculate pension obligations and therelated annual expense disclosed in our Consolidated Financial Statements. Asthe assumptions reflect our best estimate of future events, our reported valuesmay not be directly comparable to similar pension liability values disclosed byother companies.

 

The board must approve additional past service credits oraccelerated service credits. No accelerated service credits were authorized in2009. The notes to the table below show additional past service creditsauthorized by the board for the named executives who participate in theCanadian defined benefit pension plan and the executive benefit plan.

 

No benefit payments weremade to named executives in the last fiscal year.

 

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**DEFINED BENEFIT PLAN TABLE**

 
| ** **  | ** ** | **Years of**         | ** ** | **Annual Benefits Payable** | ** ** | **Accrued  Obligation at** | ** ** | **Compensatory**      | ** ** | **Non-Compensatory** | ** ** | **Accrued  Obligation at** | ** ** |
|-------------|------------|----------------------|------------|-----------------------------|------------|----------------------------|------------|-----------------------|------------|----------------------|------------|----------------------------|------------|
| **Name**    | ** ** | **Credited Service** | ** ** | **At Year End****1**        | ** ** | **At Age 65****2**         | ** ** | **Jan. 1, 2009** | ** ** | **Change****3**      | ** ** | **Change****4**            | ** ** | **Dec. 31, 2009** | ** ** |
| Romanow     |       | 22.50                | 5, 6       | 473,994                     |       | 706,110                    |       | 4,347,000             |       | 3,949,300            |       | 1,422,700                  |       | 9,719,000 |   |
| Reinhart    |       | 15.33                |       | 139,435                     |       | 277,931                    |       | 1,266,000             |       | 381,300              |       | 316,700                    |       | 1,964,000 |   |
| Nieuwenburg |       | 5.00                 | 7          | 127,936                     |       | 292,138                    |       | 1,142,000             |       | 624,300              |       | 293,700                    |       | 2,060,000 |   |
| Arnold      |       | 0.92                 | 8          | 7,374                       |       | 126,696                    |       | —                |       | 87,300               |       | 26,700                     |       | 114,000 |   |
| **Total**   | ** ** | ** **           | ** ** | **748,739**                 | ** ** | **1,402,875**              | ** ** | **6,755,000**         | ** ** | **5,042,200**        | ** ** | **2,059,800**              | ** ** | **13,857,000** | ** ** |

 

----

*1*                 All information as of December31, 2009. Represents the sum of the benefits accrued under the registered andexecutive benefit pension plans.

*2*                 Represents a value based onprojected years of credited service at a 2% accrual rate to age 65 and actualpensionable earnings used to calculate the benefit amount in the previouscolumn.

*3*                 Includes the 2009 currentservice cost, less required member contributions to the plan, plus changes incompensation in excess of actuarial assumptions. Disclosure of the valuationmethod and significant assumptions used may be found in the pension and otherpost-retirement benefits note 13 in our 2009 Consolidated Financial Statements.

*4*                 Reflects the impact of intereston prior year’s obligations, changes in discount rates used to measure theobligations and the impact of assumption and employee demographic changes.

*5*                 Ten years of additional pastservice credits were granted to Mr. Romanow by the board in 2001. This wasa competitive practice to recognize that he was at a certain level in hiscareer in 2001 when he was appointed to a new position.

*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 22.50 years of defined benefit pension plan service. A pensionbenefit, which is reflective of pensionable bonus, will also be based on 29.75years of service, which includes 7.25 years of defined contribution service.

*7*                 Mr. Nieuwenburg joined thedefined 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 5 years of defined benefit pension plan service. A pensionbenefit, which is reflective of pensionable bonus, will also be based on 28.58years of service, which includes the 23.58 years of defined contributionservice.

*8*                 Mr. Arnold joined thedefined benefit pension plan on February 1, 2009.

* *

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 31,2009; plus

·                  annual cash incentive paymentsat the lesser of the target bonus or actual bonus paid, averaged over the finalthree years of participation up to December 31, 2009.

 
| ** **  | ** ** | **Years of Credited Service** | ** ** | ** **             | ** ** | **Accrued Annual Pension Benefit****1** | ** ** | **Estimated Annual  Pension Benefit at Age 60****2** | ** ** |
|-------------|------------|-------------------------------|------------|------------------------|------------|-----------------------------------------|------------|------------------------------------------------------|------------|
| **Name**    | ** ** | **Up to  Dec. 31, 2004**      | ** ** | **From  Jan. 1, 2005** | ** ** | **Total**                               | ** ** | **Final  Average  Earnings**                         | ** ** | **Under the  Defined Benefit  Pension Plan** | ** ** | **Under the  Executive  Benefit Plan** | ** ** | **Under the  Defined Benefit  Pension Plan** | ** ** | **Under the  Executive  Benefit Plan** | ** ** |
| Romanow     |       | 17.50                         |       | 5.00                   |       | 22.50                                   |       | 1,095,833                                            |       | 30,556 |   | 443,438 |   | 45,316 |   | 551,990 |   |
| Reinhart    |       | 10.33                         |       | 5.00                   |       | 15.33                                   |       | 514,478                                              |       | 37,481 |   | 101,954 |   | 59,867 |   | 167,395 |   |
| Nieuwenburg |       | —                        |       | 5.00                   |       | 5.00                                    |       | 590,756                                              |       | 12,222 |   | 115,714 |   | 35,130 |   | 198,711 |   |
| Arnold      |       | —                        |       | 0.92                   |       | 0.92                                    |       | 410,000                                              |       | 2,241 |   | 5,133 |   | 26,815 |   | 59,660 |   |

 

----

*1*                 All information is as ofDecember 31, 2009.

*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 canreceive unreduced retirement benefits.

 

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**DEFINED CONTRIBUTION PLAN TABLE**

 

The following table represents the value of accumulatedpension assets within the registered defined contribution pension plan. Underthe terms of this plan, all benefits have been funded. The individuals wereentitled to benefits under this registered plan prior to being appointed toexecutive positions at Nexen. The individuals have no entitlements under anysupplemental defined contribution pension plan arrangement and there are noabove-market or preferential earnings provisions.

 

The two individuals are active participants of the definedbenefit pension plan and have not contributed to or received anycompany-provided benefits under the terms of this plan for more than five yearsas indicated in the notes below.

 
| **Name**     | ** ** | **Accumulated Value  at Jan. 1, 2009** | ** ** | **Compensatory****2** | ** ** | **Non-Compensatory** | ** ** | **Accumulated Value  at Dec. 31, 2009** | ** ** |
|--------------|------------|---------------------------------------------|------------|-----------------------|------------|----------------------|------------|----------------------------------------------|------------|
| Romanow1     |       | 331,641                                     |       | —                |       | 85,365               |       | 417,006                                      |       |
| Nieuwenburg2 |       | 410,801                                     |       | —                |       | 105,741              |       | 516,542                                      |       |

 

----

*1*                 Mr. Romanow joined thedefined benefit pension plan in 1997 after 7.25 years in the definedcontribution pension plan.

*2*                 Mr. Nieuwenburg joined thedefined benefit pension plan in 2005 after 23.58 years in the definedcontribution pension plan.

* *

**DEFINED CONTRIBUTION PLAN TABLE (US)**

 

The following table represents the value of the accumulatedpension assets, along with employer contributions, within the respectivequalified and non-qualified plans. Under these plans, there are no market orpreferential earnings provisions.

 
| **Name**     | ** ** | **Accumulated Value  at Jan. 1, 2009****1** | ** ** | **Compensatory****2** | ** ** | **Non-Compensatory****2** | ** ** | **Accumulated Value  at Dec. 31, 2009****3** | ** ** |
|--------------|------------|--------------------------------------------------|------------|-----------------------|------------|---------------------------|------------|---------------------------------------------------|------------|
| Reinsborough |       | 876,863                                          |       | 87,636                |       | 206,138                   |       | 1,170,637                                         |       |

 

----

*1*                 The exchange rate used toconvert US to Canadian dollars at the beginning of the year is theDecember 31, 2008 rate of 1.2246.

*2*                 The exchange rate used toconvert US to Canadian dollars during the year is the 2009 average rate for theyear of 1.1568.

*3*                 The exchange rate used to convertUS to Canadian dollars at the end of the year is the December 31, 2009rate of 1.0466.

* *

**ALL OTHERCOMPENSATION**

 

The total value of perquisites provided to any executive wasless than $50,000 and less than 10% of the named executive’s annual salary in2009. Certain perquisites shown below are at the maximum reimbursable amountavailable to executives. This maximum is often higher than what the namedexecutive actually claimed in the year. These perquisites are not available tothe broader employee population.

 
| ** **   | ** ** | **Perquisites**    | ** ** | **Other Compensation**      | ** ** | ** ** | ** ** |
|--------------|------------|--------------------|------------|-----------------------------|------------|------------|------------|
| **Name**     | ** ** | **Car  Allowance** | ** ** | **Other  Perquisites****1** | ** ** | **Total**  | ** ** | **Life  Insurance  Premiums****2** | ** ** | **Savings  Plan  Contributions** | ** ** | **Other Compensation** | ** ** | **Total** | ** ** | **Total All Other Compensation** | ** ** |
| Romanow      |       | 31,200             |       | 10,500                      |       | 41,700     |       | 1,038 |   | 66,000 |   | 71,240 | 3 | 138,278 |   | 179,978 |   |
| Reinhart     |       | 19,200             |       | 7,100                       |       | 26,300     |       | 498 |   | 26,400 |   | 71,240 | 3 | 98,138 |   | 124,438 |   |
| Nieuwenburg  |       | 19,200             |       | 7,100                       |       | 26,300     |       | 1,812 |   | 28,440 |   | — |   | 30,252 |   | 56,552 |   |
| Arnold       |       | 17,600             |       | 7,100                       |       | 24,700     |       | 1,062 |   | 12,985 |   | 200,000 | 4 | 214,047 |   | 238,747 |   |
| Reinsborough |       | 22,211             |       | 10,729                      |       | 32,940     |       | 2,526 |   | — | 5 | — |   | 2,526 |   | 35,466 |   |

 

----

*1*                 Represents a maximumreimbursement amount for financial counseling, luncheon club membership,medical exam and security monitoring. For Mr. Reinsborough, representsactual reimbursement for similar perquisites. For the CEO position only, thisalso includes a maximum reimbursement amount for a golf club membership.

*2*                 The life insurance premiumsprovided to the named executives is made available to all employees.

*3*                 Includes fees of $34,000, deferredtrust units of Canexus valued at $25,950 and distributions on trust units of$11,290.

*4*                 Mr. Arnold received a$200,000 special bonus upon hire in February 2009.

*5*                 Benefits previously classifiedas savings plan are now classified as pension.

 

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**TERMINATIONAND CHANGE OF CONTROL BENEFITS**

 

Nexen does not enter into employment service contracts.Depending on the conditions of termination, we treat executives and employeesas follows:

 
| **Event**                          | ** ** | **Action**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
|------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Resignation                        |       | ·                  All salary and benefit  programs cease

·                  Annual incentive bonus  is not paid

·                  TOPs/STARs 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/STARs 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  dependants and payout of any applicable insurance benefits

·                  Annual incentive bonus  paid on a pro-rata basis

·                  TOPs/STARs must be  exercised within 18 months

·                  Pension benefits  distributed to surviving spouse or to a designated beneficiary in the event  of no spouse                                                                     |
| Termination without  cause

  |       | ·                  All salary and benefit  programs cease

·                  TOPs/STARs 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/STARs must be  exercised on termination

·                  Pension paid as a  commuted value or deferred benefit                                                                                                                                                                                                                                                           |

** **

**PAYMENTS ON RESIGNATION**

 

There are no additional payments for named executives uponresignation. The following table discloses values that would have been providedin the normal course had they resigned effective December 31, 2009: i) thelump sum value of pension benefits accrued under the defined benefit pensionplan and executive benefit plan; and ii) the value of vested TOPs. If they areover the age of 55 and have at least 10 years of Nexen service, they are deemedto have retired and a lump sum pension benefit option is not available.

 
| **Name**      | ** ** | **Termination Scenario** | ** ** | **Pension** | ** ** | **Value of Vested TOPs****1, 2** | ** ** | **Total** | ** ** |
|---------------|------------|--------------------------|------------|-------------|------------|----------------------------------|------------|-----------|------------|
| Romanow       |       | Resignation              |       | 6,268,000   |       | 3,597,632                        |       | 9,865,632 |       |
| Reinhart      |       | Resignation              |       | 1,610,000   |       | 1,454,992                        |       | 3,064,992 |       |
| Nieuwenburg   |       | Resignation              |       | 1,410,000   |       | 199,240                          |       | 1,609,240 |       |
| Arnold        |       | Resignation              |       | 80,000      |       | —                           |       | 80,000    |       |
| Reinsborough3 |       | Resignation              |       | —      |       | 259,154                          |       | 259,154   |       |

 

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*1*                 Does not include unvestedTOPs/STARs which will vest according to the TOPs/STARs plan over 90 days forresignation.

*2*                 The difference between theclosing market price of a Nexen common share on the TSX at year end of $25.22(US$23.93 on the NYSE) and the exercise price of TOPs, times the number ofvested TOPs.

*3*                 Mr. Reinsborough does notparticipate in the defined benefit pension plan as he is employed in the US.

* *

The nature of our time-vested TOPs/STARs ensures thatretiring executives maintain a significant equity interest for at least 12month (last vesting period) after departure.

 

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**CHANGE OF CONTROL AGREEMENTS**

 

Nexen has entered into change of control agreements with eachof the named executives and other key executives. We recognize that theseexecutives are critical to Nexen’s ongoing business. Therefore, it is vital wework to retain the executives, protect them from employment interruption causedby a change of control and treat them in a fair and equitable manner.Consistent with industry standards for executives in similar circumstances,there are no restrictions on future employment or non-compete clauses in theagreements. Each year, the Compensation Committee reviews the estimatedpayments upon a change of control, including the termination value of pensionbenefits due under the defined benefit pension plan and executive benefit plan.

 

Mr. Romanow’s change of control agreement was amended inJanuary 2009 when he was appointed President and CEO. In the event of achange of control and subsequent termination of employment, Mr. Romanowwould be deemed to retire and his pension would commence upon the later of thecompletion of the severance period outlined below and the attainment of age 55,without any applicable early retirement reduction.

 

Under these agreements, a change of control includes anyacquisition of common shares or other securities that carries the right to castmore than 35% of the common share votes. Generally, it is any event thatresults in a person or group exercising effective control of Nexen.

 

If the named executives terminate following a change ofcontrol, they are entitled to salary, target bonus and other compensatorybenefits for the severance period specified below.

 
| ** **   | ** ** | **Severance Period in Months on Change of Control** | ** ** |
|--------------|------------|-----------------------------------------------------|------------|
| **Name**     | ** ** | **If Terminated**                                   | ** ** | **Upon Resignation****1** | ** ** |
| Romanow      |       | 36                                                  |       | 30 |   |
| Reinhart     |       | 24                                                  |       | — |   |
| Nieuwenburg  |       | 24                                                  |       | — |   |
| Arnold       |       | 24                                                  |       | — |   |
| Reinsborough |       | 24                                                  |       | — |   |

 

----

*1*                 Within 12 months after changeof control and only if the CEO has remained an employee.

* *

The next table outlines the estimated incremental paymentsnamed executives would be entitled to had a change of control and a subsequenttermination of employment occurred on December 31, 2009. Under theagreement, bonuses would be paid at target for the full severance period. Abenefits uplift, equal to 13% of base salary, would be provided in lieu ofmedical, dental and life insurance coverage. In addition, the agreementprovides a payment for other employee benefits and perquisites, including carallowance and savings plan contributions during the severance period, and anallowance for financial counselling, security monitoring and career transitionservices.

 

Named executives would also be entitled to an incrementalpension benefit relating to their salary, service and annual incentive targetsover the severance period. The pension value reported below discloses theresulting lump sum payout determined according to the named executive’s changeof control agreement. These additional pension benefits do not include anytermination benefits that would be payable under the registered defined benefitpension plan and executive benefit plan if a termination or retirement occurredthat was not triggered by a change of control.

 

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**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/STARs  Value****3** | ** ** | **Total  Incremental  Obligation** | ** ** |
|--------------|------------|-----------------------------------|------------|-----------------|------------|-------------------------|------------|----------------------|------------|-------------------------------|------------|--------------------------------------------------|------------|-----------------------------------------|------------|------------------------------------|------------|
| Romanow      |       | 36                                |       | 3,300,000       |       | 2,475,000               |       | 429,000              |       | 329,500                       |       | 16,188,000                                       |       | 1,956,818                               |       | 24,678,318                         |       |
| Reinhart     |       | 24                                |       | 880,000         |       | 440,000                 |       | 114,400              |       | 129,100                       |       | 2,037,000                                        |       | 538,408                                 |       | 4,138,908                          |       |
| Nieuwenburg  |       | 24                                |       | 1,000,000       |       | 600,000                 |       | 130,000              |       | 136,300                       |       | 2,721,000                                        |       | 557,660                                 |       | 5,144,960                          |       |
| Arnold       |       | 24                                |       | 840,000         |       | 378,000                 |       | 109,200              |       | 126,700                       |       | 535,000                                          |       | 692,000                                 |       | 2,680,900                          |       |
| Reinsborough |       | 24                                |       | 832,905         |       | 374,807                 |       | 108,278              |       | 77,159                        |       | 175,271                                          |       | 493,179                                 |       | 2,061,599                          |       |
| Total        |       |                              |       | **6,852,905**   | ** ** | **4,267,807**           | ** ** | **890,878**          | ** ** | **798,759**                   | ** ** | **21,656,271**                                   | ** ** | **4,238,065**                           | ** ** | **38,704,685**                     |       |

 

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*1*                 Assumes a triggering eventoccurred at December 31, 2009.

*2*                 Does not include regulartermination pension values which are reported in Payments on Resignation onpage 193. Benefits payable under the registered defined benefit pensionplan are funded from the pension trust and payable in the form of a monthlypension benefit if the named executive is 55 or older. ForMr. Reinsborough, the value does not include benefits presently residingin the qualified and non-qualified retirement plans.

*3*                 Value of TOPs/STARs thatautomatically vest on a change of control, based on the number of TOPs/STARswith accelerated vesting, times the closing market price of Nexen common shareson the TSX on December 31, 2009 of $25.22 (US$23.93 on the NYSE), less theexercise price. The incremental value is not in addition to the valueidentified in the vesting provision section of the termination chart onpage 193.

* *

**CORPORATEGOVERNANCE**

 

Nexen’s board takes its duties and responsibilities for goodcorporate governance seriously. Nexen supports and conducts business accordingto the rules of the Toronto Stock Exchange (TSX), NYSE, *NationalPolicy 58-201—Corporate Governance Guidelines**and**Multilateral Instrument 52-110—Audit Committees.*Except as noted below, Nexen’s corporate governance practices comply with thosefollowed by domestic companies under NYSE listing standards.

 

Nexen has a DSU plan for non-executive directors as describedon page 169. For this plan, Nexen follows the TSX rules which, unlikethe NYSE rules, exempt plans from shareholder approval where the common sharesissued under the plan are purchased on the open market rather than issuing newshares.

 

Annually, the CEO certifies to the NYSE that he is not awareof any violation by Nexen of the NYSE’s corporate governance listing standards.Our CEO has not had to provide any notification of non-compliance to the NYSE,since no executive officer is aware of any non-compliance with any applicableprovisions of section 303A of the NYSE listing standards. Nexen also providesthe required Annual Written Affirmation to the NYSE. As well, our CEO and CFOhave certified the quality of Nexen’s public disclosure to the SEC.

 

All Committee mandates, including those for the Audit,Compensation and Governance Committees, our code of ethics, and our corporategovernance policy and categorical standards are available at www.nexeninc.com,and we intend to provide disclosure in this manner. Shareholders wishing toreceive a copy of these documents may contact the Governance Office bytelephone at 403.699.4926, or by email at governance@nexeninc.com.

 

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**GOVERNANCECOMMITTEE REPORT**

 

The Governance Committee assists the board in overseeingimplementation of our corporate governance programs. It recommends nominees fordirector appointments and manages the evaluation process of the board, itscommittees and individual directors and chairs. This oversight ensures weimplement best-in-class governance practices relevant to an organization ofNexen’s size and complexity.

 

All Committee members are independent and knowledgeable onour corporate governance programs. Seven members are skilled or expert ingovernance and board experience or diversity—expertise most relevant to theCommittee’s mandate.

 

**CHANGES TO COMMITTEE MEMBERSHIP IN 2009**

 

Mr. Thomson, as Chair of the Committee, left upon hisretirement from the board and Mr. Bertram and Mr. Jackson joined inApril 2009.

 

**KEY ACTIVITIES IN 2009**

 

·                  Reviewed board committeecomposition, including consideration for committees that promote aknowledgeable and informed board.

·                  Recommended committeememberships in a manner that promotes issue exposure and knowledge developmenton key matters for the company.

·                  Reviewed the board chairsuccession plan.

·                  Recommended a revised IntegrityGuide.

·                  Recommended updates togovernance documents, including mandates for the board, individual directorsand all board committees (including amendments to more specifically delineateresponsibilities for assessing and addressing risk), the externalcommunications policy and the corporate governance policy.

·                  Received regular reports onmanagement’s dialogue with governance-related stakeholders.

·                  Continued advancement of theonline performance evaluation process by recommending new questions to furtherexplore the areas of: how the board acts when company performance targets arenot being met, risk management oversight, sustainability risk management, boardand CEO relations and financial understanding.

·                  Consulted with Dr. RichardLeblanc, Assistant Professor of Corporate Governance, York University, on theboard’s performance evaluations.

 

**THE BOARD AND COMMITTEES**

 

The Committee has determined that the board leadershipstructure is appropriate, given the specific characteristics and circumstancesof the company. The CEO and board chair positions are separate and the BoardChair is independent.

 

The Committee reviews board and committee membershipsannually, considering director independence, qualifications, 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.

 

**RISK MANAGEMENT OVERSIGHT**

 

The board regularly receives an assessment from management onkey risks facing Nexen, assessed by probability of occurrence and expectedmarket reaction. These risks and associated mitigation strategies are allocatedand reported upon to the appropriate committees and/or the full board accordingto their mandates. The Committee oversees the allocation of risks identified tothe appropriate committee or the full board. These risks include Long Lake projectexecution, the global recession (including the impact of commodity prices andcredit risk), concentration of cash flow from the Buzzard project, rigcommitments, marketing division performance, timing delay on capital projects,political and security risk in jurisdictions where we operate, environmentregulation, proximity of operations to urban centres, fiscal term certainty,development/project risk, operational risk, commodity price risk,reporting/disclosure risk and human resource risk.

 

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**NOMINATING A NEW DIRECTOR FOR ELECTION**

 

The Committee identifies and assesses candidates for boardappointment or nomination. Our forward-looking skills matrix identifies skillswith the greatest opportunity to strengthen the board.

 

Before recommending a new board candidate, the Committeeconsiders his or her performance, independence, competencies, financial acumen,skills and diversity. Character and behavioural qualities, includingcredibility, integrity and communication skills, are considered. The CommitteeChair and/or Board Chair meets with the candidate to discuss his or herinterest and ability to devote sufficient time and resources to the position.While the board does consider gender, ethnic background, geographic origin, andother personal characteristics when looking at diversity, it is the skills,experience, character and behaviour qualities that are most important indetermining the value which an individual could bring to the board. Prior tonomination, potential directors must disclose possible conflicts of interestwith Nexen, and background checks, as appropriate, are completed. Seewww.nexeninc.com for the individual director mandate.

 

The Committee requires the corporate secretary to maintain anevergreen list of potential directors whose skills complement the board andwhom the Committee would evaluate if the individual is available when anopening arises.

 

The Committee will also consider a board nominee recommendedby a shareholder. See page 199 for information on communicating with theboard.

 

**BOARD CHAIR TERM**

 

We have a well-established governance practice and guidelinefor a five-year rotation of the board and committee chairs. Ever since Nexenbecame a fully independent oil and gas company in 2000, we have rotated thesechair positions every five years. In 2009, the Committee discussed the end ofMr. Saville’s five-year term as board chair in 2010. The Committeeconsidered his strong leadership and Nexen’s current circumstances and decidedto extend the term for two more years. Francis Saville will remain the boardchair until 2012. When making this decision, the Committee considered the managementand board changes we have experienced in the past year and determinedcontinuity of the board chair is critical to our success and to maintaininggood corporate governance leadership.

 

Mr. Saville is committed to the success of Nexen and totop-tier corporate governance. He does an excellent job of enhancing boardeffectiveness and has diligently worked with the CEO to facilitate a smoothtransition since the CEO’s appointment at the start of 2009. There is greatvalue to continuity of leadership from Mr. Saville at this time, both tocomplete the CEO transition and to continue to lay a solid foundation of trustbetween the board and management. We continue to plan for board chairsuccession in 2012 and beyond.

 

**SAY ON PAY POLICY**

 

After careful consideration, we have decided not to adopt asay on pay policy (advisory vote on executive compensation) at this time. Webelieve we have governance and compensation practices in place that achievesubstantially the same results. The Canadian Coalition for Good Governance(CCGG) released a Model Shareholder Engagement and Say on Pay policy, whichNexen management commented on and discussed with them. As well, our Board Chairand the head of our compensation committee met with representatives of the CCGGin this regard. The CCGG ultimately released a final form of policy which wehave considered, but declined to adopt at this time. We believe we haveshareholder engagement and compensation disclosure practices that are top tier.Say on pay developments will be reviewed in the coming year as the form andsubstance of say on pay initiatives becomes clearer. For more details on ourcompensation practices, see the Compensation Discussion and Analysis onpage 172 to 183.

 

**PERFORMANCE EVALUATIONS**

 

The board and management work together to foster continuous,open and honest communication, where concerns are brought forward and dealtwith as they occur. In this spirit, the annual board evaluation is seen as anopportunity to review the past year and consider contributions, successes andopportunities for development. Visit www.nexeninc.com for a special report onour director evaluation process. This report describes the assessment processand the purpose of each of the six performance components, the four evaluationstools and the reporting and follow through process.

 

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Our six-part performance evaluation review, together with theskills matrix, are our primary tools 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 9.5years. Our retirement age is 75.

 

The Committee strengthened the online evaluation process in2009 by recommending new questions to further explore the areas of: how theboard acts when company performance targets are not being met, risk managementoversight, sustainability risk management, board and CEO relations and financialunderstanding. Additionally, questions were either expanded or added to reflectbest practices. The changes included: i) adding the assessment of compensationpolicies, procedures and practices; and ii) assessing performance metrics andrisk management relating to annual cash and long-term incentives.

 

The board rates its overall effectiveness on a 10-pointscale, where 10 is the best. The average rating of 8.9 in 2009 is consistentwith the 2008 average rating. A portion of this high score is attributed to theboard receiving concise materials and presentations, which provides sufficienttime for board discussion and inquiry. Even though this score shows a highdegree of effectiveness, we continually look for opportunities to improve boardvalue and processes in all areas of their oversight responsibilities.

 

**EXTERNAL RECOGNITION**

 

We received recognitionfor our governance practices during 2009.

 

·                  The Award of Excellence inCorporate Governance Disclosure in the 2009 Corporate Reporting Awards from theCanadian Institute of Chartered Accountants.

·                  Recognition from the CanadianCoalition for Good Governance for new best practices in shareholdercommunication and compensation disclosure.

·                  Current global rating of 10out of 10 from GovernanceMetrics International for governance practices anddisclosure.

·                  Ranked 8th, with a score of 86out of 100, in the Report on Business 2009 corporate governance rankings.

 

**COMMITTEE APPROVAL**

 

The Committee has reviewed and discussed the governancedisclosure in this document, including the information in the Directors section(pages 161 to 170). It has recommended to the board that the disclosure beincluded in the circular and, as appropriate, the Form 10-K.

 

**Submitted on behalf of the Governance Committee:**

 

Barry Jackson, Chair, Bob Bertram, Kevin Jenkins, AnneMcLellan, Eric Newell, Tom O’Neill, Francis Saville, John Willson

 

**ETHICS POLICY**

 

On January 1, 2010 we replaced our ethics policy with“How We Work: Our Integrity Guide” (our guide). Our guide provides improvedcommunication regarding expected behaviours and uses simplified language,real-life examples and Questions and Answers. It also includes an overview ofNexen’s 22 integrity-related policies, provides guidance for making ethicaldecisions and lists options for reporting concerns about business conduct.

 

Under our guide, all directors, officers and employees mustdemonstrate ethical business practices in all business relationships, withinand outside of Nexen. Employees are not permitted to commit an unethical,dishonest or illegal act or to instruct other employees to do so. Our guide hasbeen adopted as a code of ethics for our principal executive officer, principalfinancial officer and principal accounting officer or controller.

 

Any waivers from the provisions of our guide for a directoror executive officer must be approved by the audit committee and board anddisclosed to the public in accordance with regulatory requirements. Any waiversof the provisions of our guide for any employee may be made by Nexen’s chieflegal officer.

 

Our guide is available at www.nexeninc.com and if we amend orwaive any provision of it, it will be disclosed online. We also file our guideand any amendments to it on SEDAR at www.sedar.com. To request a copy of theguide, contact the Integrity Resource Centre by emailing integrity@nexeninc.comor calling 403.699.6789.

 

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**Reporting Concerns**

 

There are several ways that a stakeholder can report concernsabout Nexen’s business practices. These include contacting a member of Nexen’smanagement team, the Integrity Resource Centre, our integrity helpline or theChair of our Audit and Conduct Review Committee.

 

·                  Employees, customers,suppliers, partners, shareholders and other external stakeholders who have aconcern are encouraged to raise the matter with Nexen management or ourIntegrity Resource Centre by:

 
| -      | Mail:  | Nexen Inc.                            |   |   |
|--------|--------|---------------------------------------|--------|--------|
|   |   | 801 – 7th Avenue SW              |   |   |
|   |   | Calgary, Alberta, Canada  T2P 3P7     |   |   |
|   |   | Attention: Integrity  Resource Centre |   |   |
| *      | Email: | integrity@nexeninc.com                |   |   |
| (      | Phone: | 403.699.6789                          |   |   |

 

·                  Concerns may also bereported through the use of our integrity helpline, which is a secure reportingsystem operated by EthicsPoint, an independent third-party service provider.The helpline offers the option for anonymous reporting should the reporter wishto protect their identity. To learn more about our integrity helpline and forglobal, toll-free call numbers, visit www.nexeninc.com and click on the“Integrity Helpline” link at the top of the page. Alternatively you may accessthe helpline directly by:

 
| : | Online: | www.ethicspoint.com                          |   |   |
|---|---------|----------------------------------------------|--------|--------|
| ( | Phone:  | 1.866.384.4277  (toll-free in North America) |   |   |

 

·                  Specifically, if you wish toraise concerns about Nexen’s financial statements, accounting practices orinternal controls, and do not feel comfortable raising the matter using thereporting methods described above, you can make a report directly to the Chairof the Audit and Conduct Review Committee of Nexen’s board. The matter shouldbe documented and mailed to Nexen Inc. at the address provided above in anenvelope labeled: “To be opened by the Chair of the Audit and Conduct ReviewCommittee only”.

 

**COMMUNICATING WITH THE BOARD**

 

Shareholders may write to the board or any boardmember(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 many subjects. The board andmanagement have developed a process to manage inquiries so that the appropriatepersonnel respond to them.

 

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’soperations, policies or philosophies;

·                  commercial in nature; or

·                  not appropriate for the boardto consider.

 

All inquiries will receive a response from the board ormanagement. The Governance Office maintains a log of all correspondence sent toboard members. Directors may review the log at any time and request copies ofcorrespondence received.

 

**AUDITCOMMITTEE REPORT**

 

See page 201 for a full report on the Audit Committee.

 

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**ITEM 12.**

 

**Security Ownership of Certain Beneficial Ownersand Management and Related Stockholder Matters**

 

**SECURITYOWNERSHIP OF CERTAIN BENEFICIAL OWNERS**

 

Nexen’s common shares are the only class of votingsecurities. Based on information known to Nexen, the following table shows eachperson or group who beneficially owns (pursuant to SEC Regulations) more than5% of Nexen’s voting securities as at the date noted below.

 
| **Name and Address of Beneficial  Owner**                                                                    | ** ** | **# of Shares Beneficially Owned** | ** ** | **% of Shares Outstanding** | ** ** | **Effective Date**     | ** ** |
|--------------------------------------------------------------------------------------------------------------|------------|------------------------------------|------------|-----------------------------|------------|------------------------|------------|
| Jarislowsky, Fraser Limited1Suite 2005, 1010 Sherbrooke Street West   Montreal, Quebec, Canada, H3A 2R7 |       | 43,857,995                         |       | 8.39                        | %          | January 31,  2010 |       |

 

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*1*                 The beneficial owner has solevoting power over 38,196,468 shares, shared voting power over 5,661,527 sharesand sole power to dispose of all shares.

* *

**SECURITY OWNERSHIP OF MANAGEMENT**

 

At February 18, 2010, the following directors, certainexecutive officers, and all directors and executive officers as a groupbeneficially owned the following Nexen common shares:

 
| **Name of Beneficial Owner**                                     | ** ** | **Number of Shares****1** | ** ** | **Exercisable TOPs****2** | ** ** |
|------------------------------------------------------------------|------------|---------------------------|------------|---------------------------|------------|
| William B. Berry                                                 |       | —                    |       | —                    |       |
| Robert G. Bertram                                                |       | 16,000                    |       | —                    |       |
| Dennis G. Flanagan                                               |       | 31,264                    |       | 20,000                    |       |
| S. Barry Jackson                                                 |       | 72,000                    |       | —                    |       |
| Kevin J. Jenkins                                                 |       | 12,540                    |       | 60,000                    |       |
| A. Anne McLellan, P.C.                                           |       | 300                       |       | —                    |       |
| Eric P. Newell, O.C.                                             |       | 12,000                    |       | —                    |       |
| Thomas C. O’Neill                                           |       | 16,000                    |       | —                    |       |
| Marvin F. Romanow                                                |       | 206,875                   |       | 766,100                   |       |
| Francis M. Saville,  Q.C.                                        |       | 59,864                    |       | 60,000                    |       |
| John M. Willson                                                  |       | 15,055                    |       | —                    |       |
| Victor J. Zaleschuk                                              |       | 63,371                    |       | 140,000                   |       |
| Kevin J. Reinhart                                                |       | 66,235                    |       | 327,800                   |       |
| Gary H. Nieuwenburg                                              |       | 100,116                   |       | 281,000                   |       |
| James T. Arnold                                                  |       | 5,542                     |       | 23,800                    |       |
| Brian C. Reinsborough                                            |       | 17,895                    |       | 172,700                   |       |
| **All  Directors and Executive Officers as a Group**(23 persons) |       | **783,683**               | ** ** | **2,436,290**             |       |

 

----

*1*                 The number of shares held andTOPs exercisable by each beneficial owner represents less than 1% of the sharesoutstanding.

*2*                 Includes all TOPs exercisablewithin 60 days of February 18, 2010. All TOPs held by non-executivedirectors are vested.

* *

Under the terms of our TOPs plan, the board may grant optionsto officers and employees and, when previously allowed for, to directors. Nexendoes not receive any consideration when options are granted.

 

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**ITEM 13.**

 

**Certain Relationships and Related Transactions,and Director Independence**

 

**RELATED PARTYTRANSACTION**

 

As a Canadian foreign private issuer, Nexen provides thedisclosure required under Item 7.B. of Form 20-F dealing with “relatedparty transactions”. Nexen did not have any related party transactions in 2009as defined under that standard. Certain other transactions described belowwhich are not related party transactions, involving Nexen and certain of ourdirectors, were entered into in 2009.

 

**DIRECTORINDEPENDENCE**

 

Mr. Saville was a senior partner of Fraser MilnerCasgrain LLP (FMC), Barristers and Solicitors, Calgary, Alberta, until the endof January 2004. He has been counsel with the firm from February 1,2004 to January 31, 2010. FMC provided legal services to us in each of thelast five years. Mr. Saville does not solicit or participate in theseservices and did not receive any portion of the fees we pay to FMC, nor was hea partner or an employee of the firm. He is independent under our categoricalstandards.

 

Ms. McLellan has been counsel with Bennett Jones (BJ),Barristers and Solicitors, Edmonton, Alberta since June 27, 2006. BJprovided legal services to us in each of the last five years. Legal fees paidto BJ represent less than 6% of all legal fees paid by Nexen in 2009.Ms. McLellan does not solicit or participate in those services and doesnot receive any portion of the fees we pay to BJ, nor is she a partner or anemployee of the firm. She is independent under our categorical standards.

 

Legal fees paid to BJ represent less than 6%of all legal fees paid by Nexen in 2009.

 

Mr. Romanow is not independent as he is Nexen’sPresident and CEO.

 

**ITEM 14.**

 

**Principal Accounting Fees and Services**

 

**AUDITCOMMITTEE REPORT**

 

The Audit Committee assists our board in overseeing:

 

·                  the integrity of annual andquarterly financial statements;

·                  our compliance with accountingand finance-based legal and regulatory requirements;

·                  the independent auditor’squalifications and independence;

·                  the internal accounting systemand financial reporting controls established by management;

·                  performance of the internal andexternal audit process and independent auditor; and,

·                  implementation andeffectiveness of How We Work: Our Integrity Guide, which constitutes our codeof ethics, and related compliance programs.

 

The Committee is responsible for appointing (subject toshareholder approval), compensating and overseeing the independent registeredchartered accountant (IRCA). The IRCA is accountable to and reports directly tothe Committee, and understand that they must maintain an open and transparentrelationship with the Committee, which represents our shareholders.

 

All Committee members are independent and knowledgeable onour financial reporting controls, and internal and external audit processes.All members are skilled or expert in financial acumen, particularly financialaccounting, reporting requirements and internal controls—expertise mostrelevant to the Committee’s mandate.

 

Management is responsible for our internal controls andfinancial reporting process. The IRCA is responsible for independently auditingour: i) Consolidated Financial Statements according to Canadian and USgenerally accepted auditing standards and the standards of the Public CompanyAccounting Oversight Board (United States); and, ii) internal control overfinancial reporting according to the standards of the Public Company AccountingOversight Board. The Committee monitors and oversees these processes.

 

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**CHANGES TO COMMITTEE MEMBERSHIP IN 2009**

 

Mr. Thomson left the Committee upon his retirement fromthe board and Mr. Berry joined in April 2009.

 

**KEY ACTIVITIES FOR 2009**

 

·                  Reviewed and approved thequarterly Consolidated Financial Statements and reports on Form 10-Q.

·                  Met with management and theIRCA to review the December 31, 2009 Consolidated Financial Statements.

·                  Discussed the scope and resultof the external audit with the IRCA.

·                  Discussed matters required byCanadian and US regulators with the IRCA.

·                  Received written disclosuresfrom the IRCA required by US regulators.

·                  Discussed with the IRCA theirindependence.

·                  Oversaw the complianceactivities by management to report on the effectiveness of internal controlover financial reporting as at December 31, 2009.

·                  Approved the annual corporateaudit plan and reviewed quarterly progress updates.

·                  Reviewed management’s annualand quarterly SOX control assessments.

·                  Recommended to the board thatthe audited Consolidated Financial Statements be included in Nexen’s annualreport on Form 10-K for the year ended December 31, 2009, based onthe reviews and discussions referred to above.

·                  Recommended approval of theForm 10-K to the board.

·                  Reviewed updates on newaccounting and regulatory standards that affect Nexen, including progress onour transition to International Financial Reporting Standards.

·                  Approved a revised IntegrityGuide.

·                  Reviewed and approved thedecision to file an Annual Information Form in lieu of Form 10-K for2011.

 

**SECTIONS 302 AND 404 OF SARBANES-OXLEY**

 

Nexen is a voluntary filer of the Form 10-K in the US and hascomplied with the requirements of Sections 302 and 404 of Sarbanes-Oxley sinceDecember 31, 2004. Accordingly, Nexen is in compliance with *NationalInstrument 52-109—Certification**of Disclosure in Issuers’ Annual and Interim Filings*.In 2009, management assessed our disclosure controls and procedures and ourinternal control over financial reporting and concluded that they wereeffective as of December 31, 2009. The integrated audit report for 2009 isincluded in our Form 10-K.

 

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**IRCA ENGAGEMENT AND FEES BILLED**

 

Before Nexen or any subsidiary engages the IRCA foradditional audit or non-audit services, the Committee must approve theengagement. Since May 6, 2003, the Committee has approved all audit,audit-related, tax and other services provided by the IRCA. The Committeeconcludes that the services provided by the IRCA as described in “All OtherFees” below maintain that firm’s independence.

 
| **Type of Fee**                                                                                                                | ** ** | **Billed  in 2008** | ** ** | **Billed  in 2009** | ** ** | **Percentage  of Total  Fees Billed in 2009** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|---------------------|------------|-----------------------------------------------|------------|
| Audit Fees                                                                                                                     |       |                |       |                |       |                                          |       |
| For the integrated audit of Nexen’s consolidated  financial statements included in our annual report on Form 10-K    |       | 2,812,000           | 1          | 3,061,149           | **2**      |                                          |       |
| For the integrated audit of the consolidated  financial statements of Canexus3                                                 |       | 215,600             | 3          | 238,172             | 4          |                                          |       |
| For the first, second and third quarter reviews of  Nexen’s Consolidated Financial Statements included in Form 10-Qs |       | 110,000             |       | 117,000             |       |                                          |       |
| For the first, second and third quarter reviews of  the Consolidated Financial Statements of Canexus3                          |       | 45,000              |       | 45,000              |       |                                          |       |
| For comfort letters and submissions to commissions                                                                             |       | 3,000               |       | 130,000             |       |                                          |       |
| ** **                                                                                                                     | ** ** | ** **          | ** ** | ** **          | ** ** | ** **                                    | ** ** |
| **Total Audit  Fees**                                                                                                          | ** ** | **3,185,600**       | ** ** | **3,591,321**       | ** ** | **62**                                        | **%**      |
| Audit-Related Fees—Nexen and Canexus3                                                                                     |       |                |       |                |       |                                          |       |
| For the annual audits and quarterly reviews of  subsidiary financial statements and employee benefit plans                     |       | 1,144,700           |       | 1,786,308           |       |                                          |       |
| ** **                                                                                                                     | ** ** | ** **          | ** ** | ** **          | ** ** | ** **                                    | ** ** |
| **Total  Audit-Related Fees**                                                                                                  | ** ** | **1,144,700**       | ** ** | **1,786,308**       | ** ** | **30**                                        | **%**      |
| Tax Fees—Nexen and Canexus3                                                                                               |       |                |       |                |       |                                          |       |
| For tax return preparation assistance and  tax-related consultation                                                            |       | 139,800             |       | 151,269             |       |                                          |       |
| **Total Tax  Fees**                                                                                                            | ** ** | **139,800**         | ** ** | **151,269**         | ** ** | **3**                                         | **%**      |
| ** **                                                                                                                     | ** ** | ** **          | ** ** | ** **          | ** ** | ** **                                    | ** ** |
| **All Other  Fees**                                                                                                            | ** ** | **216,300**         | **5**      | **262,848**         | ** ** | **5**                                         | **%**      |
| **Total Annual  Fees**                                                                                                         | ** ** | **4,686,400**       | ** ** | **5,791,746**       | ** ** | **100**                                       | **%**      |

 

----

*1*                 Consulting of $936,000 tocomplete the 2007 audit and $1,876,000 to commence the 2008 audit.

*2*                 Consulting of $1,276,498 tocomplete the 2008 audit and $1,784,651 to commence the 2009 audit.

*3*                 Includes fees for CanexusIncome Fund, Canexus Limited Partnership and its subsidiaries.

*4*                 Consisting of $152,000 tocomplete the 2008 audit and $86,172 to commence the 2009 audit.

*5*                 Petroview NW Europesubscription.

* *

**EXTERNAL RECOGNITION AND VERIFICATION**

 

Nexen was recognized in 2008 and in 2009 with the Award ofExcellence for Corporate Reporting in the Oil and Gas category of the CorporateReporting Awards from the Canadian Institute of Chartered Accountants.

 

**COMMITTEE APPROVAL**

 

Based on the Committee’s discussions with management and theIRCA, and its review of both their representations, the Committee 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, 2009and that the Form 10-K be approved.

 

**Submitted on behalf of the Audit Committee:**

 

Tom O’Neill, Chair, Bill Berry, Barry Jackson, Kevin Jenkins,Eric Newell, John Willson

 

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**PART IV**

 

**ITEM 15.**

 

**Exhibits, Financial Statement Schedules**

 

**FINANCIALSTATEMENTS AND SCHEDULES**

 

Schedules and separate financial statements of subsidiariesare omitted because they are not required or applicable, or the requiredinformation is shown in the Consolidated Financial Statements or notes.

 

**EXHIBITS**

 

Exhibits filed as part of this report are listed below.Certain exhibits have been previously filed with the Commission and areincorporated in this Form 10-K by reference. Instruments defining therights of holders of debt securities that do not exceed 10% of Nexen’s consolidatedassets have not been included. A copy of such instruments will be furnished tothe Commission upon request.

 
| 2.2    | Agreement for the Sale and  Purchase 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).                                            |

 

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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).                                                                                                                                          |
|   |                                                                                                                                                                                                                                                                                                                                                                         |
| 4.58   | Second Supplemental  Indenture dated July 30, 2009 to the Trust Indenture dated May 4,  2007 between the Registrant and Deutsche Bank Trust Company Americas  pertaining to the issuance of US$300 million, 6.20% notes due 2019 and the  issuance of US$700 million, 7.50% notes due 2039 (filed as Exhibit 4.1  to Form 8-K dated July 30, 2009). |
|   |                                                                                                                                                                                                                                                                                                                                                                         |
| 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).                                                                  |

 

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| 10.56  | Tandem Option Plan amended  June 30, 2007. (filed as Exhibit 10.56 to Form 10-K for the  year ended December 31, 2008).                                                                                                                                                                        |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                               |
| 10.57  | Termination of Employment  and Retirement Agreement between the Registrant and Roger D. Thomas dated  May 12, 2009 (filed as Exhibit 10.57 to Form 10-Q for the  quarterly period ended June 30, 2009).                                                                                        |
|   |                                                                                                                                                                                                                                                                                                               |
| 10.58  | Pricing Agreement dated  July 27, 2009 among the Registrant and Banc of America Securities LLC,  BNP Paribas Securities Corp., Deutsche Bank Securities Inc., and HSBC  Securities (USA) Inc. as representatives of the Underwriters (filed as  Exhibit 10.1 to Form 8-K dated July 30, 2009). |
|   |                                                                                                                                                                                                                                                                                                               |
| 10.59* | Agreement Respecting  Change of Control with Brian C. Reinsborough dated February 29, 2008.                                                                                                                                                                                                                   |
|   |                                                                                                                                                                                                                                                                                                               |
| 10.60* | Agreement Respecting  Change of Control and Executive Benefit Plan Entitlements with James T.  Arnold dated November 12, 2009.                                                                                                                                                                                |
|   |                                                                                                                                                                                                                                                                                                               |
| 10.61* | Form of  Indemnification Agreement between the Registrant and Brian C. Reinsborough  and James T. Arnold.                                                                                                                                                                                                     |
|   |                                                                                                                                                                                                                                                                                                               |
| 11.1*  | Statement regarding the  Computation of Per Share Earnings for the three years ended December 31,  2009.                                                                                                                                                                                                      |
|   |                                                                                                                                                                                                                                                                                                               |
| 21.1*  | Subsidiaries of the  Registrant.                                                                                                                                                                                                                                                                                   |
|   |                                                                                                                                                                                                                                                                                                               |
| 23.1*  | Consent of Independent  Registered Chartered Accountants.                                                                                                                                                                                                                                                          |
|   |                                                                                                                                                                                                                                                                                                               |
| 23.2*  | Report of Third Party,  DeGolyer and MacNaughton (selected United Kingdom properties).                                                                                                                                                                                                                             |
|   |                                                                                                                                                                                                                                                                                                               |
| 23.3*  | Report of Third Party,  DeGolyer and MacNaughton (selected Yemen properties).                                                                                                                                                                                                                                      |
|   |                                                                                                                                                                                                                                                                                                               |
| 23.4*  | Report of Third Party,  DeGolyer and MacNaughton (selected Nigeria properties).                                                                                                                                                                                                                                    |
|   |                                                                                                                                                                                                                                                                                                               |
| 23.5*  | Consent of DeGolyer and  MacNaughton.                                                                                                                                                                                                                                                                              |
|   |                                                                                                                                                                                                                                                                                                               |
| 23.6*  | Report of Third Party,  McDaniel & Associates Consultants Ltd. (selected Canadian  properties).                                                                                                                                                                                                           |
|   |                                                                                                                                                                                                                                                                                                               |
| 23.7*  | Report of Third Party,  McDaniel & Associates Consultants Ltd. (Syncrude).                                                                                                                                                                                                                                |
|   |                                                                                                                                                                                                                                                                                                               |
| 23.8*  | Consent of  McDaniel & Associates Consultants Ltd.                                                                                                                                                                                                                                                        |
|   |                                                                                                                                                                                                                                                                                                               |
| 23.9*  | Report of Third Party,  Ryder Scott Company L.P. (selected Gulf of Mexico properties).                                                                                                                                                                                                                             |
|   |                                                                                                                                                                                                                                                                                                               |
| 23.10* | Consent of Ryder Scott  Company L.P.                                                                                                                                                                                                                                                                               |
|   |                                                                                                                                                                                                                                                                                                               |
| 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*  | Report 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.*

 

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**SIGNATURES**

 

Pursuant to the requirements of Section 13 or15(d) of the Securities Exchange Act of 1934, the Company has duly causedthis report to be signed on its behalf by the undersigned, thereunto dulyauthorized, on February 25, 2010.

 
| NEXEN INC.                                  |
|---------------------------------------------|
|                                        |
| By:                                         | /s/ Marvin F. Romanow |   |
| Marvin F. Romanow                           |
| President, Chief Executive  Officer         |
| and Director (Principal Executive  Officer) |

 

Pursuant to the requirements of the Securities Exchange Actof 1934, this report has been signed below by the following persons on behalfof the registrant and in the capacities indicated on February 25, 2010.

 
| /s/ Dennis G. Flanagan            |   | /s/ Victor J. Zaleschuk                            |
|-----------------------------------|--------|----------------------------------------------------|
| Dennis G. Flanagan,  Director     |   | Victor J. Zaleschuk,  Director                     |
|                              |   |                                               |
| /s/ S. Barry Jackson              |   | /s/ William B. Berry                               |
| S. Barry Jackson, Director        |   | William B. Berry, Director                         |
|                              |   |                                               |
| /s/ Kevin J. Jenkins              |   | /s/ Robert G. Bertram                              |
| Kevin J. Jenkins, Director        |   | Robert G. Bertram, Director                        |
|                              |   |                                               |
| /s/ A Anne McLellan,  Director    |   | /s/ Marvin F. Romanow                              |
| A. Anne McLellan, Director        |   | Marvin F. Romanow                                  |
|                              |   | President, Chief Executive  Officer                |
| /s/ Eric P. Newell                |   | and Director (Principal  Executive Officer)        |
| Eric P. Newell, Director          |   |                                               |
|                              |   | /s/ Kevin J. Reinhart                              |
| /s/ Thomas C. O’Neill        |   | Kevin J. Reinhart                                  |
| Thomas C. O’Neill,  Director |   | Senior Vice President and  Chief Financial Officer |
|                              |   | (Principal Financial  Officer)                     |
| /s/ Francis M. Saville            |   |                                               |
| Francis M. Saville,  Director     |   | /s/ Brendon T. Muller                              |
|                              |   | Brendon T. Muller                                  |
| /s/ John M. Willson               |   | Controller                                         |
| John M. Willson, Director         |   | (Principal Accounting  Officer)                    |
|                              |   |                                               |
|                              |   | /s/ Eric B. Miller                                 |
|                              |   | Eric B. Miller                                     |
|                              |   | Vice President, General  Counsel                   |
|                              |   | and  Secretary                                     |

 

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