form8k_042710.htm

For immediate release

Nexen Announces Ongoing Execution Success and First Quarter Results

Calgary, Alberta, April 27, 2010 – Nexen Inc. announces continued success executing on its three strategies. On the conventional side of our business, we had a major oil discovery at Appomattox in the Eastern Gulf of Mexico. When we combine this with our recent exploration successes at Golden Eagle in the North Sea, and Owowo, offshore West Africa, we have delivered significant discoveries in all of our core conventional areas. At our Long Lake oil sands project, we are steadily climbing the growth curve, achieving new record bitumen production volumes each month as we increase steam volumes. In the Horn River, we finished drilling our eight-well shale gas program and realized further cost improvements. All of this success is contributing to the visible growth we have coming - Horn River shale gas, Usan in 2012, Golden Eagle in 2014 and then Appomattox, Owowo and future phases of Long Lake. Our 85% weighting to crude oil is driving our industry-leading netbacks resulting in superior returns for every dollar we invest.

Recent highlights include:

·	First quarter cash flow of $538 million ($1.03/share)

·	Quarterly earnings of $185 million ($0.35/share)

·	Quarterly production before royalties of 252,000 boe/d (221,000 boe/d after royalties)

·	Long Lake bitumen production volumes consistently increasing each month since turnaround as steam volumes grow

·	Significant oil discovery at Appomattox in the Gulf of Mexico

·	Successfully finished drilling our eight well shale gas program in the Horn River

·	Completed sale of European marketing business and substantially completed negotiations for the sale of our North American gas marketing business

	Three Months Ended				Three Months Ended
	March 31				December 31
(Cdn$ millions)	2010		2009			2009
Production (mboe/d)
Before Royalties		252		252		265
After Royalties		221		225		235
Net Sales		1,501		1,048		1,550
Cash Flow from Operations1		538		557		836
Per Common Share ($/share)1		1.03		1.07		1.60
Net Income (Loss)		185		135		259
Per Common Share ($/share)		0.35		0.26		0.50
Capital Investment2,3		568		1,516		645
Net Debt4		5,057		5,737		5,551

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.

Financial Results

Quarterly cash flow from operations was $538 million and net income was $185 million. With the increase in WTI, our average realized oil and gas price increased 48% over the same quarter last year to $70/boe. Since 85% of our production is weighted to oil, we continue to benefit from increasing oil prices. Quarterly cash flow was reduced by Long Lake accounting and reported results from marketing.

With consistent and improving performance at Long Lake, we are no longer capitalizing start up results. As a result, we expensed an operating loss in the quarter and expect Long Lake to make positive cash flow contributions later this year as our growth continues.

Marketing’s results for the quarter reflect losses from the impact of softening gas prices on our transportation contracts and on the reported value of our gas inventories. These losses partially offset related gains reported in the previous quarter. We have substantially completed negotiations for the sale of our North American natural gas marketing business and we expect the disposition to close in the third quarter.

Compared to the previous quarter, our production volumes and financial results were impacted by temporary downtime at Buzzard, Ettrick and Syncrude.

Quarterly Production

	Quarterly Production before Royalties			Quarterly Production after Royalties

Crude Oil, NGLs and Natural Gas (mboe/d)		Q1 2010	Q4 2009		Q1 2010	Q4 2009
North Sea		112	124		112	124
Yemen		43	45		23	26
Canada – Oil & Gas		36	37		31	31
United States		27	24		24	21
Canada – Syncrude		20	24		18	22
Canada – Bitumen		12	9		11	9
Other Countries		2	2		2	2
Total		252	265		221	235

First quarter production volumes averaged 252,000 boe/d (221,000 boe/d after royalties) as volumes were temporarily impacted by downtime at Buzzard, Ettrick and Syncrude. At Buzzard, volumes were lower as repairs were made to the separator unit. Buzzard production averaged 197,000 boe/d gross (85,000 boe/d net to us) for the first quarter compared to typical rates of approximately 210,000 boe/d gross. In the second quarter, further activities are planned to permanently repair the separator unit. This downtime will coincide with our planned two week shutdown to install the topsides of the fourth platform. At Ettrick, production was primarily impacted by commissioning activities and a two week shut-in for rig moves relating to drilling and completion activities in the area. Ettrick production has been restored, is currently produci ng at rates around 20,000 boe/d gross (16,000 boe/d net to us) and continues to ramp up.

At Syncrude, production was lower than the previous quarter as a turnaround of the LC finer originally planned for the second quarter was advanced to January. The turnaround was completed in mid March. A coker turnaround is scheduled at Syncrude in the third quarter.

“We are currently producing approximately 270,000 boe/d but have scheduled downtime later this quarter at Buzzard,” commented Marvin Romanow, Nexen’s President and Chief Executive Officer. “Once this second quarter downtime is behind us, we are well positioned for strong volumes in the second half of the year as we continue to grow new production at Long Lake, Ettrick and in the Horn River.”

Long Lake—Bitumen Volumes Consistently Growing

Since the completion of the turnaround last fall, bitumen volumes have been consistently growing. Long Lake’s gross bitumen production has grown from 14,000 bbls/d in the fourth quarter of 2009 to 19,000 bbls/d in the first quarter of 2010. In March, bitumen production averaged 22,000 bbls/d and we are currently producing approximately 25,000 bbls/d and are seeing production increases from both new wells and from optimization of mature producers. This represents an 80% increase over average pre-turnaround rates.

The table below shows gross bitumen production volumes since the turnaround.

Month	Long Lake Monthly Bitumen Volumes Gross (bbls/day)
October 2009	8,600
November 2009	15,200
December 2009	16,200
January 2010	16,300
February 2010	17,700
March 2010	21,900
April 2010-MTD	24,200

Production growth reflects significant improvement in steam reliability since the turnaround and steam rates are at all-time highs of about 140,000 bbls/d and increasing. This represents a 100% increase over pre-turnaround rates. As a result, we are injecting more steam into more wells than ever before with 64 well pairs now on production and steam circulating in an additional 15 pairs. These circulating wells will be converted to production over the next few months.

Our all-in steam-to-oil ratio (SOR) is between 5 and 6 but this 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 bitumen production rates with a corresponding decrease in SOR. The SOR of our producing wells is approximately 5, and includes well pairs recently converted to production that are in the early stages of ramp up. We continue to expect a long term SOR of 3.0 over the life of the project.

“Long Lake is performing well since the turnaround last September. Steam and bitumen production volumes have steadily grown each month and this upward trend continues,” stated Romanow. “As we provide consistent steam to the reservoir, we are focusing on optimizing steam injection and individual well performance. To advance well productivity, we have converted over 50% of our wells from gas lift to electric submersible pumping and expect to have about 80% converted by year end. This offers more flexibility to optimize steam injection and grow bitumen production.”

The upgrader facility is also performing consistently. Since the turnaround, the upgrader has experienced 90% uptime, compared to 50% before and is producing high quality premium synthetic crude (PSCTM). For the quarter, our realized price for Long Lake PSCTM averaged over $81/bbl. 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.

Global Exploration—Another Significant Discovery

United States

During the quarter, we made a significant discovery in the Eastern Gulf of Mexico at Appomattox, located in Mississippi Canyon blocks 391 and 392. Drilling activities resulted in an oil discovery with excellent reservoir quality, following an exploration well and two appraisal sidetracks. The discovery well, located in 7,217 feet of water, was drilled to a depth of 25,077 feet true vertical depth and encountered approximately 530 feet gross (425 feet net) true vertical thickness of oil pay. An appraisal sidetrack was drilled to approximately 25,950 feet true vertical depth and encountered approximately 380 feet (360 feet net) true vertical thickness of oil pay. The second sidetrack was undertaken to further delineate the discovery. Well results have exceeded our pre-drill expectations.

Appomattox is the third discovery in the area following earlier discoveries at Shiloh and Vicksburg. Additional appraisal wells for Appomattox are planned for later in the year and we are investigating 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.

"Initial estimates of the Appomattox discovery support development of a regional hub and we are actively appraising results,” commented Romanow. “This is light sweet oil from a reservoir with excellent characteristics leading to strong productivity. The discovery increases our excitement regarding our other exploration prospects in the area, where we have a strong regional land position.”

Elsewhere in the deep-water, we completed drilling an appraisal well at Knotty Head and are currently evaluating results and possible development choices. Drilling operations with our new deep-water rig exceeded expectations. We completed the well in approximately 15% less time than expected and 20% below planned cost. We are continuing our efforts to unitize our lands with adjacent acreage. We are operator of Knotty Head with a 25% working interest. A second deep-water drilling rig is expected to arrive later this year which will allow us to start drilling our other identified prospects.

North Sea

The Golden Eagle area has emerged as 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 land in the area and plan to drill an exploration well here mid-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 conf iguration prior to sanctioning in 2011. We have a 34% interest in both Golden Eagle and Hobby, a 46% interest in Pink, and operate all three.

West of the Shetland Islands, we are finalizing plans to drill the North Uist prospect. We have a 35% working interest here and expect to drill the well in the second half of 2010. This prospect has a target size much larger than typical North Sea targets. BP is the operator with a 45% working interest.

“We continue to build our strategic advantage in the North Sea,” commented Romanow. “With no near-term decline expected at Buzzard, significant discoveries to develop, strategic land positions and numerous exploration and appraisal wells to be drilled, we expect to advance our leading position with even more growth in the next five to ten years.”

Conventional Development—Usan Development Continues

Offshore West Africa

Development of the Usan field, offshore West Africa, is progressing well with first production expected in 2012. The development includes a Floating Production and Storage Offloading vessel (FPSO) with the ability to process 180,000 bbls/d (36,000 bbls/d net to us) and store up to two million barrels of oil. 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. Other exploration prospects are under evaluation for drilling.

Horn River Shale Gas—Successfully Finished Drilling Eight-Well Program

We have finished drilling our eight-well program and continue to make significant progress on lowering costs and gaining access to the shale reservoir on our substantial Horn River shale gas position in north-east British Columbia. We plan to complete these wells in the second half of the year with 18 fracs per well. First production is expected before year end, ramping up to 50 mmcf/d.

Substantial cost savings and productivity improvements were realized with this drilling program and our average drilling days per well were under 25 days, down 35% over our previous pad. We currently expect that with an 18 well program we could reduce our all-in costs even further to under $0.6 million per frac.

As previously announced, we estimate our Dilly Creek lands in the Horn River basin 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. Our production results to date, together with those of our competitors, indicate that recovery factors will be higher. Additional production history will determine recovery factors and further appraisal activity is required before we can finalize resource estimates.

“I am pleased with the progress we are making in shale gas,” said Romanow. “We are successfully executing our drilling plans and bringing unit costs down. With a substantial land position and favorable land tenure terms, we are in excellent position to control the pace of development and maximize the value of this resource.”

Disposition Update

As announced in December 2009, we identified a number of non-core assets for possible disposal, including parts of our marketing business, our heavy oil assets in Western Canada and our interest in the Canexus chemicals business. We are confident that the disposition of these non-core assets will generate over $1 billion in the next 12 to 18 months with timing dependent on market conditions.

We have successfully sold our European gas and power marketing business for $15 million of cash proceeds. We have substantially completed negotiations for the sale of our North American natural gas marketing business subject to finalizing documentation and customary closing conditions. We expect to sign the agreement in the second quarter and close the sale in the third quarter. The sale is expected to be cash neutral and we expect to recognize a non-cash loss on the sale of between $250 to $290 million. This loss primarily relates to the transfer of long-term natural gas physical transportation commitments that are less valuable with increased gas supplies that reduce the need for transportation services. Although volatile on a quarterly basis, we have had great success with our marketing business over the last 10 years generating about $800 million of free cash.

“To maximize shareholder value, assets that are no longer aligned with our main areas of focus will be monetized,” said Romanow. “The sale of parts of our marketing business is almost complete and we have opened data rooms for our heavy oil assets which we expect to sell mid-year. The gains we expect to book from the sale of our heavy oil assets and Canexus will significantly exceed the loss on the closing of the marketing sale.”

Delivering on Execution

We are executing on our strategies with significant success. We have had major discoveries in each of our three key conventional basins—Golden Eagle area in the North Sea, Appomattox in the Eastern Gulf of Mexico and Owowo, offshore West Africa. At Long Lake we are consistently making progress. We are generating more steam than ever before, bitumen volumes are at all time highs and the upgrader is operating reliably producing high quality synthetic crude. In the Horn River, we continue to make significant steps in lowering our costs and we are executing our programs in line with or better than competitors in the area.

“We are generating value and are well positioned for growth,” stated Romanow. “Our industry-leading netbacks are driving superior returns for every dollar we invest. When you combine this with visible growth coming from several identified projects such as Horn River shale gas, Usan in 2012, Golden Eagle two years after that and then Appomattox, Owowo and future phases of Long Lake, the value proposition for Nexen shareholders is significant. In the next few years, we have approximately 70,000 bbls/day of new production coming on as we grow Long Lake and bring Usan on stream.”

Quarterly Dividend

The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable July 1, 2010, to shareholders of record on June 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.

For investor relations inquiries, please contact:

Michael J. Harris, CA

Vice President, Investor Relations

(403) 699-4688

Lavonne Zdunich, CA

Manager, Investor Relations

(403) 699-5821

Tim Chatten, P.Eng

Analyst, Investor Relations

(403) 699-4244

801 – 7th Ave SW

Calgary, Alberta, Canada T2P 3P7

www.nexeninc.com

For media and general inquiries, please contact:

Pierre Alvarez

Vice President, Corporate Relations

(403) 699-5560

Kevin Reinhart, CA

Senior Vice President and CFO

(403) 699-5931

Conference Call

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

Date: April 27, 2010

Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time)

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

416-695-6616 (Toronto)

800-766-6630 (North American toll-free)

800-4222-8835 (Global toll-free)

A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 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, 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 matter s and dates by which certain areas will be developed, come on stream, or reach expected operating capacity and changes in any of the foregoing are forward-looking statements. Statements relating to “reserves” or “resources” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas and chemicals products; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; volatility in energy trading markets; foreign-currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environment al and other laws and regulations; renegotiations of contracts; results of

litigation, arbitration or regulatory proceedings; and political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management’s future course of action would depend on our assessment of all information at that time.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to Items 1A and 7A in our 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, stakehol der 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 Ended March 31
(Cdn$ millions)	2010	2009

Net Sales	1,501	1,048
Cash Flow from Operations	538	557
Per Common Share ($/share)	1.03	1.07
Net Income	185	135
Per Common Share ($/share)	0.35	0.26
Capital Investment 1	556	1,504
Net Debt 2	5,057	5,737
Common Shares Outstanding (millions of shares)	524.0	520.8

1	Includes oil and gas development, exploration, and expenditures for other property, plant and equipment.

2	Net debt is defined as long-term debt and short-term borrowings less cash and cash equivalents.

Cash Flow from Operations1

	Three Months Ended March 31
(Cdn$ millions)	2010	2009
Oil & Gas
United Kingdom	671	430
Canada	60	34
Long Lake	(58)	–
Syncrude	60	26
United States	78	12
Yemen 2	99	87
Other Countries	6	9
Marketing	(59)	84
	857	682
Chemicals	22	27
	879	709
Interest and Other Corporate Items	(125)	(58)
Income Taxes 3	(216)	(94)
Cash Flow from Operations 1	538	557

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 Ended March 31
(Cdn$ millions)	2010			2009
Cash Flow from Operating Activities		798			789
Changes in Non-Cash Working Capital		(256	)		(420	)
Other		6			141
Impact of Annual Crude Oil Put Options		(10	)		47
Cash Flow from Operations		538			557

Weighted-average Number of Common Shares Outstanding (millions of shares)		523.6			520.2
Cash Flow from Operations Per Common Share ($/share)		1.03			1.07

2	After in-country cash taxes of $43 million for the three months ended March 31, 2010 (2009 – $24 million).

3	Excludes in-country cash taxes in Yemen.

Nexen Inc.

Production Volumes (before royalties) 1

	Three Months Ended March 31
	2010	2009
Crude Oil and Liquids (mbbls/d)
United Kingdom	105.6	103.8
Canada	14.2	15.5
Long Lake Bitumen	12.1	8.1
Syncrude	19.5	19.8
United States	9.8	10.4
Yemen	42.8	54.5
Other Countries	2.3	5.5
	206.3	217.6
Natural Gas (mmcf/d)
United Kingdom	40	18
Canada	133	137
United States	101	50
	274	205

Total Production (mboe/d)	252	252

Production Volumes (after royalties)

	Three Months Ended March 31
	2010	2009
Crude Oil and Liquids (mbbls/d)
United Kingdom	105.6	103.8
Canada	11.0	12.3
Long Lake Bitumen	11.3	8.1
Syncrude	17.8	19.6
United States	8.9	9.5
Yemen	23.1	35.7
Other Countries	2.1	5.1
	179.8	194.1
Natural Gas (mmcf/d)
United Kingdom	40	18
Canada	121	122
United States	88	45
	249	185

Total Production (mboe/d)	221	225

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

Nexen Inc.

Oil and Gas Prices and Cash Netback 1

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

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

Price Received ($/boe)		74.84			50.97		68.10		70.95		73.39		65.93
Operating Costs		7.60			5.48		5.85		10.34		6.77		6.87
Netback		67.24			45.49		62.25		60.61		66.62		59.06
Canada – Heavy Oil & Bitumen 2
Sales (mbbls/d)		22.62			15.4		14.7		14.0		13.5		14.4

Price Received ($/bbl)		71.24			35.35		56.05		59.88		62.53		53.04
Royalties & Other		10.27			6.86		12.83		13.47		14.07		11.70
Operating & Other Costs 3		67.57			15.42		16.41		16.21		16.73		16.17
Netback		(6.60	)		13.07		26.81		30.20		31.73		25.17
Canada – Natural Gas
Sales (mmcf/d)		124			137		134		136		130		134

Price Received ($/mcf)		5.02			4.75		3.42		2.85		4.14		3.78
Royalties & Other		0.40			0.59		0.15		0.21		0.34		0.32
Operating Costs		1.70			1.54		1.59		1.82		2.10		1.76
Netback		2.92			2.62		1.68		0.82		1.70		1.70
Syncrude
Sales (mbbls/d)		19.5			19.8		14.9		22.5		23.7		20.2

Price Received ($/bbl)		83.55			55.48		71.58		74.54		79.83		70.96
Royalties & Other		7.09			0.40		8.84		8.31		6.75		6.04
Operating Costs		38.43			36.95		57.21		29.50		27.93		35.92
Netback		38.03			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	2010 includes results from our start up activities at Long Lake.

3	2010 includes Long Lake third-party bitumen purchases.

Nexen Inc.

Oil and Gas Cash Netback 1 (continued)

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

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

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

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

Price Received ($/boe)		70.16		47.56		61.28		63.00		68.04		60.02
Royalties & Other		9.32		5.64		9.23		9.58		8.09		8.06
Operating and Other Costs 2		16.14		10.62		11.95		13.60		10.86		11.66
In-country Taxes		1.91		1.11		2.02		2.11		1.82		1.75
Netback		42.79		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 Months Ended March 31

(Cdn$ millions, except per share amounts)	2010			2009
Revenues and Other Income
Net Sales		1,501			1,048
Marketing and Other (Note 14)		151			257
		1,652			1,305
Expenses
Operating		422			305
Depreciation, Depletion, Amortization and Impairment		388			409
Transportation and Other		202			201
General and Administrative		118			100
Exploration		93			53
Interest (Note 9)		80			68
		1,303			1,136

Income before Provision for Income Taxes		349			169

Provision for (Recovery of) Income Taxes
Current		259			118
Future		(100	)		(87	)
		159			31

Net Income		190			138
Less: Net Income Attributable to Canexus Non-Controlling Interests		5			3

Net Income Attributable to Nexen Inc.		185			135

Earnings Per Common Share ($/share) (Note 15)
Basic		0.35			0.26

Diluted		0.35			0.26

See accompanying notes to the Unaudited Consolidated Financial Statements.

Nexen Inc.

Unaudited Consolidated Balance Sheet

	March 31			December 31
(Cdn$ millions, except share amounts)	2010				2009
Assets
Current Assets
Cash and Cash Equivalents		1,997				1,700
Restricted Cash		178				198
Accounts Receivable (Note 2)		2,635				2,788
Inventories and Supplies (Note 3)		574				680
Other		102				185
Total Current Assets		5,486				5,551

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $10,931 (December 31, 2009 – $10,807)		15,381				15,492
Goodwill		330				339
Future Income Tax Assets		1,238				1,148
Deferred Charges and Other Assets (Note 5)		328				370
Total Assets		22,763				22,900

Liabilities
Current Liabilities
Accounts Payable and Accrued Liabilities (Note 8)		3,084				3,038
Accrued Interest Payable		77				89
Dividends Payable		26				26
Total Current Liabilities		3,187				3,153

Long-Term Debt (Note 9)		7,054				7,251
Future Income Tax Liabilities		2,804				2,811
Asset Retirement Obligations (Note 11)		932				1,018
Deferred Credits and Other Liabilities (Note 12)		959				1,021

Equity
Nexen Inc. Shareholders’ Equity
Common Shares, no par value
Authorized:Unlimited
Outstanding:2010 – 524,046,867 shares
2009 – 522,915,843 shares		1,076				1,049
Contributed Surplus		–				1
Retained Earnings		6,881				6,722
Accumulated Other Comprehensive Loss		(201	)			(190	)
Total Nexen Inc. Shareholders’ Equity		7,756				7,582
Canexus Non-Controlling Interests		71				64
Total Equity		7,827				7,646
Commitments, Contingencies and Guarantees (Note 16)
Total Liabilities and Equity		22,763				22,900

See accompanying notes to the Unaudited Consolidated Financial Statements.

Nexen Inc.

Unaudited Consolidated Statement of Cash Flows

For the Three Months Ended March 31

(Cdn$ millions)	2010			2009
Operating Activities
Net Income		190			138
Charges and Credits to Income not Involving Cash (Note 17)		265			319
Exploration Expense		93			53
Changes in Non-Cash Working Capital (Note 17)		256			420
Other		(6	)		(141	)
		798			789

Financing Activities
Proceeds from (Repayment of) Term Credit Facilities, Net		–			1,011
Proceeds from (Repayment of) Canexus Term Credit Facilities, Net		22			10
Dividends Paid on Common Shares		(26	)		(26	)
Distributions Paid to Canexus Non-Controlling Interests		(4	)		(4	)
Issue of Common Shares and Exercise of Tandem Options for Shares		25			23
		17			1,014

Investing Activities
Capital Expenditures
Exploration and Development		(492	)		(702	)
Proved Property Acquisitions		–			(757	)
Energy Marketing, Chemicals, Corporate and Other		(64	)		(45	)
Proceeds on Disposition of Assets		15			14
Changes in Non-Cash Working Capital (Note 17)		88			19
Changes in Restricted Cash		15			(314	)
Other		(3	)		(2	)
		(441	)		(1,787	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		(77	)		35

Increase in Cash and Cash Equivalents		297			51

Cash and Cash Equivalents – Beginning of Period		1,700			2,003

Cash and Cash Equivalents – End of Period 1		1,997			2,054

1	Cash and cash equivalents at March 31, 2010 consist of cash of $257 million and short-term investments of $1,740 million (March 31, 2009 – cash of $182 million and short-term investments of $1,872 million).

See accompanying notes to the Unaudited Consolidated Financial Statements.

Nexen Inc.

Unaudited Consolidated Statement of Equity

For the Three Months Ended March 31

(Cdn$ millions)	2010			2009

Common Shares, Beginning of Period		1,049			981
Issue of Common Shares		24			23
Exercise of Tandem Options for Shares		1			–
Accrued Liability Relating to Tandem Options Exercised for Common Shares		2			–
Balance at End of Period		1,076			1,004

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

Retained Earnings, Beginning of Period		6,722			6,290
Net Income Attributable to Nexen Inc.		185			135
Dividends Paid on Common Shares (Note 13)		(26	)		(26	)
Balance at End of Period		6,881			6,399

Accumulated Other Comprehensive Loss, Beginning of Period		(190	)		(134	)
Other Comprehensive Income (Loss) Attributable to Nexen Inc.		(11	)		6
Balance at End of Period 1		(201	)		(128	)
1 Comprised of unrealized foreign currency translation adjustment.

Canexus Non-Controlling Interests, Beginning of Period		64			52
Net Income Attributable to Non-Controlling Interests		6			3
Distributions Paid to Non-Controlling Interests		(4	)		(4	)
Issue of Partnership Units to Non-Controlling Interests		5			1
Balance at End of Period		71			52

See accompanying notes to the Unaudited Consolidated Financial Statements.

Nexen Inc.

Unaudited Consolidated Statement of Comprehensive Income

For the Three Months Ended March 31

(Cdn$ millions)	2010			2009
Net Income Attributable to Nexen Inc.		185			135
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment
Net Gains (Losses) on Investment in Self-Sustaining Foreign Operations		(147	)		174
Net Gains (Losses) on Foreign-Denominated Debt Hedges of Self-Sustaining Foreign Operations 1		136			(168	)
Other Comprehensive Income (Loss) Attributable to Nexen Inc.		(11	)		6
Comprehensive Income Attributable to Nexen Inc.		174			141

1	Net of income tax expense for the three months ended March 31, 2010 of $20 million (2009 – $24 million recovery).

See accompanying notes to the Unaudited Consolidated Financial Statements.

Nexen Inc.

Notes to Unaudited Consolidated Financial Statements

Cdn$ millions, except as noted

1.	ACCOUNTING POLICIES

Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). 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 March 31, 2010 and December 31, 2009 and the results of our operations and our cash flows for the three months ended March 31, 2010 and 2009.

We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates on an ongoing basis, including those related to accruals, litigation, environmental and asset retirement obligations, recoverability of assets, income taxes, fair values of derivative assets and liabilities, 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 months ended March 31, 2010 are not necessarily indicative of the results of operations or cash fl ows to be expected for the year ending December 31, 2010. As at April 26, 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

On January 6, 2010, the Financial Accounting Standards Board issued guidance for Oil and Gas Reserve Estimation and Disclosure, which is effective for years ended December 31, 2009. The guidance expands the definition of oil and gas producing activities to: i) include unconventional sources such as oil sands; ii) change the price used in reserve estimation from the year-end price to the simple average of the first-day-of-the-month price for the previous 12 months, and iii) 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 the three months ended March 31, 2010 increased by $14 million, net income decreased by $9 million, and earnings per common share decreased by $0.02/share.

2.	ACCOUNTS RECEIVABLE

	March 31 2010			December 31 2009
Trade
Energy Marketing		1,385			1,410
Energy Marketing Derivative Contracts (Note 6)		267			466
Oil and Gas		867			823
Chemicals and Other		46			44
		2,565			2,743
Non-Trade		123			99
		2,688			2,842
Allowance for Doubtful Receivables		(53	)		(54	)
Total		2,635			2,788

3.	INVENTORIES AND SUPPLIES

	March 31 2010		December 31 2009
Finished Products
Energy Marketing		442		548
Oil and Gas		25		25
Chemicals and Other		12		12
		479		585
Work in Process		10		7
Field Supplies		85		88
Total		574		680

4.	SUSPENDED EXPLORATION WELL COSTS

The following table shows the changes in capitalized exploratory well costs during the three months ended March 31, 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.

	Three Months Ended March 31 2010			Year Ended December 31 2009
Beginning of Period		794			518
Exploratory Well Costs Capitalized Pending the Determination of Proved Reserves		146			396
Capitalized Exploratory Well Costs Charged to Expense		(2	)		(56	)
Transfers to Wells, Facilities and Equipment Based on Determination of Proved Reserves		–			(21	)
Effects of Foreign Exchange Rate Changes		(14	)		(43	)
End of Period		924			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.

	March 31 2010		December 31 2009
Capitalized for a Period of One Year or Less		425		383
Capitalized for a Period of Greater than One Year		499		411
Total		924		794

Number of Projects that have Exploratory Well Costs Capitalized for a Period Greater than One Year		13		12

As at March 31, 2010, we have exploratory costs that have been capitalized for more than one year relating to our interests in eight exploratory blocks in the North Sea ($174 million), certain coalbed methane and shale gas exploratory activities in Canada ($194 million), two exploratory blocks in the Gulf of Mexico ($113 million), and our interest in an exploratory block offshore Nigeria ($18 million). These costs relate to projects with successful exploration wells for which we have not been able to recognize proved reserves. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or otherwise assess commercial viability.

Aging of Suspended Exploration Wells Greater than One Year	United Kingdom	Canada	United States	Nigeria	Total
1-3 years	119	194	42	–	355
4-5 years	55	–	71	–	126
Greater than 5 years	–	–	–	18	18
Total	174	194	113	18	499

5.	DEFERRED CHARGES AND OTHER ASSETS

	March 31 2010		December 31 2009
Long-Term Energy Marketing Derivative Contracts (Note 6)		200		225
Crude Oil Put Options and Natural Gas Swaps (Note 6)		–		4
Defined Benefit Pension Assets		56		60
Long-Term Capital Prepayments		23		27
Other		49		54
Total		328		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 below details our derivatives and fair values as at March 31, 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 amount s 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 March 31, 2010, the estimated fair value of our long-term debt was $7,337 million (December 31, 2009 – $7,594 million) as compared to the carrying value of $7,054 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:

	March 31 2010		December 31 2009
Commodity Contracts		267		463
Foreign Exchange Contracts		–		3
Accounts Receivable (Note 2)		267		466

Commodity Contracts		200		225
Deferred Charges and Other Assets (Note 5) 1		200		225

Total Trading Derivative Assets		467		691

Commodity Contracts		212		410
Foreign Exchange Contracts		13		46
Accounts Payable and Accrued Liabilities (Note 8)		225		456

Commodity Contracts		198		212
Foreign Exchange Contracts		1		–
Deferred Credits and Other Liabilities (Note 12) 1		199		212

Total Trading Derivative Liabilities		424		668

Total Net Trading Derivative Contracts		43		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:

	March 31 2010		December 31 2009
Current Trading Assets		2,116		2,625
Non-Current Trading Assets		613		716
Total Trading Derivative Assets		2,729		3,341

Current Trading Liabilities		2,074		2,615
Non-Current Trading Liabilities		612		703
Total Trading Derivative Liabilities		2,686		3,318

Total Net Trading Derivative Contracts		43		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 months ended March 31, 2010 and 2009, the following trading revenues were recognized in marketing and other income:

	Three Months Ended March 31
	2010			2009
Commodity		91			270
Foreign Exchange		(5	)		(3	)
Marketing Revenue		86			267

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 months ended March 31, 2010 and 2009, are as follows:

		Three Months Ended March 31
		2010		2009
Natural Gas	bcf/d		15.2		28.6
Crude Oil	mmbbls/d		3.3		3.8
Power	GWh/d		280.8		212.3
Foreign Exchange	US$ millions		787		378
Foreign Exchange	Euro millions		53		153

(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:

	March 31 2010			December 31 2009
Accounts Receivable		1			13
Deferred Charges and Other Assets (Note 5) 1		–			4
Total Non-Trading Derivative Assets		1			17

Accounts Payable and Accrued Liabilities (Note 8)		20			26
Total Non-Trading Derivative Liabilities		20			26

Total Net Non-Trading Derivative Assets 2		(19	)		(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. At March 31, 2010, higher crude oil prices reduced the fair value of the options to approximately $1 million, and we recorded a fair value loss during the period of $16 million in marketing and other income.

							Three Months Ended March 31, 2010
	Notional Volumes		Term		Average Floor Price		Fair Value		Change in Fair Value
	(bbls/d)				(US$/bbl)
WTI Crude Oil Put Options (monthly)		60,000		2010		50		1		(12	)
WTI Crude Oil Put Options (annual)		30,000		2010		50		–		(4	)
								1		(16	)

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.

							Three Months Ended March 31, 2010
	Notional Volumes		Term		Average Price		Fair Value			Change in Fair Value
	(Gj/d)				($/Gj)
Fixed-Price Natural Gas Contracts		15,514		2010		2.28		(4	)		(7	)
Natural Gas Swaps		15,514		2010		7.60		(16	)		7
								(20	)		–

(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 March 31, 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 March 31, 2010	Level 1			Level 2			Level 3		Total
Commodity Contracts		(156	)		175			38		57
Foreign Exchange Contracts		–			(14	)		–		(14	)
Trading Derivatives		(156	)		161			38		43
Non-Trading Derivatives		–			(19	)		–		(19	)
Total		(156	)		142			38		24

A reconciliation of changes in the fair value of our derivatives classified as Level 3 for the three months ended March 31, 2010 is provided below:

	Level 3
Beginning of Period		42
Realized and Unrealized Gains (Losses)		7
Purchases		–
Settlements		(11	)
Transfers Into Level 3		–
Transfers Out of Level 3		–
End of Period		38

Unsettled gains relating to instruments still held as of March 31, 2010		7

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 wou ld change by $13 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.

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 o f 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.

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

Our risk management activities 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 months ended March 31, 2010 and the year ended December 31, 2009, are as follows:

Value-at-Risk	Three Months Ended March 31 2010		Year Ended December 31 2009
Period End		13		11
High		15		24
Low		9		9
Average		12		15

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

Foreign currency risk

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

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

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

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

·	short-term borrowings and long-term debt.

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 March 31, 2010 and December 31, 2009 are as follows:

(US$ millions)	March 31 2010		December 31 2009
Net Investment in Self-Sustaining Foreign Operations		4,523		4,492
Designated US-Dollar Debt		4,523		4,492

For the three month period ended March 31, 2010, the ineffective portion of our US-dollar debt resulted in a net foreign exchange gain of $21 million ($19 million, 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 $6 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 70% 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 March 31, 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. No other counterparties made up more than 5% of our credit exposure. The following table illustrates the composition of credit exposure by credit rating.

Credit Rating	March 31 2010	December 31 2009
A or higher	67%	67%
BBB	25%	26%
Non-Investment Grade	8%	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 March 31, 2010 includes $1 million of cash and $319 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 March 31, 2010, we had approximately $3.6 billion of cash and available committed lines of credit. This includes $2 billion of cash and cash equivalents on hand and undrawn term credit facilities of $1.6 billion, of which $391 million was supporting letters of credit at March 31, 2010. These facilities are available until 2012 unless extended. We also have about $466 million of undrawn, uncommitted credit facilities, of which $116 milli on was supporting letters of credit at March 31, 2010.

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

	Total		< 1 Year		1-3 Years		4-5 Years		> 5 Years
Long-Term Debt		7,144		–		1,771		854		4,519
Interest on Long-Term Debt 1		7,724		350		700		658		6,016
Total		14,868		350		2,471		1,512		10,535

Excludes interest on term credit facilities of $1.5 billion (US$1.5 billion) and Canexus term credit facilities of $247 million (US$244 million) as the amounts drawn on the facilities fluctuate. Based on amounts drawn at March 31, 2010 and existing variable interest rates, we would be required to pay $18 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.

	Total		< 1 Year		1-3 Years		4-5 Years		> 5 Years
Trading Derivatives (Note 6)		424		225		173		26		–
Non-Trading Derivatives (Note 6)		20		20		–		–		–
Total		444		245		173		26		–

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 March 31, 2010, we could be required to post collateral of up to $1,016 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 March 31, 2010, collateral posted with counterparties includes $5 million of cash and $299 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 $178 million (December 31, 2009 – $198 million), which have been included in restricted cash.

8.	ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

	March 31 2010		December 31 2009
Energy Marketing Payables		1,422		1,366
Energy Marketing Derivative Contracts (Note 6)		225		456
Accrued Payables		615		619
Trade Payables		245		210
Income Taxes Payable		233		179
Stock-Based Compensation		68		72
Other		276		136
Total		3,084		3,038

9.	SHORT-TERM BORROWINGS AND LONG-TERM DEBT

	March 31 2010			December 31 2009
Canexus Term Credit Facilities, due 2012 (US$244 million drawn) (a)		247			233
Term Credit Facilities, due 2012 (US$1.5 billion drawn) (b)		1,523			1,570
Canexus Notes, due 2013 (US$50 million)		51			52
Notes, due 2013 (US$500 million)		508			523
Canexus Convertible Debentures, due 2014		41			46
Notes, due 2015 (US$250 million)		254			262
Notes, due 2017 (US$250 million)		254			262
Notes, due 2019 (US$300 million)		305			314
Notes, due 2028 (US$200 million)		203			209
Notes, due 2032 (US$500 million)		508			523
Notes, due 2035 (US$790 million)		802			827
Notes, due 2037 (US$1,250 million)		1,270			1,308
Notes, due 2039 (US$700 million)		711			733
Subordinated Debentures, due 2043 (US$460 million)		467			481
		7,144			7,343
Unamortized Debt Issue Costs		(90	)		(92	)
Total		7,054			7,251

(a)	Canexus term credit facilities

Canexus has $450 million (US$444 million) of committed, secured term credit facilities available until 2012. At March 31, 2010, $247 million (US$244 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 1.5% for the three months ended March 31, 2010 (three months ended March 31, 2009 – 2.7%).

(b)	Term credit facilities

We have unsecured term credit facilities of $3.1 billion (US$3.1 billion) available until 2012. At March 31, 2010, $1.5 billion (US$1.5 billion) 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 at floating rates. The weighted-average interest rate on our term credit facilities was 0.9% for the three months ended March 31, 2010 (three months ended March 31, 2009 – 1.1%). At March 31, 2010, $391 million (US$385 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 Ended March 31
	2010			2009
Long-Term Debt		94			89
Other		4			5
Total		98			94
Less: Capitalized		(18	)		(26	)
Total		80			68

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 $466 million (US$459 million), none of which were drawn at March 31, 2010 (December 31, 2009 – nil). We utilized $116 million (US$114 million) of these facilities to support outstanding letters of credit at March 31, 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:

	March 31 2010			December 31 2009
Net Debt 1
Long-Term Debt		7,054			7,251
Less: Cash and Cash Equivalents		(1,997	)		(1,700	)
Total		5,057			5,551

Equity 2		7,827			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 March 31, 2010, the net debt to adjusted cash flow was 2.2 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, when we are in the investment cycle, or when we identify strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we assess whether we need to develop a strategy to reduce our leverage and lower this ratio back to target levels over time.

Our interest coverage ratio monitors our ability to fund the interest requirements associated with our debt. Our interest coverage increased from 8.5 times at the end of 2009 to 8.9 times at March 31, 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.

	Three Months Ended March 31 2010			Year Ended December 31 2009
Net Income Attributable to Nexen Inc.		586			536
Add:
Interest Expense		324			312
Provision for Income Taxes		388			260
Depreciation, Depletion, Amortization and Impairment		1,781			1,802
Exploration Expense		342			302
Recovery of Non-Cash Stock-Based Compensation		(11	)		(10	)
Change in Fair Value of Crude Oil Put Options		251			251
Other Non-Cash Expenses		(153	)		(136	)
Adjusted EBITDA		3,508			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:

	Three Months Ended March 31 2010			Year Ended December 31 2009
Balance at Beginning of Period		1,053			1,059
Obligations Incurred with Development Activities		7			27
Obligations Settled		(11	)		(42	)
Accretion Expense		17			70
Revisions to Estimates		(32	)		13
Effects of Changes in Foreign Exchange Rate		(38	)		(74	)
Balance at End of Period 1, 2		996			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 $962 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 $2,261 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 $298 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

	March 31 2010		December 31 2009
Deferred Tax Credit		460		503
Long-Term Energy Marketing Derivative Contracts (Note 6)		199		212
Defined Benefit Pension Obligations		75		76
Capital Lease Obligations		60		61
Deferred Transportation Revenue		52		55
Other		113		114
Total		959		1,021

13.	SHAREHOLDERS’ EQUITY

Dividends

Dividends per common share for the three months ended March 31, 2010 were $0.05 per common share (2009 – $0.05). Dividends paid to holders of common shares have been designated as “eligible dividends” for Canadian tax purposes.

14.	MARKETING AND OTHER INCOME

	Three Months Ended March 31
	2010			2009
Marketing Revenue, Net		86			267
Long Lake Purchased Bitumen Sales		28			–
Change in Fair Value of Crude Oil Put Options		(16	)		(16	)
Interest		4			2
Foreign Exchange Gains		34			19
Other		15			(15	)
Total		151			257

15.	EARNINGS PER COMMON SHARE

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

	Three Months Ended March 31
(millions of shares)	2010			2009
Weighted-average number of common shares outstanding		523.6			520.2
Shares issuable pursuant to tandem options		6.3			7.6
Shares notionally purchased from proceeds of tandem options		(4.8	)		(5.1	)
Weighted-average number of diluted common shares outstanding		525.1			522.7

In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2010, we excluded 16,476,455 tandem options, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2009, we excluded 4,103,560 tandem options, because their exercise price was greater than the average common share market price in the period. During the periods presented, outstanding tandem options were the only potential dilutive instruments.

16.	COMMITMENTS, CONTINGENCIES AND GUARANTEES

As described in Note 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 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. They expire at the earlier of the purchaser replacing the guarantees and July 25, 2010. We are obligated to perform under the guarantees only if the purchaser does not meet its obligations to the counterparties. Our total exposure is $275 million for which the purchaser has provided us with an indemnity and a letter of credit from a highly rated financial institution.

17.	CASH FLOWS

(a)	Charges and credits to income not involving cash

	Three Months Ended March 31
	2010			2009
Depreciation, Depletion, Amortization and Impairment		388			409
Stock-Based Compensation		(1	)		–
Loss (Gains) on Disposition of Assets		3			(7	)
Recovery of Future Income Taxes		(100	)		(87	)
Change in Fair Value of Crude Oil Put Options		16			16
Foreign Exchange		(41	)		(13	)
Other		–			1
Total		265			319

(b)	Changes in non-cash working capital

	Three Months Ended March 31
	2010			2009
Accounts Receivable		(218	)		298
Inventories and Supplies		113			(49	)
Other Current Assets		73			(8	)
Accounts Payable and Accrued Liabilities		385			185
Other Current Liabilities		(9	)		13
Total		344			439

Relating to:
Operating Activities		256			420
Investing Activities		88			19
Total		344			439

(c)	Other cash flow information

	Three Months Ended March 31
	2010		2009
Interest Paid		103		81
Income Taxes Paid		207		34

Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $12 million for the three months ended March 31, 2010 (2009 – $12 million).

18.	SUBSEQUENT EVENTS

In April 2010, we substantially completed negotiations for the sale of our North American natural gas business subject to finalizing documentation and customary closing conditions. We expect to sign the agreement in the second quarter and close the sale in the third quarter. The sale is expected to be cash neutral and we expect to recognize a non-cash loss on the sale of between $250 and $290 million. This loss primarily relates to the transfer of long-term natural gas physical transportation commitments that are less valuable with increased gas supplies that reduce the need for transport services. Although volatile on a quarterly basis, we have had success with our marketing business over the last 10 years generating about $800 million of positive cash flow.

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 March 31, 2010

	Oil and Gas																Energy Marketing			Chemicals		Corporate and Other			Total
	United Kingdom			Canada			Syncrude		United States			Yemen		Other Countries		1

Net Sales		755			180			134		113			182		15			9			113		–			1,501
Marketing and Other		5			28			1		–			5		–			83			7		22	2		151
Total Revenues		760			208			135		113			187		15			92			120		22			1,652

Less: Expenses
Operating		77			134			67		22			41		1			10			70		–			422
Depreciation, Depletion, Amortization and Impairment		168			80			13		64			35		2			5			11		10			388
Transportation and Other		(1	)		56			7		2			3		–			123			12		–			202
General and Administrative 3		13			16			–		11			1		8			21			8		40			118
Exploration		24			7			–		16			–		46	4		–			–		–			93
Interest		–			–			–		–			–		–			–			1		79			80
Income (Loss) before Income Taxes		479			(85	)		48		(2	)		107		(42	)		(67	)		18		(107	)		349
Less: Provision for (Recovery of) Income Taxes		240			(21	)		12		(1	)		37		(38	)		(23	)		4		(51	)		159
Less: Non-Controlling Interests		–			–			–		–			–		–			–			5		–			5
Net Income (Loss)		239			(64	)		36		(1	)		70		(4	)		(44	)		9		(56	)		185

Identifiable Assets		4,696			7,848	5		1,292		1,717			257		1,141			2,588	6		701		2,523			22,763

Capital Expenditures
Development and Other		88			70			19		15			10		91			9			49		6			357
Exploration		41			68			–		49			–		41			–			–		–			199
Total		129			138			19		64			10		132			9			49		6			556

Property, Plant and Equipment
Cost		6,027			9,781			1,482		3,828			2,397		991			265			1,164		377			26,312
Less: Accumulated DD&A		2,745			2,108			281		2,504			2,286		97			88			570		252			10,931
Net Book Value		3,282			7,673	5		1,201		1,324			111		894			177			594		125			15,381

1 Includes results of operations from producing activities in Colombia.

2 Includes interest income of $4 million, foreign exchange gains of $34 million and a decrease in the fair value of crude oil put options of $16 million.

3 Includes stock-based compensation expense of $2 million.

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

5 Includes costs of $6,088 million related to our insitu oil sands (Long Lake and future phases).

6 Approximately 79% of Marketing’s identifiable assets are accounts receivable and inventories.

Three months ended March 31, 2009

	Oil and Gas																Energy Marketing			Chemicals			Corporate and Other			Total
	United Kingdom			Canada			Syncrude		United States			Yemen		Other Countries		1

Net Sales		478			91			98		63			162		19			13			124			–			1,048
Marketing and Other		4			7			–		–			3		–			267			(14	)		(10	) 2		257
Total Revenues		482			98			98		63			165		19			280			110			(10	)		1,305

Less: Expenses
Operating		51			41			66		23			47		2			8			67			–			305
Depreciation, Depletion, Amortization and Impairment		193			63			11		68			41		5			4			12			12			409
Transportation and Other		(3	)		3			7		13			3		–			162			10			6			201
General and Administrative		2			14			–		14			4		8			23			9			26			100
Exploration		8			21			–		10			–		14	3		–			–			–			53
Interest		–			–			–		–			–		–			–			2			66			68
Income (Loss) before Income Taxes		231			(44	)		14		(65	)		70		(10	)		83			10			(120	)		169
Less: Provision for (Recovery of) Income Taxes		86			(11	)		4		(23	)		24		(6	)		35			2			(80	)		31
Less: Non-Controlling Interests		–			–			–		–			–		–			–			3			–			3
Net Income (Loss)		145			(33	)		10		(42	)		46		(4	)		48			5			(40	)		135

Identifiable Assets		6,403			7,678	4		1,212		2,100			400		807			3,035	5		594			1,390			23,619

Capital Expenditures
Development and Other		149			244			17		42			29		58			8			36			1			584
Exploration		28			94			–		26			–		15			–			–			–			163
Proved Property Acquisitions		–			757			–		–			–		–			–			–			–			757
Total		177			1,095			17		68			29		73			8			36			1			1,504

Property, Plant and Equipment
Cost		6,869			9,225			1,386		4,591			2,920		636			256			983			332			27,198
Less: Accumulated DD&A		2,419			1,843			244		2,850			2,729		121			80			523			212			11,021
Net Book Value		4,450			7,382	4		1,142		1,741			191		515			176			460			120			16,177

1	Includes results of operations from producing activities in Colombia.

2	Includes interest income of $2 million, foreign exchange gains of $19 million, decrease in the fair value of crude oil put options of $16 million and other losses of $15 million.

3	Includes exploration activities primarily in Norway and Colombia.

4	Includes costs of $5,658 million related to our insitu oil sands (Long Lake and future phases).

5	Approximately 77% 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 Months Ended March 31

(Cdn$ millions, except per share amounts)	2010			2009
Revenues and Other Income
Net Sales		1,501			1,048
Marketing and Other (v); (vi)		205			292
		1,706			1,340
Expenses
Operating		422			305
Depreciation, Depletion, Amortization and Impairment		388			409
Transportation and Other (v)		205			194
General and Administrative (iv)		126			108
Exploration		93			53
Interest		80			68
		1,314			1,137

Income before Provision for Income Taxes		392			203

Provision for (Recovery of) Income Taxes
Current		259			118
Deferred (iv); (vi); (vii)		(86	)		(74	)
		173			44

Net Income – US GAAP		219			159
Less: Net Income Attributable to Non-Controlling Interests		5			3

Net Income Attributable to Nexen Inc. – US GAAP 1		214			156

Earnings Per Common Share ($/share) (Note 15)
Basic		0.41			0.30

Diluted		0.41			0.30

1 Reconciliation of Canadian and US GAAP Net Income

	Three Months Ended March 31
	2010			2009
Net Income Attributable to Nexen Inc – Canadian GAAP		185			135
Impact of US Principles, Net of Income Taxes:
Stock-based Compensation (iv)		(6	)		–
Inventory Valuation (vi)		35			(6	)
Deferred Taxes (vii)		–			27
Net Income Attributable to Nexen Inc – US GAAP		214			156

Unaudited Consolidated Balance Sheet – US GAAP

	March 31			December 31
(Cdn$ millions, except share amounts)	2010				2009
Assets
Current Assets
Cash and Cash Equivalents		1,997				1,700
Restricted Cash		178				198
Accounts Receivable		2,635				2,788
Inventories and Supplies (vi)		555				610
Other		102				185
Total Current Assets		5,467				5,481

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $11,324 (December 31, 2009 - $11,200) (i); (iii)		15,332				15,443
Goodwill		330				339
Deferred Income Tax Assets		1,238				1,148
Deferred Charges and Other Assets		328				370
Total Assets		22,695				22,781

Liabilities
Current Liabilities
Accounts Payable and Accrued Liabilities (iv)		3,185				3,131
Accrued Interest Payable		77				89
Dividends Payable		26				26
Total Current Liabilities		3,288				3,246

Long-Term Debt		7,054				7,251
Deferred Income Tax Liabilities (i); (ii); (iv); (vi); (vii)		2,727				2,720
Asset Retirement Obligations		932				1,018
Deferred Credits and Other Liabilities (ii)		1,064				1,126

Equity
Nexen Inc. Shareholders’ Equity
Common Shares, no par value
Authorized:Unlimited
Outstanding:2010 – 524,046,867 shares
2009 – 522,915,843 shares		1,076				1,049
Contributed Surplus		–				1
Retained Earnings (i); (ii); (iv); (vi); (vii)		6,763				6,575
Accumulated Other Comprehensive Loss (ii)		(280	)			(269	)
Total Nexen Inc. Shareholders’ Equity		7,559				7,356
Canexus Non-Controlling Interests		71				64
Total Equity		7,630				7,420
Commitments, Contingencies and Guarantees (Note 16)
Total Liabilities and Equity		22,695				22,781

Unaudited Consolidated Statement of Comprehensive Income – US GAAP

For the Three Months Ended March 31

	Three Months Ended March 31
	2010			2009
Net Income Attributable to Nexen Inc. – US GAAP		214			156
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment		(11	)		6
Comprehensive Income Attributable to Nexen Inc. – US GAAP		203			162

Unaudited Consolidated Statement of Accumulated Other Comprehensive Loss – US GAAP

	March 31			December 31
	2010				2009
Foreign Currency Translation Adjustment		(201	)			(190	)
Unamortized Defined Benefit Pension Plan Costs (ii)		(79	)			(79	)
Accumulated Other Comprehensive Loss		(280	)			(269	)

Notes to the Unaudited Consolidated US GAAP Financial Statements:

Under Canadian GAAP, we defer 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 March 31, 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 Income (AOCI).

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 requires the accelerated recognition of stock-based compensation expense for all stock-based awards made to our retired and retirement-eligible employees. However, US GAAP requires 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 higher by $8 million, ($6 million, net of income taxes), for the three months ended March 31, 2010, (2009 – higher by $8 million ($6 million, net of income taxes)); and

·	accounts payable and accrued liabilities are higher by $101 million as at March 31, 2010 (December 31, 2009 – $93 million).

Under US GAAP, asset disposition gains and losses are included with transportation and other expense. Losses of $3 million for the three months ended March 31, 2010, were reclassified from marketing and other income to transportation and other expense (gains of $7 million were reclassified for the three months ended March 31, 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 $51 million ($35 million, net of income taxes) for the three months ended March 31, 2010 (2009 – higher by $42 million ($27 million, net of income taxes)); and

·	inventories are lower by $19 million as at March 31, 2010 (December 31, 2009 – lower by $70 million) and deferred income tax liabilities are $7 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 March 31, 2010, the total amount of our unrecognized tax benefit was approximately $279 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 March 31, 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 months ended March 31, 2010.

Our income tax filings are subject to audit by taxation authorities and as at March 31, 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 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.

1-6702	98-6000202
(Commission File Number)	(I.R.S. Employer Identification No.)

801 – 7th AVENUE S.W.
CALGARY, ALBERTA, CANADA	T2P 3P7
(Address of Principal Executive Offices)	(Zip Code)

	Exhibit Number	Description

	99.1	Press release of Nexen Inc. dated April 27, 2010.

	NEXEN INC.

	By:	/s/ Rick C. Beingessner
		Name: Rick C. Beingessner
		Title: Assistant Secretary

Exhibit Number	Description

99.1	Press release of Nexen Inc. dated April 27, 2010.