Nexen Inc.
TSX : NXY
NYSE : NXY

Nexen Inc.

July 15, 2010 06:30 ET

Nexen Announces Solid Second Quarter Results, Ongoing Execution Success and Significant Increase in Canadian Shale Gas Position

CALGARY, ALBERTA--(Marketwire - July 15, 2010) - Nexen Inc. announces solid financial results for the second quarter with cash flow of $558 million and net income of $255 million. We continue to achieve execution success with our three strategies and our non-core asset disposition program.

At our Long Lake oil sands project, bitumen production volumes continue to reach new highs and the upgrader is operating reliably, producing the highest quality synthetic crude in North America. In Horn River shale gas, we have started fracing the eight wells we drilled earlier this year. Our costs are coming down and we are executing our program at industry leading levels. In addition, we were successful at a recent land sale in northeast British Columbia where we more than doubled our shale gas position. On the conventional side of our business, we have had major discoveries in each of our three key conventional basins in the past 18 months-Golden Eagle area in the North Sea, Appomattox in the deep-water Gulf of Mexico and Owowo, offshore West Africa.

All our success is contributing to new production volumes, starting with approximately 70,000 bbls/d coming from Long Lake, Usan and shale gas over the next 24 months. Golden Eagle, Appomattox, Knotty Head, Owowo, shale gas and future oil sands phases will contribute to production volumes thereafter. With the recent sale of our Western Canadian heavy oil assets, we have exceeded our target of generating $1.0 billion from non-core asset sales. We have now increased our target to approximately $1.5 billion once we complete our disposition program which includes the sale of our Canexus investment.

In the Gulf of Mexico, the six month drilling moratorium has had no significant impact on us to date. It will likely delay our exploration and appraisal drilling programs but have little cash cost to us for the remainder of the six month period.

Second quarter highlights include:

- Quarterly cash flow of $558 million ($1.06/share) and net income of $255 million ($0.49/share)

- Quarterly production before royalties of 248,000 boe/d (218,000 boe/d after royalties)-impacted by Buzzard scheduled downtime

- Long Lake gross bitumen production has increased from 16,000 to 28,500 bbls/d since January-on track to exit the year at 40,000 to 60,000 bbls/d

- Successful disposition of Canadian heavy oil properties-sale closing soon realizing excellent value for non-core assets

- Annual production guidance unchanged at between 230,000 and 280,000 boe/d (200,000 and 250,000 boe/d after royalties)

- Success at British Columbia land sale-more than doubling our shale gas acreage



Quarterly Results

Three Months Ended Six Months Ended
June 30 June 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Production (mboe/d)
Before Royalties 248 240 250 246
After Royalties 218 208 220 217
Cash Flow from Operations(1) 558 443 1,096 1,000
Per Common Share ($/share)(1) 1.06 0.85 2.09 1.92
Net Income 255 20 440 155
Per Common Share ($/share) 0.49 0.04 0.84 0.30
Capital Investment(2)(3) 834 746 1,402 2,262
Net Debt(4) 5,471 5,889 5,471 5,889


(1) For reconciliation of this non-GAAP measure, see Cash Flow from
Operations on pg. 9.
(2) Includes geological and geophysical expenditures.
(3) Q1 2009 includes $755 million for the acquisition of an additional 15%
interest in Long Lake from our partner.
(4) Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.


Quarterly cash flow from operations was $558 million and net income was $255 million. In comparison to the same quarter last year, our cash flow has increased from stronger production and commodity prices. Our net debt is down over $400 million from a year ago and will decline substantially more once we close the heavy oil sale and sell our Canexus interest.

With consistent and improving performance at Long Lake, we stopped capitalizing start up results as of December 31, 2009. Since the first quarter, our cash flow operating loss from Long Lake has decreased from $58 million to $19 million in the second quarter. Our absolute operating costs have largely remained flat and with growing volumes our unit operating costs have improved 43% over the previous quarter. When fully ramped up, we expect Long Lake's operating costs to be about $25/bbl.

"With volumes increasing steadily, Long Lake is approaching breakeven and we expect to generate positive cash flow later this year," stated Marvin Romanow, Nexen's President and Chief Executive Officer. "This will be an important milestone and shows the future cash generating ability of Long Lake as we continue to ramp up to design rates."



Quarterly Production-Long Lake Bitumen Volumes Continue to Grow

Quarterly Production Quarterly Production
before Royalties after Royalties

Crude Oil, NGLs
and Natural Gas
(mboe/d) Q2 2010 Q1 2010 Q2 2010 Q1 2010
----------------------------------------------------------------------------
North Sea 105 112 105 112
Yemen 41 43 22 23
Canada - Oil & Gas 35 36 29 31
United States 26 27 23 24
Canada - Syncrude 23 20 22 18
Canada - Bitumen 16 12 15 11
Other Countries 2 2 2 2
---------------------------------------------------------
Total 248 252 218 221
---------------------------------------------------------


Second quarter production volumes were 85% weighted to crude oil and averaged 248,000 boe/d (218,000 boe/d after royalties) due to scheduled downtime at Buzzard in the North Sea. Buzzard's production averaged 165,000 boe/d gross (71,000 boe/d net to us) compared to typical rates of approximately 210,000 boe/d gross (90,000 boe/d net to us). Production here was reduced for approximately three weeks while we installed the fourth platform topsides and successfully repaired the main separator unit. Production from our Ettrick field more than doubled over the prior quarter and averaged 14,000 boe/d net to us. Ettrick is currently producing at approximately 20,000 boe/d net to us and continues to ramp up.

Earlier this week, a valve failure on the Forties pipeline system required us to shut-in our production from the Scott platform. The operator is currently determining the root cause and the nature of the repairs. While the operator undertakes this work, we are advancing our shutdown at Scott that was planned for later this summer. Second quarter production rates from our Scott/Telford fields averaged 18,000 boe/d.

At Long Lake, our quarterly bitumen volumes continue to grow following the successful completion of the turnaround last fall. Long Lake's gross bitumen production has increased from 14,000 bbls/d in the fourth quarter of 2009 to 19,000 bbls/d in the first quarter of 2010 to 25,000 bbls/d in the second quarter. This represents a growth rate of over 30% each quarter as we are seeing production increases from new wells and optimization of mature producers. We are currently producing approximately 28,500 bbls/d and are on track to exit the year between 40,000 and 60,000 bbls/d gross. We have a 65% operated working interest in the project.

At Syncrude, production returned to normal levels following a turnaround of the LC finer in the first quarter. A coker turnaround is scheduled at Syncrude in the third quarter.

"As we grow production at Long Lake, Ettrick and in the Horn River, we are on track to meet our original production guidance even after the sale of our heavy oil assets," stated Romanow.

Non-Core Asset Sales Update-Heavy Oil Disposition Realizes Exceptional Value

As previously announced, we signed an agreement to sell our heavy oil properties in Western Canada for approximately $975 million (before closing adjustments and costs). The sale is expected to close shortly. These properties produced approximately 15,000 boe/d in the second quarter and had proved reserves of 39 million boe at December 31, 2009.

During the quarter, we signed an agreement to sell our North American natural gas marketing business. The transaction is expected to close in the third quarter subject to customary closing conditions. The terms of the agreement transfer substantially all related market risk to the buyer effective May 5, 2010.

"We have achieved excellent value on the sale of our non-core assets, met our target of $1.0 billion of proceeds and expect to generate total net gains of approximately $500 million," said Romanow. "We now expect over $1.5 billion from all asset sales, once we complete our disposition program which includes the sale of our interest in Canexus over the next 12 to 18 months. The proceeds will be used to develop the exciting success we are having with our conventional exploration, oil sands and shale gas assets."

Long Lake-Upgrader Performing Well and Bitumen Production Continues to Increase

The upgrader is performing well and is consistently processing virtually all of our bitumen production as well as 9,000 bbls/d of purchased bitumen. The gasification process is working, creating a low-cost fuel source which reduces our need to purchase natural gas for operations and will generate a significant margin advantage over our peers, even at current low gas prices.

Bitumen production to feed the upgrader continues to ramp up following the completion of the turnaround last fall as we have significantly improved steam reliability and are optimizing our wells. Steam rates have more than doubled from pre-turnaround levels and we are currently at all-time highs of about 150,000 bbls/d. As a result, we are injecting more steam into more wells than ever before with 68 of 91 well pairs now on production and steam circulating in an additional 13 pairs. These circulating wells will be converted to production over the next few months.



The table below shows gross monthly bitumen production volumes for the
current year.

----------------------------------------------------------------------------
Month Long Lake Monthly Bitumen Volumes Gross
(bbls/d)
----------------------------------------------------------------------------
January 2010 16,300
February 2010 17,700
March 2010 21,900
April 2010 24,400
May 2010 23,600
June 2010 26,900
July 2010-MTD 28,500
----------------------------------------------------------------------------


As we provide consistent steam to the reservoir, we are focusing on optimizing steam injection and individual well performance. To support increased well productivity, we have converted 54 wells from gas lift to electric submersible pumping and will convert the remainder, when appropriate. This offers more flexibility to optimize steam injection and grow bitumen production.

Our all-in steam-to-oil ratio (SOR) is between 5 and 6 and includes steam to wells that are still in the steam circulation stage and wells early in their growth cycle. As our circulating wells start producing bitumen, we expect to see an increase in production rates with a corresponding decrease in SOR. The SOR of our mature producing wells is now 4 and improving.

We continue to pursue inexpensive ways to add bitumen capacity since bitumen production in excess of upgrader capacity can be sold for an attractive return. As a result, we are continuing with the development of two additional well pads and have commenced engineering work to add two more once-through steam generators over the next 18 to 24 months. These steam generators can be added for a cost of about $100 million ($150 million gross).

"For a modest investment of less than 3% of total project capital, we have the opportunity to increase our steam capacity by 10 to 15%," said Romanow. "This additional capacity, combined with the two new well pads which add 20% to our existing well count starting in 2012, positions us well to be bitumen long."

Phase 1 of our Long Lake project is designed to produce 72,000 bbls/d of gross bitumen, upgraded to approximately 60,000 bbls/d (39,000 bbls/d, net to us) of PSCTM and will develop approximately 10% of our oil sands inventory. We are committed to the development of our oil sands leases and plan to develop Phase 2 in two smaller SAGD stages of about 40,000 bbls/d each with upgrading available after ramp up.

"Developing Phase 2 in smaller stages will result in better management of capital investment and reduce stress on material, equipment and labor markets," commented Romanow.

Global Exploration-No Material Impact from Drilling Moratorium in the Gulf

United States

The six month drilling moratorium in the Gulf of Mexico has no material impact on our current operations. Our shelf and deep-water production are unaffected and we continue to expect our Gulf of Mexico production for the year to average between 20,000 and 28,000 boe/d before royalties (17,000 and 25,000 boe/d after royalties).

At Knotty Head, we completed drilling an appraisal well before the moratorium. We are currently evaluating results, considering possible development choices and continuing our efforts to unitize our lands with adjacent acreage. No other drilling was planned in the near term. We are the operator of Knotty Head with a 25% working interest.

In the first quarter, we made a significant discovery in the deep-water at Appomattox, located in Mississippi Canyon blocks 391 and 392. This has the potential to be our best discovery in the Gulf of Mexico. Drilling activities resulted in a light oil discovery with excellent reservoir quality, following an exploration well and two appraisal sidetracks. Appomattox is the third discovery in the area following earlier discoveries at Shiloh and Vicksburg. Additional appraisal wells for Appomattox were being considered for later in the year but have been delayed as a result of the drilling moratorium. We continue to investigate development options for Appomattox and Vicksburg, located six miles east. We have a 25% interest in Vicksburg and a 20% interest in Appomattox and Shiloh. Shell Offshore Inc. operates all three discoveries.

Our plans to drill two additional exploration wells later this year with two new deep-water drilling rigs have been delayed by the drilling moratorium. The first deep-water rig, the Ensco 8501, completed drilling an appraisal well at Knotty Head and is currently being used by the third party we share the rig with. The second rig, the Ensco 8502, has arrived in the Gulf and is undergoing sea trials prior to its acceptance. The drilling moratorium and new regulations may delay rig acceptance.

"Although the moratorium has delayed our exploration program and the delineation of our discoveries, the timing impact of delays is not material as these are long-cycle time projects," commented Romanow. "To date, the moratorium has not resulted in any cash costs and for the remainder of the six month period, we expect our costs to be modest, if anything."

North Sea

During the quarter, we completed drilling a successful appraisal well at our Blackbird discovery, a potential tie-back to Ettrick. The well was drilled in a water depth of approximately 367 feet to a total measured depth of 12,000 feet and encountered light sweet oil in good quality Upper Jurassic reservoir sands. We are currently acquiring extensive wireline log and core data over the reservoir section for further analysis. Preliminary analysis suggests the well encountered a gross oil bearing section of approximately 330 feet, with a minimum net oil pay of approximately 75 feet. We plan to complete the well and drill stem test later this month. If successful, the well will be suspended for future use as an oil producer. We have a 79.73% operated interest here.

Elsewhere in the North Sea, the Golden Eagle area is a significant development opportunity for us. Our current estimate of recoverable contingent resource is 150 million boe or higher (over 55 million boe, net to us). We are in the process of completing the acquisition of additional acreage in the area and plan to drill an exploration well here later this year. Golden Eagle area development supports standalone facilities and is economic with oil prices significantly lower than they are currently. We are assessing development options for the area and will select an appropriate configuration for sanctioning in 2011. We have a 34% interest in both Golden Eagle and Hobby, a 46% interest in Pink, and operate all three.

At Buzzard, we have a number of opportunities to add reserves. In the northern part of the field, we are seeing more oil above the water contact which will lead to more recoverable oil. In the south, we plan to drill Bluebell, a possible extension of the Buzzard field. At Polecat, a previous discovery east of Buzzard, we plan to drill an appraisal well which could be tied back to the Buzzard platform.

West of the Shetland Islands, we are finalizing plans to drill the North Uist prospect. We have a 35% non-operated working interest here and expect to drill the well later this year. This prospect has a target size much larger than typical North Sea targets.

Conventional Development-Usan Development Continues

Offshore West Africa

Development of the Usan field is progressing well with first production expected in 2012. The development includes a floating production and storage offloading (FPSO) vessel with the ability to process 180,000 bbls/d (36,000 bbls/d net to us) and store up to two million barrels of oil. In June, major topside modules were lifted onto the FPSO deck and the FPSO unit is almost 80% complete. We have a 20% interest in exploration and development on this block and Total E&P Nigeria Limited is the operator.

We continue to explore offshore West Africa and previously announced a successful exploration well at Owowo in the southern portion of Oil Prospecting License (OPL) 223. We have an 18% interest in this discovery.

"Usan is a significant step-change in our production growth, adding 36,000 boe/d of the 70,000 boe/d that we expect to bring on stream over the next two years," stated Romanow. "As we move forward here, our success at Owowo makes us more optimistic about other exploration prospects."

Shale Gas-Fracing Eight-Well Program and Successful Land Acquisition

In the first quarter, we completed drilling our eight-well program in the Horn River and realized substantial cost savings and productivity improvements. Our average drilling days per well were under 25 days, down 35% from our previous program while drilling 80% more reservoir length. We recently began fracing these wells and plan to conduct 18 fracs per well. First production is expected before year end, ramping up to 50 mmcf/d in early 2011.

"Horn River is a top-tier gas play where we are successfully executing our plans and bringing unit costs down," commented Romanow. "Based on what we know today, this play is expected to earn a ten percent rate of return with gas prices at US$4/mcf."

As previously announced, we have approximately 90,000 acres at Dilly Creek in the Horn River basin and 38,000 acres at Cordova. Our Dilly Creek lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resource, assuming a 20% recovery factor. Following our success at a June land sale, we have increased our position from 128,000 to over 300,000 acres of highly prospective shale gas lands in northeast British Columbia.

"With this acquisition, we are now one of the largest shale gas players in the area," said Romanow. "We are excited about these lands given their significant resource potential, the excellent land tenure terms and the good rocks. The lands contain plays that are similar to those on our Horn River lands, where we are having great success."

Yemen

Yemen is an important asset for us and continues to generate cash flow in excess of capital requirements. In December 2011, our production sharing contract with the Yemen government expires. We are currently working on a possible contract extension.

Quarterly Dividend

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

Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are 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 deep-water 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 recoverable contingent shale gas and Golden Eagle area resource were provided in our press releases dated April 22, 2008 and September 3, 2009 respectively. Information with respect to forward-looking statements and cautionary notes is set out below.

Conference Call

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



Date: July 15, 2010
Time: 7:00am Mountain Time (9:00am Eastern Time)

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

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

A replay of the call will be available for two weeks starting at 9:00am
Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053
(toll-free) passcode 2655438 followed by the pound sign.


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

Forward-Looking Statements

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

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas and chemicals products; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; 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 operation 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; risk related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; direct and indirect risk related to the imposition of moratoriums, suspensions or cancellations on 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 of our agents and contractors; 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; and political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management's future course of action would depend on our assessment of all information at that time.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to Items 1A and 7A in our 2009 Annual Report on Form 10-K for further discussion of the risk factors.

Cautionary Note to US Investors

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

Cautionary Note to Canadian Investors

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Resources

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

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

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



Nexen Inc.
Financial Highlights

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Net Sales (1) 1,455 1,200 2,956 2,248
Cash Flow from Operations (1) 558 443 1,096 1,000
Per Common Share ($/share) 1.06 0.85 2.09 1.92
Net Income (1) 255 20 440 155
Per Common Share ($/share) 0.49 0.04 0.84 0.30
Capital Investment (2) 817 715 1,373 1,464
Net Debt (3) 5,471 5,889 5,471 5,889
Common Shares Outstanding
(millions of shares) 524.6 521.2 524.6 521.2
--------------------------------------

(1) Includes discontinued operations as discussed in Note 15 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 Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Oil & Gas
United Kingdom 655 552 1,326 982
Canada (2) 14 43 16 77
Syncrude 79 3 139 29
United States 58 41 136 53
Yemen (3) 82 78 181 165
Other Countries 4 8 10 17
Marketing 17 34 (42) 118
--------------------------------------
909 759 1,766 1,441
Chemicals 10 21 32 48
--------------------------------------
919 780 1,798 1,489
Interest and Other Corporate Items (136) (173) (261) (231)
Income Taxes (4) (225) (164) (441) (258)
--------------------------------------
Cash Flow from Operations (1) 558 443 1,096 1,000
--------------------------------------
--------------------------------------

(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 Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash Flow from Operating Activities 510 109 1,308 898
Changes in Non-Cash Working Capital 58 340 (198) (80)
Other 2 44 8 185
Impact of Annual Crude Oil Put Options (12) (50) (22) (3)
--------------------------------------
Cash Flow from Operations 558 443 1,096 1,000
--------------------------------------
--------------------------------------

Weighted-average Number of Common
Shares Outstanding
(millions of shares) 524.5 521.2 524.0 520.7
--------------------------------------
Cash Flow from Operations Per
Common Share ($/share) 1.06 0.85 2.09 1.92
--------------------------------------
--------------------------------------

(2) Includes discontinued operations as discussed in Note 15 to our
Unaudited Consolidated Financial Statements.
(3) After in-country cash taxes of $39 million for the three months ended
June 30, 2010 (2009 - $42 million) and $82 million for the six months
ended June 30, 2010 (2009 - $66 million).
(4) Excludes in-country cash taxes in Yemen.


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

Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 98.2 97.7 101.9 100.7
Canada (2) 13.1 14.9 13.7 15.1
Long Lake Bitumen 16.2 9.3 14.2 8.7
Syncrude 23.4 14.9 21.5 17.3
United States 9.9 12.1 9.8 11.2
Yemen 40.9 51.5 41.9 52.9
Other Countries 2.1 3.6 2.2 4.5
--------------------------------------
203.8 204.0 205.2 210.4
--------------------------------------
Natural Gas (mmcf/d)
United Kingdom 40 18 40 18
Canada (2) 128 136 130 138
United States 96 61 98 56
--------------------------------------
264 215 268 212
--------------------------------------

Total Production (mboe/d) 248 240 250 246
--------------------------------------
--------------------------------------


Production Volumes (after royalties)

Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 98.2 97.6 101.9 100.6
Canada (2) 10.0 11.2 10.4 11.8
Long Lake Bitumen 15.7 9.2 13.5 8.6
Syncrude 21.5 13.0 19.7 16.3
United States 8.9 10.9 8.9 10.2
Yemen 22.2 29.0 22.6 32.3
Other Countries 2.0 3.3 2.1 4.2
--------------------------------------
178.5 174.2 179.1 184.0
--------------------------------------

Natural Gas (mmcf/d)
United Kingdom 40 18 40 18
Canada (2) 117 129 119 127
United States 83 54 85 50
--------------------------------------
240 201 244 195
--------------------------------------

Total Production (mboe/d) 218 208 220 217
--------------------------------------
--------------------------------------

(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
15 to our Unaudited Consolidated Financial Statements.


Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Before Royalties
Crude Oil and NGLs (mbbls/d) 13.1 14.9 13.7 15.1
Natural Gas (mmcf/d) 11 13 11 15
After Royalties
Crude Oil and NGLs (mbbls/d) 10.0 11.2 10.4 11.8
Natural Gas (mmcf/d) 10 13 10 13
--------------------------------------


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

Total
Quarters - 2010 Quarters - 2009 Year
(all dollar amounts in ---------------------------------------------------
Cdn$ unless noted) 1st 2nd 1st 2nd 3rd 4th 2009
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil (US$/bbl) 78.71 78.03 43.08 59.62 68.30 76.19 61.80
Nexen Average - Oil
(Cdn$/bbl) 78.00 76.23 50.41 68.32 72.95 76.39 66.85
NYMEX Natural Gas
(US$/mmbtu) 5.04 4.34 4.48 3.81 3.44 4.91 4.16
Nexen Average - Gas
(Cdn$/mcf) 5.37 4.42 5.11 3.77 3.04 4.31 4.06
----------------------------------------------------------------------------

NETBACKS:
United Kingdom
Crude Oil:
Sales (mbbls/d) 106.5 102.1 100.8 97.0 70.4 119.6 96.9
Price Received ($/bbl) 77.25 77.18 51.60 69.42 73.15 76.40 67.70
Natural Gas:
Sales (mmcf/d) 33 41 21 17 17 43 24
Price Received ($/mcf) 4.81 4.80 5.50 3.67 2.64 3.82 3.95
Total Sales Volume (mboe/d) 112.1 109.0 104.3 99.8 73.2 126.8 101.0

Price Received ($/boe) 74.84 74.12 50.97 68.10 70.95 73.39 65.93
Operating Costs 7.60 7.71 5.48 5.85 10.34 6.77 6.87
----------------------------------------------------------------------------
Netback 67.24 66.41 45.49 62.25 60.61 66.62 59.06
----------------------------------------------------------------------------
Canada - Heavy Oil
Sales (mbbls/d) 14.0 13.1 15.4 14.7 14.0 13.5 14.4

Price Received ($/bbl) 65.26 57.24 35.35 56.05 59.88 62.53 53.04
Royalties & Other 14.47 13.23 6.86 12.83 13.47 14.07 11.70
Operating & Other Costs 15.81 16.02 15.42 16.41 16.21 16.73 16.17
----------------------------------------------------------------------------
Netback 34.98 27.99 13.07 26.81 30.20 31.73 25.17
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 124 121 137 134 136 130 134

Price Received ($/mcf) 5.02 3.72 4.75 3.42 2.85 4.14 3.78
Royalties & Other 0.40 0.34 0.59 0.15 0.21 0.34 0.32
Operating Costs 1.70 1.89 1.54 1.59 1.82 2.10 1.76
----------------------------------------------------------------------------
Netback 2.92 1.49 2.62 1.68 0.82 1.70 1.70
----------------------------------------------------------------------------
Long Lake (2)
Sales (mbbls/d) 6.6 10.3 - - - - -

Price Received ($/bbl) 81.04 74.08 - - - - -
Royalties & Other 4.37 3.65 - - - - -
Operating Costs 155.40 88.39 - - - - -
----------------------------------------------------------------------------
Netback (2) (78.73)(17.96) - - - - -
----------------------------------------------------------------------------
Netback including
Third-Party Bitumen (64.09)(10.27) - - - - -
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 19.5 23.4 19.8 14.9 22.5 23.7 20.2

Price Received ($/bbl) 83.55 77.93 55.48 71.58 74.54 79.83 70.96
Royalties & Other 7.09 6.37 0.40 8.84 8.31 6.75 6.04
Operating Costs 38.43 33.33 36.95 57.21 29.50 27.93 35.92
----------------------------------------------------------------------------
Netback 38.03 38.23 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.


Total
Quarters - 2010 Quarters - 2009 Year
(all dollar amounts in ---------------------------------------------------
Cdn$ unless noted) 1st 2nd 1st 2nd 3rd 4th 2009
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 9.8 9.9 10.4 12.1 9.5 10.0 10.5
Price Received ($/bbl) 79.12 73.60 46.27 66.23 72.27 75.75 65.01
Natural Gas:
Sales (mmcf/d) 101 95 50 61 63 84 65
Price Received ($/mcf) 6.00 5.14 5.93 4.58 3.56 4.83 4.67
Total Sales Volume (mboe/d) 26.60 25.80 18.8 22.2 20.0 23.9 21.2

Price Received ($/boe) 51.92 47.23 41.50 48.53 45.43 48.55 46.27
Royalties & Other 4.92 4.86 4.52 4.94 4.77 5.21 4.89
Operating Costs 8.96 10.90 13.79 13.11 12.40 11.32 12.58
----------------------------------------------------------------------------
Netback 38.04 31.47 23.19 30.48 28.26 32.02 28.80
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 47.3 39.3 54.7 51.4 43.2 46.2 48.8

Price Received ($/bbl) 80.39 80.50 52.30 69.40 76.31 78.93 68.49
Royalties & Other 37.52 36.65 19.43 31.94 32.08 33.71 28.94
Operating Costs 9.67 10.01 9.62 10.39 12.43 10.62 10.69
In-country Taxes 10.14 10.97 4.92 9.01 9.70 10.17 8.31
----------------------------------------------------------------------------
Netback 23.06 22.87 18.33 18.06 22.10 24.43 20.55
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 2.3 2.1 5.5 3.6 2.6 2.4 3.5

Price Received ($/bbl) 78.88 74.77 41.68 66.83 70.49 74.10 59.05
Royalties & Other 5.72 5.28 3.26 5.17 5.38 5.48 4.52
Operating Costs 5.58 7.42 4.81 5.73 5.70 9.52 6.03
----------------------------------------------------------------------------
Netback 67.58 62.07 33.61 55.93 59.41 59.10 48.50
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales (mboe/d) 251.1 235.7 241.4 228.9 198.2 258.1 231.6

Price Received ($/boe) 70.16 67.56 47.56 61.28 63.00 68.04 60.02
Royalties & Other 9.32 8.18 5.64 9.23 9.58 8.09 8.06
Operating & Other Costs (2) 15.17 15.07 10.62 11.95 13.60 10.86 11.66
In-country Taxes 1.91 1.76 1.11 2.02 2.11 1.82 1.75
----------------------------------------------------------------------------
Netback 43.76 42.55 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.
(2) 2010 includes Long Lake third-party bitumen purchases.


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

Three Months Six Months
(Cdn$ millions, except per share Ended June 30 Ended June 30
amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,399 1,138 2,831 2,142
Marketing and Other (Note 14) 164 82 315 339
-------------------------------------
1,563 1,220 3,146 2,481
-------------------------------------
Expenses
Operating 399 295 798 575
Depreciation, Depletion, Amortization
and Impairment 391 381 757 758
Transportation and Other 159 229 359 426
General and Administrative 70 161 184 255
Exploration 50 77 143 130
Interest (Note 9) 77 74 157 142
-------------------------------------
1,146 1,217 2,398 2,286
-------------------------------------
Income from Continuing Operations
before Provision for Income Taxes 417 3 748 195
-------------------------------------

Provision for (Recovery of) Income
Taxes
Current 264 206 523 324
Future (84) (228) (189) (309)
-------------------------------------
180 (22) 334 15
-------------------------------------

Net Income from Continuing Operations
before Non-Controlling Interests 237 25 414 180
Less: Net Income (Loss) Attributable
to Canexus
Non-Controlling Interests (5) 2 - 5
-------------------------------------
Net Income from Continuing Operations
Attributable to Nexen Inc. 242 23 414 175
Net Income (Loss) from Discontinued
Operations (Note 15) 13 (3) 26 (20)
-------------------------------------

Net income Attributable to Nexen Inc. 255 20 440 155
-------------------------------------
-------------------------------------
Earnings Per Common Share from
Continuing Operations ($/share)
(Note 16)
Basic 0.46 0.05 0.79 0.33
-------------------------------------
-------------------------------------

Diluted 0.46 0.05 0.79 0.33
-------------------------------------
-------------------------------------

Earnings Per Common Share ($/share)
(Note 16)
Basic 0.49 0.04 0.84 0.30
-------------------------------------
-------------------------------------

Diluted 0.49 0.04 0.84 0.30
-------------------------------------
-------------------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Balance Sheet

June 30 December 31
(Cdn$ millions, except share amounts) 2010 2009
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 970 1,700
Restricted Cash 113 198
Accounts Receivable (Note 2) 2,675 2,788
Inventories and Supplies (Note 3) 621 680
Other 106 185
------------------------
Total Current Assets 4,485 5,551
------------------------

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $10,129
(December 31, 2009 - $10,807) 15,755 15,492
Goodwill 343 339
Future Income Tax Assets 1,340 1,148
Deferred Charges and Other Assets (Note 5) 289 370
Assets Held for Sale (Note 15) 303 -
------------------------
Total Assets 22,515 22,900
------------------------
------------------------

Liabilities
Current Liabilities
Short-Term Borrowings (Note 9) 158 -
Accounts Payable and Accrued Liabilities (Note 8) 3,101 3,038
Accrued Interest Payable 89 89
Dividends Payable 26 26
------------------------
Total Current Liabilities 3,374 3,153
------------------------

Long-Term Debt (Note 9) 6,283 7,251
Future Income Tax Liabilities 2,891 2,811
Asset Retirement Obligations (Note 11) 859 1,018
Deferred Credits and Other Liabilities (Note 12) 879 1,021
Liabilities Associated with Assets Held for Sale
(Note 15) 149 -

Equity
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2010 - 524,565,491 shares
2009 - 522,915,843 shares 1,088 1,049
Contributed Surplus - 1
Retained Earnings 7,110 6,722
Accumulated Other Comprehensive Loss (189) (190)
------------------------
Total Nexen Inc. Shareholders' Equity 8,009 7,582
Canexus Non-Controlling Interests 71 64
------------------------
Total Equity 8,080 7,646
Commitments, Contingencies and Guarantees (Note 17)
------------------------
Total Liabilities and Equity 22,515 22,900
------------------------
------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


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

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Operating Activities
Net Income from Continuing Operations 237 25 414 180
Net Income (Loss) from Discontinued
Operations 13 (3) 26 (20)
Charges and Credits to Income not
Involving Cash (Note 18) 270 394 535 713
Exploration Expense 50 77 143 130
Changes in Non-Cash Working Capital
(Note 18) (58) (340) 198 80
Other (2) (44) (8) (185)
--------------------------------------
510 109 1,308 898

Financing Activities
Proceeds from Short-Term Borrowings 156 - 156 -
Proceeds from (Repayment of) Term
Credit Facilities, Net (1,077) 632 (1,077) 1,643
Proceeds from Canexus Term Credit
Facilities, Net 46 42 68 52
Dividends Paid on Common Shares (26) (26) (52) (52)
Distributions Paid to Canexus
Non-Controlling Interests (2) (4) (7) (7)
Issue of Common Shares and Exercise
of Tandem Options for Shares 10 7 35 30
Other (14) - (13) (1)
--------------------------------------
(907) 651 (890) 1,665

Investing Activities
Capital Expenditures
Exploration and Development (747) (631) (1,239) (1,335)
Proved Property Acquisitions - - - (755)
Energy Marketing, Chemicals,
Corporate and Other (70) (84) (134) (129)
Proceeds on Disposition of Assets 81 1 96 15
Changes in Non-Cash Working Capital
(Note 18) (13) (74) 75 (55)
Changes in Restricted Cash 68 67 83 (247)
Other (4) 1 (7) (1)
--------------------------------------
(685) (720) (1,126) (2,507)

Effect of Exchange Rate Changes on
Cash and Cash Equivalents 55 (120) (22) (85)
--------------------------------------

Decrease in Cash and Cash Equivalents (1,027) (80) (730) (29)

Cash and Cash Equivalents - Beginning
of Period 1,997 2,054 1,700 2,003
--------------------------------------

Cash and Cash Equivalents - End of
Period (1) 970 1,974 970 1,974
--------------------------------------
--------------------------------------

(1) Cash and cash equivalents at June 30, 2010 consist of cash of $237
million and short-term investments of $733 million (June 30, 2009 - cash
of $227 million and short-term investments of $1,747 million).

See accompanying notes to the Unaudited Consolidated Financial Statements.


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

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------

Common Shares, Beginning of Period 1,076 1,004 1,049 981
Issue of Common Shares 8 6 32 29
Exercise of Tandem Options for Shares 2 1 3 1
Accrued Liability Relating to Tandem
Options Exercised for Common Shares 2 - 4 -
-------------------------------------
Balance at End of Period 1,088 1,011 1,088 1,011
-------------------------------------

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

Retained Earnings, Beginning of Period 6,881 6,399 6,722 6,290
Net Income Attributable to Nexen Inc. 255 20 440 155
Dividends Paid on Common Shares (Note
13) (26) (26) (52) (52)
-------------------------------------
Balance at End of Period 7,110 6,393 7,110 6,393
-------------------------------------
-------------------------------------

Accumulated Other Comprehensive Loss,
Beginning of Period (201) (128) (190) (134)
Other Comprehensive Income (Loss)
Attributable to Nexen Inc. 12 (29) 1 (23)
-------------------------------------
Balance at End of Period (1) (189) (157) (189) (157)
-------------------------------------
-------------------------------------
(1) Comprised of unrealized foreign currency translation adjustment.

Canexus Non-Controlling Interests,
Beginning of Period 71 52 64 52
Net Income Attributable to
Non-Controlling Interests (6) 6 - 9
Distributions Paid to Non-Controlling
Interests (6) (5) (10) (9)
Issue of Partnership Units to
Non-Controlling Interests 12 1 17 2
-------------------------------------
Balance at End of Period 71 54 71 54
-------------------------------------
-------------------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.

Unaudited Consolidated Statement of Comprehensive Income
For the Three and Six Months Ended June 30

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. 255 20 440 155
Other Comprehensive Income (Loss),
Net of Income Taxes:
Foreign Currency Translation Adjustment
Net Gains (Losses) on Investment in
Self-Sustaining Foreign Operations 209 (459) 62 (285)
Net Gains (Losses) on
Foreign-Denominated
Debt Hedges of Self-Sustaining
Foreign Operations (1) (197) 430 (61) 262
-----------------------------------
Other Comprehensive Income (Loss)
Attributable to Nexen Inc. 12 (29) 1 (23)
-----------------------------------
Comprehensive Income (Loss) Attributable
to Nexen Inc. 267 (9) 441 132
-----------------------------------
-----------------------------------

(1) Net of income tax recovery for the three months ended June 30, 2010 of
$28 million (2009 - $62 million expense) and net of income tax recovery
for the six months ended June 30, 2010 of $8 million (2009 - $38 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). The impact of significant differences between Canadian and United States GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 20. 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 June 30, 2010 and December 31, 2009 and the results of our operations and our cash flows for the three and six months ended June 30, 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, 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. The results of operations and cash flows for the three and six months ended June 30, 2010 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2010. As at July 14, 2010, there are no material subsequent events requiring additional disclosure in or amendment to these financial statements.

These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 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

In early 2010, the Financial Accounting Standards Board issued guidance for Oil and Gas Reserve Estimation and Disclosure, which is effective for years ended December 31, 2009. The guidance expands the definition of oil and gas producing activities to: i) include unconventional sources such as oil sands; ii) change the price used in reserve estimation from the year-end price to the simple average of the first-day-of-the-month price for the previous 12 months, and iii) require 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 continuing operations for the three and six months ended June 30, 2010 increased by $11 million and $24 million, net income from continuing operations decreased by $7 million and $16 million, and earnings per common share decreased by $0.02/share and $0.04/share, respectively.



2. ACCOUNTS RECEIVABLE

June 30 December 31
2010 2009
----------------------------------------------------------------------------
Trade
Energy Marketing 1,515 1,410
Energy Marketing Derivative Contracts (Note 6) 260 466
Oil and Gas 793 823
Chemicals and Other 49 44
-------------------------
2,617 2,743
Non-Trade 111 99
-------------------------
2,728 2,842
Allowance for Doubtful Receivables (53) (54)
-------------------------
Total 2,675 2,788
-------------------------
-------------------------


3. INVENTORIES AND SUPPLIES

June 30 December 31
2010 2009
----------------------------------------------------------------------------
Finished Products
Energy Marketing 473 548
Oil and Gas 32 25
Chemicals and Other 10 12
-------------------------
515 585
Work in Process 7 7
Field Supplies 99 88
-------------------------
Total 621 680
-------------------------
-------------------------


4. SUSPENDED EXPLORATION WELL COSTS

The following table shows the changes in capitalized exploratory well costs during the six months ended June 30, 2010 and the year ended December 31, 2009, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Suspended exploration well costs are included in property, plant and equipment.



Six Months Ended Year Ended
June 30 December 31
2010 2009
----------------------------------------------------------------------------
Beginning of Period 794 518
Exploratory Well Costs Capitalized Pending
the Determination of Proved Reserves 206 396
Capitalized Exploratory Well Costs Charged
to Expense (2) (56)
Transfers to Wells, Facilities and
Equipment Based on Determination of Proved
Reserves (1) (21)
Effects of Foreign Exchange Rate Changes 7 (43)
--------------------------------
End of Period 1,004 794
--------------------------------
--------------------------------


The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and shows the number of projects for which exploratory well costs have been capitalized for a period greater than one year after the completion of drilling as at June 30, 2010.



Aging of Suspended United United
Exploration Wells Kingdom Canada States Nigeria Total
----------------------------------------------------------------------------
Less than 1 year 60 162 89 13 324
1-3 years 136 348 44 - 528
4-5 years 57 - 74 - 131
Greater than 5 years - - - 21 21
-------------------------------------------------
Total 253 510 207 34 1,004
-------------------------------------------------
-------------------------------------------------
Number of Wells
Capitalized for
Greater than One Year 8 13 2 1 12
-------------------------------------------------
-------------------------------------------------


As at June 30, 2010, we have exploratory costs that have been capitalized for more than one year relating to our shale gas exploratory activities in Canada ($348 million), interests in eight exploratory blocks in the North Sea ($193 million), two exploratory blocks in the Gulf of Mexico ($118 million), and our interest in an exploratory block offshore Nigeria ($21 million). These costs relate to projects with successful exploration wells for which we have not been able to recognize proved reserves. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or otherwise assess commercial viability.



5. DEFERRED CHARGES AND OTHER ASSETS

June 30 December 31
2010 2009
----------------------------------------------------------------------------
Long-Term Energy Marketing Derivative
Contracts (Note 6) 160 225
Defined Benefit Pension Assets 53 60
Long-Term Capital Prepayments 23 27
Other 53 58
-------------------------
Total 289 370
-------------------------
-------------------------


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 approximate 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 derivatives section in the following section details our derivatives and fair values as at June 30, 2010. The fair values are included with accounts 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. Related amounts posted as margin for exchange-traded positions are recorded in restricted cash.

We carry our long-term debt at amortized cost using the effective interest rate method. At June 30, 2010, the estimated fair value of our long-term debt was $6,736 million (December 31, 2009 - $7,594 million) as compared to the carrying value of $6,283 million (December 31, 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

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:



June 30 December 31
2010 2009
----------------------------------------------------------------------------
Commodity Contracts 260 463
Foreign Exchange Contracts - 3
-------------------------
Accounts Receivable (Note 2) 260 466
-------------------------

Commodity Contracts 160 225
-------------------------
Deferred Charges and Other Assets (Note 5)(1) 160 225
-------------------------

Total Trading Derivative Assets 420 691
-------------------------
-------------------------

Commodity Contracts 202 410
Foreign Exchange Contracts 6 46
-------------------------
Accounts Payable and Accrued Liabilities (Note 8) 208 456
-------------------------

Commodity Contracts 156 212
-------------------------
Deferred Credits and Other Liabilities
(Note 12) (1) 156 212
-------------------------

Total Trading Derivative Liabilities 364 668
-------------------------
-------------------------

Total Net Trading Derivative Contracts 56 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:

June 30 December 31
2010 2009
----------------------------------------------------------------------------
Current Trading Assets 1,687 2,625
Non-Current Trading Assets 511 716
-------------------------
Total Trading Derivative Assets 2,198 3,341
-------------------------
-------------------------

Current Trading Liabilities 1,635 2,615
-------------------------
Non-Current Trading Liabilities 507 703
-------------------------
Total Trading Derivative Liabilities 2,142 3,318
-------------------------
-------------------------

-------------------------
Total Net Trading Derivative Contracts 56 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 six months ended June 30, 2010, the following trading revenues were recognized in marketing and other income:



Three Months Six Months
Ended June 30 Ended June 30
2010 2010
----------------------------------------------------------------------------
Commodity 113 204
Foreign Exchange (1) (6)
-------------------------
Marketing Revenue 112 198
-------------------------
-------------------------


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 economic hedging and trading purposes. The absolute notional volumes associated with our derivative instrument transactions for the three and six months ended June 30, 2010, are as follows:



Three Months Six Months
Ended June 30 Ended June 30
2010 2010
----------------------------------------------------------------------------
Natural Gas bcf/d 5.5 9.1
Crude Oil mmbbls/d 3.6 3.4
Power GWh/d 0.5 0.9
Foreign Exchange US$ millions 834 1,621
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:

June 30 December 31
2010 2009
----------------------------------------------------------------------------
Accounts Receivable 2 13
Deferred Charges and Other Assets (1) - 4
-------------------------
Total Non-Trading Derivative Assets 2 17
-------------------------
-------------------------

Accounts Payable and Accrued Liabilities 13 26
-------------------------
Total Non-Trading Derivative Liabilities 13 26
-------------------------
-------------------------

Total Net Non-Trading Derivative Assets (2) (11) (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

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 and provide a base level of price protection without limiting our upside to higher prices. Options on 60,000 bbls/d settle monthly, while the remaining options settle annually. These options are recorded at fair value throughout their term. As a result, changes in forward crude oil prices create gains or losses on these options at each period end. Lower forward crude oil prices at June 30, 2010 compared to the end of the previous quarter increased the fair value of the options to approximately $2 million.



Change in Fair Value
----------------------
Three Six
Months Months
Average Ended Ended
Notional Floor Fair June 30, June 30,
Volumes Term Price Value 2010 2010
----------------------------------------------------------------------------
(bbls/d) (US$/bbl)
WTI Crude Oil Put
Options (monthly) 60,000 2010 50 2 1 (11)
WTI Crude Oil Put
Options (annual) 30,000 2010 50 - - (4)
----------------------------
2 1 (15)
----------------------------
----------------------------


Fixed-price natural gas contracts and natural gas swaps

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



Change in Fair Value
----------------------
Three Six
Months Months
Average Ended Ended
Notional Floor Fair June 30, June 30,
Volumes Term Price Value 2010 2010
----------------------------------------------------------------------------
(Gj/d) ($/Gj)
Fixed-Price Natural
Gas Contracts 15,514 2010 2.28 (3) - (4)
Natural Gas Swaps 15,514 2010 7.60 (10) - 4
-----------------------------
(13) - -
-----------------------------
-----------------------------


(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 June 30, 2010. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of 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 June 30, 2010 Level 1 Level 2 Level 3 Total
----------------------------------------------------------------------------
Commodity Contracts (85) 123 24 62
Foreign Exchange Contracts - (6) - (6)
---------------------------------------
Trading Derivatives (85) 117 24 56
Non-Trading Derivatives - (11) - (11)
---------------------------------------
Total (85) 106 24 45
---------------------------------------
---------------------------------------


A reconciliation of changes in the fair value of our derivatives classified
as Level 3 for the six months ended June 30, 2010 is provided below:


Level 3
----------------------------------------------------------------------------
Beginning of Period 42
Realized and Unrealized Gains (Losses) (5)
Purchases -
Settlements (13)
Transfers Into Level 3 -
Transfers Out of Level 3 -
---------
End of Period 24
---------
---------
Unsettled gains relating to instruments still
held as of June 30, 2010 (5)
---------
---------


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 June 30, 2010 would change by $12 million (December 31, 2009 - $12 million).

7. RISK MANAGEMENT

(a) Market risk

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

The following market risk discussion focuses on the 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.

i. 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 the 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 price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. We actively manage these risks by using derivative contracts such as commodity put options.

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

In order to manage the commodity and foreign exchange price risks that come from this physical business, we use financial derivative contracts including energy-related futures, forwards, swaps and options, as well as foreign 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 six months ended June 30, 2010 are as follows:



Three Months Six Months
Ended June 30 Ended June 30
Value-at-Risk 2010 2009 2010 2009
----------------------------------------------------------------------------
Period End 8 15 8 15
High 15 19 15 24
Low 7 13 7 13
Average 12 15 12 17
---------------------------------------


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

ii. Foreign currency risk

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

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

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

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

- short-term borrowings and long-term debt.

In our oil and gas operations, we manage our exposure to fluctuations between the US and Canadian dollar by matching 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 shareholders' equity. Our net investment in self-sustaining foreign operations and our designated US-dollar debt at June 30, 2010 and December 31, 2009 are as follows:



June 30 December 31
(US$ millions) 2010 2009
----------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign
Operations 4,513 4,492
Designated US-Dollar Debt 4,513 4,492
-------------------------


For the three and six months ended June 30, 2010, the ineffective portion of our US-dollar debt resulted in a net foreign exchange loss of $39 million and $18 million, respectively ($34 million and $16 million respectively, net of income tax expense) and is included in marketing and other income. A one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $45 million, net of income tax, and would increase or decrease our net income by approximately $5 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 may actively manage significant currency exposures using forward contracts and swaps.

(b) Credit risk

Credit risk affects our oil, gas and chemicals operations, and our trading and non-trading derivative activities, and is the risk of loss if counterparties do not fulfill their contractual obligations. Most of our credit exposure is with counterparties in the energy industry, including integrated oil companies, refiners and utilities, and are subject to normal industry credit risk. Approximately 81% 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 June 30, 2010, only two counterparties individually made up more than 10% of our credit exposure. These counterparties are major integrated oil companies with a strong investment grade credit rating. One other counterparty made up more than 5% of our credit exposure. The following table illustrates the composition of credit exposure by credit rating.



June 30 December 31
Credit Rating 2010 2009
----------------------------------------------------------------------------
A or higher 65% 67%
BBB 26% 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 $53 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 June 30, 2010 includes $1 million of cash and $302 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 June 30, 2010, we had approximately $3.8 billion of cash and available committed lines of credit. This includes approximately $1 billion of cash and cash equivalents on hand and undrawn term credit facilities of $2.8 billion, of which $336 million was supporting letters of credit at June 30, 2010. These facilities are available until 2014 unless extended. We also have about $467 million of uncommitted credit facilities, of which $158 million was drawn and $24 million was supporting letters of credit at June 30, 2010.

The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at June 30, 2010:



less greater
than 1-3 4-5 than
Total 1 Year Years Years 5 Years
----------------------------------------------------------------------------
Long-Term Debt 6,383 - 360 1,304 4,719
Interest on Long-Term Debt (1) 7,970 364 728 675 6,203
--------------------------------------------
Total 14,353 364 1,088 1,979 10,922
--------------------------------------------
--------------------------------------------

(1) Excludes interest on term credit facilities of $477 million (US$450
million) and Canexus term credit facilities of $307 million (US$289
million) as the amounts drawn on the facilities fluctuate. Based on
amounts drawn at June 30, 2010 and existing variable interest rates,
we would be required to pay $28 million per year until the outstanding
amounts on the term credit facilities are repaid.


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



less greater
than 1-3 4-5 than
Total 1 Year Years Years 5 Years
----------------------------------------------------------------------------
Trading Derivatives (Note 6) 364 208 139 17 -
Non-Trading Derivatives
(Note 6) 13 13 - - -
--------------------------------------------
Total 377 221 139 17 -
--------------------------------------------
--------------------------------------------


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 normally require collateral to be posted if an adverse credit-related event occurs, such as a drop in credit ratings to non-investment grade. Based on contracts in place and commodity prices at June 30, 2010, we could be required to post collateral of up to $785 million if we were downgraded to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral secures the payment of such amounts. In the event of a ratings downgrade, we have trading inventories and receivables that can be quickly monetized as well as undrawn credit facilities.

At June 30, 2010, collateral posted with counterparties includes $133 million of letters of credit related to our trading activities. Cash posted is included with our accounts receivable. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash is retained. Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits of $113 million (December 31, 2009 - $198 million), which have been included in restricted cash.



8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

June 30 December 31
2010 2009
----------------------------------------------------------------------------
Energy Marketing Payables 1,256 1,366
Energy Marketing Derivative Contracts (Note 6) 208 456
Accrued Payables 658 619
Trade Payables 198 210
Income Taxes Payable 449 179
Stock-Based Compensation 30 72
Other 302 136
-------------------------
Total 3,101 3,038
-------------------------
-------------------------


9. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

June 30 December 31
2010 2009
----------------------------------------------------------------------------
Canexus Term Credit Facilities, due 2012
(US$289 million drawn) (a) 307 233
Canexus Notes, due 2013 (US$50 million) 53 52
Notes, due 2013 (US$500 million) 530 523
Term Credit Facilities, due 2014 (US$450
million drawn) (b) 477 1,570
Canexus Convertible Debentures, due 2014 32 46
Notes, due 2015 (US$250 million) 265 262
Notes, due 2017 (US$250 million) 265 262
Notes, due 2019 (US$300 million) 318 314
Notes, due 2028 (US$200 million) 212 209
Notes, due 2032 (US$500 million) 530 523
Notes, due 2035 (US$790 million) 838 827
Notes, due 2037 (US$1,250 million) 1,326 1,308
Notes, due 2039 (US$700 million) 742 733
Subordinated Debentures, due 2043 (US$460
million) 488 481
-------------------------
6,383 7,343
Unamortized Debt Issue Costs (100) (92)
-------------------------
Total Long-Term Debt 6,283 7,251
-------------------------
-------------------------


(a) Canexus term credit facilities

Canexus has $451 million (US$425 million) of committed, secured term credit facilities available until August 2012. At June 30, 2010, $307 million (US$289 million) was drawn on these facilities (December 31, 2009 - $233 million (US$223 million)). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans or US-dollar base rate loans. Interest is payable monthly at floating rates. The term credit facilities are secured by a floating charge debenture over all of Canexus' assets. The credit facility also contains covenants with respect to certain financial ratios of Canexus. The weighted-average interest rate on the Canexus term credit facilities was 4.3% for the three months ended June 30, 2010 (three months ended June 30, 2009 - 2.1%) and 3.0% for the six months ended June 30, 2010 (six months ended June 30, 2009 - 2.4%).

(b) Term credit facilities

We have unsecured term credit facilities of $3.2 billion (US$3.1 billion) which are available until 2014. At June 30, 2010, $477 million (US$450 million) was drawn on these facilities (December 31, 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 1.3% for the three months ended June 30, 2010 (three months ended June 30, 2009 - 1.1%) and 1.1% for the six months ended June 30, 2010 (six months ended June 30, 2009 - 1.1%). At June 30, 2010, $336 million (US$317 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2009 - $407 million (US$389 million)).




(c) Interest expense

Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Long-Term Debt 94 89 188 178
Other 5 3 9 8
------------------------------------
Total 99 92 197 186
Less: Capitalized (22) (18) (40) (44)
------------------------------------
Total 77 74 157 142
------------------------------------
------------------------------------


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.

(d) Short-term borrowings

Nexen has uncommitted, unsecured credit facilities of approximately $467 million (US$446 million), of which $158 million (US$149 million) were drawn at June 30, 2010 (December 31, 2009 - nil). We also utilized $24 million (US$23 million) of these facilities to support outstanding letters of credit at June 30, 2010 (December 31, 2009 - $86 million (US$82 million)). Interest is payable at floating rates.

10. CAPITAL MANAGEMENT

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:



June 30 December 31
2010 2009
----------------------------------------------------------------------------
Net Debt (1)
Short-Term Borrowings 158 -
Long-Term Debt 6,283 7,251
-------------------------
Total Debt 6,441 7,251
Less: Cash and Cash Equivalents (970) (1,700)
-------------------------
Total 5,471 5,551
-------------------------
-------------------------

Equity (2) 8,080 7,646
-------------------------
-------------------------

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


We monitor the leverage in our capital structure by reviewing the ratio of net debt to adjusted cash flow (cash flow from operating activities before changes in non-cash working capital and other) and interest coverage ratios at various commodity prices. Net debt and adjusted cash flow are non-GAAP measures that are 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).

We use the ratio of net debt to adjusted cash flow as a key indicator of our leverage and to monitor the strength of our balance sheet. For the twelve months ended June 30, 2010, the net debt to adjusted cash flow was 2.3 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 identify specific actions 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 9.1 times at June 30, 2010. Interest coverage is calculated by dividing our 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.



Twelve Months Year Ended
Ended June 30 December 31
2010 2009
----------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. 821 536
Add:
Interest Expense 327 312
Provision for Income Taxes 595 260
Depreciation, Depletion, Amortization and
Impairment 1,771 1,802
Exploration Expense 315 302
Recovery of Non-Cash Stock-Based Compensation (93) (10)
Change in Fair Value of Crude Oil Put Options 71 251
Other Non-Cash Expenses (161) (136)
-------------------------
Adjusted EBITDA 3,646 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:

Six Months Year Ended
Ended June 30 December 31
2010 2009
----------------------------------------------------------------------------
Balance at Beginning of Period 1,053 1,059
Obligations Incurred with Development
Activities 23 27
Obligations Settled (15) (42)
Accretion Expense 33 70
Revisions to Estimates (35) 13
Obligations Reclassified to Liabilities
Associated with Assets Held for Sale (121) -
Effects of Changes in Foreign Exchange Rate (15) (74)
-------------------------
Balance at End of Period (1) (2) 923 1,053
-------------------------
-------------------------

(1) Obligations due within 12 months of $64 million (December 31, 2009 -
$35 million) have been included in accounts payable and accrued
liabilities.
(2) Obligations relating to our oil and gas activities amount to $889
million (December 31, 2009 - $1,002 million) and obligations relating to
our chemicals business amount to $34 million (December 31, 2009 - $51
million).



Our total estimated undiscounted inflated asset retirement obligations amount to $2,167 million (December 31, 2009 - $2,341 million). We discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted, risk-free rate of 5.9%. Approximately $215 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

June 30 December 31
2010 2009
----------------------------------------------------------------------------
Deferred Tax Credit 451 503
Long-Term Energy Marketing Derivative
Contracts (Note 6) 156 212
Defined Benefit Pension Obligations (1) 77 76
Capital Lease Obligations 43 61
Deferred Transportation Revenue 37 55
Other 115 114
-------------------------
Total 879 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 June 30, 2010 were $0.05 per common share (2009 - $0.05). Dividends per common share for the six months ended June 30, 2010 were $0.10 per common share (2009 - $0.10).Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.



14. MARKETING AND OTHER INCOME

Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Marketing Revenue, Net 112 221 198 488
Long Lake Purchased Bitumen Sales 10 - 38 -
Gain on Sale of Assets 83 1 80 8
Change in Fair Value of Crude Oil
Put Options 1 (179) (15) (195)
Interest 1 1 5 3
Foreign Exchange Gain (28) - 6 19
Other (1) (15) 38 3 16
---------------------------------------
Total 164 82 315 339
---------------------------------------
---------------------------------------

(1) Includes non-cash mark-to-market losses that will reverse with the sale
of North America Natural Gas Energy Marketing as described in Note 15.


15. ASSET DISPOSITIONS

Canadian Heavy Oil Properties

During the quarter, we signed an agreement to sell our heavy oil properties in Canada for proceeds of $975 million before closing adjustments. The sale is expected to close in the third quarter following receipt of regulatory approvals. On closing, we expect to realize a gain of over $750 million. The results of operations from these properties have been presented as discontinued operations. The properties are considered assets held for sale at June 30, 2010. The following tables provide the assets and liabilities that are associated with the heavy oil properties.



June 30
2010
----------------------------------------------------------------------------
Property, Plant and Equipment, Net of Accumulated DD&A 303
Asset Retirement Obligations (121)
Deferred Credits and Other Liabilities (28)
----------
Total 154
----------
----------


Discontinued operations from these assets are:

Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 56 62 125 106
------------------------------------

Expenses
Operating 22 25 45 50
Depreciation, Depletion,
Amortization and Impairment 12 32 34 64
General and Administrative 5 6 9 12
Transportation and Other - 3 2 7
------------------------------------
39 66 90 133
------------------------------------

Income (Loss) before Provision for
Income Taxes 17 (4) 35 (27)
Provision for (Recovery of) Future
Income Taxes 4 (1) 9 (7)
------------------------------------

Net Income (Loss) from Discontinued
Operations 13 (3) 26 (20)
------------------------------------
------------------------------------

Earnings (Loss) Per Common Share
Basic 0.03 (0.01) 0.05 (0.03)
------------------------------------
------------------------------------
Diluted 0.03 (0.01) 0.05 (0.03)
------------------------------------
------------------------------------


North America Natural Gas Energy Marketing

During the quarter, we signed an agreement to sell our North American natural gas marketing business. The transaction is expected to close in the third quarter, subject to customary closing conditions. The sale is expected to be cash neutral and we expect to recognize a non-cash loss on the sale of between $250 million and $290 million. On closing, the purchaser will acquire our North American natural gas business including our storage and transportation commitments, natural gas inventory, related financial and physical derivative positions, and margin collateral posted. In the period between signing and closing, we have agreements with the purchaser which transfers the market risk of our contracts and inventory to the purchaser unless we breach our obligation to close the sale. These agreements are derivative instruments carried at fair value on our balance sheet with gains and losses included in marketing and other income.

Canadian Undeveloped Oil Sand Leases

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

16. 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 Six Months
Ended June 30 Ended June 30
(millions of shares) 2010 2009 2010 2009
----------------------------------------------------------------------------
Weighted-average number of common
shares outstanding 524.5 521.2 524.0 520.7
Shares issuable pursuant to tandem
options 5.8 11.1 6.0 11.2
Shares notionally purchased from
proceeds of tandem options (4.1) (6.8) (4.4) (7.9)
----------------------------------------------------------------------------
Weighted-average number of diluted
common shares outstanding 526.2 525.5 525.6 524.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In calculating the weighted-average number of diluted common shares outstanding for the three and six months ended June 30, 2010, we excluded 16,556,303 and 16,516,379 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 six months ended June 30, 2009, we excluded 13,100,342 and 13,158,635 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.

17. 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 continue to believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations.

During the first quarter, we sold our European gas and power marketing business. We agreed to maintain our parental guarantees to the existing counterparties until the purchaser is able to replace them. At June 30, 2010, our total exposure is $71 million. The guarantees expire at the earlier of the purchaser replacing the guarantees and September 25, 2010. We are obligated to perform under the guarantees only if the purchaser does not meet its obligations to the counterparties. To eliminate our exposure under the guarantees, the purchaser has provided us an indemnity and an irrevocable letter of credit from a highly-rated financial institution.



18. CASH FLOWS

(a) Charges and credits to income not involving cash

Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Depreciation, Depletion,
Amortization and Impairment 391 381 757 758
Stock-Based Compensation (40) 42 (41) 42
Recovery of Future Income Taxes (84) (228) (189) (309)
Gain on Sale of Assets (83) (1) (80) (8)
Non-cash Items Included in
Discontinued Operations 16 31 43 57
Change in Fair Value of Crude Oil
Put Options (1) 179 15 195
Foreign Exchange 42 (24) 1 (37)
Other 29 14 29 15
-------------------------------------
Total 270 394 535 713
-------------------------------------
-------------------------------------


(b) Changes in non-cash working capital

Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Accounts Receivable (16) (471) (234) (173)
Inventories and Supplies (37) (80) 76 (129)
Other Current Assets 5 20 78 12
Accounts Payable and Accrued
Liabilities (30) 134 355 319
Other Current Liabilities 7 (17) (2) (4)
-------------------------------------
Total (71) (414) 273 25
-------------------------------------
-------------------------------------

Relating to:
Operating Activities (58) (340) 198 80
Investing Activities (13) (74) 75 (55)
-------------------------------------
Total (71) (414) 273 25
-------------------------------------
-------------------------------------


(c) Other cash flow information

Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Interest Paid 87 97 190 178
Income Taxes Paid 43 34 250 68
-------------------------------------
-------------------------------------


Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $17 million for the three months ended June 30, 2010 (2009 - $31 million) and $29 million for the six months ended June 30, 2010 (2009 - $43 million).

19. 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.



Three months ended June 30, 2010

Oil and Gas
----------------------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
-------------------------------------------------------
Net Sales 735 125 152 99 157 14
Marketing and Other 4 90 (2) 1 1 3 -
-------------------------------------------------------
Total Revenues 739 215 153 100 160 14

Less: Expenses
Operating 76 104 71 25 36 2
Depreciation,
Depletion,
Amortization and
Impairment 198 67 14 59 24 2
Transportation and
Other 4 37 4 - 3 -
General and
Administrative(4) - 2 - 13 (1) 3
Exploration 7 6 - 13 - 24 (5)
Interest - - - - - -
-------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 454 (1) 64 (10) 98 (17)
Less: Provision for
(Recovery Of)
Income Taxes 226 (1) 16 (3) 35 (15)
Less: Non-Controlling
Interests - - - - - -
Add: Net Income from
Assets
Held for Sale - 13 - - - -
-------------------------------------------------------
Net Income (Loss) 228 13 48 (7) 63 (2)
-------------------------------------------------------
-------------------------------------------------------

Identifiable Assets 4,601 8,117 (6) 1,293 1,750 248 1,254 (7)
-------------------------------------------------------
-------------------------------------------------------

Capital Expenditures
-------------------------------------------------------
Exploration &
Development 144 355 24 64 17 143
-------------------------------------------------------
-------------------------------------------------------

Property, Plant and
Equipment
Cost 6,418 8,433 1,504 4,071 2,521 1,169
Less: Accumulated
DD&A 3,032 769 292 2,679 2,414 102
-------------------------------------------------------
Net Book Value 3,386 7,664 (6) 1,212 1,392 107 1,067 (7)
-------------------------------------------------------
-------------------------------------------------------


Energy Corporate
Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 12 105 - 1,399
Marketing and Other 95 (7) (23) (3) 164
-----------------------------------------
Total Revenues 107 98 (23) 1,563

Less: Expenses
Operating 7 78 - 399
Depreciation,
Depletion,
Amortization and
Impairment 5 12 10 391
Transportation and
Other 89 14 8 159
General and
Administrative(4) 11 9 33 70
Exploration - - - 50
Interest - 2 75 77
-----------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes (5) (17) (149) 417
Less: Provision for
(Recovery Of)
Income Taxes (5) (4) (69) 180
Less: Non-Controlling
Interests - (5) - (5)
Add: Net Income from
Assets
Held for Sale - - - 13
-----------------------------------------
Net Income (Loss) - (8) (80) 255
-----------------------------------------
-----------------------------------------

Identifiable Assets 2,648 (8) 754 1,850 22,515
-----------------------------------------
-----------------------------------------

Capital Expenditures
-----------------------------------------
Exploration &
Development 7 53 10 817
-----------------------------------------
-----------------------------------------

Property, Plant and
Equipment
Cost 228 1,222 318 25,884
Less: Accumulated
DD&A 64 582 195 10,129
-----------------------------------------
Net Book Value 164 640 123 15,755
-----------------------------------------
-----------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes gain of $80 million from the sale of non-core lands in the
Athabasca region.
(3) Includes interest income of $1 million, foreign exchange losses of $28
million, an increase in the fair value of crude oil put options of $1
million and other gains of $3 million.
(4) Includes recovery of stock-based compensation expense of $35 million.
(5) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(6) Includes PP&E costs of $6,108 million related to our insitu oil sands
(Long Lake and future phases).
(7) Includes PP&E costs of $1,016 million related to Nigeria.
(8) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.


Three months ended June 30, 2009

Oil and Gas
----------------------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
--------------------------------------------------------
Net Sales 618 36 85 88 175 20
Marketing and Other 4 1 1 - 4 -
--------------------------------------------------------
Total Revenues 622 37 86 88 179 20

Less: Expenses
Operating 53 17 77 27 49 2
Depreciation,
Depletion,
Amortization and
Impairment 182 30 9 80 32 4
Transportation and
Other 14 5 5 3 15 -
General and
Administrative(3) 5 22 1 24 (3) 16
Exploration 11 8 - 37 - 21 (4)
Interest - - - - - -
--------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income
Taxes 357 (45) (6) (83) 86 (23)
Less: Provision for
(Recovery of)
Income Taxes 170 (12) (2) (28) 30 (18)
Less: Non-Controlling
Interests - - - - - -
Add: Net Loss from
Assets
Held for Sale - (3) - - - -
--------------------------------------------------------
Net Income (Loss) 187 (36) (4) (55) 56 (5)
--------------------------------------------------------
--------------------------------------------------------

Identifiable Assets 5,831 8,349 (5) 1,232 2,043 289 911 (6)
--------------------------------------------------------
--------------------------------------------------------

Capital Expenditures
--------------------------------------------------------
Exploration &
Development 158 191 22 72 22 166
--------------------------------------------------------
--------------------------------------------------------

Property, Plant and
Equipment Cost 6,500 9,411 1,407 4,270 2,715 723
Less: Accumulated
DD&A 2,414 1,899 251 2,680 2,549 116
--------------------------------------------------------
Net Book Value 4,086 7,512 (5) 1,156 1,590 166 607 (6)
--------------------------------------------------------
--------------------------------------------------------


Energy Corporate
Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 7 109 - 1,138
Marketing and Other 221 29 (178) (2) 82
-----------------------------------------
Total Revenues 228 138 (178) 1,220

Less: Expenses
Operating 8 62 - 295
Depreciation,
Depletion,
Amortization and
Impairment 3 29 12 381
Transportation and
Other 166 14 7 229
General and
Administrative(3) 26 16 54 161
Exploration - - - 77
Interest - 2 72 74
-----------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 25 15 (323) 3
Less: Provision for
(Recovery of)
Income Taxes 9 4 (175) (22)
Less: Non-Controlling
Interests - 2 - 2
Add: Net Loss from
Assets
Held for Sale - - - (3)
-----------------------------------------
Net Income (Loss) 16 9 (148) 20
-----------------------------------------
-----------------------------------------

Identifiable Assets 3,332 (7) 618 1,321 23,926
-----------------------------------------
-----------------------------------------

Capital Expenditures
-----------------------------------------
Exploration &
Development 3 72 9 715
-----------------------------------------
-----------------------------------------

Property, Plant and
Equipment Cost 259 1,005 349 26,639
Less: Accumulated
DD&A 83 507 223 10,722
-----------------------------------------
Net Book Value 176 498 126 15,917
-----------------------------------------
-----------------------------------------

(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $1 million and a decrease in the fair value
of crude oil put options of $179 million.
(3) Includes stock-based compensation expense of $56 million.
(4) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(5) Includes PP&E costs of $5,832 million related to our insitu oil sands
(Long Lake and future phases).
(6) Includes PP&E costs of $551 million related to Nigeria.
(7) Approximately 82% of Marketing's identifiable assets are accounts
receivable and inventories.


Six months ended June 30, 2010


Oil and Gas
----------------------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
--------------------------------------------------------
Net Sales 1,490 236 286 212 339 29
Marketing and Other 9 118 (2) 2 1 8 -
--------------------------------------------------------
Total Revenues 1,499 354 288 213 347 29

Less: Expenses
Operating 153 215 138 47 77 3
Depreciation,
Depletion,
Amortization and
Impairment 366 125 27 123 59 4
Transportation and
Other 3 91 11 2 6 -
General and
Administrative(4) 13 14 - 24 - 11
Exploration 31 13 - 29 - 70 (5)
Interest - - - - - -
--------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income Taxes 933 (104) 112 (12) 205 (59)
Less: Provision for
(Recovery of)
Income Taxes 466 (27) 28 (4) 72 (53)
Less: Non-Controlling
Interests - - - - - -
Add: Net Income from
Assets
Held for Sale - 26 - - - -
--------------------------------------------------------
Net Income (Loss) 467 (51) 84 (8) 133 (6)
--------------------------------------------------------
--------------------------------------------------------

Identifiable Assets 4,601 8,117 (6) 1,293 1,750 248 1,254 (7)
--------------------------------------------------------
--------------------------------------------------------

Capital Expenditures
--------------------------------------------------------
Exploration &
Development 273 493 43 128 27 275
--------------------------------------------------------
--------------------------------------------------------

Property, Plant and
Equipment Cost 6,418 8,433 1,504 4,071 2,521 1,169
Less: Accumulated
DD&A 3,032 769 292 2,679 2,414 102
--------------------------------------------------------
Net Book Value 3,386 7,664 (6) 1,212 1,392 107 1,067 (7)
--------------------------------------------------------
--------------------------------------------------------

Energy Corporate
Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 21 218 - 2,831
Marketing and Other 178 - (1) (3) 315
-----------------------------------------
Total Revenues 199 218 (1) 3,146

Less: Expenses
Operating 17 148 - 798
Depreciation,
Depletion,
Amortization and
Impairment 10 23 20 757
Transportation and
Other 212 26 8 359
General and
Administrative(4) 32 17 73 184
Exploration - - - 143
Interest - 3 154 157
-----------------------------------------
Income (Loss) from
Continuing
Operations
before Income Taxes (72) 1 (256) 748
Less: Provision for
(Recovery of)
Income Taxes (28) (120) 334
Less: Non-Controlling
Interests - - - -
Add: Net Income from
Assets
Held for Sale - - - 26
-----------------------------------------
Net Income (Loss) (44) 1 (136) 440
-----------------------------------------
-----------------------------------------

Identifiable Assets 2,648 (8) 754 1,850 22,515
-----------------------------------------
-----------------------------------------

Capital Expenditures
-----------------------------------------
Exploration &
Development 16 102 16 1,373
-----------------------------------------
-----------------------------------------

Property, Plant and
Equipment
Cost 228 1,222 318 25,884
Less: Accumulated
DD&A 64 582 195 10,129
-----------------------------------------
Net Book Value 164 640 123 15,755
-----------------------------------------
-----------------------------------------

(1) Includes results of operations from producing activities in Colombia.
(2) Includes gain of $80 million from the sale of non-core lands in the
Athabasca region.
(3) Includes interest income of $5 million, foreign exchange gains of $6
million, decrease in the fair value of crude oil put options of $15
million and other gains of $3 million.
(4) Includes recovery of stock-based compensation expense of $33 million.
(5) Includes exploration activities primarily in Norway and Colombia.
(6) Includes PP&E costs of $6,108 million related to our insitu oil sands
(Long Lake and future phases).
(7) Includes PP&E costs of $1,016 million related to Nigeria.
(8) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.


Six months ended June 30, 2009

Oil and Gas
----------------------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
--------------------------------------------------------
Net Sales 1,096 83 183 151 337 39
Marketing and Other 8 8 1 - 7 -
--------------------------------------------------------
Total Revenues 1,104 91 184 151 344 39

Less: Expenses
Operating 104 33 143 50 96 4
Depreciation,
Depletion,
Amortization and
Impairment 375 61 20 148 73 9
Transportation and
Other 11 4 12 16 18 -
General and
Administrative (3) 7 30 1 38 1 24
Exploration 19 29 - 47 - 35 (4)
Interest - - - - - -
--------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income Taxes 588 (66) 8 (148) 156 (33)
Less: Provision for
(Recovery of)
Income Taxes 256 (17) 2 (51) 54 (24)
Less: Non-Controlling
Interests - - - - - -
Add: Net Loss from
Assets
Held for Sale - (20) - - - -
--------------------------------------------------------
Net Income (Loss) 332 (69) 6 (97) 102 (9)
--------------------------------------------------------
--------------------------------------------------------

Identifiable Assets 5,831 8,349 (5) 1,232 2,043 289 911 (6)
--------------------------------------------------------
--------------------------------------------------------

Capital Expenditures
Exploration &
Development 335 531 39 140 51 239
Proved Property
Acquisitions - 755 - - - -
--------------------------------------------------------
Total 335 1,286 39 140 51 239
--------------------------------------------------------
--------------------------------------------------------

Property, Plant and
Equipment
Cost 6,500 9,411 1,407 4,270 2,715 723
Less: Accumulated
DD&A 2,414 1,899 251 2,680 2,549 116
--------------------------------------------------------
Net Book Value 4,086 7,512 (5) 1,156 1,590 166 607 (6)
--------------------------------------------------------
--------------------------------------------------------


Energy Corporate
Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 20 233 - 2,142
Marketing and Other 488 15 (188) (2) 339
-----------------------------------------
Total Revenues 508 248 (188) 2,481

Less: Expenses
Operating 16 129 - 575
Depreciation,
Depletion,
Amortization and
Impairment 7 41 24 758
Transportation and
Other 328 24 13 426
General and
Administrative (3) 49 25 80 255
Exploration - - - 130
Interest - 4 138 142
-----------------------------------------
Income (Loss) from
Continuing
Operations
before Income Taxes 108 25 (443) 195
Less: Provision for
(Recovery of)
Income Taxes 44 6 (255) 15
Less: Non-Controlling
Interests - 5 - 5
Add: Net Loss from
Assets
Held for Sale - - - (20)
-----------------------------------------
Net Income (Loss) 64 14 (188) 155
-----------------------------------------
-----------------------------------------

Identifiable Assets 3,332 (7) 618 1,321 23,926
-----------------------------------------
-----------------------------------------

Capital Expenditures
Exploration &
Development 11 108 10 1,464
Proved Property
Acquisitions - - - 755
-----------------------------------------
Total 11 108 10 2,219
-----------------------------------------
-----------------------------------------

Property, Plant and
Equipment Cost 259 1,005 349 26,639
Less: Accumulated
DD&A 83 507 223 10,722
-----------------------------------------
Net Book Value 176 498 126 15,917
-----------------------------------------
-----------------------------------------

(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $3 million, foreign exchange gains of $19
million, decrease in the fair value of crude oil put options of $195
million and other losses of $15 million.
(3) Includes stock-based compensation expense of $56 million.
(4) Includes exploration activities primarily in Norway and Colombia.
(5) Includes PP&E costs of $5,832 million related to our insitu oil sands
(Long Lake and future phases).
(6) Includes PP&E costs of $551 million related to Nigeria.
(7) Approximately 82% of Marketing's identifiable assets are accounts
receivable and inventories.


20. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statements and summaries of differences from Canadian GAAP are as follows:



Unaudited Consolidated Statement of Income - US GAAP
For the Three and Six Months Ended June 30

Three Months Six Months
(Cdn$ millions, except per share Ended June 30 Ended June 30
amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,399 1,138 2,831 2,142
Marketing and Other (v); (vi) 98 66 303 358
-------------------------------------
1,497 1,204 3,134 2,500
-------------------------------------

Expenses
Operating 399 295 798 575
Depreciation, Depletion, Amortization
and Impairment 391 381 757 758
Transportation and Other (v) 76 228 279 418
General and Administrative (iv) 50 191 172 293
Exploration 50 77 143 130
Interest 77 74 157 142
-------------------------------------
1,403 1,246 2,306 2,316
-------------------------------------

Income (Loss) from Continuing
Operations before Provision for Income
Taxes 454 (42) 828 184
-------------------------------------

Provision for (Recovery of) Income
Taxes
Current 264 206 523 324
Deferred (iv); (vi) (73) (241) (164) (309)
-------------------------------------
191 (35) 359 15
-------------------------------------

Net Income (Loss) from Continuing
Operations before Non-Controlling
Interests 263 (7) 469 169
Less: Net Income (Loss) Attributable
to Canexus Non Controlling Interests (5) 2 - 5
-------------------------------------

Net Income (Loss) from Continuing
Operations Attributable to Nexen Inc. 268 (9) 469 164

Net Income (Loss) from Discontinued
Operations 13 (3) 26 (20)
-------------------------------------
Net Income (Loss) Attributable to
Nexen Inc. - US GAAP (1) 281 (12) 495 144
-------------------------------------
-------------------------------------

Earnings (Loss) Per Common Share from
Continuing Operations ($/share)
Basic 0.51 (0.02) 0.89 0.31
-------------------------------------
-------------------------------------
Diluted 0.51 (0.02) 0.89 0.31
-------------------------------------
-------------------------------------

Earnings (Loss) Per Common Share
($/share)
Basic 0.54 (0.02) 0.94 0.28
-------------------------------------
-------------------------------------
Diluted 0.54 (0.02) 0.94 0.28
-------------------------------------
-------------------------------------

(1) Reconciliation of Canadian and US
GAAP Net Income Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Net Income Attributable to Nexen Inc -
Canadian GAAP 255 20 440 155
Impact of US Principles, Net of Income
Taxes:
Stock-based Compensation (iv) 15 (22) 9 (28)
Inventory Valuation (vi) 11 (10) 46 17
-------------------------------------
Net Income (Loss) Attributable to
Nexen Inc - US GAAP 281 (12) 495 144
-------------------------------------
-------------------------------------


Unaudited Consolidated Balance Sheet - US GAAP
June 30 December 31
(Cdn$ millions, except share amounts) 2010 2009
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 970 1,700
Restricted Cash 113 198
Accounts Receivable 2,675 2,788
Inventories and Supplies (vi) 619 610
Other 106 185
------------------------
Total Current Assets 4,483 5,481
------------------------

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $10,521 (December
31, 2009 - $11,200) (i); (iii) 15,706 15,443
Goodwill 343 339
Deferred Income Tax Assets 1,340 1,148
Deferred Charges and Other Assets 289 370
Assets Held for Sale 303 -
------------------------
Total Assets 22,464 22,781
------------------------
------------------------

Liabilities
Current Liabilities
Short-Term Borrowings 158 -
Accounts Payable and Accrued Liabilities (iv) 3,182 3,131
Accrued Interest Payable 89 89
Dividends Payable 26 26
------------------------
Total Current Liabilities 3,455 3,246
------------------------

Long-Term Debt 6,283 7,251
Deferred Income Tax Liabilities (i); (ii); (iv);
(vi); (vii) 2,825 2,720
Asset Retirement Obligations 859 1,018
Deferred Credits and Other Liabilities (ii) 984 1,126
Liabilities Associated with Assets Held for Sale 149 -

Equity
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2010 - 524,565,491 shares
2009 - 522,915,843 shares 1,088 1,049
Contributed Surplus - 1
Retained Earnings (i); (ii); (iv); (vi); (vii) 7,018 6,575
Accumulated Other Comprehensive Loss (ii) (268) (269)
------------------------
Total Nexen Inc. Shareholders' Equity 7,838 7,356
Canexus Non-Controlling Interests 71 64
------------------------
Total Equity 7,909 7,420
------------------------
Commitments, Contingencies and Guarantees
Total Liabilities and Equity 22,464 22,781
------------------------
------------------------

Unaudited Consolidated Statement of Comprehensive Income (Loss) - US GAAP
For the Three and Six Months Ended June 30

Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Net Income (Loss) Attributable to Nexen
Inc. - US GAAP 281 (12) 495 144
Other Comprehensive Income (Loss), Net
of Income Taxes:
Foreign Currency Translation Adjustment 12 (29) 1 (23)
-----------------------------------
Comprehensive Income (Loss) Attributable
to Nexen Inc. - US GAAP 293 (41) 496 121
-----------------------------------
-----------------------------------

Unaudited Consolidated Statement of Accumulated Other Comprehensive Loss -
US GAAP

June 30 December 31
2010 2009
----------------------------------------------------------------------------
Foreign Currency Translation Adjustment (189) (190)
Unamortized Defined Benefit Pension Plan Costs (ii) (79) (79)
------------------------
Accumulated Other Comprehensive Loss (268) (269)
------------------------
------------------------


Notes to the Unaudited Consolidated US GAAP Financial Statements:

i. Under Canadian GAAP, we deferred certain development costs to PP&E. Under US principles, these costs have been included in operating expenses in prior years. As a result, PP&E is lower under US GAAP by $30 million (December 31, 2009 - $30 million) and deferred income tax liabilities are lower by $11 million (December 31, 2009 - $11 million).

ii. US GAAP requires the recognition of the over-funded and under-funded status of a defined benefit plan on the balance sheet as an asset or liability. At June 30, 2010 and December 31, 2009, the unfunded amount of our defined benefit pension plans that was not included in the pension liability under Canadian GAAP was $105 million. This amount has been included in deferred credits and other liabilities and $79 million, net of income taxes, has been included in Accumulated Other Comprehensive Loss (AOCL).

iii. On January 1, 2003, we adopted Accounting for Asset Retirement Obligations for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004. These standards are consistent except for the adoption date which results in our PP&E under US GAAP being lower by $19 million.

iv. Under Canadian principles, we record obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. Under US principles, obligations for liability-based stock compensation plans are recorded using the fair-value method of accounting. In addition, under Canadian principles, we retroactively adopted EIC-162 which required the accelerated recognition of stock-based compensation expense for all stock-based awards made to our retired and retirement-eligible employees. However, US GAAP required the accelerated recognition of stock-based compensation expense for such employees for awards granted on or after January 1, 2006. As a result under US GAAP:

- general and administrative (G&A) expense is lower by $20 million and $12 million, ($15 million and $9 million, net of income taxes), for the three and six months ended June 30, 2010, (2009 - higher by $30 million and $38 million, respectively, ($22 million and $28 million, net of income taxes)); and

- accounts payable and accrued liabilities are higher by $81 million as at June 30, 2010 (December 31, 2009 - $93 million).

v. Under US GAAP, asset disposition gains and losses are included with transportation and other expense. Gains of $83 million and $80 million for the three and six months ended June 30, 2010, respectively, were reclassified from marketing and other income to transportation and other expense (gains of $1 million and $8 million, respectively were reclassified for the three and six months ended June 30, 2009).

vi. Under Canadian GAAP, we carry our commodity inventory held for trading purposes at fair value, less any costs to sell. Under US GAAP, we are required to carry this inventory at the lower of cost or net realizable value. As a result:
- marketing and other income is higher by $17 million and $68 million ($11 million and $46 million, net of income taxes) for the three and six months ended June 30, 2010 (2009 - lower by $15 million and higher by $27 million ($10 million and $17 million, net of income taxes)); and

- inventories are lower by $2 million as at June 30, 2010 (December 31, 2009 - lower by $70 million) and deferred income tax liabilities are $1 million lower (December 31, 2009 - lower by $23 million).

vii. Under US GAAP, we are required to apply FIN48 Accounting for Uncertainty in Income Taxes regarding accounting and disclosure for uncertain tax positions.

As at June 30, 2010, the total amount of our unrecognized tax benefit was approximately $284 million, all of which, if recognized, would affect our effective tax rate. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the Unaudited Consolidated Statement of Income. As at June 30, 2010, the total amount of interest and penalties related to uncertain tax positions recognized in deferred income tax liabilities in the US GAAP - Unaudited Consolidated Balance Sheet was approximately $8 million. We had no interest or penalties included in the US GAAP - Unaudited Consolidated Statement of Income for the three and six months ended June 30, 2010.

Our income tax filings are subject to audit by taxation authorities and as at June 30, 2010 the following tax years remained subject to examination, (i) Canada - 1985 to date (ii) United Kingdom - 2008 to date and (iii) United States - 2005 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next 12 months.

New Accounting Pronouncements - US GAAP

In January 2010, the Financial Accounting Standards Board issued guidance to improve financial instrument fair value measurement disclosures. The guidance requires entities to describe transfers between the three levels of the fair value hierarchy and present items separately in the level 3 reconciliation. This guidance is consistent with fair value measurement disclosures adopted for Canadian GAAP in 2009. Adoption of this guidance did not have an impact on our results of operations or financial position.

Contact Information

  • Michael J. Harris, CA
    Vice President, Investor Relations
    (403) 699-4688
    or
    Lavonne Zdunich, CA
    Manager, Investor Relations
    (403) 699-5821
    or
    Tim Chatten, P.Eng
    Analyst, Investor Relations
    (403) 699-4244
    or
    Pierre Alvarez
    Vice President, Corporate Relations
    (403) 699-6291
    or
    Kevin Reinhart, CA
    Executive Vice President and CFO
    (403) 699-5931
    or
    Nexen Inc.
    801 - 7th Ave SW
    Calgary, Alberta, Canada T2P 3P7
    www.nexeninc.com