Nexen Inc.
TSX : NXY
NYSE : NXY

Nexen Inc.

July 17, 2008 06:30 ET

Nexen Reports Solid Second Quarter Financial Results

CALGARY, ALBERTA--(Marketwire - July 17, 2008) - Nexen Inc. -

Second Quarter Highlights:

- Cash flow of $946 million ($1.78/share) for the second quarter of 2008

- Net income of $380 million ($0.72/share)

- Quarterly production before royalties of 254,000 boe/d-on track to meet annual production guidance

- Encouraging exploration results in the UK North Sea

- At Long Lake, bitumen production rates are approximately 13,000 bbls/d (6,500 bbls/d net to us); upgrader start up on track for late third quarter

- Approval for Normal Course Issuer Bid to be sought from Toronto Stock Exchange to allow for share repurchases

- 2008 capital program increased by between $600 and $800 million to accelerate various projects



Three Months Ended Six Months Ended
June 30 June 30
-------------------- ------------------
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Production (mboe/d)(1)
Before Royalties 254 253 261 246
After Royalties 211 208 217 199
Net Sales 2,071 1,399 3,941 2,539
Cash Flow from Operations(2) 946 913 1,985 1,511
Per Common Share ($/share)(2) 1.78 1.73 3.75 2.87
Net Income 380 368 1010 489
Per Common Share ($/share) 0.72 0.70 1.91 0.93
Capital Expenditures 662 869 1,458 1,690
----------------------------------------------------------------------------

(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. 9.


Nexen delivered solid second quarter results generating cash flow from operations of $946 million and net income of $380 million. We also generated the highest quarterly cash netbacks in our history. Our production is unhedged and we remain well positioned to capture all upside from high commodity prices.

Production averaged 254,000 boe/d (211,000 boe/d after royalties) for the second quarter. The shut down of the Forties pipeline by a two-day labour strike at the Grangemouth refinery in Scotland caused us to temporarily shut in our North Sea production. Consequently, our production volumes for the second quarter were lower than our first quarter volumes. We remain on track to meet our annual production guidance.

At the end of the quarter, we were carrying approximately 850,000 barrels of crude oil inventory from our North Sea operations. This moved approximately $50 million of cash flow into early July, when the inventory was sold.

Net income includes a charge of approximately $330 million ($240 million after tax) for stock-based compensation resulting from a 33% increase in our stock price since the end of the first quarter.

Our marketing division reported a cash flow loss of $164 million in the second quarter compared to a contribution of $13 million in the first quarter. The loss primarily relates to significant increases in NYMEX natural gas prices in North America which resulted in widening location spreads between western supply regions and eastern consuming regions at a time when we were positioned to take advantage of traditional seasonal narrowing. By way of offset, we have $207 million of unrecognized gains on our marketing inventories and transportation assets that have increased in value. These gains can only be booked in the future when the inventories are sold and the transportation assets are used.

Comparing our second quarter results year over year, additional current taxes primarily in the UK and the impact of a weaker US dollar reduced our cash flow in 2008 by more than $500 million.

For the first six months of 2008, our cash flow exceeded our capital investment by over $500 million and we expect this excess to grow over the balance of the year. These net cash inflows can be used to fund additional capital investment programs, reduce net debt, increase dividends and repurchase shares. Earlier this year, we doubled our quarterly dividend and repaid maturing long term debt. We now intend to seek approval from the Toronto Stock Exchange (TSX) for a Normal Course Issuer Bid. Subject to approval by the TSX, this Normal Course Issuer Bid will allow us to repurchase for cancellation up to 10% of our public float of common shares. 10% of our public float amounts to approximately 53 million common shares.

We have also increased our capital investment by between $600 and $800 million, depending on program timing. This additional investment allows us to accelerate various projects such as shale gas, coalbed methane (CBM) and Medicine Hat shallow gas and provides Usan with funding for the remainder of 2008. In our shale gas program, encouraging results have led us to increase our investment plans by almost $150 million. Modifications to the royalty regime for CBM have restored development economics and we have reinstated our investment program accordingly. In the Medicine Hat area of Alberta and Saskatchewan, we plan to drill, complete and tie-in approximately 190 shallow gas wells. At Usan, we expect to invest a total of $300 million this year now that development of the project is underway. We have also allocated additional capital to the Masila field in Yemen where we plan to drill more development wells. We expect these wells will increase our 2008 exit rate and 2009 production volumes.

At Ettrick, additional drilling is required later this year to maximize reserves recoveries, bringing our share of total full-cycle development costs to approximately $620 million. Capital allocated to Long Lake brings the total Phase 1 investment to the upper end of our previously announced range.

For the full year, we expect to generate approximately $4 billion of cash flow assuming WTI oil price of US$90 per barrel and NYMEX gas price of US$8.50 for the second half of the year. This will fund our revised capital investment program of between $3.0 and $3.2 billion and other working capital requirements. Each US$1 increase in benchmark oil and gas prices adds about $20 million and $25 million, respectively, to our after tax cash flow for the balance of the year.

"We continue to review the best opportunities we have to deploy our excess cash to generate value for our shareholders," stated Charlie Fischer, Nexen's President and Chief Executive Officer. "The additional capital investment will add between 4,000 and 6,000 boe/d to our 2008 exit volumes and increase our production in 2009."



Oil and Gas Production

Production before Production after
Royalties Royalties
Crude Oil, NGLs
and Natural Gas (mboe/d) Q2 2008 Q1 2008 Q2 2008 Q1 2008
----------------------------------------------------------------------------
North Sea 103 110 103 110
Yemen 58 62 30 32
Canada - Oil & Gas 37 37 30 29
Canada - Bitumen 3 1 3 1
United States 28 32 24 28
Other Countries 6 6 5 5
Syncrude 19 19 16 17
------------------- ------------------
Total 254 267 211 222
------------------- ------------------


Our second quarter production volumes averaged 254,000 boe/d (211,000 boe/d after royalties). North Sea production was disrupted by a strike at the Grangemouth refinery which reduced quarterly volumes by approximately 3,000 boe/d.

Buzzard performed well and contributed 86,500 boe/d (200,200 boe/d gross) to our second quarter volumes. In early July, Buzzard was shutdown for two days for a planned rig move and returned to full rates soon after. The shutdown corresponded with maintenance downtime on the Frigg gas pipeline. In August, we have one week of scheduled downtime to move the rig back and carry out platform maintenance.

Syncrude volumes matched levels seen in the first quarter as a result of a coker turnaround which took longer than expected. The turnaround has since been completed and production volumes are now back to 26,000 bbls/d net to us. Another coker turnaround is planned for later in the quarter.

"We remain on track to meet our annual guidance range of 260,000 boe/d to 280,000 boe/d," commented Fischer. "Our Long Lake volumes are continuing to ramp up and we are seeing improved reliability at Syncrude."

Long Lake Project Update

Commissioning of the upgrader is approximately 80% complete and we remain on track for start up late in the third quarter.

We continue to inject steam into the reservoir and currently have 35 of 81 well pairs converted to SAGD operation. While the reservoir is performing well, we have been limited at surface by facility start up issues that have restricted our ability to generate our full complement of steam. Reliability of surface facilities has been impacted by third-party power outages, the recalibration of burner tips on the once-through steam generators and downtime associated with the heat exchangers. These issues have all been resolved and steam generation is ramping up to planned rates.

In late June, there was a failure of the main third-party transformer at Kinosis which required us to shutdown our SAGD facilities. As a result, bitumen production and steam circulation was temporarily suspended. Production volumes subsequently ramped back up to pre-shutdown levels but this slowed our near-term bitumen ramp up profile.

At this stage of the ramp up process and considering our past steaming constraints, production is meeting expectations with oil rates increasing and steam-oil-ratios (SOR) decreasing. The well pairs that have been converted to SAGD operation are currently producing, in aggregate, approximately 13,000 bbls/d or 6,500 bbls/d net to us, at a combined SOR of about 3.0. The overall SOR of the well pairs on SAGD together with those still circulating steam is currently ranging between 5.0 and 6.0. This is expected to decrease to our long-term expectation of approximately 3.0 when peak rates are achieved in 2009.

We continue to expect to have sufficient bitumen feedstock to start up the upgrader later this summer. SAGD volumes are expected to continue ramping up through the remainder of 2008 and reach the full design rate of 72,000 bbls/d (36,000 bbls/d net to us) in late 2009.

Excellent progress has been made on upgrader commissioning. Synthetic crude and pentane have been loaded into the OrCrude™ unit and testing in this unit is advancing well. Catalyst loading is complete in the hydrocracker and the sulphur recovery units, with these units moving into the final commissioning steps required before start up activities commence. In the gasification unit, automation testing activities are progressing with our licensor, Shell Global Solutions.

As previously announced, a holding tank used to balance liquid oxygen flow between the air separation plant and the gasifier was damaged in the commissioning process. Damage to the tank was limited to the upper section of the tank and we have since replaced this section. Hydrotesting, reinsulation and commissioning of the tank will be completed early in the third quarter. We remain on track to start up the upgrader later this summer. Our start up schedule forecasts production of synthetic crude to ramp up to full rates over a 12 to 18 month period following initial upgrader start up. The upgrader is designed to produce approximately 60,000 bbls/d (30,000 bbls/d net to us) of premium synthetic crude.

"We are very pleased with the reservoir performance at Long Lake," said Fischer. "We expect to see our bitumen production ramp up as the reliability of our surface SAGD facilities improves and are looking forward to start up of the upgrader shortly."

Phase 1 of Long Lake will develop approximately 10% of our oil sands inventory. Work continues on Phase 2 and our goal is to sanction this phase late this year. However, ultimate timing depends on accumulating sufficient operating history from Phase 1 and receiving clarity on proposed regulatory changes such as climate change. Proposed federal climate change regulations indicate a move towards carbon capture and sequestration of greenhouse gas emissions. With the addition of shift reactors to future phases, our unique process allows for the pre-combustion capture of these emissions for future sequestration.

North Sea Update

During the quarter, we drilled exploration wells in the North Sea at Blackbird and Pink. Blackbird is located 6 km south of Ettrick and if successful, this prospect could be fast tracked for development given the short distance to the Ettrick floating production, storage and offloading vessel (FPSO). We operate both Ettrick and Blackbird and have an 80% working interest in each.

Pink has been sidetracked and we are currently evaluating the results of this discovery. The Pink well is a candidate for co-development with Golden Eagle. We have a 46% operated working interest in this field.

At Ettrick, delivery of the leased FPSO has taken longer than expected due to third-party labour shortages in the Singapore construction yard. The FPSO is designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. We expect first production to commence in the fourth quarter with a modest contribution to our annual production volumes.

"We are encouraged with the results of our exploration program in the North Sea," commented Fischer. "The prospects we have drilled are near existing infrastructure and can be tied back quickly upon success, providing incremental production growth to complement our outstanding Buzzard asset."

Shale Gas Update

The Horn River basin in northeast British Columbia has the potential to become one of the most significant shale gas plays in North America and the recoverable contingent resource identified on our Dilly Creek lands here could double our total proved reserves. As previously announced, we currently estimate 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 resources. Further appraisal activity is required before these estimates can be finalized and commerciality established. We have increased our holdings to approximately 88,000 acres in the Dilly Creek area with a 100% working interest. This shale gas play has been compared to the Barnett Shale in Texas by other operators in the area as it displays similar rock properties and play characteristics.

Following the success of last winter's drilling program, we have accelerated the drilling of two horizontal wells which will be fraced and tested this summer. This winter, we are planning an 8 to 16 well drilling and completion program. We have secured access to 70 mmcf/d of pipeline and processing capacity for our shale gas production for a five year period with a renewal option.

"We have been able to secure a strong land position in the heart of this exciting play," said Fischer. "The potential resource size here is significant and development of our shale gas acreage will provide us with short cycle-time production growth."

CBM Development Continues

In Canada, we have reinstated the investment program for our Mannville CBM development project following modifications to the royalty regime by the Government of Alberta which restored the economics associated with this play. Our CBM production averaged 40 mmcf/d for the quarter. This is a significant increase from last quarter and primarily reflects improved well pumping reliability. We expect to exit the year around 46 mmcf/d as our existing wells dewater and production increases.

Gulf of Mexico Update

In the Eastern Gulf of Mexico, we recently spud the Fredericksburg exploration well. This is the third prospect to be drilled in this area following earlier success at Vicksburg and Shiloh. We have a 20% interest in Fredericksburg and Shiloh, and a 25% interest in Vicksburg, with Shell operating all three. When we combine the discoveries at Shiloh and Vicksburg with several prospects we see on our land holdings, this area has the potential to become a significant part of our Gulf of Mexico business.

Development of the Longhorn discovery is progressing well and first production is expected in 2009 with a peak production rate of approximately 200 mmcf/d gross (50 mmcf/d net to us). We have a 25% non-operated working interest and ENI is the operator.

At Knotty Head, we plan to drill an appraisal well in mid 2009 when the first of our two new deep-water drilling rigs arrives. We have a 25% operated interest in the field.

Offshore West Africa Update

Development of the Usan field, offshore Nigeria has recently commenced. The field development plan includes a FPSO vessel with a storage capacity of two million barrels of oil. All major contracts for deep-water facilities have been awarded and contractors are mobilizing for detailed engineering and project execution. Development of the Usan field commenced earlier this year than we expected and we recently allocated additional capital accordingly. Our investment is expected to be within the range of US$1.6 to US$2.0 billion over the development period. The Usan field is expected to come on stream in early 2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d net to us).

The Usan field development is located in OML 138 and is covered by the original production sharing contract for OPL 222 issued in 1993, with the Nigerian National Petroleum Corporation as concessionaire. The contract conveys the right to develop and produce crude oil and continue with exploration activity. We are currently processing three-dimensional seismic in anticipation of further exploratory drilling in the area in 2009. The Usan field was discovered in 2002 and is located approximately 100 km offshore in water depths ranging from 750 to 850 meters. Drilling of the development wells is expected to commence next year. Nexen has a 20% interest in exploration and development along with Elf Petroleum Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration and Production Nigeria (Offshore East) Limited (30%).

Middle East Opportunity

We have recently been advised that we have successfully pre-qualified to participate in future oil and gas opportunities that may present themselves in Iraq.

"We were the only Canadian company to successfully pre-qualify in a group that contains a number of the world's major oil and gas companies," stated Fischer. "This builds on our strength in the Middle East and could present us with long term opportunities in one of the world's richest resource basins."

Quarterly Dividend

The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable October 1, 2008, to shareholders of record on September 10, 2008. 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 coalbed methane and shale gas), 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.

Conference Call

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



Date: July 17, 2008
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:

416-641-2140 (Toronto)
800-952-4972 (North American toll-free)
800-6578-9898 (Global toll-free)


A replay of the call will be available for two weeks starting at 2:30 p.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 3265843 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, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended) or "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements or information ("forward-looking statements") are generally identifiable by the terminology used such as "anticipate", "believe", "intend", "plan", "expect", "estimate", "budget", "outlook" 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, 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 reserves or resources, expected finding and development costs, expected operating performance, including expected reliability of operations and 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 or will come on stream, 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; the results of exploration and development drilling and related activities; the risks inherent in operating in harsh climates; the risks inherent in operating significant facilities which process hazardous and potentially explosive materials under high temperature and pressure; volatility in energy trading markets; foreign-currency exchange rates; economic conditions in the countries and regions in which we carry on business including the increasing costs of materials and labour and the ability of suppliers to meet delivery schedules and cost estimates; 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 2007 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 required to disclose oil and gas activities under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (NI 51-101). However, the Canadian securities regulatory authorities (CSA) have granted us exemptions from certain provisions of NI 51-101 to permit US style disclosure. These exemptions were sought because we are a US Securities and Exchange Commission (SEC) registrant and our securities regulatory disclosures, including Form 10-K and other related forms, must comply with SEC requirements. Our disclosures may differ from those of Canadian companies who have not received similar exemptions under NI 51-101.

Please read the "Special Note to Canadian Investors" in Item 7A in our 2007 Annual Report on Form 10-K, for a summary of the exemption granted by the CSA and the major differences between SEC requirements and NI 51-101. The summary is not intended to be all-inclusive or to convey specific advice. Reserve estimation is highly technical and requires professional collaboration and judgment.

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.

Please note that the differences between SEC requirements and NI 51-101 may be material.

Our probable reserves disclosure applies the Society of Petroleum Engineers/World Petroleum Council (SPE/WPC) definition for probable reserves. The Canadian Oil and Gas Evaluation Handbook states there should not be a significant difference in estimated probable reserve quantities using the SPE/WPC definition versus NI 51-101.

In this disclosure, we refer to oil and gas in common units called barrel of oil equivalent (boe). A boe is derived by converting six thousand cubic feet of gas to one barrel of oil (6mcf:1bbl). This conversion may be misleading, particularly if used in isolation, since the 6mcf:1bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head.

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) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net Sales 2,071 1,399 3,941 2,539
Cash Flow from Operations 946 913 1,985 1,511
Per Common Share ($/share) 1.78 1.73 3.75 2.87
Net Income 380 368 1,010 489
Per Common Share ($/share) 0.72 0.70 1.91 0.93
Capital Investment (1) 638 819 1,424 1,630
Net Debt (2) 3,835 4,755 3,835 4,755
Common Shares Outstanding
(millions of shares) 530.3 527.1 530.3 527.1
---------------------------------
(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) 2008 2007 2008 2007
----------------------------------------------------------------------------
Oil & Gas and Syncrude
United Kingdom 921 562 1,801 853
Yemen (2) 183 182 348 340
Canada 127 51 213 95
United States 165 113 312 246
Other Countries 29 25 63 32
Marketing (164) 70 (151) 71
Syncrude 109 60 199 127
--------------------------------
1,370 1,063 2,785 1,764
Chemicals 19 18 32 36
--------------------------------
1,389 1,081 2,817 1,800
Interest and Other Corporate Items (83) (82) (147) (187)
Income Taxes (3) (360) (86) (685) (102)
--------------------------------
Cash Flow from Operations (1) 946 913 1,985 1,511
--------------------------------
--------------------------------
(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) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash Flow from Operating Activities 1,163 582 2,331 1,030
Changes in Non-Cash Working Capital (232) 304 (372) 272
Other 21 34 38 223
Amortization of Premium for
Crude Oil Put Options (6) (7) (12) (14)
---------------------------------
Cash Flow from Operations 946 913 1,985 1,511
---------------------------------
---------------------------------

Weighted-average Number of Common
Shares Outstanding (millions of shares) 530.0 527.0 529.5 526.5
---------------------------------
Cash Flow from Operations Per
Common Share ($/share) 1.78 1.73 3.75 2.87
---------------------------------
---------------------------------

(2) After in-country cash taxes of $91 million for the three months ended
June 30, 2008 (2007 - $65 million) and $158 million for the six months
ended June 30, 2008 (2007 - $109 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
2008 2007 2008 2007
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
United Kingdom 100.3 85.6 103.1 70.7
Yemen 57.6 73.3 59.9 75.2
Canada 16.4 17.2 16.3 17.5
United States 11.3 16.0 12.5 18.8
Other Countries 5.7 6.2 5.8 6.0
Long Lake Bitumen 3.2 - 1.9 -
Syncrude (mbbls/d) (2) 19.1 19.0 19.2 20.2
---------------------------------
213.6 217.3 218.7 208.4
---------------------------------
Natural Gas (mmcf/d)
Canada 126 116 127 117
United States 99 86 105 93
United Kingdom 19 14 20 14
---------------------------------
244 216 252 224
---------------------------------

Total Production (mboe/d) 254 253 261 246
---------------------------------
---------------------------------


Production Volumes (after royalties)

Three Months Six Months
Ended June 30 Ended June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
United Kingdom 100.3 85.6 103.1 70.7
Yemen 29.2 41.6 30.4 43.3
Canada 12.6 13.4 12.4 13.8
United States 9.7 14.2 10.9 16.8
Other Countries 5.2 5.7 5.4 5.5
Long Lake Bitumen 3.2 - 1.9 -
Syncrude (mbbls/d) (2) 15.9 16.4 16.4 17.6
---------------------------------
176.1 176.9 180.5 167.7
---------------------------------
Natural Gas (mmcf/d)
Canada 108 97 107 96
United States 85 74 90 80
United Kingdom 19 14 20 14
---------------------------------
212 185 217 190
---------------------------------

Total Production (mboe/d) 211 208 217 199
---------------------------------
---------------------------------
Notes:
(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) Considered a mining operation for US reporting purposes.


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

Total
Quarters-2008 Quarters-2007 Year
(all dollar amounts in Cdn$ --------------------------------------------
unless noted) 1st 2nd 1st 2nd 3rd 4th 2007
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil (US$/bbl) 97.90 123.98 58.16 65.03 75.38 90.69 72.31
Nexen Average - Oil (Cdn$/bbl) 93.00 118.00 61.69 72.27 75.86 82.80 73.43
NYMEX Natural Gas (US$/mmbtu) 8.75 11.48 7.18 7.66 6.24 7.39 7.12
Nexen Average - Gas (Cdn$/mcf) 7.97 10.21 7.58 7.52 5.80 6.47 6.81
----------------------------------------------------------------------------

NETBACKS:
Canada - Heavy Oil
Sales (mbbls/d) 16.2 16.4 17.8 17.2 16.9 16.4 17.1

Price Received ($/bbl) 65.94 93.16 41.71 41.89 46.76 46.07 44.07
Royalties & Other 16.65 22.61 9.16 9.52 10.93 10.04 9.91
Operating Costs 15.76 17.17 13.65 15.14 14.53 15.22 14.62
----------------------------------------------------------------------------
Netback 33.53 53.38 18.90 17.23 21.30 20.81 19.54
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 127 126 118 116 112 124 118

Price Received ($/mcf) 7.57 9.67 7.16 7.06 5.17 5.88 6.32
Royalties & Other 1.18 1.53 1.26 1.09 0.78 0.86 1.00
Operating Costs 1.67 1.84 1.59 1.81 2.52 1.71 1.90
----------------------------------------------------------------------------
Netback 4.72 6.30 4.31 4.16 1.87 3.31 3.42
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 62.5 57.4 77.5 72.7 69.9 66.2 71.5

Price Received ($/bbl) 96.57 120.39 63.02 77.34 78.27 88.24 76.29
Royalties & Other 48.07 59.21 28.17 33.84 34.73 43.04 34.69
Operating Costs 7.76 8.80 6.07 6.29 6.72 7.24 6.56
In-country Taxes 11.82 17.45 6.38 9.89 10.03 12.18 9.52
----------------------------------------------------------------------------
Netback 28.92 34.93 22.40 27.32 26.79 25.78 25.52
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 19.3 19.1 21.4 19.0 25.2 22.6 22.1

Price Received ($/bbl) 101.70 130.90 70.03 77.12 82.09 88.33 79.76
Royalties & Other 11.93 22.08 8.26 10.33 13.42 15.33 12.02
Operating Costs 35.16 45.09 24.40 29.91 22.37 27.52 25.80
----------------------------------------------------------------------------
Netback 54.61 63.73 37.37 36.88 46.30 45.48 41.94
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 13.7 11.3 21.6 16.0 14.1 13.9 16.4
Price Received ($/bbl) 94.07 120.77 58.49 68.18 74.43 84.33 69.83
Natural Gas:
Sales (mmcf/d) 112 99 101 86 98 119 101
Price Received ($/mcf) 9.03 11.80 8.58 8.85 6.75 7.27 7.80
Total Sales Volume (mboe/d) 32.4 27.8 38.4 30.4 30.5 33.8 33.3

Price Received ($/boe) 71.10 91.08 55.44 61.04 56.28 60.32 58.16
Royalties & Other 9.53 12.88 6.78 7.71 7.28 8.13 7.45
Operating Costs 8.20 9.28 8.11 9.46 7.40 8.78 8.43
----------------------------------------------------------------------------
Netback 53.37 68.92 40.55 43.87 41.60 43.41 42.28
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 108.9 89.0 58.8 87.2 83.6 94.5 81.1
Price Received ($/bbl) 93.38 118.24 64.33 74.07 78.06 84.06 76.30
Natural Gas:
Sales (mmcf/d) 22 24 13 13 16 21 16
Price Received ($/mcf) 6.82 7.06 3.87 3.32 4.99 5.84 4.71
Total Sales Volume (mboe/d) 112.6 93.0 60.8 89.3 86.3 98.0 83.7

Price Received ($/boe) 91.67 114.95 62.92 72.75 76.56 82.29 74.79
Operating Costs 5.67 7.42 9.60 6.59 6.28 6.23 6.94
----------------------------------------------------------------------------
Netback 86.00 107.53 53.32 66.16 70.28 76.06 67.85
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 6.0 5.7 5.8 6.2 6.5 6.2 6.2

Price Received ($/bbl) 91.85 113.18 59.81 68.04 76.29 79.74 71.29
Royalties & Other 7.46 8.95 4.80 5.62 6.46 6.60 5.90
Operating Costs 4.74 4.43 2.97 3.39 3.34 4.13 3.45
----------------------------------------------------------------------------
Netback 79.65 99.80 52.04 59.03 66.49 69.01 61.94
----------------------------------------------------------------------------

Company-Wide
Oil and Gas Sales (mboe/d) 270.1 240.4 241.5 254.1 253.9 263.9 253.4

Price Received ($/boe) 85.90 108.26 59.13 68.48 69.82 75.50 68.46
Royalties & Other 14.87 19.92 12.26 12.65 13.02 14.37 13.10
Operating Costs 9.46 11.89 9.67 9.41 9.26 9.46 9.45
In-country Taxes 2.74 4.16 2.05 2.83 2.76 3.05 2.69
----------------------------------------------------------------------------
Netback 58.83 72.29 35.15 43.59 44.78 48.62 43.22
----------------------------------------------------------------------------

(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 per share Ended June 30 Ended June 30
amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 2,071 1,399 3,941 2,539
Marketing and Other (Note 16) 34 299 256 547
-------------------------------------
2,105 1,698 4,197 3,086
-------------------------------------
Expenses
Operating 348 289 657 579
Depreciation, Depletion, Amortization
and Impairment 334 360 698 694
Transportation and Other 195 210 400 456
General and Administrative 418 38 473 240
Exploration 101 105 133 154
Interest (Note 7) 16 46 43 94
-------------------------------------
1,412 1,048 2,404 2,217
-------------------------------------

Income before Income Taxes 693 650 1,793 869
-------------------------------------

Provision for Income Taxes
Current 451 151 843 211
Future (139) 126 (62) 161
-------------------------------------
312 277 781 372
-------------------------------------

Net Income before Non-Controlling
Interests 381 373 1,012 497
Less: Net Income Attributable to
Non-Controlling Interests (1) (5) (2) (8)
-------------------------------------

Net Income 380 368 1,010 489
-------------------------------------
-------------------------------------

Earnings Per Common Share ($/share)
Basic (Note 14) 0.72 0.70 1.91 0.93
-------------------------------------
-------------------------------------

Diluted (Note 14) 0.70 0.68 1.87 0.91
-------------------------------------
-------------------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Balance Sheet
June 30 December 31
(Cdn$ millions, except share amounts) 2008 2007
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 614 206
Restricted Cash 263 203
Accounts Receivable (Note 2) 4,909 3,502
Inventories and Supplies (Note 3) 1,078 659
Other 109 89
------------------------
Total Current Assets 6,973 4,659
------------------------

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $7,991
(December 31, 2007 - $7,195) 13,425 12,498
Future Income Tax Assets 268 268
Deferred Charges and Other Assets (Note 4) 703 324
Goodwill 335 326
------------------------
Total Assets 21,704 18,075
------------------------
------------------------

Liabilities and Shareholders' Equity
Current Liabilities
Accounts Payable and Accrued Liabilities (Note 6) 5,749 4,135
Income Taxes Payable 730 45
Accrued Interest Payable 55 54
Dividends Payable 27 13
------------------------
Total Current Liabilities 6,561 4,247
------------------------

Long-Term Debt (Note 7) 4,449 4,610
Future Income Tax Liabilities 2,264 2,290
Asset Retirement Obligations (Note 9) 934 792
Deferred Credits and Other Liabilities (Note 10) 781 459
Non-Controlling Interests 62 67

Shareholders' Equity (Note 13)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2008 - 530,282,975 shares
2007 - 528,304,813 shares 972 917
Contributed Surplus 2 3
Retained Earnings 5,953 4,983
Accumulated Other Comprehensive Loss (274) (293)
------------------------
Total Shareholders' Equity 6,653 5,610
------------------------
Commitments, Contingencies and Guarantees (Note 17)

------------------------
Total Liabilities and Shareholders' Equity 21,704 18,075
------------------------
------------------------

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) 2008 2007 2008 2007
----------------------------------------------------------------------------
Operating Activities
Net Income 380 368 1,010 489
Charges and Credits to Income not
Involving Cash (Note 15) 471 447 854 882
Exploration Expense 101 105 133 154
Changes in Non-Cash Working
Capital (Note 15) 232 (304) 372 (272)
Other (21) (34) (38) (223)
--------------------------------------
1,163 582 2,331 1,030

Financing Activities
Repayment of Short-Term
Borrowings, Net - (44) - (92)
Repayment of Term Credit
Facilities, Net - (1,321) (228) (955)
Repayment of Medium-Term Notes
(Note 7) (125) - (125) -
Proceeds from Long-Term Notes - 1,660 - 1,660
Proceeds from (Repayment of) Term
Credit Facilities of Canexus, Net (18) 15 (10) 33
Proceeds from Canexus Notes (Note 7) 51 - 51 -
Dividends on Common Shares (27) (13) (40) (26)
Issue of Common Shares and
Exercise of Tandem Options 14 11 40 40
Other (5) (28) (9) (35)
--------------------------------------
(110) 280 (321) 625

Investing Activities
Capital Expenditures
Exploration and Development (606) (747) (1,375) (1,537)
Proved Property Acquisitions (2) (45) (2) (46)
Chemicals, Corporate and Other (30) (27) (47) (47)
Changes in Restricted Cash (174) 66 (53) 82
Changes in Non-Cash Working
Capital (Note 15) (76) 16 (54) 44
Other (70) (10) (97) (14)
--------------------------------------
(958) (747) (1,628) (1,518)

Effect of Exchange Rate Changes on
Cash and Cash Equivalents (5) (67) 26 (80)
--------------------------------------

Increase in Cash and Cash Equivalents 90 48 408 57

Cash and Cash Equivalents
- Beginning of Period 524 110 206 101
--------------------------------------

Cash and Cash Equivalents
- End of Period 614 158 614 158
--------------------------------------
--------------------------------------

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) 2008 2007 2008 2007
----------------------------------------------------------------------------
Common Shares
Balance at Beginning of Period 949 866 917 821
Issue of Common Shares 4 4 24 25
Proceeds from Tandem Options
Exercised for Shares 10 7 16 15
Accrued Liability Relating to
Tandem Options Exercised for Shares 9 16 15 32
--------------------------------------
Balance at End of Period 972 893 972 893
--------------------------------------
--------------------------------------

Contributed Surplus
Balance at Beginning of Period 3 4 3 4
Stock-Based Compensation Expense - 1 - 1
Exercise of Tandem Options (1) - (1) -
--------------------------------------
Balance at End of Period 2 5 2 5
--------------------------------------
--------------------------------------

Retained Earnings
Balance at Beginning of Period 5,600 4,080 4,983 3,972
Net Income 380 368 1,010 489
Dividends on Common Shares (Note 13) (27) (13) (40) (26)
--------------------------------------
Balance at End of Period 5,953 4,435 5,953 4,435
--------------------------------------
--------------------------------------

Accumulated Other Comprehensive Loss
Balance at Beginning of Period (266) (167) (293) (161)
Opening Derivatives Designated as
Cash Flow Hedges - - - 61
Other Comprehensive Income/(Loss) (8) (86) 19 (153)
--------------------------------------
Balance at End of Period (274) (253) (274) (253)
--------------------------------------
--------------------------------------


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

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net Income 380 368 1,010 489
Other Comprehensive Income, Net of
Income Taxes:
Foreign Currency Translation
Adjustment:
Net Gains (Losses) on Investment
in Self-Sustaining Foreign
Operations (42) (437) 144 (495)
Net Gains (Losses) on Hedges of
Self-Sustaining Foreign Operations
(1) 34 353 (125) 403
Realized Translation Adjustments
Recognized in Net Income (2) - (2) - -
Cash Flow Hedges:
Realized Mark-to-Market Gains
Recognized in Net Income - - - (61)
--------------------------------------
Other Comprehensive Income/(Loss) (8) (86) 19 (153)
--------------------------------------
Comprehensive Income 372 282 1,029 336
--------------------------------------
--------------------------------------

(1) Net of income tax expense for the three months ended June 30, 2008 of $4
million (2007 - $57 million) and net of income tax recovery for the six
months ended June 30, 2008 of $19 million (2007 - net of income tax
expense of $66 million).
(2) Net of income tax recovery for the three months ended June 30, 2007 of
$1 million.

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 (US) GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 19. 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, 2008 and December 31, 2007 and the results of our operations and our cash flows for the three and six months ended June 30, 2008 and 2007.

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, including those related to accruals, litigation, environmental and asset retirement obligations, income taxes, derivative contract assets and liabilities and determination of proved reserves, on an ongoing basis. 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, 2008 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2008.

These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2007 Annual Report on 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 2007 Annual Report on Form 10-K.

Change in Accounting Policies

Inventories

In 2007, we adopted CICA Section 3031 Inventories issued by the Canadian Accounting Standards Board (AcSB). Effective October 1, 2007, we began carrying the commodity inventories held for trading by our energy marketing group at fair value, less any costs to sell. This standard was adopted prospectively and our results for the first six months of 2007 have not been restated for this change in accounting policy.

Capital Disclosures

On January 1, 2008, we prospectively adopted CICA Section 1535 Capital Disclosures issued by the AcSB. This Section establishes standards for disclosing information about an entity's objectives, policies and processes for managing its capital structure. The disclosures have been included in Note 8.

Financial Instruments Disclosures and Presentation

On January 1, 2008, we prospectively adopted the following new standards issued by the AcSB: Financial Instruments - Disclosure (Section 3862) and Financial Instruments - Presentation (Section 3863). These accounting standards replaced Financial Instruments - Disclosure and Presentation (Section 3861). The disclosures required by Section 3862 and 3863 provide additional information on the risks associated with our financial instruments and how we manage those risks. The additional disclosures required by these standards are provided in Notes 11 and 12.

New Accounting Pronouncements

In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada will converge with the International Financial Reporting Standards (IFRS) by 2011 and we will be required to report according to IFRS standards for the year ended December 31, 2011. We are currently assessing the impact of the convergence of Canadian GAAP with IFRS on our results of operations, financial position and disclosures.

In February 2008, the AcSB issued Section 3064, Goodwill and Intangible Assets and amended Section 1000, Financial Statement Concepts clarifying the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for fiscal years beginning on or after October 1, 2008 and early adoption is permitted. We do not expect the adoption of this section to have a material impact on our results of operations and financial position.



2. ACCOUNTS RECEIVABLE

June 30 December 31
2008 2007
----------------------------------------------------------------------------
Trade
Marketing 3,650 2,501
Oil and Gas 1,030 819
Chemicals and Other 79 60
------------------------
4,759 3,380
Non-Trade 157 132
------------------------
4,916 3,512
Allowance for Doubtful Receivables (7) (10)
------------------------
Total 4,909 3,502
------------------------
------------------------


3. INVENTORIES AND SUPPLIES

June 30 December 31
2008 2007
----------------------------------------------------------------------------
Finished Products
Marketing 950 577
Oil and Gas 48 14
Chemicals and Other 19 13
------------------------
1,017 604
Work in Process 5 3
Field Supplies 56 52
------------------------
Total 1,078 659
------------------------
------------------------


4. DEFERRED CHARGES AND OTHER ASSETS

June 30 December 31
2008 2007
----------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 11) 500 248
Long-Term Capital Prepayments 112 9
Crude Oil Put Options and Natural Gas Swaps (Note 11) 26 -
Asset Retirement Remediation Fund 13 13
Other 52 54
------------------------
Total 703 324
------------------------
------------------------


5. SUSPENDED WELL COSTS

The following table shows the changes in capitalized exploratory well costs during the six months ended June 30, 2008 and the year ended December 31, 2007, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Capitalized exploratory well costs are included in property, plant and equipment.



Six Months
Ended Year Ended
June 30 December 31
2008 2007
----------------------------------------------------------------------------
Balance at Beginning of Period 326 226
Additions to Capitalized Exploratory Well
Costs Pending the Determination of Proved
Reserves 124 215
Capitalized Exploratory Well Costs Charged to
Expense (20) (10)
Transfers to Wells, Facilities and Equipment
Based on Determination of Proved Reserves - (74)
Effects of Foreign Exchange 16 (31)
---------------------------
Balance at End of Period 446 326
---------------------------
---------------------------


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
2008 2007
----------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 250 202
Capitalized for a Period of Greater than One Year 196 124
------------------------
Balance at End of Period 446 326
------------------------
------------------------

Number of Projects that have Exploratory Well Costs
Capitalized for a Period Greater than One Year 8 5
------------------------


As at June 30, 2008, we have exploratory costs that have been capitalized for more than one year relating to our interests in four exploratory blocks in the North Sea ($58 million), an exploratory block in the Gulf of Mexico ($55 million), our coalbed methane exploratory activities in Canada ($46 million), exploratory activities on Block 51 in Yemen ($19 million) and our interest in an exploratory block, offshore Nigeria ($18 million). These costs relate to projects with successful exploration wells for which we have not been able to record 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. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

June 30 December 31
2008 2007
----------------------------------------------------------------------------
Accrued Payables 2,982 2,546
Marketing Derivative Contracts (Note 11) 1,148 413
Trade Payables 708 578
Stock-based Compensation 551 393
Other 360 205
------------------------
Total 5,749 4,135
------------------------
------------------------


7. LONG-TERM DEBT AND SHORT-TERM BORROWINGS

June 30 December 31
2008 2007
----------------------------------------------------------------------------
Term Credit Facilities (a) - 211
Canexus Limited Partnership Term Credit Facilities
(US$193 million) (b) 197 202
Medium-Term Notes, due 2008 (c) - 125
Canexus Notes, due 2013 (US$50 million) (d) 51 -
Notes, due 2013 (US$500 million) 509 494
Notes, due 2015 (US$250 million) 255 247
Notes, due 2017 (US$250 million) 255 247
Notes, due 2028 (US$200 million) 204 198
Notes, due 2032 (US$500 million) 509 494
Notes, due 2035 (US$790 million) 805 781
Notes, due 2037 (US$1,250 million) 1,273 1,235
Subordinated Debentures, due 2043 (US$460 million) 468 454
------------------------
4,526 4,688
Less: Unamortized Debt Issue Costs (77) (78)
------------------------
4,449 4,610
------------------------
------------------------


(a) Term credit facilities

We have unsecured term credit facilities of $3.1 billion available to 2012, none of which were drawn at June 30, 2008 (December 31, 2007 - US$214 million). 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 3.3% for the three months ended June 30, 2008 (2007 - 5.9%) and 3.7% for the six months ended June 30, 2008 (2007 - 5.9%). At June 30, 2008, $229 million of these facilities were utilized to support outstanding letters of credit (December 31, 2007 - $283 million).

(b) Canexus LP term credit facilities

During the quarter, the Canexus LP term credit facility was amended to increase the available amount from $350 million to $410 million and to increase the available short-term swing line loans under the facility from $20 million to $35 million. These committed, secured term credit facilities are available until 2011. At June 30, 2008, $197 million (US$193 million) was drawn on these facilities (December 31, 2007 - $202 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 the assets at Canexus LP. The credit facility also contains covenants with respect to certain financial ratios. The weighted-average interest rate on our term credit facilities was 4.6% for the three months ended June 30, 2008 (2007 - 6.2%).

(c) Medium-term notes, due 2008

During October 1997, we issued $125 million of notes. Interest was payable semi-annually at a rate of 6.3% and the principal was repaid in June 2008.

(d) Canexus notes, due 2013

During the quarter, Canexus issued US$50 million of notes. Interest is payable quarterly at a rate of 6.57%, and the principal is to be repaid in May 2013. Canexus may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term to maturity equal to the remaining terms of the notes plus 0.20%.



(e) Interest expense

Three Months Six Months
Ended June 30 Ended June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Long-Term Debt 69 83 145 164
Other 6 4 10 9
------------------------------------
75 87 155 173
Less: Capitalized (59) (41) (112) (79)
------------------------------------
Total 16 46 43 94
------------------------------------
------------------------------------


Capitalized interest relates to and is included as part of the cost of our oil and gas properties under development. The capitalization rates are based on our weighted-average cost of borrowings.

(f) Short-term borrowings

Nexen has uncommitted, unsecured credit facilities of approximately $656 million, none of which were drawn at June 30, 2008 (December 31, 2007 - nil). We utilized $21 million of these facilities to support outstanding letters of credit at June 30, 2008 (December 31, 2007 - $196 million). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 3.7% for the three months ended June 30, 2008 (2007 - 5.8%) and 3.8% for the six months ended June 30, 2008 (2007 - 5.8%).

8. CAPITAL DISCLOSURES

Our objective for managing our capital structure is to ensure that we have the financial capacity, liquidity and flexibility to fund our investment in full-cycle exploration and development of conventional and unconventional resources and for energy marketing activities. We generally rely on operating cash flows to fund capital investments. However, given the long cycle-time of some of our development projects which require significant capital investment prior to cash flow generation and volatile commodity prices, it is not unusual for capital expenditures to exceed our cash flow from operating activities in any given year. As such, our financing needs depend on where we are in a particular development cycle. This requires us to maintain financial flexibility and liquidity. Our capital management policies are aimed at:

- maintaining an appropriate balance between short-term debt, long-term debt and equity;

- maintaining sufficient undrawn committed credit capacity to provide liquidity;

- ensuring ample covenant room permitting us to draw on credit lines as required;

- maintaining a reasonable level of leverage; and

- ensuring we maintain a credit rating that is appropriate for our circumstances.

We have the ability to make adjustments to our capital structure by issuing additional equity or debt, returning cash to shareholders and making adjustments to our capital investment programs. Our capital consists of shareholders' equity, short-term and long-term debt and cash and cash equivalents as follows:



June 30 December 31
2008 2007
----------------------------------------------------------------------------
Net Debt (1)
Bank Debt 197 413
Senior Notes 3,799 3,758
------------------------
Senior Debt 3,996 4,171
Subordinated Debt 453 439
------------------------
Total Debt 4,449 4,610
Less: Cash and Cash Equivalents (614) (206)
------------------------
Total Net Debt 3,835 4,404
------------------------
------------------------

Shareholders' Equity 6,653 5,610
------------------------
------------------------
(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 as well as interest coverage ratios.

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 which is calculated 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, 2008, our net debt to cash flow from operating activities ratio was 0.9 times compared to 1.6 times at December 31, 2007. 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 to implement a strategy to reduce our leverage and lower this ratio back to target levels. In the past, each time we exceeded our internal net debt to cash flow from operating activities target band, we successfully brought our leverage down through asset sales and capital management.

Our interest coverage ratio allows us to monitor our ability to fund the interest requirements associated with our debt. The higher the interest coverage, the better positioned we are to finance our longer-term investment projects. Our interest coverage strengthened in 2008 from 12.1 times at the end of 2007 to 16.9 times at June 30, 2008.

Interest coverage is calculated by dividing our twelve-month trailing earnings before interest, taxes, depreciation, depletion, amortization and impairment (EBITDA) by interest expense before capitalized interest. EBITDA is a non-GAAP measure which is calculated using net income excluding interest expense, provision for income taxes, exploration expenses, DD&A and other non-cash expenses. The calculation of EBITDA is set out in the following table.



Twelve Months Twelve Months
Ended Ended
June 30 December 31
2008 2007
----------------------------------------------------------------------------
Net Income 1,607 1,086
Add:
Interest Expense 117 168
Provision for Income Taxes 1,201 792
Depreciation, Depletion, Amortization and
Impairment 1,771 1,767
Exploration Expense 305 326
Other Non-cash Expenses 139 (52)
------------------------------
EBITDA 5,140 4,087
------------------------------
------------------------------


9. ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of the asset retirement obligations associated with our property, plant and equipment are as follows:



Six Months Year
Ended Ended
June 30 December 31
2008 2007
----------------------------------------------------------------------------
Balance at Beginning of Period 832 704
Obligations Incurred with Development Activities 11 105
Expenditures Made on Asset Retirements (16) (23)
Accretion 26 44
Revisions to Estimates 102 79
Effects of Foreign Exchange 19 (77)
---------------------------
Balance at End of Period (1) (2) 974 832
---------------------------
---------------------------

(1) Obligations due within 12 months of $40 million (December 31, 2007 - $40
million) have been included in accounts payable and accrued liabilities.
(2) Obligations relating to our oil and gas activities amount to $925
million (December 31, 2007 - $786 million) and obligations relating to
our chemicals business amount to $49 million (December 31, 2007 - $46
million).


Our total estimated undiscounted inflated asset retirement obligations amount to $2,366 million (December 31, 2007 - $2,165 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.9%. Approximately $135 million included in our asset retirement obligations will be settled over the next five years. The remaining obligations settle beyond five years and will be funded by future cash flows from our operations.

We own interests in assets for which the fair value of the asset retirement obligations cannot be reasonably determined because the assets currently have an indeterminate life and we cannot determine when remediation activities would take place. These assets include our interest in Syncrude's upgrader and sulphur pile. The estimated future recoverable reserves at Syncrude are significant and given the long life of this asset, we are unable to determine when asset retirement activities would take place. Furthermore, the Syncrude plant can continue to run indefinitely with ongoing maintenance activities. The retirement obligations for these assets will be recorded in the first year in which the obligation to remediate becomes determinable.



10. DEFERRED CREDITS AND OTHER LIABILITIES

June 30 December 31
2008 2007
----------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 11) 437 163
Deferred Transportation Revenue 71 82
Fixed-Price Natural Gas Contracts and Swaps (Note 11) 61 51
Defined Benefit Pension Obligations 60 57
Capital Lease Obligations 53 52
Long-Term Stock-based Compensation 30 2
Other 69 52
------------------------
Total 781 459
------------------------
------------------------


11. 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, income taxes payable, accrued interest payable, dividends payable, short-term borrowings and long-term debt are carried at cost or amortized cost. The carrying value of our short-term receivables and payables approximates their fair value because the instruments are near maturity.

In our energy marketing group, we enter into contracts to purchase and sell crude oil and natural gas 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. Refer to the derivatives section below for details of our derivatives and fair values as at June 30, 2008. 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, 2008, the estimated fair value of our long-term debt was $4,370 million (December 31, 2007 - $4,692 million) as compared to the carrying value of $4,449 million (December 31, 2007 - $4,610 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers.

Derivatives

a) Total carrying value of derivative contracts related to trading activities

The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:



June 30 December 31
2008 2007
----------------------------------------------------------------------------
Accounts Receivable 851 334
Deferred Charges and Other Assets (1) 500 248
------------------------
Total Derivative Assets 1,351 582
------------------------
------------------------

Accounts Payable and Accrued Liabilities 1,148 413
Deferred Credits and Other Liabilities (1) 437 163
------------------------
Total Derivative Liabilities 1,585 576
------------------------
------------------------

Total Net Derivatives related to Trading Activities (234) 6
------------------------
------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.


b) Total carrying value of derivative contracts related to non-trading activities

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



June 30 December 31
2008 2007
----------------------------------------------------------------------------
Accounts Receivable 22 -
Deferred Charges and Other Assets (1) 26 1
------------------------
Total Derivative Assets 48 1
------------------------
------------------------
Accounts Payable and Accrued Liabilities 50 28
Deferred Credits and Other Liabilities (1) 61 51
------------------------
Total Derivative Liabilities 111 79
------------------------
------------------------

Total Net Derivatives related to Non-Trading
Activities (63) (78)
------------------------
------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.


Crude oil put options

In 2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crude oil production. These options establish an annual average Dated Brent floor price of US$60/bbl on these volumes. In 2007, we purchased put options on 36 million barrels or approximately 100,000 bbls/d of our 2008 crude oil production. These options establish an annual average Dated Brent floor price of US$50/bbl on these volumes.

The put options are carried at fair value within amounts receivable and are classified as long-term or short-term based on their anticipated settlement date. Any change in fair value is included in marketing and other income.



Notional Average Fair
Volumes Term Floor Price Value
----------------------------------------------------------------------------
(bbls/d) (US$/bbl) (Cdn$ millions)
Dated Brent Crude Oil
Put Options 100,000 2008 50 -
Dated Brent Crude Oil
Put Options 70,000 2009 60 4
----------------
4
----------------
----------------


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. Any change in fair value is included in marketing and other income.



Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Fixed-Price Natural Gas
Contracts 15,514 2008 2.46 (50)
15,514 2009 - 2010 2.56 - 2.77 (61)
Natural Gas Swaps 15,514 2008 7.60 22
15,514 2009 - 2010 7.60 22
----------------
(67)
----------------
----------------


c) Fair value of derivatives

Wherever possible, the estimated fair value of our derivative instruments is based on quoted market prices, and if not available, on estimates from third-party brokers. We utilize market data or assumptions that market participants would use when pricing the asset or liability, including assumptions about risk. As a basis for establishing fair value, we utilize a mid-market pricing convention between bid and ask and then adjust our pricing to the ask price when we have a net open sell position and the bid price when we have a net open buy position. We incorporate the credit risk associated with counterparty default into our estimates of fair value. Inputs to fair valuations may be readily observable, market-corroborated, or generally unobservable. We utilize valuation techniques that maximize the use of observable inputs wherever possible and minimize the use of unobservable inputs. To value longer-term transactions and transactions in less active markets for which pricing information is not generally available, unobservable inputs may be used.

We classify the fair value of our derivatives according to the following hierarchy based on the amount of observable inputs used to value the instruments.

- Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and we use information from markets such as the New York Mercantile Exchange and the International Petroleum Exchange.

- Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value, volatility factors, and broker quotations, which can be observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options. We obtain information from sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes.

- Level 3 - Valuations in this level are based on inputs which are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value. Level 3 instruments include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value which primarily includes extrapolation of observable future prices to similar locations, similar instruments or later time periods.

The following table includes our derivatives that are carried at fair value on a recurring basis for our trading and non-trading activities as at June 30, 2008. 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.



Level 1 Level 2 Level 3 Total
----------------------------------------------------------------------------
Net Derivatives
Trading Derivatives 15 (238) (11) (234)
Non-Trading Derivatives - (63) - (63)
---------------------------------------
Total Net Derivatives 15 (301) (11) (297)
---------------------------------------
---------------------------------------


A reconciliation of changes in the fair value of our derivatives classified
as Level 3 for the six months ended June 30, 2008 is provided below:

Level 3
----------------------------------------------------------------------------
Fair Value at January 1, 2008 (7)
Realized and unrealized gains (losses) (8)
Purchases, issuances and settlements (2)
Transfers in and/or out of Level 3 6
---------
Fair Value at June 30, 2008 (11)
---------
---------

Unsettled gains (losses) relating to instruments still
held as of June 30, 2008 (2)
---------
---------


Transfers in and/or out 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.

12. RISK MANAGEMENT

(a) Market Risk

We invest in significant capital projects, purchase and sell commodities, issue short and long-term debt, including amounts in foreign currencies, and invest in foreign operations. These activities expose us to market risk 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 exposures to market risk that result from these activities.

The following market risk discussion relates primarily to commodity price risk and foreign exchange risk related to our financial instruments. 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 world crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, such prices also may affect the value of our oil and gas properties and our level of spending for exploration and development.

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

Our energy marketing group markets and trades crude oil, natural gas, NGLs, ethanol and power through physical purchase and sales contracts, as well as financial commodity contracts. These activities expose us to commodity price risk, as well as foreign currency risk and volatility within these markets. Our energy marketing group actively manages risk by utilizing energy and currency derivatives. We typically take advantage of location, time and quality spreads using physical and financial contracts. Our marketing group also tries to take advantage of volatility within commodity markets and can establish net open commodity positions to take advantage of existing market conditions.

Volatility within various commodity markets can vary and change over time. While this volatility gives us opportunities, it can also cause our results to vary significantly between periods. We attempt to manage the associated risk and take on positions based on market intelligence; however, it is possible that we could incur financial loss.

Open positions exist when not all contracted purchases and sales terms have been matched. These net open positions allow us to generate income, but also expose us to risk of loss due to fluctuating market prices (market risk sensitivities in our portfolio).

We manage the level of market risk through daily monitoring of our energy trading activities relative to:

- prescribed limits for Value-at-Risk (VaR);

- nominal size of commodity positions;

- stop loss limits; and

- stress testing.

VaR is a statistical estimate assuming normal market conditions exist. Our VaR calculation estimates the maximum probable loss, given a 95% confidence level that we would incur if we were to unwind our outstanding positions over a two-day period. We estimate VaR primarily by using the Variance-Covariance method based on historical commodity price volatility, correlation inputs where available and by historical simulation in other situations. Our estimate is based upon the following key assumptions:

- changes in commodity prices follow a statistical pattern of distribution;

- price volatility remains stable; and

- price correlation relationships remain stable.

If a severe market shock occurred, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We also use stress testing using extreme market movements which complements our VaR estimates. Stress testing is used to quantify potential unexpected losses from low probability market movements. Our VaR analysis incorporates our derivative positions, non-derivative transportation and storage contracts and assets, as well as our commodity trading inventories.

Our quarter end, high, low, and average VaR amounts for the three and six months ended June 30 are as follows:



Three Months Six Months
Ended June 30 Ended June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Value-at-Risk
Quarter End 31 34 31 34
High 40 38 40 38
Low 29 24 21 24
Average 34 30 32 29
------------------------------------


Foreign currency risk

Foreign exchange 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 and long-term borrowings.

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 net cash flows. We designate our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. At June 30, 2008, we had US$4,443 million of long-term debt issued in US dollars and a one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $45 million, before income tax.

In our energy marketing group, the majority of the financial commodity contracts are denominated in US dollars. We enter into US-dollar forward contracts and swaps to manage this exposure.

We also have exposures to currencies other than the US dollar. A portion of our United Kingdom operating expenses, capital spending and future asset retirement obligations are denominated in British pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies.

(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. The majority of our accounts receivable are with counterparties in the energy industry and are subject to normal industry credit risk. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. We assess the financial strength of our counterparties, including those involved in marketing and other commodity arrangements, and we limit the total exposure to individual counterparties. As well, a number of our contracts contain provisions that allow us to demand the posting of collateral in the event of a downgrade to a non-investment grade credit rating occurs. Credit risk, including credit concentrations, is routinely reported to our management. We also use standard agreements that allow for the netting of exposures associated with a single counterparty. We believe this minimizes our overall credit risk. However, there can be no assurance that these processes will protect us against all losses from non-performance.

At June 30, 2008:

- over 97% of our credit exposures were investment grade; and

- only one counterparty individually made up more than 10% of our credit exposure. This counterparty was investment grade.

Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts of non-derivative financial assets such as accounts receivable, as well as the fair value of derivative financial assets. There are no significant amounts past due or impaired at the balance sheet date. Collateral received from customers at June 30, 2008 includes $132 million of cash and $239 million of letters of credit related to our trading activities and the cash received is included in our accounts payable and accrued liabilities.

(c) Liquidity Risk

Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they become due, and to engage in 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, 2008, we had unsecured term credit facilities of $3.1 billion available until 2012. At June 30, 2008, no amounts were drawn on these facilities; however, $229 million of the facilities were used to support outstanding letters of credit. We also had $656 million of undrawn, uncommitted, unsecured credit facilities, of which $21 million was supporting letters of credit at June 30, 2008.

The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at June 30, 2008:



Less Greater
than 1 1-3 4-5 than 5
Total Year Years Years Years
----------------------------------------------------------------------------
Long-Term Debt 4,526 - - 197 4,329
Interest on Long-Term Debt
(1) 6,493 176 544 544 5,229
-----------------------------------------------
Total 11,019 176 544 741 9,558
-----------------------------------------------
-----------------------------------------------
(1) Excludes interest on term credit facilities of $3.1 billion and Canexus
LP term credit facilities of $410 million as the amounts drawn on the
facilities fluctuate. As a result, we are unable to provide a reasonable
estimate of the interest.


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



Less Greater
than 1 1-3 4-5 than 5
Total Year Years Years Years
----------------------------------------------------------------------------
Trading Derivatives 1,585 1,148 437 - -
Non-Trading Derivatives 111 50 61 - -
-----------------------------------------------
Total 1,696 1,198 498 - -
-----------------------------------------------
-----------------------------------------------


The commercial agreements our energy marketing group enters 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, such as a drop in credit ratings, occurs. Based on contracts in place and commodity prices at June 30, 2008, we could be required to post collateral of up to $2.2 billion if we were downgraded to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral merely secures the payment of such amounts.

At June 30, 2008, collateral posted with counterparties includes $90 million of cash and $35 million of letters of credit related to our trading activities. Cash posted is included with our accounts receivable. Letters of credit issued cannot be drawn on unless there has been default, which would have to be proven to the bank in order for them to release the funds. 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 $263 million (December 31, 2007 - $203 million), which have been included in restricted cash.

13. SHAREHOLDERS' EQUITY

Dividends

During the quarter, the Board of Directors declared an increase in the quarterly dividend to $0.05 per common share, payable on July 1, 2008 (2007 - $0.025). Dividends for the six months ended June 30, 2008 were $0.075 (2007 - $0.05). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.

14. EARNINGS PER COMMON SHARE

We calculate basic earnings per common share using net income and 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) 2008 2007 2008 2007
----------------------------------------------------------------------------
Weighted-average number of common
shares outstanding 530.0 527.0 529.5 526.5
Shares issuable pursuant to tandem
options 24.9 26.9 25.7 27.6
Shares notionally purchased from
proceeds of tandem options (14.4) (15.6) (16.4) (15.4)
-------------------------------------
Weighted-average number of diluted
common shares outstanding 540.5 538.3 538.8 538.7
-------------------------------------
-------------------------------------


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. In calculating the weighted-average number of diluted common shares outstanding for the three and six months ended June 30, 2007, we excluded 36,000 and 37,667 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.



15. CASH FLOWS

(a) Charges and credits to income not involving cash

Three Months Six Months
Ended June 30 Ended June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Depreciation, Depletion, Amortization
and Impairment 334 360 698 694
Stock-Based Compensation 259 (70) 200 (26)
Future Income Taxes (139) 126 (62) 161
Change in Fair Value of Crude Oil Put
Options 10 4 10 20
Net Income Attributable to
Non-Controlling Interests 1 5 2 8
Other 6 22 6 25
------------------------------------
Total 471 447 854 882
------------------------------------
------------------------------------


(b) Changes in non-cash working capital

Three Months Six Months
Ended June 30 Ended June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Accounts Receivable (878) (142) (1,324) (67)
Inventories and Supplies (310) (244) (388) (179)
Other Current Assets (6) 15 (16) 11
Accounts Payable and Accrued
Liabilities 1,040 52 1,358 (60)
Income Taxes Payable 309 2 674 56
Accrued Interest Payable (12) 29 1 11
Dividends Payable 13 - 13 -
-------------------------------------
Total 156 (288) 318 (228)
-------------------------------------
-------------------------------------

Relating to:
Operating Activities 232 (304) 372 (272)
Investing Activities (76) 16 (54) 44
-------------------------------------
Total 156 (288) 318 (228)
-------------------------------------
-------------------------------------

(c) Other cash flow information

Three Months Six Months
Ended June 30 Ended June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Interest Paid 82 55 148 156
Income Taxes Paid 76 100 161 157
-------------------------------------


Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $24 million for the three months ended June 30, 2008 (2007 - $50 million) and $34 million for the six months ended June 30, 2008 (2007 - $60 million).



16. MARKETING AND OTHER INCOME

Three Months Six Months
Ended June 30 Ended June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Marketing Revenue, Net 21 284 232 531
Change in Fair Value of Crude Oil Put
Options (10) (4) (10) (20)
Interest 3 10 13 19
Foreign Exchange Losses (6) (38) (1) (43)
Other 26 47 22 60
------------------------------------
Total 34 299 256 547
------------------------------------
------------------------------------


17. COMMITMENTS, CONTINGENCIES AND GUARANTEES

As described in Note 15 to the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations.

18. 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 20 to the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K.



Three months ended June 30, 2008

(Cdn$ millions) 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: Provision 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
----------------------------------------------------
----------------------------------------------------

Corporate
Energy and
(Cdn$ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------

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

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

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

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

Property, Plant and
Equipment
Cost 264 1,348 866 312 21,416
Less: Accumulated DD&A 68 223 483 187 7,991
----------------------------------------------------
Net Book Value 196 1,125 383 125 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 Long Lake Project
(Phase 1 and future phases).
(6) Approximately 83% of Marketing's identifiable assets are accounts
receivable and inventories.

Six months ended June 30, 2008

(Cdn$ millions) 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: Provision 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
Acquisition - 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
----------------------------------------------------
----------------------------------------------------

Corporate
Energy and
(Cdn$ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------

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

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

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

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

Property, Plant and
Equipment
Cost 264 1,348 866 312 21,416
Less: Accumulated DD&A 68 223 483 187 7,991
----------------------------------------------------
Net Book Value 196 1,125 383 125 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 a 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 Long Lake Project (Phase
1 and future phases).
(7) Approximately 83% of Marketing's identifiable assets are accounts
receivable and inventories.


Three months ended June 30, 2007

(Cdn$ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------------

Net Sales 288 113 148 592 35
Marketing and Other 3 3 - 24 -
----------------------------------------------------
Total Revenues 291 116 148 616 35

Less: Expenses
Operating 42 42 26 53 2
Depreciation, Depletion,
Amortization and
Impairment 64 41 62 158 3
Transportation and Other 1 6 - - -
General and
Administrative (3) (4) 8 (5) (3) 1
Exploration 2 9 49 18 27(4)
Interest - - - - -
----------------------------------------------------
Income (Loss) before
Income Taxes 186 10 16 390 2
Less: Provision for
(Recovery of) Income
Taxes 64 2 - 202 9
Less: Non-Controlling
Interests - - - - -
----------------------------------------------------
Net Income (Loss) 122 8 16 188 (7)
----------------------------------------------------
----------------------------------------------------

Identifiable Assets 441 4,543(5) 1,581 5,107 258
----------------------------------------------------
----------------------------------------------------

Capital Expenditures
Development and Other 31 316 128 158 7
Exploration 5 12 49 17 16
Proved Property
Acquisitions - - - 45(7) -
----------------------------------------------------
36 328 177 220 23
----------------------------------------------------
----------------------------------------------------

Property, Plant and
Equipment
Cost 2,260 5,920 2,878 4,702 241
Less: Accumulated DD&A 2,012 1,521 1,406 636 77
----------------------------------------------------
Net Book Value 248 4,399(5) 1,472 4,066 164
----------------------------------------------------
----------------------------------------------------

Corporate
Energy and
(Cdn$ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------

Net Sales 7 115 101 - 1,399
Marketing and Other 284 - 17 (32)(2) 299
----------------------------------------------------
Total Revenues 291 115 118 (32) 1,698

Less: Expenses
Operating 6 51 67 - 289
Depreciation, Depletion,
Amortization and
Impairment 3 12 11 6 360
Transportation and Other 189 4 8 2 210
General and
Administrative (3) 23 - 8 10 38
Exploration - - - - 105
Interest - - 3 43 46
----------------------------------------------------------------------------
Income (Loss) before
Income Taxes 70 48 21 (93) 650
Less: Provision for
(Recovery of) Income
Taxes 26 13 6 (45) 277
Less: Non-Controlling
Interests - - 5 - 5
----------------------------------------------------
Net Income (Loss) 44 35 10 (48) 368
----------------------------------------------------
----------------------------------------------------

Identifiable Assets 3,355(6) 1,186 495 228 17,194
----------------------------------------------------
----------------------------------------------------

Capital Expenditures
Development and Other 1 8 14 12 675
Exploration - - - - 99
Proved Property
Acquisitions - - - - 45
----------------------------------------------------
1 8 14 12 819
----------------------------------------------------
----------------------------------------------------

Property, Plant and
Equipment
Cost 229 1,314 802 303 18,649
Less: Accumulated DD&A 52 196 444 158 6,502
----------------------------------------------------
Net Book Value 177 1,118 358 145 12,147
----------------------------------------------------
----------------------------------------------------

(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $10 million, foreign exchange losses of $38
million and decrease in the fair value of crude oil put options of $4
million.
(3) Includes recovery of stock-based compensation of $55 million.
(4) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(5) Includes costs of $3,028 million related to our Long Lake Project, which
are not being depreciated, depleted or amortized.
(6) Approximately 81% of Marketing's identifiable assets are accounts
receivable and inventories.
(7) Includes acquisition of additional interests in the Scott and Telford
fields.


Six months ended June 30, 2007

(Cdn$ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------------

Net Sales 531 228 316 936 64
Marketing and Other 6 4 - 28 -
----------------------------------------------------
Total Revenues 537 232 316 964 64

Less: Expenses
Operating 84 81 54 106 4
Depreciation, Depletion,
Amortization and
Impairment 122 82 146 272 6
Transportation and Other 4 13 - - -
General and
Administrative (3) (3) 40 14 2 25
Exploration 5 14 62 38 35(4)
Interest - - - - -
----------------------------------------------------
Income (Loss) before
Income Taxes 325 2 40 546 (6)
Less: Provision for
(Recovery of) Income
Taxes 113 - 14 284 7
Less: Non-Controlling
Interests - - - - -
----------------------------------------------------
Net Income (Loss) 212 2 26 262 (13)
----------------------------------------------------
----------------------------------------------------

Identifiable Assets 441 4,543(5) 1,581 5,107 258
----------------------------------------------------
----------------------------------------------------

Capital Expenditures
Development and Other 63 672 267 298 15
Exploration 10 45 63 63 26
Proved Property
Acquisitions - - - 46(7) -
----------------------------------------------------
73 717 330 407 41
----------------------------------------------------
----------------------------------------------------

Property, Plant and
Equipment
Cost 2,260 5,920 2,878 4,702 241
Less: Accumulated DD&A 2,012 1,521 1,406 636 77
----------------------------------------------------
Net Book Value 248 4,399(5) 1,472 4,066 164
----------------------------------------------------
----------------------------------------------------

Corporate
Energy and
(Cdn$ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------

Net Sales 23 234 207 - 2,539
Marketing and Other 531 - 22 (44)(2) 547
----------------------------------------------------
Total Revenues 554 234 229 (44) 3,086

Less: Expenses
Operating 19 98 133 - 579
Depreciation, Depletion,
Amortization and
Impairment 7 25 22 12 694
Transportation and Other 409 9 19 2 456
General and
Administrative (3) 53 - 17 92 240
Exploration - - - - 154
Interest - - 6 88 94
----------------------------------------------------
Income (Loss) before
Income Taxes 66 102 32 (238) 869
Less: Provision for
(Recovery of) Income
Taxes 26 30 9 (111) 372
Less: Non-Controlling
Interests - - 8 - 8
----------------------------------------------------
Net Income (Loss) 40 72 15 (127) 489
----------------------------------------------------
----------------------------------------------------

Identifiable Assets 3,355(6) 1,186 495 228 17,194
----------------------------------------------------
----------------------------------------------------

Capital Expenditures
Development and Other 1 15 26 20 1,377
Exploration - - - - 207
Proved Property
Acquisitions - - - - 46
----------------------------------------------------
1 15 26 20 1,630
----------------------------------------------------
----------------------------------------------------

Property, Plant and
Equipment
Cost 229 1,314 802 303 18,649
Less: Accumulated DD&A 52 196 444 158 6,502
----------------------------------------------------
Net Book Value 177 1,118 358 145 12,147
----------------------------------------------------
----------------------------------------------------

(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $19 million, foreign exchange losses of $43
million and decrease in the fair value of crude oil put options of $20
million.
(3) Includes stock-based compensation expense of $61 million.
(4) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(5) Includes costs of $3,028 million related to our Long Lake Project, which
are not being depreciated, depleted or amortized.
(6) Approximately 81% of Marketing's identifiable assets are accounts
receivable and inventories.
(7) Includes acquisition of additional interests in the Scott and Telford
fields.


19. 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 Statement of Income and Balance Sheet and summaries of differences from Canadian GAAP are as follows:



(a) Unaudited Consolidated Statement of Income - US GAAP
For the Three and Six Months ended June 30

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions, except per share
amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 2,071 1,399 3,941 2,539
Marketing and Other (vii); (viii) (102) 299 104 545
-------------------------------------
1,969 1,698 4,045 3,084
-------------------------------------
Expenses
Operating (ii) 347 296 657 592
Depreciation, Depletion, Amortization
and Impairment 334 360 698 694
Transportation and Other (viii) 191 210 396 456
General and Administrative (iii) 390 51 452 250
Exploration 101 105 133 154
Interest 16 46 43 94
-------------------------------------
1,379 1,068 2,379 2,240
-------------------------------------

Income before Income Taxes 590 630 1,666 844
-------------------------------------

Provision for Income Taxes
Current 451 151 843 211
Deferred (i) - (vii) (180) 120 (114) 153
-------------------------------------
271 271 729 364
-------------------------------------

Net Income before Non-Controlling
Interests 319 359 937 480
Net Income Attributable to
Non-Controlling Interests (1) (5) (2) (8)
-------------------------------------

Net Income - US GAAP (1) 318 354 935 472
-------------------------------------
-------------------------------------

Earnings Per Common Share ($/share)
Basic (Note 14) 0.60 0.67 1.77 0.90
-------------------------------------
-------------------------------------

Diluted (Note 14) 0.59 0.66 1.74 0.88
-------------------------------------
-------------------------------------

Note:
(1) Reconciliation of Canadian and US GAAP Net Income


Three Months Six Months
Ended June 30 Ended June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Net Income - Canadian GAAP 380 368 1,010 489
Impact of US Principles, Net of Income
Taxes:
Ineffective Portion of Cash Flow
Hedges(i) - - - (2)
Pre-operating Costs (ii) - (5) - (8)
Inventory Valuation (vii) (83) - (90) -
Stock-based Compensation (iii) 20 (9) 15 (7)
Other 1 - - -
-------------------------------------
Net Income - US GAAP 318 354 935 472
-------------------------------------
-------------------------------------


(b) Unaudited Consolidated Balance Sheet - US GAAP

June December
30 31
(Cdn$ millions, except share amounts) 2008 2007
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 614 206
Restricted Cash 263 203
Accounts Receivable 4,909 3,502
Inventories and Supplies (vii) 886 615
Other 109 89
-----------------
Total Current Assets 6,781 4,615
-----------------

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $8,384
December 31, 2007 - $7,588)(ii); (v) 13,376 12,449
Goodwill 335 326
Deferred Income Tax Assets 268 268
Deferred Charges and Other Assets 703 324
-----------------
Total Assets 21,463 17,982
-----------------
-----------------
Liabilities and Shareholders' Equity
Current Liabilities
Accounts Payable and Accrued Liabilities (iii) 5,781 4,188
Income Taxes Payable 730 45
Accrued Interest Payable 55 54
Dividends Payable 27 13
-----------------
Total Current Liabilities 6,593 4,300
-----------------

Long-Term Debt 4,449 4,610
Deferred Income Tax Liabilities (i) - (vii) 2,152 2,230
Asset Retirement Obligations 934 792
Deferred Credits and Liabilities (iv) 856 534
Non-Controlling Interests 62 67
Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2008 - 530,282,975 shares
2007 - 528,304,813 shares 972 917
Contributed Surplus 2 3
Retained Earnings (i) - (vii) 5,771 4,876
Accumulated Other Comprehensive Loss (i); (iv) (328) (347)
-----------------
Total Shareholders' Equity 6,417 5,449
-----------------
Commitments, Contingencies and Guarantees

Total Liabilities and Shareholders' Equity 21,463 17,982
-----------------
-----------------
(c) Unaudited Consolidated Statement of Comprehensive Income - US GAAP
For the Three and Six Months Ended June 30

Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net Income - US GAAP 318 354 935 472
Other Comprehensive Income, Net of Income
Taxes:
Foreign Currency Translation Adjustment (8) (86) 19 (92)
Change in Mark to Market on Cash Flow
Hedges(i) - - - (61)
------------------------------
Comprehensive Income 310 268 954 319
------------------------------
------------------------------

(d) Unaudited Consolidated Statement of Accumulated Other Comprehensive
Loss - US GAAP
June 30 December 31
(Cdn$ millions) 2008 2007
----------------------------------------------------------------------------
Foreign Currency Translation Adjustment (274) (293)
Unamortized Defined Benefit Pension Costs (iv) (54) (54)
------------------------
(328) (347)
------------------------
------------------------


Notes:

i. Under US GAAP, all derivative instruments are recognized on the balance sheet as either an asset or a liability measured at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. On January 1, 2007, we adopted the equivalent Canadian standard for derivative instruments.

Future sale of gas inventory: At December 31, 2006, we included $25 million of gains on cash flow hedges in accounts receivable. Accumulated Other Comprehensive Income (AOCI) includes the effective portion of $23 million ($16 million, net of taxes) and $2 million ($2 million, net of taxes) of the ineffective portion was included in our 2006 US GAAP net income. Under Canadian GAAP, these gains were recognized in the first quarter of 2007.

At June 30, 2008, there were no cash flow hedges in place.

ii. Under Canadian GAAP, we defer certain development costs and all pre-operating revenues and costs to property, plant and equipment. Under US principles, these costs have been included in operating expenses. As a result:

- operating expenses include pre-operating costs of $7 million and $13 million for the three and six months ended June 30, 2007, respectively ($5 million and $8 million, respectively, net of income taxes); and

- property, plant and equipment is lower under US GAAP by $30 million (December 31, 2007 - $30 million).

iii. 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. We are also required to accelerate the recognition of stock-based compensation expense for all stock-based awards made to our retirement-eligible employees under Canadian GAAP. However, under US GAAP, the accelerated recognition for such employees is only required for stock-based awards granted on or after January 1, 2006. As a result under US GAAP:

- general and administrative expense is lower by $28 million and $21 million ($20 million and $15 million, net of income taxes) for the three and six months ended June 30, 2008, respectively (2007 - higher by $13 million and $10 million, respectively, ($9 million and $7 million, respectively, net of income taxes)); and

- accounts payable and accrued liabilities are higher by $32 million as at June 30, 2008 (December 31, 2007 - $53 million).

iv. On December 31, 2006, we adopted FASB Statement 158 Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans (FAS 158). At June 30, 2008, the unfunded amount of our defined benefit pension plans was $75 million. This amount has been included in deferred credits and other liabilities and $54 million, net of income taxes has been included in AOCI.

v. 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 property, plant and equipment under US GAAP being lower by $19 million.

vi. On January 1, 2007, we adopted FASB Interpretation 48, Accounting for Uncertainty in Income Taxes (FIN 48) with respect to FAS 109 Accounting for Income Taxes 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, with a corresponding decrease to our retained earnings as at January 1, 2007 in our US GAAP - Unaudited Consolidated Balance Sheet. As at June 30, 2008, the total amount of our unrecognized tax benefit was approximately $225 million, all of which, if recognized, would affect our effective tax rate. As at June 30, 2008, the total amount of interest and penalties in relation to uncertain tax positions recognized in deferred income tax liabilities in the US GAAP -Unaudited Consolidated Balance Sheet is approximately $11 million. We had no interest or penalties in the US GAAP - Unaudited Consolidated Statement of Income for the first half of 2008. Our income tax filings are subject to audit by taxation authorities and as at June 30, 2008 the following tax years remained subject to examination; (i) Canada - 1985 to date, (ii) United Kingdom - 2002 to date and (iii) United States - 2004 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next twelve months.

vii. Under Canadian GAAP, we began carrying our commodity inventory held for trading purposes at fair value, less any costs to sell, effective October 31, 2007. 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 $132 million and $148 million ($83 million and $90 million, net of income taxes) for the three months and six months ended June 30, 2008, respectively; and

- inventories are lower by $192 million as at June 30, 2008 (December 31, 2007 - $44 million).

viii. Under US GAAP, asset disposition gains and losses are included with transportation and other expense. Gains of $4 million for the three and six months ended June 30, 2008 were reclassified from marketing and other income to transportation and other expense ($nil for the three and six months ended June 30, 2007).

Changes in Accounting Policies - US GAAP

On January 1, 2008, we adopted FASB Statement 157 Fair Value Measurements which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The adoption of this statement did not have a material impact on our results of operations or financial position. The additional disclosures required by the statement are included in Note 11.

New Accounting Pronouncements - US GAAP

Effective December 31, 2006, we adopted the recognition and disclosure provisions of FASB Statement 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans. This statement also requires measurement of the funded status of a plan as of the balance sheet date. The measurement provisions of the statement are effective for fiscal years ending after December 15, 2008. We do not expect the adoption of the change in measurement date in 2008 will have a material impact on our results of operations or financial position.

In December 2007, FASB issued Statement 141 (revised), Business Combinations. Statement 141 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position.

In December 2007, FASB issued Statement 160, Non-controlling Interests In Consolidated Financial Statements, an amendment of ARB. No. 51. 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. This statement is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position.

In March 2008, FASB issued Statement 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133. 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 positions. The statement also requires the disclosure of the location and amounts of derivative instruments in the financial statements. This statement is effective for fiscal years and interim periods beginning on or after November 15, 2008. 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
    Analyst, 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