Nexen Inc.
TSX : NXY
NYSE : NXY

Nexen Inc.

July 14, 2011 06:00 ET

Nexen Announces Second Quarter Results & Return to Drilling in the Gulf of Mexico

CALGARY, ALBERTA--(Marketwire - July 14, 2011) - Nexen Inc. today reported second quarter 2011 operating and financial results, led by strong oil prices, high netbacks, and a portfolio weighted towards unhedged, Brent-priced oil. We generated cash flow from operations of $598 million ($1.13/share) and net income of $252 million ($0.48/share). Production of 204,000 barrels of oil equivalent per day (boe/d) reflects maintenance activities at our Buzzard platform in the UK North Sea which are expected to be completed in August. In light of our production in the first half of the year, we now expect company-wide production before royalties for the year to average between 210,000 and 230,000 boe/d.

During the quarter, we achieved several milestones. Our Usan project remains on track, with the floating production and storage offloading vessel (FPSO) enroute to site. The project is expected to achieve first oil in the first half of 2012. In our oil sands business, Long Lake production increased 9% over the first quarter and generated positive cash flow for the quarter. In June, we processed 45,000 barrels per day (bbls/d) of proprietary and third- party bitumen volumes (28,900 bbls/d and 16,100 bbls/day respectively) achieving approximately 65% of upgrader capacity. We continued to advance various initiatives for resource development to fill the upgrader. We also continued our industry-leading execution in our shale gas business with the drilling of a nine-well pad. We began fracing and completion activities during the quarter, and first production from this pad is expected in the fourth quarter. We also commenced drilling an 18-well pad.

Our exploration efforts advanced in the Gulf of Mexico. We received a drilling permit for our Kakuna exploration well and commenced drilling late in June. Our partner, Shell, received a drilling permit for an appraisal well to follow up our Appomattox discovery.

"While we are disappointed with the downtime at Buzzard, we are making steady progress in all areas of our business. We continue to focus on developing our attractive opportunity portfolio and are advancing our near-term and longer-term value contributors to our business," said Marvin Romanow, President and Chief Executive Officer.

"The Gulf of Mexico is a key component of our significant resource potential, and we are excited to be back to drilling," continued Mr. Romanow. "We've spent the past several years building an attractive prospect inventory in the Gulf, and the value of the opportunity in this area was highlighted by the Appomattox discovery last year. Along with the North Sea and West Africa, the Gulf is expected to be integral to growing our conventional business for many years to come."

Highlights

Financial

- Cash flow from operations of $598 million ($1.13/share) and net income of $252 million ($0.48/share).

- Oil and gas operations generated a cash netback of $59.87/boe ($42.76/boe after tax).

- Achieved our first quarterly positive cash flow at Long Lake.

- Net debt decreased approximately 50% from a year ago. It is expected to increase in the second half of the year as our capital program is weighted more towards the latter half of the year as we increase our drilling activities.

Production

- Production of 204,000 boe/d (180,000 boe/d after royalties) was impacted by Buzzard's unscheduled maintenance and interruptions to a third-party operated natural gas export pipeline which constrain oil production to minimize gas flaring. We also had unscheduled downtime at Syncrude.

- At Long Lake, production increased 9% over the prior quarter to 27,900 bbls/d gross (18,100 bbls/d net to Nexen).

Project Advancements

- Received drilling permits for the Appomattox appraisal well and Kakuna exploration well in the deepwater Gulf of Mexico. Commenced drilling the Kakuna well and brought in Statoil USA E&P Inc. as a partner on a promoted basis.

- Continued industry-leading pace of drilling at our shale gas operations in the Horn River. We have strong interest in our joint venture process.

- Advancing various projects to develop high quality resource to fill the Long Lake upgrader, including acceleration of development of a portion of the Kinosis lease.

- Successfully ran the Long Lake upgrader at approximately 65% of capacity, with an on-stream factor of 96% during June.

- Continued drilling on pads 12 and 13 at Long Lake, and converted several pad 11 wells from circulation to production.

- Usan FPSO set sail for location offshore Nigeria, West Africa.


Financial Summary

                                      Three Months Ended   Six Months Ended
----------------------------------------------------------------------------
                                June 30 March 31 June 30   June 30  June 30
(Cdn$ millions)                    2011     2011    2010      2011     2010
----------------------------------------------------------------------------
Average Daily Production
(mboe/d)
 Before Royalties                   204      232     248       218      250
 After Royalties                    180      207     218       194      220
Cash flow from operations(1)        598      669     549     1,267    1,098
 Per common share ($/share)        1.13     1.27    1.05      2.40     2.09
Net income                          252      202     245       454      386
 Per common share ($/share)        0.48     0.38    0.47      0.86     0.74
Capital investment(2)               530      499     840     1,029    1,410
Net debt(3)                       2,838    3,350   5,492     2,838    5,492
                              ----------------------------------------------

(1) For reconciliation of this non-GAAP measure, see Cash Flow from
    Operations on pg. 11.
(2) Includes geological and geophysical expenditures.
(3) Net debt is defined as long-term debt and short-term borrowings less
    cash and cash equivalents. 

Our portfolio weighting towards unhedged, Brent-priced oil contributed to strong cash flow in the quarter. Brent averaged US$117.36 per barrel, a premium of US$14.80 per barrel over WTI. Our approach to hedging allows us to benefit when prices rise, while giving us some protection if prices decline below certain levels. Higher realized crude oil prices, which averaged $110.28 per barrel, partially offset lower production from temporary downtime at Buzzard and Syncrude and natural declines in Yemen. Also contributing to cash flow was our Long Lake operation, which generated its first positive quarterly cash flow of $6 million as compared to a loss of $19 million in the first quarter. Higher production, prices and upgrader throughput contributed to this positive cash flow.

Net income increased from the prior quarter. The first quarter included the impact of the UK tax rate change which resulted in an accrual for higher income taxes of $336 million. This was partially offset by a $299 million after-tax gain on the sale of Canexus.

Net debt has declined about 50% over the past year following our successful asset disposition program and a stronger Canadian dollar. This amount is expected to rise in the second half of the year due to the timing of our capital spending and working capital changes. Capital investment is expected to increase in the latter half of the year with the increased drilling in the Gulf of Mexico, the North Sea and for Canadian shale gas and oil sands.


Production
                        Average Daily Quarterly     Average Daily Quarterly
                    Production before Royalties  Production after Royalties
Crude Oil, NGLs
 and Natural Gas
 (mboe/d)             Q2 2011  Q1 2011  Q2 2010   Q2 2011  Q1 2011  Q2 2010
----------------------------------------------------------------------------
North Sea                  84      103      105        84      103      105
Yemen                      35       38       41        19       20       22
United States              25       26       26        22       23       23
Canada - Oil & Gas(1)      20       23       35        19       21       29
Canada - Syncrude          20       23       23        18       22       22
Canada - Bitumen           18       17       16        17       16       15
Other Countries             2        2        2         1        2        2
                   ---------------------------------------------------------
Total                     204      232      248       180      207      218
                   ---------------------------------------------------------

(1) Q2, 2010 includes production before royalties of 15 mboe/d and
    production after royalties of 12 mboe/d from discontinued operations
    as disclosed in Note 14 to our Unaudited Condensed Consolidated
    Financial Statements 

The Buzzard field continues to be our largest producing asset and typically contributes 85,000 to 95,000 boe/d net to Nexen. Production in the quarter averaged 114,000 boe/d (49,000 boe/d net to Nexen). This reflects unscheduled maintenance to repair the cooling system and interruptions to a third-party operated natural gas export pipeline which constrain oil production to minimize gas flaring. While the repair work proceeded on schedule, production was lower than expected due to the gas export restrictions. Production is expected to be back to full rates in August.

We utilized Buzzard's downtime to bring forward maintenance work originally scheduled for September. Further maintenance work will be advanced to August when the third-party operated Forties pipeline system undergoes a one-week shutdown. As a result, the September shutdown will not be required.

Yemen production reflects natural field declines following the completion of development drilling activities as we near the end of the primary contract term in December of this year, and by the two-day shutdown during a labour strike. This was the longest disruption in our Yemen operations since production began in 1993. Following a successful restart, the facility quickly returned to normal production. We remain confident that we can continue to manage our operations during the current period of uncertainty in the country. Safety and security continue to be our primary focus.

Unscheduled maintenance on the LC Finer and the Vacuum Distillation Unit impacted Syncrude production. The repairs have been completed and production subsequently returned to full rates.

At Long Lake, bitumen production averaged 27,900 bbls/d gross (18,100 bbls/d net to Nexen), up 2,300 bbls/d from the first quarter. Production is increasing as a result of higher steam injection following the hot lime softener (HLS) scheduled maintenance, well optimizations and the continuing ramp-up of the new pad 11 wells. Production at the end of June was approximately 30,000 bbls/d and we expect production from Long Lake to continue to increase into the mid-30,000 bbls/d range by year-end.


                           Long Lake Quarterly Operating Results
-------------------------------------------------------------------------
                   Bitumen                 Steam                    Unit
         Production (Gross)     Injection (Gross)      Operating Costs(1)
        -----------------------------------------------------------------
                    bbls/d                bbls/d                   $/bbl
2011
 Q2                 27,900               152,000                      95
 Q1                 25,500               146,000                      89
2010
 Q4                 28,100               158,000                      86
 Q3                 25,700               146,000                      85
 Q2                 24,900               137,000                      90
 Q1                 18,700               114,000                     154
2009
 Q4                 13,600                77,000                     150
 Q3                  8,500                48,000                     180
 Q2                 14,300                75,000                     160
 Q1                 12,500                66,000                     220

(1) Unit operating costs are based on volumes sold and exclude activities
    related to third-party bitumen purchased, processed and sold.

Unit operating costs temporarily increased in the first half of this year due to planned and unplanned maintenance, along with initiatives to increase upgrader reliability and improve well performance. The first quarter included planned maintenance of the first HLS unit. The second quarter included planned maintenance on the second HLS unit and a cogeneration unit, as well as unplanned maintenance on the sulphur recovery units and gasifiers. The third HLS unit and second cogeneration unit are scheduled to undergo maintenance in August. Despite this increase in operating costs, the facility generated positive cash flow for the quarter due to higher production and prices, and increased upgrader throughput from Long Lake and third-party sourced bitumen.

Guidance Update

We generate a large portion of our production volumes from a relatively small number of high-netback fields. While our focus on developing high-netback legacy assets provides us with a competitive advantage in our operating areas and delivers attractive value, it results in our production being sensitive to operating rates in these areas.

Given the impact of operational events at Buzzard and Long Lake in the first half of the year, our annual production before royalties is now expected to be 210,000 to 230,000 boe/d. This is lower than we expected in May largely as a result of the gas export restrictions. The range reflects variability of production at Buzzard as we complete the cooling system repairs and the final stages of commissioning the fourth platform that will allow us to produce from our full suite of wells regardless of H2S levels. It also reflects variability in the Long Lake ramp-up, timing of Telford and Blackbird well tie-ins, and potential for hurricane disruptions in the Gulf of Mexico. The following provides production ranges by quarter and major areas:


                                                                    Average
                                                                      Daily
                                                                     Annual
                                                                 Production
                                                                     before
                          Average Daily Quarterly Production      Royalties
                                  before Royalties                     2011
Crude Oil, NGLs and   Q1 2011   Q2 2011     Q3 2011     Q4 2011      Annual
 Natural Gas (mboe/d) (actual)  (actual)  (estimate)  (estimate)  (estimate)
----------------------------------------------------------------------------
Buzzard                    71        49     67 - 74     82 - 95     67 - 72
Other UK                   32        35     23 - 27     24 - 32     28 - 32
Yemen                      38        35     32 - 34     24 - 33     32 - 35
United States              26        25     20 - 24     21 - 24     23 - 25
Canada - Oil & Gas         23        20     19 - 21     19 - 22     20 - 22
Canada - Syncrude          23        20     19 - 22     20 - 23     20 - 22
Canada - Bitumen           17        18     18 - 21     18 - 24     18 - 20
Other Countries             2         2           2           2           2
                     -------------------------------------------------------
Total                     232       204   200 - 225   210 - 255   210 - 230
                     -------------------------------------------------------
                     -------------------------------------------------------

The production guidance for the various areas reflect:

- In the UK:

-- Buzzard repairs of the cooling system and completion of the start-up of the fourth platform continues into the third quarter. The facility will also be taken down in early August for the planned one-week shutdown of the third-party operated Forties pipeline. Once the fourth platform is available, production is expected to be strong as we will be able to almost double the number of available wells as we bring our higher concentration sour producers onstream.

-- Planned maintenance activities at Scott and Ettrick in the third quarter.

-- Production is expected to increase late in the year with the start-up of production from the tie-ins of the Telford TAC well to the Scott facility, and the Blackbird field to the Ettrick facility.

- In Yemen, production will continue with natural field declines. Our current contract expires in mid-December unless we receive a contract extension.

- In the U.S., the range of production is based on the potential for hurricane-related disruptions through the third quarter and into the early part of the fourth quarter.

- At Long Lake, the ongoing ramp-up of pad 11 and well optimizations are expected to contribute to modest production growth over the remainder of the year.

We expect to add new production next year with Usan coming on-stream in the first half of the year and the start-up of our 18-well shale gas pad and Long Lake pad 12 in the fourth quarter of the year.

Project Advancements

Nexen has numerous opportunities available with several development and appraisal projects underway, and a large resource base to support growth. Near-term projects include new production from a Telford development well; the Blackbird field tie-in; ongoing shale gas drilling; and the Rochelle development. Longer-term projects include Golden Eagle, Appomattox, Knotty Head and Owowo, along with further oil sands and shale gas development.

During the second quarter, we made significant progress on our key milestones in moving these projects into production and cash flow.

Conventional

Offshore West Africa - Development of the Usan field remains on track for first oil in the first half of 2012. Fabrication of the FPSO vessel in Korea is now complete. The FPSO is under tow and expected to arrive on location offshore Nigeria this summer for hook-up to the wells and commissioning. At full capacity, the project is capable of producing 180,000 boe/d (36,000 boe/d net to Nexen). Nexen has a 20% interest in Usan and the project joint venture partners are Total E&P Nigeria Limited (the operator), ExxonMobil and Chevron.

Gulf of Mexico - Shell, the operator of the Appomattox discovery, received approval of the supplemental Exploration Plan for a multi-well exploration and appraisal drilling program on the Appomattox discovery. They received a drilling permit for the first appraisal well and expect to spud it in the third quarter. This is the first of three wells planned to appraise Appomattox and adjacent structures. Nexen estimates the recoverable contingent resource for this discovery exceeds 250 million boe (gross) with further upside potential. Nexen has a 20% working interest in Appomattox and a 25% working interest in the nearby Vicksburg discovery.

Nexen received approval to drill the Kakuna exploration well which spud in late June in the vicinity of the producing Tahiti field and various other discoveries. Following the Kakuna well, we expect to drill the Angel Fire prospect once the drilling permit is approved. Farm-out negotiations continue on exploration prospects in the Gulf of Mexico.

UK North Sea - The approval process for the Golden Eagle development continues to progress well. Development of the field is expected to commence once all partners complete their approval processes and regulatory approvals are in place, which we expect to occur later this summer.

Regulatory approval was received for the Blackbird tieback to the Ettrick facility. We also continue to progress the tie-in of the Telford TAC well to the Scott platform. Blackbird and Telford are both on track to deliver increased production late this year. These projects, when combined with the Rochelle tie-back to the Scott platform, are expected to contribute approximately 10,000 to 20,000 boe/d net to Nexen by the end of 2012. Over the next 12 months, the company plans to drill an appraisal of the Polecat discovery and a number of exploration prospects, including the North Uist well west of the Shetland Islands.

Oil Sands

Long Lake - Our primary focus is on increasing our bitumen production to fill the upgrader. This provides us with an attractive return on capital as the predominantly fixed cost nature of the operation means that each incremental barrel of production contributes significantly to cash flow and profitability. With the upgrader operating at an average of about 50% capacity during the quarter, we generated positive cash flow. At full capacity and US$90 WTI, the project is expected to generate about $800 million of cash flow annually.

Our strategy for filling the upgrader includes:

- growth in production from the initial 10 pads;

- ramp-up of pad 11;

- start-up of pads 12 and 13 that are currently being drilled;

- drilling of pads 14 and 15 which we are targeting to commence drilling in 2012;

- identifying future drilling on the Long Lake and Kinosis leases; and

- processing of third-party sourced bitumen in the interim to enhance returns from this facility.

We believe the continued drilling of high-quality resource on Long Lake and the advancement of Kinosis drilling is the most economic and expedient strategy to grow and sustain our proprietary bitumen volumes to fill the upgrader.

Initially, we expected to fill the upgrader from the first 11 pads that are now on-stream; however, we underestimated the impact lean zones and shales would have on production rates and steam-oil ratio (SOR). We better understand the correlation between reservoir characteristics and production and SOR, based on the range of well performance we experienced in the initial wells. This understanding allows us to target the best quality resource for development that is analogous to the wells in our initial set that are exhibiting good performance. It also confirms that our oil sands lands, including undeveloped areas on the Long Lake lease, contain attractive resource.

We expect production from pads 1 to 11 to continue to increase over time from additional steam, heating through the lean zones, the ramp-up of wells as they mature, and well work-over activities. Production from pad 11 is currently approximately 1,700 bbls/d and is expected to contribute 4,000 to 8,000 bbls/d at maturity.

Pads 12 and 13 were the first to be targeted at the higher quality resource from across the entire lease rather than concentrating on the resource in the vicinity of the upgrader. Well logs and core data indicate these 18 wells are similar to our best producing wells on the lease, which are meeting or exceeding expectations. They also compare favorably with wells drilled on leases by other companies that match our performance expectations. Drilling on the two pads is in progress. Pad 12 is expected to start steaming in the second quarter of next year and pad 13 in the third quarter. Production is expected about three months after first steam and is expected to ramp-up to full rates over the following 12 to 18 months. We expect production from these two pads to contribute 11,000 to 17,000 bbls/d at maturity.

We plan to commence drilling 10 to 12 wells on pads 14 and 15 in 2012, subject to regulatory approvals. First steam to these wells is expected in late 2013. These wells are also targeting high quality resource. We expect production from these two pads to contribute 6,000 to 9,000 bbls/d at maturity.

We are also progressing the acceleration of the development of 25 to 30 wells at Kinosis, which is along the southern border of the Long Lake lease. Our core-hole analysis and reservoir understanding of Kinosis confirms the resource here has minimal lean zones and shale barriers. Well log and core data show these to be analogous to our best producing wells on Long Lake. Also, with core-holes in place and regulatory approval at an advanced stage, we expect to be able to develop these well pairs faster than for pads beyond 14 and 15. Production from these wells is expected to contribute 15,000 to 25,000 bbls/d at maturity. We expect to provide details regarding timing and cost of this opportunity later this year.

We expect these wells to fill the upgrader and offset production declines in the initial 10 pads.

To further evaluate our Long Lake and Kinosis leases for future development, we are proceeding with a 200 well core-hole drilling program this winter. This program supports our sustaining development activities to keep the Long Lake upgrader full and to begin development of the rest of the Kinosis lease using our bitumen-leading strategy. This strategy allows us to ramp-up SAGD production while retaining flexibility in the timing of building additional upgraders to enhance the economics of the developments.

We are also planning to participate with a 25% working interest in a non-operated SAGD project at Hangingstone. Project sanctioning is expected late this year or early next year, and first steam would be in about late 2014. Our share of production at full rates is expected to be about 6,000 bbls/d.

The upgrader continued to perform well with an on-stream factor of 91% and premium synthetic crude (PSC) yield of 70% compared to 93% and 74%, respectively, in the first quarter. In June, we successfully processed 45,000 bbls/d of produced and purchased bitumen, reaching upgrader throughput of about 65% of capacity. We will continue to purchase and upgrade third-party volumes when market and operating conditions are appropriate.

Shale Gas

Northeast British Columbia - Our shale gas strategy is progressing as planned and production from the eight-well pad at Horn River brought on-stream late last year continues to meet expectations. Horn River production averaged approximately 40 million cubic feet (mmcf/d) during the quarter. Plans to increase production at Horn River later this year continued to progress with our successful drilling program on the nine-well pad, where we once again set industry benchmarks for drilling days per well, including one well drilled in a record 14 days. We also began fracing and completion activities on the wells during the quarter. Production from this nine-well pad is expected on-stream in the fourth quarter but will be limited to our existing facility capacity of about 50 mmcf/d. This capacity increases to 175 mmcf/d in late 2012 to coincide with the start-up of production from our 18-well pad. We commenced drilling this pad in late June and production is expected to come on-stream in the fourth quarter of 2012. Additional facility capacity is planned to be added as our production increases. Our process to seek a joint venture partner to accelerate value realization for a portion of our shale gas asset is proceeding on schedule with numerous parties accessing the data room.

Director Appointments

During the second quarter, Nexen appointed two new directors to our Board, Thomas Ebbern and Arthur Scace, C.M., Q.C. Thomas Ebbern began his career as a geophysicist, and has recently held positions as managing director at Macquarie Capital Markets Canada Ltd., and managing director at Tristone Capital Inc., an energy advisory firm. Arthur Scace comes with a distinguished career in law, where he was former partner and chair of McCarthy Tetrault LLP. He has also sat on various boards, and was the former Chair of the Bank of Nova Scotia.

Quarterly Dividend

The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable October 1, 2011, to shareholders of record on September 9, 2011.

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 Appomattox resource disclosure, please refer to our press release dated September 27, 2010.

Conference Call

Marvin Romanow, President and CEO, and Kevin Reinhart, Executive Vice President and CFO, will host a conference call to discuss our second quarter 2011 financial results.

Date: July 14, 2011

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:

416-340-2216 (Toronto)

866-226-1792 (North American toll-free)

800-9559-6853 (Global toll-free)

A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, by calling 905-694-9451 (Toronto) or 800-408-3053 (toll-free) passcode 6758230 followed by the pound sign.

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

Forward-Looking Statements

Certain statements in this 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 negotiating of an extension to certain of our production sharing agreements; 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; future demand for chemicals products; estimates on a per share basis; future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and 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.

Cautionary Note to US Investors

In this disclosure, we may refer to "recoverable reserves", "recoverable resources", "recoverable contingent resources" and "prospective resources" which are inherently more uncertain than proved reserves or probable reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Information Form available under our profile on SEDAR at www.sedar.com for further reserves disclosure.

Cautionary Note to Canadian Investors

Nexen has received an exemption from the securities regulatory authorities in the various provinces of Canada from certain requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") that permits us to disclose reserves estimates and related disclosures that have been prepared in accordance with SEC requirements.

As a result of this exemption, Nexen's disclosures may differ from other Canadian companies and investors should note the following fundamental differences between reserves estimates and related disclosures prepared in accordance with SEC requirements and those prepared in accordance with NI 51-101:

- SEC reserves estimates are based upon different reserves definitions and are prepared in accordance with generally recognized industry practices in the US whereas NI 51-101 reserves are based on definitions and standards promulgated by the Canadian Oil and Gas Evaluation Handbook ("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; 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 also received an exemption from NI 51-101 that permits us to forego the requirement to have our 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.

Resources

The resource estimates contained in this news release were announced on September 27, 2010 and were prepared by qualified reserves evaluators. The estimated contingent and prospective resources in this news release reflects all of our low, high and best case of recoverable resources. A "best estimate" is the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. The 'low estimate' and 'high estimate' are considered to be conservative and optimistic estimates of resources with 90% and 10% confidence respectively. Nexen's estimates of contingent and prospective resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook. Contingent resources are quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Prospective resources are quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.

Contingencies on resources may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific oil sands contingencies precluding these contingent resources being classified as reserves include but are not limited to: project sanction, the cost and effectiveness of steam-assisted gravity drainage application, stakeholder and regulatory approvals, access to required services and infrastructure, oil prices and a demonstration of economic viability. There is no certainty that it will be commercially viable to produce any portion of these contingent oil sands resources.

Specific shale gas contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program and testing results, project sanction, the cost and effectiveness of fracing optimization, stakeholder and regulatory approvals, access to required services and field development infrastructure, gas prices and a demonstration of economic viability. There is no certainty that it will be commercially viable to produce any portion of these contingent shale gas resources. In the case of shale gas prospective resources there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.

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


Nexen Inc.
Financial Highlights
                                      Three Months Ended   Six Months Ended
                                June 30 March 31 June 30   June 30  June 30
(Cdn$ millions)                    2011     2011    2010      2011     2010
----------------------------------------------------------------------------
Net Sales (1)                     1,507    1,640   1,466     3,147    2,995
Cash Flow from Operations (1)       598      669     549     1,267    1,098
 Per Common Share ($/share)        1.13     1.27    1.05      2.40     2.10
Net Income (1)                      252      202     245       454      386
 Per Common Share ($/share)        0.48     0.38    0.47      0.86     0.74
Capital Investment (2)              530      499     840     1,029    1,410
Net Debt (3)                      2,838    3,350   5,492     2,838    5,492
Common Shares Outstanding
 (millions of shares)             527.0    526.7   524.6     527.0    524.6
                                --------------------------------------------

(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     Six Months Ended
                            June 30  March 31  June 30    June 30   June 30
(Cdn$ millions)                2011      2011     2010       2011      2010
----------------------------------------------------------------------------
Conventional Oil & Gas
 United Kingdom                 699       887      658      1,586     1,325
 North America (2)               91        65       91        156       229
 Other Countries (3)            115        96       86        211       191
Oil Sands
 In Situ                          6       (19)     (19)       (13)      (77)
 Syncrude                       103       107       80        210       145
                            ------------------------------------------------
                              1,014     1,136      896      2,150     1,813
Interest, Marketing and
 Other Corporate Items (2)      (90)      (85)    (122)      (175)     (274)
Income Taxes (4)               (326)     (382)    (225)      (708)     (441)
                            ------------------------------------------------
Cash Flow from Operations(1)    598       669      549      1,267     1,098
                            ------------------------------------------------
                            ------------------------------------------------

(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     Six Months Ended
                          June 30    March 31  June 30    June 30   June 30
(Cdn$ millions)              2011        2011     2010       2011      2010
----------------------------------------------------------------------------
Cash Flow from Operating
 Activities                   995         736      533      1,731     1,345
Changes in Non-Cash
 Working Capital Including
 Income Taxes and Interest
 Payable                     (405)        (66)      58       (471)     (198)
Other                          16           7      (30)        23       (27)
Impact of Annual Crude
 Oil Put Options               (8)         (8)     (12)       (16)      (22)
                          --------------------------------------------------
Cash Flow from Operations     598         669      549      1,267     1,098
                          --------------------------------------------------
                          --------------------------------------------------
Weighted-average Number
 of Common Shares
 Outstanding
 (millions of shares)       527.0       526.3    524.5      526.6     524.0
                          --------------------------------------------------
Cash Flow from Operations
 Per Common Share
 ($/share)                   1.13        1.27     1.05       2.40      2.10
                          --------------------------------------------------
                          --------------------------------------------------
(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 $58 million for the three months
    ended June 30, 2011 (March 31, 2011 - $42 million; June 30, 2010 - $39
    million) and $100 million for the six months ended June 30, 2011 (2010
    - $82 million).
(4) Excludes in-country cash taxes in Yemen.


Nexen Inc.
Production Volumes (before royalties)(1)
                                           Three Months          Six Months
                                          Ended June 30       Ended June 30
                                         2011      2010      2011      2010
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
 United Kingdom                          77.6      98.2      87.3     101.9
 Yemen                                   34.7      40.9      36.5      41.9
 Oil Sands - Syncrude                    20.4      23.4      21.8      21.5
 Oil Sands - Long Lake Bitumen           18.1      16.2      17.4      14.2
 United States                            8.9       9.9       9.0       9.8
 Canada (2)                                 -      13.1         -      13.7
 Other Countries                          1.8       2.1       1.7       2.2
                                       -------------------------------------
                                        161.5     203.8     173.7     205.2
                                       -------------------------------------
Natural Gas (mmcf/d)
 United Kingdom                            37        40        36        40
 United States                             96        96        99        98
 Canada (2)                               124       128       130       130
                                       -------------------------------------
                                          257       264       265       268
                                       -------------------------------------

Total Production (mboe/d)                 204       248       218       250
                                       -------------------------------------
                                       -------------------------------------

Production Volumes (after royalties)
                                           Three Months          Six Months
                                          Ended June 30       Ended June 30
                                         2011      2010      2011      2010
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
 United Kingdom                          77.3      98.2      87.1     101.9
 Yemen                                   18.8      22.2      19.7      22.6
 Oil Sands - Syncrude                    17.8      21.5      20.1      19.7
 Oil Sands - Long Lake Bitumen           16.9      15.7      16.3      13.5
 United States                            8.0       8.9       8.1       8.9
 Canada (2)                                 -      10.0         -      10.4
 Other Countries                          1.6       2.0       1.6       2.1
                                       -------------------------------------
                                        140.4     178.5     152.9     179.1
                                       -------------------------------------
Natural Gas (mmcf/d)
 United Kingdom                            37        40        36        40
 United States                             83        83        86        85
 Canada (2)                               119       117       123       119
                                       -------------------------------------
                                          239       240       245       244
                                       -------------------------------------

Total Production (mboe/d)                 180       218       194       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 in Note
    14 to our Unaudited Condensed Consolidated Financial Statements.


                                           Three Months          Six Months
                                          Ended June 30       Ended June 30
                                         2011      2010      2011      2010
----------------------------------------------------------------------------
Before Royalties
 Crude Oil and NGLs (mbbls/d)               -      13.1         -      13.7
 Natural Gas (mmcf/d)                       -        11         -        11
After Royalties
 Crude Oil and NGLs (mbbls/d)               -      10.0         -      10.4
 Natural Gas (mmcf/d)                       -        10         -        10
                                        ------------------------------------

Nexen Inc.

Oil and Gas Prices and Cash Netback(1)


(all dollar        
 amounts in                                                           Total
 Cdn$ unless          Quarters - 2011            Quarters - 2010       Year
 noted)            1st     2nd  3rd  4th   1st     2nd    3rd    4th   2010
----------------------------------------------------------------------------
PRICES:
Brent Crude
 Oil
 (US$/bbl)     104.97  117.36            76.23   78.30  76.86  86.48  79.47
WTI Crude
 Oil
 (US$/bbl)      94.10  102.56            78.71   78.03  76.20  85.12  79.52
Nexen Average -
 Oil
 (Cdn$/bbl)     98.37  110.28            78.00   76.23  77.03  84.47  78.94
NYMEX
 Natural Gas
 (US$/mmbtu)     4.20    4.37             5.04    4.34   4.24   3.97   4.39
AECO Natural
 Gas
 (Cdn$/mcf)      3.58    3.54             5.08    3.66   3.52   3.41   3.92
Nexen Average -
 Gas
 (Cdn$/mcf)      4.51    4.75             5.37    4.42   4.18   4.16   4.54
----------------------------------------------------------------------------
NETBACKS(1):
----------------------------------------------------------------------------
United
 Kingdom
 Crude Oil:
  Sales
   (mbbls/d)    104.2    73.3            106.5   102.1  103.9  110.0  105.6
  Price
   Received
   ($/bbl)      99.97  110.55            77.24   77.18  77.45  83.88  79.02
 Natural Gas:
  Sales
  (mmcf/d)         36      37               33      41     29     38     36
  Price
   Received
   ($/mcf)       7.29    8.20             4.81    4.80   5.11   6.34   5.28
 Total Sales
  Volume
  (mboe/d)      110.2    79.5            112.1   109.0  108.8  116.3  111.5
 Price
  Received
  ($/boe)       96.91  105.76            74.84   74.12  75.35  81.37  76.51
 Operating
  Costs          9.85    8.48             7.60    7.85   8.41   9.19   8.28
----------------------------------------------------------------------------
 Netback        87.06   97.28            67.24   66.27  66.94  72.18  68.23
----------------------------------------------------------------------------
United States
 Crude Oil:
  Sales
   (mbbls/d)      9.2     8.9              9.8     9.9    9.8   10.1    9.9
  Price
   Received
   ($/bbl)      91.39  101.89            79.12   73.60  73.72  80.41  76.73
 Natural Gas:
  Sales
   (mmcf/d)       103      96              101      95    102     99     99
  Price
   Received
   ($/mcf)       4.36    4.42             6.00    5.14   4.70   4.05   4.97
 Total Sales
  Volume
  (mboe/d)       26.3    24.9             26.6    25.8   26.9   26.6   26.5
 Price
  Received
  ($/boe)       48.91   53.56            51.92   47.23  44.85  45.55  47.35
 Royalties &
  Other          5.65    6.11             4.92    4.86   5.10  (0.63)  3.55
 Operating
  Costs         10.43   10.72             8.96   10.90   9.44  10.78  10.02
----------------------------------------------------------------------------
 Netback        32.83   36.73            38.04   31.47  30.31  35.40  33.78
----------------------------------------------------------------------------
Canada -
 Natural Gas
 Sales
  (mmcf/d)(2)      97      85              124     121    107    104    114
 Price
  Received
  ($/mcf)        3.65    3.62             5.02    3.72   3.43   3.48   3.94
 Royalties &
  Other          0.28    0.24             0.40    0.34   0.26   0.24   0.32
 Operating
  Costs          1.70    1.54             1.70    1.89   1.90   1.55   1.76
----------------------------------------------------------------------------
 Netback         1.67    1.84             2.92    1.49   1.27   1.69   1.86
----------------------------------------------------------------------------
Yemen
 Sales
  (mbbls/d)      34.9    39.3             47.3    39.3   43.5   38.8   42.2
 Price
  Received
  ($/bbl)      101.57  111.77            80.39   80.50  79.33  87.82  81.86
 Royalties &
  Other         46.98   52.26            37.52   36.65  34.75  37.72  36.65
 Operating
  Costs         10.75    9.18             9.67   10.01   9.46  12.05  10.25
 In-country
  Taxes         13.48   16.26            10.14   10.97  10.70  11.52  10.80
----------------------------------------------------------------------------
 Netback        30.36   34.07            23.06   22.87  24.42  26.53  24.16
----------------------------------------------------------------------------


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

(2) Excludes sales related to shale gas activities in north eastern British
    Columbia.


(all dollar        
 amounts in                                                           Total
 Cdn$ unless          Quarters - 2011            Quarters - 2010       Year
 noted)            1st     2nd  3rd  4th   1st     2nd    3rd    4th   2010
----------------------------------------------------------------------------
Other Countries
 Sales (mbbls/d)   1.8     1.7             2.3     2.1    2.0    1.9    2.1

 Price Received
  ($/bbl)        93.52  106.57           78.88   74.77  75.93  77.63  76.83
 Royalties &
  Other           6.22    6.93            5.72    5.28   5.22   5.24   5.37
 Operating Costs  8.11   10.19            5.58    7.42   6.98   8.19   6.99
----------------------------------------------------------------------------
 Netback         79.19   89.45           67.58   62.07  63.73  64.20  64.47
----------------------------------------------------------------------------
 In Situ (2)
  Sales
   (mbbls/d)      12.9    14.3             6.6    10.3   11.9   12.1   10.3

  Price Received
   ($/bbl)       89.82  108.78           81.04   74.08  70.64  82.99  77.07
  Royalties &
   Other          3.58    6.05            4.37    2.98   3.08   3.81   3.65
  Operating
   Costs         89.43   95.34          154.00   89.95  84.75  85.61 100.09
----------------------------------------------------------------------------
  Netback (2)    (3.19)   7.39          (77.33) (18.84)(17.19) (6.43)(26.67)
----------------------------------------------------------------------------
 Syncrude
  Sales (mbbls/d) 23.2    20.4            19.5    23.4   19.1   22.8   21.2

  Price Received
   ($/bbl)       94.60  111.79           83.55   77.93  78.27  85.12  81.23
  Royalties &
   Other          4.30   13.82            7.09    6.37   4.82   6.72   6.27
  Operating
   Costs         36.11   39.98           35.84   32.67  38.06  31.65  34.34
----------------------------------------------------------------------------
 Netback         54.19   57.99           40.62   38.89  35.39  46.75  40.62
----------------------------------------------------------------------------
Company-Wide

 Oil and Gas
  Sales (mboe/d) 225.5   196.4           249.1   243.1  232.9  235.9  240.2

 Price Received
  ($/boe)        85.98   95.26           70.16   67.56  68.23  74.49  70.11
 Royalties &
  Other           8.74   13.42            9.38    8.05   7.96   7.13   8.16
 Operating &
  Other Costs(2) 17.32   18.68           14.93   15.85  15.42  15.97  15.48
 In-country
 Taxes            2.08    3.29            1.92    1.76   2.00   1.89   1.90
----------------------------------------------------------------------------
 Netback         57.84   59.87           43.92   41.90  42.85  49.50  44.57
----------------------------------------------------------------------------

(1) Defined as average sales price less royalties and other, operating
    costs, and in-country taxes in Yemen.
(2) Excludes activities related to third-party bitumen purchased, processed
    and sold. Sales volumes and amounts relate to PSC sales made to third
    parties during the period.

Nexen Inc.
Unaudited Condensed Consolidated Statement of Income 
For the Three and Six Months Ended June 30


                                           Three Months          Six Months
(Cdn$ millions, except per share          Ended June 30       Ended June 30
 amounts)                                2011      2010      2011      2010
----------------------------------------------------------------------------
Revenues and Other Income
 Net Sales                              1,507     1,305     3,105     2,652
 Marketing and Other Income (Note 13)      95        96       141       187
                                       -------------------------------------
                                        1,602     1,401     3,246     2,839
                                       -------------------------------------

Expenses
 Operating                                341       321       704       644
 Depreciation, Depletion, Amortization
  and Impairment                          335       358       705       701
 Transportation and Other                 112       141       179       334
 General and Administrative                76        40       181       149
 Exploration                               93        50       219       143
 Finance (Note 8)                          60        97       134       186
 Loss on Debt Redemption and Repurchase
 (Note 7)                                   1         -        91         -
 Net Gain from Dispositions                 -       (80)        -       (80)
                                       -------------------------------------
                                        1,018       927     2,213     2,077
                                       -------------------------------------

Income from Continuing Operations
 before Provision for Income Taxes        584       474     1,033       762
                                       -------------------------------------

Provision for (Recovery of) Income
 Taxes
 Current                                  384       264       808       523
 Deferred                                 (52)      (28)       73      (110)
                                       -------------------------------------
                                          332       236       881       413
                                       -------------------------------------

Net Income from Continuing Operations     252       238       152       349
Net Income from Discontinued
 Operations, Net of Tax (Note 14)           -         7       302        37
                                       -------------------------------------
Net Income Attributable to Nexen Inc.     252       245       454       386
                                       -------------------------------------
                                       -------------------------------------

Earnings Per Common Share from
 Continuing Operations ($/share)
 Basic                                   0.48      0.45      0.29      0.66
                                       -------------------------------------
                                       -------------------------------------
 Diluted                                 0.45      0.42      0.27      0.62
                                       -------------------------------------
                                       -------------------------------------

Earnings Per Common Share ($/share)
 Basic                                   0.48      0.47      0.86      0.74
                                       -------------------------------------
                                       -------------------------------------
 Diluted                                 0.45      0.43      0.84      0.69
                                       -------------------------------------
                                       -------------------------------------

See accompanying notes to the Unaudited Condensed Consolidated Financial
Statements.


Nexen Inc.
Unaudited Condensed Consolidated Balance Sheet
                                            June 30  December 31  January 1
(Cdn$ millions)                                2011         2010       2010
----------------------------------------------------------------------------
Assets
 Current Assets
  Cash and Cash Equivalents                   1,312        1,005      1,700
  Restricted Cash                                50           40        198
  Accounts Receivable (Note 3)                1,871        1,789      2,322
  Derivative Contracts                           80          149        466
  Inventories and Supplies (Note 4)             344          550        680
  Other                                         148          142        185
  Assets Held for Sale (Note 14)                  -          729          -
                                           ---------------------------------
   Total Current Assets                       3,805        4,404      5,551
                                           ---------------------------------
 Non-Current Assets
  Property, Plant and Equipment (Note 5)     14,628       14,579     14,669
  Goodwill                                      276          286        330
  Deferred Income Tax Assets                    175          160         75
  Derivative Contracts                           27          116        225
  Other Long-Term Assets                        149          102        105
                                           ---------------------------------
Total Assets                                 19,060       19,647     20,955
                                           ---------------------------------
                                           ---------------------------------
Liabilities
 Current Liabilities
  Accounts Payable and Accrued Liabilities
   (Note 6)                                   2,988        2,459      2,681
  Derivative Contracts                           88          168        456
  Accrued Interest Payable                       74           83         89
  Dividends Payable                              26           26         26
  Liabilities Held for Sale (Note 14)             -          582          -
                                           ---------------------------------
   Total Current Liabilities                  3,176        3,318      3,252
                                           ---------------------------------
 Non-Current Liabilities
  Long-Term Debt (Note 7)                     4,150        5,090      7,259
  Deferred Income Tax Liabilities             1,636        1,487      1,678
  Asset Retirement Obligations (Note 9)       1,561        1,516      1,397
  Derivative Contracts                           35          115        210
  Other Long-Term Liabilities                   321          307        372

Equity (Note 11)
 Nexen Inc. Shareholders' Equity
  Common Shares                               1,142        1,111      1,050
  Retained Earnings                           7,094        6,692      5,704
  Accumulated Other Comprehensive Loss          (55)         (37)         -
                                           ---------------------------------
 Total Nexen Inc. Shareholders' Equity        8,181        7,766      6,754
  Canexus Non-Controlling Interest (Note 14)      -           48         33
                                           ---------------------------------
 Total Equity                                 8,181        7,814      6,787
 Commitments, Contingencies and
  Guarantees (Note 12)
                                           ---------------------------------
Total Liabilities and Equity                 19,060       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 Six Months Ended June 30


                                           Three Months          Six Months
                                          Ended June 30       Ended June 30
(Cdn$ millions)                          2011      2010      2011      2010
----------------------------------------------------------------------------
Operating Activities
 Net Income from Continuing Operations    252       238       152       349
 Net Income from Discontinued
  Operations                                -         7       302        37
 Charges and Credits to Income not
  Involving Cash (Note 15)                694       638     1,532     1,302
 Exploration Expense                       93        50       219       143
 Income Taxes Paid                        (69)      (43)     (460)     (250)
 Interest Paid                            (66)     (101)     (130)     (190)
 Changes in Non-Cash Working Capital
  (Note 15)                               121      (286)      153       (73)
 Other                                    (11)       30       (18)       27
                                       -------------------------------------
                                        1,014       533     1,750     1,345

Financing Activities
 Proceeds from Short-Term Borrowings        -       156         -       156
 Repayment of Term Credit Facilities,
 Net                                        -    (1,077)        -    (1,077)
 Repayment of Long-Term Debt (Note 7)    (525)        -      (871)        -
 Proceeds from Canexus Long-Term Debt,
 Net                                        -        46         5        68
 Dividends Paid on Common Shares          (26)      (26)      (52)      (52)
 Issue of Common Shares and Exercise of
  Tandem Options for Shares                 8        10        31        35
 Other                                     (6)      (16)       (4)      (20)
                                       -------------------------------------
                                         (549)     (907)     (891)     (890)

Investing Activities
 Capital Expenditures
  Exploration, Evaluation, and
   Development                           (481)     (748)     (935)   (1,236)
  Capitalized Interest Paid               (29)      (22)      (57)      (40)
  Corporate and Other                     (20)      (70)      (37)     (134)
 Proceeds from Dispositions                12        81       474        96
 Changes in Restricted Cash                (2)       68       (11)       83
 Changes in Non-Cash Working Capital
  (Note 15)                                31       (13)      115        75
 Other                                    (23)       (4)      (75)       (7)
                                       -------------------------------------
                                         (512)     (708)     (526)   (1,163)

Effect of Exchange Rate Changes on Cash
 and Cash Equivalents                     (15)       55       (26)      (22)
                                       -------------------------------------

Increase (Decrease) in Cash and Cash
 Equivalents                              (62)   (1,027)      307      (730)

Cash and Cash Equivalents - Beginning
 of Period                              1,374     1,997     1,005     1,700
                                       -------------------------------------

Cash and Cash Equivalents - End of
 Period (1)                             1,312       970     1,312       970
                                       -------------------------------------
                                       -------------------------------------
(1) Cash and cash equivalents at June 30, 2011 consists of cash of $218
    million and short-term investments of $1,094 million (June 30, 2010 -
    cash of $237 million and short-term investments of $733 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 Six Months Ended June 30

                                           Three Months          Six Months
                                          Ended June 30       Ended June 30
(Cdn$ millions)                          2011      2010      2011      2010
----------------------------------------------------------------------------

Common Shares, Beginning of Period      1,134     1,077     1,111     1,050
 Issue of Common Shares                     8         8        31        32
 Exercise of Tandem Options for Shares      -         2         -         3
 Accrued Liability Relating to Tandem
  Options Exercised for Common Shares       -         1         -         3
                                       -------------------------------------
 Balance at End of Period               1,142     1,088     1,142     1,088
                                       -------------------------------------
                                       -------------------------------------

Retained Earnings, Beginning of Period  6,868     5,819     6,692     5,704
  Net Income Attributable to Nexen Inc.   252       245       454       386
  Dividends on Common Shares (Note 11)    (26)      (26)      (52)      (52)
                                       -------------------------------------
 Balance at End of Period               7,094     6,038     7,094     6,038
                                       -------------------------------------
                                       -------------------------------------

Accumulated Other Comprehensive Loss,
 Beginning of Period                      (48)      (13)      (37)        -
  Other Comprehensive Income (Loss)
   Attributable to Nexen Inc.              (7)        8       (18)       (5)
                                       -------------------------------------
 Balance at End of Period                 (55)       (5)      (55)       (5)
                                       -------------------------------------
                                       -------------------------------------

Canexus Non-Controlling Interests,
 Beginning of Period                        -        39        48        33
  Net Income Attributable to
   Non-Controlling Interests                -        (6)        1        (1)
  Distributions Declared to
   Non-Controlling Interests                -        (3)        -        (7)
  Issue of Partnership Units to
   Non-Controlling Interests                -        12         -        17
  Disposition of Canexus (Note 14)          -         -       (49)        -
                                       -------------------------------------
 Balance at End of Period                   -        42         -        42
                                       -------------------------------------
                                       -------------------------------------

See accompanying notes to the Unaudited Condensed Consolidated Financial
Statements.


Nexen Inc.
Unaudited Condensed Consolidated Statement of Comprehensive Income 
For the Three and Six Months Ended June 30

                                           Three Months          Six Months
                                          Ended June 30       Ended June 30
(Cdn$ millions)                          2011      2010      2011      2010
----------------------------------------------------------------------------
Net Income                                252       245       454       386
 Other Comprehensive Income (Loss), Net
  of Income Taxes:
  Foreign Currency Translation Adjustment
   Net Gains (Losses) on Investment in
    Self-Sustaining Foreign Operations    (35)      221      (139)       66
   Net Gains (Losses) on
    Foreign-Denominated Debt Hedging
    of Self-Sustaining Foreign
    Operations (1)                         28      (213)      121       (71)
                                       -------------------------------------
  Other Comprehensive Income (Loss)
   Attributable to Nexen Inc.              (7)        8       (18)       (5)
                                       -------------------------------------
Total Comprehensive Income                245       253       436       381
                                       -------------------------------------
                                       -------------------------------------

(1) Net of income tax expense for the three months ended June 30, 2011 of $4
    million (2010 - net of income tax recovery of $31 million) and net of
    income tax expense for the six months ended June 30, 2011 of $17 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. 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 six months ended June 30, 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 six months ended June 30, 2010 and as at 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 July 13, 2011 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 will adopt 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 currently evaluating the impact that these standards will have on our results of operations and financial position:


--  IFRS 9 Financial Instruments - in November 2009, the International
    Accounting Standards Board (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, 2013.
    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 is required to be
    adopted for periods beginning January 1, 2013. We are evaluating the
    impact that this standard may have on our results of operations and
    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 is required to be adopted for periods
    beginning January 1, 2013. We are evaluating the impact that this
    standard may have on our results of operations and financial position. 
--  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 are evaluating the
    impact that this standard may have on our results of operations and
    financial position. 
--  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 are
    evaluating the impact that this standard may have on our results of
    operations and 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 split 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 are evaluating the impact that this standard may have on our
    results of operations and financial position. 
--  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. We are evaluating the impact that this standard may have on our
    results of operations and financial position. 


3. ACCOUNTS RECEIVABLE 

                                          June 30   December 31   January 1 
                                             2011          2010        2010 
----------------------------------------------------------------------------
Trade                                                                       
 Energy Marketing                           1,069           929       1,410 
 Oil and Gas                                  706           822         823 
 Other                                          6             2          44 
                                      --------------------------------------
                                            1,781         1,753       2,277 
Non-Trade                                     131            80          99 
                                      --------------------------------------
                                            1,912         1,833       2,376 
Allowance for Doubtful Receivables            (41)          (44)        (54)
                                      --------------------------------------
Total (1)                                   1,871         1,789       2,322 
                                      --------------------------------------
                                      --------------------------------------
(1) At December 31, 2010, accounts receivable related to our chemicals      
    operations have been included with assets held for sale (see Note 14).  


Receivables are generally on 30-day terms and were current as of June 30,
2011, December 31, 2010 and January 1, 2010.

4. INVENTORIES AND SUPPLIES 

                                           June 30   December 31   January 1
                                              2011          2010        2010
----------------------------------------------------------------------------
Finished Products                                                           
 Energy Marketing                              223           452         548
 Oil and Gas                                    58            35          25
 Other                                           -             -          12
                                      --------------------------------------
                                               281           487         585
Work in Process                                  7             5           7
Field Supplies                                  56            58          88
                                      --------------------------------------
Total (1)                                      344           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

(a) Carrying amount of PP&E 

                   Exploration                 Producing                    
                           and  Assets 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                (326)            -          (2)         -    (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               2,992         1,748      18,885        757  24,382 
  Additions                427           270         294         37   1,028 
  Disposals/                                                                
   Derecognitions          (43)            -         (51)       (11)   (105)
  Transfers               (235)          235           -          -       - 
  Exploration                                                               
   Expense                (218)            -          (1)         -    (219)
  Other                     77            17          44          -     138 
  Effect of                                                                 
   Changes in                                                               
   Exchange Rate           (27)          (59)       (330)        (3)   (419)
                   ---------------------------------------------------------
 As at June 30,                                                             
  2011                   2,973         2,211      18,841        780  24,805 
                   ---------------------------------------------------------
                   ---------------------------------------------------------

Accumulated 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)
  Impairment                                                                
   Losses                    -             -         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                      24             -         645         36     705 
  Disposals/                                                                
   Derecognitions           (7)            -         (51)        (8)    (66)
  Other                      -             -          (2)         -      (2)
  Effect of                                                                 
   Changes in                                                               
   Exchange Rate            (7)            -        (253)        (3)   (263)
                   ---------------------------------------------------------
 As at June 30,                                                             
  2011                     341             -       9,393        443  10,177 
                   ---------------------------------------------------------
                   ---------------------------------------------------------

Net Book Value                                                              
 As at January 1,                                                           
  2010                   2,033         1,034      10,695        907  14,669 
                   ---------------------------------------------------------
                   ---------------------------------------------------------
 As at December                                                             
  31, 2010               2,661         1,748       9,831        339  14,579 
                   ---------------------------------------------------------
                   ---------------------------------------------------------
 As at June 30,                                                             
  2011                   2,632         2,211       9,448        337  14,628 
                   ---------------------------------------------------------
                   ---------------------------------------------------------

Exploration and evaluation assets mainly comprise of unproved properties and capitalized exploration drilling costs. Assets under construction include our Usan development, offshore Nigeria.

(b) Impairment

Our 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 reduced properties' estimated future cash flows, which resulted in impairments for properties in the US Gulf of Mexico and Canada.

These properties were written down to their estimated fair value based on their estimated future discounted net cash flows. The estimated future cash flows incorporate a risk-adjusted discount rate and management's estimates of future prices, capital expenditures and production.

6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES


                                            June 30  December 31   January 1
                                               2011         2010        2010
----------------------------------------------------------------------------
Energy Marketing Payables                     1,051        1,016       1,366
Accrued Payables                                664          676         619
Income Taxes Payable                            733          345         179
Trade Payables                                  176          164         210
Stock-Based Compensation                         99          111         173
Other                                           265          147         134
                                         -----------------------------------
Total (1)                                     2,988        2,459       2,681
                                         -----------------------------------
                                         -----------------------------------
(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

                                           June 30  December 31   January 1 
                                              2011         2010        2010 
----------------------------------------------------------------------------
Term Credit Facilities, due 2016 (a)             -            -       1,570 
Notes, due 2013 (US$500 million) (b)             -          497         523 
Notes, due 2015 (US$126 million) (c)           121          249         262 
Notes, due 2017 (US$62 million) (c)             60          249         262 
Notes, due 2019 (US$300 million)               289          298         314 
Notes, due 2028 (US$200 million)               193          199         209 
Notes, due 2032 (US$500 million)               482          497         523 
Notes, due 2035 (US$790 million)               762          786         827 
Notes, due 2037 (US$1,250 million)           1,205        1,243       1,308 
Notes, due 2039 (US$700 million)               675          696         733 
Subordinated Debentures, due 2043                                           
 (US$460 million)                              444          457         481 
                                       -------------------------------------
                                             4,231        5,171       7,012 
Unamortized debt issue costs                   (81)         (81)        (88)
                                       -------------------------------------
                                             4,150        5,090       6,924 
Canexus debt                                     -            -         335 
                                       -------------------------------------
Total                                        4,150        5,090       7,259 
                                       -------------------------------------
                                       -------------------------------------

(a) Term credit facilities

We have unsecured term credit facilities of $3 billion (US$3.1 billion) available until 2016, none of which were drawn at either June 30, 2011 or December 31, 2010. 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. During the six months ended June 30, 2011, we did not incur any interest expense on our term credit facilities. The weighted-average interest rate on our term credit facilities for the three months ended June 30, 2010 was 1.3% and 1.1% for the six months ended June 30, 2010. At June 30, 2011, $279 million (US$289 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2010 - $322 million (US$324 million)).

(b) Redemption of Notes, due 2013

During the quarter, 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 during the first quarter as the difference between carrying value and the redemption price.

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

In the first quarter, 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) Short-term borrowings

Nexen has uncommitted, unsecured credit facilities of approximately $463 million (US$481 million), none of which were drawn at either June 30, 2011 or December 31, 2010. We utilized $24 million (US$25 million) of these facilities to support outstanding letters of credit at June 30, 2011 (December 31, 2010-$112 million (US$112 million)). Interest is payable at floating rates.

8. FINANCE EXPENSE


                                              Three Months       Six Months 
                                             Ended June 30    Ended June 30 
                                              2011    2010     2011    2010 
----------------------------------------------------------------------------
Long-Term Debt Interest Expense                 74      89      158     180 
Accretion Expense related to Asset                                          
 Retirement Obligations (Note 9)                12       9       23      19 
Other Interest Expense                           3      17       10      21 
                                           ---------------------------------
Total                                           89     115      191     220 
 Less: Capitalized at 6.5% (2010 - 5.2%)       (29)    (18)     (57)    (34)
                                           ---------------------------------
Total (1)                                       60      97      134     186 
                                           ---------------------------------
                                           ---------------------------------
(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:


                                              Six Months      Twelve Months 
                                              Ended June     Ended December 
                                                      30                 31 
                                                    2011               2010 
----------------------------------------------------------------------------
ARO, Beginning of Period                           1,571              1,432 
 Obligations Incurred with Development                                      
 Activities                                           19                 81 
 Changes in Estimates                                 42                332 
 Obligations Related to Dispositions                  (3)              (224)
 Obligations Settled                                 (25)               (43)
 Accretion                                            23                 47 
 Effects of Changes in Foreign Exchange Rate         (13)               (54)
                                            --------------------------------
ARO, End of Period                                 1,614              1,571 
                                            --------------------------------
                                            --------------------------------

Of which:                                                                   
 Due within Twelve Months (1)                         53                 55 
 Due after Twelve Months                           1,561              1,516 
                                            --------------------------------
                                            --------------------------------
(1) Included in accounts payable and accrued liabilities.                   

ARO represents the present value of estimated remediation and reclamation costs associated with our PP&E. We have discounted the estimated asset retirement obligation using a weighted-average risk-free rate of 3.0% (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 $367 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 and joint ventures

The Unaudited Condensed Consolidated Financial Statements include the financial statements of Nexen Inc. and our subsidiaries as at June 30, 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 six months ended June 30, 2011 and 2010.



                                          Country of    Principal           
Major subsidiaries                     Incorporation   Activities  Ownership
----------------------------------------------------------------------------
Nexen Petroleum UK Limited            United Kingdom    Oil & Gas       100%
Nexen Ettrick UK Limited              United Kingdom    Oil & Gas       100%
Nexen Petroleum Dragon UK Limited     United Kingdom    Oil & Gas       100%
Nexen Petroleum Nigeria Limited              Nigeria    Oil & Gas       100%
Nexen Petroleum Offshore USA Inc       United States    Oil & Gas       100%
Canadian Nexen Petroleum Yemen                 Yemen    Oil & Gas       100%
Canadian Nexen Petroleum East Al Hajr         Canada    Oil & Gas       100%
Nexen Petroleum Colombia Limited              Jersey    Oil & Gas       100%
Nexen Med Hat-Hatton Partnership              Canada    Oil & Gas       100%
Nexen Crossfield Partnership                  Canada    Oil & Gas       100%
Nexen Marketing                               Canada    Marketing       100%
Nexen Energy Marketing Europe         United Kingdom    Marketing       100%
Nexen Energy Marketing USA Inc         United States    Marketing       100%

Joint Venture                                                               
Syncrude                                      Canada    Oil & Gas      7.23%

11. EQUITY

(a) Common Shares

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 June 30, 2011, there were 527,014,110 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 (December 31, 2010 - nil; January 1, 2010 - nil).

(b) Dividends

Dividends paid per common share for the three months ended June 30, 2011 were $0.05 per common share (three months ended June 30, 2010 - $0.05). Dividends per common share for the six months ended June 30, 2011 were $0.10 per common share (six months ended June 30, 2010 - $0.10). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes. On July 13, 2011, the Board of Directors declared a quarterly dividend of $0.05 per common share, payable October 1, 2011 to the shareholders of record on September 9, 2011.

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 new drilling rig commitments in the UK North Sea and made additional office lease commitments, comprised of the following:


                               2011   2012   2013   2014   2015   Thereafter
----------------------------------------------------------------------------
Drilling Rig Commitments         39     71     12      -      -            -
Operating Lease Commitments       -      2      5      6      7           50
                               ---------------------------------------------

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 June 30, 2011 have not materially changed from the information previously disclosed in our 2010 Audited Consolidated Financial Statements.

13. MARKETING AND OTHER INCOME


                                              Three Months       Six Months 
                                             Ended June 30    Ended June 30 
                                               2011   2010     2011    2010 
----------------------------------------------------------------------------
Marketing Revenue, Net                           51    113      102     196 
Insurance Proceeds                               26      -       26       - 
Change in Fair Value of Crude Oil Put                                       
 Options                                          -      2       (7)    (14)
Foreign Exchange Gains (Losses)                   6    (11)     (16)     (2)
Other                                            12     (8)      36       7 
                                           ---------------------------------
Total                                            95     96      141     187 
                                           ---------------------------------
                                           ---------------------------------

14. DISCONTINUED OPERATIONS

In February 2011, we completed the sale of our 62.7% investment in Canexus Limited Partnership, 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 June 30 
                                                                       2010 
                                             -------------------------------
                                               Canada   Chemicals     Total 
----------------------------------------------------------------------------
Revenues and Other Income                                                   
 Net Sales                                         56         105       161 
 Other                                              -          (7)       (7)
                                             -------------------------------
                                                   56          98       154 
                                             -------------------------------
Expenses                                                                    
 Operating                                         22          78       100 
 Depreciation, Depletion, Amortization and                                  
  Impairment                                        7           8        15 
 Transportation and Other                           -          12        12 
 General and Administrative                         5           8        13 
 Finance                                            2           6         8 
                                             -------------------------------
                                                   36         112       148 
                                             -------------------------------
Income (Loss) before Provision for Income                                   
 Taxes                                             20         (14)        6 
Less: Provision for Deferred Income Taxes           5          (3)        2 
                                             -------------------------------

Income (Loss) before Non-Controlling                                        
 Interest                                          15         (11)        4 
Less: Non-Controlling Interest                      -          (3)       (3)
                                             -------------------------------
Net Income (Loss) from Discontinued                                         
 Operations, Net of Tax                            15          (8)        7 
                                             -------------------------------
                                             -------------------------------

Earnings Per Common Share                                                   
 Basic                                                                 0.02 
 Diluted                                                               0.01 


                                             -------------------------------
                                              Six Months Ended June 30      
                                       -------------------------------------
                                            2011                        2010
                                       -------------------------------------
                                       Chemicals    Canada  Chemicals  Total
----------------------------------------------------------------------------
Revenues and Other Income                                                   
 Net Sales                                    42       125        218    343
 Other                                        (1)        -          -      -
 Gain on Disposition                         348         -          -      -
                                       -------------------------------------
                                             389       125        218    343
                                       -------------------------------------
Expenses                                                                    
 Operating                                    25        45        148    193
 Depreciation, Depletion, Amortization                                      
  and Impairment                               4        20         14     34
 Transportation and Other                      2         2         28     30
 General and Administrative                    2         9         18     27
 Finance                                       2         3          7     10
                                       -------------------------------------
                                              35        79        215    294
                                       -------------------------------------
Income before Provision for Income                                          
 Taxes                                       354        46          3     49
Less: Provision for Deferred Income                                         
 Taxes                                        51        10          1     11
                                       -------------------------------------

Income before Non-Controlling Interest       303        36          2     38
Less: Non-Controlling Interest                 1         -          1      1
                                       -------------------------------------
Net Income from Discontinued                                                
 Operations, Net of Tax                      302        36          1     37
                                       -------------------------------------
                                       -------------------------------------

Earnings Per Common Share                                                   
 Basic                                      0.57                        0.08
 Diluted                                    0.57                        0.07
                                       -------------------------------------

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 June 30, 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.  


15. CASH FLOWS 

(a) Charges and credits to income not involving cash 


                                              Three Months       Six Months 
                                             Ended June 30    Ended June 30 
                                              2011    2010     2011    2010 
----------------------------------------------------------------------------
Depreciation, Depletion, Amortization and                                   
 Impairment                                    335     358      705     701 
Finance                                         60      97      134     186 
Stock-Based Compensation                       (29)    (61)      (2)    (59)
Loss on Debt Redemption and Repurchase           1       -       91       - 
Non-cash Items Included in Discontinued                                     
 Operations                                      -      27     (290)     60 
Provision for Income Taxes                     332     236      881     413 
Foreign Exchange                                (6)     (1)      17       1 
Other                                            1     (18)      (4)      - 
                                           ---------------------------------
Total                                          694     638    1,532   1,302 
                                           ---------------------------------
                                           ---------------------------------


(b) Changes in non-cash working capital 

                                              Three Months       Six Months 
                                             Ended June 30    Ended June 30 
                                              2011    2010     2011    2010 
----------------------------------------------------------------------------
Accounts Receivable                            194     (16)    (134)   (234)
Inventories and Supplies                       163     (37)     184      76 
Other Current Assets                           (17)      5       (9)     78 
Accounts Payable and Accrued Liabilities      (188)   (251)     227      82 
                                           ---------------------------------
Total                                          152    (299)     268       2 
                                           ---------------------------------
                                           ---------------------------------

Relating to:                                                                
 Operating Activities                          121    (286)     153     (73)
 Investing Activities                           31     (13)     115      75 
                                           ---------------------------------
Total                                          152    (299)     268       2 
                                           ---------------------------------
                                           ---------------------------------

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 ramped up production at Long Lake. We report our segments to align with our key growth strategies, specifically, Conventional Oil and Gas, Oil Sands and Unconventional Gas. Prior period results have been revised to reflect the presentation changes made in the current period.

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 (Yemen, offshore West Africa and Colombia).

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.

Unconventional Gas: We explore for and produce unconventional gas from shale formations in northeastern British Columbia and Poland. 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. Canexus manufactures, markets and distributes industrial chemicals, principally sodium chlorate, chlorine, muriatic acid and caustic soda. The results of our chemicals business have been presented as discontinued operations.

The accounting policies of our operating segments are the same as those described in Note 2. Net income 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 June 30, 2011


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

Net Sales            764     134        229   188       181        11  1,507
Marketing and                                                               
 Other Income          1      30          3     -         1        60     95
                 -----------------------------------------------------------
                     765     164        232   188       182        71  1,602

Less: Expenses                                                              
 Operating            61      36         35   127        75         7    341
 Depreciation,                                                              
  Depletion,                                                                
  Amortization                                                              
  and                                                                       
  Impairment         133     116         23    36        14        13    335
 Transportation                                                             
 and Other             -      11         11    51         6        33    112
 General and                                                                
  Administrative       2      19          8     2         -        45     76
 Exploration          13      41      37 (2)    2         -         -     93
 Finance               5       4          1     -         2        48     60
 Net Loss on                                                                
  Debt Redemption      -       -          -     -         -         1      1
                 -----------------------------------------------------------
Income (Loss)                                                               
 from Continuing                                                            
 Operations                                                                 
 before Income                                                              
 Taxes               551     (63)       117   (30)       85       (76)   584
Less: Provision                                                             
 for (Recovery                                                              
 of) Income Taxes    326     (15)        22    (7)       21       (15)   332
                 -----------------------------------------------------------
Net Income                                                                  
 (Loss)              225     (48)        95   (23)       64       (61)   252
                 -----------------------------------------------------------
                 -----------------------------------------------------------

Capital                                                                     
 Expenditures        104     123        171    91        27        14    530
                 -----------------------------------------------------------
                 -----------------------------------------------------------
(1) Includes results of conventional crude oil and natural gas operations in
    Yemen and Colombia.                                                     
(2) Includes exploration activities primarily in Yemen, Nigeria, Norway,    
    Colombia and Poland.                                                    


Segmented net income for the three months ended June 30, 2010

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

Net Sales           735     133        171    102      152        12  1,305 
Marketing and                                                               
 Other Income         4       1          3      -        1        87     96 
                ------------------------------------------------------------
                    739     134        174    102      153        99  1,401 

Less: Expenses                                                              
 Operating           77      44         38     85       70         7    321 
 Depreciation,                                                              
  Depletion,                                                                
  Amortization                                                              
  and                                                                       
  Impairment        189      92         25     25       13        14    358 
 Transportation                                                             
  and Other           1       5          3     32        4        96    141 
 General and                                                                
  Administrative      -      11         (1)     -        -        30     40 
 Exploration          7      18      24 (2)     1        -         -     50 
 Finance              4       4          -      -        1        88     97 
 Net Gain from                                                          
  Dispositions        -       -          - (80)(3)       -         -    (80)
                ------------------------------------------------------------
Income (Loss)                                                               
 from                                                                       
 Continuing                                                                 
 Operations                                                                 
 before Income                                                              
 Taxes              461     (40)        85    39        65      (136)   474 
Less: Provision                                                             
 for (Recovery                                                              
 of) Income                                                                 
 Taxes              230     (10)        22    10        16       (32)   236 
                ------------------------------------------------------------
Income (Loss)                                                               
 from                                                                       
 Continuing                                                                 
 Operations         231     (30)        63    29        49      (104)   238 
Add: Net Income                                                             
 (Loss) from                                                                
 Discontinued                                                               
 Operations                                                                 
 (Note 14)            -      15          -     -         -        (8)     7 
                ------------------------------------------------------------
Net Income                                                                  
 (Loss)             231     (15)        63    29        49      (112)   245 
                ------------------------------------------------------------
                ------------------------------------------------------------

Capital                                                                     
 Expenditures       150     380        170    45        25        70    840 
                ------------------------------------------------------------
                ------------------------------------------------------------
(1) Includes results of conventional crude oil and natural gas operations   
    in Yemen and Colombia.                                                  
(2) Includes exploration activities primarily in Yemen, Nigeria, Norway and 
    Colombia.                                                               
(3) Gain on disposition of non-core lands in the Athabasca region.          


Segmented net income for the six months ended June 30, 2011

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

Net Sales          1,726     267        414   303       370        25  3,105
Marketing and                                                               
 Other Income         17      32          7     -         1        84    141
                 -----------------------------------------------------------
                   1,743     299        421   303       371       109  3,246

Less: Expenses                                                              
 Operating           159      76         70   234       150        15    704
 Depreciation,                                                              
  Depletion,                                                                
  Amortization                                                              
  and                                                                       
  Impairment         315     221         48    65        30        26    705
 Transportation                                                             
  and Other            -      15         16    69        12        67    179
  General and                                                               
  Administrative     (10)     52         23    13         -       103    181
 Exploration          17     100     100 (2)    2         -         -    219
 Finance              10       8          1     1         3       111    134
 Net Loss on                                                                
  Debt                                                                      
  Redemption           -       -          -     -         -        91     91
                 -----------------------------------------------------------
Income (Loss)                                                               
 from Continuing                                                            
 Operations                                                                 
 before Income                                                              
 Taxes             1,252    (173)       163   (81)      176      (304) 1,033
Less: Provision                                                             
 for (Recovery                                                              
of) Income Taxes   1,012     (46)         4   (20)       44      (113)   881
                 -----------------------------------------------------------
Income (Loss)                                                               
 from Continuing                                                            
 Operations          240    (127)       159   (61)      132      (191)   152
Add: Net Income                                                             
 from                                                                       
 Discontinued                                                               
 Operations                                                                 
 (Note 14)             -       -          -     -         -       302    302
                 -----------------------------------------------------------
Net Income                                                                  
 (Loss)              240    (127)       159   (61)      132       111    454
                 -----------------------------------------------------------
                 -----------------------------------------------------------

Capital                                                                     
 Expenditures        178     242        317   220        46        26  1,029
                 -----------------------------------------------------------
                 -----------------------------------------------------------
(1) Includes results of conventional crude oil and natural gas operations in
    Yemen and Colombia.                                                     
(2) Includes exploration activities primarily in Yemen, Nigeria, Norway,    
    Colombia and Poland.                                                    


Segmented net income for the six months ended June 30, 2010

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

Net Sales         1,490     294        368    193      286        21  2,652 
Marketing and                                                               
 Other Income         9       1          8      -        2       167    187 
                ------------------------------------------------------------
                  1,499     295        376    193      288       188  2,839 

Less: Expenses                                                              
 Operating          154      82         80    180      132        16    644 
 Depreciation,                                                              
  Depletion,                                                                
  Amortization                                                              
  and                                                                       
  Impairment        353     190         62     40       27        29    701 
 Transportation                                                             
  and Other           4      10          6     83       11       220    334 
  General and                                                               
  Administrative     13      30          8      4        -        94    149 
 Exploration         31      41      70 (2)     1        -         -    143 
 Finance              8       8          -      1        2       167    186 
 Net Gain from                                                          
  Dispositions        -       -          - (80)(3)       -         -    (80)
                ------------------------------------------------------------
Income (Loss)                                                               
 from Continuing                                                            
 Operations                                                                 
 before Income                                                              
 Taxes              936     (66)       150   (36)      116      (338)   762 
Less: Provision                                                             
 for (Recovery                                                              
 of) Income Taxes   468     (17)        21    (9)       29       (79)   413 
                ------------------------------------------------------------
Income (Loss)                                                               
 from Continuing                                                            
 Operations         468     (49)       129   (27)       87      (259)   349 
Add: Net Income                                                             
 from                                                                       
 Discontinued                                                               
 Operations                                                                 
 (Note 14)            -      36          -     -         -         1     37 
                ------------------------------------------------------------
Net Income                                                                  
 (Loss)             468     (13)       129   (27)       87      (258)   386 
                ------------------------------------------------------------
                ------------------------------------------------------------

Capital                                                                     
 Expenditures       277     527        313   109        49       135  1,410 
                ------------------------------------------------------------
                ------------------------------------------------------------
(1) Includes results of conventional crude oil and natural gas operations   
    in Yemen and Colombia.                                                  
(2) Includes exploration activities primarily in Yemen, Nigeria, Norway and 
    Colombia.                                                               
(3) Gain on disposition of non-core lands in the Athabasca region.          


Segmented assets as at June 30, 2011

                                                           Corporate        
                             Conventional        Oil Sands and Other   Total
----------------------------------------------------------------------------

               United   North     Other       In                            
              Kingdom America Countries     Situ  Syncrude                  
              --------------------------------------------                 

Total Assets    4,423   3,199     1,822    5,982     1,272  2,362 (1) 19,060
              --------------------------------------------------------------
              --------------------------------------------------------------

Property, Plant                                                            
 and Equipment                                                             
 Cost           6,332   6,484     3,840    5,975     1,563       611  24,805
 Less:                                                                     
  Accumulated                                                               
  DD&A          3,277   3,670     2,348      145       387       350  10,177
              --------------------------------------------------------------
Net Book Value  3,055 2,814(2)  1,492(3) 5,830(4)    1,176       261  14,628
               -------------------------------------------------------------
               -------------------------------------------------------------

Goodwill          269       -         -        -         -         7     276
               -------------------------------------------------------------
               -------------------------------------------------------------
(1) Includes cash of $583 million, and Energy Marketing accounts receivable 
    and inventory of $1,292 million.                                        
(2) Includes capitalized costs of $1,070 million associated with our        
    Canadian shale gas operations.                                          
(3) Includes $1,398 million related to our Usan development, offshore       
    Nigeria.                                                                
(4) Includes net book value of $4,962 million for Long Lake Phase 1 and $868
    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       In                            
              Kingdom America Countries     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 $1,381 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       In                            
              Kingdom America Countries     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 $1,958 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) 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. 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, which is included in accumulated other comprehensive income, 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 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   June 30   December 31
(Cdn$ millions)                    Note        2010      2010          2010
----------------------------------------------------------------------------
Shareholders' Equity under                                                  
 Canadian GAAP                                7,646     8,080         8,791
Differences increasing                                                      
 (decreasing) reported                                                      
 shareholders' equity:                                                      
 Borrowing Costs                     (i)       (841)     (814)         (778)
 Asset Retirement Obligations       (ii)       (228)     (252)         (241)
 Employee Benefits                 (iii)       (104)     (104)         (150)
 Stock-Based Compensation           (iv)        (96)      (81)          (92)
 Property, Plant & Equipment         (v)       (124)     (112)          (90)
 Foreign Exchange                   (vi)        (11)       (9)             -
 Long-term Debt                    (vii)         (9)      (26)          (28)
 Income Taxes                     (viii)        554       473           429
 Other                                            -         8           (27)
                                           ---------------------------------
Shareholders' Equity under IFRS               6,787     7,163         7,814
                                           ---------------------------------
                                           ---------------------------------

(i) Borrowing Costs

We applied the IFRS 1 exemption to prospectively capitalize borrowing costs 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 it's 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 were required on transition to IFRS.

Major Maintenance

Under 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.

(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 Months   Six Months         Twelve
                                          Ended        Ended   Months Ended
                                        June 30      June 30    December 31
(Cdn$ millions)               Note         2010         2010           2010
----------------------------------------------------------------------------
Net Income under Canadian                                                   
 GAAP                                       255          440          1,197
Differences increasing                                                      
 (decreasing)                                                               
 reported net income:                                                       
  Borrowing Costs               (i)          16           27             63
  Asset Retirement                                                          
   Obligations                 (ii)          (7)         (24)           (13)
  Stock-Based Compensation    (iii)          23           14              3
  Property, Plant & Equipment  (iv)           4           12             34
  Long-term Debt                (v)         (13)         (17)           (19)
  Income Taxes                 (vi)         (54)         (81)          (136)
  Other                                      21           15             (2)
                                    ----------------------------------------
  Total Differences in Net                                                  
   Income                                   (10)         (54)           (70)
                                    ----------------------------------------
Net Income under IFRS                       245          386          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 $59 million for the three and six months ended June 30, 2010, respectively, and lower by $117 million for the twelve months ended December 31, 2010.

Other

All other adjustments to IFRS net income were tax effected which increased deferred tax expense by $25 million and $22 million for the three and six months ended June 30, 2010, respectively, and $19 million for the twelve months ended December 31, 2010.

Reconciliation of Comprehensive Income


                                   Three Months   Six Months         Twelve
                                          Ended        Ended   Months Ended
                                        June 30      June 30    December 31
(Cdn$ millions)               Note         2010         2010           2010
----------------------------------------------------------------------------
Comprehensive income under                                                  
 Canadian GAAP                              267          441          1,168
Differences increasing                                                      
 (decreasing) reported                                                      
 comprehensive income, net of                                               
 income taxes:                                                              
  Differences in net income                 (10)         (54)           (70)
  Foreign Currency                                                          
   Translation                  (i)          (4)          (6)            (8)
  Employee Benefits            (ii)           -            -            (35)
                                    ----------------------------------------
Comprehensive Income under                                                  
 IFRS                                       253          381          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, 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

    Kim Woima, CA
    Manager, Investor Relations
    (403) 699-5821

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

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