Nexen Inc.
TSX : NXY
NYSE : NXY

Nexen Inc.

February 16, 2012 06:00 ET

Nexen Announces Solid Financial Results & Progress on Milestones

Cash Flow, Production and Cash Netbacks Rise From Q3 2011; Major Projects & Deliverables On-Track

CALGARY, ALBERTA--(Marketwire - Feb. 16, 2012) - Nexen Inc. (TSX, NYSE: NXY) today reported 2011 fourth quarter and annual operating and financial results, and provided a progress update on its strategic priorities for 2012.

In the fourth quarter, we generated cash flow from operations of $585 million ($1.11/share), reflecting a 12% increase in production over the third quarter to 208,000 boe/d (193,000 boe/d after royalties), and cash netbacks from oil and gas operations of $42.85/boe (after-tax).

Net income was $43 million ($0.08/share), reflecting one-time, after-tax charges of $190 million ($0.36/share) related to previous costs associated with our shift away from large, integrated upgrading projects in our future oil sands development strategy, and $127 million after-tax ($0.24/share) for impairments related to our gas assets in Canada and the United States, due to low gas prices.

For the full year, cash flow was $2.4 billion ($4.49/share), net income was $697 million ($1.32/share) and production averaged 207,000 boe/d (186,000 boe/d after royalties). Cash netbacks from oil and gas operations were $40.20/boe (after-tax) in 2011.

The annual results met our expectations for cash flow ($2.1-$2.8 billion) and our revised expectations for production (200,000-215,000 boe/d). Total 2011 capital expenditures of $2.6 billion were also within our expected range of $2.4-$2.7 billion.

"Nexen delivered solid results in the fourth quarter," said Kevin Reinhart, Nexen's interim President & CEO. "Production met expectations, Long Lake generated positive cash flow, and we entered into two joint ventures in the Gulf of Mexico and shale gas with strong partners.

"I'm pleased with the commitment our employees have made to delivering on our strategic priorities for 2012 and beyond," continued Reinhart. "2012 has started off strong. Long Lake production continues to grow and Buzzard is back to operating normally. We advanced our near term production growth projects including Usan, our UK tiebacks and Long Lake pads 12 and 13. We are also excited about our second drilling success on the Appomattox field in the Gulf of Mexico."

Fourth Quarter Overview


--  Cash flow from operations of $585 million ($1.11/share). 
--  Net income of $43 million ($0.08/share); reflects $190 million
    ($0.36/share) after-tax charge related to future oil sands projects and
    $127 million ($0.24/share) of after-tax impairments on gas assets in
    Canada and the US. 
--  Production of 208,000 boe/d (193,000 boe/d after royalties). 
--  Cash netback from oil & gas operations of $42.85/boe, after-tax. 
--  Long Lake cash flow of $22 million, driven by higher production and
    improving yield; this resulted in positive cash flow of $5 million for
    the full year. 
--  Buzzard production of 186,000 boe/d (80,000 boe/d net to Nexen). 
--  Achieved first production from Blackbird tieback in the UK. 
--  Started up our 9-well shale gas pad in northeast British Columbia. 
--  $700 million joint venture (JV) agreement on northeast British Columbia
    shale gas assets, representing a 60% premium to our invested costs;
    closing in the first half of 2012. 
--  JV agreement on up to six exploration wells in the Gulf of Mexico; deal
    completed on a promoted basis and has closed. 

2011 Overview


--  Cash flow from operations of $2.4 billion ($4.49/share). 
--  Net income of $697 million ($1.32/share). 
--  Production of 207,000 boe/d (186,000 boe/d after royalties). 
--  Cash netback from oil & gas operations of $40.20/boe, after-tax. 
--  Proved reserve additions replacing 96% of production. 
--  Strategic transactions: disposed of our interest in Canexus for $458
    million (net) and signed JV agreements in northeast British Columbia and
    the Gulf of Mexico. 
--  Supported CNOOC Limited's acquisition of our partner at Long Lake, OPTI
    Canada; CNOOC brings technical and financial capacity to the
    partnership. 
--  Continued to reduce net debt using proceeds from non-core asset
    dispositions. 
--  Sanctioned and began construction on the Golden Eagle and Rochelle
    developments in the UK North Sea. 
--  Developed and commenced action plan to increase production at Long Lake
    to fill the upgrader: ramped-up pad 11, drilled pads 12 and 13 and
    progressed regulatory process for pads 14, 15 and Kinosis K1A. 
--  Commissioned the fourth platform at Buzzard and it is now operating
    normally. 

2012 Update


--  On track to meet 2012 first quarter production guidance. 
--  At Appomattox, we completed drilling in the northeast fault block of 
    the structure and have confirmed an oil discovery; this followed a 
    previous success in the south fault block. 
--  Usan project in Nigeria on track for start-up; Usan drives 2012 cash
    margin expansion. 
--  Long Lake bitumen production as of early February approximately 35,000
    bbls/d. 
--  Long Lake pad 12 and 13 drilling is complete and results met our
    expectations; pad 12 on track for first steam this spring, pad 13 to
    follow. 
--  Telford TAC tieback in the UK North Sea came on-stream in February. 

Results Summary


                        Three Months Ended                 Year Ended       
----------------------------------------------------------------------------
(Cdn$ millions      Dec. 31    Sept. 30     Dec. 31     Dec. 31      Dec. 31
 unless noted)         2011        2011        2010        2011         2010
----------------------------------------------------------------------------
Brent                                                                       
 (US$/bbl)           109.31      113.47       86.48      111.28        79.47
WTI (US$/bbl)         94.06       89.76       85.12       95.12        79.52
NYMEX natural                                                               
 gas                                                                        
 (US$/mmbtu)           3.48        4.06        3.97        4.03         4.39
Cash netback                                                                
 ($/boe)(1)           42.85       38.67       35.87       40.20        33.26
Average Daily                                                               
 Production                                                                 
 (mboe/d)                                                                   
  Before                                                                    
   Royalties            208         186         246         207          246
  After                                                                     
   Royalties            193         164         227         186          220
Cash flow from                                                              
 operations(2)          585         516         556       2,368        2,150
  Per common                                                                
   share                                                                    
   ($/share)           1.11        0.98        1.06        4.49         4.10
Net income               43         200         160         697        1,127
  Per common                                                                
   share                                                                    
   ($/share)           0.08        0.38        0.30        1.32         2.15
Capital                                                                     
 investment(3)          817         729         685       2,575        2,724
Net debt(4)           3,538       3,454       4,085       3,538        4,085
               -------------------------------------------------------------

1.  Cash netback is defined as our corporate average cash netback from oil
    and gas operations, after-tax. 
2.  For reconciliation of this non-GAAP measure, see Cash Flow from
    Operations on pg. 13 
3.  Includes geological and geophysical expenditures. 
4.  Net debt is defined as long-term debt and short-term borrowings less
    cash and cash equivalents. 

Fourth quarter cash flow from operations increased 13% over the third quarter primarily due to increased production and our rising cash netbacks. Annual cash flow from operations was the highest since 2008 as our weighting to unhedged, Brent-priced oil allowed us to realize premium pricing throughout the year. Brent averaged US$111 in 2011; this represented a $16 premium to WTI.

Net income declined quarter-over-quarter and year-over-year as a result of several items. It reflects a one-time charge of $190 million (after-tax) related to changes in our future oil sands development strategy. Our original strategy was to build duplicates of the existing Long Lake SAGD facilities and upgrader. We now expect to pursue smaller, phased, SAGD-only projects and will consider adding upgrading capacity once we are bitumen-long and economic conditions are favourable. As a result, previously capitalized design and engineering work done on the future phases has been expensed.

Lower annual net income also reflects impairments, primarily on our gas assets, in the third and fourth quarters of 2011, and gains on the sale of our heavy oil properties which increased net income in the third quarter of 2010.

Net debt has declined 13% in the past year and 36% over the past two years based on the success of our non-core asset disposition program.

Production Summary


                       Average Daily Quarterly       Average Daily Quarterly
                   Production before Royalties    Production after Royalties
Crude Oil, NGLs                                                             
 and Natural Gas                                                            
 (mboe/d)          Q4 2011   Q3 2011   Q4 2010   Q4 2011   Q3 2011   Q4 2010
----------------------------------------------------------------------------
North Sea              102        71       115       102        71       115
Yemen                   27        32        40        16        17        23
United States           18        21        27        18        19        28
Canada - Oil &                                                              
 Gas                    20        19        21        20        17        20
Canada -                                                                    
 Syncrude               18        22        23        16        21        21
Canada - Bitumen        21        19        18        19        17        18
Other Countries          2         2         2         2         2         2
                ------------------------------------------------------------
Total                  208       186       246       193       164       227
                ------------------------------------------------------------

Fourth quarter production increased 12% over the third quarter, primarily due to higher production from Buzzard and Long Lake.

Reliability at Buzzard significantly improved following completion of the commissioning of the fourth platform; our production efficiency rate was 86%. For 2012, we are targeting 85% before planned shutdowns (78% including scheduled downtime).

In the North Sea, the Blackbird tieback to Ettrick came on-stream in November, seven weeks ahead of schedule, and is currently producing to expectations; production in the fourth quarter was approximately 5,000 boe/d (gross). Severe weather resulted in longer than expected downtime to complete the Telford TAC tieback, which was finished in early February.

Long Lake bitumen production averaged 31,500 bbls/d (gross). This represents a 7% increase over the third quarter as production from the first 11 pads continues to increase and facility turnarounds were completed in the third quarter. At Syncrude, production was lower as a result of unscheduled maintenance on a hydrogen plant.

Production in Yemen and the Gulf of Mexico continued to experience natural declines; Yemen production was further reduced with the expiry of our contract for the Masila block in mid-December.


                          Annual Production before   Annual Production after
                                         Royalties                 Royalties
Crude Oil, NGLs and                                                         
 Natural Gas (mboe/d)            2011         2010         2011         2010
----------------------------------------------------------------------------
North Sea                          90          111           90          111
Yemen                              33           41           18           23
United States                      22           27           21           25
Canada - Oil & Gas(1)              20           28           19           25
Canada - Syncrude                  21           21           19           19
Canada - Bitumen                   19           16           17           15
Other Countries                     2            2            2            2
                        ----------------------------------------------------
Total                             207          246          186          220
                        ----------------------------------------------------

1.  2010 includes production before royalties of 9 mboe/d and production
    after royalties of 7 mboe/d from discontinued operations. 

Production in 2011 was lower than 2010, primarily as a result of the sale of our heavy oil properties in the third quarter of 2010, natural declines, and production interruptions at Buzzard due to unplanned maintenance, third-party pipeline restrictions, and delays in commissioning the fourth platform.

We met our revised fourth quarter and annual production guidance.


                          Average Daily Quarterly      Average Daily Annual 
                                Production before         Production before 
                                        Royalties                 Royalties 
Crude Oil, NGLs and          Q4 2011                   FY 2011              
 Natural Gas (mboe/d)         (prior      Q4 2011       (prior      FY 2011 
                            estimate)     (actual)    estimate)     (actual)
----------------------------------------------------------------------------
Buzzard                      75 - 95           80      61 - 66           62 
Other UK                     24 - 32           22      28 - 30           28 
Yemen                        24 - 33           27      32 - 35           33 
United States                21 - 24           18      23 - 24           22 
Canada - Oil & Gas           19 - 22           20      20 - 21           20 
Canada - Syncrude            20 - 23           18      21 - 22           21 
Canada - Bitumen             18 - 24           21      18 - 20           19 
Other Countries                    2            2            2            2 
                        ----------------------------------------------------
Total                    approx. 200               approx. 200              
                               - 230          208        - 215          207 
                        ----------------------------------------------------
                        ----------------------------------------------------

Guidance Update

We are on track to achieve 2012 first quarter production guidance. Year-to-date production volumes are a little over 190,000 boe/d compared to our first quarter guidance range of 180,000-220,000 boe/d.

Buzzard has averaged approximately 185,000 boe/d (gross) so far this year, reflecting our operating efficiency of 85%. At Long Lake, bitumen production has increased to recent 7-day rates of approximately 35,000 bbls/d as pad 11 production continues to grow and we focus on production optimization from all wells.

At Long Lake, we have rescheduled the planned maintenance turnaround to take advantage of better labour availability. As a result, the three-week SAGD turnaround and six-week upgrader outage will now take place in the third quarter; they were previously scheduled for the second quarter. We have updated our second and third quarter guidance to reflect this change in timing.


                       Estimated Average Daily Production before Royalties  
Crude Oil, NGLs and                                                         
 Natural Gas                                                                
 (mboe/d)              Q1 2012    Q2 2012    Q3 2012    Q4 2012 2012 Annual 
----------------------------------------------------------------------------
Buzzard                  75-95      75-95      50-60      75-95     70 - 85 
Other UK                 26-34      26-34      20-26      25-32     24 - 32 
Canada - Syncrude        22-24      18-20      22-24      22-24     21 - 23 
Canada - Bitumen         20-25      20-27      14-18      22-28     19 - 25 
West Africa               0-10      13-30      20-35      22-35     14 - 28 
United States            15-20      15-20      13-17      15-17     15 - 19 
Canada - Oil & Gas       15-20      15-18      15-17      15-20     15 - 19 
Other Countries              2          2          2          2           2 
                    --------------------------------------------------------
                      approx.    approx.    approx.    approx.     approx.  
                     180 - 220  190 - 235  160 - 190  205 - 240   185 - 220 
                    --------------------------------------------------------
                    --------------------------------------------------------

Operational Update

Conventional

Offshore West Africa - Development of the Usan field remains on schedule; the project is our largest source of new production in 2012 and is expected to contribute to significantly stronger corporate cash netbacks this year. Final commissioning activities are in progress and first production is expected in the next month or two. Development activities were not affected by earlier civil unrest in Nigeria.

Usan's facility capacity is 36,000 bbls/d net to Nexen; actual production rates will vary based on well performance, pace of ramp-up and facility uptime.

"First production from Usan will be a major achievement," commented Reinhart. "The project is our newest legacy asset, and will generate significant cash flow for Nexen for many years. It also significantly strengthens our corporate netback, as the margin it generates is higher than our already strong corporate average."

We expect to drill an exploration well at Owowo West in 2012. This well is targeted to follow-up on our earlier success at Owowo South B.

UK North Sea - Following final regulatory approval of the Golden Eagle development early in the fourth quarter, we began work on the fabrication of the facilities, utilizing many of the same teams that oversaw the successful construction of the Buzzard platforms. The work is proceeding on-time and on-budget, and we expect first production in late 2014. The facility will have a capacity of 70,000 boe/d (26,000 boe/d net to Nexen).

We also continue to progress our tieback projects in the North Sea. Blackbird came on-stream through the Ettrick facility in November and is currently producing to expectations. Telford TAC came on-stream in February; Rochelle is proceeding as planned and first production is expected around the end of 2012.

We have an active UK exploration program planned, including the North Uist exploration well west of the Shetland Islands, where drilling is expected to begin late in the first quarter.

Gulf of Mexico - At Appomattox, we followed-up our successful 2010 exploration well in the south fault block with another success in the northeast fault block. The well encountered approximately 150 feet of net oil pay; we are currently completing an evaluation to determine the size of the discovery. Resource on the northeast block would be in addition to the 65 million boe of probable reserves we booked on the south block.

We plan to continue drilling at Appomattox with an appraisal well on the south fault block and a sidetrack into the northwest fault block to test the third major part of the Appomattox structure. We have a 20% interest in Appomattox, the remaining interest is held by Shell Offshore Inc., who is the operator.

At Kakuna, we expect to reach target depth around the end of the first quarter. We expect to drill our next operated exploration well in the Gulf, at Angel Fire, later this year.

Oil Sands

Long Lake - At Long Lake, our focus is on advancing the 60 additional wells to fill the upgrader.

In the fourth quarter, Long Lake showed strong progress. Total production increased 7% over the prior quarter to 31,500 bbls/d of gross bitumen at a steam oil ratio (SOR) of 4.8.

Upgrader yield (PSC(TM) barrels per barrel of bitumen) was 76% and facility on-stream time was 78%. Per barrel operating costs were lower than previous quarters, primarily due to the increased production and the higher yield.

These factors contributed to positive cash flow from operations of $22 million in the quarter and $5 million for the full year.


Long Lake Quarterly Operating Metrics                                       

                   Bitumen        Steam       Unit                          
                 Production   Injection   Operating                Realized 
                     (Gross)     (Gross)    Cost(1)   Cash Flow       Price 
                    (bbls/d)    (bbls/d)     ($/bbl)($ millions)     ($/bbl)
----------------------------------------------------------------------------
2011                                                                        
 Q4                  31,500     151,000          67          22          97 
 Q3                  29,500     144,000          85          (4)         94 
 Q2                  27,900     152,000          95           6         109 
 Q1                  25,500     146,000          89         (19)         90 
2010                                                                        
 Q4                  28,100     158,000          86          (9)         83 
 Q3                  25,700     146,000          85         (42)         71 
 Q2                  24,900     137,000          90         (19)         74 
 Q1                  18,700     114,000         154         (58)         81 
                ------------------------------------------------------------

1. Unit operating costs and realized prices are based on PSC(TM) and bitumen volumes sold and exclude activities related to third-party bitumen purchased, processed and sold. Unit operating cost includes energy cost.

Over the past few weeks, production at Long Lake has increased to approximately 35,000 bbls/d. This reflects successful and ongoing well optimization initiatives and the growth in pad 11 production. Pad 11 is currently producing approximately 4,500 bbls/d and is continuing to ramp-up. The expected production range for this pad is 4,000 to 8,000 bbls/d.

We are making steady progress on our plans to fill the upgrader. Drilling has concluded on pads 12 and 13, and well completion activities are underway. We remain on track to begin steaming pad 12 in the spring; pad 13 is expected to follow sometime in the late summer or early fall. Production from both pads is expected before the end of the year. These pads specifically targeted higher-quality resource; our drilling results confirm that the resource quality is as we expected.

The regulatory approvals for pads 14, 15 and K1A are progressing. We are awaiting approvals for one or both projects this spring, which would enable us to begin drilling next winter. These wells have geological characteristics similar to our current best-producing wells.

In aggregate, we anticipate these wells will allow us to fill the upgrader over the next several years:


                                         Number of Wells      Expected Rates
                                                                      bbls/d
----------------------------------------------------------------------------
Pad 11                                                10       4,000 - 8,000
Pads 12 & 13                                          18     11,000 - 17,000
Pads 14 & 15                                       10-12       6,000 - 9,000
Kinosis K1A                                        25-30     15,000 - 25,000

"I am pleased with the progress we are making on our action plan to fill the upgrader," said Reinhart. "We continue to increase production from our existing wells, and are on track to bring on-stream additional wells in the high-quality resource areas."

We are also continuing work on a non-operated SAGD project at Hangingstone, of which we own 25%. The operator has delayed sanctioning of the project until late this year in order to complete the regulatory approval process. We expect the project to come on-stream in 2016 and our share of production at full rates will be about 6,000 bbls/d.

Shale Gas

Northeast British Columbia - We continued our strong execution on our Horn River shale gas program during the quarter. Our 9-well pad started up ahead of schedule and early production results are meeting expectations. Preliminary results indicate initial rates up to 18 mmcf/d per well. We are currently producing at our facility capacity of 50 mmcf/d.

Work continues on our 18-well pad and we remain on-time and on-budget. We anticipate production from this pad will begin in the fourth quarter, in conjunction with an increase in our facility capacity. This is expected to bring our total gross production capacity to 175 mmcf/d.

Our previously announced JV agreement with INPEX CORPORATION and JGC Corporation is expected to close in the second quarter 2012.

2011 Capital Investment and Reserves

In 2011, we invested $2.5 billion in oil and gas activities and added 73 million boe of proved reserves. These reserve additions replaced 96% of our production. On a proved plus probable basis, reserves increased 8%. Detailed tables outlining changes to reserves can be found on page 12 of this release.


                                            2011 Annual Results             
                                      Capital                Proved Reserve 
                                   Investment     Production      Additions 
                                  ($ millions)        (mmboe)        (mmboe)
----------------------------------------------------------------------------
Conventional Oil & Gas                  1,525             59             25 
Oil Sands                                 521             14             18 
Shale Gas                                 470              3             30 
                               ---------------------------------------------
Total Oil and Gas                       2,516             76             73 
                               ---------------------------------------------
                               ---------------------------------------------

The proved reserve additions relate primarily to the following areas:


--  Northeast British Columbia shale gas (30 million boe). 
--  Buzzard (15 million boe). 
--  Long Lake/Kinosis K1A (10 million boe), reflecting a reduction relating
    to the lower resource quality areas on Long Lake (84 million boe) more
    than offset by additions from the high-quality resource in the K1A area
    (94 million boe). 
--  Scott/Telford, including the Telford TAC tieback (9 million boe). 
--  Syncrude (8 million boe). 

We have 1 billion boe of proved reserves and 2.3 billion boe of proved plus probable reserves, representing reserve life indices of 13 years on a proved basis and 30 years on a proved plus probable basis. As previously disclosed, we also have a large inventory of attractive exploration prospects and billions of barrels of oil equivalent in contingent oil sands and shale gas resources. This provides a significant resource base for future growth.

Update on Executive Appointments

Nexen also announced today that Catherine Hughes, Executive Vice President of International, and Alan O'Brien, Senior Vice President, General Counsel & Secretary, have been confirmed in their current roles; both positions were previously held on an interim basis. Una Power, Nexen's Senior Vice President of Corporate Planning & Business Development, has been appointed interim CFO; she also retains oversight for her previous responsibilities. Biographies of Nexen's senior management team are available at www.nexeninc.com.

Quarterly Dividend

The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable April 1st, 2012, to shareholders of record on March 9th, 2012.

About Nexen

Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. Nexen is focused on three growth strategies: oil sands and shale gas in Western Canada and conventional exploration and development primarily in the North Sea, offshore West Africa and deepwater Gulf of Mexico. Nexen adds value for shareholders through successful full-cycle oil and gas exploration and development, and leadership in ethics, integrity, governance and environmental stewardship.

For further information on our shale gas joint venture, please refer to our press release dated November 29th, 2011. For more information on our estimates of reserves, please refer to our Annual Information Form. For more information on our estimates of resource, please refer to our press release dated November 15th, 2010.

Conference Call

Kevin Reinhart, Interim President & CEO, and Una Power, Interim CFO and Senior Vice President of Corporate Planning & Business Development, will discuss the financial and operating results as well as Nexen's business strategy and future expectations.

The webcast will be archived under the Investors section of our website.


Conference Call Details:  

Date:   February 16th, 2012                
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) 340-2218 (Toronto)  
(866) 226-1793 (North American toll-free)  
(800) 9559-6849 (Global toll-free)         

A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, February 16th by calling (905) 694-9451 (Toronto) or (800) 408-3053 (toll-free) passcode 2188506 followed by the pound sign.

Forward-Looking Statements

Certain statements in this release constitute "forward-looking statements" (within the meaning of the United States Private Securities Litigation Reform Act of 1995, as amended) 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 royalties and tax levels; future capital expenditures, their timing 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 of our projects; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; the expectation of achieving the production design rates from our oil sands facilities; the expectation that our oil sands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected design size of our operations; the expected timing and associated production impact of facilities turnarounds and maintenance; the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; 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; the expectation of our ability to comply with the new safety and environmental rules enacted in the US at a minimal incremental cost, and of receiving necessary drilling permits for our US offshore operations; estimates on a per share basis; future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and our ability to comply therewith; 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.

All of the forward-looking statements in this release are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although we believe that these assumptions are reasonable, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve volumes; commodity price and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund our capital and operating requirements as needed; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

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; 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; the cumulative impact of oil sands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oil sands production facilities; labour and material shortages; risks related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particularly our deepwater activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deepwater activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions and financial circumstances of our agents, counterparties, contractors, and joint venture parties; 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 including without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control.

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 forward-looking 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 the Risk Factors contained in our 2010 Annual Information form, and to the Quantitative Disclosures about Market Risk and our Forward Looking Statements contained in our 2010 Management Discussion and Analysis.

Note to Investors on Reserves

The reserves estimates in this disclosure were prepared in February 2012 with an effective date of December 31, 2011. The estimates of reserves and future net revenue and have been internally prepared by an internal qualified reserves evaluator in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Nexen's estimates of reserves prepared in accordance with SEC requirements are attached to its 2011 Annual Information Form.

Investors should note the following fundamental differences between reserves estimates and related disclosures prepared in accordance with NI 51-101 and those prepared in accordance with SEC requirements:


--  SEC reserves estimates are based upon different reserves definitions and
    are prepared in accordance with generally recognized industry practices
    in the U.S. whereas NI 51-101 reserves are based on definitions and
    standards promulgated by the COGE Handbook and generally recognized
    industry practices in Canada;
--  SEC reserves definitions differ from NI 51-101 in areas such as the use
    of reliable technology, areal 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 monthly average prices and costs held
    constant whereas NI 51-101 requires disclosure of reserves and related
    future net revenues using forecast prices and costs;
--  the SEC mandates disclosure of reserves by geographic area whereas NI
    51-101 requires disclosure of reserves by additional categories and
    product types;
--  the SEC does not require the disclosure of future net revenue of proved
    and proved plus probable reserves using forecast pricing at various
    discount rates;
--  the SEC requires future development costs to be estimated using existing
    conditions held constant, whereas NI 51-101 requires estimation using
    forecast conditions;
--  the SEC does not require the validation of reserves estimates by
    independent qualified reserves evaluators or auditors, whereas, without
    an exemption noted below, NI 51-101 requires issuers to engage such
    evaluators or auditors to evaluate, audit or review reserves and related
    future net revenue attributable to those reserves; and
--  the SEC does not allow proved and probable reserves to be aggregated
    whereas NI 51-101 requires issuers to make such aggregation.

The foregoing is a general description of the principal differences only. The differences between SEC requirements and NI 51-101 may be material for certain properties. Please also note:


--  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. Using the forecast prices
    applied to our reserves estimates, the boe conversion ratio based on
    wellhead value is approximately 30 mcf: 1 bbl; 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.

Nexen has received an exemption from NI 51-101 that permits us to forego the requirement to have our NI 51-101 reserves and related future net revenue attributable to our reserves evaluated, audited or reviewed by an independent qualified reserves evaluator or auditor. Accordingly, our future net revenue and reserves estimates are based on internal evaluations. Due to the extent and expertise of our internal reserves evaluation resources, our staff's familiarity with our properties and the controls applied to the evaluation process, we believe the reliability of our internally generated reserves estimates is not materially less than would be generated by an independent reserves evaluator.


NI 51-101 Reserves (before royalties, forecast pricing) - December 31, 2011





                                                    Other   
                                      North Sea   Intl (1)    United States
                               ---------------------------------------------
(mmboe)                            Oil      Gas       Oil      Oil      Gas
----------------------------------------------------------------------------
PROVED
December 31, 2010                  195       11        55       19       22
 Discoveries                         -        -         -        -        -
 Extensions & Improved Recovery      1        1         1        -        -
 Acquisitions                        -        -         -        -        -
 Revisions                          27        1         1        -        1
 Divestments                         -        -         -        -        -
                               ---------------------------------------------
 Net Additions                      28        2         2        -        1

 Production                        (32)      (2)      (14)      (3)      (5)

----------------------------------------------------------------------------
December 31, 2011                  191       11        43       16       18
----------------------------------------------------------------------------
----------------------------------------------------------------------------

PROBABLE                  
December 31, 2010                  106       10        41        7       13
 Discoveries                         3        -         -       58        6
 Extensions & Improved Recovery      -        -         4        1        1
 Acquisitions                        -        -         -        -        -
 Revisions                          10       (1)       (4)       -       (1)
 Divestments                         -        -         -        -        -
                               ---------------------------------------------
 Net Additions                      13       (1)        -       59        6

 Conversions (3)                   (21)      (2)       (2)      (1)      (2)
 Reclassification to Bitumen (4)     -        -         -        -        -

----------------------------------------------------------------------------
December 31, 2011                   98        7        39       65       17
----------------------------------------------------------------------------
----------------------------------------------------------------------------

PROVED + PROBABLE         
December 31, 2010                  301       21        96       26       35
 Discoveries                         3        -         -       58        6
 Extensions & Improved Recovery      1        1         5        1        1
 Acquisitions                        -        -         -        -        -
 Revisions                          37        -        (3)       -        -
 Divestments                         -        -         -        -        -
                               ---------------------------------------------
 Net Additions                      41        1         2       59        7

 Conversions (3)                   (21)      (2)       (2)      (1)      (2)
 Reclassification to Bitumen (4)     -        -         -        -        -
 Production                        (32)      (2)      (14)      (3)      (5)

----------------------------------------------------------------------------
December 31, 2011                  289       18        82       81       35
----------------------------------------------------------------------------
----------------------------------------------------------------------------

NI 51-101 Reserves (before royalties, forecast pricing) - December 31, 2011

                                              Canada   
                               -----------------------------------
                                    Oil Sand   Oil Sand
                                Gas   Insitu     Insitu   Syncrude    Total
                               ---------------------------------------------
                                     Bitumen  Synthetic  Synthetic  Oil and
(mmboe)                         Gas       (2)       Oil        Oil      Gas
----------------------------------------------------------------------------
PROVED
December 31, 2010                71        -        314        324    1,011
 Discoveries                      7        -          -          -        7
 Extensions & Improved Recovery  16        -         94          8      121
 Acquisitions                     -        -          -          -        -
 Revisions                       (1)       -        (84)         -      (55)
 Divestments                      -        -          -          -        -
                               ---------------------------------------------
 Net Additions                   22        -         10          8       73
                                           -           
 Production                      (7)       -         (5)        (8)     (76)

----------------------------------------------------------------------------
December 31, 2011                86        -        319        324    1,008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

PROBABLE                  
December 31, 2010                18        -        882         46    1,123
 Discoveries                     29       49          -          -      145
 Extensions & Improved Recovery  83        -          -          8       97
 Acquisitions                     -        -          -          -        -
 Revisions                        4        -        (40)         -      (32)
 Divestments                      -        -          -          -        -
                               ---------------------------------------------
 Net Additions                  116       49        (40)         8      210

 Conversions (3)                  -        -        (94)        (8)    (130)
 Reclassification to Bitumen (4)  -      612       (517)         -       95

----------------------------------------------------------------------------
December 31, 2011               134      661        231         46    1,298
----------------------------------------------------------------------------
----------------------------------------------------------------------------

PROVED + PROBABLE         
December 31, 2010                89        -      1,196        370    2,134
 Discoveries                     36       49          -          -      152
 Extensions & Improved Recovery  99        -         94         16      218
 Acquisitions                     -        -          -          -        -
 Revisions                        3        -       (124)         -      (87)
 Divestments                      -        -          -          -        -
                               ---------------------------------------------
 Net Additions                  138       49        (30)        16      283

 Conversions (3)                  -        -        (94)        (8)    (130)
 Reclassification to Bitumen (4)  -      612       (517)         -       95
 Production                      (7)       -         (5)        (8)     (76)

----------------------------------------------------------------------------
December 31, 2011               220      661        550        370    2,306
----------------------------------------------------------------------------
----------------------------------------------------------------------------

1.  Other International includes Yemen, Nigeria and Colombia.
2.  Includes reserves for which there are no definitive plans for upgrading
    at this time.
3.  Represents probable reserves converted to proved.
4.  Reserves reclassified to bitumen as we no longer have sufficient
    certainty as to when we will build additional upgrading facilities at
    Kinosis.

Nexen Inc.

Financial Highlights


                                    Three Months Ended   Twelve Months Ended
                                      Dec 31    Dec 31      Dec 31    Dec 31
(Cdn$ millions, except per-share           
 amounts)                               2011      2010        2011      2010
----------------------------------------------------------------------------
Net Sales (1)                          1,665     1,643       6,211     6,090
Cash Flow from Operations (1)            585       556       2,368     2,150
 Per Common Share ($/share)             1.11      1.06        4.49      4.10
Net Income (1)                            43       160         697     1,127
 Per Common Share ($/share)             0.08      0.30        1.32      2.15
Capital Investment (2)                   817       685       2,575     2,724
Net Debt (3)                           3,538     4,085       3,538     4,085
Common Shares Outstanding (millions        
 of shares)                            527.9     525.7       527.9     525.7
                                    ----------------------------------------

1.  Includes discontinued operations as discussed in Note 14 to our
    Unaudited Condensed Consolidated Financial Statements.
2.  Includes oil and gas development, exploration, and expenditures for
    other property, plant and equipment.
3.  Net debt is defined as long-term debt and short-term borrowings less
    cash and cash equivalents.

Cash Flow from Operations (1)


                                         Three Months  
                                                Ended   Twelve Months Ended
                                     Dec 31    Dec 31      Dec 31    Dec 31
(Cdn$ millions)                        2011      2010        2011      2010
----------------------------------------------------------------------------
Conventional Oil & Gas    
 United Kingdom                         854       780       3,085     2,775
 North America (2)                       46        67         252       359
 Other Countries (3)                     93        79         390       371
Oil Sands                 
 In Situ                                 22        (8)          5      (127)
 Syncrude                                89        95         405       298
                                    ----------------------------------------
                                      1,104     1,013       4,137     3,676
Interest, Marketing and Other              
 Corporate Items (2)                   (130)     (166)       (367)     (567)
Income Taxes (4)                       (389)     (291)     (1,402)     (959)
                                    ----------------------------------------
Cash Flow from Operations (1)           585       556       2,368     2,150
                                    ----------------------------------------
                                    ----------------------------------------

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. We consider it a key measure as it demonstrates our
    ability to generate the cash flow necessary to fund future growth
    through capital investment. Cash flow from operations may not be
    comparable with the calculation of similar measures for other companies.

                                    Three Months Ended  Twelve Months Ended
                                     Dec 31     Dec 31     Dec 31    Dec 31
(Cdn$ millions)                        2011       2010       2011      2010
----------------------------------------------------------------------------
Cash Flow from Operating Activities     459        342      2,497     2,392
Changes in Non-Cash Working Capital      32         72       (255)     (338)
Other                                   102        141        158       128
Impact of Annual Crude Oil Put             
 Options                                 (8)         1        (32)      (32)
                                    ----------------------------------------
Cash Flow from Operations               585        556      2,368     2,150
                                    ----------------------------------------
                                    ----------------------------------------

Weighted-average Number of Common          
 Shares Outstanding (millions of           
 shares)                              527.9      525.6      527.2     524.7
                                    ----------------------------------------
Cash Flow from Operations Per Common       
 Share ($/share)                       1.11       1.06       4.49      4.10
                                    ----------------------------------------
                                    ----------------------------------------

2.  Includes discontinued operations as discussed in Note 14 to our
    Unaudited Condensed Consolidated Financial Statements.
3.  After in-country cash taxes in Yemen of $36 million for the three months
    ended December 31, 2011 (December 31, 2010 - $41 million) and $182
    million for the twelve months ended December 31, 2011 (December 31, 2010
    - $166 million).
4.  Excludes in-country cash taxes in Yemen.

Nexen Inc.

Production Volumes (before royalties) (1)


                                            Three Months       Twelve Months
                                            Ended Dec 31        Ended Dec 31
                                          2011      2010      2011      2010
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)            
 United Kingdom                           98.8     109.4      85.0     104.9
 Yemen                                    26.5      40.1      32.9      41.3
 Oil Sands - Syncrude                     18.2      22.8      20.9      21.2
 Oil Sands - Long Lake Bitumen            20.5      18.3      18.6      15.9
 United States                             7.2      10.1       8.2       9.9
 Canada (2)                                  -         -         -       7.5
 Other Countries                           1.6       1.9       1.7       2.1
                                      --------------------------------------
                                         172.8     202.6     167.3     202.8
                                      --------------------------------------
Natural Gas (mmcf/d)      
 United Kingdom                             22        33        30        35
 United States                              66        99        86        99
 Canada (2)                                124       129       123       126
                                      --------------------------------------
                                           212       261       239       260
                                      --------------------------------------

Total Production (mboe/d)                  208       246       207       246
                                      --------------------------------------
                                      --------------------------------------

Production Volumes (after royalties)


                                            Three Months       Twelve Months
                                            Ended Dec 31        Ended Dec 31
                                          2011      2010      2011      2010
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)            
 United Kingdom                           98.3     109.4      84.7     104.8
 Yemen                                    15.5      23.6      18.1      23.1
 Oil Sands - Syncrude                     16.4      21.0      19.2      19.6
 Oil Sands - Long Lake Bitumen            19.4      17.5      17.3      15.1
 United States                             6.3       9.3       7.4       9.0
 Canada (2)                                  -         -         -       5.8
 Other Countries                           1.5       1.8       1.6       1.9
                                      --------------------------------------
                                         157.4     182.6     148.3     179.3
                                      --------------------------------------
Natural Gas (mmcf/d)      
 United Kingdom                             22        33        30        35
 United States                              72       115        78        94
 Canada (2)                                118       121       117       116
                                      --------------------------------------
                                           212       269       225       245
                                      --------------------------------------

Total Production (mboe/d)                  193       227       186       220
                                      --------------------------------------
                                      --------------------------------------

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

                                            Three Months       Twelve Months
                                            Ended Dec 31        Ended Dec 31
                                          2011      2010      2011      2010
----------------------------------------------------------------------------
Before Royalties          
 Crude Oil and NGLs (mbbls/d)                -         -         -       7.5
 Natural Gas (mmcf/d)                        -         -         -         6
After Royalties           
 Crude Oil and NGLs (mbbls/d)                -         -         -       5.8
 Natural Gas (mmcf/d)                        -         -         -         5
                                    ----------------------------------------

Nexen Inc.

Oil and Gas Prices and Cash Netback (1)


                                                                       Total
                                                      Quarters - 2011   Year
                                          ----------------------------------
(all dollar amounts in Cdn$ unless noted)    1st    2nd    3rd    4th   2011
----------------------------------------------------------------------------
PRICES:                   
Brent Crude Oil (US$/bbl)                 104.97 117.36 113.47 109.31 111.28
WTI Crude Oil (US$/bbl)                    94.10 102.56  89.76  94.06  95.12
Nexen Average - Oil (Cdn$/bbl)             98.37 110.28 103.98 108.44 105.21
NYMEX Natural Gas (US$/mmbtu)               4.20   4.37   4.06   3.48   4.03
AECO Natural Gas (Cdn$/mcf)                 3.58   3.54   3.53   3.29   3.48
Nexen Average - Gas (Cdn$/mcf)              4.51   4.75   4.36   3.63   4.31
----------------------------------------------------------------------------
NETBACKS (1):             
----------------------------------------------------------------------------
United Kingdom            
 Crude Oil:               
  Sales (mbbls/d)                          104.2   73.3   75.2   92.7   86.3
  Price Received ($/bbl)                   99.97 110.67 107.58 110.46 106.76
 Natural Gas:             
  Sales (mmcf/d)                              36     37     26     22     30
  Price Received ($/mcf)                    7.29   8.20   7.28   6.52   7.42
 Total Sales Volume (mboe/d)               110.2   79.5   79.5   96.4   91.3

 Price Received ($/boe)                    96.91 105.87 104.13 107.70 103.32
 Royalties & Other                             -   0.11   0.82   0.54   0.36
 Operating Costs                            9.85   8.48  14.46   9.99  10.60
 In-country Taxes                          42.46  42.76  41.00  43.24  42.41
----------------------------------------------------------------------------
 Netback                                   44.60  54.52  47.85  53.93  49.95
----------------------------------------------------------------------------
United States             
 Crude Oil:               
  Sales (mbbls/d)                            9.2    8.9    7.7    7.2    8.2
  Price Received ($/bbl)                   91.39 101.89  96.00 110.89  99.65
 Natural Gas:             
  Sales (mmcf/d)                             103     96     81     66     86
  Price Received ($/mcf)                    4.36   4.42   4.27   3.59   4.21
 Total Sales Volume (mboe/d)                26.3   24.9   21.2   18.2   22.6

 Price Received ($/boe)                    48.91  53.56  50.72  57.27  52.31
 Royalties & Other                          5.65   6.11   5.63   3.31   5.30
 Operating Costs                           10.43  10.72  11.18  16.73  11.96
----------------------------------------------------------------------------
 Netback                                   32.83  36.73  33.91  37.23  35.05
----------------------------------------------------------------------------
Canada - Natural Gas(2)   
 Sales (mmcf/d)                               97     85     79    112     93

 Price Received ($/mcf)                     3.65   3.62   3.51   3.08   3.44
 Royalties & Other                          0.28   0.24   0.27   0.17   0.23
 Operating Costs                            1.70   1.54   1.65   1.70   1.65
----------------------------------------------------------------------------
 Netback                                    1.67   1.84   1.59   1.21   1.56
----------------------------------------------------------------------------
Yemen 
 Sales (mbbls/d)                            34.9   39.3   31.8   27.8   33.4

 Price Received ($/bbl)                   101.57 111.77 107.98 111.14 108.11
 Royalties & Other                         46.98  52.26  49.72  45.94  48.97
 Operating Costs                           10.75   9.18  13.20  20.48  12.92
 In-country Taxes                          13.48  16.26  15.49  14.03  14.89
----------------------------------------------------------------------------
 Netback                                   30.36  34.07  29.57  30.69  31.33
----------------------------------------------------------------------------

                                                                       Total
                                                      Quarters - 2010   Year
                                          ----------------------------------
(all dollar amounts in Cdn$ unless noted)    1st    2nd    3rd    4th   2010
----------------------------------------------------------------------------
PRICES:                   
Brent Crude Oil (US$/bbl)                  76.23  78.30  76.86  86.48  79.47
WTI Crude Oil (US$/bbl)                    78.71  78.03  76.20  85.12  79.52
Nexen Average - Oil (Cdn$/bbl)             78.00  76.23  77.03  84.47  78.94
NYMEX Natural Gas (US$/mmbtu)               5.04   4.34   4.24   3.97   4.39
AECO Natural Gas (Cdn$/mcf)                 5.08   3.66   3.52   3.41   3.92
Nexen Average - Gas (Cdn$/mcf)              5.37   4.42   4.18   4.16   4.54
----------------------------------------------------------------------------
NETBACKS (1):             
----------------------------------------------------------------------------
United Kingdom            
 Crude Oil:               
  Sales (mbbls/d)                          106.5  102.1  103.9  110.0  105.6
  Price Received ($/bbl)                   77.24  77.18  77.45  83.88  79.02
 Natural Gas:             
  Sales (mmcf/d)                              33     41     29     38     36
  Price Received ($/mcf)                    4.81   4.80   5.11   6.34   5.28
 Total Sales Volume (mboe/d)               112.1  109.0  108.8  116.3  111.5

 Price Received ($/boe)                    74.84  74.12  75.35  81.37  76.51
 Royalties & Other                             -      -      -      -      -
 Operating Costs                            7.60   7.85   8.41   9.19   8.28
 In-country Taxes                          23.48  22.15  23.92  27.64  24.36
----------------------------------------------------------------------------
 Netback                                   43.76  44.12  43.02  44.54  43.87
----------------------------------------------------------------------------
United States             
 Crude Oil:               
  Sales (mbbls/d)                            9.8    9.9    9.8   10.1    9.9
  Price Received ($/bbl)                   79.12  73.60  73.72  80.41  76.73
 Natural Gas:             
  Sales (mmcf/d)                             101     95    102     99     99
  Price Received ($/mcf)                    6.00   5.14   4.70   4.05   4.97
 Total Sales Volume (mboe/d)                26.6   25.8   26.9   26.6   26.5

 Price Received ($/boe)                    51.92  47.23  44.85  45.55  47.35
 Royalties & Other                          4.92   4.86   5.10  (0.63)  3.55
 Operating Costs                            8.96  10.90   9.44  10.78  10.02
----------------------------------------------------------------------------
 Netback                                   38.04  31.47  30.31  35.40  33.78
----------------------------------------------------------------------------
Canada - Natural Gas(2)   
 Sales (mmcf/d)                              124    121    107    104    114

 Price Received ($/mcf)                     5.02   3.72   3.43   3.48   3.94
 Royalties & Other                          0.40   0.34   0.26   0.24   0.32
 Operating Costs                            1.70   1.89   1.90   1.55   1.76
----------------------------------------------------------------------------
 Netback                                    2.92   1.49   1.27   1.69   1.86
----------------------------------------------------------------------------
Yemen 
 Sales (mbbls/d)                            47.3   39.3   43.5   38.8   42.2

 Price Received ($/bbl)                    80.39  80.50  79.33  87.82  81.86
 Royalties & Other                         37.52  36.65  34.75  37.72  36.65
 Operating Costs                            9.67  10.01   9.46  12.05  10.25
 In-country Taxes                          10.14  10.97  10.70  11.52  10.80
----------------------------------------------------------------------------
 Netback                                   23.06  22.87  24.42  26.53  24.16
----------------------------------------------------------------------------

1. Netbacks are defined as average sales price less royalties and other,

operating costs and in-country taxes.

2. Includes Canadian conventional, CBM and shale gas activities. Shale gas

was included beginning in Q4, 2011 when it became commercial.

Nexen Inc.

Oil and Gas Cash Netback (1) (continued)


                                                                      Total
                                                     Quarters - 2011   Year
                                         -----------------------------------
(all dollar amounts in Cdn$ unless noted)   1st    2nd    3rd    4th   2011
----------------------------------------------------------------------------
Other Countries           
 Sales (mbbls/d)                            1.8    1.7    1.6    1.6    1.7

 Price Received ($/bbl)                   93.52 106.57 101.28 110.46 102.71
 Royalties & Other                         6.22   6.93   6.57   7.03   6.68
 Operating Costs                           8.11  10.19   8.58   9.65   9.11
----------------------------------------------------------------------------
 Netback                                  79.19  89.45  86.13  93.78  86.92
----------------------------------------------------------------------------
In Situ(2)                
 Sales (mbbls/d)                           12.9   14.3   11.8   16.7   13.9

 Price Received ($/bbl)                   89.82 108.78  94.15  97.28  98.33
 Royalties & Other                         3.58   6.05   5.07   5.29   5.05
 Operating Costs                          89.43  95.34  85.42  67.41  83.44
----------------------------------------------------------------------------
 Netback (2)                              (3.19)  7.39   3.66  24.58   9.84
----------------------------------------------------------------------------
Syncrude                  
 Sales (mbbls/d)                           23.2   20.4   21.6   18.2   20.8

 Price Received ($/bbl)                   94.60 111.79  97.65 104.32 101.73
 Royalties & Other                         4.30  13.82   4.65  10.59   8.10
 Operating Costs                          36.11  39.98  37.10  38.24  37.78
----------------------------------------------------------------------------
 Netback                                  54.19  57.99  55.90  55.49  55.85
----------------------------------------------------------------------------
Company-Wide              
 Oil and Gas Sales (mboe/d)               225.5  194.3  180.7  197.6  199.2

 Price Received ($/boe)                   85.98  95.31  91.06  94.11  91.46
 Royalties & Other                         8.74  13.47  10.83   8.62  10.34
 Operating & Other Costs (2)              17.32  18.68  20.80  19.56  19.00
 In-country Taxes                         22.84  20.78  20.76  23.08  21.92
----------------------------------------------------------------------------
 Netback                                  37.08  42.38  38.67  42.85  40.20
----------------------------------------------------------------------------

                                                                      Total
                                                     Quarters - 2010   Year
                                         -----------------------------------
(all dollar amounts in Cdn$ unless noted)   1st    2nd    3rd    4th   2010
----------------------------------------------------------------------------
Other Countries           
 Sales (mbbls/d)                            2.3    2.1    2.0    1.9    2.1

 Price Received ($/bbl)                   78.88  74.77  75.93  77.63  76.83
 Royalties & Other                         5.72   5.28   5.22   5.24   5.37
 Operating Costs                           5.58   7.42   6.98   8.19   6.99
----------------------------------------------------------------------------
 Netback                                  67.58  62.07  63.73  64.20  64.47
----------------------------------------------------------------------------
In Situ(2)                
 Sales (mbbls/d)                            6.6   10.3   11.9   12.1   10.3

 Price Received ($/bbl)                   81.04  74.08  70.64  82.99  77.07
 Royalties & Other                         4.37   2.98   3.08   3.81   3.65
 Operating Costs                         154.00  89.95  84.75  85.61 100.09
----------------------------------------------------------------------------
 Netback (2)                             (77.33)(18.85)(17.19) (6.43)(26.67)
----------------------------------------------------------------------------
Syncrude                  
 Sales (mbbls/d)                           19.5   23.4   19.1   22.8   21.2

 Price Received ($/bbl)                   83.55  77.93  78.27  85.12  81.23
 Royalties & Other                         7.09   6.37   4.82   6.72   6.27
 Operating Costs                          35.84  32.67  38.06  31.65  34.34
----------------------------------------------------------------------------
 Netback                                  40.62  38.89  35.39  46.75  40.62
----------------------------------------------------------------------------
Company-Wide              
 Oil and Gas Sales (mboe/d)               249.1  243.1  232.9  235.9  240.2

 Price Received ($/boe)                   70.16  67.56  68.23  74.49  70.11
 Royalties & Other                         9.38   8.05   7.96   7.13   8.16
 Operating & Other Costs (2)              14.93  15.85  15.42  15.97  15.48
 In-country Taxes                         12.49  11.59  13.17  15.52  13.21
----------------------------------------------------------------------------
 Netback                                  33.36  32.07  31.68  35.87  33.26
----------------------------------------------------------------------------

1. Netbacks are defined as average sales price less royalties and other,

operating costs and in-country taxes.

2. Excludes activities related to third-party bitumen purchased, processed

and sold.

Nexen Inc.

Unaudited Condensed Consolidated Statement of Income

For the Three and Twelve Months Ended December 31


                                           Three Months       Twelve Months
(Cdn$ millions, except per-share      Ended December 31   Ended December 31
 amounts)                                2011      2010      2011      2010
----------------------------------------------------------------------------
Revenues and Other Income 
 Net Sales                              1,665     1,523     6,169     5,496
 Marketing and Other Income (Note 13)      29        19       295       323
                                      --------------------------------------
                                        1,694     1,542     6,464     5,819
                                      --------------------------------------
Expenses                  
 Operating                                371       358     1,431     1,336
 Depreciation, Depletion, Amortization     
  and Impairment (Note 5)                 799       492     1,913     1,628
 Transportation and Other                 136       102       425       566
 General and Administrative                96       164       300       428
 Exploration                               90       129       368       328
 Finance (Note 8)                          58        89       251       362
 Loss on Debt Redemption and               
  Repurchase (Note 7)                       -         -        91         -
 Net (Gain) Loss from Dispositions        (38)     (138)      (38)       41
                                      --------------------------------------
                                        1,512     1,196     4,741     4,689
                                      --------------------------------------

Income from Continuing Operations          
 before Provision for Income Taxes        182       346     1,723     1,130
                                      --------------------------------------

Provision for (Recovery of) Income                                          
 Taxes
 Current                                  425       332     1,584     1,125
 Deferred                                (286)     (145)     (256)     (449)
                                      --------------------------------------
                                          139       187     1,328       676
                                      --------------------------------------

Net Income from Continuing Operations      43       159       395       454
Net Income from Discontinued               
 Operations, Net of Tax (Note 14)           -         1       302       673
                                      --------------------------------------
Net Income Attributable to Nexen Inc.      
 Shareholders                              43       160       697     1,127
                                      --------------------------------------
                                      --------------------------------------

Earnings Per Common Share from             
 Continuing Operations ($/share)           
 Basic                                   0.08      0.30      0.75      0.87
                                      --------------------------------------
                                      --------------------------------------

 Diluted                                 0.08      0.30      0.69      0.86
                                      --------------------------------------
                                      --------------------------------------

Earnings Per Common Share ($/share)        
 Basic                                   0.08      0.30      1.32      2.15
                                      --------------------------------------
                                      --------------------------------------

 Diluted                                 0.08      0.30      1.24      2.09
                                      --------------------------------------
                                      --------------------------------------

See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.

Nexen Inc.

Unaudited Condensed Consolidated Balance Sheet


                                         December 31  December 31  January 1
(Cdn$ millions)                                 2011         2010       2010
----------------------------------------------------------------------------
Assets
 Current Assets           
  Cash and Cash Equivalents                      845        1,005      1,700
  Restricted Cash                                 45           40        198
  Accounts Receivable (Note 3)                 2,247        1,789      2,322
  Derivative Contracts                           119          158        479
  Inventories and Supplies (Note 4)              320          550        680
  Other                                          115          133        172
  Assets Held for Sale (Note 14)                   -          729          -
                                         -----------------------------------
   Total Current Assets                        3,691        4,404      5,551
                                         -----------------------------------
 Non-Current Assets       
  Property, Plant and Equipment (Note 5)      15,571       14,579     14,669
  Goodwill                                       291          286        330
  Deferred Income Tax Assets                     338          160         75
  Derivative Contracts                            25          116        229
  Other Long-Term Assets                         152          102        101
                                         -----------------------------------
Total Assets                                  20,068       19,647     20,955
                                         -----------------------------------
                                         -----------------------------------

Liabilities               
 Current Liabilities      
  Accounts Payable and Accrued             
   Liabilities (Note 6)                        2,867        2,223      2,591
  Current Income Taxes Payable                   458          345        179
  Derivative Contracts                           103          168        482
  Liabilities Held for Sale (Note 14)              -          582          -
                                         -----------------------------------
   Total Current Liabilities                   3,428        3,318      3,252
                                         -----------------------------------
 Non-Current Liabilities  
  Long-Term Debt (Note 7)                      4,383        5,090      7,259
  Deferred Income Tax Liabilities              1,488        1,487      1,678
  Asset Retirement Obligations (Note 9)        2,010        1,516      1,397
  Derivative Contracts                            24          115        210
  Other Long-Term Liabilities                    362          307        372
Equity (Note 11)          
 Nexen Inc. Shareholders' Equity           
  Share Capital                                1,157        1,111      1,050
  Retained Earnings                            7,211        6,692      5,704
  Cumulative Translation Adjustment                5          (37)         -
                                         -----------------------------------
 Total Nexen Inc. Shareholders' Equity         8,373        7,766      6,754
  Canexus Non-Controlling Interest (Note   
   14)                                             -           48         33
                                         -----------------------------------
 Total Equity                                  8,373        7,814      6,787
                                         -----------------------------------
Total Liabilities and Equity                  20,068       19,647     20,955
                                         -----------------------------------
                                         -----------------------------------

See accompanying notes to Unaudited Condensed Consolidated Financial Statements.

Nexen Inc.

Unaudited Condensed 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)                          2011      2010      2011      2010
----------------------------------------------------------------------------
Operating Activities      
 Net Income from Continuing Operations     43       159       395       454
 Net Income from Discontinued              
  Operations                                -         1       302       673
 Charges and Credits to Income not         
  Involving Cash (Note 15)                460       266     1,335       727
 Exploration Expense                       90       129       368       328
 Changes in Non-Cash Working Capital       
  (Note 15)                               (32)      (72)      255       338
 Other                                   (102)     (141)     (158)     (128)
                                      --------------------------------------
                                          459       342     2,497     2,392

Financing Activities      
 Repayment of Term Credit Facilities,      
  Net                                       -         2         -    (1,538)
 Repayment of Long-Term Debt (Note 7)       -         -      (871)        -
 Proceeds from Canexus Long-Term Debt,     
  Net                                       -       (12)        -       112
 Dividends Paid on Common Shares          (27)      (26)     (105)     (104)
 Issue of Common Shares and Exercise       
  of Tandem Options for Shares              7        11        46        55
 Other                                     (4)       (3)       (2)      (31)
                                      --------------------------------------
                                          (24)      (28)     (932)   (1,506)

Investing Activities      
 Capital Expenditures     
  Exploration, Evaluation, and             
   Development                           (723)     (467)   (2,431)   (2,334)
  Proved Property Acquisitions              -       (79)        -       (79)
  Corporate and Other                     (43)      (71)      (93)     (243)
 Proceeds from Dispositions                43       218       518     1,264
 Changes in Restricted Cash                 6        (3)       (4)       37
 Changes in Non-Cash Working Capital       
  (Note 15)                               137       (29)      321       (59)
 Other                                      7       (43)      (68)      (51)
                                      --------------------------------------
                                         (573)     (474)   (1,757)   (1,465)

Effect of Exchange Rate Changes on         
 Cash and Cash Equivalents                (42)      (45)       32      (116)
                                      --------------------------------------

Increase (Decrease) in Cash and Cash       
 Equivalents                             (180)     (205)     (160)     (695)

Cash and Cash Equivalents - Beginning      
 of Period                              1,025     1,210     1,005     1,700
                                      --------------------------------------

Cash and Cash Equivalents - End of         
 Period (1)                               845     1,005       845     1,005
                                      --------------------------------------
                                      --------------------------------------

1.  Cash and cash equivalents at December 31, 2011 consists of cash of $283
    million and short-term investments of $562 million (December 31, 2010 -
    cash of $345 million and short-term investments of $660 million).

See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.

Nexen Inc.

Unaudited Condensed Consolidated Statement of Changes in Equity

For the Three and Twelve Months Ended December 31


                                           Three Months       Twelve Months
                                      Ended December 31   Ended December 31
(Cdn$ millions)                          2011      2010      2011      2010
----------------------------------------------------------------------------

Share Capital, Beginning of Period      1,150     1,097     1,111     1,050
  Issue of Common Shares                    6         9        45        50
  Exercise of Tandem Options for           
   Shares                                   1         2         1         5
  Accrued Liability Relating to Tandem     
   Options Exercised For Common Shares      -         3         -         6
                                      --------------------------------------
 Balance at End of Period               1,157     1,111     1,157     1,111
                                      --------------------------------------
                                      --------------------------------------

Retained Earnings, Beginning of Period  7,268     6,593     6,692     5,704
  Net Income Attributable to Nexen         
   Inc. Shareholders                       43       160       697     1,127
  Actuarial Losses of Defined Benefit      
   Pension Plans                          (73)      (35)      (73)      (35)
  Dividends on Common Shares (Note 11)    (27)      (26)     (105)     (104)
                                      --------------------------------------
 Balance at End of Period               7,211     6,692     7,211     6,692
                                      --------------------------------------
                                      --------------------------------------

Cumulative Translation Adjustment,         
 Beginning of Period                        8       (14)      (37)        -
  Currency Translation Adjustment         (12)      (23)       33       (37)
  Realized Translation Adjustments (1)      9         -         9         -
                                      --------------------------------------
 Balance at End of Period                   5       (37)        5       (37)
                                      --------------------------------------
                                      --------------------------------------

Canexus Non-Controlling Interests,         
 Beginning of Period                        -        48        48        33
  Net Income Attributable to Non-          
   Controlling Interests                    -         1         1         5
  Distributions Declared to Non-           
   Controlling Interests                    -        (5)        -       (17)
  Issue of Partnership Units to Non-       
   Controlling Interests                    -         4         -        27
  Disposition of Canexus (Note 14)          -         -       (49)        -
                                      --------------------------------------
 Balance at End of Period                   -        48         -        48
                                      --------------------------------------
                                      --------------------------------------

1.  Net of income tax recovery for the three months ended December 31, 2011
    of $6 million (2010 - net of income tax expense of $4 million) and net
    of income tax expense for the twelve months ended December 31, 2011 of
    $18 million (2010 - net of income tax expense of $4 million).

See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.

Nexen Inc.

Unaudited Condensed 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)                          2011      2010      2011      2010
----------------------------------------------------------------------------
Net Income Attributable to Nexen Inc.      
 Shareholders                              43       160       697     1,127
 Other Comprehensive Income (Loss):        
  Currency Translation Adjustment          
   Net Translation Gains (Losses) of       
    Foreign Operations                    (91)     (176)      109      (264)
   Net Translation Gains (Losses) on       
    US-Denominated Debt Hedging of         
    Foreign Operations (1)                 79       153       (76)      227
                                      --------------------------------------
  Total Currency Translation               
   Adjustment                             (12)      (23)       33       (37)
  Actuarial Losses of Defined Benefit      
   Pension Plans (2)                      (73)      (35)      (73)      (35)
                                      --------------------------------------
 Other Comprehensive Loss                 (85)      (58)      (40)      (72)
                                      --------------------------------------
Total Comprehensive Income (Loss)         (42)      102       657     1,055
                                      --------------------------------------
                                      --------------------------------------

1.  Net of income tax expense for the three months ended December 31, 2011
    of $11 million (2010 - net of income tax expense of $22 million) and net
    of income tax recovery for the twelve months ended December 31, 2011 of
    $11 million (2010 - net of income tax expense of $32 million).
2.  Net of income tax recovery for the three months ended December 31, 2011
    of $24 million (2010 - net of income tax recovery of $11 million) and
    net of income tax recovery for the twelve months ended December 31, 2011
    of $24 million (2010 - net of income tax recovery of $11 million).

See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.

Nexen Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Cdn$ millions, except as noted

1. BASIS OF PRESENTATION

Nexen Inc. (Nexen, we or our) is an independent, global energy company with operations in the North Sea, Gulf of Mexico, offshore West Africa, Canada, Yemen and Colombia. Nexen is incorporated and domiciled in Canada and our head office is located at 801-7th Avenue SW, Calgary, Alberta, Canada. Nexen's shares are publicly traded on both the Toronto Stock Exchange and the New York Stock Exchange.

These Unaudited Condensed Consolidated Financial Statements for the three and twelve months ended December 31, 2011 have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting. The Unaudited Condensed Consolidated Financial Statements do not include all of the information required for annual financial statements. Amounts relating to the three and twelve months ended December 31, 2010 were previously presented in accordance with Canadian GAAP. These amounts have been restated as necessary to be compliant with our accounting policies under International Financial Reporting Standards (IFRS) (see Note 2). Reconciliations and descriptions relating to the transition from Canadian GAAP to IFRS are included in Note 17.

The Unaudited Condensed Consolidated Financial Statements were authorized for issue on February 15, 2012 and should be read in conjunction with the Audited Consolidated Financial Statements for the year ended December 31, 2010, which have been prepared in accordance with Canadian GAAP.

2. ACCOUNTING POLICIES

The accounting policies we follow are described in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011.

Future Changes in Accounting Policies

As part of our transition to IFRS, we have adopted all IFRS accounting standards in effect on December 31, 2011.

The following standards and interpretations have not been adopted as they apply to future periods. They may result in future changes to our existing accounting policies and other note disclosures. We are evaluating the impacts that these standards may have on our results of operations, financial position and disclosure, except where indicated.


--  IFRS 7 Financial Instruments: Disclosures - in December 2011, the
    International Accounting Standards Board (IASB) issued final amendments
    to the disclosure requirements for the offsetting of a financial asset
    and financial liabilities when offsetting is permitted under IFRS. The
    disclosure amendments are required to be adopted retrospectively for
    periods beginning January 1, 2013.
--  IFRS 9 Financial Instruments - in November 2009, the IASB issued IFRS 9
    to address classification and measurement of financial assets. In
    October 2010, the IASB revised the standard to include financial
    liabilities. The standard is required to be adopted for periods
    beginning January 1, 2015. Portions of the standard remain in
    development and the full impact of the standard will not be known until
    the project is complete.
--  IFRS 10 Consolidated Financial Statements - in May 2011, the IASB issued
    IFRS 10 which provides additional guidance to determine whether an
    investee should be consolidated. The guidance applies to all investees,
    including special purpose entities. The standard replaces IAS 27 (which
    still contains guidance on separate financial statements) and is
    required to be adopted for periods beginning January 1, 2013. We do not
    expect the adoption of this standard to impact our results of operations
    or financial position.
--  IFRS 11 Joint Arrangements - in May 2011, the IASB issued IFRS 11 which
    presents a new model for determining whether an entity should account
    for joint arrangements using proportionate consolidation or the equity
    method. An entity will have to follow the substance rather than legal
    form of a joint arrangement and will no longer have a choice of
    accounting method. The standard also amends IAS 28 to include joint
    ventures and is required to be adopted for periods beginning January 1,
    2013.
--  IFRS 12 Disclosure of Interests in Other Entities - in May 2011, the
    IASB issued IFRS 12 which aggregates and amends disclosure requirements
    included within other standards. The standard requires a company to
    provide disclosures about subsidiaries, joint arrangements, associates
    and unconsolidated structured entities. The standard is required to be
    adopted for periods beginning January 1, 2013. We expect this standard
    to result in additional disclosures in our financial statements.
--  IFRS 13 Fair Value Measurement - in May 2011, the IASB issued IFRS 13 to
    provide comprehensive guidance for instances where IFRS requires fair
    value to be used. The standard provides guidance on determining fair
    value and requires disclosures about those measurements. The standard is
    required to be adopted for periods beginning January 1, 2013. We do not
    expect a material impact on our results of operations or financial
    position.
--  IAS 1 Presentation of Items of Other Comprehensive Income - in June
    2011, the IASB issued amendments to IAS 1 Presentation of Financial
    Statements to separate items of other comprehensive income (OCI) between
    those that are reclassed to income and those that do not. The standard
    is required to be adopted for periods beginning on or after July 1,
    2012. We do not expect a significant change to our presentation of items
    of other comprehensive income.
--  IAS 19 Employee Benefits - in June 2011, the IASB issued amendments to
    IAS 19 to revise certain aspects of the accounting for pension plans and
    other benefits. The amendments eliminate the corridor method of
    accounting for defined benefit plans, change the recognition pattern of
    gains and losses, and require additional disclosures. The standard is
    required to be adopted for periods beginning on or after January 1,
    2013.
--  IAS 32 Financial Instruments: Presentation - in December 2011, the IASB
    issued amendments to address inconsistencies when applying the
    offsetting criteria outlined in this standard. These amendments clarify
    certain of the criteria required to be met in order to permit the
    offsetting of financial assets and financial liabilities. The standard
    is required to be adopted retrospectively for periods beginning January
    1, 2014.

3. ACCOUNTS RECEIVABLE


                                      December 31   December 31   January 1
                                             2011          2010        2010
----------------------------------------------------------------------------
Trade 
 Energy Marketing                           1,146           929       1,410
 Oil and Gas                                1,037           822         823
 Other                                          3             2          44
                                      --------------------------------------
                                            2,186         1,753       2,277
Non-Trade                                      73            80          99
                                      --------------------------------------
                                            2,259         1,833       2,376
Allowance for Doubtful Receivables (1)        (12)          (44)        (54)
                                      --------------------------------------
Total (2)                                   2,247         1,789       2,322
                                      --------------------------------------
                                      --------------------------------------

1.  Includes a general provision of $1 million and a specific provision
    against certain accounts. In 2011, allowance for doubtful receivables
    decreased as a result of reassessing prior impairment provisions. In
    2010, allowance for doubtful receivables decreased primarily from a
    reduction in counterparty credit reserves.
2.  At December 31, 2010, accounts receivable related to our chemicals
    operations have been included with assets held for sale (see Note 14).

Receivables terms are up to 30-days and were current as of December 31, 2011, December 31, 2010 and January 1, 2010.

4. INVENTORIES AND SUPPLIES


                                       December 31   December 31   January 1
                                              2011          2010        2010
----------------------------------------------------------------------------
Finished Products         
 Energy Marketing                              230           452         548
 Oil and Gas                                    36            35          25
 Other                                           -             -          12
                                       -------------------------------------
                                               266           487         585
Work in Process                                  6             5           7
Field Supplies                                  48            58          88
                                       -------------------------------------
Total (1)                                      320           550         680
                                       -------------------------------------
                                       -------------------------------------


1.  At December 31, 2010, inventories and supplies related to our chemicals
    operations have been included with assets held for sale (see Note 14).

5. PROPERTY, PLANT AND EQUIPMENT (PP&E)

(a) Carrying amount of PP&E


                  Exploration        Assets   Producing
                          and         Under   Oil & Gas  Corporate
                   Evaluation  Construction  Properties  and Other    Total
----------------------------------------------------------------------------
Cost  
 As at January 1,         
  2010                  2,393         1,045      20,020      1,849   25,307
  Additions             1,092           693         696        243    2,724
  Disposals/              
   Derecognitions         (70)           (8)     (1,638)      (122)  (1,838)
  Transfers               (82)           78           4          -        -
  Exploration             
   Expense               (328)            -           -          -     (328)
  Transferred to          
   Held for Sale            -             -           -     (1,207)  (1,207)
  Other                    36            15         408         (3)     456
  Effect of               
   Changes in             
   Exchange Rate          (51)          (75)       (603)        (3)    (732)
                  ----------------------------------------------------------
 As at December           
  31, 2010              2,990         1,748      18,887        757   24,382
  Additions             1,056           734         693         92    2,575
  Disposals/              
   Derecognitions        (303)            -      (2,004)       (18)  (2,325)
  Transfers            (1,253)         (216)      1,469          -        -
  Exploration             
   Expense               (368)            -           -          -     (368)
  Other                    65            31         493          -      589
  Effect of               
   Changes in             
   Exchange Rate           19            50         294          6      369
                  ----------------------------------------------------------
 As at December           
  31, 2011              2,206         2,347      19,832        837   25,222
                  ----------------------------------------------------------
                  ----------------------------------------------------------

Accumulated               
 Depreciation,            
 Depletion &              
 Amortization             
 (DD&A)                   
 As at January 1,         
  2010                    360            11       9,325        942   10,638
  DD&A                     41             -       1,384        119    1,544
  Disposals/              
   Derecognitions         (59)           (8)     (1,378)       (62)  (1,507)
  Impairments               -             -         139          -      139
  Transferred to          
   Held for Sale            -             -           -       (578)    (578)
  Other                     1             -          (7)        (5)     (11)
  Effect of               
   Changes in             
   Exchange Rate          (12)           (3)       (409)         2     (422)
                  ----------------------------------------------------------
 As at December           
  31, 2010                331             -       9,054        418    9,803
  DD&A                     50             -       1,210         78    1,338
  Disposals/              
   Derecognitions         (12)            -      (1,938)       (75)  (2,025)
  Impairments               -             -         322          -      322
  Other                    (6)            -          (8)         -      (14)
  Effect of               
   Changes in             
   Exchange Rate            5             -         220          2      227
                  ----------------------------------------------------------
 As at December           
  31, 2011                368             -       8,860        423    9,651
                  ----------------------------------------------------------
                  ----------------------------------------------------------

Net Book Value            
 As at January 1,         
  2010                  2,033         1,034      10,695        907   14,669
                  ----------------------------------------------------------
                  ----------------------------------------------------------
 As at December           
  31, 2010              2,659         1,748       9,833        339   14,579
                  ----------------------------------------------------------
                  ----------------------------------------------------------
 As at December           
  31, 2011              1,838         2,347      10,972        414   15,571
                  ----------------------------------------------------------
                  ----------------------------------------------------------

Exploration and evaluation assets mainly comprise of unproved properties and capitalized exploration drilling costs. Assets under construction primarily include our Usan development, offshore Nigeria and developments in the UK North Sea.

(b) Impairment

DD&A expense for 2011 includes non-cash impairment charges of $322 million for our oil and gas properties in our Conventional North America segment. Canadian natural gas assets were impaired $234 million in the second half of 2011 due to lower estimated future natural gas prices and performance-related negative reserve revisions. In the fourth quarter, lower estimated future natural gas prices and higher estimated future abandonment costs resulted in an $88 million impairment of mature Gulf of Mexico properties.

DD&A expense for 2010 includes non-cash impairment charges of $139 million for properties in the US Gulf of Mexico and Canada. In the second half of 2010, low natural gas prices, higher estimated future abandonment costs and declining production performance impaired these properties.

The properties were written down to the higher amount of value-in-use and estimated fair value less costs to sell. We estimated fair value based on discounted future net cash flows using estimated future prices, a discount rate of 9% and management's estimate of future production, capital and operating expenditures.

(c) Asset Derecognitions

Nexen's original strategy for future oil sands development was to build duplicates of the existing Long Lake SAGD facilities and upgrader. We now expect to pursue smaller, phased, SAGD-only projects and we will consider adding upgrading capacity once we are bitumen-long and economic conditions are favourable. As a result, previously capitalized design and engineering costs of $253 million on the future phases have been expensed.

6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES


                                       December 31   December 31   January 1
                                              2011          2010        2010
----------------------------------------------------------------------------
Energy Marketing Payables                    1,287         1,016       1,366
Accrued Payables                             1,035           676         619
Trade Payables                                 288           164         210
Other                                          122           147         108
Accrued Interest Payable                        78            83          89
Stock-Based Compensation                        31           111         173
Dividends Payable                               26            26          26
                                      --------------------------------------
Total (1)                                    2,867         2,223       2,591
                                      --------------------------------------
                                      --------------------------------------

1.  At December 31, 2010, accounts payable and accrued liabilities related
    to our chemicals operations have been included with liabilities held for
    sale (see Note 14).

7. LONG-TERM DEBT


                                      December 31   December 31   January 1
                                             2011          2010        2010
----------------------------------------------------------------------------
Term Credit Facilities (a)                      -             -       1,570
Notes, due 2013 (b)                             -           497         523
Notes, due 2015 (US$126 million) (c)          128           249         262
Notes, due 2017 (US$62 million) (c)            63           249         262
Notes, due 2019 (US$300 million)              305           298         314
Notes, due 2028 (US$200 million)              203           199         209
Notes, due 2032 (US$500 million)              509           497         523
Notes, due 2035 (US$790 million)              804           786         827
Notes, due 2037 (US$1,250 million)          1,271         1,243       1,308
Notes, due 2039 (US$700 million)              712           696         733
Subordinated Debentures, due 2043          
 (US$460 million)                             468           457         481
                                      --------------------------------------
                                            4,463         5,171       7,012
Unamortized Debt Issue Costs                  (80)          (81)        (88)
                                      --------------------------------------
                                            4,383         5,090       6,924
Canexus Debt (1)                                -             -         335
                                      --------------------------------------
Total                                       4,383         5,090       7,259
                                      --------------------------------------
                                      --------------------------------------

1.  At December 31, 2010, long-term debt related to our chemicals operations
    have been included with liabilities held for sale (see Note 14).

(a) Term credit facilities

We have committed unsecured term credit facilities of $3.8 billion (US$3.7 billion) which were not drawn at either December 31, 2011 or December 31, 2010 (January 1, 2010-$1.6 billion (US$1.5 billion)). Of these facilities, $700 million is available until 2014 and $3.1 billion is available until 2016. 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. At December 31, 2011, $367 million of these facilities were utilized to support outstanding letters of credit (December 31, 2010-$322 million and January 1, 2010-$407 million).

(b) Redemption of Notes, due 2013

In the second quarter 2011, we redeemed and cancelled US$500 million of principal from bonds due in 2013. We paid $525 million for the redemption. We recorded a $52 million loss as the difference between carrying value and the redemption price.

(c) Repurchase for Cancellation of Certain 2015 and 2017 Notes

In the first quarter 2011, we repurchased and cancelled US$124 million and US$188 million of principal from the 2015 and 2017 bonds, respectively. We paid $346 million for the repurchase and recorded a $39 million loss as the difference between carrying value and the redemption price.

(d) Credit Facilities

Nexen has uncommitted, unsecured credit facilities of approximately $180 million (US$178 million), none of which were drawn at December 31, 2011, December 31, 2010 or January 1, 2010. We utilized $17 million of these facilities to support outstanding letters of credit at December 31, 2011 (December 31, 2010-$112 million and January 1, 2010-$86 million). Interest is payable at floating rates.

Nexen has uncommitted, unsecured credit facilities exclusive to letters of credit of approximately $213 million (US$210 million). We utilized $4 million of these facilities to support outstanding letters of credit at December 31, 2011 (December 31, 2010-nil and January 1, 2010-nil).

8. FINANCE EXPENSE


                                           Three Months       Twelve Months
                                      Ended December 31   Ended December 31
                                         2011      2010      2011      2010
----------------------------------------------------------------------------
Long-Term Debt Interest Expense            73        92       304       361
Accretion Expense related to Asset         
 Retirement Obligations (Note 9)            9        16        44        47
Other Interest Expense and Fees            10         4        27        34
                                    ----------------------------------------
Total                                      92       112       375       442
 Less: Capitalized at 6.7% (2010 -         
  5.8%)                                   (34)      (23)     (124)      (80)
                                    ----------------------------------------
Total (1)                                  58        89       251       362
                                    ----------------------------------------
                                    ----------------------------------------

1.  Excludes interest expense related to our chemical operations (see Note
    14).

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.

9. ASSET RETIREMENT OBLIGATIONS (ARO)

Changes in the carrying amount of our ARO provisions are as follows:


                                           Twelve Months      Twelve Months
                                       Ended December 31  Ended December 31
                                                    2011               2010
----------------------------------------------------------------------------
ARO, Beginning of Period                           1,571              1,432
 Obligations Incurred with Development     
  Activities                                          69                 81
 Changes in Estimates                                450                332
 Obligations Related to Dispositions                  (9)              (224)
 Obligations Settled                                 (72)               (43)
 Accretion                                            44                 47
 Effects of Changes in Foreign Exchange    
  Rates                                               23                (54)
                                         -----------------------------------
ARO, End of Period (1)                             2,076              1,571
                                         -----------------------------------
                                         -----------------------------------

Of which:                 
 Due within Twelve Months (2)                         66                 55
 Due after Twelve Months                           2,010              1,516
                                           ---------------------------------
                                           ---------------------------------

1.  At December 31, 2010, asset retirement obligations related to our
    chemicals operations have been included with liabilities held for sale
    (see Note 14).
2.  Included in accounts payable and accrued liabilities.

ARO represents the present value of estimated remediation and reclamation costs associated with our PP&E. We discounted the estimated asset retirement obligation using a weighted-average, credit-adjusted risk-free rate of 2.6% (2010-3.3%). While the provision for abandonment is based on our best estimates of future costs and the economic lives of the assets involved, there is uncertainty regarding both the amount and timing of incurring these costs. We expect approximately $428 million included in our ARO will be settled over the next five years with the balance settling beyond that. We expect to fund ARO from future cash flows from our operations.

10. RELATED PARTY DISCLOSURES

Major subsidiaries

The Unaudited Condensed Consolidated Financial Statements include the financial statements of Nexen Inc. and our subsidiaries as at December 31, 2011. The following is a list of the major subsidiaries of our operations. Transactions between subsidiaries are eliminated on consolidation. Nexen did not have any material related party transactions with entities outside the consolidated group in the years ended December 31, 2011 and 2010.



                                   Jurisdiction of    Principal   
Major Subsidiaries                   Incorporation   Activities   Ownership
----------------------------------------------------------------------------
Nexen Petroleum UK Limited       England and Wales    Oil & Gas         100%
Nexen Petroleum Nigeria Limited            Nigeria    Oil & Gas         100%
Nexen Petroleum Offshore USA Inc.          Delaware   Oil & Gas         100%
Nexen Marketing                            Alberta    Marketing         100%
Canadian Nexen Petroleum Yemen               Yemen    Oil & Gas         100%
Nexen Oil Sands Partnership                Alberta    Oil & Gas         100%

11. EQUITY

(a) Authorized Capital

Authorized share capital consists of an unlimited number of common shares of no par value and an unlimited number of Class A preferred shares of no par value, issuable in series. At December 31, 2011, there were 527,892,635 common shares outstanding (December 31, 2010-525,706,403 shares; January 1, 2010-522,915,843 shares). There were no preferred shares issued and outstanding as at December 31, 2011 (December 31, 2010-nil; January 1, 2010-nil). The rights, privileges, restrictions and conditions attached to common shares include a vote at all meetings of shareholders they are invited to, the receipt of any dividend declared by the board of directors on the common shares, and receipt of all remaining property of Nexen upon dissolution.

(b) Dividends

Dividends paid per common share for the three months ended December 31, 2011 were $0.05 per common share (three months ended December 31, 2010-$0.05). Dividends per common share for the year ended December 31, 2011 were $0.20 per common share (year ended December 31, 2010-$0.20). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.

On February 15, 2012, the board of directors declared a quarterly dividend of $0.05 per common share, payable April 1, 2012 to the shareholders of record on March 9, 2012.

12. COMMITMENTS, CONTINGENCIES AND GUARANTEES

As described in Note 15 to the 2010 Audited Consolidated Financial Statements, 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 believe that payments, if any, related to existing indemnities, would not have a material adverse effect on our liquidity, financial condition or results of operations.

We assume various contractual obligations and commitments in the normal course of our operations. During the quarter, we entered into commitments comprised of the following:


                                2012   2013   2014   2015   2016  Thereafter
----------------------------------------------------------------------------
Operating Leases                   -      2      4      4      4          51
Transportation, Processing and             
 Storage Commitments              15     14     24     13     13          39
Drilling Rig Commitments          59     16      4      -      -           -
                              ----------------------------------------------

The commitments above are in addition to those included in Note 15 to the 2010 Audited Consolidated Financial Statements. Our operating leases, transportation and storage commitments, and other drilling rig commitments as at December 31, 2011 have not materially changed from the information previously disclosed in our 2010 Audited Consolidated Financial Statements.

13. MARKETING AND OTHER INCOME


                                           Three Months       Twelve Months
                                      Ended December 31   Ended December 31
                                         2011      2010      2011      2010
----------------------------------------------------------------------------
Marketing Revenue, Net                     21        57       195       337
Insurance Proceeds                          -         -        26         -
Change in Fair Value of Crude Oil Put      
 Options                                  (29)      (22)      (23)      (41)
Foreign Exchange Gains (Losses)            22       (32)       36       (38)
Other                                      15        16        61        65
                                      --------------------------------------
Total                                      29        19       295       323
                                      --------------------------------------
                                      --------------------------------------

14. DISPOSITIONS

(a) Discontinued Operations

In February 2011, we completed the sale of our 62.7% investment in Canexus, which operates a chemicals business, for net proceeds of $458 million and we realized a gain on disposition of $348 million in the first quarter. In the fourth quarter of 2010, we received board approval to sell our interest in Canexus and classified the assets and liabilities as held for sale at December 31, 2010. The gain on sale and results of our chemicals business have been presented as discontinued operations.

In July 2010, we completed the sale of our heavy oil properties in Canada. We received proceeds of $939 million, net of closing adjustments and realized a gain on disposition of $828 million in the third quarter of 2010. The gain on sale and results of operations of these properties have been presented as discontinued operations.


                                                         Three Months Ended
                                                                December 31
                                                                       2010
                                                         -------------------
                                                                  Chemicals
----------------------------------------------------------------------------
Revenues and Other Income 
 Net Sales                                                              120
 Other                                                                   12
                                                         -------------------
                                                                        132
                                                         -------------------
Expenses                  
 Operating                                                               80
 Depreciation, Depletion, Amortization and Impairment                    15
 Transportation and Other                                                19
 General and Administrative                                              12
 Finance                                                                  7
                                                         -------------------
                                                                        133
                                                         -------------------
Loss before Provision for Income Taxes                                   (1)
 Less: Recovery of Deferred Income Taxes                                 (1)
                                                         -------------------

Income before Non-Controlling Interests                                   -
 Less: Non-Controlling Interests                                         (1)
                                                         -------------------
Net Income from Discontinued Operations, Net of Tax                       1
                                                         -------------------
                                                         -------------------

Earnings Per Common Share 
 Basic                                                                 0.00
 Diluted                                                               0.00
                                                         -------------------


                                        Twelve Months Ended December 31 
                                         2011              2010   
                                   -----------------------------------------
                                    Chemicals     Canada Chemicals     Total
----------------------------------------------------------------------------
Revenues and Other Income 
  Net Sales                                42        138       456       594
  Other                                    (1)         -        25        25
  Gain on Disposition                     348        828         -       828
                                   -----------------------------------------
                                          389        966       481     1,447
                                   -----------------------------------------
Expenses                  
  Operating                                25         50       308       358
  Depreciation, Depletion,
   Amortization and Impairment              4         20        35        55
  Transportation and Other                  2          2        60        62
  General and Administrative                2         10        38        48
  Finance                                   2          3        19        22
                                   -----------------------------------------
                                           35         85       460       545
                                   -----------------------------------------
Income before Provision for Income         
 Taxes                                    354        881        21       902
  Less: Provision for Deferred             
   Income Taxes                            51        220         4       224
                                   -----------------------------------------

Income before Non-Controlling              
 Interests                                303        661        17       678
  Less: Non-Controlling Interests           1          -         5         5
                                   -----------------------------------------
Net Income from Discontinued               
 Operations, Net of Tax                   302        661        12       673
                                   -----------------------------------------
                                   -----------------------------------------

Earnings Per Common Share 
  Basic                                  0.57                           1.28
  Diluted                                0.55                           1.23
                                   -----------------------------------------

The following table provides the assets and liabilities that are associated with our chemicals business at December 31, 2010 and January 1, 2010. There were no assets or liabilities related to our chemical operations at December 31, 2011.


                                                    December 31    January 1
                                                           2010         2010
----------------------------------------------------------------------------
Cash and Cash Equivalents                                     3           14
Accounts Receivable                                          48           54
Inventories and Supplies                                     35           33
Other Current Assets                                          1            3
Property, Plant and Equipment, Net of Accumulated      
 DD&A                                                       629          535
Deferred Income Tax Assets                                    7            4
Other Long-Term Assets                                        6           11
                                                  --------------------------
  Assets                                                  729(1)         654
                                                  --------------------------
Accounts Payable and Accrued Liabilities                     59           64
Accrued Interest Payable                                      3            -
Long-Term Debt                                              414          335
Deferred Income Tax Liabilities                              15           11
Asset Retirement Obligations                                 73           74
Other Long-Term Liabilities                                  18           16
                                                  --------------------------
  Liabilities                                             582(1)         500
                                                  --------------------------
  Equity - Canexus Non-Controlling Interest                  48           33
                                                  --------------------------

1. Included in assets and liabilities held for sale at December 31, 2010.

Amounts related to prior periods have not been reclassified.

(b) Asset Dispositions

UK North Sea

During the fourth quarter of 2011, we sold our non-operated working interest in the Duart field for proceeds of $38 million. The sale closed in December 2011 and we recognized a gain on sale of $38 million in the fourth quarter of 2011.

UK Undeveloped Lease

During the fourth quarter of 2010, we sold non-core lands in the UK North Sea for proceeds of $17 million. We had no plans to develop these leases. We recognized a gain on disposition of $17 million in the fourth quarter of 2010.

North Dakota/Montana Crude Oil Marketing

During the fourth quarter of 2010, we sold our oil lease gathering, pipelines and storage assets in North Dakota and Montana for proceeds of $201 million. The sale closed in December 2010 and we recognized a gain on disposition of $121 million in the fourth quarter of 2010.

15. CASH FLOWS

(a) Charges and credits to income not involving cash


                                       Three Months           Twelve Months
                                  Ended December 31       Ended December 31
                                   2011        2010        2011        2010
----------------------------------------------------------------------------
Depreciation, Depletion,  
 Amortization and Impairment        799         492       1,913       1,628
Stock-Based Compensation            (18)          9         (85)        (52)
Loss on Debt Redemption and                
 Repurchase                           -           -          91           -
Net (Gain) Loss on        
 Dispositions                       (26)       (138)        (38)         41
Non-Cash Items Included in
 Discontinued Operations              2          28        (290)       (549)
Provision for Deferred    
 Income Taxes                      (286)       (145)       (256)       (449)
Foreign Exchange                    (19)          4         (33)         26
Other                                 8          16          33          82
                            ------------------------------------------------
Total                               460         266       1,335         727
                            ------------------------------------------------
                            ------------------------------------------------

(b) Changes in non-cash working capital


                                       Three Months           Twelve Months
                                  Ended December 31       Ended December 31
                                   2011        2010        2011        2010
----------------------------------------------------------------------------
Accounts Receivable                (308)         90        (381)         96
Inventories and Supplies             27         (93)        208        (105)
Other Current Assets                 39           1          26          47 
Accounts Payable and Accrued               
 Liabilities                        347         (99)        723         241
                            ------------------------------------------------
Total                               105        (101)        576         279
                            ------------------------------------------------
                            ------------------------------------------------

Relating to:              
  Operating Activities              (32)        (72)        255         338
  Investing Activities              137         (29)        321         (59)
                            ------------------------------------------------
Total                               105        (101)        576         279
                            ------------------------------------------------
                            ------------------------------------------------

(c) Other cash flow information


                                            Three Months       Twelve Months
                                       Ended December 31   Ended December 31
                                          2011      2010      2011      2010
----------------------------------------------------------------------------
Interest Paid                               87        87       305       380
Income Taxes Paid                          342       325     1,448       951
                                    ----------------------------------------

16. OPERATING SEGMENTS AND RELATED INFORMATION

Effective in the first quarter of 2011, we amended our segment reporting to reflect changes in our business. In 2010, we disposed of non-core operations including heavy oil operations in Canada, chemicals and certain energy marketing businesses, and increased production at our Long Lake oil sands project. We report our segments to align with our key growth areas, specifically, Conventional Oil and Gas, Oil Sands and Shale Gas. Prior year results have been revised to reflect the presentation changes made in the current year.

Nexen has the following operating segments:

Conventional Oil and Gas: We explore for, develop and produce crude oil and natural gas from conventional sources around the world. Our operations are focused on the UK, North America (Canada and US) and other countries (offshore West Africa, Colombia and Yemen).

Oil Sands: We develop and produce synthetic crude oil from the Athabasca oil sands in northern Alberta. We produce bitumen using in situ and mining technologies and upgrade it into synthetic crude oil before ultimate sale. Our in situ activities are comprised of our operations at Long Lake and future development phases. Our mining activities are conducted through our 7.23% ownership of the Syncrude Joint Venture.

Shale Gas: We explore for and produce unconventional gas from shale formations in northeastern British Columbia. Production and results of operations are included within Conventional Oil and Gas until they become significant.

Corporate and Other includes energy marketing, unallocated items and the results of Canexus prior to its sale in February 2011. The results of Canexus have been presented as discontinued operations.

The accounting policies of our operating segments are the same as those described in Note 2 of our Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011. Net income (loss) of our operating segments excludes interest income, interest expense, unallocated corporate expenses and foreign exchange gains and losses. Identifiable assets are those used in the operations of the segments.


Segmented net income for the three months ended December 31, 2011 

                                                            Corporate   
                                                                  and   
                           Conventional         Oil Sands       Other Total
----------------------------------------------------------------------------
                                        Other          
                     United   North Countries    In    
                    Kingdom America      (1,2) Situ Syncrude
                    ----------------------------------------

Net Sales               950     120       182   239      158       16 1,665
Marketing and Other       
 Income                   4       3         9     -        -       13    29
                    --------------------------------------------------------
                        954     123       191   239      158       29 1,694

Less: Expenses            
  Operating              88      46        55   108       64       10   371
  Depreciation,           
   Depletion,             
   Amortization and                                 
   Impairment           192   277(3)       10 289(4)      14       17   799
  Transportation and      
   Other                  2      10         5   102        5       12   136
  General and             
   Administrative         9      19         6     7        -       55    96
  Exploration            52      31       7(5)    -        -        -    90
  Finance                 1       3         1     1        2       50    58 
  Net gain from           
   Dispositions         (38)      -         -     -        -        -   (38)
                    --------------------------------------------------------
  Income (Loss) from      
   Continuing             
   Operations before      
   Income Taxes         648    (263)      107  (268)      73     (115)  182
Less: Provision for       
 (Recovery of)            
 Income Taxes           384     (79)       38   (67)      17     (154)  139
                    --------------------------------------------------------
Net Income (Loss)       264    (184)       69  (201)      56       39    43
                    --------------------------------------------------------
                    --------------------------------------------------------

Capital Expenditures    214     209     239(6)   88       44       23   817
                    --------------------------------------------------------
                    --------------------------------------------------------

(1) Includes results of operations in Yemen and Colombia.

(2) Includes Masila net sales of $135 million and net income of $36 million.

(3) Includes non-cash impairment charges of $181 million in Canada and the US.

(4) Includes non-cash expenses of $253 million related to previously capitalized engineering and design costs.

(5) Includes exploration activities primarily in Nigeria, Norway, Colombia and Poland.

(6) Includes capital expenditures in Nigeria of $193 million.


Segmented net income for the three months ended December 31, 2010 

                                                            Corporate   
                                                                  and   
                           Conventional         Oil Sands       Other Total
----------------------------------------------------------------------------
                                        Other          
                     United   North Countries    In    
                    Kingdom America      (1,2) Situ Syncrude
                    ----------------------------------------

Net Sales               872     146       190   141      164       10 1,523
Marketing and Other       
 Income                   3       2         4     -        1        9    19
                    --------------------------------------------------------
                        875     148       194   141      165       19 1,542

Less: Expenses            
  Operating              99      42        44   100       65        8   358
  Depreciation,           
   Depletion,             
   Amortization and       
   Impairment           233     177        26    26       14       16   492
  Transportation and      
   Other                 (3)      7        18    47        5       28   102
  General and             
   Administrative         6      38        15     4        -      101   164
  Exploration            25      90      14(3)    -        -        -   129
  Finance                 5       5         -     1        1       77    89
  Gain from 
   Dispositions      (17)(4)      -         -     -        -  (121)(5) (138)
                    --------------------------------------------------------
Income (Loss) from        
 Continuing               
 Operations before        
 Income Taxes           527    (211)       77   (37)      80      (90)  346
Less: Provision for       
 (Recovery of)            
 Income Taxes           263     (64)       19   (10)      20      (41)  187
                    --------------------------------------------------------
Income (Loss) from        
 Continuing               
 Operations             264    (147)       58   (27)      60      (49)  159
Add: Net Income from      
 Discontinued             
 Operations (Note         
 14)                      -       -         -     -        -        1     1
                    --------------------------------------------------------
Net Income (Loss)       264    (147)       58   (27)      60      (48)  160
                    --------------------------------------------------------
                    --------------------------------------------------------

Capital Expenditures    228     123     189(6)   72       36       37   685
                    --------------------------------------------------------
                    --------------------------------------------------------

(1)Includes results of operations in Yemen and Colombia.

(2)Includes Masila net sales of $143 million and net income of $43 million.

(3)Includes exploration activities primarily in Yemen, Nigeria, Norway and Colombia.

(4)Gain on disposition of UK undeveloped lease.

(5)Gain on disposition of North Dakota/Montana Crude Oil Marketing assets.

(6)Includes capital expenditures in Nigeria of $158 million.


Segmented net income for the year ended December 31, 2011   

                                                           Corporate    
                                                                 and    
                          Conventional         Oil Sands       Other  Total
----------------------------------------------------------------------------
                                       Other           
                    United   North Countries    In     
                   Kingdom America      (1,2) Situ Syncrude 
                   ---------------------------------------- 

Net Sales            3,432     499       781   688      713       56  6,169
Marketing and Other       
 Income                 21      39        21     -        3      211    295
                   ---------------------------------------------------------
                     3,453     538       802   688      716      267  6,464

Less: Expenses            
  Operating            353     156       164   439      287       32  1,431
  Depreciation,           
   Depletion,             
   Amortization and                                 
   Impairment          631   708(3)       76 384(4)      60       54  1,913
  Transportation          
   and Other             7      35        28   220       23      112    425
  General and             
   Administrative       (8)     74        31    19        1      183    300
  Exploration           84     148     134(5)    2        -        -    368
  Finance               17      16         2     3        6      207    251
  Net Loss on Debt        
   Redemption            -       -         -     -        -       91     91
  Net Gain from           
   Dispositions        (38)      -         -     -        -        -    (38)
                   ---------------------------------------------------------
Income (Loss) from        
 Continuing               
 Operations before        
 Income Taxes        2,407    (599)      367  (379)     339     (412) 1,723
Less: Provision for       
 (Recovery of)            
 Income Taxes        1,697    (164)       68   (95)      84     (262) 1,328
                   ---------------------------------------------------------
Income (Loss) from        
 Continuing               
 Operations            710    (435)      299  (284)     255     (150)   395
Add: Net Income           
 from Discontinued        
 Operations (Note         
 14)                     -       -         -     -        -      302    302
                   ---------------------------------------------------------
Net Income (Loss)      710    (435)      299  (284)     255      152    697
                   ---------------------------------------------------------
                   ---------------------------------------------------------

Capital                   
 Expenditures          583     694     718(6)  397      124       59  2,575
                   ---------------------------------------------------------
                   ---------------------------------------------------------

(1) Includes results of operations in Yemen and Colombia.

(2) Includes Masila net sales of $588 million and net income of $161 million.

(3) Includes non-cash impairment charges of $322 million in Canada and the US.

(4) Includes non-cash expenses of $253 million related to previously capitalized engineering and design costs.

(5) Includes exploration activities primarily in Nigeria, Norway, Colombia and Poland.

(6) Includes capital expenditures in Nigeria of $542 million.


Segmented net income for the year ended December 31, 2010   

                                                            Corporate   
                                                                  and   
                          Conventional          Oil Sands       Other  Total
----------------------------------------------------------------------------
                                        Other          
                     United   North Countries    In    
                    Kingdom America      (1,2) Situ Syncrude
                   -----------------------------------------

Net Sales             3,115     569       750   443      580       39  5,496
Marketing and Other       
 Income                  17       3        16     -        5      282    323
                   ---------------------------------------------------------
                      3,132     572       766   443      585      321  5,819

Less: Expenses            
  Operating             337     166       163   373      265       32  1,336
  Depreciation,           
   Depletion,       
   Amortization     
   and Impairment       783   519(3)      120    94       53       59  1,628
  Transportation          
   and Other              2      22        27   181       21      313    566
  General and             
   Administrative        22      90        28    14        1      273    428
  Exploration            67     156     104(4)    1        -        -    328
  Finance                17      17         1     3        4      320    362
  Net (Gain) Loss         
   from                                            
   Dispositions      (17)(5)      -         -   (80)(6)    -    138(7)    41
                   ---------------------------------------------------------
Income (Loss) from        
 Continuing
 Operations before        
 Income Taxes         1,921    (398)      323  (143)     241     (814) 1,130
Less: Provision for       
 (Recovery of)            
 Income Taxes           960    (119)       64   (36)      60     (253)   676
                   ---------------------------------------------------------
Income (Loss) from        
 Continuing
 Operations             961    (279)      259  (107)     181     (561)   454
Add: Net Income           
 from Discontinued
 Operations (Note
 14)                      -     635         -     -        -       38    673
                   ---------------------------------------------------------
Net Income (Loss)       961     356       259  (107)     181     (523) 1,127
                   ---------------------------------------------------------
                   ---------------------------------------------------------

Capital                   
 Expenditures           699     815     652(8)  228      119      211  2,724
                   ---------------------------------------------------------
                   ---------------------------------------------------------

(1)Includes results of operations in Yemen and Colombia.

(2)Includes Masila net sales of $570 million and net income of $156 million.

(3)Includes non-cash impairment charges of $139 million for Canada and the US.

(4)Includes exploration activities primarily in Yemen, Nigeria, Norway and Colombia.

(5)Gain on disposition of UK undeveloped lease.

(6)Gain on disposition of non-core lands in the Athabasca region.

(7)Net loss on disposition of Natural Gas Energy Marketing Business and North Dakota/Montana Crude Oil Marketing assets.

(8)Includes capital expenditures in Nigeria of $495 million.


Segmented assets as at December 31, 2011   

                                                          Corporate   
                     Conventional             Oil Sands   and Other   Total
----------------------------------------------------------------------------
               United    North     Other  
              Kingdom  America Countries  In Situ Syncrude  
              --------------------------------------------- 


Total Assets    4,817    3,403     2,138    5,881    1,423  2,406(1) 20,068
              --------------------------------------------------------------
              --------------------------------------------------------------

Property,                 
 Plant and                
 Equipment                
 Cost           7,103    7,256     2,566    5,915    1,733      649  25,222
 Less:
  Accumulated             
  DD&A          3,707    4,299       648      205      411      381   9,651
              --------------------------------------------------------------
Net Book  
 Value          3,396  2,957(2)  1,918(3) 5,710(4)   1,322      268  15,571
              --------------------------------------------------------------
              --------------------------------------------------------------

Goodwill          284        -         -        -        -        7     291
              --------------------------------------------------------------
              --------------------------------------------------------------

(1)Includes cash of $453 million, and Energy Marketing accounts receivable and inventory of $1,449 million.

(2)Includes capitalized costs of $1,293 million associated with our Canadian shale gas operations.

(3)Includes $1,821 million related to our Usan development, offshore Nigeria.

(4)Includes net book value of $5,050 million for Long Lake Phase 1 and $660 million for future phases of our in situ oil sands projects.


Segmented assets as at December 31, 2010   

                                                          Corporate   
                     Conventional             Oil Sands   and Other   Total
----------------------------------------------------------------------------
               United    North     Other  
              Kingdom  America Countries  In Situ Syncrude  
              --------------------------------------------- 


Total Assets    4,249    3,195     1,646    5,782    1,259  3,516(1) 19,647
              --------------------------------------------------------------
              --------------------------------------------------------------

Property,                 
 Plant and                
 Equipment                
 Cost           6,389    6,422     3,700    5,756    1,519       596 24,382
 Less:
  Accumulated             
  DD&A          3,055    3,597     2,370       91      359       331  9,803
              --------------------------------------------------------------
Net Book    
 Value          3,334  2,825(2)  1,330(3) 5,665(4)    1,160      265 14,579
              --------------------------------------------------------------
              --------------------------------------------------------------

Goodwill          277        -         -        -        -         9    286
              --------------------------------------------------------------
              --------------------------------------------------------------

(1)Includes cash of $817 million, Energy Marketing accounts receivable and inventory of $1,498 million and Chemicals assets of $729 million.

(2)Includes capitalized costs of $938 million associated with our Canadian shale gas operations.

(3)Includes $1,210 million related to our Usan development, offshore Nigeria.

(4)Includes net book value of $4,865 million for Long Lake Phase 1 and $800 million for future phases of our in situ oil sands projects.


Segmented assets as at January 1, 2010     

                                                          Corporate   
                     Conventional             Oil Sands   and Other   Total
----------------------------------------------------------------------------
               United    North     Other  
              Kingdom  America Countries  In Situ Syncrude  
              --------------------------------------------- 

Total Assets    4,840    3,146     1,320    5,616    1,165  4,868(1) 20,955
              --------------------------------------------------------------
              --------------------------------------------------------------

Property,                 
 Plant and                
 Equipment                
 Cost           5,884    7,464     3,344    5,523    1,390     1,702 25,307
 Less:
  Accumulated             
  DD&A          2,458    4,600     2,387        7      319       867 10,638
              --------------------------------------------------------------
Net Book  
 Value          3,426  2,864(2)    957(3) 5,516(4)   1,071       835 14,669
              --------------------------------------------------------------
              --------------------------------------------------------------

Goodwill          292        -         -        -        -        38    330
              --------------------------------------------------------------
              --------------------------------------------------------------

(1)Includes cash of $1,016 million, Energy Marketing accounts receivable and inventory of $2,392 million and Chemicals assets of $654 million.

(2)Includes capitalized costs of $477 million associated with our Canadian shale gas operations.

(3)Includes $760 million related to our Usan development, offshore Nigeria.

(4)Includes net book value of $4,776 million for Long Lake Phase 1 and $740 million for future phases of our in situ oil sands projects.

17. TRANSITION TO IFRS

For all periods up to and including the year ended December 31, 2010, we prepared our Consolidated Financial Statements in accordance with Canadian generally accepted accounting principles (Canadian GAAP). As a publicly listed company in Canada, we are required to prepare consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) for all periods after January 1, 2011 including comparative historical information. As we are also publicly listed in the United States, we were required to include a reconciliation of our financial results between Canadian GAAP and US GAAP. The reconciliation to US GAAP is no longer required.

In accordance with transitional provisions, we prepared our opening balance sheet as at January 1, 2010 (the transition date) and 2010 comparative financial information using the accounting policies set out in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011. The consolidated financial statements for the year ended December 31, 2011 will be the first annual financial statements that comply with IFRS by applying existing IFRS with an effective date of December 31, 2011 or earlier. This transition note explains the material adjustments we made to convert our financial statements to IFRS.

Elected Exemptions from Full Retrospective Application

In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1 First-time Adoption of International Financial Reporting Standards (IFRS 1), we applied the following optional exemptions from full retrospective application of IFRS.

(i) Business Combinations

We applied the business combinations exemption to not apply IFRS 3 Business Combinations retrospectively to past business combinations. Accordingly, we have not restated business combinations that took place prior to the transition date.

(ii) Fair Value or Revaluation as Deemed Cost

We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet.

(iii) Cumulative Translation Differences

We elected to set the cumulative translation account to nil at January 1, 2010. This exemption has been applied to all subsidiaries.

(iv) Share-Based Payment Transactions

We elected to use the IFRS 1 exemption whereby the liabilities for share-based payments that had vested or settled prior to January 1, 2010 were not required to be retrospectively restated.

(v) Employee Benefits

We elected to apply the exemption for employee benefits to recognize the accumulated unrecognized net actuarial loss in retained earnings at January 1, 2010. This exemption has been applied to all defined benefit pension plans.

(vi) Asset Retirement Obligations

We applied the exemption from full retrospective application of our asset retirement obligations as permitted for first-time adoption of IFRS. As such, we re-measured ARO as at January 1, 2010. We estimated the amount to be included in the related asset by discounting the liability to the date when the obligation first arose using our best estimates of the historical risk-free discount rates applicable during the intervening period.

(vii) Borrowing Costs

We applied an IFRS transitional exemption to prospectively capitalize borrowing costs only from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to retained earnings.

Mandatory Exceptions to Retrospective Application

In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1, we were required to apply the following mandatory exceptions from full retrospective application of IFRS.

(i) Hedge Accounting

Only hedging relationships that satisfied the hedge accounting criteria as of the transition date are reflected as hedges in our results under IFRS. Any derivatives not meeting the IAS 39 Financial Instruments: Recognition and Measurement criteria for hedge accounting were recorded as a non-hedging derivative financial instrument.

(ii) Estimates

Hindsight was not used to create or revise estimates and accordingly, our estimates previously made under Canadian GAAP are consistent with their application under IFRS.

Reconciliations of Canadian GAAP to IFRS

IFRS 1 requires the presentation of a reconciliation of shareholders' equity, net income, comprehensive income, and cash flows for prior periods. The transition from Canadian GAAP to IFRS had no material effect upon previously reported cash flows. The following represents the reconciliations from Canadian GAAP to IFRS for the respective periods for shareholders' equity, net income, and comprehensive income:

Reconciliation of Shareholders' Equity


                                                    January 1   December 31
(Cdn$ millions)                             Note         2010          2010
----------------------------------------------------------------------------
Shareholders' Equity under Canadian GAAP                7,646         8,791
Differences increasing (decreasing)        
 reported shareholders' equity:            
 Borrowing Costs                              (i)        (841)         (778)
 Asset Retirement Obligations                (ii)        (228)         (241)
 Employee Benefits                          (iii)        (104)         (150)
 Stock-Based Compensation                    (iv)         (96)          (92)
 Property, Plant & Equipment                  (v)        (124)          (90)
 Foreign Exchange                            (vi)         (11)            -
 Long-term Debt                             (vii)          (9)          (28)
 Income Taxes                              (viii)         554           429
 Other                                                      -           (27)
                                                  --------------------------
Shareholders' Equity under IFRS                         6,787         7,814
                                                  --------------------------
                                                  --------------------------

(i) Borrowing Costs

We applied the IFRS 1 exemption to prospectively capitalize borrowing costs only from the transition date as described above.

(ii) Asset Retirement Obligations (ARO)

We applied the IFRS 1 exemption for asset retirement obligations and re-measured our ARO as at January 1, 2010 as described above.

(iii) Employee Benefits

We have chosen to include previously unrecognized actuarial gains and losses of our defined benefit pension plans on the balance sheet under IFRS. Under Canadian GAAP, we amortized actuarial gains and losses to income over the estimated average remaining service life, with disclosure of the unrecognized amount in the notes to the Consolidated Financial Statements. On January 1, 2010, we applied the IFRS 1 exemption to recognize the accumulated unrecognized net actuarial loss in retained earnings on transition to IFRS.

(iv) Stock-Based Compensation (SBC)

Under Canadian GAAP, we recorded obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. IFRS requires that we record these SBC obligations at fair value and subsequently re-measure the obligation each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. On transition, we recorded the liability at fair value for unsettled awards.

(v) Property, Plant and Equipment

Impairment

Under Canadian GAAP, if indications of impairment exist and the asset's estimated undiscounted future cash flows were lower than its carrying amount, the carrying value was written down to fair value. Under IFRS, if indications of impairments exist, the asset's carrying value is immediately compared to its estimated recoverable amount, which could trigger additional impairment under IFRS. We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet. As a result, oil and gas properties were written down to fair value of $460 million and resulted in an impairment expense of $91 million on transition.

Componentization

Under Canadian GAAP, we depleted oil and gas capitalized costs using the unit-of-production method on a field-by-field basis and depreciated non-resource capitalized costs based on their estimated useful life. On adoption of IFRS, we reviewed our PP&E to identify each material component that has a significantly different useful life and as a result, adjustments to the accumulated depletion of certain assets resulted in an expense of $51 million on transition to IFRS.

Major Maintenance

Under Canadian GAAP, operating expenses included major maintenance costs that were expensed as incurred. Under IFRS, $18 million was capitalized and depreciated separately until the next planned major maintenance project.

(vi) Foreign Exchange

Foreign Currency Translation

We applied the first-time IFRS adoption exemption to reset our cumulative translation differences to nil on the transition date. Accumulated foreign exchange gains and losses of our self-sustaining foreign operations, net of foreign exchange translation gains and losses of long-term debt designated as hedges are included in retained earnings on the transition date. This one-time adjustment had no impact on shareholders' equity on transition.

Change in Functional Currency

As a result of additional guidance under IFRS, our assessment of the functional currency of a subsidiary changed from Canadian dollars to US dollars to better reflect the economic environment in which it operates.

(vii) Long-Term Debt

Canexus Convertible Debentures

Canexus unitholders have the ability to redeem fund units for cash pursuant to the terms of the trust indenture. Under IFRS, these convertible debentures are considered to be financial liabilities containing an embedded derivative. Under Canadian GAAP, the convertible debentures were considered to be compound instruments with an equity component. Accordingly, the equity component and unamortized deferred transaction costs recorded under Canadian GAAP were derecognized on January 1, 2010 and charged to retained earnings. We elected to recognize the convertible debentures at fair value and to recognize changes in fair value in net income during the period of change.

(viii) Income Taxes

Recognition of Deferred Tax Credit

In 2008, we completed an internal reorganization and financing of our assets in the North Sea, which provided us with a one-time tax deduction in the UK. Canadian GAAP precluded us from recognizing the full estimated benefit of the tax deductions until the assets were recognized in net income either by a sale or depletion through use. As a result, we deferred the initial recognition of the benefit and were amortizing it to future income tax expense over the life of the underlying assets under Canadian GAAP. On adoption of IFRS, no such prohibition exists and we recognized the remaining deferred tax credit in retained earnings on transition to IFRS.

Exceptions

Under Canadian GAAP, deferred taxes were generally provided on all temporary differences. Conversely, IFRS does not recognize deferred taxes on temporary differences arising from the initial recognition of assets or liabilities in transactions that are not business combinations and that affect neither accounting nor taxable profit or loss.

Reconciliation of Net Income


                                                        Three        Twelve
                                                       Months        Months
                                                        Ended         Ended
                                                  December 31   December 31
(Cdn$ millions)                             Note         2010          2010
----------------------------------------------------------------------------
Net Income under Canadian GAAP                            220         1,197
Differences increasing (decreasing)        
 reported net income:     
 Borrowing Costs                              (i)          18            63
 Asset Retirement Obligations                (ii)          (4)          (13)
 Stock-Based Compensation                   (iii)         (20)            3
 Property, Plant & Equipment                 (iv)         (43)           34
 Long-term Debt                               (v)          (1)          (19)
 Income Taxes                                (vi)           2          (136)
 Other                                                    (12)           (2)
                                                  --------------------------
 Total Differences in Net Income                          (60)          (70)
                                                  --------------------------
Net Income under IFRS                                     160         1,127
                                                  --------------------------
                                                  --------------------------

(i) Borrowing Costs

We applied an IFRS transitional exemption to prospectively capitalize borrowing costs from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to shareholders' equity. The reduced capitalized amounts decreased DD&A expense during 2010.

(ii) Asset Retirement Obligations (ARO)

Under Canadian GAAP, foreign exchange translation gains and losses arising from the revaluation of GBP-denominated asset retirement obligations were included in net income in the period in which they occurred. Under IFRS, these translation gains and losses are treated as a change in estimate and therefore increase or decrease PP&E with a corresponding impact on net income.

(iii) Stock-Based Compensation (SBC)

As described above, we record obligations for liability-based stock compensation plans at fair value each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. The changes in the SBC fair value in 2010 were recognized in net income.

(iv) Property, Plant and Equipment

Impairment

As described above, certain properties were impaired and written down to fair value on transition. These adjustments reduced IFRS DD&A expense during 2010 by immaterial amounts. In the last half of 2010, additional properties were impaired and written down to fair value. The impairment expense of $46 million reduced net income in the third and fourth quarters.

Major Maintenance Costs

As described above, Canadian GAAP operating expenses included major maintenance costs that were expensed as incurred. Under IFRS, these costs are capitalized and depreciated separately until the next planned major maintenance project. During 2010, we capitalized $18 million of maintenance costs under IFRS that were expensed as operating costs under Canadian GAAP.

Gain on Sale of Heavy Oil Properties

We completed the sale of our Canadian heavy oil properties in the third quarter of 2010. As the adoption of IFRS resulted in different carrying values of property, plant & equipment and asset retirement obligations prior to the sale, our gain on sale under IFRS was $47 million higher.

(v) Long-Term Debt

Canexus Convertible Debentures

As described above, we elected to carry the Canexus convertible debentures at fair value under IFRS. The change in fair value during 2010 was included in net income.

(vi) Income Taxes

Recognition of Deferred Tax Credit

As described above, we amortized a deferred tax credit to income over the life of the underlying asset under Canadian GAAP. Under IFRS, the deferred tax credit was recognized in retained earnings on transition. Therefore, IFRS net income was lower by $29 million and $117 million for the three and twelve months ended December 31, 2010, respectively.

Other

All other adjustments to IFRS net income were tax effected which decreased deferred tax expense $31 and increased $19 million for the three and twelve months ended December 31, 2010, respectively.

Reconciliation of Comprehensive Income


                                                        Three        Twelve
                                                       Months        Months
                                                        Ended         Ended
                                                  December 31   December 31
(Cdn$ millions)                             Note         2010          2010
----------------------------------------------------------------------------
Comprehensive Income under Canadian GAAP                  197         1,168
Differences increasing (decreasing)        
 reported comprehensive income, net of     
 income taxes:            
 Differences in net income                                (60)          (70)
 Foreign Currency Translation                 (i)           -            (8)
 Employee Benefits                           (ii)         (35)          (35)
                                                  --------------------------
Comprehensive Income under IFRS                           102         1,055
                                                  --------------------------
                                                  --------------------------

(i) Foreign Currency Translation

Transitional adjustments reflect the foreign currency exchange impact of the IFRS adjustments during the respective periods.

(ii) Employee Benefits

As described in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011, actuarial gains and losses are recognized directly in other comprehensive income in the period in which they occur. For the twelve months ended December 31, 2010, actuarial losses on our defined benefit plans reduced other comprehensive income by $35 million.

Contact Information

  • Janet Craig
    Vice President, Investor Relations
    (403) 699-4230

    Pierre Alvarez
    Vice President, Corporate Relations
    (403) 699-5202

    Nexen Inc.
    801 - 7th Ave SW
    Calgary, Alberta, Canada T2P 3P7
    www.nexeninc.com