Nexen Inc.
TSX : NXY
NYSE : NXY

Nexen Inc.

July 16, 2009 06:30 ET

Ongoing North Sea Exploration Success Highlights Nexen's Second Quarter Results

CALGARY, ALBERTA--(Marketwire - July 16, 2009) - Nexen announces second quarter results highlighted by exploration success in the UK North Sea. A summary of the quarter is as follows:

- Cash flow of $443 million ($0.85/share) and net income of $20 million ($0.04/share)

- Production before royalties of 240,000 boe/d-impacted by scheduled downtime at Buzzard and Syncrude

- Current production volumes approximately 260,000 boe/d; third quarter volumes expected to be lower as a result of planned maintenance downtime; fourth quarter volumes expected to be higher as new fields ramp up

- Ongoing exploration success in the UK North Sea at Hobby-significant development potential for the Golden Eagle area

- Long Lake-record steam injection driven by water treatment modifications; bitumen volumes ramping up; reservoir performing well



Three Months Ended Six Months Ended
June 30 June 30
---------------------------------------
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Production (mboe/d)(1)
Before Royalties 240 254 246 261
After Royalties 208 211 217 217
Net Sales 1,200 2,071 2,248 3,941
Cash Flow from Operations(2) 443 946 1,000 1,985
Per Common Share ($/share)(2) 0.85 1.78 1.92 3.75
Net Income 20 380 155 1,010
Per Common Share ($/share) 0.04 0.72 0.30 1.91
Capital Investment(3), excluding
Acquisitions 746 660 1,605 1,456
Acquisitions(4) - 2 755 2
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(1) Production includes our share of Syncrude oil sands. US investors should
read the Cautionary Note to US Investors at the end of this release.
(2) For reconciliation of this non-GAAP measure see Cash Flow from
Operations on pg. 10.
(3) Includes geological and geophysical expenditures.
(4) 2009 represents acquisition of additional 15% interest in Long Lake
from Opti Canada Inc.


Financial Results

Quarterly cash flow from operations was $443 million compared to $946 million last year. This reflects the impact of lower commodity prices as WTI averaged US$60/bbl for the quarter, compared to US$124/bbl a year ago.

In the second quarter, cash flow from operations of $443 million (Q1 - $557 million) and net income of $20 million (Q1 - $135 million) were impacted by lower production, higher oil prices and the following items:



Comparing Q2 vs Q1 2009
(Cdn$ millions) Cash Flow Reduction Net Income Reduction
----------------------------------------------------------------------------
Lower quarterly marketing
contribution (50) (29)
Decrease in value of put options (48) (82)
----------------------------------------------------------------------------


Production was lower in the quarter due to a shutdown at Buzzard for a planned rig move and a coker turnaround at Syncrude. Presently, total company production volumes are approximately 260,000 boe/d with Buzzard and Syncrude back at full rates.

For the quarter, our marketing business contributed $34 million to our cash flow, compared to $84 million in the previous quarter. Marketing's first quarter contribution was boosted by gains on the use of its storage positions to take advantage of contango in the crude oil markets.

WTI averaged US$60/bbl in the second quarter, compared to US$43/bbl in the previous quarter. With oil prices increasing throughout the second quarter, the fair value of our put options has fallen considerably. The put options have an annual average Dated Brent strike price of US$60/bbl and would be in-the-money if prices average approximately US$70/bbl or lower for the rest of the year.

Year to date, our capital investment has exceeded cash flow. Our 2009 capital program is somewhat front-end loaded as we complete our new developments at Ettrick and Longhorn, and the Long Lake debottleneck project. With expenditures on these investments behind us, capital on these projects next year will be minimal. When ramped up, the annual pre-tax cash flow contribution of Ettrick and Longhorn at current commodity prices is approximately $300 million. Gas prices will drive the pace of our future shale gas investment programs.

"Our solid quarterly cash flow continues to be driven by our industry leading cash netbacks," stated Marvin Romanow, Nexen's President and Chief Executive Officer. "Our financial position remains strong and we have substantial liquidity. When we combine this with our high netbacks, we are well positioned in the current environment."



Quarterly Production-Rig move at Buzzard; turnaround at Syncrude

Production before Production after
Royalties Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) Q2 2009 Q1 2009 Q2 2009 Q1 2009
----------------------------------------------------------------------------
North Sea 101 107 101 107
Yemen 51 54 29 36
Canada - Oil & Gas 38 38 33 32
Canada - Bitumen 9 8 9 8
United States 22 19 20 17
Other Countries 4 6 3 5
Syncrude 15 20 13 20
------------------------------------------
Total 240 252 208 225
------------------------------------------


Second quarter production volumes averaged 240,000 boe/d (208,000 boe/d after royalties) with 85% of our production weighted to crude oil. Volumes were lower due to a planned rig move at Buzzard and a turnaround at Syncrude. At Buzzard, production was temporarily shut-in while a development drilling rig was moved back to the platform following the completion of rig modifications. Buzzard contributed 87,500 boe/d (202,500 boe/d gross) to our volumes, which was 5,200 boe/d less than the first quarter. Syncrude production was lower due to a planned turnaround of Coker 8-3, which took longer than anticipated. Presently, total company production volumes are approximately 260,000 boe/d with Buzzard and Syncrude back at full rates.

In the third quarter, production is expected to be temporarily lower than second quarter volumes as a result of maintenance downtime at a number of fields. As previously announced, Buzzard will be shut down for four weeks for the tie-in and jacket installation of the fourth platform. This platform will allow us to handle higher levels of hydrogen sulphide and maintain peak production until at least 2014. The shutdown is scheduled to coincide with an expected six week slowdown of the Forties pipeline for routine maintenance.

Elsewhere in the North Sea, Scott/Telford will be shut down for approximately five weeks for planned maintenance. In the Gulf of Mexico, production volumes from Wrigley will be limited for approximately three weeks to complete corrosion mitigation work. Finally, at Long Lake, bitumen volumes will be impacted by downtime related to the replacement of valves and maintenance in the water treatment plant.

In the fourth quarter, volumes are expected to grow significantly from current levels with the continued ramp up of Long Lake, the start up of Ettrick and Longhorn and incremental shale gas production.

"New volumes from the start-up of Ettrick and Longhorn will help to offset some of this downtime," said Romanow. "With the longer than expected turnaround at Syncrude and the ongoing ramp up of Long Lake, we now expect to be towards the low end of our annual guidance."

Global Exploration-Delivering exciting results

UK North Sea

The Golden Eagle area is emerging as a potential significant development opportunity. Our current estimates of recoverable resource are at the high end of our pre-drill estimates. We expect development of the area will be economic at approximately US$40/bbl and should support standalone facilities with project sanction targeted for 2010.

In 2007, we drilled the initial Golden Eagle discovery well in what is now the Golden Eagle area. This well, and a subsequent sidetrack to the north, indicated the presence of a high quality reservoir and testing of the initial discovery well demonstrated production rates of approximately 5,000 boe/d. Net pays of 150 feet and 60 feet were encountered in the discovery and sidetrack wells, respectively.

In 2008, we drilled our Pink discovery well further south, between the Golden Eagle discovery well and Buzzard. We encountered 57 feet of net pay in a high quality reservoir, which was primarily light oil from Upper Jurassic Burns sands. We successfully sidetracked the well to the west and encountered 134 feet of net oil pay. In addition, we have recently completed an appraisal well here and the results are being assessed.

In January 2009, we drilled the Hobby discovery. The well encountered light sweet oil with an API of 37 degrees and was tested at a constrained rate of 5,550 bbls/d with a 56/64 inch choke. We have subsequently drilled three successful sidetracks from the discovery well and an appraisal well. In the second half of the year, we expect to continue the appraisal drilling program for the Hobby discovery. We have a 34% operated interest in both Hobby and Golden Eagle and a 46% operated working interest in Pink.

"The success we are having in the Golden Eagle area is coming from hard to find, stratigraphic traps. These discoveries come from the same exploration team that found Buzzard, one of the largest stratigraphic traps in the UK," commented Romanow. "Our geological model is working well in this mature basin and we intend to leverage this knowledge as we move forward with our exploration programs in the North Sea."

Offshore West Africa

We recently completed drilling an exploration well in the southern portion of Oil Prospecting License (OPL) 223, Offshore West Africa.

The Owowo South B-1 well was drilled in a water depth of 670 metres and is located 20 kilometres northeast of the Usan field, currently under development. We expect to announce drilling results shortly.

Under the production sharing contract governing OPL 223, the Nigerian National Petroleum Corporation (NNPC) is concessionaire of the license, which is operated by Total Exploration & Production Nigeria Ltd. (18%) with its co-venturers: Nexen Petroleum Exploration & Production Nigeria Ltd. (18%), Chevron Nigeria Deepwater F Ltd. (27%), Esso Exploration and Production Nigeria (Upstream) Ltd. (27%) and Nigerian Petroleum Development Company (NPDC) Ltd. (10%).

Deep-water Gulf of Mexico

In the Eastern Gulf of Mexico, we have previously made two discoveries at Vicksburg and Shiloh. We are currently reviewing tie-back options to existing platforms for the Vicksburg discovery and expect to drill an appraisal well here in 2010. In addition, we recently spud the Antietam prospect, which is located three miles west of our Shiloh discovery. Drilling results are expected in the third quarter. Later this year, we also expect to drill an exploration well at Appomattox, about six miles west of Vicksburg. We have a 25% interest in Vicksburg and a 20% interest in Antietam, Appomattox and Shiloh, with Shell operating all four.

"By focusing where we have had success, our global exploration program is delivering excellent results," said Romanow, "We are leveraging talent and learnings across our select basins and the discoveries we are making are adding significant upside to our strong portfolio of identified growth projects."

Long Lake-Bitumen volumes responding to record steam injection rates

The ramp up of Long Lake is progressing and the reservoir continues to perform as expected given the amount of steam that has been injected. Steam volumes have been limited by our ability to treat water.

In May, we successfully completed a project to add supplementary heat to the hot lime softeners ("HLS") in the water treatment plant. We also completed routine maintenance work to remove deposits which typically build up in water treatment plants. Steam production increased in June and we have achieved record injection rates of approximately 95,000 bbls/d and gross bitumen production rates of approximately 18,000 bbls/d. There are currently 41 of 81 well pairs on production and we are producing at a steam to oil ratio ("SOR") which ranges between 4.0 and 5.0. We continue to expect a long term SOR of 3.0, over the life of the project.

Bitumen production volumes for the second quarter set a new record and averaged approximately 14,300 bbls/d (gross), an increase of 7% over the first quarter. Production volumes have been impacted by downtime associated with improvements made to the HLS units. We plan to replace valves and conduct maintenance on our water treatment plant during the third quarter to further optimize our steam production. The cost of these activities will not be significant and will result in scheduled downtime in the third quarter, impacting bitumen and premium synthetic crude (PSC™) production. As steam generation increases, all wells will be converted to production mode.

With respect to the Upgrader, all major units are operational and Syngas is being used in SAGD operations. This allows us to decrease operating costs by reducing the requirement for purchased natural gas. The solvent de-asphalter and thermal cracker units are expected to start shortly and will allow us to transition from gasifying vacuum residue, which contains some lighter parts of the barrel, to gasifying asphaltenes, the heaviest part of the barrel. As a result, we expect our PSC™ yield to increase from approximately 60% to 80%.

During the ramp up phase, we expect periods of downtime but anticipate that the stability of operations will continue to improve. We expect to reach full design rates of 72,000 bbls/d of gross bitumen production, upgraded to approximately 60,000 bbls/d (39,000 bbls/d, net to us) of PSC™ in 2010. We have a 65% interest in the Long Lake project and joint venture lands. We are the sole operator of the resource and upgrader. This allows us to maximize operational efficiencies and reduce the cost of managing the project.

"The reservoir at Long Lake continues to meet expectations," commented Romanow. "Water treatment issues have limited production to date, but we have identified and continue to implement cost effective solutions. We are committed to a safe and reliable start-up. Long Lake will generate significant value with 40 years of production at a $10/bbl margin advantage."

UK North Sea-First oil at Ettrick scheduled in the next few weeks

Our Ettrick development in the North Sea is expected to produce first oil in the next few weeks. The project is expected to add approximately 12,000 to 16,000 boe/d to our production volumes for the remainder of the year. Ettrick will produce to a leased floating production, storage and offloading vessel (FPSO) designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. We have a discovery at Blackbird which could be a future tie-back to Ettrick. We operate both Ettrick and Blackbird, with an 79.73% working interest in each.

Gulf of Mexico-Longhorn nearing first production

Longhorn is expected to commence production shortly. We expect peak production of approximately 200 mmcf/d or 33,000 boe/d gross (50 mmcf/d or 8,000 boe/d, net to us). A fourth development well for the project, Leo, exceeded expectations and has extended our reserve base. We have a 25% non-operated working interest and ENI is the operator.

At Knotty Head, we plan to start drilling an appraisal well in the fourth quarter of 2009 after the first of our two new deep-water drilling rigs arrives. The rig left the Singapore shipyard in mid-June and is expected to enter the Gulf of Mexico in August and begin deep-water sea trials. This new rig has been contracted at attractive day rates, which are significantly better than industry average. We are currently negotiating the terms of an agreement to jointly develop Knotty Head and Pony. We have a 25% operated interest in Knotty Head.

Horn River Shale Gas-Well tests confirm high quality resource

During the quarter, we put two horizontal wells on production that were drilled last summer and completed in the first quarter. Initial production rates for the first month averaged 850 mcf/d per frac. These results are in line with previous tests and those of our competitors. We drilled three additional wells earlier this year and we recently began fracing these wells. We are starting to see efficiencies in our shale gas program as the time to complete the initial fracs in our new program is substantially less than our previous experience. We plan to complete and tie-in these wells in the third quarter. By the end of the year, we expect to have six wells on production at a total exit rate ranging between 12 and 18 mmcf/d.

Our drilling activity to date has allowed us to secure tenure on the majority of our Dilly Creek lands. Only two more wells are required to secure the remainder. Primary tenure in the Horn River basin is four years and drilling activity and extensions increases this up to 18 years.

The Horn River basin has the potential to become the most significant shale gas play in North America as it has the highest resource density and excellent well productivity. We have approximately 88,000 acres in the Dilly Creek area and 38,000 acres in the Cordova area in northeast British Columbia with a 100% working interest in each. As previously announced on April 22, 2008, we estimate that our Dilly Creek lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resource which could double our total proved reserves. Further appraisal activity is required before these estimates can be finalized and commerciality established.

"Our most recent well tests continue to confirm the resource quality of our Horn River shale gas play," said Romanow. "The long land tenure we have secured gives us significant optionality in pacing our development, allowing us to focus on creating value as gas prices warrant, rather than managing land expiries."

Offshore West Africa-Usan development continues

Development of the Usan field on block OML 138, offshore Nigeria is fully underway. The field development plan includes a FPSO vessel with a storage capacity of two million barrels of oil. Development drilling has begun and throughout the course of the year the FPSO hull will be constructed. The Usan field is expected to come on stream in 2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d net to us). Nexen has a 20% interest in exploration and development along with Total E&P Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration and Production Nigeria (Offshore East) Limited (30%).

Quarterly Dividend

The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable October 1, 2009, to shareholders of record on September 10, 2009. 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 uniquely positioned for growth in the North Sea, Western Canada (including the Athabasca oil sands of Alberta and unconventional gas resource plays such as shale gas and coalbed methane), deep-water Gulf of Mexico, offshore West Africa and the Middle East. We add value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity, governance and environmental protection.

Information with respect to forward-looking statements and cautionary notes is set out below.

Conference Call

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

Date: July 16, 2009

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

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

416-340-8530 (Toronto)

877-240-9772 (North American toll-free)

800-9559-6849 (Global toll-free)

A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 2755450 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 cost recovery oil revenues from our Yemen operations, future capital expenditures and their allocation to exploration and development activities, future earnings, future asset 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 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 demand for chemicals products, estimates on a per share basis, sales, future expenditures and future allowances relating to environmental matters and dates by which certain areas will be developed, come on stream, or reach expected operating capacity and changes in any of the foregoing are forward-looking statements. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas and chemicals products; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design 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 environmental 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 2008 Annual Report on Form 10-K for further discussion of the risk factors.

Cautionary Note to US Investors

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to discuss only proved reserves that are supported by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. In this disclosure, we may refer to "recoverable reserves", "probable reserves", "recoverable resources" and "recoverable contingent resources" which are inherently more uncertain than proved 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.

In addition, under SEC regulations, the Syncrude oil sands operations are considered mining activities rather than oil and gas activities. Production, reserves and related measures in this release include results from the Company's share of Syncrude.

Under SEC regulations, we are required to recognize bitumen reserves rather than the upgraded premium synthetic crude oil we will produce and sell from Long Lake.

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 reserves disclosures are made in reliance upon exemptions granted to Nexen 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 standards of the Canadian Oil and Gas Evaluation Handbook (COGE Handbook) 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 evaluators.

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 herein:

- SEC registrants apply SEC reserves definitions and prepare their proved 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 mandates disclosure of proved reserves and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein calculated using year-end constant 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 proved and proved developed reserves by geographic region only whereas NI 51-101 requires disclosure of more reserve categories and product types;

- the SEC does not prescribe the nature of the information required in connection with proved undeveloped reserves and future development costs whereas NI 51-101 requires certain detailed information regarding proved undeveloped reserves, related development plans and future development costs;

- 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 be disclosed. NI 51-101 requires that F&D costs be calculated by dividing the aggregate of exploration and development costs incurred in the current year and the change in estimated future development costs relating to proved reserves by the additions to proved reserves in the current year. However, this will generally not reflect full cycle finding and development costs related to reserve additions for the year;

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

- the SEC does not consider the upgrading component of our integrated oil sands project at Long Lake as an oil and gas activity, and therefore permits recognition of bitumen reserves only. NI 51-101 specifically includes such activity as an oil and gas activity and recognizes synthetic oil as a product type, and therefore permits recognition of synthetic reserves. At year end, we have recognized 285 million barrels before royalties of proved bitumen reserves (282 million barrels after royalties) under SEC requirements, whereas under NI 51-101 we would have recognized 233 million barrels before royalties of proved synthetic reserves (231 million barrels after royalties);

- the SEC considers our Syncrude operation as a mining activity rather than an oil and gas activity, and therefore does not permit related reserves to be included with oil and gas reserves. NI 51-101 specifically includes such activity as an oil and gas activity and recognizes synthetic oil as a product type, and therefore permits them to be included with oil and gas reserves. We have provided a separate table showing our share of the Syncrude proved reserves as well as the additional disclosures relating to mining activities required by SEC requirements; and

- any reserves data in this document reflects our estimates of reserves. While we obtain an independent assessment of a portion of our reserves estimates, no independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data disclosed in this Form 10-K.

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

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

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

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

Resources

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

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

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



Nexen Inc.
Financial Highlights

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Net Sales 1,200 2,071 2,248 3,941
Cash Flow from Operations 443 946 1,000 1,985
Per Common Share ($/share) 0.85 1.78 1.92 3.75
Net Income 20 380 155 1,010
Per Common Share ($/share) 0.04 0.72 0.30 1.91
Capital Investment(1) 715 636 1,464 1,422
Acquisitions - 2 755 2
Net Debt(2) 5,889 3,835 5,889 3,835
Common Shares Outstanding (millions of
shares) 521.2 530.3 521.2 530.3
--------------------------------------
(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 Operations(1)
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Oil & Gas and Syncrude
United Kingdom 552 921 982 1,801
Yemen(2) 78 183 165 348
Canada 43 127 77 213
United States 41 165 53 312
Other Countries 8 29 17 63
Marketing 34 (164) 118 (151)
Syncrude 3 109 29 199
--------------------------------------
759 1,370 1,441 2,785
Chemicals 21 19 48 32
--------------------------------------
780 1,389 1,489 2,817
Interest and Other Corporate Items (173) (83) (231) (147)
Income Taxes(3) (164) (360) (258) (685)
--------------------------------------
Cash Flow from Operations(1) 443 946 1,000 1,985
--------------------------------------
--------------------------------------

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

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash Flow from Operating
Activities 109 1,163 898 2,331
Changes in Non-Cash Working
Capital 340 (232) (80) (372)
Other 44 21 185 38
Impact of Annual Crude Oil Put
Options (50) (6) (3) (12)
--------------------------------------
Cash Flow from Operations 443 946 1,000 1,985
--------------------------------------
--------------------------------------

Weighted-average Number of
Common Shares Outstanding
(millions of shares) 521.2 530.0 520.7 529.5
--------------------------------------
Cash Flow from Operations Per
Common Share ($/share) 0.85 1.78 1.92 3.75
--------------------------------------
--------------------------------------

(2) After in-country cash taxes of $42 million for the three months ended
June 30, 2009 (2008 - $91 million) and $66 million for the six months
ended June 30, 2009 (2008 - $158 million).
(3) Excludes in-country cash taxes in Yemen.


Nexen Inc.

Production Volumes (before royalties) 1

Three Months Six Months
Ended June 30 Ended June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 97.7 100.3 100.7 103.1
Yemen 51.5 57.6 52.9 59.9
Canada 14.9 16.4 15.1 16.3
United States 12.1 11.3 11.2 12.5
Long Lake Bitumen (2) 9.3 3.2 8.7 1.9
Other Countries 3.6 5.7 4.5 5.8
Syncrude (mbbls/d) (3) 14.9 19.1 17.3 19.2
--------------------------------------
204.0 213.6 210.4 218.7
--------------------------------------
Natural Gas (mmcf/d)
United Kingdom 18 19 18 20
Canada 136 126 138 127
United States 61 99 56 105
--------------------------------------
215 244 212 252
--------------------------------------

Total Production (mboe/d) 240 254 246 261
--------------------------------------
--------------------------------------

Production Volumes (after royalties)

Three Months Six Months
Ended June 30 Ended June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 97.6 100.3 100.6 103.1
Yemen 29.0 29.2 32.3 30.4
Canada 11.2 12.6 11.8 12.4
United States 10.9 9.7 10.2 10.9
Long Lake Bitumen (2) 9.2 3.2 8.6 1.9
Other Countries 3.3 5.2 4.2 5.4
Syncrude (mbbls/d) (3) 13.0 15.9 16.3 16.4
--------------------------------------
174.2 176.1 184.0 180.5
--------------------------------------
Natural Gas (mmcf/d)
United Kingdom 18 19 18 20
Canada 129 108 127 107
United States 54 85 50 90
--------------------------------------
201 212 195 217
--------------------------------------

Total Production (mboe/d) 208 211 217 217
--------------------------------------
--------------------------------------

(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Pre-operating revenues and costs associated with Long Lake bitumen are
capitalized as development costs until we reach commercial operations.
(3) Considered a mining operation for US reporting purposes.

Nexen Inc.

Oil and Gas Prices and Cash Netback (1)

Total
Quarters - 2009 Quarters 2008 Year
----------------------------------------------------------------------------
(all dollar amounts in Cdn$
unless noted) 1st 2nd 1st 2nd 3rd 4th 2008
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil (US$/bbl) 43.08 59.62 97.90 123.98 117.98 58.73 99.65
Nexen Average -
Oil (Cdn$/bbl) 50.41 68.32 93.00 118.00 115.56 59.90 96.92
NYMEX Natural Gas
(US$/mmbtu) 4.48 3.81 8.75 11.48 8.95 6.41 8.90
Nexen Average - Gas (Cdn$/mcf) 5.11 3.77 7.97 10.21 8.65 6.34 8.44
----------------------------------------------------------------------------

NETBACKS:
Canada - Heavy Oil
Sales (mbbls/d) 15.4 14.7 16.2 16.4 16.0 16.2 16.2

Price Received ($/bbl) 35.35 56.05 65.94 93.16 97.91 41.14 74.51
Royalties & Other 6.86 12.83 16.65 22.61 24.24 8.81 18.07
Operating Costs 15.42 16.41 15.76 17.17 16.99 16.69 16.66
----------------------------------------------------------------------------
Netback 13.07 26.81 33.53 53.38 56.68 15.64 39.78
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 137 134 127 126 133 138 131

Price Received ($/mcf) 4.75 3.42 7.57 9.67 8.00 6.06 7.73
Royalties & Other 0.59 0.15 1.18 1.53 1.52 1.07 1.32
Operating Costs 1.54 1.59 1.67 1.84 1.84 1.66 1.75
----------------------------------------------------------------------------
Netback 2.62 1.68 4.72 6.30 4.64 3.33 4.66
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 54.7 51.4 62.5 57.4 54.2 51.7 56.4

Price Received ($/bbl) 52.30 69.40 96.57 120.39 115.92 64.48 99.87
Royalties & Other 19.43 31.94 48.07 59.21 52.47 26.33 46.94
Operating Costs 9.62 10.39 7.76 8.80 7.82 9.80 8.51
In-country Taxes 4.92 9.01 11.82 17.45 16.11 7.60 13.31
----------------------------------------------------------------------------
Netback 18.33 18.06 28.92 34.93 39.52 20.75 31.11
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 19.8 14.9 19.3 19.1 22.9 22.3 20.9

Price Received ($/bbl) 55.48 71.58 101.70 130.90 126.56 65.48 105.47
Royalties & Other 0.40 8.84 11.93 22.08 21.89 4.97 15.11
Operating Costs 36.95 57.21 35.16 45.09 32.40 34.67 36.53
----------------------------------------------------------------------------
Netback 18.13 5.53 54.61 63.73 72.27 25.84 53.83
----------------------------------------------------------------------------

United States
Crude Oil:
Sales (mbbls/d) 10.4 12.1 13.7 11.3 8.5 3.8 9.3
Price Received ($/bbl) 46.27 66.23 94.07 120.77 122.46 58.43 104.94
Natural Gas:
Sales (mmcf/d) 50 61 112 99 70 31 78
Price Received ($/mcf) 5.93 4.58 9.03 11.80 10.14 8.09 10.07
Total Sales Volume (mboe/d) 18.8 22.2 32.4 27.8 20.2 8.9 22.3

Price Received ($/boe) 41.50 48.53 71.10 91.08 86.75 52.77 79.02
Royalties & Other 4.52 4.94 9.53 12.88 12.30 7.89 11.03
Operating Costs 13.79 13.11 8.20 9.28 15.62 21.58 11.57
----------------------------------------------------------------------------
Netback 23.19 30.48 53.37 68.92 58.83 23.30 56.42
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 100.8 97.0 108.9 89.0 107.0 96.4 100.3
Price Received ($/bbl) 51.60 69.42 93.38 118.24 114.89 58.60 96.23
Natural Gas:
Sales (mmcf/d) 21 17 22 24 18 16 20
Price Received ($/mcf) 5.50 3.67 6.82 7.06 7.53 5.44 6.78
Total Sales Volume (mboe/d) 104.3 99.8 112.6 93.0 110.0 99.0 103.7

Price Received ($/boe) 50.97 68.10 91.67 114.95 112.99 57.91 94.45
Operating Costs 5.48 5.85 5.67 7.42 6.71 7.39 6.75
----------------------------------------------------------------------------
Netback 45.49 62.25 86.00 107.53 106.28 50.52 87.70
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 5.5 3.6 6.0 5.7 5.7 5.8 5.8

Price Received ($/bbl) 41.68 66.83 91.85 113.18 120.11 72.43 98.98
Royalties & Other 3.26 5.17 7.46 8.95 9.42 5.81 7.88
Operating Costs 4.81 5.73 4.74 4.43 5.14 3.79 4.52
----------------------------------------------------------------------------
Netback 33.61 55.93 79.65 99.80 105.55 62.83 86.58
----------------------------------------------------------------------------

Company-Wide
Oil and Gas Sales (mboe/d) 241.4 228.9 270.1 240.4 250.9 226.9 247.0

Price Received ($/boe) 47.56 61.28 85.90 108.26 106.22 56.94 89.78
Royalties & Other 5.64 9.23 14.87 19.92 16.98 8.22 15.06
Operating Costs 10.62 11.95 9.46 11.89 10.90 12.01 11.04
In-country Taxes 1.11 2.02 2.74 4.16 3.48 1.73 3.04
----------------------------------------------------------------------------
Netback 30.19 38.08 58.83 72.29 74.86 34.98 60.64
----------------------------------------------------------------------------

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


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

Three Months Six Months
(Cdn$ millions, except Ended June 30 Ended June 30
per share amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,200 2,071 2,248 3,941
Marketing and Other (Note 15) 82 34 339 256
----------------------------------------
1,282 2,105 2,587 4,197
----------------------------------------

Expenses
Operating 320 348 625 657
Depreciation, Depletion,
Amortization and Impairment 413 334 822 698
Transportation and Other 232 195 433 400
General and Administrative 167 418 267 473
Exploration 77 101 130 133
Interest (Note 10) 74 16 142 43
----------------------------------------
1,283 1,412 2,419 2,404
----------------------------------------

Income(Loss) before Provision for
Income Taxes (1) 693 168 1,793
----------------------------------------

Provision for (Recovery of)
Income Taxes
Current 206 451 324 843
Future (229) (139) (316) (62)
----------------------------------------
(23) 312 8 781
----------------------------------------

Net Income 22 381 160 1,012
Less: Net Income Attributable to
Non-Controlling Interests (2) (1) (5) (2)
----------------------------------------

Net Income Attributable to Nexen Inc. 20 380 155 1,010
----------------------------------------
----------------------------------------

Earnings Per Common Share ($/share)
(Note 16)
Basic 0.04 0.72 0.30 1.91
----------------------------------------
----------------------------------------

Diluted 0.04 0.70 0.30 1.87
----------------------------------------
----------------------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.



Nexen Inc.
Unaudited Consolidated Balance Sheet

June 30 December 31
(Cdn$ millions, except share amounts) 2009 2008
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 1,974 2,003
Restricted Cash (Notes 2 and 8) 335 103
Accounts Receivable (Note 3) 3,272 3,163
Inventories and Supplies (Note 4) 598 484
Other 167 169
----------------------
Total Current Assets 6,346 5,922
----------------------

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $10,722
(December 31, 2008 - $10,393) 15,917 14,922
Goodwill 372 390
Future Income Tax Assets 921 351
Deferred Charges and Other Assets (Note 6) 370 570
----------------------
Total Assets 23,926 22,155
----------------------
----------------------

Liabilities
Current Liabilities
Accounts Payable and Accrued Liabilities (Note 9) 3,608 3,326
Accrued Interest Payable 63 67
Dividends Payable 26 26
----------------------
Total Current Liabilities 3,697 3,419
----------------------

Long-Term Debt (Note 10) 7,863 6,578
Future Income Tax Liabilities 2,852 2,619
Asset Retirement Obligations (Note 12) 1,044 1,024
Deferred Credits and Other Liabilities (Note 13) 1,167 1,324

Shareholders' Equity (Note 14)
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2009 - 521,205,270 shares
2008 - 519,448,590 shares 1,011 981
Contributed Surplus 2 2
Retained Earnings 6,393 6,290
Accumulated Other Comprehensive Loss (157) (134)
----------------------
Total Nexen Inc. Shareholders' Equity 7,249 7,139
Non-Controlling Interests 54 52
----------------------
Total Shareholders' Equity 7,303 7,191

----------------------
Commitments, Contingencies and Guarantees (Note 17)
Total Liabilities and Shareholders' Equity 23,926 22,155
----------------------
----------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.



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

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Operating Activities
Net Income 22 381 160 1,012
Charges and Credits to Income not
Involving Cash (Note 18) 394 470 713 852
Exploration Expense 77 101 130 133
Changes in Non-Cash Working Capital
(Note 18) (340) 232 80 372
Other (44) (21) (185) (38)
--------------------------------------
109 1,163 898 2,331


Financing Activities
Proceeds from (Repayment of) Term
Credit Facilities, Net 632 - 1,643 (228)
Proceeds from (Repayment of) Canexus
Term Credit Facilities, Net 42 (18) 52 (10)
Proceeds from Canexus Notes - 51 - 51
Repayment of Medium-Term Notes - (125) - (125)
Dividends on Common Shares (26) (27) (52) (40)
Distributions Paid to Non-Controlling
Interests (4) (3) (7) (7)
Issue of Common Shares and Exercise
of Tandem Options for Shares 7 14 30 40
Other - (2) (1) (2)
--------------------------------------
651 (110) 1,665 (321)


Investing Activities
Capital Expenditures
Exploration and Development (631) (606) (1,335) (1,375)
Proved Property Acquisitions - (2) (755) (2)
Marketing, Chemicals, Corporate
and Other (84) (30) (129) (47)
Proceeds on Disposition of Assets 1 - 15 -
Changes in Restricted Cash 67 (174) (247) (53)
Changes in Non-Cash Working Capital
(Note 18) (74) (76) (55) (54)
Other 1 (70) (1) (97)
--------------------------------------
(720) (958) (2,507) (1,628)


Effect of Exchange Rate Changes on
Cash and Cash Equivalents (120) (5) (85) 26
--------------------------------------

Increase (Decrease) in Cash and Cash
Equivalents (80) 90 (29) 408

Cash and Cash Equivalents - Beginning
of Period 2,054 524 2,003 206
--------------------------------------

Cash and Cash Equivalents - End of
Period (1) 1,974 614 1,974 614
--------------------------------------
--------------------------------------

(1) Cash and cash equivalents at June 30, 2009 consist of cash of $227
million and short-term investments of $1,747 million (June 30,
2008 - cash of $32 million and short-term investments of $582 million).

See accompanying notes to the Unaudited Consolidated Financial Statements.



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

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Common Shares, Beginning of Period 1,004 949 981 917
Issue of Common Shares 6 4 29 24
Exercise of Tandem Options for
Shares 1 10 1 16
Accrued Liability Relating to Tandem
Options Exercised for Common Shares - 9 - 15
---------------------------------------
Balance at End of Period 1,011 972 1,011 972
---------------------------------------
---------------------------------------

Contributed Surplus, Beginning of
Period 2 3 2 3
Exercise of Tandem Options - (1) - (1)
---------------------------------------
Balance at End of Period 2 2 2 2
---------------------------------------
---------------------------------------

Retained Earnings, Beginning of
Period 6,399 5,600 6,290 4,983
Net Income Attributable to
Nexen Inc. 20 380 155 1,010
Dividends on Common Shares (Note 14) (26) (27) (52) (40)
---------------------------------------
Balance at End of Period 6,393 5,953 6,393 5,953
---------------------------------------
---------------------------------------

Accumulated Other Comprehensive
Loss, Beginning of Period (128) (266) (134) (293)
Other Comprehensive Income (Loss) (29) (8) (23) 19
---------------------------------------
Balance at End of Period (157) (274) (157) (274)
---------------------------------------
---------------------------------------

Non-Controlling Interests,
Beginning of Period 52 64 52 67
Net Income Attributable to
Non-Controlling Interests 6 1 9 2
Distributions Declared to
Non-Controlling Interests (5) (4) (9) (8)
Issue of Partnership Units to
Non-Controlling Interests under
Distribution Reinvestment Plan 1 1 2 1
---------------------------------------
Balance at End of Period 54 62 54 62
---------------------------------------
---------------------------------------



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

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. 20 380 155 1,010
Other Comprehensive Income (Loss),
Net of Income Taxes:
Foreign Currency Translation
Adjustment
Net Gains (Losses) on Investment in
Self-Sustaining Foreign Operations (459) (42) (285) 144
Net Gains (Losses) on
Foreign-Denominated Debt
Hedging Self-Sustaining Foreign
Operations(1) 430 34 262 (125)
---------------------------------------
Other Comprehensive Income (Loss) (29) (8) (23) 19
---------------------------------------
Comprehensive Income (Loss)
Attributable to Nexen Inc. (9) 372 132 1,029
---------------------------------------
---------------------------------------

(1) Net of income tax expense for the three months ended June 30, 2009 of
$62 million (2008 - $4 million expense) and net of income tax expense
for the six months ended June 30, 2009 of $38 million (2008 -
$19 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 June 30, 2009 and December 31, 2008 and the results of our operations and our cash flows for the three and six months ended June 30, 2009 and 2008.

We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates on an ongoing basis, including those related to accruals, litigation, environmental and asset retirement obligations, recoverability of assets, income taxes, fair values of derivative assets and liabilities, capital adequacy and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. The results of operations and cash flows for the three and six months ended June 30, 2009 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2009. As at July 15, 2009, 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 2008 Form 10-K. Except as described below, the accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2008 Form 10-K.

Changes in Accounting Policies

Goodwill and Intangible Assets

On January 1, 2009, we retrospectively adopted the Canadian Institute of Chartered Accountants (CICA) Section 3064, Goodwill and Intangible Assets issued by the AcSB. This section clarifies the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Adoption of this standard did not have a material impact on our results of operations or financial position.

Business Combinations

On January 1, 2009, we prospectively adopted CICA Section 1582, Business Combinations issued by the AcSB. This section establishes principles and requirements of the acquisition method for business combinations and related disclosures. Adoption of this statement did not have a material impact on our results of operations or financial position.

Consolidated Financial Statements and Non-Controlling Interests

On January 1, 2009, we adopted CICA Sections 1601, Consolidated Financial Statements, and 1602, Non-Controlling Interests issued by the AcSB. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for non-controlling interests in consolidated financial statements subsequent to a business combination. Adoption of these statements did not have a material impact on our results of operations or financial position. The retrospective presentation changes have been included in the Unaudited Consolidated Financial Statements as applicable.

2. RESTRICTED CASH

At June 30, 2009, our restricted cash consists of margin deposits of $335 million (December 31, 2008 - $103 million) related to exchange-traded derivative financial contracts used by our energy marketing group to hedge physical commodities, and storage, transportation and customer sales contracts. We are required to maintain margin for net out-of-the-money derivative financial contracts. The increase in margin primarily relates to derivative financial contracts hedging our natural gas positions. Declining natural gas prices and widening time spreads increased the value of storage and fixed price customer sales contracts. Concurrently, the derivative financial contracts hedging these positions declined in value. Additional margin was required to cover the increase in the net out-of-the-money derivative financial contracts.



3. ACCOUNTS RECEIVABLE

June 30 December 31
2009 2008
----------------------------------------------------------------------------
Trade
Energy Marketing 1,682 1,501
Energy Marketing Derivative Contracts (Note 7) 614 755
Oil and Gas 778 639
Chemicals and Other 47 68
------------------------
3,121 2,963
Non-Trade 215 270
------------------------
3,336 3,233
Allowance for Doubtful Receivables (64) (70)
------------------------
Total 3,272 3,163
------------------------
------------------------

4. INVENTORIES AND SUPPLIES

June 30 December 31
2009 2008
----------------------------------------------------------------------------
Finished Products
Energy Marketing 466 384
Oil and Gas 21 17
Chemicals and Other 14 16
------------------------
501 417
Work in Process 9 6
Field Supplies 88 61
------------------------
Total 598 484
------------------------
------------------------


5. SUSPENDED EXPLORATION WELL COSTS

The following table shows the changes in capitalized exploratory well costs during the six months ended June 30, 2009 and the year ended December 31, 2008, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Suspended exploration well costs are included in property, plant and equipment.



Six Months Ended Year Ended
June 30 December 31
2009 2008
----------------------------------------------------------------------------
Beginning of Period 518 326
Exploratory Well Costs Capitalized Pending
the Determination of Proved Reserves 175 254
Capitalized Exploratory Well Costs Charged
to Expense (21) (81)
Transfers to Wells, Facilities and Equipment
Based on Determination of Proved Reserves - (29)
Effects of Foreign Exchange Rate Changes (21) 48
---------------------------------
End of Period 651 518
---------------------------------
---------------------------------


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.



June 30 December 31
2009 2008
----------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 356 239
Capitalized for a Period of Greater than One Year 295 279
------------------------
Total 651 518
------------------------
------------------------

Number of Projects that have Exploratory Well Costs
Capitalized for a Period Greater than One Year 9 7
------------------------


As at June 30, 2009, we have exploratory costs that have been capitalized for more than one year relating to our interests in two exploratory blocks in the Gulf of Mexico ($120 million), certain coalbed methane and shale gas exploratory activities in Canada ($77 million), four exploratory blocks in the North Sea ($78 million), and our interest in an exploratory block offshore Nigeria ($20 million). These costs relate to projects with 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 to assess commercial viability.



6. DEFERRED CHARGES AND OTHER ASSETS

June 30 December 31
2009 2008
----------------------------------------------------------------------------
Crude Oil Put Options and Natural Gas Swaps
(Note 7) (1) - 234
Long-Term Energy Marketing Derivative Contracts
(Note 7) 230 217
Long-Term Capital Prepayments 40 61
Asset Retirement Remediation Fund 7 9
Defined Benefit Pension Assets 47 3
Other 46 46
------------------------
Total 370 570
------------------------
------------------------

(1) The crude oil put options were reclassified to other current assets in
the first quarter as they settle within 12 months.


7. 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 as 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 June 30, 2009. 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.

We carry our long-term debt at amortized cost using the effective interest rate method. At June 30, 2009, the estimated fair value of our long-term debt was $7,571 million (December 31, 2008 - $5,686 million) as compared to the carrying value of $7,863 million (December 31, 2008 - $6,578 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers.


Derivatives

(a) Derivative contracts related to trading activities

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



June 30 December 31
2009 2008
----------------------------------------------------------------------------
Commodity Contracts 609 742
Foreign Exchange Contracts 5 13
------------------------
Accounts Receivable (Note 3) 614 755
------------------------

Commodity Contracts 229 213
Foreign Exchange Contracts 1 4
------------------------
Deferred Charges and Other Assets (Note 6) (1) 230 217
------------------------

Total Trading Derivative Assets 844 972
------------------------
------------------------

Commodity Contracts 616 585
Foreign Exchange Contracts 37 30
------------------------
Accounts Payable and Accrued Liabilities (Note 9) 653 615
------------------------

Commodity Contracts 216 248
Foreign Exchange Contracts 10 46
------------------------
Deferred Credits and Other Liabilities (Note 13) (1) 226 294
------------------------

Total Trading Derivative Liabilities 879 909
------------------------
------------------------

Total Net Trading Derivative Contracts (35) 63
------------------------
------------------------

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

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

June 30
2009
----------------------------------------------------------------------------
Current Trading Assets 4,320
Non-Current Trading Assets 1,208
---------
Total Trading Derivative Assets 5,528
---------
---------

Current Trading Liabilities 4,359
Non-Current Trading Liabilities 1,204
---------
Total Trading Derivative Liabilities 5,563
---------
---------

---------
Total Net Trading Derivative Contracts (35)
---------
---------


Trading revenues generated by our energy marketing group include gains and losses on derivative instruments and non-derivative instruments such as physical inventory. During the three and six months ended June 30, 2009, the following trading revenues were recognized in marketing and other income:



Three Months Six Months
Ended June 30 Ended June 30
2009 2009
----------------------------------------------------------------------------
Commodity 223 571
Foreign Exchange (2) (83)
------------------------------
Marketing Revenue 221 488
------------------------------
------------------------------


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



Three Months Six Months
Ended June 30 Ended June 30
2009 2009
----------------------------------------------------------------------------
Natural Gas bcf/d 18.8 23.7
Crude Oil mmbbls/d 3.9 3.8
Power GWh/d 244.4 228.4
Foreign Exchange USD millions 852 1,230
Foreign Exchange Euro millions 107 260
------------------------------

(b) Derivative contracts related to non-trading activities

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

June 30 December 31
2009 2008
----------------------------------------------------------------------------
Accounts Receivable 36 6
Deferred Charges and Other Assets (Note 6) (1) - 234
------------------------
Total Non-Trading Derivative Assets 36 240
------------------------
------------------------

Accounts Payable and Accrued Liabilities 28 21
Deferred Credits and Other Liabilities (Note 13) (1) 13 26
------------------------
Total Non-Trading Derivative Liabilities 41 47
------------------------
------------------------

Total Net Non-Trading Derivative Assets (2) (5) 193
------------------------
------------------------

(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 2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crude oil production for $14 million. These options establish an annual average Dated Brent floor price of US$60/bbl on these volumes. In September 2008, Lehman Brothers filed for bankruptcy protection. This impacts approximately 25,000 bbls/d of our 2009 put options and the carrying value of these put options has been reduced to nil. The crude oil put options are carried at fair value and are classified as long-term or short-term based on their anticipated settlement date. Fair value of the put options is supported by multiple quotes obtained from third party brokers, which were validated with observable market data to the extent possible. With the rise in Dated Brent oil price, the fair value of the crude oil put options decreased, which is included in marketing and other income.



Change in Fair Value
----------------------------
Three Months Six Months
Ended Ended
Notional Average Fair June 30, June 30,
Volumes Term Floor Price Value 2009 2009
----------------------------------------------------------------------------
(bbls/d) (US$/bbl)
Dated Brent
Crude Oil
Put Options 45,000 2009 60 36 (179) (195)
Dated Brent
Crude Oil
Put Options 25,000 2009 60 - - -
-----------------------------------
36 (179) (195)
-----------------------------------
-----------------------------------


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 long-term or short-term based on their anticipated settlement date. The change in fair value of the fixed price natural gas contracts and natural gas swaps is included in marketing and other income.



Change in Fair Value
------------------------------
Three Months Six Months
Notional Average Fair Ended Ended
Volumes Term Price Value June 30, 2009 June 30, 2009
----------------------------------------------------------------------------
(Gj/d) ($/Gj)
Fixed-Price
Natural Gas
Contracts 15,514 2009 2.28 (12) (1) 9
15,514 2010 2.28 (9) 6 17
Natural Gas
Swaps 15,514 2009 7.60 (16) - (22)
15,514 2010 7.60 (4) 2 (5)
--------------------------------------
(41) 7 (1)
--------------------------------------
--------------------------------------


(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, 2008. The following table includes our derivatives carried at fair value for our trading and non-trading activities as at June 30, 2009. 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 Level 1 Level 2 Level 3 Total
----------------------------------------------------------------------------
Trading Derivatives (201) 162 4 (35)
Non-Trading Derivatives - (5) - (5)
---------------------------------------
Total (201) 157 4 (40)
---------------------------------------
---------------------------------------

A reconciliation of changes in the fair value of our derivatives classified
as Level 3 for the six months ended June 30, 2009 is provided below:

Level 3
----------------------------------------------------------------------------
Beginning of Period (82)
Realized and Unrealized Gains (Losses) 49
Purchases, Issuances and Settlements 46
Transfers In and/or Out of Level 3 (9)
---------
End of Period 4
---------
---------

Unsettled Gains (Losses) Relating to Instruments Still Held as of
June 30, 2009 41
---------
---------


Trading derivatives 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.

8. 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 exchange rates and interest rates, which 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.

Commodity price risk

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

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

Our energy marketing business is focused on providing services for our customers and suppliers to meet their energy commodity needs. We market and trade physical energy commodities including crude oil, natural gas, electricity and other commodities in selected regions of the world. We accomplish this by buying and selling physical commodities, by acquiring and holding rights to physical transportation and storage assets for these commodities, and by building strong relationships with our customers and suppliers. In order to manage the commodity and foreign exchange price risks that are generated by 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. We may also carry exposures to the absolute change in commodity prices based on our market views or as a consequence of managing our physical and financial positions on a daily basis.

Our risk management activities make use of tools such as Value-at-Risk (VaR) and stress testing consistent with the methodology used at December 31, 2008. Our period end, high, low and average VaR amounts for the three and six months ended June 30, 2009 are as follows:



Three Months Six Months
Ended June 30 Ended June 30
Value-at-Risk 2009 2008 2009 2008
----------------------------------------------------------------------------
Period End 15 31 15 31
High 19 40 24 40
Low 13 29 13 21
Average 15 34 17 32
------------------------------------


If market shocks occur in 2009 as they did 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 non-normal 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, Syncrude 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. Net revenue from our foreign operations and our US-dollar borrowings 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 cash flows. We designate a portion of our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations.

The effective portion of the foreign exchange gains or losses related to our designated US-dollar debt are included in accumulated other comprehensive income in shareholders' equity. Our net investment in self-sustaining foreign operations and our designated US-dollar debt at June 30, 2009 and December 31, 2008 are as follows:



June 30 December 31
(US$ millions) 2009 2008
----------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign Operations 4,350 4,662
Designated US-Dollar Debt 4,350 4,545
------------------------


For the three and six months ended June 30, 2009, the ineffective portion of the net foreign exchange gain was $41 million and $57 million, respectively ($36 million and $50 million, respectively, net of income tax expense) and is included in marketing and other income. A one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $44 million, net of income tax and would increase or decrease our net income by approximately $8 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 both our trading and non-trading 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, crude oil refiners and utilities, and are subject to normal industry credit risk. Approximately 94% 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, 2008.

At June 30, 2009, only one counterparty individually made up more than 10% of our credit exposure. This counterparty is a major integrated oil company 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.



June 30 December 31
Credit Rating 2009 2008
----------------------------------------------------------------------------
A or higher 68% 65%
BBB 26% 29%
Non-Investment Grade 6% 6%
------------------------
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 $64 million for credit risk with our counterparties. In addition, we incorporate the credit risk associated with counterparty default, as well as Nexen's own credit risk, into our estimates of fair value.

Collateral received from customers at June 30, 2009 includes $102 million of cash and $553 million of letters of credit. The cash received reflects customer deposits that are 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 become due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they become due, and to operate our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At June 30, 2009, we had approximately $2.5 billion of cash and available committed lines of credit. This includes $2.0 billion of cash and cash equivalents on hand. In addition, we have undrawn term credit facilities of $0.9 billion, of which $0.4 billion was supporting letters of credit at June 30, 2009. These facilities are available until 2012. We also have about $0.5 billion of undrawn, uncommitted credit facilities at June 30, 2009.

The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at June 30, 2009:



less than greater than
Total 1 Year 1-3 Years 4-5 Years 5 Years
----------------------------------------------------------------------------
Long-Term Debt (1) 7,935 - 251 3,384 4,300
Interest on Long-Term
Debt (2) 7,067 314 628 607 5,518
-----------------------------------------------------
Total 15,002 314 879 3,991 9,818
-----------------------------------------------------
-----------------------------------------------------

(1) Excludes cash and cash equivalents currently available.

(2) Excludes interest on term credit facilities of $3.6 billion and Canexus
term credit facilities of $455 million as the amounts drawn on the
facilities fluctuate. Based on amounts drawn at June 30, 2009 and
current interest rates, we would be required to pay $33 million per year
until the outstanding amounts on the term credit facilities are repaid.


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



less than greater than
Total 1 Year 1-3 Years 4-5 Years 5 Years
----------------------------------------------------------------------------
Trading Derivatives
(Note 7) 879 653 131 25 70
Non-Trading Derivatives
(Note 7) 41 28 13 - -
----------------------------------------------------
Total 920 681 144 25 70
----------------------------------------------------
----------------------------------------------------


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 rating. Based on contracts in place and commodity prices at June 30, 2009, we could be required to post collateral of up to $1.1 billion if we were downgraded to non-investment grade. This represents the maximum amount of collateral that we would be required to post assuming a severe event that causes all rating agencies to simultaneously downgrade us. This amount includes trade payables of $795 million and derivative contracts with a fair value of $313 million. All of these obligations are included on our June 30, 2009 balance sheet. In the event of a ratings downgrade, we could monetize our trading inventories and receivables and draw on our existing credit facilities to meet our collateral obligations. Various actions can be taken, in anticipation of a downgrade that would reduce the maximum amount of collateral we would need to provide.

At June 30, 2009, collateral posted with counterparties includes $15 million of cash and $209 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 $335 million (December 31, 2008 - $103 million), which have been included in restricted cash.



9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

June 30 December 31
2009 2008
----------------------------------------------------------------------------
Accrued Payables 1,808 2,033
Energy Marketing Derivative Contracts (Note 7) 653 615
Trade Payables 505 303
Stock-Based Compensation 130 97
Income Taxes Payable 206 69
Other 306 209
------------------------
Total 3,608 3,326
------------------------
------------------------

10. SHORT-TERM BORROWINGS AND LONG-TERM DEBT

June 30 December 31
2009 2008
----------------------------------------------------------------------------
Canexus Term Credit Facilities, due 2011 (US$227
million drawn) (a) 263 223
Term Credit Facilities, due 2012 (US$2.3 billion
drawn) (b) 2,732 1,225
Canexus Notes, due 2013 (US$50 million) 58 61
Notes, due 2013 (US$500 million) 581 612
Notes, due 2015 (US$250 million) 291 306
Notes, due 2017 (US$250 million) 291 306
Notes, due 2028 (US$200 million) 232 245
Notes, due 2032 (US$500 million) 581 612
Notes, due 2035 (US$790 million) 918 968
Notes, due 2037 (US$1,250 million) 1,453 1,531
Subordinated Debentures, due 2043 (US$460 million) 535 563
------------------------
7,935 6,652
Unamortized Debt Issue Costs (72) (74)
------------------------
Total 7,863 6,578
------------------------
------------------------


(a) Canexus term credit facilities

Canexus has $455 million (US$391 million) of committed, secured term credit facilities, $432 million (US$371 million) of which is available until 2011, with the balance due 2013. At June 30, 2009, $263 million (US$227 million) was drawn on these facilities (December 31, 2008 - $223 million (US$182 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 2.1% for the three months ended June 30, 2009 (three months ended June 30, 2008 - 4.6%) and 2.4% for the six months ended June 30, 2009 (six months ended June 30, 2008 - 4.5%).

(b) Term credit facilities

We have unsecured term credit facilities of $3.6 billion (US$3.1 billion) available until 2012. At June 30, 2009, $2.7 billion (US$2.3 billion) was drawn on these facilities (December 31, 2008 - $1.2 billion (US$1 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 1.1% for the three months ended June 30, 2009 (three months ended June 30, 2008 - 3.3%) and 1.1% for the six months ended June 30, 2009 (six months ended June 30, 2008 - 3.7%). At June 30, 2009, $392 million (US$337 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2008 - $381 million (US$311 million)).

(c) Interest expense



Three Months Six Months
Ended June 30 Ended June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Long-Term Debt 89 69 178 145
Other 3 6 8 10
------------------------------------
Total 92 75 186 155
Less: Capitalized (18) (59) (44) (112)
------------------------------------
Total 74 16 142 43
------------------------------------
------------------------------------


Capitalized interest relates to and is included as part of the cost of our oil and gas and Syncrude 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 $496 million (US$427 million), none of which were drawn at June 30, 2009 (December 31, 2008 - nil). We utilized $33 million (US$28 million) of these facilities to support outstanding letters of credit at June 30, 2009 (December 31, 2008 - $29 million (US$24 million)). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 0.9% for the three months ended June 30, 2009 (three months ended June 30, 2008 - 3.7%) and 2.1% for the six months ended June 30, 2009 (six months ended June 30, 2008 - 3.8%).

11. CAPITAL MANAGEMENT

Our objectives and processes for managing our capital structure are consistent with those in place at December 31, 2008. Our capital consists of shareholders' equity, short-term borrowings, long-term debt and cash and cash equivalents as follows:



June 30 December 31
2009 2008
----------------------------------------------------------------------------
Net Debt (1)
Long-Term Debt 7,863 6,578
Less: Cash and Cash Equivalents (1,974) (2,003)
------------------------
Total 5,889 4,575
------------------------
------------------------

Shareholders' Equity 7,303 7,191
------------------------
------------------------

(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.


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

We use the ratio of net debt to cash flow from operating activities as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is a non-GAAP measure that does not have any standard meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by others. We calculate net debt using the GAAP measures of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash).

For the twelve months ended June 30, 2009, our net debt to cash flow from operating activities ratio was 2.1 times compared to 1.1 times at December 31, 2008. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher 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 was 10.4 times at June 30, 2009 (December 31, 2008 - 15.6 times). Interest coverage is calculated by dividing our twelve-month trailing adjusted EBITDA by interest expense before capitalized interest. Adjusted EBITDA is a non-GAAP measure. The calculation of Adjusted EBITDA is set out in the following table and is unlikely to be comparable to similar measures presented by others.



Twelve Months Year Ended
Ended June 30 December 31
2009 2008
----------------------------------------------------------------------------
Net Income 860 1,715
Add:
Interest Expense 193 94
Provision for Income Taxes 684 1,457
Depreciation, Depletion, Amortization and
Impairment 2,138 2,014
Exploration Expense 399 402
Recovery of Non-Cash Stock-Based
Compensation (430) (272)
Change in Fair Value of Crude Oil Put
Options (18) (203)
Other Non-Cash Expenses (34) (1)
------------------------------
Adjusted EBITDA 3,792 5,206
------------------------------
------------------------------


12. ASSET RETIREMENT OBLIGATIONS

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



Six Months Year Ended
Ended June 30 December 31
2009 2008
----------------------------------------------------------------------------
Balance at Beginning of Period 1,059 832
Obligations Incurred with Development Activities 22 32
Obligations Settled (16) (45)
Accretion Expense 34 58
Revisions to Estimates (25) 159
Effects of Changes in Foreign Exchange Rate 5 23
------------------------------
Balance at End of Period (1)(2) 1,079 1,059
------------------------------
------------------------------

(1) Obligations due within 12 months of $35 million (December 31, 2008 -
$35 million) have been included in accounts payable and accrued
liabilities.
(2) Obligations relating to our oil and gas activities amount to $1,028
million (December 31, 2008 - $1,009 million) and obligations relating
to our chemicals business amount to $51 million (December 31, 2008 - $50
million).


Our total estimated undiscounted inflated asset retirement obligations amount to $2,470 million (December 31, 2008 - $2,393 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted, risk-free rate of 5.9%. Approximately $396 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.



13. DEFERRED CREDITS AND OTHER LIABILITIES

June 30 December 31
2009 2008
----------------------------------------------------------------------------
Deferred Tax Credit 616 709
Long-Term Energy Marketing Derivative Contracts
(Note 7) 226 294
Deferred Transportation Revenue 61 69
Fixed-Price Natural Gas Contracts and Swaps (Note 7) 13 26
Defined Benefit Pension Obligations 70 67
Capital Lease Obligations 62 53
Other 119 106
------------------------
Total 1,167 1,324
------------------------
------------------------


14. SHAREHOLDERS' EQUITY

Dividends

Dividends per common share for the six months ended June 30, 2009 were $0.10 per common share (2008 - $0.075). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.



15. MARKETING AND OTHER INCOME

Three Months Six Months
Ended June 30 Ended June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Marketing Revenue, Net (Note 7) 221 21 488 232
Change in Fair Value of Crude Oil Put
Options (Note 7) (179) (10) (195) (10)
Interest 1 3 3 13
Foreign Exchange Gains (Losses) - (6) 19 (1)
Other 39 26 24 22
------------------------------------
Total 82 34 339 256
------------------------------------
------------------------------------


16. EARNINGS PER COMMON SHARE

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



Three Months Six Months
Ended June 30 Ended June 30
(millions of shares) 2009 2008 2009 2008
----------------------------------------------------------------------------
Weighted-average number of common
shares outstanding 521.2 530.0 520.7 529.5
Shares issuable pursuant to tandem
options 11.1 24.9 11.2 25.7
Shares notionally purchased from
proceeds of tandem options (6.8) (14.4) (7.9) (16.4)
---------------------------------------
Weighted-average number of diluted
common shares outstanding 525.5 540.5 524.0 538.8
---------------------------------------
---------------------------------------


In calculating the weighted-average number of diluted common shares outstanding for the three and six months ended June 30, 2009, we excluded 13,100,342 and 13,158,635 tandem options, respectively, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three and six months ended June 30, 2008, we excluded 1,667 and 25,833 tandem options, respectively, because their exercise price was greater than the average common share market price in the period. During the periods presented, outstanding tandem options were the only potential dilutive instruments.

17. COMMITMENTS, CONTINGENCIES AND GUARANTEES

As described in Note 16 to the Audited Consolidated Financial Statements included in our 2008 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. There have been no significant developments since year-end.



18. CASH FLOWS

(a) Charges and credits to income not involving cash

Three Months Six Months
Ended June 30 Ended June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Depreciation, Depletion, Amortization
and Impairment 413 334 822 698
Stock-Based Compensation 42 259 42 200
Recovery of Future Income Taxes (229) (139) (316) (62)
Change in Fair Value of Crude Oil Put
Options 179 10 195 10
Other (11) 6 (30) 6
---------------------------------------
Total 394 470 713 852
---------------------------------------
---------------------------------------

(b) Changes in non-cash working capital

Three Months Six Months
Ended June 30 Ended June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Accounts Receivable (471) (878) (173) (1,324)
Inventories and Supplies (80) (310) (129) (388)
Other Current Assets 20 (6) 12 (16)
Accounts Payable and Accrued
Liabilities 134 1,349 319 2,032
Other (17) 1 (4) 14
---------------------------------------
Total (414) 156 25 318
---------------------------------------
---------------------------------------

Relating to:
Operating Activities (340) 232 80 372
Investing Activities (74) (76) (55) (54)
---------------------------------------
Total (414) 156 25 318
---------------------------------------
---------------------------------------


(c) Other cash flow information
Three Months Six Months
Ended June 30 Ended June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Interest Paid 97 82 178 148
Income Taxes Paid 34 76 68 161
------------------------------------


Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $31 million for the three months ended June 30, 2009 (2008 - $24 million) and $43 million for the six months ended June 30, 2009 (2008 - $34 million).

19. OPERATING SEGMENTS AND RELATED INFORMATION

Nexen is involved in activities relating to Oil and Gas, Energy Marketing, Syncrude and Chemicals in various geographic locations as described in Note 22 to the Audited Consolidated Financial Statements included in our 2008 Form 10-K.



Three months ended June 30, 2009

Oil and Gas
------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------------------------------------
Net Sales 175 98 88 618 20
Marketing and Other 4 1 - 4 -
------------------------------------------------
Total Revenues 179 99 88 622 20

Less: Expenses
Operating 49 42 27 53 2
Depreciation, Depletion,
Amortization and
Impairment 32 62 80 182 4
Transportation and Other 15 8 3 14 -
General and Administrative(3) (3) 28 24 5 16
Exploration - 8 37 11 21 (4)
Interest - - - - -
------------------------------------------------
Income (Loss)
before Income Taxes 86 (49) (83) 357 (23)
Less: Provisions for
(Recovery of) Income Taxes 30 (13) (28) 170 (18)
Less: Non-Controlling
Interests - - - - -
------------------------------------------------
Net Income (Loss) 56 (36) (55) 187 (5)
------------------------------------------------
------------------------------------------------

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

Capital Expenditures
Development and Other 22 138 33 109 140
Exploration - 53 39 49 26
------------------------------------------------
22 191 72 158 166
------------------------------------------------
------------------------------------------------

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


Energy Corporate
Syncrude Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 85 7 109 - 1,200
Marketing and Other 1 221 29 (178) (2) 82
---------------------------------------------------
Total Revenues 86 228 138 (178) 1,282

Less: Expenses
Operating 77 8 62 - 320
Depreciation, Depletion,
Amortization and
Impairment 9 3 29 12 413
Transportation and Other 5 166 14 7 232
General and Administrative (3) 1 26 16 54 167
Exploration - - - - 77
Interest - - 2 72 74
---------------------------------------------------
Income (Loss)
before Income Taxes (6) 25 15 (323) (1)
Less: Provisions for
(Recovery of) Income Taxes (2) 9 4 (175) (23)
Less: Non-Controlling
Interests - - 2 - 2
---------------------------------------------------
Net Income (Loss) (4) 16 9 (148) 20
---------------------------------------------------
---------------------------------------------------

Identifiable Assets 1,232 3,332 (6) 618 1,321 23,926
---------------------------------------------------
---------------------------------------------------

Capital Expenditures
Development and Other 22 3 72 9 548
Exploration - - - - 167
---------------------------------------------------
22 3 72 9 715
---------------------------------------------------
---------------------------------------------------

Property, Plant and
Equipment
Cost 1,407 259 1,005 349 26,639
Less: Accumulated DD&A 251 83 507 223 10,722
---------------------------------------------------
Net Book Value 1,156 176 498 126 15,917
---------------------------------------------------
---------------------------------------------------

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


Three months ended June 30, 2008

Oil and Gas
------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------------------------------------
Net Sales 319 206 198 973 54
Marketing and Other 3 1 3 10 1
------------------------------------------------
Total Revenues 322 207 201 983 55

Less: Expenses
Operating 45 47 24 63 2
Depreciation, Depletion,
Amortization and
Impairment 40 47 62 143 4
Transportation and Other 2 5 - - -
General and Administrative(3) 13 78 45 13 58
Exploration - 32 23 17 29 (4)
Interest - - - - -
------------------------------------------------
Income (Loss)
before Income Taxes 222 (2) 47 747 (38)
Less: Provisions for
(Recovery of) Income Taxes 78 (1) 17 378 (3)
Less: Non-Controlling
Interests - - - - -
------------------------------------------------
Net Income (Loss) 144 (1) 30 369 (35)
------------------------------------------------
------------------------------------------------

Identifiable Assets 340 6,092 (5) 1,856 4,911 494
------------------------------------------------
------------------------------------------------

Capital Expenditures
Development and Other 14 259 55 121 10
Exploration 4 26 42 55 9
Proved Property
Acquisition - 2 - - -
------------------------------------------------
18 287 97 176 19
------------------------------------------------
------------------------------------------------

Property, Plant and
Equipment
Cost 2,284 7,424 3,480 5,128 310
Less: Accumulated DD&A 2,088 1,682 1,937 1,235 88
------------------------------------------------
Net Book Value 196 5,742 (5) 1,543 3,893 222
------------------------------------------------
------------------------------------------------


Energy Corporate
Syncrude Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 189 21 111 - 2,071
Marketing and Other - 21 6 (11)(2) 34
---------------------------------------------------
Total Revenues 189 42 117 (11) 2,105

Less: Expenses
Operating 78 14 75 - 348
Depreciation, Depletion,
Amortization and
Impairment 12 4 11 11 334
Transportation and Other 2 166 10 10 195
General and Administrative(3) - 41 8 162 418
Exploration - - - - 101
Interest - - 2 14 16
---------------------------------------------------
Income (Loss)
before Income Taxes 97 (183) 11 (208) 693
Less: Provisions for
(Recovery of) Income Taxes 27 (53) 3 (134) 312
Less: Non-Controlling
Interests - - 1 - 1
---------------------------------------------------
Net Income (Loss) 70 (130) 7 (74) 380
---------------------------------------------------
---------------------------------------------------

Identifiable Assets 1,256 5,551 (6) 525 679 21,704
---------------------------------------------------
---------------------------------------------------

Capital Expenditures
Development and Other 11 1 20 9 500
Exploration - - - - 136
Proved Property
Acquisition - - - - 2
---------------------------------------------------
11 1 20 9 638
---------------------------------------------------
---------------------------------------------------

Property, Plant and
Equipment
Cost 1,348 264 866 312 21,416
Less: Accumulated DD&A 223 68 483 187 7,991
---------------------------------------------------
Net Book Value 1,125 196 383 125 13,425
---------------------------------------------------
---------------------------------------------------

(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $3 million, foreign exchange losses of $6
million, decrease in the fair value of crude oil put options of $10
million and other gains of $2 million.
(3) Includes stock-based compensation expense of $328 million.
(4) Includes exploration activities primarily in Norway and Colombia.
(5) Includes costs of $4,223 million related to our insitu oil sands
projects (Long Lake and future phases).
(6) Approximately 83% of Marketing's identifiable assets are accounts
receivable and inventories.


Six months ended June 30, 2009

Oil and Gas
------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------------------------------------
Net Sales 337 189 151 1,096 39
Marketing and Other 7 8 - 8 -
-----------------------------------------------
Total Revenues 344 197 151 1,104 39

Less: Expenses
Operating 96 83 50 104 4
Depreciation, Depletion,
Amortization and
Impairment 73 125 148 375 9
Transportation and Other 18 11 16 11 -
General and Administrative(3) 1 42 38 7 24
Exploration - 29 47 19 35 (4)
Interest - - - - -
-----------------------------------------------
Income (Loss)
before Income Taxes 156 (93) (148) 588 (33)
Less: Provisions for
(Recovery of) Income Taxes 54 (24) (51) 256 (24)
Less: Non-Controlling
Interests - - - - -
-----------------------------------------------
Net Income (Loss) 102 (69) (97) 332 (9)
-----------------------------------------------
-----------------------------------------------

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

Capital Expenditures
Development and Other 51 384 75 258 198
Exploration - 147 65 77 41
Proved Property Acquisitions - 755 - - -
-----------------------------------------------
51 1,286 140 335 239
-----------------------------------------------
-----------------------------------------------

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


Energy Corporate
Syncrude Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 183 20 233 - 2,248
Marketing and Other 1 488 15 (188) (2) 339
--------------------------------------------------
Total Revenues 184 508 248 (188) 2,587

Less: Expenses
Operating 143 16 129 - 625
Depreciation, Depletion,
Amortization and
Impairment 20 7 41 24 822
Transportation and Other 12 328 24 13 433
General and Administrative(3) 1 49 25 80 267
Exploration - - - - 130
Interest - - 4 138 142
--------------------------------------------------
Income (Loss)
before Income Taxes 8 108 25 (443) 168
Less: Provisions for
(Recovery of) Income Taxes 2 44 6 (255) 8
Less: Non-Controlling
Interests - - 5 - 5
--------------------------------------------------
Net Income (Loss) 6 64 14 (188) 155
--------------------------------------------------
--------------------------------------------------

Identifiable Assets 1,232 3,332 (6) 618 1,321 23,926
--------------------------------------------------
--------------------------------------------------

Capital Expenditures
Development and Other 39 11 108 10 1,134
Exploration - - - - 330
Proved Property
Acquisitions - - - - 755
--------------------------------------------------
39 11 108 10 2,219
--------------------------------------------------
--------------------------------------------------

Property, Plant and
Equipment
Cost 1,407 259 1,005 349 26,639
Less: Accumulated DD&A 251 83 507 223 10,722
--------------------------------------------------
Net Book Value 1,156 176 498 126 15,917
--------------------------------------------------
--------------------------------------------------

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


Six months ended June 30, 2008

Oil and Gas
------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------------------------------------
Net Sales 595 353 379 1,912 100
Marketing and Other 7 1 4 11 1
------------------------------------------------
Total Revenues 602 354 383 1,923 101

Less: Expenses
Operating 90 89 48 120 5
Depreciation, Depletion,
Amortization and
Impairment 74 94 136 313 8
Transportation and Other 4 10 1 - -
General and Administrative(4) 11 79 51 12 59
Exploration - 36 29 24 44 (5)
Interest - - - - -
------------------------------------------------
Income (Loss)
before Income Taxes 423 46 118 1,454 (15)
Less: Provisions for
(Recovery of) Income Taxes 148 13 42 737 -
Less: Non-Controlling
Interests - - - - -
------------------------------------------------
Net Income (Loss) 275 33 76 717 (15)
------------------------------------------------
------------------------------------------------

Identifiable Assets 340 6,092 (6) 1,856 4,911 494
------------------------------------------------
------------------------------------------------

Capital Expenditures
Development and Other 32 610 134 221 38
Exploration 9 112 109 71 19
Proved Property
Acquisitions - 2 - - -
------------------------------------------------
41 724 243 292 57
------------------------------------------------
------------------------------------------------

Property, Plant and
Equipment
Cost 2,284 7,424 3,480 5,128 310
Less: Accumulated DD&A 2,088 1,682 1,937 1,235 88
------------------------------------------------
Net Book Value 196 5,742 (6) 1,543 3,893 222
------------------------------------------------
------------------------------------------------


Energy Corporate
Syncrude Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 347 35 220 - 3,941
Marketing and Other - 232 (1) 1 (2) 256
--------------------------------------------------
Total Revenues 347 267 219 1 4,197

Less: Expenses
Operating 140 23 142 - 657
Depreciation, Depletion,
Amortization and
Impairment 24 7 21 21 698
Transportation and Other 7 339 29 (3) 10 400
General and Administrative(4) 1 67 15 178 473
Exploration - - - - 133
Interest - - 5 38 43
--------------------------------------------------
Income (Loss)
before Income Taxes 175 (169) 7 (246) 1,793
Less: Provisions for
(Recovery of) Income Taxes 49 (52) 3 (159) 781
Less: Non-Controlling
Interests - - 2 - 2
--------------------------------------------------
Net Income (Loss) 126 (117) 2 (87) 1,010
--------------------------------------------------
--------------------------------------------------

Identifiable Assets 1,256 5,551 (7) 525 679 21,704
--------------------------------------------------
--------------------------------------------------

Capital Expenditures
Development and Other 20 1 33 13 1,102
Exploration - - - - 320
Proved Property
Acquisitions - - - - 2
--------------------------------------------------
20 1 33 13 1,424
--------------------------------------------------
--------------------------------------------------

Property, Plant and
Equipment
Cost 1,348 264 866 312 21,416
Less: Accumulated DD&A 223 68 483 187 7,991
--------------------------------------------------
Net Book Value 1,125 196 383 125 13,425
--------------------------------------------------
--------------------------------------------------

(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $13 million, foreign exchange losses of
$1 million, decrease in the fair value of crude oil put options of $10
million and other losses of $1 million.
(3) Includes severance accrual of $7 million in connection with North
Vancouver technology conversion project.
(4) Includes stock-based compensation expense of $287 million.
(5) Includes exploration activities primarily in Norway and Colombia.
(6) Includes costs of $4,223 million related to our insitu oil sands
projects (Long Lake and future phases).
(7) Approximately 83% 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 (Loss) - US GAAP
For the Three and Six Months Ended June 30

Three Months Six Months
(Cdn$ millions, Ended June 30 Ended June 30
except per share amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,200 2,071 2,248 3,941
Marketing and Other (v); (vi) 66 (102) 358 104
---------------------------------------
1,266 1,969 2,606 4,045
---------------------------------------

Expenses
Operating (i) 320 347 625 657
Depreciation, Depletion, Amortization
and Impairment 413 334 822 698
Transportation and Other (v) 231 191 425 396
General and Administrative (iv) 197 390 305 452
Exploration 77 101 130 133
Interest 74 16 142 43
---------------------------------------
1,312 1,379 2,449 2,379
---------------------------------------

Income (Loss) before Provision for
Income Taxes (46) 590 157 1,666
---------------------------------------

Provision for (Recovery of) Income
Taxes
Current 206 451 324 843
Deferred (iv); (vi) (242) (180) (316) (114)
---------------------------------------
(36) 271 8 729
---------------------------------------

Net Income (Loss) (10) 319 149 937
Less: Net Income Attributable to
Non-Controlling Interests (2) (1) (5) (2)
---------------------------------------

Net Income (Loss) Attributable to Nexen
Inc. - US GAAP (1) (12) 318 144 935
---------------------------------------
---------------------------------------

Earnings (Loss) Per Common Share
($/share) (Note 16)
Basic (0.02) 0.60 0.28 1.77
---------------------------------------
---------------------------------------

Diluted (0.02) 0.59 0.28 1.74
---------------------------------------
---------------------------------------

(1) Reconciliation of Canadian and US GAAP Net Income (Loss)

Three Months Six Months
Ended June 30 Ended June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Net Income - Canadian GAAP 20 380 155 1,010
Impact of US Principles, Net of
Income Taxes:
Stock-based Compensation (iv) (22) 20 (28) 15
Inventory Valuation (vi) (10) (83) 17 (90)
Other - 1 - -
---------------------------------------
Net Income (Loss) - US GAAP (12) 318 144 935
---------------------------------------
---------------------------------------

Unaudited Consolidated Balance Sheet - US GAAP

June 30 December 31
(Cdn$ millions, except share amounts) 2009 2008
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 1,974 2,003
Restricted Cash 335 103
Accounts Receivable 3,272 3,163
Inventories and Supplies (vi) 567 426
Other 167 169
-------------------------
Total Current Assets 6,315 5,864
-------------------------

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $11,115
(December 31, 2008 - $10,786) (i); (iii) 15,868 14,873
Goodwill 372 390
Deferred Income Tax Assets 921 351
Deferred Charges and Other Assets 370 570
-------------------------
Total Assets 23,846 22,048
-------------------------
-------------------------

Liabilities and Shareholders' Equity
Current Liabilities
Accounts Payable and Accrued Liabilities (iv) 3,704 3,384
Accrued Interest Payable 63 67
Dividends Payable 26 26
-------------------------
Total Current Liabilities 3,793 3,477
-------------------------

Long-Term Debt 7,863 6,578
Deferred Income Tax Liabilities (i); (ii); (iv);
(vi); (vii) 2,776 2,543
Asset Retirement Obligations 1,044 1,024
Deferred Credits and Other Liabilities (ii) 1,271 1,428

Shareholders' Equity
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2009 - 521,205,270 shares
2008 - 519,448,590 shares 1,011 981
Contributed Surplus 2 2
Retained Earnings (i) - (vii) 6,264 6,172
Accumulated Other Comprehensive Loss (ii) (232) (209)
-------------------------
Total Nexen Inc. Shareholders' Equity 7,045 6,946
Non-Controlling Interests 54 52
-------------------------
Total Shareholders Equity 7,099 6,998
-------------------------
Commitments, Contingencies and Guarantees
Total Liabilities and Shareholders' Equity 23,846 22,048
-------------------------
-------------------------

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

Three Months Six Months
Ended June 30 Ended June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Net Income (Loss) Attributable to
Nexen Inc. - US GAAP (12) 318 144 935
Other Comprehensive Income (Loss), Net
of Income Taxes:
Foreign Currency Translation Adjustment (29) (8) (23) 19
------------------------------------
Comprehensive Income (Loss) Attributable
to Nexen Inc. (41) 310 121 954
------------------------------------

Unaudited Consolidated Statement of Accumulated Other Comprehensive Loss -
US GAAP

June 30 December 31
2009 2008
----------------------------------------------------------------------------
Foreign Currency Translation Adjustment (157) (134)
Unamortized Defined Benefit Pension Plan Costs (ii) (75) (75)
-------------------------
Accumulated Other Comprehensive Loss (232) (209)
-------------------------
-------------------------


Notes to the Unaudited Consolidated US GAAP Financial Statements:

i. Under Canadian GAAP, we defer certain development costs to PP&E. Under US principles, these costs have been included in operating expenses. As a result PP&E is lower under US GAAP by $30 million (December 31, 2008 - $30 million).

ii. US GAAP requires the recognition of the over-funded and under-funded status of a defined benefit plan on the balance sheet as an asset or liability. At June 30, 2009, the unfunded amount of our defined benefit pension plans that was not included in the Pension Liability under Canadian GAAP was $104 million. This amount has been included in deferred credits and other liabilities and $75 million, net of income taxes, has been included in AOCI.

iii. On January 1, 2003, we adopted FASB Statement 143, Accounting for Asset Retirement Obligations (FAS 143) 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:

- general and administrative (G&A) expense is higher by $30 million and $38 million ($22 million and $28 million, net of income taxes) for the three and six months ended June 30, 2009, respectively (2008 - lower by $28 million and $21 million, respectively ($20 million and $15 million, net of income taxes)); and

- accounts payable and accrued liabilities are higher by $96 million as at June 30, 2009 (December 31, 2008 - $58 million).

v. Under US GAAP, asset disposition gains and losses are included with transportation and other expense. Gains of $1 million and $8 million for the three and six months ended June 30, 2009, respectively, were reclassified from marketing and other income to transportation and other expense (gains of $4 million were reclassified for the three and six months ended June 30, 2008).

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 lower by $15 million and higher by $27 million ($10 million and $17 million, net of income taxes) for the three and six months ended June 30, 2009, respectively (2008 - lower by $132 million and $148 million ($83 million and $90 million, net of income taxes)); and

- inventories are lower by $31 million as at June 30, 2009 (December 31, 2008 - lower by $58 million).

vii. On January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation 48, Accounting for Uncertainty in Income Taxes (FIN 48) regarding accounting and disclosure for uncertain tax positions. On the adoption of FIN 48, we recorded a cumulative effect of a change in accounting principle of $28 million. This amount increased our deferred income tax liabilities, and decreased our retained earnings as at January 1, 2007 in our US GAAP - Unaudited Consolidated Balance Sheet.

As at June 30, 2009, the total amount of our unrecognized tax benefit was approximately $269 million, all of which, if recognized, would affect our effective tax rate. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the Unaudited Consolidated Statement of Income. As at June 30, 2009, 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 - Consolidated Statement of Income for the three and six months ended June 30, 2009.

Our income tax filings are subject to audit by taxation authorities and as at June 30, 2009 the following tax years remained subject to examination, (i) Canada - 1985 to date (ii) United Kingdom - 2007 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.

Changes in Accounting Policies - US GAAP

Business Combinations

On January 1, 2009, we prospectively adopted FASB Statement 141 ®, Business Combinations. Statement 141 establishes principles and requirements of the acquisition method for business combinations and related disclosures. The adoption of this statement did not impact our results of operations or financial position.

Non-Controlling Interests

On January 1, 2009, we prospectively adopted FASB Statement 160, Non-controlling Interests in Consolidated Financial Statements. This statement clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. The adoption of this statement did not have a material impact on our results of operations or financial position. The presentation changes have been included in the Consolidated Financial Statements, as applicable.

Derivative and Hedging Accounting and Disclosures

On January 1, 2009, we prospectively adopted FASB Statement 161, Disclosures about Derivative Instruments and Hedging Activities. The statement requires qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of gains and losses on derivative contracts and details of credit-risk-related contingent features in their hedged position. The statement also requires the disclosure of the location and amounts of derivative instruments in the financial statements. The disclosures required by this standard are provided in Notes 7 and 8.

On April 1, 2009, we prospectively adopted three FASB staff positions to improve guidance and disclosures on fair value measurement and impairments. The positions clarify fair value accounting specifically regarding: inactive markets and distressed transactions; other-than-temporary impairments; and expanded fair value disclosures for financial instruments in interim periods. The adoption of these positions did not have a material impact on our results of operation or financial position.

Subsequent Events

On April 1, 2009, we prospectively adopted FASB Statement 165, Subsequent Events. The new standard reflects the existing principles of current subsequent events accounting guidance and retains the notion and definition of "available to be issued" financial statements. The new standard requires disclosure of the date through which subsequent events have been evaluated and clarifies that original issuance of financial statements means both "issued" or "available to be issued". The adoption of this standard did not have a material impact on our results of operation or financial position.

New Accounting Pronouncements - US GAAP

In December 2008, FASB issued FSP FAS 132® -1, Employers Disclosures about Postretirement Benefit Plan Assets. This position provides guidance on disclosures about plan assets of a defined benefit pension or other postretirement plans. This position is effective for fiscal years ending after December 15, 2009. We do not expect the adoption of this statement to materially impact our results of operations or financial position.

In June 2009, FASB issued Statement 167, Amendments to FASB Interpretation No. 46 ®. It retains the scope of Interpretation 46® with the addition of entities previously considered qualifying special-purpose entities and eliminates the previous quantitative approach for a qualitative analysis in determining whether the enterprise's variable interest or interests give it a controlling financial interest in a variable interest entity. The Statement further amends Interpretation 46® to require ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity and requires enhanced disclosures about an enterprise's involvement in a variable interest entity. The Statement is effective at the beginning of the first annual reporting period after November 15, 2009. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position.

Contact Information

  • Michael J. Harris, CA
    Vice President, Investor Relations
    (403) 699-4688
    or
    Lavonne Zdunich, CA
    Manager, Investor Relations
    (403) 699-5821
    or
    Tim Chatten, P.Eng
    Analyst, Investor Relations
    (403) 699-4244
    or
    Nexen Inc.
    801 - 7th Ave SW
    Calgary, Alberta, Canada T2P 3P7
    Website: www.nexeninc.com