Nexen Inc.
TSX : NXY
NYSE : NXY

Nexen Inc.

February 16, 2011 21:33 ET

Nexen Announces Strong 2010 Results and Recaps Successful Year

CALGARY, ALBERTA--(Marketwire - Feb. 16, 2011) - Nexen Inc. released its 2010 financial results today and highlighted its significant progress in delivering results and building value. 2010 highlights include:

Corporate-wide

- Increased annual after royalties production by 7% (after adjusting for the heavy oil sale)

- Achieved mid-point of production guidance as solid production across the portfolio more than compensated for the sale of our heavy oil properties and disruptions caused by maintenance at third-party facilities

- Added 101 million boe of proved reserves from its $2.5 billion oil and gas capital investment program, resulting in a competitive F&D cost and replacing 114% of its production

- Non-core asset disposition program including early 2011 Canexus sale generated $1.7 billion of cash proceeds and net debt reduction of $2.1 billion, capturing significant value and enhancing our financial capacity

Conventional operations

- Progressed Usan field toward first production next year

- Advanced the Golden Eagle area project by capturing land adjacent to the field and filing a Field Development Plan with the regulatory authority

- Made a significant discovery at Appomattox in the Gulf of Mexico, and several other discoveries around our existing infrastructure in the North Sea

Northeast BC shale gas

- Delivered drilling, fracing and completions program at industry-leading pace with a 100% success rate

- Initial production from the eight-well program is meeting expectations and is giving us the desired information on well design

- Acquired additional acreage in the Cordova and Liard basins, making us one of the largest acreage-holders in this highly attractive area

Oil sands

- Although we doubled production during 2010, the ramp-up at Long Lake was below expectations; we commenced actions to: fill the upgrader through accelerated pad drilling; increase steam capacity; enhance independence between the SAGD and upgrader operations; and increase water-disposal capacity

- Developed a bitumen-leading strategy at Kinosis to simplify the development while retaining the option to capture the benefits of upgrading and our integrated process

Focus for 2011

- Delivering new production of 70,000 boe/d over the next 12 to 24 months from Usan start-up, shale gas growth, UK tie-backs and Long Lake ramp-up

- Sanctioning Golden Eagle development in the first half of 2011

- Obtaining a contract extension in Yemen

- Returning to drilling in the Gulf of Mexico to further appraise and explore our Appomattox discovery and our other attractive exploration prospects

- Progressing plans to drill an 18-well shale gas program at Horn River

"I am pleased with the success we've had in virtually all areas of our operations during 2010 as this sets us up for robust growth in the coming years," commented Marvin Romanow, President and Chief Executive Officer. "While I'm disappointed with the Long Lake ramp-up, I'm satisfied that we are taking the right steps to get the upgrader full so we can demonstrate the significant value of our oil sands strategy and vast bitumen resource."

Our fourth quarter and 2010 financial highlights include:

- Cash flow from operations of $549 million ($1.04/share); annual cash flow of $2.1 billion ($4.06/share)

- Net income of $220 million ($0.42/share); annual net income of $1.2 billion ($2.28/share)

- Production after royalties of 227,000 boe/d (246,000 boe/d before royalties) representing a 7% increase over third quarter 2010; decline from fourth quarter 2009 due to heavy oil sale and downtime related to the start-up of Buzzard fourth platform in 2010

- Annual production after royalties of 220,000 boe/d (246,000 boe/d before royalties) representing a 7% increase over 2009 (excluding dispositions, after royalties) and well within initial production guidance

- Reduced our net debt by $1.5 billion, over 25%, with an additional $0.5 billion reduction in early February from the Canexus disposition



(Cdn$ millions) Q4 2010 Q3 2010 Q4 2009 2010 2009
----------------------------------------------------------------------------
Production (mboe/d)
Before Royalties 246 239 265 246 243
After Royalties 227 213 235 220 213
Cash Flow from Operations(1) 549 485 836 2,130 2,215

Per Common Share
($/share)(1) 1.04 0.92 1.60 4.06 4.25
Net Income 220 537 259 1,197 536

Per Common Share ($/share) 0.42 1.02 0.50 2.28 1.03

Capital Investment(2,3) 677 623 645 2,702 3,578

Net Debt(4) 4,074 4,468 5,551 4,074 5,551
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1. For reconciliation of this non-GAAP measure, see Cash Flow from
Operations on pg. 12.
2. Includes geological and geophysical expenditures.
3. 2009 includes $755 million for the acquisition of an additional 15%
interest in Long Lake in the first quarter.
4. Net debt is defined as long-term debt and short-term borrowings less cash
and cash equivalents.


Financial Results

Fourth quarter cash flow from operations increased 13% to $549 million ($1.04/share) over the third quarter 2010. This reflects increased production and rising oil prices driven by the strengthening global economic recovery. In 2010, WTI and Brent traded at similar levels. Since late December, international oil prices have risen faster than WTI with Brent currently trading at a premium of $18/bbl (average January premium $7/bbl) as WTI is being held back by high regional inventories. With 80% of our oil production receiving international prices, we are seeing the strong benefits of this in 2011 as our cash flow sensitivity is $270 million annually per $10 change in Brent after tax.

Fourth quarter cash flow from operations was lower than the same period in 2009, primarily as a result of lower production, lower marketing contribution and adjustments to the annual cash tax provision in the U.K. Production decreases reflect downtime related to the commissioning of the fourth platform at Buzzard, natural declines in Yemen and the sale of our Canadian heavy oil properties. The higher 2009 marketing contribution reflected the increased value of our natural gas inventories with rising gas prices in late 2009. This business was sold in the third quarter of 2010.

Cash flow from operations for the year was $2.1 billion ($4.06/share) and net income was $1.2 billion ($2.28/share). The doubling of net income in 2010 reflects the net gains from our disposition program ($566 million, after tax.)



Quarterly Production

Quarterly Production before Quarterly Production after
Royalties Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) Q4 2010 Q3 2010 Q4 2009 Q4 2010 Q3 2010 Q4 2009
----------------------------------------------------------------------------
North Sea 115 111 124 115 111 124
Yemen 40 41 45 23 23 26
United States 27 27 24 28 24 21
Canada - Oil & Gas 21 22 37 20 19 31
Canada - Syncrude 23 19 24 21 18 22
Canada - Bitumen 18 17 9 18 16 9
Other Countries 2 2 2 2 2 2
-------------------------------------------------------
Total 246 239 265 227 213 235
-------------------------------------------------------


Fourth quarter after royalties production increased 7% over the third quarter. Higher production from Syncrude following the completion of the third quarter turnaround and improved uptime at Scott/Telford following maintenance at a third-party transportation facility more than offset Buzzard downtime. Commissioning of the fourth platform at Buzzard is proceeding well and we are near to having it fully integrated with the existing production systems. With the increased H2S handling capability, we expect to be able to continue to maintain our high netback Buzzard production at plateau for many more years. Fourth quarter production also benefited from shale gas volumes, following the startup of our eight-well pad.

Fourth quarter production was lower than the same period in 2009 due to downtime related to the commissioning of the fourth platform at Buzzard in 2010 and sale of our heavy oil properties, partially offset by increased production at Long Lake.



Annual Production

Annual Production Annual Production
before Royalties after Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) 2010 2009 2010 2009
----------------------------------------------------------------------------
North Sea 111 102 111 102
Yemen 41 50 23 30
United States 26 21 24 19
Canada - Oil & Gas 29 38 25 32
Canada - Syncrude 21 20 20 19
Canada - Bitumen 16 8 15 8
Other Countries 2 4 2 3
---------------------------------------
Total 246 243 220 213
---------------------------------------


Annual production increased over 2009 as a result of higher production at Long Lake, achieving full capacity at Ettrick, shale gas growth and good performance across our US fields. Production gains were offset by the mid-year sale of 15,000 boe/d of heavy oil volumes and natural declines in Yemen. During the past five years, production after royalties has grown at a compound annual rate of 6% excluding our heavy oil disposition.

2010 Capital Investment and Reserves

We had a successful 2010 capital investment program. We invested $2.5 billion in our oil and gas activities and added 101 million boe of proved reserves. These additions replaced 114% of our production and the conventional reserves replacement ratio of 105% is our best in four years. A summary of our 2010 capital investment program and proved reserve additions are shown in the table below. Detailed tables can be found on pages 10 and 11.



2010 Annual Results
----------------------------------------------
Capital Proved Reserve
Investment Production Additions
(Cdn$ millions) (mmboe) (mmboe)
----------------------------------------------------------------------------
Conventional Exploration &
Production 1,688 76 80
Unconventional - Oil Sands 328 12 8
Unconventional - Shale Gas 476(1) 1 13
----------------------------------------------
Total Oil and Gas 2,492 89 101
----------------------------------------------
1. A little less than half relates to wells and facilities; the remainder
relates to our increased land holdings in northeast BC.


The reserve additions relate primarily to the following areas:

- Filed a Field Development Plan for the Golden Eagle area (34 million boe)

- Successful drilling and good production performance at Buzzard (22 million boe)

- Successful drilling program and continued cost reductions in our Horn River shale gas play (13 million boe)

- Syncrude (8 million boe)

- Successful drilling and good production performance at Telford (6 million boe)

- Progress on development plans for our Rochelle and Blackbird discoveries (6 million boe)

We have 987 million boe of proved reserves and 2,120 million boe of proved and probable reserves, representing reserve life indices of 11 years on a proved basis and 24 years on a proved and probable basis. These reserves exclude our discoveries at Appomattox, Vicksburg, Owowo and Knotty Head. They also exclude the incremental reserves we would recognize if we are successful in obtaining an extension on our Yemen contract. As previously disclosed, we also have a large inventory of attractive exploration prospects, 3 to 6 billion barrels of contingent resource in our oil sands, 4 to 15 tcf of contingent resource in the Horn River and Cordova basins and 5 to 23 tcf of prospective resource in the Liard basin. This provides us with a significant resource base for future growth.

As we move into 2011, our capital spending priorities centre around the 70,000 boe/d of new production we anticipate bringing on stream over the next 12 to 24 months. This growth will come from the start-up of our Usan project, further development of our Horn River shale gas acreage, ramp-up of Long Lake, and numerous tieback opportunities in the North Sea.

"Our capital investment program over the past several years has delivered significant value additions," commented Romanow. "We now have a strong pipeline of projects that will fuel our future growth. This includes our Usan project that comes on stream next year; several developments, including Golden Eagle, set to get underway; various discoveries to appraise; several high quality exploration prospects to drill; Horn River shale gas to continue to pursue; and our second oil sands project at Kinosis to advance towards sanctioning."

2010 Capital Program Review and Project Updates

Conventional Oil & Gas

North Sea

We continue to have significant success in the North Sea. Since entering the basin in late 2004, we have gone from 100 million boe of proved reserves to 255 million boe of produced and remaining proved reserves. Buzzard is one of the drivers to this growth. We have continued to find more oil than originally expected, allowing us to recognize increased reserves, identify further development drilling locations and extend the production plateau for several more years.

In 2010, we invested $733 million in the North Sea, including $305 million on exploration and appraisal activities. We drilled successful wells at Polecat and West Rochelle, and a successful follow up to our Blackbird discovery.

At Buzzard, we spent $80 million to install the topsides and commission the fourth platform. This will enable us to produce our wells with higher H2S concentrations. We added 22 million boe of proved reserves here, primarily attributable to successful drilling and production performance which resulted in increases in both reservoir size and recovery factor.

Also during the year, we made significant progress in advancing our discoveries in the Golden Eagle area. We expanded the acreage position to follow the trend to the north. In late 2010, we filed a Field Development Plan with the regulatory authority. Our discoveries are large enough to require standalone facilities and are economic with oil prices significantly lower than current prices. Facility design size is expected to be 70,000 boe/d (gross). Following equalization of the blocks, we will have a 36.5% working interest and will operate the project. We expect to sanction the development later this year. To date, we have booked 34 million boe of proved reserves and an additional 16 million boe of probable reserves for this area.

We are also having success with our drilling program centered around our infrastructure. At Scott/Telford, we invested $150 million and added 6 million boe of proved reserves from development drilling. We anticipate further upside in this area with opportunities for quick tie-backs. We also added 5 million boe of proved reserves for Rochelle, a tie-back development to our Scott platform.

During the quarter, the UK Government announced that, subject to completion of the award process, we were the successful applicant for 10 licences covering 18 blocks in the UK North Sea 26th Offshore Oil and Gas Licensing Round. Most of these blocks are near our existing acreage and infrastructure, and are expected to enhance our ongoing exploration program where we are having a great deal of success.

"Since the acquisition of our UK assets, we have had significant success and we're not done yet," commented Romanow. "This acquisition and follow-up investments have made this one of the most successful investments by industry in the North Sea in the last decade."

Yemen

In 2010, we invested $52 million and added 6 million boe of proved reserves. We continue to focus on maximizing the value of these assets over the remaining life of the contracts. We are currently in discussions with the Yemen government on a contract extension.

Offshore West Africa

We made excellent progress on the development of the Usan field, offshore West Africa, and remain on track to achieve first oil next year. The development includes a FPSO with the ability to process 180,000 bbls/d (36,000 bbls/d net to us) and store up to two million barrels of oil. FPSO fabrication is nearing completion and the vessel will soon be towed to the field installation. The project is approximately 85% complete and is expected to generate $800 to $850 million of net annual cash flow at $90/bbl Brent. We have a 20% interest in exploration and development on this block along with partners ExxonMobil, Chevron and operator Total E&P Nigeria Limited.

United States

In the Gulf of Mexico, our capital program is focused on the deepwater and in 2010, we invested $178 million on exploration and appraisal, and $83 million on our deepwater and shelf producing assets.

Our exploration program resulted in a significant discovery at Appomattox, located in Mississippi Canyon blocks 391 and 392. An exploration well and two appraisal sidetracks have confirmed this to be an oil discovery with excellent reservoir quality. We estimate the recoverable contingent resource for this discovery exceeds 250 million boe (gross) with upside potential. We plan to further appraise this discovery once drilling permits are received.

Elsewhere in the deepwater, we drilled an appraisal well at Knotty Head and the joint venture participants have signed a letter of intent to unitize the field with Hess' Pony discovery. We are working on having an integrated project team in place later this year to work on a joint development plan to move the Knotty Head and Pony discoveries towards sanctioning. As we advance our development concept, we expect to book reserves here.

We are waiting on drilling permits from the Bureau of Ocean Energy Management to drill two exciting exploration prospects, Kakuna and Angel Fire, in the area near our Knotty Head discovery. We have negotiated a reduced standby rate on one of our drilling rigs and have declared force majeure on the other. The estimated maximum 2011 cost to Nexen for these costs is $65 million assuming we cannot commence drilling until the end of the second quarter. We are actively pursuing ways to reduce this cost.

Early in 2010, we initiated a process to market a portion of our attractive Gulf of Mexico exploration portfolio including the farm-down of higher working interest prospects. With the Macondo incident, we focused on farm-outs on a well-by-well basis of our near-term drilling prospects. Negotiations with several parties are underway and are expected to be completed before the wells commence drilling.

Oil Sands

We invested $228 million on the Long Lake project and other joint venture lands. The focus of the capital has been on the electric submersible pump (ESP) installation program, activities to increase production and reliability at Long Lake, advancing Kinosis and on our other future oil sands developments.

Ongoing initiatives to support the ramp-up at Long Lake include accelerated drilling of pads 12 and 13, which will be ready for steaming next year; the addition of two once-through steam generators that will add 10 to 15% to our existing steam capacity which will be ready for service late next year; and creating greater independence between the SAGD operations and upgrader by increasing gas inlet capacity and adding a diluent recovery unit. These investments represent $400 to $500 million of capital (net to Nexen) over the next few years, of which approximately half relates to the additional pads and represents an acceleration of capital spending.

We are also advancing engineering activities on Kinosis to develop two 40,000 bbl/d SAGD projects. This development plan provides us with the option to add an upgrader when SAGD projects are ramped up to capacity.

We are monitoring our partner's financial status and assessing their capabilities to continue funding their share of the capital spending. As the potential for this type of situation was contemplated at the time we entered into the joint venture we believe our interests are well protected.

Shale Gas

We made considerable progress in advancing our northeast BC shale gas play. We successfully drilled and brought on-stream our eight-well pad, and commenced drilling another nine-well pad late in the year. We more than doubled our acreage position to 300,000 acres (100% working interest), making us one of the largest leaseholders in this attractive play.

We invested in the drilling, completion and tie-in of the eight-well pad and expansion of in-field facilities. The drilling campaign was completed in under 25 days per well. Compared to our previous program, these wells were drilled in 35% fewer days and were 80% longer. These wells were completed with 18 fracs per well at an industry-leading pace of 3.5 fracs per day with a 100% success rate. We recently started producing these wells and are experiencing initial production rates of 8 to 15 mmcf/d per well. With the success we're seeing on our activities, we expect to be able to make a 10% return with gas prices as low as US$4.00 to US$4.50/mcf NYMEX.

We recently commenced drilling our nine-well pad and expect fracing and completion activities this summer. We are also progressing plans to drill an 18-well pad in the second half of 2011. First shale gas production from the nine-well pad is expected in the fourth quarter of 2011, while production from the 18-well pad would be in late 2012.

Our shale gas capital includes the purchase of almost 175,000 acres of land in the Cordova and Liard basins. This brings our total acreage in northeast BC to over 300,000 acres (100% working interest).

"We see a long-term opportunity for value-adding growth from our shale gas position," said Romanow. "With continued success and improving efficiencies, we are becoming increasingly excited by the potential this area offers. In addition to being a top quartile North American gas play, this is one of the few places in Canada and the United States where LNG export is a genuine opportunity with oil-indexed pricing."

We also recently commenced a process to seek a joint venture partner for various portions of our northeast BC shale gas acreage. This will allow us to monetize a portion of the value that we have created from the success we have had capturing high quality acreage, understanding the reservoir and reducing our costs. We have engaged Bank of America Merrill Lynch as our advisors on this process.

Divestment Update

In early 2011, Nexen completed the sale of its 62.7% interest in Canexus Income Fund. The sale proceeds amounted to $458 million and were received in early February.

Our successful disposition program has generated $1.7 billion in cash proceeds and net debt reduction of $2.1 billion including the elimination of Canexus' debt from our balance sheet.

"Our divestment program exceeded our expectations of generating $1 billion representing significant value capture," commented Romanow. "The program also greatly enhanced our financial capacity by reducing our net debt."

Review of Financial Position

Following our non-core asset dispositions, we have reduced our net debt by 31% from its peak in 2009 after the acquisition of an additional 15% in our Long Lake project. Our net debt to cash flow, a measure of our leverage, has decreased to 1.7 times 2010 cash flows at US$80 WTI. We now have US$1.5 billion of cash following the sale of Canexus. We also have further liquidity support with US$3 billion of available committed credit facilities.

"In December, Moody's put our credit rating under review over concerns on the ramp-up of Long Lake and our total debt outstanding before considering the cash we have on hand. We are evaluating our choices to determine the actions we could take to maintain our investment grade rating from them while ensuring we retain our strong financial capacity to support our growth initiatives," said Romanow.

Quarterly Dividend

The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable April 1, 2011, to shareholders of record on March 10, 2011. Shareholders are advised that the dividend is an eligible dividend for Canadian Income Tax purposes.

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

Information on our previously announced contingent Appomattox and Canadian unconventional (oil sands and shale gas) resource were provided in our press releases dated September 27, 2010, and November 15, 2010, respectively. Information with respect to forward-looking statements and cautionary notes is set out below.

Conference Call

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

Date: February 17, 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:

416-695-6616 (Toronto)

800-355-4959 (North American toll-free)

800-6578-9898 (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 5120438 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 Items 1A and 7A in our 2009 Annual Report on Form 10-K and Part II, Item 1A in our second quarter 2010 Quarterly Report on Form 10-Q for further discussion of the risk factors.

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 their 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 made on September 30, 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.
2010 Reserve Continuity Table

----------------------------------------------------------------------------
Other
North Sea Yemen Intl US
---------------------------------------------------------
Mmboe Oil Gas Oil Oil Oil Gas
----------------------------------------------------------------------------
PROVED RESERVES(1)
Dec 2009 169 3 23 43 22 28

Extensions &
Discoveries 35 5 - 1 - -
Acquisitions 1 - - - - -
Divestments - - - - - -
Revisions 26 5 6 (1) 1 -
---------------------------------------------------------
Net Additions 62 10 6 - 1 -
---------------------------------------------------------

Production (38) (2) (16) (1) (4) (6)
---------------------------------------------------------

---------------------------------------------------------
Dec 2010 193 11 13 42 19 22
---------------------------------------------------------

PROBABLE RESERVES(1)
Dec 2009 159 10 4 45 7 17

Extensions &
Discoveries 3 3 - - - -
Acquisitions 4 - - - - -
Divestments - - - - - -
Revisions (1) 2 1 (5) 1 (2)
---------------------------------------------------------
Net Additions 6 5 1 (5) 1 (2)
---------------------------------------------------------
Conversions (57) (5) (3) (1) (1) (2)
---------------------------------------------------------

---------------------------------------------------------
Dec 2010 108 10 2 39 7 13
---------------------------------------------------------

PROVED + PROBABLE
RESERVES(1)
Dec 2009 328 13 27 88 29 45

Extensions & 38 8 - 1 - -
Discoveries

Acquisitions 5 - - - - -
Divestments - - - - - -
Revisions 25 7 7 (6) 2 (2)
---------------------------------------------------------

Net Additions 68 15 7 (5) 2 (2)
---------------------------------------------------------
Conversions (57) (5) (3) (1) (1) (2)

Production (38) (2) (16) (1) (4) (6)
---------------------------------------------------------

---------------------------------------------------------
Dec 2010 301 21 15 81 26 35
---------------------------------------------------------


----------------------------------------------------------------------------
Canada
---------------------------------------------------------
Insitu
Other Oilsands Syncrude Total
---------------------------------------------------------
Mmboe Oil Gas Synthetic Synthetic Oil and Gas
----------------------------------------------------------------------------
PROVED RESERVES (1)
Dec 2009 37 44 318 324 1,011

Extensions & - 16 3 8 68
Discoveries
Acquisitions - - - - 1
Divestments (34) (2) - - (36)
Revisions - (2) (3) - 32
---------------------------------------------------------
Net Additions (34) 12 - 8 65
---------------------------------------------------------

Production (3) (7) (4) (8) (89)
---------------------------------------------------------

---------------------------------------------------------
Dec 2010 - 49 314 324 987
---------------------------------------------------------

PROBABLE RESERVES(1)
Dec 2009 27 14 888 46 1,217

Extensions& - 17 - 8 31
Discoveries
Acquisitions - - - - 4
Divestments (27) (2) - - (29)
Revisions - (3) (3) - (10)
---------------------------------------------------------
Net Additions (27) 12 (3) 8 (4)
---------------------------------------------------------
Conversions - - (3) (8) (80)
---------------------------------------------------------

---------------------------------------------------------
Dec 2010 - 26 882 46 1,133
---------------------------------------------------------

PROVED + PROBABLE
RESERVES(1)
Dec 2009 64 58 1,206 370 2,228

Extensions & - 33 3 16 99
Discoveries

Acquisitions - - - - 5
Divestments (61) (4) - - (65)
Revisions - (5) (6) - 22
---------------------------------------------------------
Net Additions (61) 24 (3) 16 61
---------------------------------------------------------
Conversions - - (3) (8) (80)

Production (3) (7) (4) (8) (89)
---------------------------------------------------------

---------------------------------------------------------
Dec 2010 - 75 1,196 370 2,120
---------------------------------------------------------
1. We internally evaluate all of our reserves and have at least 80% of our
proved and probable reserves assessed by independent qualified
consultants each year; 99% of which were assessed this year. Our reserves
are also reviewed and approved by our Board of Directors. Reserves
represent our working interest before royalties using SEC rules which are
based on average 2010 prices held constant. Gas is converted to
equivalent oil at a 6:1 ratio.


Nexen Inc.
2010 Capital Investment Table(1)

(Cdn$ millions)
----------------------------------------------------------------------------
North Other
Sea(2) Yemen International(3) US
----------------------------------------------------------------------------
Core Asset Development 315 52 2 83
Major Development 37 - 446 -
Early-stage Development 13 - 22 -
Exploration 305 - 14 178
Proved Property
Acquisition 79 - - -
---------------------------------------------------
Oil and Gas Investment 749 52 484 261
Long Lake Upgrader
Capitalized Interest 17 - 47 -
---------------------------------------------------
Total Oil and Gas
Capital 766 52 531 261
Marketing, Corporate,
Chemicals and Other - - - -
---------------------------------------------------
Total Capital Investment 766 52 531 261
----------------------------------------------------------------------------
% of Total 28% 2% 20% 10%
----------------------------------------------------------------------------


(Cdn$ millions)
----------------------------------------------------------------------------
Insitu
Canada Oil Sands Syncrude Total
----------------------------------------------------------------------------
Core Asset Development 18 135 100 705
Major Development 190 - - 673
Early-stage Development - 35 - 70
Exploration 346 1 - 844
Proved Property
Acquisition - - - 79
---------------------------------------------------
Oil and Gas Investment 554 171 100 2,371
Long Lake Upgrader 41 41
Capitalized Interest - 16 - 80
---------------------------------------------------
Total Oil and Gas
Capital 554 228 100 2,492
Marketing, Corporate,
Chemicals and Other 210 - - 210
---------------------------------------------------
Total Capital
Investment 764 228 100 2,702
----------------------------------------------------------------------------
% of Total 28% 8% 4% 100%
----------------------------------------------------------------------------

1. Includes geological and geophysical expenditures of $100 million.
2. Includes UK and Norway.
3. Includes Nigeria and Colombia.


Nexen Inc.
Financial Highlights

Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Net Sales (1) 1,620 1,550 6,005 4,895
Cash Flow from Operations (1) 549 836 2,130 2,215
Per Common Share ($/share) 1.04 1.60 4.06 4.25
Net Income (1) 220 259 1,197 536
Per Common Share ($/share) 0.42 0.50 2.28 1.03
Capital Investment Including
Acquisitions (2) 677 645 2,702 3,578
Net Debt (3) 4,074 5,551 4,074 5,551
Common Shares Outstanding (millions
of shares) 525.7 522.9 525.7 522.9
----------------------------------------

(1) Includes discontinued operations as discussed in Note 17 to our
Unaudited 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 Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Oil & Gas
United Kingdom 773 777 2,769 2,159
Yemen (2) 77 101 355 345
Syncrude 87 94 279 192
United States 69 53 262 140
Canada (3) (10) 45 (28) 130
Other Countries 2 1 15 31
Marketing (1) 109 (45) 256
----------------------------------------
997 1,180 3,607 3,253
Chemicals (3) 15 18 61 102
----------------------------------------
1,012 1,198 3,668 3,355
Interest and Other Corporate Items (165) (143) (572) (512)
Income Taxes (4) (298) (219) (966) (628)
----------------------------------------
Cash Flow from Operations (1) 549 836 2,130 2,215
----------------------------------------
----------------------------------------

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


Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash Flow from Operating Activities 373 527 2,349 1,886
Changes in Non-Cash Working Capital 72 218 (338) 25
Other 112 84 159 318
Impact of Annual Crude Oil Put
Options (8) 7 (40) (14)
----------------------------------------
Cash Flow from Operations 549 836 2,130 2,215
----------------------------------------
----------------------------------------

Weighted-average Number of Common
Shares Outstanding
(millions of shares) 525.6 522.7 524.7 521.4
----------------------------------------
Cash Flow from Operations Per Common
Share ($/share) 1.04 1.60 4.06 4.25
----------------------------------------
----------------------------------------

(2) After in-country cash taxes of $41 million for the three months ended
December 31, 2010 (2009 - $43 million) and $166 million for the year
ended December 31, 2010 (2009 - $148 million).
(3) Includes discontinued operations as discussed in Note 17 to our
Unaudited Consolidated Financial Statements.
(4) Excludes in-country cash taxes in Yemen.


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

Three Months Twelve Months
Ended December 31 Ended December 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 109.4 117.0 104.9 98.0
Yemen 40.1 45.1 41.3 49.9
Syncrude 22.8 23.7 21.2 20.2
Long Lake Bitumen 18.3 8.8 15.9 7.9
United States 10.1 10.0 9.9 10.5
Canada (2) - 13.7 7.5 14.6
Other Countries 1.9 2.4 2.1 3.5
----------------------------------------
202.6 220.7 202.8 204.6
----------------------------------------
Natural Gas (mmcf/d)
United Kingdom 33 44 35 24
United States 99 84 99 65
Canada (2) 129 140 126 139
----------------------------------------
261 268 260 228
----------------------------------------

Total Production (mboe/d) 246 265 246 243
----------------------------------------
----------------------------------------


Production Volumes (after royalties)

Three Months Twelve Months
Ended December 31 Ended December 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 109.4 117.0 104.8 98.0
Yemen 23.6 26.3 23.1 29.8
Syncrude 21.0 21.4 19.6 18.6
Long Lake Bitumen 17.5 8.8 15.1 7.9
United States 9.3 9.1 9.0 9.5
Canada (2) - 10.7 5.8 11.4
Other Countries 1.8 2.2 1.9 3.2
----------------------------------------
182.6 195.5 179.3 178.4
----------------------------------------
Natural Gas (mmcf/d)
United Kingdom 33 44 35 24
United States 116 73 94 57
Canada (2) 121 122 116 128
----------------------------------------
269 239 245 209
----------------------------------------

Total Production (mboe/d) 227 235 220 213
----------------------------------------
----------------------------------------

(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
17 to our Unaudited Consolidated Financial Statements.


Three Months Twelve Months
Ended December 31 Ended December 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Before Royalties
Crude Oil and NGLs (mbbls/d) - 13.7 7.5 14.6
Natural Gas (mmcf/d) - 12 6 13
After Royalties
Crude Oil and NGLs (mbbls/d) - 10.7 5.8 11.4
Natural Gas (mmcf/d) - 10 5 11
----------------------------------------


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

Total
Quarters - 2010 Year
(dollar amounts in Cdn$ ------------------------------------------------
unless noted) 1st 2nd 3rd 4th 2010
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil (US$/bbl) 78.71 78.03 76.20 85.12 79.52
Nexen Average - Oil
(Cdn$/bbl) 78.00 76.23 77.03 84.47 78.94
NYMEX Natural Gas 5.04 4.34 4.24 3.97 4.39
(US$/mmbtu)
Nexen Average - Gas
(Cdn$/mcf) 5.37 4.42 4.18 4.16 4.54
----------------------------------------------------------------------------

NETBACKS:
United Kingdom
Crude Oil:
Sales (mbbls/d) 106.5 102.1 103.9 110.0 105.6
Price Received ($/bbl) 77.25 77.18 77.45 83.88 79.02
Natural Gas:
Sales (mmcf/d) 33 41 29 38 36
Price Received ($/mcf) 4.81 4.80 5.11 6.34 5.28
Total Sales Volume
(mboe/d) 112.1 109.0 108.8 116.3 111.5

Price Received ($/boe) 74.84 74.12 75.35 81.37 76.51
Operating Costs 7.60 7.71 8.40 9.17 8.24
----------------------------------------------------------------------------
Netback 67.24 66.41 66.95 72.20 68.27
----------------------------------------------------------------------------
Canada - Heavy Oil
Sales (mbbls/d) 14.0 13.1 3.0 - 7.5

Price Received ($/bbl) 65.26 57.27 61.56 - 61.39
Royalties & Other 14.47 13.23 13.45 - 13.83
Operating & Other Costs 15.81 16.02 18.49 - 16.18
----------------------------------------------------------------------------
Netback 34.98 27.99 29.62 - 31.38
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 124 121 107 104 114

Price Received ($/mcf) 5.02 3.72 3.43 3.48 3.94
Royalties & Other 0.40 0.34 0.26 0.24 0.32
Operating Costs 1.70 1.89 1.90 1.55 1.76
----------------------------------------------------------------------------
Netback 2.92 1.49 1.27 1.69 1.86
----------------------------------------------------------------------------
Long Lake (2)
Sales (mbbls/d) 6.6 10.3 11.9 12.1 10.3

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

Price Received ($/bbl) 83.55 77.93 78.27 85.12 81.23
Royalties & Other 7.09 6.37 4.82 6.72 6.27
Operating Costs 38.43 33.33 41.49 34.80 36.74
----------------------------------------------------------------------------
Netback 38.03 38.23 31.96 43.60 38.22
----------------------------------------------------------------------------


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

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

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

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

Price Received ($/mcf) 4.75 3.42 2.85 4.14 3.78
Royalties & Other 0.59 0.15 0.21 0.34 0.32
Operating Costs 1.54 1.59 1.82 2.10 1.76
----------------------------------------------------------------------------
Netback 2.62 1.68 0.82 1.70 1.70
----------------------------------------------------------------------------
Long Lake (2)
Sales (mbbls/d) - - - - -

Price Received ($/bbl) - - - - -
Royalties & Other - - - - -
Operating Costs - - - - -
----------------------------------------------------------------------------
Netback (2) - - - - -
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 19.8 14.9 22.5 23.7 20.2

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

(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 sales made to third
parties during the period.


Total
Quarters - 2010 Year
(dollar amounts in Cdn$ ------------------------------------------------
unless noted) 1st 2nd 3rd 4th 2010
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 9.8 9.9 9.8 10.1 9.9
Price Received ($/bbl) 79.12 73.60 73.72 80.41 76.73
Natural Gas:
Sales (mmcf/d) 101 95 102 99 99
Price Received ($/mcf) 6.00 5.14 4.70 4.05 4.97
Total Sales Volume
(mboe/d) 26.6 25.8 26.9 26.6 26.5

Price Received ($/boe) 51.92 47.23 44.85 45.55 47.35
Royalties & Other 4.92 4.86 5.10 (0.63) 3.55
Operating Costs 8.96 10.90 9.44 10.78 10.02
----------------------------------------------------------------------------
Netback 38.04 31.47 30.31 35.40 33.78
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 47.3 39.3 43.5 38.8 42.2

Price Received ($/bbl) 80.39 80.50 79.33 87.82 81.86
Royalties & Other 37.52 36.65 34.75 37.72 36.65
Operating Costs 9.67 10.01 9.46 12.05 10.25
In-country Taxes 10.14 10.97 10.70 11.52 10.80
----------------------------------------------------------------------------
Netback 23.06 22.87 24.42 26.53 24.16
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 2.3 2.1 2.0 1.9 2.1

Price Received ($/bbl) 78.88 74.77 75.93 77.63 76.83
Royalties & Other 5.72 5.28 5.22 5.24 5.37
Operating Costs 5.58 7.42 6.98 8.19 6.99
----------------------------------------------------------------------------
Netback 67.58 62.07 63.73 64.20 64.47
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales
(mboe/d) 249.1 243.1 232.9 235.9 240.2

Price Received ($/boe) 70.16 67.56 68.23 74.49 70.11
Royalties & Other 9.47 8.05 7.96 7.13 8.16
Operating & Other Costs 14.18 15.85 15.70 16.26 15.67
In-country Taxes 1.94 1.76 2.00 1.89 1.90
----------------------------------------------------------------------------
Netback 44.57 41.90 42.57 49.21 44.38
----------------------------------------------------------------------------


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

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

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

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

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

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


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

Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions, except per share
amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,500 1,375 5,411 4,203
Marketing and Other (Note 14) 55 268 415 859
---------------------------------------
1,555 1,643 5,826 5,062
---------------------------------------
Expenses
Operating 364 240 1,354 916
Depreciation, Depletion,
Amortization and
Impairment 464 581 1,662 1,615
Transportation and Other 103 163 566 732
General and Administrative 148 105 439 434
Exploration 129 83 328 302
Interest (Note 9) 79 85 310 305
Net Loss (Gain) on Dispositions
(Note 15) (138) - 41 -
---------------------------------------
1,149 1,257 4,700 4,304
---------------------------------------

Income from Continuing Operations
before Provision for Income Taxes 406 386 1,126 758

Provision for (Recovery of) Income
Taxes
Current 339 262 1,127 773
Future (151) (125) (573) (527)
---------------------------------------
188 137 554 246
---------------------------------------

Net Income from Continuing
Operations 218 249 572 512
Net Income from Discontinued
Operations, Net of Tax (Note 17) 2 10 625 24
---------------------------------------

Net Income Attributable to Nexen
Inc. 220 259 1,197 536
---------------------------------------
---------------------------------------

Earnings Per Common Share from
Continuing
Operations ($/share) (Note 18)
Basic 0.41 0.48 1.09 0.98

---------------------------------------
---------------------------------------
Diluted 0.41 0.47 1.08 0.96
---------------------------------------
---------------------------------------

Earnings Per Common Share ($/share)
(Note 18)
Basic 0.42 0.50 2.28 1.03
---------------------------------------
---------------------------------------

Diluted 0.42 0.49 2.27 1.01
---------------------------------------
---------------------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Balance Sheet

December 31 December 31
(Cdn$ millions, except share amounts) 2010 2009
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 1,005 1,700
Restricted Cash 40 198
Accounts Receivable (Note 2) 1,938 2,788
Inventories and Supplies (Note 3) 549 680
Other 142 185
Assets Held for Sale (Note 17) 748 -
----------------------------
Total Current Assets 4,422 5,551
----------------------------

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and
Impairment of $9,881 (2009 - $10,807) 15,249 15,492
Future Income Tax Assets 1,678 1,148
Goodwill 286 339
Deferred Charges and Other Assets (Note 5) 272 370
----------------------------
Total Assets 21,907 22,900
----------------------------
----------------------------

Liabilities
Current Liabilities
Accounts Payable and Accrued Liabilities
(Note 8) 2,545 3,038
Accrued Interest Payable 83 89
Dividends Payable 26 26
Liabilities Held for Sale (Note 17) 540 -
----------------------------
Total Current Liabilities 3,194 3,153
----------------------------

Long-Term Debt (Note 9) 5,079 7,251
Future Income Tax Liabilities 3,138 2,811
Asset Retirement Obligations (Note 11) 1,009 1,018
Deferred Credits and Other Liabilities (Note
12) 696 1,021

Equity
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2010 - 525,706,403 shares
2009 - 522,915,843 shares 1,111 1,049
Contributed Surplus - 1
Retained Earnings 7,815 6,722
Accumulated Other Comprehensive Loss (219) (190)
----------------------------
Total Nexen Inc. Shareholders' Equity 8,707 7,582
Canexus Non-Controlling Interests 84 64
----------------------------
Total Equity 8,791 7,646
----------------------------
Commitments, Contingencies and Guarantees
(Notes 15 and 19)
----------------------------
Total Liabilities and Equity 21,907 22,900
----------------------------
----------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


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

Three Months Twelve Months
Ended Ended
December 31 December 31
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Operating Activities
Net Income from Continuing Operations 218 249 572 512
Net Income from Discontinued
Operations (Note 17) 3 13 630 44
Charges and Credits to Income not
Involving Cash (Note 20) 207 484 640 1,371
Exploration Expense 129 83 328 302
Changes in Non-Cash Working Capital
(Note 20) (72) (218) 338 (25)
Other (112) (84) (159) (318)
---------------------------------------
373 527 2,349 1,886

Financing Activities
Repayment of Short-Term Borrowings,
Net - - - (1)
Proceeds from Long-Term Notes - - - 1,081
Proceeds from (Repayment of) Term
Credit Facilities, Net 2 - (1,538) 728
Proceeds from Canexus Long-Term Debt,
Net (12) - 112 94
Dividends on Common Shares (26) (26) (104) (104)
Distributions Paid to Canexus
Non-Controlling Interests (4) (3) (17) (14)
Issue of Common Shares and Exercise of
Tandem Options for Shares 11 15 55 57
Other 1 (1) (14) (20)
---------------------------------------
(28) (15) (1,506) 1,821

Investing Activities
Capital Expenditures
Exploration and Development (520) (546) (2,313) (2,467)
Proved Property Acquisitions (79) - (79) (755)
Energy Marketing, Chemicals, Corporate
and Other (38) (77) (210) (275)
Proceeds on Dispositions of Assets 216 - 1,262 17
Changes in Non-Cash Working Capital
(Note 20) (29) (69) (59) (110)
Changes in Restricted Cash (3) 14 37 (140)
Other (52) 3 (60) (13)
---------------------------------------
(505) (675) (1,422) (3,743)

Effect of Exchange Rate Changes on
Cash and Cash Equivalents (45) (34) (116) (267)
---------------------------------------

Decrease in Cash and Cash Equivalents (205) (197) (695) (303)

Cash and Cash Equivalents - Beginning
of Period 1,210 1,897 1,700 2,003
---------------------------------------

Cash and Cash Equivalents - End of
Period (1) 1,005 1,700 1,005 1,700
---------------------------------------
---------------------------------------

(1) Cash and cash equivalents at December 31, 2010 consist of cash of $345
million and short-term investments of $660 million (2009 - cash of $210
million and short-term investments of $1,490 million).

See accompanying notes to the Unaudited Consolidated Financial Statements.


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

Three Months Twelve Months
Ended Ended
December 31 December 31
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------

Common Shares, Beginning of Period 1,097 1,025 1,049 981
Issue of Common Shares 9 8 50 45
Exercise of Tandem Options for Shares 2 7 5 12
Accrued Liability Relating to Tandem
Options Exercised for Common Shares 3 9 7 11
--------------------------------------
Balance at End of Period 1,111 1,049 1,111 1,049
--------------------------------------
--------------------------------------

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

Retained Earnings, Beginning of
Period 7,621 6,489 6,722 6,290
Net Income Attributable to Nexen Inc. 220 259 1,197 536
Dividends Declared on Common Shares
(Note 13) (26) (26) (104) (104)
---------------------------------------
Balance at End of Period 7,815 6,722 7,815 6,722
---------------------------------------
---------------------------------------

Accumulated Other Comprehensive Loss,
Beginning of Period (196) (183) (190) (134)
Other Comprehensive Loss
Attributable to Nexen Inc. (23) (7) (29) (56)
---------------------------------------
Balance at End of Period (1) (219) (190) (219) (190)
---------------------------------------
---------------------------------------

Canexus Non-Controlling Interests,
Beginning of Period 84 69 64 52
Net Income Attributable to
Non-Controlling Interests 1 3 5 27
Distributions Declared to
Non-Controlling Interests (5) (4) (20) (18)
Issue of Partnership Units to
Non-Controlling Interests 4 1 27 4
Estimated Fair Value of Conversion
Feature of Convertible Debenture
Issue Attributable to
Non-Controlling Interests - - 8 4
Other Comprehensive Loss
Attributable to Canexus
Non-Controlling Interests - (5) - (5)
---------------------------------------
Balance at End of Period 84 64 84 64
---------------------------------------
---------------------------------------

(1) Comprised of unrealized foreign currency translation adjustment.

See accompanying notes to the Unaudited Consolidated Financial Statements.


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

Three Months Twelve Months
Ended Ended
December 31 December 31
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. 220 259 1,197 536
Other Comprehensive Income (Loss),
Net of Income Taxes:
Foreign Currency Translation
Adjustment
Net Losses on Investment in
Self-Sustaining Foreign
Operations (174) (117) (257) (810)
Net Gains on Foreign-Denominated
Debt Hedges of Self-Sustaining
Foreign Operations (1) 151 111 228 757
Realized Translation Adjustments
Recognized in Net Income - (1) - (3)
---------------------------------------
Other Comprehensive Loss
Attributable to Nexen Inc. (23) (7) (29) (56)
---------------------------------------
Comprehensive Income Attributable
to Nexen Inc. 197 252 1,168 480
---------------------------------------
---------------------------------------

(1) Net of income tax expense for the three months ended December 31,
2010 of $21 million (2009 - $16 million expense) and net of
income tax expense for the twelve months ended December 31, 2010
of $33 million (2009 - $109 million expense).

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.

Notes to Unaudited Consolidated Financial Statements

Cdn$ millions, except as noted

1. ACCOUNTING POLICIES

Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). In the opinion of management, the Unaudited Consolidated Financial Statements contain all adjustments of a normal and recurring nature necessary to present fairly Nexen Inc.'s (Nexen, we or our) financial position at December 31, 2010 and 2009 and the results of our operations and our cash flows for the three and twelve months ended December 31, 2010 and 2009.

We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates on an ongoing basis, including those related to accruals, litigation, environmental and asset retirement obligations, recoverability of assets, income taxes, fair values of derivative assets and liabilities, fair values of commodity trading inventories, capital adequacy and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2009 Form 10-K. The accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2009 Form 10-K.

Changes in Accounting Policies

Oil and Gas Reserve Estimates

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

We follow the successful efforts method of accounting for our oil and gas activities, which use the estimated proved reserves we believe are recoverable from our oil and gas properties. Specifically, reserves estimates are used to calculate our unit-of-production depletion rates and to assess, when necessary, our oil and gas assets for impairment. Adoption of these amendments changed our estimate of reserves used to calculate depletion in 2010. As a result of the amendments, depletion expense for the three and twelve months ended December 31, 2010 increased by $11 million and $47 million, net income decreased by $7 million and $32 million, and earnings per common share decreased by $0.01/share and $0.07/share, respectively.

New Accounting Pronouncements

We will be required to adopt International Financial Reporting Standards (IFRS) for interim and annual reporting purposes for fiscal years beginning on or after January 1, 2011.



2. ACCOUNTS RECEIVABLE

December 31 December 31
2010 2009
----------------------------------------------------------------------------
Trade
Energy Marketing 929 1,410
Energy Marketing Derivative Contracts (Note 6) 149 466
Oil and Gas 822 823
Chemicals and Other 2 44
----------------------------
1,902 2,743
Non-Trade 80 99
----------------------------
1,982 2,842
Allowance for Doubtful Receivables (44) (54)
----------------------------
Total(1) 1,938 2,788
----------------------------
----------------------------

(1) At December 31, 2010, accounts receivable related to our chemicals
operations have been included in assets held for sale (see Note 17).


3. INVENTORIES AND SUPPLIES

December 31 December 31
2010 2009
----------------------------------------------------------------------------
Finished Products
Energy Marketing 452 548
Oil and Gas 34 25
Chemicals and Other - 12
----------------------------
486 585
Work in Process 5 7
Field Supplies 58 88
----------------------------
Total(1) 549 680
----------------------------
----------------------------

(1) At December 31, 2010, inventories and supplies related to our chemicals
operations have been included in assets held for sale (see Note 17).


4. PROPERTY, PLANT AND EQUIPMENT

Depreciation, Depletion, Amortization and Impairment

Our DD&A expense for 2010 includes non-cash impairment charges of $93 million on properties in the Gulf of Mexico. In the third quarter, low natural gas prices resulted in impairment on three shelf properties. We impaired two properties during the fourth quarter where declining production performance and higher estimated future abandonment costs reduced the properties' estimated future cash flows. These properties were written down to their estimated fair value based on their estimated future discounted net cash flows. The estimated future cash flows incorporate a risk-adjusted discount rate and management's estimates of future prices, capital expenditures and production. Based on these significant unobservable inputs, the measurements were considered Level 3 within the fair value hierarchy.



5. DEFERRED CHARGES AND OTHER ASSETS
December 31 December 31
2010 2009
----------------------------------------------------------------------------
Long-Term Energy Marketing Derivative Contracts
(Note 6) 116 225
Defined Benefit Pension Asset 75 60
Long-Term Capital Prepayments 12 27
Other 69 58
----------------------------
Total 272 370
----------------------------
----------------------------


6. FINANCIAL INSTRUMENTS

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

In our energy marketing group, we enter into contracts to purchase and sell crude oil, natural gas and other energy commodities and use derivative contracts, including futures, forwards, swaps and options, for hedging and trading purposes (collectively derivatives). We also use derivatives to manage commodity price risk and foreign currency risk for non-trading purposes. We categorize our derivative instruments as trading or non-trading activities and carry the instruments at fair value on our balance sheet. The fair values are included with amounts receivable or payable and are classified as long-term or short-term based on anticipated settlement date. Any change in fair value is included in marketing and other income.

We carry our long-term debt at amortized cost using the effective interest rate method. At December 31, 2010, the estimated fair value of our long-term debt was $5,290 million (2009 - $7,594 million) as compared to the carrying value of $5,079 million (2009 - $7,251 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers.

Derivatives

(a) Derivative contracts related to trading activities

During 2010, we sold substantially all of our North American natural gas marketing operations, our lease gathering, pipeline and storage assets in North Dakota and Montana, and our European gas and power marketing operations, as described in Note 15. Our energy marketing group primarily focuses on our crude oil marketing activities in North America, Europe and Asia.

Our energy marketing group engages in various activities, including the purchase and sale of physical commodities and the use of financial instruments such as commodity and foreign exchange futures, forwards and swaps to economically hedge exposures and generate revenue. These contracts are accounted for as derivatives and, where applicable, are presented net on the balance sheet in accordance with netting arrangements. The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:



December 31 December 31
2010 2009
----------------------------------------------------------------------------
Commodity Contracts 149 463
Foreign Exchange Contracts - 3
----------------------------
Accounts Receivable (Note 2) 149 466
----------------------------

Commodity Contracts 116 225
----------------------------
Deferred Charges and Other Assets (Note 5) (1) 116 225
----------------------------

Total Trading Derivative Assets 265 691
----------------------------
----------------------------

Commodity Contracts 168 410
Foreign Exchange Contracts - 46
----------------------------
Accounts Payable and Accrued Liabilities
(Note 8) 168 456
----------------------------

Commodity Contracts 115 212
----------------------------
Deferred Credits and Other Liabilities
(Note 12) (1) 115 212
----------------------------

Total Trading Derivative Liabilities 283 668
----------------------------
----------------------------

Total Net Trading Derivative Contracts (18) 23
----------------------------
----------------------------

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

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



December 31 December 31
2010 2009
----------------------------------------------------------------------------
Current Trading Assets 467 2,625
Non-Current Trading Assets 156 716
----------------------------
Total Trading Derivative Assets 623 3,341
----------------------------
----------------------------

Current Trading Liabilities 486 2,615
Non-Current Trading Liabilities 155 703
----------------------------
Total Trading Derivative Liabilities 641 3,318
----------------------------
----------------------------

----------------------------
Total Net Trading Derivative Contracts (18) 23
----------------------------
----------------------------


Trading revenues generated by our energy marketing group include gains and losses on derivative instruments and non-derivative instruments such as physical inventory. During the three and twelve months ended December 31, 2010 and 2009, the following trading revenues were recognized in marketing and other income:



Three Months Ended Three Months Ended
December 31 December 31
2010 2009
----------------------------------------------------------------------------
Commodity 52 263
Foreign Exchange - 4
---------------------------------------
Marketing Revenue 52 267
---------------------------------------
---------------------------------------

Twelve Months Ended Twelve Months Ended
December 31 December 31
2010 2009
----------------------------------------------------------------------------
Commodity 342 1,011
Foreign Exchange (8) (68)
---------------------------------------
Marketing Revenue 334 943
---------------------------------------
---------------------------------------


As an energy marketer, we may undertake several transactions during a period to execute a single sale of physical product. Each transaction may be represented by one or more derivative instruments including a physical buy, physical sell, and in many cases, numerous financial instruments for economically hedging and trading purposes. The absolute notional volumes associated with our derivative instrument transactions for the three and twelve months ended December 31, 2010, are as follows:



Three Months Ended Twelve Months Ended
December 31 December 31
2010 2010
----------------------------------------------------------------------------
Natural Gas (bcf/d) 2.7 6.5
Crude Oil (mmbbls/d) 2.8 3.1
Power (GWh/d) 0.6 69.5
Foreign Exchange (US$ millions) 288 2,457
Foreign Exchange (Euro millions) - 53
---------------------------------------


(b) Derivative contracts related to non-trading activities

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

December 31 December 31
2010 2009
----------------------------------------------------------------------------
Accounts Receivable 9 13
Deferred Charges and Other Assets (1) - 4
----------------------------
Total Non-Trading Derivative Assets 9 17
----------------------------
----------------------------

Accounts Payable and Accrued Liabilities - 26
----------------------------
Total Non-Trading Derivative Liabilities - 26
----------------------------
----------------------------

Total Net Non-Trading Derivative Assets (2) 9 (9)
----------------------------
----------------------------

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


Crude oil put options

During the third and fourth quarters of 2010, we purchased put options on 100,000 bbls/d of our 2011 crude oil production for $33 million. These options establish a monthly WTI floor price of between US$50/bbl and US$63/bbl on these volumes and provide a base level of price protection without limiting our upside to higher prices. The options settle monthly and unexpired options are recorded at fair value throughout their term. As a result, changes in forward crude oil prices create gains or losses on these options at each period end. Higher forward crude oil prices at December 31, 2010 reduced the fair value of the options to approximately $9 million and we recorded a fair value loss of $23 million and $24 million, for the three and twelve month periods ended December 31, 2010, respectively.

In 2009, we purchased put options on 90,000 bbls/d of our 2010 crude oil production for $39 million. These options establish a WTI floor price of US$50/bbl on these volumes. Options on 60,000 bbls/d settle monthly, while the remaining options settle annually. These options are recorded at fair value throughout their term. Higher forward crude oil prices at December 31, 2009 compared to the end of the previous quarter and a shorter term to expiry reduced the fair value of the options to nil and we recorded a fair value loss of $12 million and $229 million for the three and twelve month periods ended December 31, 2009, respectively.

(c) Fair value of derivatives

Our processes for estimating and classifying the fair value of our derivative contracts are consistent with those in place at December 31, 2009. The following table includes our derivatives carried at fair value for our trading and non-trading activities as at December 31, 2010 and 2009. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the least observable input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.



Net Derivatives at December 31, 2010 Level 1 Level 2 Level 3 Total
----------------------------------------------------------------------------
Trading Derivatives (Commodity
Contracts) (17) (18) 17 (18)
Non-Trading Derivatives - 9 - 9
--------------------------------------
Total (17) (9) 17 (9)
--------------------------------------
--------------------------------------

Net Derivatives at December 31, 2009 Level 1 Level 2 Level 3 Total
----------------------------------------------------------------------------
Commodity Contracts (143) 167 42 66
Foreign Exchange Contracts - (43) - (43)
--------------------------------------
Trading Derivatives (143) 124 42 23
Non-Trading Derivatives - (9) - (9)
--------------------------------------
Total (143) 115 42 14
--------------------------------------
--------------------------------------

A reconciliation of changes in the fair value of our derivatives classified
as Level 3 for the years ended December 31, 2010 and 2009 are provided
below:

2010 2009
----------------------------------------------------------------------------
Level 3 Net Derivatives at January 1 42 (82)
Realized and Unrealized Gains 19 74
Purchases - 4
Settlements (44) 54
Transfers Into Level 3 - -
Transfers Out of Level 3 - (8)
----------------------------
Level 3 Net Derivatives at December 31 17 42
----------------------------
----------------------------

Unsettled gains relating to instruments still
held as of December 31 19 66
----------------------------
----------------------------


Items classified in Level 3 are generally economically hedged such that gains or losses on positions classified in Level 3 are often offset by gains or losses on positions classified in Level 1 or 2. Transfers into or out of Level 3 represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Fair values of instruments in Level 3 are determined using broker quotes, pricing services and internally-developed inputs. We performed a sensitivity analysis of inputs used to calculate the fair value of Level 3 instruments. Using reasonably possible alternative assumptions, the fair value of Level 3 instruments at December 31, 2010 would change by $5 million.

7. RISK MANAGEMENT

(a) Market risk

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

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

Commodity price risk

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

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

Our energy marketing business is focused on maximizing the value of our equity production and, to a lesser extent, providing services to customers and suppliers to meet their energy commodity needs. We primarily market and trade physical crude oil in selected regions of the world. We accomplish this by buying and selling physical commodities, by acquiring and holding rights to physical transportation and storage assets for these commodities, and by building strong relationships with our customers and suppliers. Prior to the related disposition in 2010, we also marketed and traded physical natural gas, electricity and other commodities. In order to manage the commodity and foreign exchange price risks that come from this physical business, we use financial derivative contracts, including energy-related futures, forwards, swaps and options, as well as currency swaps or forwards.

Our risk management activities include prescribed capital limits and the use of tools such as Value-at-Risk (VaR) and stress testing consistent with the methodology used at December 31, 2009. Our period end, high, low and average VaR amounts for the three and twelve months ended December 31, 2010 are as follows:



Three Months Twelve Months
Ended December 31 Ended December 31
Value-at-Risk 2010 2009 2010 2009
----------------------------------------------------------------------------
Period End 11 11 11 11
High 14 18 15 24
Low 5 9 4 9
Average 9 13 10 15
---------------------------------------


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

Foreign currency risk

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

- sales of crude oil and natural gas;

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

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

- short-term borrowings and long-term debt.

We manage our exposure to fluctuations between the US and Canadian dollar by maintaining our expected net cash flows and borrowings in the same currency. Cash inflows generated by our foreign operations and borrowings on our US-dollar debt facilities are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows.

We designate most of our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. The foreign exchange gains or losses related to the effective portion of our designated US-dollar debt are included in accumulated other comprehensive income in equity. Our net investment in self-sustaining foreign operations and our designated US-dollar debt at December 31, 2010 and 2009 are as follows:



December 31 December 31
(US$ millions) 2010 2009
----------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign
Operations 4,443 4,492
Designated US-Dollar Debt 4,393 4,492
-------------------------------


For the three and twelve months ended December 31, 2010, the ineffective portion of our US-dollar debt resulted in a net foreign exchange gain of $3 million and a net foreign exchange loss of $3 million, respectively (gain of $2 million and loss of $3 million respectively, net of income tax expense) and is included in marketing and other income. A one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $38 million, net of income tax, and would increase or decrease our net income by approximately $3 million, net of income tax.

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

(b) Credit risk

Credit risk affects our oil and gas operations, and our energy marketing activities, and is the risk of loss if counterparties do not fulfill their contractual obligations. Most of our credit exposures are with counterparties in the energy industry, including integrated oil companies, refiners and utilities, and are subject to normal industry credit risk. Over 80% of our exposure is with these large energy companies. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. Our processes to manage this risk are consistent with those in place at December 31, 2009.

At December 31, 2010, three counterparties individually made up more than 10% of our credit exposure. These counterparties are major integrated oil companies with strong investment-grade ratings. Two other counterparties made up more than 5% of our credit exposure. The following table illustrates the composition of credit exposure by credit rating.



December 31 December 31
Credit Rating 2010 2009
----------------------------------------------------------------------------
A or higher 71% 67%
BBB 20% 26%
Non-Investment Grade 9% 7%
-----------------------------
Total 100% 100%
-----------------------------
-----------------------------


Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts on non-derivative financial assets such as cash and cash equivalents, restricted cash, accounts receivable, as well as the fair value of derivative financial assets. We provided an allowance of $44 million for credit risk with our counterparties. In addition, we incorporate the credit risk associated with counterparty default, as well as Nexen's own credit risk, into our estimates of fair value.

Collateral received from customers at December 31, 2010 includes $38 million of cash and $104 million of letters of credit. The cash received is included in accounts payable and accrued liabilities.

(c) Liquidity risk

Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they come due, and to operate our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At December 31, 2010, we had approximately $4 billion of cash and available undrawn committed lines of credit. This includes approximately $1 billion of cash and cash equivalents on hand and undrawn committed term credit facilities of $3 billion, of which $322 million was supporting letters of credit at December 31, 2010. These facilities are available until 2014 unless extended. We also have about $464 million of undrawn, uncommitted credit facilities, of which $112 million was supporting letters of credit at December 31, 2010.

The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2010:



less than 1-3 4-5 greater than
Total 1 Year Years Years 5 Years
----------------------------------------------------------------------------
Long-Term Debt (Note 9) 5,171 - 497 249 4,425
Cumulative Interest on
Long-Term Debt (1) 7,286 336 670 612 5,668
----------------------------------------------
Total 12,457 336 1,167 861 10,093
----------------------------------------------
----------------------------------------------

(1) At December 31, 2010 none of our variable interest rate debt was drawn.


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



less than 1-3 4-5 greater than
Total 1 Year Years Years 5 Years
----------------------------------------------------------------------------
Trading Derivatives (Note 6) 283 168 105 5 5
----------------------------------------------
----------------------------------------------


At December 31, 2010, collateral posted with counterparties includes $4 million of cash and $185 million of letters of credit related to our trading activities. Cash posted is included with our accounts receivable. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash would likely be retained.

The commercial agreements our energy marketing group enter into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements can require collateral to be posted if an adverse credit-related event occurs, such as a drop in credit ratings to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral secures the payment of such amounts. We have significant undrawn credit facilities and cash to fund these potential collateral requirements.

Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits of $40 million (2009 - $198 million), which have been included in restricted cash.



8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
December 31 December 31
2010 2009
----------------------------------------------------------------------------
Energy Marketing Payables 1,015 1,366
Energy Marketing Derivative Contracts (Note 6) 168 456
Accrued Payables 676 619
Trade Payables 164 210
Income Taxes Payable 345 179
Stock-Based Compensation 30 72
Other 147 136
-----------------------------
Total (1) 2,545 3,038
-----------------------------
-----------------------------

(1) At December 31, 2010, accounts payable related to our chemicals
operations have been included in liabilities held for sale
(see Note 17).


9. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

December 31 December 31
2010 2009
----------------------------------------------------------------------------
Canexus Term Credit Facilities, due 2012 (1) - 233
Canexus Notes, due 2013 (1) - 52
Notes, due 2013 (US$500 million) 497 523
Term Credit Facilities, due 2014 (a) - 1,570
Canexus Convertible Debentures, due 2014 (1) - 46
Notes, due 2015 (US$250 million) 249 262
Notes, due 2017 (US$250 million) 249 262
Notes, due 2019 (US$300 million) 298 314
Notes, due 2028 (US$200 million) 199 209
Notes, due 2032 (US$500 million) 497 523
Notes, due 2035 (US$790 million) 786 827
Notes, due 2037 (US$1,250 million) 1,243 1,308
Notes, due 2039 (US$700 million) 696 733
Subordinated Debentures, due 2043
(US$460 million) 457 481
-----------------------------
5,171 7,343
Unamortized Discount and Debt Issue Costs (92) (92)
-----------------------------
Total 5,079 7,251
-----------------------------
-----------------------------

(1) Included in liabilities held for sale at December 31, 2010 (see Notes
16 and 17).


(a) Term credit facilities

We have unsecured term credit facilities of $3 billion (US$3 billion), available until July 2014, none of which were drawn at December 31, 2010 (2009 - $1.6 billion (US$1.5 billion)). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable monthly at a floating rate. The weighted-average interest rate on our term credit facilities was 3.0% for the three months ended December 31, 2010 (2009 - 0.9%) and 1.6% for the year ended December 31, 2010 (2009 - 1.0%). At December 31, 2010, $322 million (US$324 million) of these facilities were utilized to support outstanding letters of credit (2009 - $407 million (US$389 million)).

(b) Short-term borrowings

Nexen has uncommitted, unsecured credit facilities of approximately $464 million (US$467 million), (2009 - $492 million (US$470 million)), none of which were drawn at either December 31, 2010 or 2009. We utilized $112 million (US$112 million) of these facilities to support outstanding letters of credit at December 31, 2010 (2009 - $86 million (US$82 million)). Interest is payable at floating rates.



(c) Interest expense

Three Months Twelve Months
Ended December 31 Ended December 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Long-Term Debt 92 94 361 360
Other 11 5 29 17
---------------------------------------
Total 103 99 390 377
Less: Capitalized (24) (14) (80) (72)
---------------------------------------
Total(1) 79 85 310 305
---------------------------------------
---------------------------------------

(1) Excludes interest expense related to our chemicals operations (see
Notes 16 and 17).


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.

10. CAPITAL DISCLOSURE

Our objectives and processes for managing our capital structure are consistent with those in place at December 31, 2009. Our capital consists of equity, short-term borrowings, long-term debt and cash and cash equivalents as follows:



December 31 December 31
2010 2009
----------------------------------------------------------------------------
Net Debt(1)
Long-Term Debt 5,079 7,251
Less: Cash and Cash Equivalents (1,005) (1,700)
-----------------------------
Total(2) 4,074 5,551
-----------------------------
-----------------------------
Equity(3) 8,707 7,582
-----------------------------
-----------------------------

(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.
(2) December 31, 2010 excludes net debt related to our chemicals operations
included in assets and liabilities held for sale (see Note 17).
(3) Equity is the historical issue of equity and accumulated retained
earnings.


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

We use the ratio of net debt to cash flow from operating activities as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is a non-GAAP measure that does not have any standard meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by others. We calculate net debt using the GAAP measures of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash). For the twelve months ended December 31, 2010, the net debt to cash flow from operating activities was 1.9 times compared to 2.5 times at December 31, 2009. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher or lower depending on commodity price volatility, where we are in the investment cycle or when we identify strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we assess whether we need to develop a strategy to reduce our leverage and lower this ratio back to target levels over time.

Our interest coverage ratio monitors our ability to fund the interest requirements associated with our debt. Our interest coverage increased from 8.5 times at the end of 2009 to 9.3 times at December 31, 2010. Interest coverage is calculated by dividing our twelve-month trailing earnings before interest, taxes, DD&A, exploration expense and other non-cash items (adjusted EBITDA) by interest expense before capitalized interest. Adjusted EBITDA is a non-GAAP measure that is calculated using net income excluding interest expense, provision for income taxes, exploration expenses, DD&A, impairment and other non-cash expenses. The calculation of adjusted EBITDA is set out in the following table and is unlikely to be comparable to similar measures presented by others.



December 31 December 31
2010 2009
----------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. 1,197 536
Add:
Interest Expense 310 305
Provision for Income Taxes 554 246
Depreciation, Depletion, Amortization and
Impairment 1,662 1,615
Exploration Expense 328 302
Recovery of Non-Cash Stock-Based Compensation (41) (10)
Change in Fair Value of Crude Oil Put Options 41 251
Items Related to Discontinued Operations (475) -
Other Non-Cash Items 50 72
------------------------
Adjusted EBITDA 3,626 3,317
------------------------
------------------------


11. ASSET RETIREMENT OBLIGATIONS

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

December 31 December 31
2010 2009
----------------------------------------------------------------------------
Balance at Beginning of Year 1,053 1,059
Obligations Incurred with Development
Activities 32 27
Obligations Settled (43) (42)
Accretion Expense 66 70
Revisions to Estimates 169 13
Obligations Related to Dispositions(1) (166) -
Effects of Changes in Foreign Exchange Rate (47) (74)
-------------------------
Balance at End of Year (2,3) 1,064 1,053
-------------------------
-------------------------

(1) Includes obligations associated with discontinued operations of $163
million.
(2) Obligations due within 12 months of $55 million (2009 -- $35 million)
have been included in accounts payable and accrued liabilities.
(3) Obligations relating to our oil and gas activities amount to $1,064
million (2009 -- $1,002 million), and obligations relating to our
chemicals business amount to nil (2009 -- $51 million). At December 31,
2010, asset retirement obligations associated with our chemicals
business are included in liabilities held for sale (see Note 17).


Our total estimated undiscounted inflated asset retirement obligations amount to $2,552 million (2009 - $2,341 million). We discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted, risk-free rate of 6% (2009 - 5.9%). Approximately $306 million included in our asset retirement obligations is expected to be settled over the next five years. The remaining obligations settle beyond five years and are expected to be funded by future cash flows from our operations.



12. DEFERRED CREDITS AND OTHER LIABILITIES

December 31 December 31
2010 2009
----------------------------------------------------------------------------
Deferred Tax Credit 367 503
Long-Term Energy Marketing Derivative Contracts
(Note 6) 115 212
Defined Benefit Pension Obligations (1) 75 76
Capital Lease Obligations 42 61
Deferred Transportation Revenue - 55
Other 97 114
----------------------------
Total 696 1,021
----------------------------
----------------------------
(1) The obligations are secured by letters of credit drawn on our term
credit facilities.


13. SHAREHOLDERS' EQUITY

Dividends

Dividends per common share for the three months ended December 31, 2010 were $0.05 per common share (2009 - $0.05). Dividends per common share for the twelve months ended December 31, 2010 were $0.20 per common share (2009 - $0.20). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.



14. MARKETING AND OTHER INCOME
Three Months Twelve Months
Ended December 31 Ended December 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Marketing Revenue, Net 52 267 334 943
Long Lake Purchased Bitumen Sales 22 - 85 -
Change in Fair Value of Crude Oil Put
Options (23) (33) (41) (251)
Interest 1 3 7 7
Foreign Exchange Gains (Losses) (7) 16 (14) 128
Other 10 15 44 32
---------------------------------------
Total 55 268 415 859
---------------------------------------
---------------------------------------


15. DISPOSITIONS

Canadian Heavy Oil

In May 2010, we signed an agreement to sell our heavy oil properties in Canada. The sale closed in July 2010. We received proceeds of $939 million, net of closing adjustments and realized a gain of $781 million in the third quarter. The results of operations of these properties have been presented as discontinued operations in Note 17.

Natural Gas Energy Marketing

During the third quarter of 2010, we sold our North American natural gas marketing operations. The sale, which generated proceeds of $9 million, closed in the third quarter and we recognized a non-cash loss of $259 million. The purchaser acquired our North American natural gas storage and transportation commitments, natural gas inventory, and related financial and physical derivative positions. As is customary with such transactions, not all contracts could be assigned to the purchaser by the closing date. We have a total return swap in place with the purchaser to transfer to them the economic results on the unassigned contracts until they are assigned to the purchaser. The total return swap and unassigned contracts are derivative instruments carried at fair value on our balance sheet. The related gains and losses offset each other for the current and future periods.

In connection with our natural gas energy marketing disposition, we assigned substantially all of our natural gas transportation and storage contracts, reducing our future commitments by $342 million. We agreed to maintain our parental guarantee to the pipeline provider related to one transportation commitment. We are obligated to perform under the guarantee only if the purchaser does not meet its obligation to the pipeline provider. To guarantee its performance, the purchaser provided us with cash collateral of US$43 million for the maximum exposure under the guarantee at that time. This collateral is included in accounts payable. We expect to cancel this guarantee in the first quarter of 2011.

North Dakota/Montana Crude Oil Marketing

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

Canadian Undeveloped Oil Sand Leases

During the second quarter of 2010, we sold our non-core lands in the Athabasca region for proceeds of $81 million. We had no plans to develop these lands for a least a decade. We recognized a gain on disposition of $80 million.

UK Undeveloped Leases

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

European Gas and Power Marketing

During the first quarter of 2010, we sold our European Gas and Power marketing business for cash proceeds of $15 million. There was no gain or loss on the disposition.

16. SUBSEQUENT EVENTS

In early 2011, we completed the sale of our 62.7% investment in Canexus Limited Partnership, which operates the chemicals business, for net proceeds of $458 million. 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 results of our chemical business have been presented as discontinued operations for the last two years.

17. DISCONTINUED OPERATIONS

The results of operations of our Canadian heavy oil properties, disposed of during the year and our chemicals business, disposed of in early 2011, are detailed below and shown as discontinued operations in our Unaudited Consolidated Statement of Income.



Three Months Ended Three Months Ended
December 31, 2010 December 31, 2009
-----------------------------------------------
Canada Chemicals Total Canada Chemicals Total
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales - 120 120 65 110 175
Other - 12 12 - 6 6
-----------------------------------------------
- 132 132 65 116 181

Expenses
Operating - 80 80 23 71 94
Depreciation, Depletion,
Amortization and Impairment - 21 21 29 12 41
Transportation and Other - 13 13 3 11 14
General and Administrative - 8 8 4 8 12
Interest - 7 7 - 1 1
-----------------------------------------------
- 129 129 59 103 162
-----------------------------------------------

Income before Provision for
Income Taxes - 3 3 6 13 19

Provision for Future Income
Taxes - - - 3 3 6
-----------------------------------------------

Income before Non-Controlling
Interests - 3 3 3 10 13
Less: Non-Controlling
Interests - 1 1 - 3 3
-----------------------------------------------

Net Income from Discontinued
Operations - 2 2 3 7 10
-----------------------------------------------
-----------------------------------------------

Earnings Per Common Share
Basic 0.01 0.02
------ ------
------ ------
Diluted 0.00 0.02
------ ------
------ ------


Twelve Months Ended Twelve Months Ended
December 31, 2010 December 31, 2009
-----------------------------------------------
Canada Chemicals Total Canada Chemicals Total
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 138 456 594 234 458 692
Other - 25 25 - 5 50
Gain on Disposition (Note
15) 781 - 781 - - -
-----------------------------------------------
919 481 1,400 234 508 742
Expenses
Operating 50 308 358 97 267 364
Depreciation, Depletion,
Amortization and Impairment 35 57 92 122 65 187
Transportation and Other 2 51 53 15 48 63
General and Administrative 10 33 43 21 42 63
Interest - 14 14 - 7 7
-----------------------------------------------
97 463 560 255 429 684
-----------------------------------------------
Income (Loss) before
Provision for Income Taxes 822 18 840 (21) 79 58

Provision for (Recovery of)
Income Taxes
Current - 5 5 - 3 3
Future 206 (1) 205 (4) 15 11
-----------------------------------------------
206 4 210 (4) 18 14
-----------------------------------------------
Income (Loss) before Non-
Controlling Interests 616 14 630 (17) 61 44
Less: Non-Controlling
Interests - 5 5 - 20 20
-----------------------------------------------
Net Income (Loss) from
Discontinued Operations 616 9 625 (17) 41 24
-----------------------------------------------
-----------------------------------------------
Earnings Per Common Share
Basic 1.19 0.05
------ ------
------ ------
Diluted 1.19 0.05
------ ------
------ ------


Assets and liabilities on the Unaudited Consolidated Balance Sheet at December 31, 2009 include the following amounts for our heavy oil discontinued operations in Canada. There were no assets and liabilities related to heavy oil discontinued operations in Canada at December 31, 2010.



December 31 December 31
2010 2009
----------------------------------------------------------------------------
Property, Plant and Equipment, Net of Accumulated
DD&A - 331
Asset Retirement Obligations - (116)
Deferred Credits and Other Liabilities - (29)
----------------------------
Total - 186
----------------------------
----------------------------


The following table provides the assets and liabilities that are associated
with our chemicals business at December 31, 2010 and 2009.

December 31 December 31
2010 2009
----------------------------------------------------------------------------
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 643 573
Future Income Tax Asset 7 4
Deferred Charges and Other Assets 11 12
----------------------------
Assets 748 (1) 693
----------------------------
Accounts Payable and Accrued Liabilities 56 67
Accrued Interest Payable 3 -
Long-Term Debt(2) 394 327
Future Income Tax Liability 39 35
Asset Retirement Obligations 41 47
Deferred Credits and Other Liabilities 7 5
----------------------------
Liabilities 540 (1) 481
----------------------------
Equity - Canexus Non-Controlling Interest 84 64
----------------------------

(1) Included in assets and liabilities held for sale as at December 31,
2010.
(2) Long-term debt included in chemicals liabilities held for sale at
December 31, 2010, comprised of:
- Term credit facilities of $273 million, available until August 2012, with
interest payable monthly at variable rates;
- US$50 million notes, repayable in May 2013, with interest payable
quarterly at 6.57%;
- Convertible debentures of $22 million, maturing December 2014, with
interest payable semi-annually at 8%, convertible at the holders option
subject to certain conditions; and
- Convertible debentures of $49 million, maturing December 2015, with
interest payable semi-annually at 5.75%, convertible at the holders option
subject to certain conditions.


18. EARNINGS PER COMMON SHARE

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



Three Months Ended Twelve Months Ended
December 31 December 31
(millions of shares) 2010 2009 2010 2009
----------------------------------------------------------------------------
Weighted-average number of common
shares, basic 525.6 522.7 524.7 521.4
Shares issuable pursuant to tandem
options 4.1 7.5 5.7 10.1
Shares notionally purchased from
proceeds of tandem options (3.4) (5.2) (4.7) (7.0)
---------------------------------------
Weighted-average number of
common shares, diluted 526.3 525.0 525.7 524.5
---------------------------------------
---------------------------------------


In calculating the weighted-average number of diluted common shares outstanding for the three and twelve months ended December 31, 2010, we excluded 15,074,477 and 15,432,784 tandem options, respectively, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three and twelve months ended December 31, 2009, we excluded 14,187,472 and 13,485,465 tandem options, respectively, because their exercise price was greater than the average common share market price in the period. During the periods presented, outstanding tandem options were the only potential dilutive instruments.

19. COMMITMENTS, CONTINGENCIES AND GUARANTEES

As described in Note 15 to the Audited Consolidated Financial Statements included in our 2009 Form 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations.



20. CASH FLOWS

(a) Charges and credits to income not involving cash

Three Months Ended Twelve Months Ended
December 31 December 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Depreciation, Depletion, Amortization
and Impairment 464 581 1,662 1,615
Stock-Based Compensation 3 (33) (41) (10)
Recovery of Future Income Taxes (151) (125) (573) (527)
Net Loss (Gains) on Dispositions (138) - 41 -
Non-cash Items Included in Discontinued
Operations 11 80 (499) 149
Change in Fair Value of Crude Oil Put
Options 23 33 41 251
Foreign Exchange 7 (68) 14 (128)
Other (12) 16 (5) 21
---------------------------------------
Total 207 484 640 1,371
---------------------------------------
---------------------------------------

(b) Changes in non-cash working capital
Three Months Ended Twelve Months Ended
December 31 December 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Accounts Receivable 90 53 96 92
Inventories and Supplies (93) (94) (105) (236)
Other Current Assets 1 21 47 9
Accounts Payable and Accrued
Liabilities (109) (274) 241 (23)
Other Current Liabilities 10 7 - 23
--------------------------------------
Total (101) (287) 279 (135)
--------------------------------------
--------------------------------------
Relating to:
Operating Activities (72) (218) 338 (25)
Investing Activities (29) (69) (59) (110)
---------------------------------------
Total (101) (287) 279 (135)
---------------------------------------
---------------------------------------

(c) Other cash flow information

Three Months Ended Twelve Months Ended
December 31 December 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Interest Paid 87 87 380 335
Income Taxes Paid 325 236 951 483
---------------------------------------


Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $40 million for the three months ended December 31, 2010 (2009 - $22 million) and $100 million for the twelve months ended December 31, 2010 (2009 - $81 million).

21. OPERATING SEGMENTS AND RELATED INFORMATION

Nexen is involved in activities relating to Oil and Gas, Energy Marketing and Chemicals in various geographic locations as described in Note 20 to the Audited Consolidated Financial Statements included in our 2009 Form 10-K. With the sale of our Chemicals operations in early 2011, we have presented the associated discontinued operations in Corporate, Chemicals and Other.



Three months ended December 31, 2010

Oil and Gas
--------------------------------------------------------
United United Other
Kingdom Canada(1) Syncrude States Yemen Countries(2)
--------------------------------------------------------
Net Sales 872 150 164 114 178 12
Marketing and Other 3 24 1 - 4 -
--------------------------------------------------------
Total Revenues 875 174 165 114 182 12

Less: Expenses
Operating 98 115 72 27 43 1
Depreciation,
Depletion,
Amortization and
Impairment 249 67 14 93 24 2
Transportation and
Other (2) 54 5 - 18 -
General and
Administrative(4) 4 16 - 21 4 9
Exploration 25 22 - 68 - 14(5)
Interest - - - - - -
Gains on
Dispositions (17) - - - - -
--------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income Taxes 518 (100) 74 (95) 93 (14)
Less: Provision for
(Recovery
Of) Income Taxes 145 (25) 19 (32) 32 (13)
--------------------------------------------------------
Income (Loss) from
Continuing
Operations 373 (75) 55 (63) 61 (1)
Add: Net Income from
Discontinued
Operations - - - - - -
--------------------------------------------------------
Net Income (Loss) 373 (75) 55 (63) 61 (1)
--------------------------------------------------------
--------------------------------------------------------

Identifiable Assets 4,251 8,002(6) 1,339 1,662 248 1,412(7)
--------------------------------------------------------
--------------------------------------------------------

Capital Expenditures
Exploration &
Development 136 111 29 58 12 174
Proved Property
Acquisitions 79 - - - - -
--------------------------------------------------------
Total 215 111 29 58 12 174
--------------------------------------------------------
--------------------------------------------------------

Property, Plant and
Equipment Cost 6,610 8,729 1,545 3,913 2,379 1,362
Less: Accumulated
DD&A 3,273 883 305 2,689 2,312 88
--------------------------------------------------------
Net Book Value 3,337 7,846(6) 1,240 1,224 67 1,274(7)
--------------------------------------------------------
--------------------------------------------------------


Corporate,
Energy Chemicals
Marketing and Other Total
------------------------------------------
Net Sales 10 - 1,500
Marketing and Other 52 (29)(3) 55
------------------------------------------
Total Revenues 62 (29) 1,555

Less: Expenses
Operating 8 - 364
Depreciation, Depletion,
Amortization and Impairment 4 11 464
Transportation and Other 40 (12) 103
General and Administrative (4) 18 76 148
Exploration - - 129
Interest - 79 79
Gains on Dispositions (121) - (138)
------------------------------------------
Income (Loss) from Continuing
Operations before Income Taxes 113 (183) 406
Less: Provision for (Recovery
Of) Income Taxes 44 18 188
------------------------------------------
Income (Loss) from Continuing
Operations 69 (201) 218
Add: Net Income from Discontinued
Operations - 2 2
------------------------------------------
Net Income (Loss) 69 (199) 220
------------------------------------------
------------------------------------------

Identifiable Assets 1,778(8) 3,215(9) 21,907
------------------------------------------
------------------------------------------

Capital Expenditures
Exploration & Development 4 34 558
Proved Property Acquisitions - - 79
------------------------------------------
Total 4 34 637
------------------------------------------
------------------------------------------

Property, Plant and Equipment
Cost 195 397 25,130
Less: Accumulated DD&A 66 265 9,881
------------------------------------------
Net Book Value 129 132 15,249
------------------------------------------
------------------------------------------

(1) Includes results of operations from conventional, oil sands, shale gas
and CBM.
(2) Includes results of operations from producing activities in Colombia.
(3) Includes interest income of $1 million, foreign exchange losses of $7
million and a decrease in the fair value of crude oil put options of
$23 million.
(4) Includes stock-based compensation expense of $20 million.
(5) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(6) Includes $6,179 million related to our insitu oil sands projects (Long
Lake and future phases).
(7) Includes $1,222 million related to our Usan development, offshore
Nigeria.
(8) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.
(9) Includes $748 million of assets held for sale relating to our chemicals
operations (see Notes 16 and 17).


Three months ended December 31, 2009

Oil and Gas
--------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
--------------------------------------------------------
Net Sales 856 49 160 96 192 15
Marketing and Other 5 (1) 6 - 4 -
--------------------------------------------------------
Total Revenues 861 48 166 96 196 15

Less: Expenses
Operating 78 23 60 25 46 2
Depreciation,
Depletion,
Amortization and
Impairment (3) 338 88 30 97 10 3
Transportation and
Other 3 5 11 4 5 -
General and
Administrative(4) 3 5 - 9 1 6
Exploration 24 31 - 17 - 11(5)
Interest - - - - - -
--------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income Taxes 415 (104) 65 (56) 134 (7)
Less: Provision for
(Recovery
of) Income Taxes 129 (28) 17 (14) 52 6
--------------------------------------------------------
Income (Loss) from
Continuing
Operations 286 (76) 48 (42) 82 (13)
Add: Net Income from
Discontinued
Operations - 3 - - - -
--------------------------------------------------------
Net Income (Loss) 286 (73) 48 (42) 82 (13)
--------------------------------------------------------
--------------------------------------------------------

Identifiable Assets 4,866 7,809(6) 1,287 1,715 229 1,090
--------------------------------------------------------
--------------------------------------------------------

Capital Expenditures
--------------------------------------------------------
Exploration &
Development 126 135 31 68 7 179
--------------------------------------------------------
--------------------------------------------------------

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


Corporate,
Energy Chemicals
Marketing and Other Total
------------------------------------------
Net Sales 7 - 1,375
Marketing and Other 267 (13)(2) 268
------------------------------------------
Total Revenues 274 (13) 1,643

Less: Expenses
Operating 6 - 240
Depreciation, Depletion,
Amortization and Impairment (3) 6 9 581
Transportation and Other 130 5 163
General and Administrative (4) 23 58 105
Exploration - - 83
Interest - 85 85
------------------------------------------
Income (Loss) from Continuing
Operations before Income Taxes 109 (170) 386
Less: Provision for (Recovery
of) Income Taxes 44 (69) 137
------------------------------------------
Income (Loss) from Continuing
Operations 65 (101) 249
Add: Net Income from
Discontinued Operations - 7 10
------------------------------------------
Net Income (Loss) 65 (94) 259
------------------------------------------
------------------------------------------

Identifiable Assets 3,050(7) 2,854 22,900
------------------------------------------
------------------------------------------

Capital Expenditures
------------------------------------------
Exploration & Development 8 69 623
------------------------------------------
------------------------------------------

Property, Plant and Equipment
Cost 259 1,506 26,299
Less: Accumulated DD&A 83 802 10,807
------------------------------------------
Net Book Value 176 704 15,492
------------------------------------------
------------------------------------------

(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $3 million, foreign exchange gains of $16
million, decrease in the fair value of crude oil put options of $33
million and other gains of $1 million.
(3) Includes an impairment charge related to gas properties in Canada and
the US Gulf of Mexico of $58 million and $20 million, respectively.
(4) Includes recovery of stock-based compensation expense of $18 million.
(5) Includes exploration activities primarily in Norway, Nigeria and
Colombia.
(6) Includes $6,045 million related to our insitu oil sands (Long Lake and
future phases).
(7) 78% of Marketing's identifiable assets are accounts receivable and
inventories.


Twelve months ended December 31, 2010

Oil and Gas
--------------------------------------------------------
United United Other
Kingdom Canada(1) Syncrude States Yemen Countries(2)
--------------------------------------------------------
Net Sales 3,115 503 580 424 696 54
Marketing and Other 17 87 5 1 16 -
--------------------------------------------------------
Total Revenues 3,132 590 585 425 712 54

Less: Expenses
Operating 335 442 284 97 158 5
Depreciation,
Depletion,
Amortization and
Impairment (4) 827 259 53 343 112 9
Transportation and
Other 2 201 21 2 26 1
General and
Administrative(5) 22 45 1 62 6 27
Exploration 67 42 - 115 - 104(6)
Interest - - - - - -
Net (Gains) Loss on
Dispositions (17) (80) - - - -
--------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income Taxes 1,896 (319) 226 (194) 410 (92)
Less: Provision for
(Recovery
of) Income Taxes 834 (80) 57 (67) 143 (83)
--------------------------------------------------------
Income (Loss) from
Continuing
Operations 1,062 (239) 169 (127) 267 (9)
Add: Net Income from
Discontinued
Operations - 590 - - - -
--------------------------------------------------------
Net Income (Loss) 1,062 351 169 (127) 267 (9)
--------------------------------------------------------
--------------------------------------------------------

Identifiable Assets 4,251 8,002(7) 1,339 1,662 248 1,412(8)
--------------------------------------------------------
--------------------------------------------------------

Capital Expenditures
Exploration &
Development 596 773 100 214 52 578
Proved Property
Acquisitions 79 - - - - -
--------------------------------------------------------
Total 675 773 100 214 52 578
--------------------------------------------------------

Property, Plant and
Equipment Cost 6,610 8,729 1,545 3,913 2,379 1,362
Less: Accumulated
DD&A 3,273 883 305 2,689 2,312 88
--------------------------------------------------------
Net Book Value 3,337 7,846(7) 1,240 1,224 67 1,274(8)
--------------------------------------------------------
--------------------------------------------------------


Corporate,
Energy Chemicals
Marketing and Other Total
------------------------------------------
Net Sales 39 - 5,411
Marketing and Other 334 (45)(3) 415
------------------------------------------
Total Revenues 373 (45) 5,826

Less: Expenses
Operating 33 - 1,354
Depreciation, Depletion,
Amortization and Impairment (4) 18 41 1,662
Transportation and Other 314 (1) 566
General and Administrative (5) 69 207 439
Exploration - - 328
Interest - 310 310
Net (Gains) Loss on Dispositions 138 - 41
------------------------------------------
Income (Loss) from Continuing
Operations before Income Taxes (199) (602) 1,126
Less: Provision for (Recovery
of) Income Taxes (78) (172) 554
------------------------------------------
Income (Loss) from Continuing
Operations (121) (430) 572
Add: Net Income from
Discontinued Operations 26 9 625
------------------------------------------
Net Income (Loss) (95) (421) 1,197
------------------------------------------
------------------------------------------

Identifiable Assets 1,778(9) 3,215(10) 21,907
------------------------------------------
------------------------------------------

Capital Expenditures
Exploration & Development 29 181 2,523
Proved Property Acquisitions - - 79
------------------------------------------
Total 29 181 2,602
------------------------------------------
------------------------------------------

Property, Plant and Equipment
Cost 195 397 25,130
Less: Accumulated DD&A 66 265 9,881
------------------------------------------
Net Book Value 129 132 15,249
------------------------------------------
------------------------------------------

(1) Includes results of operations from conventional, oil sands, shale gas
and CBM.
(2) Includes results of operations from producing activities in Colombia.
(3) Includes interest income of $7 million, foreign exchange losses of $14
million, decrease in the fair value of crude oil put options of $41
million and other gains of $3 million.
(4) Includes an impairments charge related to gas properties in the US Gulf
of Mexico of $93 million.
(5) Includes net recovery of stock-based compensation expense of $14
million.
(6) Includes exploration activities primarily in Norway, Nigeria, and
Colombia.
(7) Includes $6,179 million related to our insitu oil sands projects (Long
Lake and future phases).
(8) Includes $1,222 million related to our Usan development, offshore
Nigeria.
(9) 84% of marketing's identifiable assets are accounts receivable and
inventories.
(10) Includes $748 million of assets held for sale relating to our chemicals
operations (see Notes 16 and 17).


Twelve months ended December 31, 2009


Oil and Gas
--------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
--------------------------------------------------------
Net Sales 2,430 161 480 321 705 70
Marketing and Other 18 1 7 - 14 6
--------------------------------------------------------
Total Revenues 2,448 162 487 321 719 76

Less: Expenses
Operating 253 74 265 98 191 8
Depreciation,
Depletion,
Amortization and
Impairment (3) 875 179 63 312 102 14
Transportation and
Other 17 12 28 22 30 -
General and
Administrative(4) 18 46 1 60 6 35
Exploration 50 84 - 104 - 64(5)
Interest - - - - - -
--------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income Taxes 1,235 (233) 130 (275) 390 (45)
Less: Provision for
(Recovery
of) Income Taxes 487 (60) 33 (95) 141 (23)
--------------------------------------------------------
Income (Loss) from
Continuing
Operations 748 (173) 97 (180) 249 (22)
Add: Net Loss from
Discontinued
Operations - (17) - - - -
--------------------------------------------------------
Net Income (Loss) 748 (190) 97 (180) 249 (22)
--------------------------------------------------------
--------------------------------------------------------

Identifiable Assets 4,866 7,809(6) 1,287 1,715 229 1,090
--------------------------------------------------------
--------------------------------------------------------

Capital Expenditures
Exploration &
Development 626 843 87 285 69 557
Proved Property
Acquisitions - 755 - - - -
--------------------------------------------------------
Total 626 1,598 87 285 69 557
--------------------------------------------------------
--------------------------------------------------------

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


Corporate,
Energy Chemicals
Marketing and Other Total
------------------------------------------
Net Sales 36 - 4,203
Marketing and Other 943 (130)(2) 859
------------------------------------------
Total Revenues 979 (130) 5,062

Less: Expenses
Operating 27 - 916
Depreciation, Depletion,
Amortization and Impairment(3) 27 43 1,615
Transportation and Other 599 24 732
General and Administrative(4) 91 177 434
Exploration - - 302
Interest - 305 305
------------------------------------------
Income (Loss) from Continuing
Operations before Income Taxes 235 (679) 758
Less: Provision for (Recovery
of) Income Taxes 96 (333) 246
------------------------------------------
Income (Loss) from Continuing
Operations 139 (346) 512
Add: Net Loss from Discontinued
Operations - 41 24
------------------------------------------
Net Income (Loss) 139 (305) 536
------------------------------------------
------------------------------------------

Identifiable Assets 3,050(7) 2,854 22,900
------------------------------------------
------------------------------------------

Capital Expenditures
Exploration & Development 28 247 2,742
Proved Property Acquisitions - - 755
------------------------------------------
Total 28 247 3,497
------------------------------------------
------------------------------------------

Property, Plant and Equipment
Cost 259 1,506 26,299
Less: Accumulated DD&A 83 802 10,807
------------------------------------------
Net Book Value 176 704 15,492
------------------------------------------
------------------------------------------

(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $7 million, foreign exchange gains of $128
million, decrease in the fair value of crude oil put options of $251
million and other losses of $14 million.
(3) Includes an impairment charge related to gas properties in Canada and
the US Gulf of Mexico of $58 million and $20 million, respectively.
(4) Includes stock-based compensation expense of $69 million.
(5) Includes exploration activities primarily in Norway, Nigeria and
Colombia.
(6) Includes $6,045 million related to our insitu oil sands (Long Lake and
future phases).
(7) 78% of Marketing's identifiable assets are accounts receivable and
inventories.


Contact Information

  • Tim Chatten, P.Eng
    Analyst, Investor Relations
    (403) 699-4244
    or
    Pierre Alvarez
    Vice President, Corporate Relations
    (403) 699-6291
    or
    Gary Nieuwenburg
    Executive Vice President - Canada
    (403) 699-4910
    or
    Nexen Inc.
    801 - 7th Ave SW
    Calgary, Alberta, Canada T2P 3P7
    www.nexeninc.com