Nexen Inc.
TSX : NXY
NYSE : NXY

Nexen Inc.

February 18, 2010 06:30 ET

Nexen Announces Strong Fourth Quarter and Annual Financial Results Together With Excellent Reserve Adds

CALGARY, ALBERTA--(Marketwire - Feb. 18, 2010) - In 2009 we made significant progress on our three corporate strategies relating to the Athabasca oil sands, Horn River shale gas, and conventional exploration and development. Strong proved reserve adds allowed us to replace over 200% of our production. During the year, we generated cash flow of $2.2 billion ($4.25/share) and earnings of $536 million ($1.03/share) driven by outstanding results in the fourth quarter. We achieved major milestones at our Long Lake oil sands project as we successfully brought the upgrader on stream. We are now creating our own fuel source and producing premium synthetic crude oil. In the Horn River, we moved our shale gas costs down. Our exploration program delivered significant discoveries and we brought new production on stream in the North Sea and the Gulf of Mexico. As we move into the new year, our priorities include the ongoing ramp up of Long Lake, building on the success of our Horn River shale gas program, the development of our offshore Usan project, and ongoing exploration and development in our core areas.

Recent highlights include:

- Fourth quarter cash flow of $836 million ($1.60/share), an increase of 50% over 2008

- Quarterly earnings of $259 million ($0.50/share)

- Quarterly production before royalties of 265,000 boe/d (235,000 boe/d after royalties), 13% higher than the average of the first three quarters of the year

- Excellent 2009 proved reserve adds of 184 million boe which replaces over 200% of our production

- Successful exploration well at Owowo, offshore West Africa

- Post turnaround, Long Lake has experienced its three best consecutive months of steaming and bitumen production; the upgrader is consistently processing 90% of bitumen feedstock



Three Months Ended Twelve Months Ended
December 31 December 31
----------------------------------------------
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Production (mboe/d)
Before Royalties 265 230 243 250
After Royalties 235 198 213 210
Net Sales 1,550 1,270 4,895 7,424
Cash Flow from Operations(1) 836 559 2,215 4,229
Per Common Share ($/share)(1) 1.60 1.08 4.25 8.04
Net Income (Loss) 259 (181) 536 1,715
Per Common Share ($/share) 0.50 (0.35) 1.03 3.26
Capital Investment(2)(3) 645 982 3,578 3,203


(1) For reconciliation of this non-GAAP measure, see Cash Flow from
Operations on pg. 13.
(2) Includes geological and geophysical expenditures.
(3) 2009 includes $755 million for the acquisition of an additional 15%
interest in Long Lake from our partner.


Financial Results-Strong Fourth Quarter

Strong fourth quarter production volumes combined with attractive oil prices, industry-leading cash netbacks and solid results from our marketing division generated cash flow of $836 million, almost 40% of our annual cash flow. WTI strengthened on renewed economic optimism and averaged US$76.19/bbl for the quarter compared to US$58.73/bbl a year ago. With 85% of our production weighted to oil, we continue to benefit from increasing oil prices. Our industry-leading cash netbacks are generated by our low-royalty production and low conventional operating costs which averaged $9.13/bbl. Net income for the quarter was $259 million compared to a loss of $181 million in 2008 which included impairment charges and marketing losses.

For the year we generated cash flow of $2.2 billion ($4.25/share) and earnings of $536 million ($1.03/share). Our results were lower than the previous year as WTI averaged US$61.80/bbl in 2009 compared to US$99.65/bbl in 2008. In addition, the impact of scheduled downtime at several of our facilities reduced production volumes for the year.

"We had a strong fourth quarter which has set us up well for 2010," commented Marvin Romanow, Nexen's President and Chief Executive Officer. "At Long Lake steam volumes are at record levels and we are steaming more wells than ever before. On the exploration and appraisal front, our Appomattox and Knotty Head wells in the Gulf of Mexico are progressing well. And in the Horn River area, our winter drilling campaign is underway."



Quarterly Production

Quarterly Production Quarterly Production
before Royalties after Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) Q4 2009 Q3 2009 Q4 2009 Q3 2009
----------------------------------------------------------------------------
North Sea 124 76 124 76
Yemen 45 49 26 28
Canada - Oil & Gas 37 38 31 34
Canada - Bitumen 9 6 9 6
United States 24 20 21 18
Other Countries 2 2 2 2
Syncrude 24 23 22 20
---------------------------------------------------
Total 265 214 235 184
---------------------------------------------------


The fourth quarter delivered our strongest quarterly production volumes since early 2008, averaging 265,000 boe/d (235,000 boe/d after royalties) compared to 214,000 boe/d (184,000 boe/d after royalties) in the previous quarter. This increase reflects more production in the North Sea from Ettrick and Telford as well as the start up of Longhorn in the Gulf of Mexico. In addition, we saw production return from scheduled downtime during the previous quarter for maintenance and turnaround activities at Buzzard, Scott/Telford, the Gulf of Mexico and Long Lake.

Buzzard continues to perform well and contributed 86,500 boe/d (200,000 boe/d gross) in the quarter. We expect our North Sea volumes to remain strong in 2010 with Buzzard producing at plateau rates, Ettrick ramping up and additional development drilling at Telford.



Annual Production

Annual Production Annual Production
before Royalties after Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) 2009 2008 2009 2008
----------------------------------------------------------------------------
North Sea 102 103 102 103
Yemen 50 56 30 31
Canada - Oil & Gas 38 38 32 30
Canada - Bitumen 8 4 8 4
United States 21 22 19 19
Other Countries 4 6 3 5
Syncrude 20 21 19 18
---------------------------------------------------
Total 243 250 213 210
---------------------------------------------------


Our annual production averaged 243,000 boe/d before royalties and was impacted by extended downtime during the year for maintenance and turnaround activities at Buzzard, Scott/Telford, the Gulf of Mexico, Syncrude and Long Lake. Fourth quarter volumes averaged 265,000 boe/d before royalties and reflects new production from a successful step-out well at Telford, the start up of Ettrick and Longhorn, and the ramp up of Long Lake.

In 2010, we expect our annual production to grow approximately 4% to 6%, assuming the midpoint of our guidance, and range from 230,000 to 280,000 boe/d (200,000 to 250,000 boe/d after royalties). This growth reflects a full year of production from Ettrick and Longhorn, and increasing volumes from Long Lake. At the high end of our guidance, our production growth would be as high as 15%. The low end includes the possibility of advancing the start up of the fourth platform at Buzzard which is currently scheduled for 2011. Advancement to 2010 would only be required if we see higher than expected levels of hydrogen sulphide. The downtime associated with advancing the start up could reduce annual volumes by 10,000 to 15,000 boe/d.

Our annual production grew from 210,000 boe/d to 213,000 boe/d, after royalties, reflecting increasing contributions from Long Lake. Over the last three years our production, after royalties, has grown at an average compound annual rate of 11%.

2009 Capital Investment and Reserves

We invested $2.8 billion on oil and gas activities and added 184 million boe of proved and 349 million boe of probable reserves, before the year-end transition to new SEC reserve rules (see footnote one to the table below). We are not carrying any proved or probable reserves for our discoveries in the Eastern Gulf, at Knotty Head or for our shale gas lands. A summary of our 2009 capital investment program and reserve additions are shown in the table below. Detailed tables can be found on pages 11 and 12 of this release.



2009 Annual Results
Proved Probable Total
Capital Reserve Reserve Reserve
Investment Production Additions Additions Additions
(Cdn$ millions) (mmboe) (mmboe) (mmboe) (mmboe)
----------------------------------------------------------------------------
Conventional
Exploration &
Production 1,649 80 70 13 83
Unconventional
- Oil Sands
(1)(2) 942 10 114 336 450
Unconventional
- Shale Gas 216 - - - -
-----------------------------------------------------
Total Oil and Gas 2,807 90 184 349 533
-----------------------------------------------------

(1) At December 31, 2009, new SEC reserve rules came into effect requiring
us to report our Long Lake oil sands resource as synthetic reserves
rather than bitumen. This reduced our total proved and probable
year-end reserves by 71 million bbls and 180 million bbls,
respectively, with 18 million bbls and 41 million bbls, respectively
relating to current year additions.
(2) Includes $419 million allocation for the acquisition of an additional
15% interest in Long Lake oil sands resource from our partner.


Our conventional reserve replacement ratio is the best in three years at approximately 90% and excludes any potential proved reserve additions relating to our discoveries in the Golden Eagle area, at Owowo, Vicksburg and Knotty Head.

"Our 2009 global exploration program was one of our most successful ever and resulted in a number of significant discoveries," stated Romanow. "We plan to build on this success in 2010 with an exploration program that includes drilling up to 15 exploration and appraisal wells. In the North Sea, we are targeting several exploration and appraisal wells including a high impact prospect west of Shetlands and a potential extension of Buzzard. In the Gulf of Mexico, we have matured a number of prospects and plan to drill up to four of them."

In the North Sea, we added 34 million boe of proved and 33 million boe of probable reserves. At Buzzard, we added 22 million boe of proved reserves. For the Golden Eagle area, we added 32 million boe of probables which brings our total booked probable reserves for this area to 50 million boe.

At Long Lake, we added 107 million bbls of proved and 336 million bbls of probable reserves. Following the acquisition of an additional 15% interest in the Long Lake project and joint venture lands, we increased our proved and probable reserves by 86 million bbls and 220 million bbls, respectively. In addition, core hole drilling and ongoing delineation of the reservoir increased our proved and probable reserves by 21 million bbls and 116 million bbls, respectively.

New SEC rules that came into effect at the end of the year require us to report our Long Lake oil sands resource as synthetic reserves rather than bitumen. This reduced our proved and probable year-end reserves by 71 million bbls and 180 million bbls, respectively. The reduction reflects the removal of asphaltenes from bitumen which we use as a fuel source in our steaming, upgrading and co-generation power processes.

Capital Program Review

North Sea

We invested $697 million in the North Sea last year including $214 million on exploration activities. As previously announced, our exploration program in the Golden Eagle area has generated exciting discoveries at Golden Eagle, Pink and Hobby. Estimates of gross contingent recoverable resource are 150 million boe or higher (over 55 million boe, net to us). To date, we have booked 50 million boe of probable reserves for this area. We expect to book proved reserves as we advance the field development plan, which is progressing. We expect development will support standalone facilities and be economic with oil prices significantly lower than they are currently. We have a 34% interest in both Golden Eagle and Hobby, and a 46% interest in Pink, and operate all three.

At Buzzard, we invested $232 million of which $104 million related to the construction of the fourth platform with the rest relating to ongoing development drilling. During the year we added 22 million boe of proved reserves here. 14 million boe are attributable to successful drilling and production performance which resulted in increases in both reservoir size and recovery factor. The remaining 8 million boe relate to positive economic revisions associated with improved oil prices.

In 2010, Buzzard will continue to be a significant contributor to our cash flow and production volumes. Assuming WTI of US$70/bbl, Buzzard will generate about $2.0 billion in pre-tax cash flow.

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

At Scott/Telford, we added 12 million boe of proved reserves largely as a result of successful development drilling at Telford which allowed us to almost double our production from the Scott platform. We see further upside in the area with opportunities for quick tiebacks and additional drilling is planned for 2010.

"In just over five years, we've gone from having no presence in the UK North Sea to being the second largest oil producer there," commented Romanow. "With no near-term decline expected at Buzzard, significant discoveries to develop and numerous exploration and appraisal wells to be drilled, we expect to advance our leading position with even more growth in the next five to ten years."

Yemen

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

Offshore West Africa

Development of the Usan field, offshore West Africa, is progressing well with first production expected in 2012. The development includes a FPSO with the ability to process 180,000 bbls/d (36,000 bbls/d net to us) and store up to two million barrels of oil. In 2009, our capital investment here focused on fabrication of the FPSO hull and topside facilities, subsea equipment, development drilling and completion of detailed engineering and procurement. In 2010, we expect to complete fabrication of the FPSO hull and most of the topsides. In addition, we will continue fabrication of subsea components, development drilling and well completion activities. We have a 20% interest in exploration and development on this block and Total E&P Nigeria Limited is the operator.

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

United States

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

We invested $91 million to complete the development of Longhorn which includes four sub-sea wells tied in to the ENI operated Corral platform. Production is approaching peak rates in excess of 200 mmcf/d gross (50 mmcf/d net to us). In 2009, we added 2 million boe of proved reserves and to date we have recognized 16 million boe of proved plus probable reserves here. We have a 25% non-operated working interest in Longhorn and ENI is the operator.

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

Elsewhere in the deep-water, we are drilling an appraisal well at Knotty Head with our contracted Ensco 8501 rig. The well spud in December and we expect results in the second quarter. To date, we have not booked any proved or probable reserves here. A second deep-water drilling rig is expected to arrive in mid 2010 which will allow us to start drilling more of our identified prospects.

Insitu Oil Sands - Long Lake

In 2009, we invested $755 million on the acquisition of an additional 15% interest in the Long Lake project and joint venture lands. This added 86 million bbls of proved and 220 million bbls of probable bitumen reserves. In addition, core-hole delineation activities on the first phase of Long Lake added 21 million bbls of proved bitumen reserves while lease delineation work on Phase 2 added 116 million bbls of probable bitumen reserves.

Syncrude

At Syncrude, we invested $87 million in 2009 and converted 7 million boe of probable reserves to proved reserves. In 2010, a coker turnaround is scheduled in the third quarter and we expect annual production of between 19,000 and 24,000 bbls/d before royalties.

Horn River Shale Gas

As conventional basins in Canada mature, we are focusing our investment on unconventional resource plays such as shale gas. In northeast British Columbia, we have a material shale gas position in the Horn River basin with a 100% working interest. This play has the potential to be one of the most significant shale gas plays in North America. In 2009, we invested approximately $216 million to drill, frac, complete and test wells, and build infrastructure. Substantial cost savings and productivity improvements were realized with this drilling and completion program. We took advantage of improved equipment utilization, drilled longer wells, initiated more fracs per well and maintained an industry-leading frac pace this summer of 26 fracs in 15 days while achieving a 100% success rate on our frac program.

In 2010, we plan to build on this success by drilling an eight-well pad which will have longer horizontal wells with more fracs (18 fracs per well) than our earlier programs. The wells will be drilled this winter and then fraced and completed with production commencing in the second half of the year. We expect to achieve shale gas volumes from this program of approximately 50 mmcf/d in 2011. This program sets up a potential capital investment plan consisting of an 18-well pad which could commence drilling later in 2010.

As previously announced, we estimate our Dilly Creek lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resource. Further appraisal activity is required before we can finalize these estimates, establish commerciality and book meaningful reserves.

"I am pleased with our progress at Horn River," said Romanow. "While we weren't looking for shale gas five years ago, today we have captured significant resource, with the potential to double our current proved reserves. With larger programs, increased well productivities and higher recovery factors we are successfully lowering unit costs and increasing returns."

Long Lake Update

The following update was provided on February 9, 2010:

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

The reservoir is responding to consistent steaming and bitumen production levels are increasing. Prior to the turnaround, which was completed late last year, we were only providing meaningful steam to about one third of our 91 wells. These wells are providing the majority of our bitumen production which averaged 13,600 bbls/d (gross) in the fourth quarter. The remaining wells have been cold for about a year and need to go through the circulation 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 SOR includes steam to the wells that are in the steam circulation stage and not yet producing bitumen, and wells early in their ramp up cycle. As our circulating wells start producing, we expect to see an increase in bitumen production rates with a corresponding decrease in SOR. The SOR of our producing wells is approximately 5.0, and includes well pairs recently converted to production that are in the early stages of ramp up. We continue to expect a long term SOR of 3.0 over the life of the project.

"Post turnaround, we have experienced our three best consecutive months of steaming and bitumen production, and we are building on this," said Romanow. "Now that we are in a position to provide consistent steam to the reservoir, we are focusing on optimizing steam injection and individual well performance. To advance well productivity, we have converted over 40% of our wells from gas lift to electric submersible pumping and expect to have about 80% converted by year end. This offers more flexibility to optimize steam injection and grow bitumen production."

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

Buzzard update

On February 16th, we identified an item requiring repair to the separator unit on the Buzzard platform. We are currently investigating the cause and have temporarily reduced production volumes to 30,000 to 50,000 boe/d (gross). Preliminary findings suggest that Buzzard will be operating at these reduced rates for the next several weeks. We will provide an update once our investigation is complete.

Disposition Update

As announced in December 2009, we have identified a number of non-core assets for possible disposal, including parts of our marketing business, our heavy oil assets in Western Canada and our interest in the Canexus chemicals business. We have entered into an agreement to sell our European gas and power marketing business and have opened data rooms for other parts of our marketing business. We are also in the process of opening data rooms for our heavy oil assets. We expect that the disposition of non-core assets could generate over $1 billion in the next 12 to 24 months with timing dependent on market conditions.

"Assets that are no longer aligned with our main areas of focus will be monetized to focus on our three core areas," said Romanow. "We have an excellent portfolio of opportunities with significant captured resource and will focus on these."

Quarterly Dividend

The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable April 1, 2010, to shareholders of record on March 10, 2010. Shareholders are advised that the dividend is an eligible dividend for Canadian Income Tax purposes.

Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are uniquely positioned for growth in the North Sea, Western Canada (including the Athabasca oil sands of Alberta and unconventional gas resource plays such as shale gas), deep-water Gulf of Mexico, offshore West Africa and the Middle East. We add value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity, governance and environmental protection.

Information on our previously announced contingent recoverable shale gas and Golden Eagle area resource were provided in our press releases dated April 22, 2008 and September 3, 2009 respectively. Information with respect to forward-looking statements and cautionary notes is set out below.

Conference Call

Marvin Romanow, President and CEO, and Kevin Reinhart, Senior Vice President and CFO, will host a conference call to discuss our fourth quarter and year end financial and operating results and expectations for the future.



Date: February 18, 2010
Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time)

To listen to the conference call, please call one of the following:

416-695-6616 (Toronto)
800-766-6630 (North American toll-free)
800-4222-8835 (Global toll-free)

A replay of the call will be available for two weeks starting at 9:00 a.m.
Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053
(toll-free) passcode 8278506 followed by the pound sign.

A live and on demand webcast of the conference call will be available at
www.nexeninc.com.


Forward-Looking Statements

Certain statements in this report constitute "forward-looking statements" (within the meaning of the United States Private Securities Litigation Reform Act of 1995) or "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements or information (together "forward-looking statements") are generally identifiable by the forward-looking terminology used such as "anticipate", "believe", "intend", "plan", "expect", "estimate", "budget", "outlook", "forecast" or other similar words and include statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil, natural gas or chemicals prices, future production levels, future capital expenditures and their allocation to exploration and development activities, future earnings, future asset acquisitions or dispositions, future sources of funding for our capital program, future debt levels, availability of committed credit facilities, possible commerciality, development plans or capacity expansions, future ability to execute dispositions of assets or businesses, future sources of liquidity, cash flows and their uses, future drilling of new wells, ultimate recoverability of current and long-term assets, ultimate recoverability of reserves or resources, expected finding and development costs, expected operating costs, future cost recovery oil revenues from our Yemen operations, future demand for chemicals products, estimates on a per share basis, future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and dates by which certain areas will be developed, come on stream, or reach expected operating capacity and changes in any of the foregoing are forward-looking statements. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas and chemicals products; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; volatility in energy trading markets; foreign-currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; and political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management's future course of action would depend on our assessment of all information at that time.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to Items 1A and 7A in our 2008 Annual Report on Form 10-K for further discussion of the risk factors.

Cautionary Note to US Investors

In this disclosure, we may refer to "recoverable reserves", "recoverable resources" and "recoverable contingent resources" which are inherently more uncertain than proved reserves or probable reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Report on Form 10-K available from us or the SEC for further reserve disclosure.

Cautionary Note to Canadian Investors

Nexen is an SEC registrant and a voluntary Form 10-K (and related forms) filer. Therefore, our reserves estimates and securities regulatory disclosures follow SEC requirements. In Canada, National Instrument 51-101-Standards of Disclosure for Oil and Gas Activities (NI 51-101) prescribes that Canadian companies follow certain standards for the preparation and disclosure of reserves and related information. Nexen's reserves disclosures are made in reliance upon exemptions granted to it by Canadian securities regulators from certain requirements of NI 51-101 which permits us to:

- prepare our reserves estimates and related disclosures in accordance with SEC disclosure requirements, generally accepted industry practices in the US and the Canadian Oil and Gas Evaluation Handbook (COGE Handbook) standards modified to reflect SEC requirements;

- substitute those SEC disclosures for much of the annual disclosure required by NI 51-101; and

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

As a result of these exemptions, Nexen's disclosures may differ from other Canadian companies and Canadian investors should note the following fundamental differences in reserves estimates and related disclosures contained in the Form 10-K:

- SEC registrants apply SEC reserves definitions and prepare their reserves estimates in accordance with SEC requirements and generally accepted industry practices in the US whereas NI 51-101 requires adherence to the definitions and standards promulgated by the COGE Handbook;

- the SEC's technical rules in estimating reserves differ from NI 51-101 in areas such as the use of reliable technology, aerial extent around a drilled location, quantities below the lowest known oil and quantities across an undrilled fault block;

- the SEC mandates disclosure of proved reserves and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein calculated using the year's 12-month average prices and costs only whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecast prices;

- the SEC mandates disclosure of reserves by geographic area only whereas NI 51-101 requires disclosure of more reserve categories and product types;

- the SEC prescribes certain information about proved and probable undeveloped reserves and future developments costs whereas NI 51-101 requirements are different;

- the SEC does not require disclosure of finding and development (F&D) costs per boe of proved reserves additions whereas NI 51-101 requires that various F&D costs per boe and additional information be disclosed;

- the SEC leaves the engagement of independent qualified reserves consultants to the discretion of a company's board of directors whereas NI 51-101 requires issuers to engage such evaluators;

- the SEC does not allow proved and probable reserves to be aggregated whereas NI 51-101 requires issuers disclose such; and

- the reserves disclosures in this document have not been reviewed by the independent qualified reserves consultants whereas NI 51-101 requires them to review it.

The foregoing is a general description of the principal differences only. The differences between SEC requirements and NI 51-101 may be material.

NI 51-101 requires that we make the following disclosures:

- we use oil equivalents (boe) to express quantities of natural gas and crude oil in a common unit. A conversion ratio of 6 mcf of natural gas to 1 barrel of oil is used. Boe may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead; and

- because reserves data are based on judgments regarding future events actual results will vary and the variations may be material. Variations as a result of future events are expected to be consistent with the fact that reserves are categorized according to the probability of their recovery.

Resources

Nexen's estimates of contingent resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe contingent resources as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Such contingencies may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program results, drilling and completions optimization, stakeholder and regulatory approval of future drilling and infrastructure plans, access to required infrastructure, economic fiscal terms, a lower level of delineation, the absence of regulatory approvals, detailed design estimates and near-term development plans, and general uncertainties associated with this early stage of evaluation. The estimated range of contingent resources reflects conservative and optimistic likelihoods of recovery. However, there is no certainty that it will be commercially viable to produce any portion of these contingent resources.

Nexen's estimates of discovered resources (equivalent to discovered petroleum initially-in-place) are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe discovered resources as those quantities of petroleum estimated, as of a given date, to be contained in known accumulations prior to production. Discovered resources do not represent recoverable volumes. We disclose additional information regarding resource estimates in accordance with NI 51-101. These disclosures can be found on our website and on SEDAR.

Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.



Nexen Inc.
2009 Reserve Continuity Table
----------------------------------------------------------------------------
North Sea Yemen Other Intl US
--------------------------------------------------
Mmboe Oil Gas Oil Oil Oil Gas
----------------------------------------------------------------------------
PROVED RESERVES (1)
Dec 2008 172 3 31 34 20 29

Extensions & Discoveries 19 1 - 8 1 2
Acquisitions (3) - - - - - -
Revisions 14 - 12 2 5 1
--------------------------------------------------
Net Additions 33 1 12 10 6 3

Production (36) (1) (20) (1) (4) (4)
--------------------------------------------------
169 3 23 43 22 28

SEC Rule
Transition:(2)
Prior Years - - - - - -
Current Year - - - - - -
--------------------------------------------------
Dec 2009 169 3 23 43 22 28
--------------------------------------------------

PROBABLE RESERVES (1)
Dec 2008 132 4 13 61 8 16

Extensions, Discoveries
& Conversions 24 6 (7) (4) (1) 2
Acquisitions (3) - - - - - -
Revisions 3 - (2) (12) - (1)
--------------------------------------------------
Net Additions 27 6 (9) (16) (1) 1
--------------------------------------------------
159 10 4 45 7 17

SEC Rule
Transition:(2)
Prior Years - - - - - -
Current Year - - - - - -
--------------------------------------------------
Dec 2009 159 10 4 45 7 17
--------------------------------------------------

PROVED + PROBABLE
RESERVES (1)
Dec 2008 304 7 44 95 28 45

Extensions & Discoveries 43 7 (7) 4 - 4
Acquisitions (3) - - - - - -
Revisions 17 - 10 (10) 5 -
--------------------------------------------------
Net Additions 60 7 3 (6) 5 4

Production (36) (1) (20) (1) (4) (4)
--------------------------------------------------
328 13 27 88 29 45

SEC Rule
Transition:(2)
Prior Years - - - - - -
Current Year - - - - - -
--------------------------------------------------
Dec 2009 328 13 27 88 29 45
--------------------------------------------------



----------------------------------------------------------------------------
Canada
----------------------------------------------------------------------------
Other Long Lake Syncrude Total
----------------------------------------------------------------------------
Bitumen/
Mmboe Oil Gas Synthetic(2) Synthetic Oil and Gas
----------------------------------------------------------------------------
PROVED RESERVES(1)
Dec 2008 26 64 285 324 988

Extensions
& Discoveries 1 3 25 7 67
Acquisitions(3) - - 86 - 86
Revisions 15 (14) (4) - 31
---------------------------------------------------------
Net Additions 16 (11) 107 7 184

Production (5) (9) (3) (7) (90)
---------------------------------------------------------
37 44 389 324 1,082

SEC Rule
Transition:(2)
Prior Years - - (53) - (53)
Current Year - - (18) - (18)
---------------------------------------------------------
Dec 2009 37 44 318 324 1,011
---------------------------------------------------------

PROBABLE RESERVES(1)
Dec 2008 13 23 732 46 1,048

Extensions,
Discoveries &
Conversions 7 - 152 - 179
Acquisitions(3) - - 220 - 220
Revisions 7 (9) (36) - (50)
---------------------------------------------------------
Net Additions 14 (9) 336 - 349
---------------------------------------------------------
27 14 1,068 46 1,397

SEC Rule
Transition:(2)
Prior Years - - (139) - (139)
Current Year - - (41) - (41)
---------------------------------------------------------
Dec 2009 27 14 888 46 1,217
---------------------------------------------------------

PROVED + PROBABLE
RESERVES(1)
Dec 2008 39 87 1,017 370 2,036
Extensions &
Discoveries 8 3 177 7 246
Acquisitions(3) - - 306 - 306
Revisions 22 (23) (40) - (19)
---------------------------------------------------------
Net Additions 30 (20) 443 7 533

Production (5) (9) (3) (7) (90)
---------------------------------------------------------
64 58 1,457 370 2,479

SEC Rule
Transition:(2)
Prior Years - - (192) - (192)
Current Year - - (59) - (59)
---------------------------------------------------------
Dec 2009 64 58 1,206 370 2,228
---------------------------------------------------------

(1) We internally evaluate all of our reserves and have at least 80% of our
proved and probable reserves assessed by independent qualified
consultants each year; 98% of each were assessed this year. Our
reserves are also reviewed and approved by our Board of Directors.
Reserves represent our working interest before royalties using SEC
rules. New pricing rules require the use of average 2009 prices held
constant and were applied to our reserve calculations. Gas is converted
to equivalent oil at a 6:1 ratio.
(2) Reflects adoption of new SEC rules at December 31, 2009 which resulted
in Long Lake reserves being disclosed as synthetic rather than
bitumen barrels; shrinkage reflects internal fuel.
(3) Reflects acquisition of additional 15% interest in Long Lake from
our partner.



Nexen Inc.
2009 Capital Investment Table(1)

(Cdn$ millions)
----------------------------------------------------------------------------
North Other US
Sea(2) Yemen International(3)
----------------------------------------------------------------------------
Core Asset Development 326 69 4 16
Major Development 128 - 467 112
Early-stage Development - - - -
Exploration 214 - 28 193
Proved Property
Acquisition(4) - - - -
----------------------------------------------------
Total Oil and Gas
Investment 668 69 499 321
Long Lake Upgrader(5) - - - -
Marketing, Corporate,
Chemicals and Other - - - -
Capitalized Interest 29 - 19 -
----------------------------------------------------------------------------
Total Capital Investment 697 69 518 321
----------------------------------------------------------------------------
% of Total 20% 2% 14% 9%
----------------------------------------------------------------------------



(Cdn$ millions)
----------------------------------------------------------------------------
Insitu
Canada Oil Sands Syncrude Total
----------------------------------------------------------------------------
Core Asset Development 81 370 87 953
Major Development - - - 707
Early-stage Development - 65 - 65
Exploration 227 1 - 663
Proved Property
Acquisition(4) - 419 - 419
----------------------------------------------------
Total Oil and Gas
Investment 308 855 87 2,807
Long Lake Upgrader(5) - 424 - 424
Marketing, Corporate,
Chemicals and Other 270 - - 270
Capitalized Interest 5 24 - 77
----------------------------------------------------------------------------
Total Capital Investment 583 1,303 87 3,578
----------------------------------------------------------------------------
% of Total 16% 37% 2% 100%
----------------------------------------------------------------------------

(1) Includes geological and geophysical expenditures of $81 million.
(2) Includes UK and Norway.
(3) Includes Nigeria and Colombia.
(4) Reflects allocation of purchase price of additional Long Lake working
interest acquired to oil sands resource.
(5) Includes allocation of purchase price of additional Long Lake working
interest acquired to upgrader and other capital investment relating to
the upgrader.



Nexen Inc.
Financial Highlights

Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Net Sales 1,550 1,270 4,895 7,424
Cash Flow from Operations 836 559 2,215 4,229
Per Common Share ($/share) 1.60 1.08 4.25 8.04
Net Income (Loss) 259 (181) 536 1,715
Per Common Share ($/share) 0.50 (0.35) 1.03 3.26
Capital Investment (1) 645 962 2,823 3,181
Acquisitions - 20 755 22
Net Debt (2) 5,551 4,575 5,551 4,575
Common Shares Outstanding (millions
of shares) 522.9 519.4 522.9 519.4
---------------------------------------

(1) Includes oil and gas development, exploration, and expenditures for
other property, plant and equipment.
(2) Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.


Cash Flow from Operations (1)

Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Oil & Gas
United Kingdom 777 451 2,159 3,308
Canada 45 45 130 389
Syncrude 94 50 192 400
United States 53 103 140 508
Yemen (2) 101 95 345 638
Other Countries 1 25 31 133
---------------------------------------
1,071 769 2,997 5,376
Marketing 109 (140) 256 (356)
Chemicals 18 25 102 85
---------------------------------------
1,198 654 3,355 5,105
Interest and Other Corporate Items (143) (89) (512) (292)
Income Taxes (3) (219) (6) (628) (584)
---------------------------------------
Cash Flow from Operations (1) 836 559 2,215 4,229
---------------------------------------
---------------------------------------

(1) Defined as cash flow from operating activities before changes in
non-cash working capital and other. We evaluate our performance and that
of our business segments based on earnings and cash flow from
operations. Cash flow from operations is a non-GAAP term that represents
cash generated from operating activities before changes in non-cash
working capital and other and excludes items of a non-recurring nature.
We consider it a key measure as it demonstrates our ability and the
ability of our business segments to generate the cash flow necessary to
fund future growth through capital investment and repay debt. Cash flow
from operations may not be comparable with the calculation of similar
measures for other companies.


Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash Flow from Operating Activities 527 1,055 1,886 4,354
Changes in Non-Cash Working Capital 218 (587) 25 (119)
Other 84 97 318 18
Impact of Annual Crude Oil Put Options 7 (6) (14) (24)
---------------------------------------
Cash Flow from Operations 836 559 2,215 4,229
---------------------------------------
---------------------------------------

Weighted-average Number of Common
Shares Outstanding (millions of
shares) 522.7 519.5 521.4 526.1
---------------------------------------
Cash Flow from Operations Per Common
Share ($/share) 1.60 1.08 4.25 8.04
---------------------------------------
---------------------------------------

(2) After in-country cash taxes of $43 million for the three months ended
December 31, 2009 (2008 - $36 million) and $148 million for the year
ended December 31, 2009 (2008 - $275 million).
(3) Excludes in-country cash taxes in Yemen.


Nexen Inc.
Production Volumes (before royalties) (1)

Three Months Twelve Months
Ended December 31 Ended December 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 117.0 92.4 98.0 99.7
Canada 13.7 16.2 14.6 16.2
Long Lake Bitumen 8.8 6.6 7.9 3.9
Syncrude 23.7 22.3 20.2 20.9
United States 10.0 3.8 10.5 9.3
Yemen 45.1 52.6 49.9 56.6
Other Countries 2.4 5.8 3.5 5.8
---------------------------------------
220.7 199.7 204.6 212.4
---------------------------------------
Natural Gas (mmcf/d)
United Kingdom 44 15 24 18
Canada 140 138 139 131
United States 84 31 65 78
---------------------------------------
268 184 228 227
---------------------------------------

Total Production (mboe/d) 265 230 243 250
---------------------------------------
---------------------------------------


Production Volumes (after royalties)

Three Months Twelve Months
Ended December 31 Ended December 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 117.0 92.4 98.0 99.7
Canada 10.7 12.4 11.4 12.3
Long Lake Bitumen 8.8 6.5 7.9 3.9
Syncrude 21.4 20.8 18.6 18.2
United States 9.1 3.3 9.5 8.1
Yemen 26.3 31.7 29.8 30.6
Other Countries 2.2 5.4 3.2 5.3
---------------------------------------
195.5 172.5 178.4 178.1
---------------------------------------
Natural Gas (mmcf/d)
United Kingdom 44 15 24 18
Canada 122 112 128 109
United States 73 26 57 66
---------------------------------------
239 153 209 193
---------------------------------------

Total Production (mboe/d) 235 198 213 210
---------------------------------------
---------------------------------------

(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.


Nexen Inc.
Oil and Gas Prices and Cash Netback (1)

Total
Quarters - 2009 Year
-----------------------------------------------
(all dollar amounts in
Cdn$ unless noted) 1st 2nd 3rd 4th 2009
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil (US$/bbl) 43.08 59.62 68.30 76.19 61.80
Nexen Average - Oil
(Cdn$/bbl) 50.41 68.32 72.95 76.39 66.85
NYMEX Natural Gas
(US$/mmbtu) 4.48 3.81 3.44 4.91 4.16
Nexen Average - Gas
(Cdn$/mcf) 5.11 3.77 3.04 4.31 4.06
----------------------------------------------------------------------------

NETBACKS:
United Kingdom
Crude Oil:
Sales (mbbls/d) 100.8 97.0 70.4 119.6 96.9
Price Received ($/bbl) 51.60 69.42 73.15 76.40 67.70
Natural Gas:
Sales (mmcf/d) 21 17 17 43 24
Price Received ($/mcf) 5.50 3.67 2.64 3.82 3.95
Total Sales Volume
(mboe/d) 104.3 99.8 73.2 126.8 101.0

Price Received ($/boe) 50.97 68.10 70.95 73.39 65.93
Operating Costs 5.48 5.85 10.34 6.77 6.87
----------------------------------------------------------------------------
Netback 45.49 62.25 60.61 66.62 59.06
----------------------------------------------------------------------------
Canada - Heavy Oil
Sales (mbbls/d) 15.4 14.7 14.0 13.5 14.4

Price Received ($/bbl) 35.35 56.05 59.88 62.53 53.04
Royalties & Other 6.86 12.83 13.47 14.07 11.70
Operating Costs 15.42 16.41 16.21 16.73 16.17
----------------------------------------------------------------------------
Netback 13.07 26.81 30.20 31.73 25.17
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 137 134 136 130 134

Price Received ($/mcf) 4.75 3.42 2.85 4.14 3.78
Royalties & Other 0.59 0.15 0.21 0.34 0.32
Operating Costs 1.54 1.59 1.82 2.10 1.76
----------------------------------------------------------------------------
Netback 2.62 1.68 0.82 1.70 1.70
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 19.8 14.9 22.5 23.7 20.2

Price Received ($/bbl) 55.48 71.58 74.54 79.83 70.96
Royalties & Other 0.40 8.84 8.31 6.75 6.04
Operating Costs 36.95 57.21 29.50 27.93 35.92
----------------------------------------------------------------------------
Netback 18.13 5.53 36.73 45.15 29.00
----------------------------------------------------------------------------


Total
Quarters - 2008 Year
-----------------------------------------------
(all dollar amounts in
Cdn$ unless noted) 1st 2nd 3rd 4th 2008
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil (US$/bbl) 97.90 123.98 117.98 58.73 99.65
Nexen Average - Oil
(Cdn$/bbl) 93.00 118.00 115.56 59.90 96.92
NYMEX Natural Gas
(US$/mmbtu) 8.75 11.48 8.95 6.41 8.90
Nexen Average - Gas
(Cdn$/mcf) 7.97 10.21 8.65 6.34 8.44
----------------------------------------------------------------------------

NETBACKS:
United Kingdom
Crude Oil:
Sales (mbbls/d) 108.9 89.0 107.0 96.4 100.3
Price Received ($/bbl) 93.38 118.24 114.89 58.60 96.23
Natural Gas:
Sales (mmcf/d) 22 24 18 16 20
Price Received ($/mcf) 6.82 7.06 7.53 5.44 6.78
Total Sales Volume
(mboe/d) 112.6 93.0 110.0 99.0 103.7

Price Received ($/boe) 91.67 114.95 112.99 57.91 94.45
Operating Costs 5.67 7.42 6.71 7.39 6.75
----------------------------------------------------------------------------
Netback 86.00 107.53 106.28 50.52 87.70
----------------------------------------------------------------------------
Canada - Heavy Oil
Sales (mbbls/d) 16.2 16.4 16.0 16.2 16.2

Price Received ($/bbl) 65.94 93.16 97.91 41.14 74.51
Royalties & Other 16.65 22.61 24.24 8.81 18.07
Operating Costs 15.76 17.17 16.99 16.69 16.66
----------------------------------------------------------------------------
Netback 33.53 53.38 56.68 15.64 39.78
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 127 126 133 138 131

Price Received ($/mcf) 7.57 9.67 8.00 6.06 7.73
Royalties & Other 1.18 1.53 1.52 1.07 1.32
Operating Costs 1.67 1.84 1.84 1.66 1.75
----------------------------------------------------------------------------
Netback 4.72 6.30 4.64 3.33 4.66
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 19.3 19.1 22.9 22.3 20.9

Price Received ($/bbl) 101.70 130.90 126.56 65.48 105.47
Royalties & Other 11.93 22.08 21.89 4.97 15.11
Operating Costs 35.16 45.09 32.40 34.67 36.53
----------------------------------------------------------------------------
Netback 54.61 63.73 72.27 25.84 53.83
----------------------------------------------------------------------------

(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.


Total
Quarters - 2009 Year
-----------------------------------------------
(all dollar amounts in
Cdn$ unless noted) 1st 2nd 3rd 4th 2009
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 10.4 12.1 9.5 10.0 10.5
Price Received ($/bbl) 46.27 66.23 72.27 75.75 65.01
Natural Gas:
Sales (mmcf/d) 50 61 63 84 65
Price Received ($/mcf) 5.93 4.58 3.56 4.83 4.67
Total Sales Volume
(mboe/d) 18.8 22.2 20.0 23.9 21.2

Price Received ($/boe) 41.50 48.53 45.43 48.55 46.27
Royalties & Other 4.52 4.94 4.77 5.21 4.89
Operating Costs 13.79 13.11 12.40 11.32 12.58
----------------------------------------------------------------------------
Netback 23.19 30.48 28.26 32.02 28.80
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 54.7 51.4 43.2 46.2 48.8

Price Received ($/bbl) 52.30 69.40 76.31 78.93 68.49
Royalties & Other 19.43 31.94 32.08 33.71 28.94
Operating Costs 9.62 10.39 12.43 10.62 10.69
In-country Taxes 4.92 9.01 9.70 10.17 8.31
----------------------------------------------------------------------------
Netback 18.33 18.06 22.10 24.43 20.55
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 5.5 3.6 2.6 2.4 3.5

Price Received ($/bbl) 41.68 66.83 70.49 74.10 59.05
Royalties & Other 3.26 5.17 5.38 5.48 4.52
Operating Costs 4.81 5.73 5.70 9.52 6.03
----------------------------------------------------------------------------
Netback 33.61 55.93 59.41 59.10 48.50
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales (mboe/d) 241.4 228.9 198.2 258.1 231.6

Price Received ($/boe) 47.56 61.28 63.00 68.04 60.02
Royalties & Other 5.64 9.23 9.58 8.09 8.06
Operating Costs 10.62 11.95 13.60 10.86 11.66
In-country Taxes 1.11 2.02 2.11 1.82 1.75
----------------------------------------------------------------------------
Netback 30.19 38.08 37.71 47.27 38.55
----------------------------------------------------------------------------


Total
Quarters - 2008 Year
------------------------------------------------
(all dollar amounts in
Cdn$ unless noted) 1st 2nd 3rd 4th 2008
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 13.7 11.3 8.5 3.8 9.3
Price Received ($/bbl) 94.07 120.77 122.46 58.43 104.94
Natural Gas:
Sales (mmcf/d) 112 99 70 31 78
Price Received ($/mcf) 9.03 11.80 10.14 8.09 10.07
Total Sales Volume
(mboe/d) 32.4 27.8 20.2 8.9 22.3

Price Received ($/boe) 71.10 91.08 86.75 52.77 79.02
Royalties & Other 9.53 12.88 12.30 7.89 11.03
Operating Costs 8.20 9.28 15.62 21.58 11.57
----------------------------------------------------------------------------
Netback 53.37 68.92 58.83 23.30 56.42
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 62.5 57.4 54.2 51.7 56.4

Price Received ($/bbl) 96.57 120.39 115.92 64.48 99.87
Royalties & Other 48.07 59.21 52.47 26.33 46.94
Operating Costs 7.76 8.80 7.82 9.80 8.51
In-country Taxes 11.82 17.45 16.11 7.60 13.31
----------------------------------------------------------------------------
Netback 28.92 34.93 39.52 20.75 31.11
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 6.0 5.7 5.7 5.8 5.8

Price Received ($/bbl) 91.85 113.18 120.11 72.43 98.98
Royalties & Other 7.46 8.95 9.42 5.81 7.88
Operating Costs 4.74 4.43 5.14 3.79 4.52
----------------------------------------------------------------------------
Netback 79.65 99.80 105.55 62.83 86.58
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales (mboe/d) 270.1 240.4 250.9 226.9 247.0

Price Received ($/boe) 85.90 108.26 106.22 56.94 89.78
Royalties & Other 14.87 19.92 16.98 8.22 15.06
Operating Costs 9.46 11.89 10.90 12.01 11.04
In-country Taxes 2.74 4.16 3.48 1.73 3.04
----------------------------------------------------------------------------
Netback 58.83 72.29 74.86 34.98 60.64
----------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.


Nexen Inc.
Unaudited Consolidated Statement of Income
For the Three and Twelve Months Ended December 31

Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions, except per share
amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,550 1,270 4,895 7,424
Marketing and Other (Note 14) 274 426 909 813
---------------------------------------
1,824 1,696 5,804 8,237
---------------------------------------
Expenses
Operating 334 337 1,280 1,335
Depreciation, Depletion,
Amortization and Impairment 622 930 1,802 2,014
Transportation and Other 177 276 795 967
General and Administrative 117 92 497 257
Exploration 83 157 302 402
Interest (Note 9) 86 35 312 94
---------------------------------------
1,419 1,827 4,988 5,069
---------------------------------------

Income before Provision for Income
Taxes 405 (131) 816 3,168
---------------------------------------
Provision for (Recovery of) Income
Taxes
Current 262 42 776 859
Future (119) 15 (516) 598
---------------------------------------
143 57 260 1,457
---------------------------------------

Net Income (Loss) 262 (188) 556 1,711
Less: Net Income (Loss)
Attributable to Canexus
Non-Controlling Interests 3 (7) 20 (4)

---------------------------------------

Net Income (Loss) Attributable to
Nexen Inc. 259 (181) 536 1,715

---------------------------------------
---------------------------------------

Earnings (Loss) Per Common Share
($/share) (Note 15)
Basic 0.50 (0.35) 1.03 3.26
---------------------------------------
---------------------------------------

Diluted 0.49 (0.35) 1.01 3.22
---------------------------------------
---------------------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Balance Sheet

December 31 December 31
(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
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $10,807
(December 31, 2008 - $10,393) 15,492 14,922
Goodwill 339 390
Future Income Tax Assets 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 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 13)
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
(Note 16)
----------------------------
Total Liabilities and Equity 22,900 22,155
----------------------------
----------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Statement of Cash Flows
For the Three and Twelve Months Ended December 31


Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Operating Activities
Net Income (Loss) 262 (188) 556 1,711
Charges and Credits to Income not
Involving Cash (Note 17) 484 596 1,371 2,140
Exploration Expense 83 157 302 402
Changes in Non-Cash Working Capital
(Note 17) (218) 587 (25) 119
Other (84) (97) (318) (18)
---------------------------------------
527 1,055 1,886 4,354

Financing Activities
Proceeds from Long-Term Notes - - 1,081 -
Repayment of Medium-Term Notes and
Debentures - - - (125)
Proceeds from Term Credit
Facilities, Net - - 728 803
Repayment of Short-Term Borrowings,
Net - - (1) (4)
Proceeds from Canexus Debentures - - 46 -
Proceeds from Canexus Notes - - - 51
Proceeds from (Repayment of)
Canexus Term Credit Facilities, Net - (1) 48 (20)
Dividends on Common Shares (26) (26) (104) (92)
Distributions Paid to Canexus
Non-Controlling Interests (3) (6) (14) (17)
Issue of Common Shares and Exercise
of Tandem Options for Shares 15 16 57 64
Repurchase of Common Shares for
Cancellation - (38) - (338)
Changes in Non-Cash Working Capital
(Note 17) - (10) - -
Other (1) - (20) -
---------------------------------------
(15) (65) 1,821 322

Investing Activities
Capital Expenditures
Exploration and Development (546) (831) (2,467) (2,895)
Proved Property Acquisitions - (20) (755) (22)
Energy Marketing, Chemicals,
Corporate and Other (77) (66) (275) (149)
Proceeds on Disposition of Assets - 6 17 6
Changes in Non-Cash Working Capital
(Note 17) (69) (4) (110) (124)
Changes in Restricted Cash 14 (37) (140) 106
Other 3 (50) (13) (111)
---------------------------------------
(675) (1,002) (3,743) (3,189)

Effect of Exchange Rate Changes on
Cash and Cash Equivalents (34) 243 (267) 310
---------------------------------------

Increase (Decrease) in Cash and Cash
Equivalents (197) 231 (303) 1,797

Cash and Cash Equivalents -
Beginning of Period 1,897 1,772 2,003 206
---------------------------------------

Cash and Cash Equivalents - End of
Period (1) 1,700 2,003 1,700 2,003
---------------------------------------
---------------------------------------

(1) Cash and cash equivalents at December 31, 2009 consist of cash of $210
million (2008 - $355 million) and short-term investments of $1,490
million (2008 - $1,648 million).

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Statement of Equity
For the Three and Twelve Months Ended December 31

Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Common Shares, Beginning of Period 1,025 963 981 917
Issue of Common Shares 8 9 45 41
Exercise of Tandem Options for
Shares 7 7 12 23
Accrued Liability Relating to
Tandem Options Exercised for
Common Shares 9 6 11 22
Repurchased Under Normal Course
Issuer Bid - (4) - (22)
---------------------------------------
Balance at End of Period 1,049 981 1,049 981
---------------------------------------
---------------------------------------

Contributed Surplus, Beginning of
Period 1 2 2 3
Exercise of Tandem Options - - (1) (1)
---------------------------------------
Balance at End of Period 1 2 1 2
---------------------------------------
---------------------------------------

Retained Earnings, Beginning of
Period 6,489 6,531 6,290 4,983
Net Income (Loss) Attributable to
Nexen Inc. 259 (181) 536 1,715
Dividends on Common Shares (26) (26) (104) (92)
Repurchase of Common Shares for
Cancellation - (34) - (316)
---------------------------------------
Balance at End of Period 6,722 6,290 6,722 6,290
---------------------------------------
---------------------------------------

Accumulated Other Comprehensive
Loss, Beginning of Period (183) (233) (134) (293)
Other Comprehensive Income (Loss)
Attributable to Nexen Inc. (7) 99 (56) 159
---------------------------------------
Balance at End of Period (190) (134) (190) (134)
---------------------------------------
---------------------------------------

Canexus Non-Controlling Interests,
Beginning of Period 69 59 52 67
Net Income (Loss) Attributable to
Non-Controlling Interests 3 (8) 27 (5)
Distributions Declared to
Non-Controlling Interests (4) (7) (18) (20)
Issue of Partnership Units to
Non-Controlling Interests under
Distribution Reinvestment Plan 1 1 4 3
Estimated Fair Value of Conversion
Feature of Convertible
Debenture Issue Attributable to
Non-Controlling Interests - - 4 -
Other Comprehensive Income (Loss)
Attributable to Non-Controlling
Interests (5) 7 (5) 7
---------------------------------------
Balance at End of Period 64 52 64 52
---------------------------------------
---------------------------------------


Nexen Inc.
Unaudited Consolidated Statement of Comprehensive Income
For the Three and Twelve Months Ended December 31

Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Net Income (Loss) Attributable to
Nexen Inc. 259 (181) 536 1,715
Other Comprehensive Income (Loss),
Net of Income Taxes:
Foreign Currency Translation
Adjustment
Net Gains (Losses) on Investment in
Self-Sustaining Foreign Operations (117) 863 (810) 1,228
Net Gains (Losses) on
Foreign-Denominated Debt Hedges of
Self-Sustaining Foreign
Operations(1) 111 (757) 757 (1,062)
Realized Translation Adjustments
Recognized in Net Income (1) (7) (3) (7)
---------------------------------------
Other Comprehensive Income (Loss) (7) 99 (56) 159
---------------------------------------
Comprehensive Income (Loss)
Attributable to Nexen Inc. 252 (82) 480 1,874
---------------------------------------
---------------------------------------

(1) Net of income tax expense for the three months ended December 31, 2009
of $16 million (2008 - $100 million recovery) and net of income tax
expense for the twelve months ended December 31, 2009 of $109 million
(2008 - $145 million recovery).

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.

Notes to Unaudited Consolidated Financial Statements

Cdn$ millions, except as noted

1. ACCOUNTING POLICIES

Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). In the opinion of management, the Unaudited Consolidated Financial Statements contain all adjustments of a normal and recurring nature necessary to present fairly Nexen Inc.'s (Nexen, we or our) financial position at December 31, 2009 and 2008 and the results of our operations and our cash flows for the three and twelve months ended December 31, 2009 and 2008.

We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates on an ongoing basis, including those related to accruals, litigation, environmental and asset retirement obligations, recoverability of assets, income taxes, fair values of derivative assets and liabilities, capital adequacy and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. As at February 17, 2010, there are no material subsequent events requiring additional disclosure in or amendment to these financial statements.

These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2008 Form 10-K. Except as described below, the accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2008 Form 10-K.

Changes in Accounting Policies

Goodwill and Intangible Assets

On January 1, 2009, we retrospectively adopted the Canadian Institute of Chartered Accountants (CICA) Section 3064, Goodwill and Intangible Assets issued by the Accounting Standards Board (AcSB). This section clarifies the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Adoption of this standard did not have a material impact on our results of operations or financial position.

Business Combinations

On January 1, 2009, we prospectively adopted CICA Section 1582, Business Combinations issued by the AcSB. This section establishes principles and requirements of the acquisition method for business combinations and related disclosures. Adoption of this statement did not have a material impact on our results of operations or financial position.

Consolidated Financial Statements and Non-Controlling Interests

On January 1, 2009, we prospectively adopted CICA Sections 1601, Consolidated Financial Statements, and 1602, Non-Controlling Interests issued by the AcSB. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for non-controlling interests in consolidated financial statements subsequent to a business combination. Adoption of these statements did not have a material impact on our results of operations or financial position. The presentation changes have been included in the Unaudited Consolidated Financial Statements as applicable.

Financial Instruments

In June 2009, the AcSB amended Section 3862, Financial Instruments - Disclosures, to improve fair value and liquidity risk disclosures. Section 3862 now requires disclosure of the relative reliability of inputs into fair value estimates of financial instruments and disclosure of a three-level hierarchy based on the observability of inputs. The amendments are effective for fiscal years ending after September 30, 2009. Adoption of these amendments did not have a material impact on our results of operations or financial position.

Oil and Gas Reserve Estimates

On January 6, 2010, the Financial Accounting Standards Board issued guidance for Oil and Gas Reserve Estimation and Disclosure, which is effective for years ended December 31, 2009. The guidance expands the definition of oil and gas producing activities to: i) include unconventional sources such as oil sands, ii) change the price used in reserve estimation from the year-end price to the simple average of the first-day-of-the-month price for the previous 12 months, and iii) requires disclosures for geographic areas which represent 15% or more of proved reserves.

We follow the successful efforts method of accounting for our oil and gas activities, which depends on the estimated reserves we believe are recoverable from our oil and gas properties. Specifically, reserves estimates are used to calculate our unit-of-production depletion rates and to assess, when necessary, our oil and gas 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 publicly accountable enterprises will be required to adopt International Financial Reporting Standards (IFRS) for interim and annual reporting purposes for fiscal years beginning on or after January 1, 2011. A project team, consisting of dedicated personnel who have the experience and IFRS knowledge, has been set up to manage this transition and to ensure successful implementation within the required timeframe.



2. ACCOUNTS RECEIVABLE

December 31 December 31
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. INVENTORIES AND SUPPLIES

December 31 December 31
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

Depreciation, Depletion, Amortization and Impairment

Our DD&A expense in 2009 includes non-cash impairment charges of $78 million at three natural gas properties in Canada and the US Gulf of Mexico. Year-end natural gas proved reserves at these properties were lower as a result of weak natural gas prices throughout 2009. These properties were written down to their estimated fair value based on their estimated future discounted net cash flows. The estimated future cash flows incorporate a risk-adjusted discount rate and management's estimates of future prices, capital expenditures and production. Based on these significant unobservable inputs, the measurements are considered Level 3 within the fair value hierarchy. DD&A expense also includes $49 million for our Perth discovery in the North Sea, where we expensed the allocated acquisition costs as we are unlikely to proceed with development of this prospect.

Our DD&A expense in 2008 included $568 million of impairment expense relating to oil and gas properties in the US Gulf of Mexico and UK North Sea. These properties were written down to their estimated fair value based on their estimated total future discounted net cash flows.

In the US Gulf of Mexico, we reduced 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 asset remediation costs. These late-life, mature properties have a shorter production horizon, and therefore are sensitive to near-term commodity prices and higher abandonment costs. Inflationary pressures in the oil and gas industry increased the estimated future costs to remediate the assets. At Green Canyon 6, we reduced the carrying value of our assets by $107 million to reflect the impact of Hurricane Ike which destroyed a third-party production platform in the third quarter of 2008. This resulted in unexpected and uninsured costs to rebuild facilities as the original third-party production platform was not replaced by the operator.

In the UK North Sea, we reduced the carrying value of our Ettrick project by $256 million in 2008, primarily due to higher costs and lower reserve estimates following drilling and testing activities. We also expensed costs of $62 million related to our Selkirk discovery as we are unlikely to proceed with development.

Suspended Exploration Well Costs

The following table shows the changes in capitalized exploratory well costs during the years ended December 31, 2009 and 2008, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Suspended exploration well costs are included in property, plant and equipment.



Year Ended Year Ended
December 31 December 31
2009 2008
----------------------------------------------------------------------------
Beginning of Period 518 326
Exploratory Well Costs Capitalized Pending the
Determination of Proved Reserves 396 254
Capitalized Exploratory Well Costs Charged to
Expense (56) (81)
Transfers to Wells, Facilities and Equipment Based
on Determination of Proved Reserves (21) (29)
Effects of Foreign Exchange Rate Changes (43) 48
----------------------------
End of Period 794 518
----------------------------
----------------------------


The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and shows the number of projects for which exploratory well costs have been capitalized for a period greater than one year after the completion of drilling.



December 31 December 31
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 year relating to our interests in six exploratory blocks in the UK North Sea ($138 million), certain coalbed methane and shale gas exploratory activities in Canada ($138 million), two exploratory blocks in the Gulf of Mexico ($116 million) and our interest in two exploratory blocks offshore Nigeria ($19 million). These costs relate to projects with successful exploration wells for which we have not been able to recognize proved reserves. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or otherwise assess commercial viability.



Aging of Suspended Exploration Wells United United
greater than 1 Year Canada Kingdom 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. DEFERRED CHARGES AND OTHER ASSETS

December 31 December 31
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 Assets 60 2
Long-Term Capital Prepayments 27 61
Other 54 56
----------------------------
Total 370 570
----------------------------
----------------------------


6. FINANCIAL INSTRUMENTS

Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives used for trading and non-trading purposes. Our other financial instruments including accounts receivable, accounts payable, income taxes payable, accrued interest payable, dividends payable, short-term borrowings and long-term debt are carried at cost or amortized cost. The carrying value of our short-term receivables and payables approximates their fair value because the instruments are near maturity.

In our energy marketing group, we enter into contracts to purchase and sell crude oil, natural gas and other energy 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 currency risk for non-trading purposes. We categorize our derivative instruments as trading or non-trading activities and carry the instruments at fair value on our balance sheet. The fair values are included with amounts receivable or payable and are classified as long-term or short-term based on anticipated settlement date. Any change in fair value is included in marketing and other income.

We carry our long-term debt at amortized cost using the effective interest rate method. At December 31, 2009, the estimated fair value of our long-term debt was $7,594 million (2008-$5,686 million) as compared to the carrying value of $7,251 million (2008-$6,578 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers. The economic crisis in 2008 impacted market prices for corporate bonds and as a result, the estimated fair value of our long-term debt was lower in the fourth quarter of 2008.

Derivatives

(a) Derivative contracts related to trading activities

Our energy marketing group engages in various activities including the purchase and sale of physical commodities and the use of financial instruments such as commodity and foreign exchange futures, forwards and swaps to economically hedge exposures and generate 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 by our energy marketing operations are as follows:



December 31 December 31
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 derivative contracts settle beyond 12 months and are considered
non-current; once settlement is within 12 months, they are included in
accounts receivable or accounts payable.

Excluding the impact of netting arrangements, the fair value of derivative
instruments is as follows:

December 31 December 31
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
----------------------------
----------------------------


Trading revenues generated by our energy marketing group include gains and losses on derivative instruments and non-derivative instruments such as physical inventory. During the three and twelve months ended December 31, 2009, the following trading revenues were recognized in marketing and other income:



Three Months Twelve Months
Ended December 31 Ended December 31
2009 2009
----------------------------------------------------------------------------
Commodity 263 1,011
Foreign Exchange 4 (68)
---------------------------------------
Marketing Revenue, Net (Note 14) 267 943
---------------------------------------
---------------------------------------


As an energy marketer, we may undertake several transactions during a period to execute a single sale of physical product. Each transaction may be represented by one or more derivative instruments 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 instrument transactions are as follows:



Three Months Twelve Months
Ended December 31 Ended December 31
2009 2009
----------------------------------------------------------------------------
Natural Gas bcf/d 18.0 21.1
Crude Oil mmbbls/d 3.4 3.5
Power GWh/d 176.7 217.3
Foreign Exchange USD millions 1,011 2,981
Foreign Exchange Euro millions 68 376
---------------------------------------

(b) Derivative contracts related to non-trading activities

The fair value and carrying amounts of derivative instruments related to
non-trading activities are as follows:

December 31 December 31
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 derivative contracts settle beyond 12 months and are considered
non-current.
(2) The net fair value of these derivatives is equal to the gross fair value
before consideration of netting arrangements and collateral posted or
received with counterparties.


Crude oil put options

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 and provide a base level of price protection without limiting our upside to higher prices. Options on 60,000 bbls/d settle monthly, while the remaining options settle annually. These options are recorded at fair value throughout their term. As a result, changes in forward crude oil prices create gains or losses on these options at each period end. The put options were purchased for $39 million and are carried at fair value. At December 31, 2009, higher crude oil prices reduced the fair value of the options to $17 million, and we recorded a fair value loss for the quarter and the year ended December 31, 2009 of $22 million.

In early 2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crude oil production. These options were purchased for $14 million and established a Dated Brent floor price of US$60/bbl on these volumes. 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 in 2009 reduced the fair value of these options to nil and we recorded a fair value loss of $12 million and $229 million for the quarter and the year ended December 31, 2009 respectively.

The crude oil put options are carried at fair value and are classified as long-term or short-term based on their anticipated settlement date. Fair value of the put options is supported by multiple quotes obtained from third-party brokers, which were validated with observable market data to the extent possible. Any change in fair value is included in marketing and other income.



Change in Fair Value
(Cdn$ millions)
-----------------------------
Three Twelve
Average Fair Months Months
Notional Floor Value Ended Ended
Volumes Price (Cdn$ December 31 December 31
(bbls/d) Term (US$/bbl) millions) 2009 2009
----------------------------------------------------------------------------
WTI Crude Oil
Put Options
(monthly) 60,000 2010 50 13 (12) (12)
WTI Crude Oil
Put Options
(annual) 30,000 2010 50 4 (10) (10)
--------------------------------------
17 (22) (22)
--------------------------------------
--------------------------------------


Fixed-price natural gas contracts and natural gas swaps

We have fixed-price natural gas sales contracts and offsetting natural gas swaps that are not part of our trading activities. These sales contracts and swaps are carried at fair value and are classified as short-term based on their anticipated settlement date. Any change in fair value is included in marketing and other income.



Change in Fair Value
(Cdn$ millions)
-----------------------------
Three Twelve
Fair Months Months
Notional Average Value Ended Ended
Volumes Price (Cdn$ December 31 December 31
(Gj/d) Term ($/Gj) millions) 2009 2009
----------------------------------------------------------------------------
Fixed-Price
Natural
Gas Contracts
(Monthly) 15,514 2010 2.28 (14) 2 12
Natural Gas
Swaps
(Monthly) 15,514 2010 7.60 (12) (1) (13)
----------------------------------------
(26) 1 (1)
----------------------------------------
----------------------------------------


(c) Fair value of derivatives

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

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

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

- Level 1-Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 consists of financial instruments such as exchange-traded derivatives and we use information from markets such as the New York Mercantile Exchange

- Level 2-Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reported date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value, volatility factors and broker quotations, which can be substantially observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options, including those which have prices similar to quoted market prices. We obtain information from sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes.

- Level 3-Valuations in this level are those with inputs which are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value. Level 3 instruments may include items based on pricing services or broker quotes where we are unable to verify the observability of inputs into their prices. Level 3 instruments include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value which primarily includes extrapolation of observable future prices to similar locations, similar instruments or later time periods.

The following table includes our derivatives that are carried at fair value for our trading and non-trading activities as at December 31, 2009. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the least observable input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value 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 in the fair value of our derivatives classified
as Level 3 for the years ended December 31, 2009 and 2008 are provided
below:

Level 3
----------------------------------------------------------------------------
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
-----------
-----------

Level 3
----------------------------------------------------------------------------
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 are generally economically hedged such that gains or losses on positions classified in Level 3 are often offset by gains or losses on positions classified in Level 1 or 2. Transfers into or out of Level 3 represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Fair values of instruments in Level 3 are determined using broker quotes, pricing services, and internally-developed inputs. We performed a sensitivity analysis of inputs used to calculate the fair value of Level 3 instruments. Using reasonably possible alternative assumptions, the fair value of Level 3 instruments would change by $12 million.

7. RISK MANAGEMENT

(a) Market risk

We invest in significant capital projects, purchase and sell commodities, issue short-term borrowings and long-term debt and invest in foreign operations. These activities expose us to market risks from changes in commodity prices, foreign currency rates and interest rates, which could affect our earnings and the value of the financial instruments we hold. We use derivatives for trading and non-trading purposes as part of our overall risk management policy to manage these market risk exposures.

The following market risk discussion relates primarily to commodity price risk and foreign currency risk related to our financial instruments as our exposure to interest rate risk is immaterial, given that the majority of our debt is fixed rate.

Commodity price risk

We are exposed to commodity price movements as part of our normal oil and gas operations, particularly in relation to the prices received for our crude oil and natural gas. Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil and natural gas are sensitive to numerous worldwide factors, many of which are beyond our control, and are generally sold at contract or posted prices. Changes in global supply and demand fundamentals in the crude oil market and geopolitical events can significantly affect crude oil prices. Changes in crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, these changes also may affect the value of our oil and gas properties, our level of spending for exploration and development, and our ability to meet our obligations as they come due.

The majority of our oil and gas production is sold under short-term contracts, exposing us to the risk of near-term price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. We actively manage these risks by using derivative contracts such as commodity put options.

Our energy marketing business is focused on providing services to our customers and suppliers to meet their energy commodity needs. We market and trade physical energy commodities in selected regions of the world including crude oil, natural gas, electricity and other commodities. We do this by buying and selling physical commodities, by acquiring and holding rights to physical transportation and storage assets for these commodities, and by building strong relationships with our customers and suppliers.

In order to manage the commodity and foreign exchange price risks that come from this physical business, we use financial derivative contracts including energy-related futures, forwards, swaps and options, as well as currency swaps or forwards.

We also seek to profit from our views on the future movement of energy commodity pricing relationships, primarily between different locations, time periods or qualities. We do this by holding open positions, where the terms of physical or financial contracts are not completely matched to offsetting positions.

Our risk management activities 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 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 non-normal market conditions, or if positions are held longer than two days based on market views or a lack of market liquidity to exit them, which is typical for long-term assets and may also apply to nearer term positions. We estimate VaR primarily by using the Variance-Covariance method based on historical commodity price volatility and correlation inputs where available, and by historical simulation in other situations. Our estimate is based upon the following key assumptions:

- changes in commodity prices are either normally or "T" distributed;

- price volatility remains stable; and

- price correlation relationships remain stable.

We have defined VaR limits for different segments of our energy marketing business. These limits are calculated on an economic basis and include physical and financial derivatives, as well as physical transportation and storage capacity contracts accounted for as executory contracts in our financial statements. We monitor our positions against these VaR limits daily. Our period end, annual high, annual low and average VaR amounts for the three and twelve months ended December 31, 2009 are as follows:



Three Months Twelve Months
Ended December 31 Ended December 31
Value-at-Risk (Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Period End 11 25 11 25
High 18 30 24 40
Low 9 23 9 19
Average 13 26 15 30
--------------------------------------


If a market shock occurred as in 2008, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We perform stress tests on a regular basis to complement VaR and assess the impact of abnormal changes in prices on our positions.

Foreign currency risk

Foreign currency risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates. A substantial portion of our activities are transacted in or referenced to US dollars including:

- sales of crude oil, natural gas and certain chemicals products;

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

- commodity derivative contracts used primarily by our energy marketing group; and

- short-term borrowings and long-term debt.

The foreign exchange gains or losses related to the effective portion of our designated US-dollar debt are included in accumulated other comprehensive income in equity. Our net investment in self-sustaining foreign operations and our designated US-dollar debt at December 31, 2009 and 2008 are as follows:



December 31 December 31
(US$ millions) 2009 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 by maintaining our expected net cash flows and borrowings in the same currency. Cash inflows generated by our foreign operations and borrowings on our US-dollar debt facilities are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows. We designate most of our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. For the three and twelve month periods ended December 31, 2009, the undesignated portion of our US-dollar debt resulted in a net foreign exchange gain of $16 million and $151 million, respectively ($14 million and $132 million, respectively, net of income tax expense) and is included in marketing and other income. A one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $45 million, net of income tax, and would increase or decrease our net income by approximately $10 million, net of income tax.

We also have exposures to currencies other than the US dollar including a portion of our UK operating expenses, capital spending and future asset retirement obligations which are denominated in British pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies. In our energy marketing group, we enter into transactions in various currencies including Canadian and US dollars, British pounds and Euros. We actively manage significant currency exposures using forward contracts and swaps.

(b) Credit risk

Credit risk affects both our trading and non-trading activities and is the risk of loss if counterparties do not fulfill their contractual obligations. Most of our credit exposures are with counterparties in the 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. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. We take the following measures to reduce this risk:

- assess the financial strength of our counterparties through a rigorous credit analysis process;

- limit the total exposure extended to individual counterparties, and may require collateral from some counterparties;

- routinely monitor credit risk exposures, including sector, geographic and corporate concentrations of credit, and report these to our executive Risk Management Committee and the Finance Committee of the board;

- set credit limits based on rating agency credit ratings and internal assessments based on company and industry analysis;

- review counterparty credit limits regularly; and

- use standard agreements that allow for the netting of exposures associated with a single counterparty.

We believe these measures minimize our overall credit risk. However, there can be no assurance that these processes will protect us against all losses from non-performance. Since 2008, we have taken the following specific actions for certain counterparties deemed to be at higher risk of non-performance:

- ceased trading activities;

- significantly reduced and, in some cases, revoked credit privileges;

- redirected business to i) exchanges or clearing houses; and ii) entities with physical-based operations;

- increased "set off" arrangements with counterparties; and

- increased collateral and margining requirements where possible.

At December 31, 2009, only one counterparty individually made up more than 10% of our credit exposure. This counterparty is a major integrated oil company with a strong investment grade rating. One other counterparty made up more than 5% of our credit exposure. The following table illustrates the composition of credit exposure by credit rating.




Credit Rating 2009 2008
----------------------------------------------------------------------------
A or higher 67% 65%
BBB 26% 29%
Non-Investment Grade 7% 6%
---------------------
Total 100% 100%
---------------------
---------------------


Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts of non-derivative financial assets such as cash and cash equivalents, restricted cash, accounts receivable, as well as the fair value of derivative financial assets. We have provided an allowance of $54 million for credit risk with our counterparties. In addition, we incorporate the credit risk associated with counterparty default, as well as Nexen's own credit risk, into our estimates of fair value.

Collateral received from customers at December 31, 2009 includes $45 million of cash and $444 million of letters of credit. The cash received is included in accounts payable and accrued liabilities.

(c) Liquidity risk

Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they become due, and to operate our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At December 31, 2009, we had about $3.3 billion of cash and available undrawn committed lines of credit (US$3.2 billion). This includes $1.7 billion (US$1.6 billion) of cash and 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 letters of credit at December 31, 2009. Our committed term credit facilities are available until 2012 unless extended. We also have $492 million (US$470 million) of undrawn, uncommitted credit facilities, of which $86 million (US$82 million) was supporting letters of credit at year end.

The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2009:



December 31, 2009
-----------------------------------------------------------
greater than
Total less than 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 Debt
(1) 8,052 361 721 688 6,282
-----------------------------------------------------------
Total 15,395 361 2,524 1,309 11,201
-----------------------------------------------------------
-----------------------------------------------------------

(1) Excludes interest on term credit facilities of $1.6 billion (US$1.5
billion) and Canexus term credit facilities of $233 million (US$223
million) as the amounts drawn on the facilities fluctuate. Based on
amounts drawn at December 31, 2009 and existing variable interest rates,
we would be required to pay $19 million per year until the outstanding
amounts on the term credit facilities are repaid.

The following table details contractual maturities for our derivative
financial liabilities. The balance sheet amounts for derivative
financial liabilities included below are not materially different
from the contractual amounts due on maturity.


December 31, 2009
-----------------------------------------------------------
greater than
Total less than 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 our energy marketing group enters into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event occurs, such as a drop in credit ratings to non-investment grade. 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 were downgraded to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral secures the payment of such amounts. In the event of a ratings downgrade, we have trading inventories and receivables that can be quickly monetized as well as significant undrawn credit facilities.

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. Cash posted is included with our accounts receivable. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash is retained.

Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits of $198 million (2008-$103 million), which have been included in restricted cash.



8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
December 31 December 31
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
Stock-Based Compensation 72 97
Income Taxes Payable 179 69
Other 136 113
----------------------------
Total 3,038 3,326
----------------------------
----------------------------

9. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

December 31 December 31
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) 52 61
Notes, due 2013 (US$500 million) 523 612
Canexus Convertible Debentures, due 2014 (c) 46 -
Notes, due 2015 (US$250 million) 262 306
Notes, due 2017 (US$250 million) 262 306
Notes, due 2019 (US$300 million) (d) 314 -
Notes, due 2028 (US$200 million) 209 245
Notes, due 2032 (US$500 million) 523 612
Notes, due 2035 (US$790 million) 827 968
Notes, due 2037 (US$1,250 million) 1,308 1,531
Notes, due 2039 (US$700 million) (e) 733 -
Subordinated Debentures, due 2043 (US$460
million) 481 563
----------------------------
7,343 6,652
Unamortized Discounts and Debt Issue Costs (92) (74)
----------------------------
Total 7,251 6,578
----------------------------
----------------------------


(a) Canexus term 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 - $223 million (US$182 million)). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans or US-dollar base rate loans. Interest is payable monthly at floating rates. The term credit facilities are secured by a floating charge debenture over all of Canexus' assets. The credit facility also contains covenants with respect to certain financial ratios for Canexus. The weighted-average interest rate on the Canexus term credit facilities was 2.0% for the three months ended December 31, 2009 (three months ended December 31, 2008 - 4.2%) and 2.2% for the year ended December 31, 2009 (year ended December 31, 2008 - 4.4%).

(b) Term credit 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 or British pound call-rate loans. Interest is payable at floating rates. The weighted-average interest rate on our term credit facilities was 0.9% for the three months ended December 31, 2009 (three months ended December 31, 2008 - 2.1%) and 1.0% for the year ended December 31, 2009 (year ended December 31, 2008 - 2.8%). At December 31, 2009, $407 million (US$389 million) of these facilities were utilized to support outstanding letters of credit (2008 - $381 million (US$311 million)).

(c) Canexus convertible debentures

In August 2009, Canexus issued $46 million of unsecured subordinated convertible debentures to non-controlling interests. Interest is payable semi-annually at a rate of 8.00%. These debentures mature December 31, 2014 and are convertible at the holder's option at any time prior to the close of business on the earlier of i) the maturity date and ii) the business day immediately preceding the date specified by Canexus for redemption of the debentures into trust units. The conversion price is $5.10 per trust unit.

Canexus has the option to redeem the debentures in whole or in part from time to time subject to the satisfaction of certain conditions, after December 31, 2012 but before maturity, at a redemption price equal to the principal amount and unpaid interest. Canexus may elect to satisfy its obligation to pay interest or repay the principal by issuing trust units at market value.

The estimated fair value of the conversion feature of the convertible debentures amounted to $4 million and was included in non-controlling interests in equity. The amount of the convertible debentures allocated to long-term debt is being accreted over the term of the debt using the effective interest rate method.

Concurrent with the issuance of the $46 million of unsecured subordinated convertible debentures to non-controlling interests, we acquired $40 million of debentures from Canexus with substantially the same terms which allow us to protect against dilution of our ownership interest at our option. These debentures are eliminated on consolidation.

(d) 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 be repaid 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 the same yield as a US Treasury security having a term-to-maturity equal to the remaining term of the notes plus 0.40%.

(e) 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 be repaid 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 the same yield as a US Treasury security having a term-to-maturity equal to the remaining term of the notes plus 0.45%.

(f) Short-term borrowings

Nexen has uncommitted, unsecured credit facilities of approximately $492 million (US$470 million), none of which were drawn at December 31, 2009 (December 31, 2008 - nil). We utilized $86 million (US$82 million) of these facilities to support outstanding letters of credit at December 31, 2009 (December 31, 2008 - $29 million (US$24 million)). Interest is payable at floating rates. As these facilities were undrawn for the quarter we did not incur interest costs. For the three months ended December 31, 2008, the weighted-average interest rate on our short-term borrowings was 2.2%. For the twelve months ended December 31, 2009, the weighted average interest rate was 2.1% (year ended December 31, 2008 - 3.2%).



(g) Interest expense

Three Months Twelve Months
Ended December 31 Ended December 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Long-Term Debt 98 95 372 315
Other 5 4 17 19
---------------------------------------
Total 103 99 389 334
Less: Capitalized (17) (64) (77) (240)
---------------------------------------
Total 86 35 312 94
---------------------------------------
---------------------------------------


Capitalized interest relates to and is included as part of the cost of our oil and gas properties. The capitalization rates are based on our weighted-average cost of borrowings. In 2009, we ceased capitalizing interest on phase 1 of Long Lake.

10. CAPITAL MANAGEMENT

Our objective for managing our capital structure is to ensure that we have the financial capacity, liquidity and flexibility to fund our investment in full-cycle exploration and development of conventional and unconventional resources and for energy marketing activities. We generally rely on operating cash flows to fund capital investments. However, given the long cycle-time of some of our development projects which require significant capital investment prior to cash flow generation and volatile commodity prices, it is not unusual for capital expenditures to exceed our cash flow from operating activities in any given period. As such, our financing needs depend on the timing of expected net cash flows in a particular development or commodity cycle. This requires us to maintain financial flexibility and liquidity. Our capital management policies are aimed at:

- maintaining an appropriate balance between short-term borrowings, long-term debt and equity;

- maintaining sufficient undrawn committed credit capacity to provide liquidity;

- ensuring ample covenant room permitting us to draw on credit lines as required; and

- ensuring we maintain a credit rating that is appropriate for our circumstances.

We have the ability to make adjustments to our capital structure by issuing additional equity or debt, returning cash to shareholders and making adjustments to our capital investment programs. Our capital consists of equity, short-term borrowings, long-term debt, and cash and cash equivalents as follows:



December 31 December 31
2009 2008
----------------------------------------------------------------------------
Net Debt (1)
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
----------------------------
----------------------------
(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.
(2) Equity is the historical issue price of equity and accumulated retained
earnings.


We monitor the leverage in our capital structure by reviewing the ratio of net debt to cash flow from operating activities and interest coverage ratios at various commodity prices.

We use the ratio of net debt to cash flow from operating activities as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is a non-GAAP measure that does not have any standard meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by others. We calculate net debt using the GAAP measures of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash).

For the twelve months ended December 31, 2009, the net debt to cash flow from operating activities ratio (before changes in non-cash working 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 and 2.0 times under normalized commodity prices, this can be higher or lower depending on commodity price volatility or when we identify strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we assess whether we need to develop a strategy to reduce our leverage and lower this ratio back to target levels over time.

Our interest coverage ratio monitors our ability to fund the interest requirements associated with our debt. Our interest coverage decreased from 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 earnings before interest, taxes, DD&A (adjusted EBITDA) by interest expense before capitalized interest. Adjusted EBITDA is a non-GAAP measure which is calculated using net income excluding interest expense, provision for income taxes, exploration expense, DD&A, impairment and other non-cash expenses. The calculation of adjusted EBITDA is set out in the following table and is unlikely to be comparable to similar measures presented by others.



Twelve Months Twelve Months
Ended December 31 Ended December 31
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
---------------------------------------
---------------------------------------

11. ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of the asset retirement obligations associated
with our Property, Plant & Equipment (PP&E) are as follows:

Twelve Months Twelve Months
Ended December 31 Ended December 31
2009 2008
----------------------------------------------------------------------------
Balance at Beginning of Period 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
---------------------------------------
Balance at End of Period (1) (2) 1,053 1,059
---------------------------------------
---------------------------------------
(1) Obligations due within twelve months of $35 million (2008 - $35 million)
have been included in accounts payable and accrued liabilities.
(2) Obligations relating to our oil and gas activities amount to $1,002
million (2008 - $1,009 million) and obligations relating to our
chemicals business amount to $51 million (2008 - $50 million).


Our total estimated undiscounted inflated asset retirement obligations amount to $2,341 million (2008 - $2,393 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.9% (2008 - 5.9%). Approximately $276 million included in our asset retirement obligations will be settled over the next five years. The remaining obligations settle beyond five years and will be funded by future cash flows from our operations.



12. DEFERRED CREDITS AND OTHER LIABILITIES

December 31 December 31
2009 2008
----------------------------------------------------------------------------
Deferred Tax Credit 503 709
Long-Term Energy Marketing Derivative Contracts
(Note 6) 212 294
Defined Benefit Pension Obligations 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 and financing of our assets in the North Sea which provided us with an additional one-time tax deduction in the UK. As these transactions were completed within our consolidated group, we are unable to recognize the benefit of the tax deductions until the assets are recognized in income by way of a sale to a third party or depletion through use. At December 31, 2009, we deferred recognizing $503 million (2008-$709 million) of tax credits in our Consolidated Statement of Income.

13. EQUITY

Dividends

Dividends per common share for the three months ended December 31, 2009 were $0.05 per common share (2008-$0.05), and for the twelve months ended December 31, 2009 were $0.20 per common share (2008 - $0.18). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.



14. MARKETING AND OTHER INCOME
Three Months Twelve Months
Ended December 31 Ended December 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Marketing Revenue, Net (Note 6) 267 86 943 467
Change in Fair Value of Crude Oil Put
Options (Note 6) (33) 204 (251) 203
Interest 3 8 7 28
Foreign Exchange Gains 16 162 128 128
Other 21 (34) 82 (13)
---------------------------------------
Total 274 426 909 813
---------------------------------------
---------------------------------------


15. EARNINGS PER COMMON SHARE

We calculate basic earnings per common share using net income divided by the weighted-average number of common shares outstanding. We calculate diluted earnings per common share in the same manner as basic, except we use the weighted-average number of diluted common shares outstanding in the denominator.



Three Months Twelve Months
Ended December 31 Ended December 31
(millions of shares) 2009 2008 2009 2008
----------------------------------------------------------------------------
Weighted-average number of common
shares, basic 522.7 519.5 521.4 526.1
Shares issuable pursuant to tandem
options 7.5 - 10.1 18.8
Shares to be notionally purchased
from proceeds of tandem options (5.2) - (7.0) (12.7)
---------------------------------------
Weighted-average number of common
shares, diluted 525.0 519.5 524.5 532.2
---------------------------------------
---------------------------------------


In calculating the weighted-average number of diluted common shares outstanding for the three and twelve months ended December 31, 2009, we excluded 14,187,472 and 13,485,465 tandem options, respectively, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three months ended December 31, 2008, all tandem options were excluded because they have an anti-dilutive impact on the loss per share amounts. In calculating the weighted-average number of diluted common shares outstanding for the twelve months ended December 31, 2008, we excluded 5,694,055 tandem options, because their exercise price was greater than the average common share market price in the period. During the periods presented, outstanding tandem options were the only potential dilutive instruments.

16. COMMITMENTS, CONTINGENCIES AND GUARANTEES

As described in Note 16 to the Audited Consolidated Financial Statements included in our 2008 Form 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We continue to believe the resolution of these matters would not have a material adverse effect on our liquidity, financial condition or results of operations.



17. CASH FLOWS

(a) Charges and credits to income not involving cash

Three Months Twelve Months
Ended December 31 Ended December 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Depreciation, Depletion, Amortization
and Impairment 622 930 1,802 2,014
Stock-Based Compensation (33) (62) (10) (272)
Provision for (Recovery of) Future
Income Taxes (119) 15 (516) 598
Change in Fair Value of Crude Oil Put
Options (Note 14) 33 (204) 251 (203)
Foreign Exchange (23) (52) (177) (4)
Other 4 (31) 21 7
--------------------------------------
Total 484 596 1,371 2,140
--------------------------------------
--------------------------------------

(b) Changes in non-cash working capital

Three Months Twelve Months
Ended December 31 Ended December 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Accounts Receivable 53 1,771 92 950
Inventories and Supplies (94) 374 (236) 246
Other Current Assets 21 85 9 5
Accounts Payable and Accrued
Liabilities (274) (1,657) (23) (1,232)
Other Current Liabilities 7 - 23 26
--------------------------------------
Total (287) 573 (135) (5)
--------------------------------------
--------------------------------------

Relating to:
Operating Activities (218) 587 (25) 119
Financing Activities - (10) - -
Investing Activities (69) (4) (110) (124)
--------------------------------------
Total (287) 573 (135) (5)
--------------------------------------
--------------------------------------

(c) Other cash flow information

Three Months Twelve Months
Ended December 31 Ended December 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Interest Paid 87 107 335 319
Income Taxes Paid 236 239 483 1,055
--------------------------------------


Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $22 million for the three months ended December 31, 2009 (2008 - $65 million) and $81 million for the twelve months ended December 31, 2009 (2008 - $137 million).

18. OPERATING SEGMENTS AND RELATED INFORMATION

Nexen is involved in activities relating to Oil and Gas, Energy Marketing and Chemicals in various geographic locations as described in Note 22 to the Audited Consolidated Financial Statements included in our 2008 Form 10-K.

Our energy marketing group sells our crude oil 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 trading purposes. Our energy marketing group also uses physical commodity transportation and storage capacity contracts to capture regional opportunities as well as to take advantage of seasonal pricing differences. Weakness in gas markets has reduced the value of holding transportation contracts. Any losses associated with the transportation and storage capacity contracts will be recognized when the contracts are used or sold. In 2009 we initiated a strategic review of our energy marketing natural gas and power businesses. This review continues to align our marketing activities with our upstream oil and gas businesses.

In early 2010, we entered into an agreement to sell our European gas and power marketing business. These operations are not material to our results of operations. While net assets (total assets less total liabilities) of the business are not material, current assets and current liabilities in these operations comprise approximately 7% and 12% of our consolidated amounts, respectively.



Three months ended December 31, 2009

Oil and Gas
--------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries (1)
----------------------------------------------------------------------------
Net Sales 856 114 160 96 192 15
Marketing and Other 5 (1) 6 - 4 -
--------------------------------------------------------
Total Revenues 861 113 166 96 196 15

Less: Expenses
Operating 78 46 60 25 46 2
Depreciation,
Depletion,
Amortization and
Impairment (3) 338 117 30 97 10 3
Transportation and
Other 3 8 11 4 5 -
General and
Administrative (4) 3 9 - 9 1 6
Exploration 24 31 - 17 - 11(5)
Interest - - - - - -
--------------------------------------------------------
Income (Loss)
before Income Taxes 415 (98) 65 (56) 134 (7)
Less: Provisions for
(Recovery of)
Income Taxes 129 (25) 17 (14) 52 6
Less: Non-Controlling
Interests - - - - - -
--------------------------------------------------------
Net Income (Loss) 286 (73) 48 (42) 82 (13)
--------------------------------------------------------
--------------------------------------------------------

Identifiable Assets 4,866 7,809 (6) 1,287 1,715 229 1,090
--------------------------------------------------------
--------------------------------------------------------
Capital Expenditures
Development and Other 92 109 31 22 7 162
Exploration 34 26 - 46 - 17
--------------------------------------------------------
126 135 31 68 7 179
--------------------------------------------------------
--------------------------------------------------------

Property, Plant and
Equipment
Cost 6,115 9,664 1,463 3,900 2,462 930
Less: Accumulated
DD&A 2,664 2,038 270 2,529 2,322 99
--------------------------------------------------------
Net Book Value 3,451 7,626 (6) 1,193 1,371 140 831
--------------------------------------------------------
--------------------------------------------------------


Energy Corporate
Marketing Chemicals and Other Total
-----------------------------------------
Net Sales 7 110 - 1,550
Marketing and Other 267 6 (13) (2) 274
-----------------------------------------
Total Revenues 274 116 (13) 1,824

Less: Expenses
Operating 6 71 - 334
Depreciation, Depletion,
Amortization and
Impairment (3) 6 12 9 622
Transportation and Other 130 11 5 177
General and Administrative (4) 23 8 58 117
Exploration - - - 83
Interest - 1 85 86
-----------------------------------------
Income (Loss)
before Income Taxes 109 13 (170) 405
Less: Provisions for (Recovery
of) Income Taxes 44 3 (69) 143
Less: Non-Controlling
Interests - 3 - 3
-----------------------------------------
Net Income (Loss) 65 7 (101) 259
-----------------------------------------
-----------------------------------------

Identifiable Assets 3,050 (7) 693 2,161 22,900
-----------------------------------------
-----------------------------------------

Capital Expenditures
Development and Other 8 53 16 500
Exploration - - - 123
-----------------------------------------
8 53 16 623
-----------------------------------------
-----------------------------------------

Property, Plant and Equipment
Cost 259 1,135 371 26,299
Less: Accumulated DD&A 83 562 240 10,807
-----------------------------------------
Net Book Value 176 573 131 15,492
-----------------------------------------
-----------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $3 million, foreign exchange gains of $16
million, decrease in the fair value of crude oil put options of $33
million and other gains of $1 million.
(3) Includes an impairment charge related to gas properties in Canada and
the US Gulf of Mexico of $58 million and $20 million, respectively.
(4) Includes stock-based compensation expense of $18 million.
(5) Includes exploration activities primarily in Norway, Nigeria and
Colombia.
(6) Includes costs of $6,045 million related to our insitu oil sands (Long
Lake and future phases).
(7) 78% of Marketing's identifiable assets are accounts receivable and
inventories.


Three months ended December 31, 2008

Oil and Gas
------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
----------------------------------------------------------------------------

Net Sales 527 111 124 147 181 36
Marketing and
Other (12) 1 3 - 3 (2)
----------------------------------------------------------
Total Revenues 515 112 127 147 184 34

Less: Expenses
Operating 67 45 72 17 47 3
Depreciation,
Depletion,
Amortization and
Impairment (3) 494 64 13 283 40 5
Transportation
and Other (2) 2 5 1 2 -
General and
Administrative(4) (1) 7 - 15 2 (1)
Exploration 44 38 - 39 3 33(5)
Interest - - - - - -
----------------------------------------------------------
Income (Loss)
before Income
Taxes (87) (44) 37 (208) 90 (6)
Less: Provisions
for (Recovery
Of) Income Taxes (55) (12) 10 (74) 30 (1)
Less:
Non-Controlling
Interests - - - - - -
----------------------------------------------------------
Net Income (Loss) (32) (32) 27 (134) 60 (5)
----------------------------------------------------------
----------------------------------------------------------
Identifiable
Assets 6,632 6,643(6) 1,198 2,044 342 701
----------------------------------------------------------
----------------------------------------------------------
Capital
Expenditures
Development and
Other 135 325 16 71 31 117
Exploration 32 79 - 7 - 18
Proved Property
Acquisitions - 20 - - - -
----------------------------------------------------------
167 424 16 78 31 135
----------------------------------------------------------
----------------------------------------------------------

Property, Plant
and Equipment
Cost 6,532 8,134 1,372 4,398 2,808 554
Less:
Accumulated DD&A 2,159 1,786 236 2,702 2,610 113
----------------------------------------------------------
Net Book Value 4,373 6,348(6) 1,136 1,696 198 441
----------------------------------------------------------
----------------------------------------------------------



Energy Corporate
Marketing Chemicals and Other Total
-----------------------------------------
Net Sales 18 126 - 1,270
Marketing and Other 86 (37) 384(2) 426
-----------------------------------------
Total Revenues 104 89 384 1,696

Less: Expenses
Operating 10 76 - 337
Depreciation, Depletion,
Amortization and
Impairment (3) 8 12 11 930
Transportation and Other 231 14 23 276
General and Administrative (4) 16 9 45 92
Exploration - - - 157
Interest - 4 31 35
-----------------------------------------
Income (Loss)
before Income Taxes (161) (26) 274 (131)
Less: Provisions for (Recovery
Of) Income Taxes (30) (3) 192 57
Less: Non-Controlling
Interests - (7) - (7)
-----------------------------------------
Net Income (Loss) (131) (16) 82 (181)
-----------------------------------------
-----------------------------------------
Identifiable Assets 3,280(7) 573 742 22,155
-----------------------------------------
-----------------------------------------
Capital Expenditures
Development and Other 5 31 30 761
Exploration - - - 136
Proved Property Acquisitions - - - 20
-----------------------------------------
5 31 30 917
-----------------------------------------
-----------------------------------------

Property, Plant and Equipment
Cost 246 940 331 25,315
Less: Accumulated DD&A 76 507 204 10,393
-----------------------------------------
Net Book Value 170 433 127 14,922
-----------------------------------------
-----------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $8 million, foreign exchange gains of $162
million, increase in the fair value of crude oil put options of $204
million and other gains of $10 million.
(3) Includes an impairment charge related to oil and gas properties in the
UK North Sea and the US Gulf of Mexico of $318 million and $250 million,
respectively.
(4) Includes recovery of stock-based compensation expense of $39 million.
(5) Includes exploration activities primarily in Norway and Colombia.
(6) Includes costs of $4,742 million related to our insitu oil sands (Long
Lake and future phases).
(7) 79% of Marketing's identifiable assets are accounts receivable and
inventories.


Twelve months ended December 31, 2009

Oil and Gas
---------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries (1)
----------------------------------------------------------------------------

Net Sales 2,430 395 480 321 705 70
Marketing and Other 18 1 7 - 14 6
---------------------------------------------------------
Total Revenues 2,448 396 487 321 719 76

Less: Expenses
Operating 253 171 265 98 191 8
Depreciation,
Depletion,
Amortization and
Impairment (3) 875 301 63 312 102 14
Transportation and
Other 17 27 28 22 30 -
General and
Administrative (4) 18 67 1 60 6 35
Exploration 50 84 - 104 - 64(5)
Interest - - - - - -
---------------------------------------------------------
Income (Loss)
before Income
Taxes 1,235 (254) 130 (275) 390 (45)
Less: Provisions
for (Recovery of)
Income Taxes 487 (64) 33 (95) 141 (23)
Less:
Non-Controlling
Interests - - - - - -
---------------------------------------------------------
Net Income (Loss) 748 (190) 97 (180) 249 (22)
---------------------------------------------------------
---------------------------------------------------------
Identifiable Assets 4,866 7,809(6) 1,287 1,715 229 1,090
---------------------------------------------------------
---------------------------------------------------------
Capital
Expenditures
Development and
Other 483 628 87 128 69 490
Exploration 143 215 - 157 - 67
Proved Property
Acquisitions - 755 - - - -
---------------------------------------------------------
626 1,598 87 285 69 557
---------------------------------------------------------
---------------------------------------------------------

Property, Plant and
Equipment
Cost 6,115 9,664 1,463 3,900 2,462 930
Less: Accumulated
DD&A 2,664 2,038 270 2,529 2,322 99
---------------------------------------------------------
Net Book Value 3,451 7,626(6) 1,193 1,371 140 831
---------------------------------------------------------
---------------------------------------------------------

Energy Corporate
Marketing Chemicals and Other Total
----------------------------------------
Net Sales 36 458 - 4,895
Marketing and Other 943 50 (130)(2) 909
----------------------------------------
Total Revenues 979 508 (130) 5,804

Less: Expenses
Operating 27 267 - 1,280
Depreciation, Depletion,
Amortization and
Impairment (3) 27 65 43 1,802
Transportation and Other 599 48 24 795
General and Administrative (4) 91 42 177 497
Exploration - - - 302
Interest - 7 305 312
----------------------------------------
Income (Loss)
before Income Taxes 235 79 (679) 816
Less: Provisions for (Recovery
of) Income Taxes 96 18 (333) 260
Less: Non-Controlling
Interests - 20 - 20
----------------------------------------
Net Income (Loss) 139 41 (346) 536
----------------------------------------
----------------------------------------
Identifiable Assets 3,050(7) 693 2,161 22,900
----------------------------------------
----------------------------------------
Capital Expenditures
Development and Other 28 214 33 2,160
Exploration - - - 582
Proved Property Acquisitions - - - 755
----------------------------------------
28 214 33 3,497
----------------------------------------
----------------------------------------
Property, Plant and Equipment
Cost 259 1,135 371 26,299
Less: Accumulated DD&A 83 562 240 10,807
----------------------------------------
Net Book Value 176 573 131 15,492
----------------------------------------
----------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $7 million, foreign exchange gains of $128
million, decrease in the fair value of crude oil put options of $251
million and other losses of $14 million.
(3) Includes an impairment charge related to gas properties in Canada and
the US Gulf of Mexico of $58 million and $20 million, respectively.
(4) Includes stock-based compensation expense of $69 million.
(5) Includes exploration activities primarily in Norway, Nigeria and
Colombia.
(6) Includes cost of $6,045 million related to our insitu oil sands (Long
Lake and future phases).
(7) 78% of Marketing's identifiable assets are accounts receivable and
inventories.


Twelve months ended December 31, 2009

Oil and Gas
---------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
----------------------------------------------------------------------------
Net Sales 3,580 656 691 665 1,093 192
Marketing and Other 5 3 6 4 12 -
---------------------------------------------------------
Total Revenues 3,585 659 697 669 1,105 192

Less: Expenses
Operating 253 182 280 94 176 10
Depreciation,
Depletion,
Amortization and
Impairment(3) 999 208 49 475 160 17
Transportation and
Other 19 12 16 3 9 -
General and
Administrative (4) (8) 20 1 38 (7) 13
Exploration 86 79 - 109 5 123(5)
Interest - - - - - -
---------------------------------------------------------
Income (Loss)
before Income Taxes 2,236 158 351 (50) 762 29
Less: Provisions for
(Recovery of) Income
Taxes 1,126 45 99 (19) 264 (4)
Less: Non-Controlling
Interests - - - - - -
---------------------------------------------------------
Net Income (Loss) 1,110 113 252 (31) 498 33
---------------------------------------------------------
---------------------------------------------------------

Identifiable Assets 6,632 6,643 (6) 1,198 2,044 342 701
---------------------------------------------------------
---------------------------------------------------------

Capital Expenditures
Development and Other 545 1,180 55 251 92 190
Exploration 146 225 - 154 9 48
Proved Property
Acquisitions - 22 - - - -
---------------------------------------------------------
691 1,427 55 405 101 238
---------------------------------------------------------
---------------------------------------------------------

Property, Plant and
Equipment Cost 6,532 8,134 1,372 4,398 2,808 554
Less: Accumulated
DD&A 2,159 1,786 236 2,702 2,610 113
---------------------------------------------------------
Net Book Value 4,373 6,348 (6) 1,136 1,696 198 441
---------------------------------------------------------
---------------------------------------------------------

Energy Corporate
Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 70 477 - 7,424
Marketing and Other 467 (50) 366 (2) 813
-----------------------------------------
Total Revenues 537 427 366 8,237

Less: Expenses
Operating 43 297 - 1,335
Depreciation, Depletion,
Amortization and
Impairment (3) 19 44 43 2,014
Transportation and Other 805 55 48 967
General and Administrative (4) 79 33 88 257
Exploration - - - 402
Interest - 12 82 94
-----------------------------------------
Income (Loss)
before Income Taxes (409) (14) 105 3,168
Less: Provisions for (Recovery
of) Income Taxes (102) 2 46 1,457
Less: Non-Controlling
Interests - (4) - (4)
-----------------------------------------
Net Income (Loss) (307) (12) 59 1,715
-----------------------------------------
-----------------------------------------

Identifiable Assets 3,280 (7) 573 742 22,155
-----------------------------------------
-----------------------------------------

Capital Expenditures
Development and Other 8 88 53 2,462
Exploration - - - 582
Proved Property Acquisitions - - - 22
-----------------------------------------
8 88 53 3,066
-----------------------------------------
-----------------------------------------

Property, Plant and Equipment
Cost 246 940 331 25,315
Less: Accumulated DD&A 76 507 204 10,393
-----------------------------------------
Net Book Value 170 433 127 14,922
-----------------------------------------
-----------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $28 million, foreign exchange gains of $128
million, increase in the fair value of crude oil put options of $203
million and other income of $7 million.
(3) Includes an impairment charge related to oil and gas properties in the
UK North Sea and Gulf of Mexico of $318 million and $250 million,
respectively.
(4) Includes recovery of stock-based compensation expense of $160 million.
(5) Includes exploration activities primarily in Norway, Nigeria and
Colombia.
(6) Includes cost of $4,742 million related to our insitu oil sands (Long
Lake and future phases).
(7) 79% of Marketing's identifiable assets are accounts receivable and
inventories.

Contact Information

  • Investor Relations Inquiries:
    Michael J. Harris, CA
    Vice President, Investor Relations
    (403) 699-4688
    or
    Lavonne Zdunich, CA
    Manager, Investor Relations
    (403) 699-5821
    or
    Tim Chatten, P.Eng
    Analyst, Investor Relations
    (403) 699-4244
    or
    Media and General Inquiries:
    Pierre Alvarez
    Vice President, Corporate Relations
    (403) 699-5560
    or
    Carla Yuill
    Manager, Corporate Communications
    (403) 699-4704
    or
    Nexen Inc.
    801 - 7th Ave SW
    Calgary, Alberta, Canada T2P 3P7
    www.nexeninc.com