Nexen Inc.
TSX : NXY
NYSE : NXY

Nexen Inc.

October 24, 2007 06:30 ET

Nexen Reports Quarterly Results-Continued Production Growth Contributes to Strong Cash Flow

Third Quarter Highlights: - Third quarter production after royalties increases 45% over 2006 to 214,000 boe/d (261,000 boe/d before royalties) - Quarterly cash flow of $868 million ($1.65/share) and earnings of $403 million ($0.77/share) - Buzzard production ramps up during the quarter and exceeds facility design rates - Steam injection continues at Long Lake--on track for bitumen production this winter and upgrader start up mid 2008 - Significant exploration acreage acquired in the Gulf of Mexico (deep-water) and British Columbia (shale gas) - Early results from Vicksburg encouraging

CALGARY, ALBERTA--(Marketwire - Oct. 24, 2007) -



Three Months Nine Months
Ended September 30 Ended September 30
--------------------------------------------
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Production (mboe/d)(1)
Before Royalties 261 203 251 213
After Royalties 214 148 204 155
Net Sales 1,446 997 3,985 3,016
Cash Flow from Operations(2) 868 594 2,379 1,996
Per Common Share ($/share)(2,3) 1.65 1.13 4.52 3.81
Net Income 403 199 892 524
Per Common Share ($/share)(2,3) 0.77 0.38 1.69 1.00
Capital Expenditures(4) 901 879 2,531 2,508
----------------------------------------------------------------------------

(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. 8.
(3) 2006 per share values have been adjusted to reflect the May 2007
two-for-one stock split.
(4) Includes business acquisitions in 2006.


Nexen reported strong financial results in the third quarter with cash flow of $868 million and net income of $403 million. These results reflect increased production from the successful ramp up of our high margin production at Buzzard. Although WTI increased during the quarter and averaged US$75.38/bbl compared to US$70.48/bbl a year ago, we were unable to retain the full benefit of the price increase due to the weakening US dollar. At the end of the quarter we were carrying almost 600,000 bbls of oil in inventory. The sale of this inventory will generate additional cash flow in the fourth quarter. Net income for the quarter includes a recovery of $55 million (after tax) for stock-based compensation expense.

While our marketing group added economic value for the quarter, for accounting purposes they reported a cash flow loss of $7 million. These results reflect the impact of soft gas markets and a sudden rise in crude oil spot prices without a corresponding rise in forward prices.



Oil and Gas Production

Production before Royalties Production after Royalties
Crude Oil, NGLs
and Natural Gas
(mboe/d) Q3 2007 Q2 2007 Q3 2007 Q2 2007
----------------------------------------------------------------------------
North Sea 93 88 93 88
Yemen 70 73 39 42
Canada 35 37 29 30
United States 31 30 26 26
Other Countries 7 6 6 5
Syncrude 25 19 21 17
----------------------------- ----------------------------
Total 261 253 214 208
----------------------------- ----------------------------


Throughout the course of the year, our production volumes have been growing. In the fourth quarter of 2006, our production volumes were 207,000 boe/d, growing to 238,000 boe/d in the first quarter of 2007, 253,000 boe/d in the second and 261,000 boe/d in the third. This translates into a 45% increase in net production volumes compared to a year ago. We expect to show continued growth in the fourth quarter and have seen production volumes as high as 280,000 boe/d with all facilities on line.

The growing production volumes reflect completed development projects in the North Sea such as Buzzard and Duart. At Syncrude, production was strong following a turnaround in the second quarter. Our assets in Yemen, Canada and Colombia continue to meet expectations.

"A number of our development projects are now on stream, but these have taken us longer to complete than we expected," said Charlie Fischer, Nexen's President and Chief Executive Officer. "As we bring these development projects on stream we are starting to achieve our target rates and our financial results are beginning to show the significant value of these projects. The full year impact of these new volumes will add to our production growth in 2008."

North Sea Update

At Buzzard, daily production volumes continued to increase and contributed 76,000 boe/d net (177,000 boe/d gross) to our third quarter volumes. Production has regularly exceeded facility design rates and we continue to look for debottlenecking opportunities to increase the processing capacity of the platform. We currently have sufficient well deliverability to take advantage of additional capacity that may be available.

In September, Buzzard was producing at rates as high as 220,000 boe/d gross. However, as a result of a damaged pipe in the acid gas removal system, Buzzard production has averaged approximately 175,000 boe/d gross so far this month. The damaged pipe has been repaired and rates are currently ramping back up to approximately 220,000 boe/d gross.

"We are delighted with the performance of the Buzzard field," said Fischer. "We exceeded facility design rates during the quarter and believe production at these rates can continue. In addition, the reservoir is performing well which raises our confidence in the potential for increased recovery factors and reserves over time."

As we continue to develop the field, we are acquiring additional information regarding hydrogen sulphide in the reservoir. We are confident that we can maintain deliverability through existing equipment and processes until additional equipment is brought on stream in 2010. We have recently submitted an environmental impact assessment for an additional hydrogen sulphide treatment facility. The proposed facilities comprise a fourth platform with production sweetening capabilities. We plan to sanction this project early in 2008. Our preliminary analysis indicates additional capital of between approximately $350 million and $400 million net to Nexen for the facilities.

"At Buzzard, we have an attractive solution to deal with future hydrogen sulphide at a capital cost that is relatively modest considering that the field is expected to generate approximately $1.7 billion of annual pre-tax cash flow for us at design rates, assuming Brent of US$65/bbl," said Fischer.

During the quarter, production commenced from our Duart field located approximately 100 miles northeast of Aberdeen. We have a 50% non-operated interest here and production is currently ramping up to expected peak rates of approximately 3,000 bbls/d our share.

Elsewhere in the North Sea, we completed an appraisal well at Selkirk. The well confirmed commercial quantities of hydrocarbons and is currently being sidetracked. We have a 38% operated working interest here. In addition, we continue to evaluate development options for our Golden Eagle discovery. Before year end, we plan to drill appraisal wells at Bugle and Kildare, and spud one exploration well.

Ettrick Development On Track for First Oil in 2008

Our Ettrick field development in the North Sea continues to progress well and is approximately 80% complete. The project will consist of three subsea production wells and one water injector tied back to a leased floating production, storage and offloading vessel (FPSO). The FPSO is designed to handle 30,000 bbls/d of oil, 35 mmcf/d of gas and to re-inject 55,000 bbls/d of water. Production from the field is expected to commence mid 2008 with our share averaging approximately 9,000 boe/d for the year. We hold an 80% operated working interest here.

Long Lake Project Update

At Long Lake, we continue to inject steam into the reservoir and are now starting to see bitumen in the fluid returns. We remain on track to have sufficient bitumen production for the upgrader start up in mid 2008. Depending on production ramp up and new facility uptime, bitumen production should reach capacity of approximately 72,000 bbls/d (36,000 bbls/d net to Nexen) in 2009.

"Our SAGD facilities are performing as expected and the recycling of fluid returns from the reservoir is a milestone for the project," commented Fischer.

Construction and commissioning of the upgrader continues. We recently completed the construction of the hydrocracker, the OrCrude™ unit and all main plant utilities. We are on track to complete construction of the gasifier, the air separation unit and sulphur recovery unit in sufficient time for first production of synthetic crude oil in mid 2008. We anticipate the upgrader will reach its full production capacity of approximately 60,000 bbls/d (30,000 bbls/d net to Nexen) of premium synthetic crude about 12 to 18 months after initial start up. Our cost estimate for Phase 1 ranges from $5.8 to $6.1 billion ($2.9 to $3.05 billion net to Nexen).

Phase 1 of Long Lake will develop approximately 10% of our 5.5 billion barrel recoverable resource using our patented process which significantly reduces the need to purchase natural gas, a key cost driver in competing technologies. This will result in a significant cost advantage for us.

"We plan to sequentially develop additional 60,000 bbls/d phases using the same technology and design as Long Lake," stated Fischer. "However, given uncertainty regarding climate change regulations and potential changes to the Alberta royalty regime, we are reviewing our overall execution strategy."

Gulf of Mexico Update

Production commenced at Wrigley on Mississippi Canyon Block 506 early in the third quarter. Based on production tests, Wrigley is capable of producing at approximately 60 mmcf/d (30 mmcf/d net to Nexen). However, limited heat exchanger capability on the third party processing facility has restricted our rates to approximately 40 mmcf/d (20 mmcf/d net to Nexen). Once rectified, we expect to deliver at full capacity rates in 2008. We have a 50% non-operated interest here.

At Aspen, we began producing from an additional development well in August. Current production from this well is averaging approximately 2,100 boe/d and we are reviewing the well completion to determine if mechanical issues in the wellbore are limiting production volumes. We have a 100% operated working interest at Aspen.

At Longhorn, located on Mississippi Canyon Blocks 546 and 502, we drilled an appraisal well during the quarter which exceeded our expectations, encountering approximately 400 feet of net gas pay in multiple sands. The original Longhorn discovery well was drilled in 2006 with a pre-drill resource estimate of between 60 and 250 bcfe for the prospect. Development of the Longhorn discovery, which would include subsea tie-backs to an existing platform, is expected to be sanctioned later this year with first production in 2009. We have a 25% non-operated interest in Longhorn.

During the quarter, we completed drilling our Vicksburg exploration well located on De Soto Canyon Block 353 in the Eastern Gulf. The well was drilled to a depth of approximately 25,400 feet and encountered hydrocarbons. The well was sidetracked and core was recovered. We are still completing our analysis of the data and core samples and early indications are encouraging. We expect to announce more information in the next quarter once our analysis is complete and future plans have been determined. We have a 25% non-operated working interest in the block.

We have a 25% operated interest in Knotty Head on Green Canyon Block 512, where our current estimate of resource for the field is between 200 and 500 mmboe. We continue to pursue rig availability to allow us to spud an appraisal well by mid 2008 and we have also contracted a new-build drilling rig which is scheduled to arrive in mid 2009.

To ensure we can continue to execute our deep-water growth strategy, we recently contracted a second new-build fifth generation dynamically positioned semi-submersible drilling rig which is scheduled for delivery in 2010. The rig contract is for two years, with day rates totaling $340 million, and provides for two optional one year extensions. This rig, together with the rig scheduled to arrive in mid 2009, is capable of drilling to depths of 35,000 feet in 8,500 feet of water.

We were recently named the high bidder on 30 offshore blocks in the Central Gulf of Mexico Outer Continental Shelf Lease Sale 205 for a total investment of $113 million net to Nexen. These awards are subject to the approval of the Minerals Management Service section of the US Department of the Interior.

"We are continuing to build our significant portfolio of exploration opportunities in the deep-water of the Gulf of Mexico," said Fischer. "These leases contain several exciting sub-salt blocks with a number of drill-ready prospects."

British Columbia Shale Gas

We have secured a material land position in northeast British Columbia on an emerging Devonian shale gas play, which has the potential to be one of the most significant shale gas plays in Canada. Last winter we drilled and cored two vertical exploration wells which will be completed and tested this winter. With success at recent land sales we currently have approximately 123,000 acres with a 100% working interest on the play, making us a significant player in the area.

Offshore West Africa

The Usan field development, located in Nigeria on offshore Block OPL-222, continues to progress toward project sanction. The project will have the ability to process an average of 180,000 bbls/d of oil during the initial production plateau period through a new FPSO which contains two million barrels of storage capacity. We expect the Usan development to be formally sanctioned this year, at which time the major deep-water facilities contracts will be awarded. We have a 20% interest in exploration and development on this block.

Capital Update

During the first nine months of the year, we invested $2.5 billion in capital projects. For the full year, we anticipate capital spending to be between $3.5 and $3.7 billion. Capital increases reflect additional investment at Long Lake and recent success at land sales in the Gulf of Mexico deep-water and in northeast British Columbia shale gas.

"We are currently developing our 2008 capital budget, and in light of uncertainty surrounding proposed changes to Alberta's royalty regime, we are reviewing our strategy with respect to coalbed methane and future oil sands development," stated Fischer. "Should changes go ahead as proposed by the Alberta Royalty Review Panel, our portfolio of opportunities provides us with many choices to invest capital where overall returns are attractive."

Quarterly Dividend

The Board of Directors has declared the regular quarterly dividend of $0.025 per common share payable January 1, 2008 to shareholders of record on December 10, 2007. 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, deep-water Gulf of Mexico, the Athabasca oil sands of Alberta, the Middle East and offshore West Africa. We add value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity and environmental protection.

Conference Call

Charlie Fischer, President and CEO, and Kevin Reinhart, Vice President, Corporate Planning and Business Development, will host a conference call to discuss our third quarter financial and operating results and expectations for the future.



Date: October 24, 2007
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:

416-641-6125 (Toronto)
866-542-4236 (North American toll-free)
800-8989-6323 (Global toll-free)

A replay of the call will be available for two weeks starting at 9:00 a.m.
Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free)
passcode 3239085 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. Such 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 expected full year production, cash flow and capital expenditures as well as future production associated with our coalbed methane, Long Lake, Syncrude, North Sea, Gulf of Mexico, Yemen, West Africa and other projects.

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 and transport crude oil and natural gas to markets; the results of exploration and development drilling and related activities; volatility in energy trading markets; foreign-currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; and political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management's future course of action would depend on our assessment of all information at that time. 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 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, expected finding and development costs, expected operating costs, future demand for chemicals products, 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.

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. Readers should also refer to Items 1A and 7A in our 2006 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 press release, we may refer to "recoverable reserves", "probable reserves" and "recoverable 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.

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 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 2006 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. 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 press release, 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.



Nexen Inc.
Financial Highlights

Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net Sales 1,446 997 3,985 3,016
Cash Flow from Operations 868 594 2,379 1,996
Per Common Share ($/share) (1) 1.65 1.13 4.52 3.81
Net Income 403 199 892 524
Per Common Share ($/share) (1) 0.77 0.38 1.69 1.00
Capital Investment, including
Acquisitions (2) 901 879 2,531 2,508
Net Debt (3) 4,393 4,161 4,393 4,161
Common Shares Outstanding
(millions of shares) (1) 527.4 524.6 527.4 524.6
----------------------------------------
(1) Restated to reflect a two-for-one stock split in the second quarter of
2007.
(2) Includes oil and gas development, exploration, and expenditures for
other property, plant and equipment.
(3) Net Debt is defined as long-term debt and short-term borrowings, less
cash and cash equivalents.


Cash Flow from Operations (1)

Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Oil & Gas and Syncrude
Yemen (2) 171 223 511 688
Canada 35 56 130 188
United States 109 172 355 446
United Kingdom 563 83 1,416 385
Other Countries 29 25 61 75
Marketing (7) 41 64 285
Syncrude 102 85 229 175
----------------------------------------
1,002 685 2,766 2,242
Chemicals 26 20 62 66
----------------------------------------
1,028 705 2,828 2,308
Interest and Other Corporate Items (89) (75) (276) (179)
Income Taxes (3) (71) (36) (173) (133)
----------------------------------------
Cash Flow from Operations (1) 868 594 2,379 1,996
----------------------------------------
----------------------------------------
(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. 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.


Reconciliation of Cash Flow
from Operations Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash Flow from Operating Activities 1,097 676 2,127 1,784
Changes in Non-Cash Working Capital (253) (212) 19 92
Other 30 16 253 43
Amortization of Premium for Crude
Oil Put Options (6) (20) (20) (57)
Provision for Non-Recurring
Arbitration - 134 - 134
----------------------------------------
Cash Flow from Operations 868 594 2,379 1,996
----------------------------------------
----------------------------------------

Weighted-average Number of
Common Shares Outstanding
(millions of shares) 527.4 524.6 526.8 524.0
----------------------------------------
Cash Flow from Operations Per
Common Share ($/share) 1.65 1.13 4.52 3.81
----------------------------------------
----------------------------------------

(2) After in-country cash taxes of $65 million for the three months ended
September 30, 2007 (2006 - $76 million) and $174 million for the nine
months ended September 30, 2007 (2006 - $224 million).
(3) Excludes in-country cash taxes in Yemen.


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

Three Months Nine Months
Ended September 30 Ended September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
Yemen 69.8 90.5 73.3 96.0
Canada 17.0 19.2 17.3 20.7
United States 14.2 16.7 17.3 17.9
United Kingdom 90.0 12.8 77.2 15.2
Other Countries 6.5 6.7 6.2 6.4
Syncrude (2) 25.2 20.5 21.9 17.6
----------------------------------------
222.7 166.4 213.2 173.8
----------------------------------------
Natural Gas (mmcf/d)
Canada 111 106 115 105
United States 98 105 95 111
United Kingdom 18 11 15 22
----------------------------------------
227 222 225 238
----------------------------------------

Total Production (mboe/d) 261 203 251 213
----------------------------------------
----------------------------------------


Production Volumes (after royalties)

Three Months Nine Months
Ended September 30 Ended September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
Yemen 39.0 49.5 41.8 51.8
Canada 12.9 14.6 13.5 16.2
United States 12.5 14.6 15.3 15.7
United Kingdom 90.0 12.8 77.2 15.2
Other Countries 6.0 6.2 5.7 5.8
Syncrude (2) 21.1 18.2 18.8 15.8
----------------------------------------
181.5 115.9 172.3 120.5
----------------------------------------
Natural Gas (mmcf/d)
Canada 94 90 96 89
United States 83 89 81 94
United Kingdom 18 11 15 22
----------------------------------------
195 190 192 205
----------------------------------------

Total Production (mboe/d) 214 148 204 155
----------------------------------------
----------------------------------------

(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 - 2007 Quarters - 2006 Year
-------------------------------------------------------------
(all dollar
amounts in
Cdn$ unless
noted) 1st 2nd 3rd 1st 2nd 3rd 4th 2006
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil
(US$/bbl) 58.16 65.03 75.38 63.48 70.70 70.48 60.21 66.22
Nexen Average
- Oil
(Cdn$/bbl) 61.69 72.27 75.86 63.11 72.90 73.06 60.89 67.50
NYMEX Natural
Gas
(US$/mmbtu) 7.18 7.66 6.24 7.87 6.67 6.14 7.26 6.99
Nexen Average
- Gas
(Cdn$/mcf) 7.58 7.52 5.80 8.71 6.68 6.39 6.84 7.18
----------------------------------------------------------------------------

NETBACKS:
Canada -
Heavy Oil
Sales
(mbbls/d) 17.8 17.2 16.9 21.9 20.1 19.0 18.3 19.8

Price
Received
($/bbl) 41.71 41.89 46.76 30.00 51.67 52.95 37.61 42.79
Royalties
& Other 9.16 9.52 10.93 6.25 11.38 12.55 8.43 9.58
Operating
Costs 13.65 15.14 14.53 11.47 11.66 12.61 12.98 12.15
----------------------------------------------------------------------------
Netback 18.90 17.23 21.30 12.28 28.63 27.79 16.20 21.06
----------------------------------------------------------------------------
Canada -
Natural Gas
Sales (mmcf/d) 118 116 112 106 104 106 118 108

Price Received
($/mcf) 7.16 7.06 5.17 7.65 6.21 5.78 6.37 6.49
Royalties
& Other 1.26 1.09 0.78 1.17 0.89 0.90 0.98 0.97
Operating
Costs 1.59 1.81 2.52 1.27 1.33 1.33 1.64 1.38
----------------------------------------------------------------------------
Netback 4.31 4.16 1.87 5.21 3.99 3.55 3.75 4.14
----------------------------------------------------------------------------
Yemen
Sales
(mbbls/d) 77.5 72.7 69.9 102.6 94.5 88.8 85.1 92.7

Price Received
($/bbl) 63.02 77.34 78.27 68.32 76.86 76.08 64.90 71.57
Royalties
& Other 28.17 33.84 34.73 32.73 34.60 34.80 26.76 32.32
Operating
Costs 6.07 6.29 6.72 3.88 4.39 4.53 5.11 4.45
In-country
Taxes 6.38 9.89 10.03 7.20 9.46 9.29 7.94 8.45
----------------------------------------------------------------------------
Netback 22.40 27.32 26.79 24.51 28.41 27.46 25.09 26.35
----------------------------------------------------------------------------
Syncrude
Sales
(mbbls/d) 21.4 19.0 25.2 14.8 17.4 20.5 21.9 18.7

Price Received
($/bbl) 70.03 77.12 82.09 69.95 79.50 77.53 63.37 72.32
Royalties
& Other 8.26 10.33 13.42 6.68 7.95 8.54 4.79 6.93
Operating
Costs 24.40 29.91 22.37 40.12 27.84 21.69 24.42 27.53
----------------------------------------------------------------------------
Netback 37.37 36.88 46.30 23.15 43.71 47.30 34.16 37.86
----------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.

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

Total
Quarters - 2007 Quarters - 2006 Year
-------------------------------------------------------------
(all dollar
amounts in
Cdn$ unless
noted) 1st 2nd 3rd 1st 2nd 3rd 4th 2006
----------------------------------------------------------------------------
United States
Crude Oil:
Sales
(mbbls/d) 21.6 16.0 14.1 19.3 17.8 16.7 14.6 17.0
Price
Received
($/bbl) 58.49 68.18 74.43 63.73 70.23 70.23 58.09 65.80
Natural Gas:
Sales (mmcf/d) 101 86 98 120 107 105 111 111
Price Received
($/mcf) 8.58 8.85 6.75 9.06 7.51 7.18 7.56 7.86
Total Sales
Volume
(mboe/d) 38.4 30.4 30.5 39.3 35.6 34.1 33.0 35.5

Price Received
($/boe) 55.44 61.04 56.28 58.97 57.60 56.35 50.97 56.12
Royalties
& Other 6.78 7.71 7.28 7.96 7.62 7.42 7.06 7.53
Operating
Costs 8.11 9.46 7.40 8.47 7.00 8.42 8.78 8.17
----------------------------------------------------------------------------
Netback 40.55 43.87 41.60 42.54 42.98 40.51 35.13 40.42
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales
(mbbls/d) 58.8 87.2 83.6 17.6 17.9 13.8 16.2 16.3
Price
Received
($/bbl) 64.33 74.07 78.06 69.02 73.24 77.73 65.67 71.19
Natural Gas:
Sales (mmcf/d) 13 13 16 24 29 10 15 19
Price Received
($/mcf) 3.87 3.32 4.99 11.82 5.52 5.57 5.52 7.43
Total Sales
Volume
(mboe/d) 60.8 89.3 86.3 21.5 22.8 15.4 18.6 19.6

Price Received
($/boe) 62.92 72.75 76.56 69.37 64.59 73.13 61.38 66.81
Royalties
& Other - - - - - - - -
Operating
Costs 9.60 6.59 6.28 11.24 9.59 15.12 10.18 11.28
----------------------------------------------------------------------------
Netback 53.32 66.16 70.28 58.13 55.00 58.01 51.20 55.53
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 5.8 6.2 6.5 5.8 6.6 6.7 6.0 6.3

Price
Received
($/bbl) 59.81 68.04 76.29 58.81 69.63 74.05 60.22 66.09
Royalties
& Other 4.80 5.62 6.46 4.71 5.92 6.33 4.89 5.51
Operating
Costs 2.97 3.39 3.34 2.27 2.74 2.55 3.93 2.87
----------------------------------------------------------------------------
Netback 52.04 59.03 66.49 51.83 60.97 65.17 51.40 57.71
----------------------------------------------------------------------------

Company-Wide
Oil and Gas
Sales
(mboe/d) 241.5 254.1 253.9 223.5 214.5 202.1 202.6 210.6

Price
Received
($/boe) 59.13 68.48 69.82 61.11 66.78 66.82 56.95 62.92
Royalties
& Other 12.26 12.65 13.02 18.04 18.95 19.25 14.38 17.68
Operating
Costs 9.67 9.41 9.26 8.78 8.21 8.72 9.40 8.77
In-country
Taxes 2.05 2.83 2.76 3.31 4.17 4.08 3.33 3.72
----------------------------------------------------------------------------
Netback 35.15 43.59 44.78 30.98 35.45 34.77 29.84 32.75
----------------------------------------------------------------------------
(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 Nine Months Ended September 30
Cdn$ millions, except per share amounts

Three Months Nine Months
Ended Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,446 997 3,985 3,016
Marketing and Other (Note 13) 226 287 773 1,089
--------------------------------
1,672 1,284 4,758 4,105
--------------------------------

Expenses
Operating 283 229 862 702
Depreciation, Depletion, Amortization and
Impairment 349 244 1,043 770
Transportation and Other 238 333 694 796
General and Administrative 7 51 247 379
Exploration 67 82 221 231
Interest (Note 6) 40 15 134 35
--------------------------------
984 954 3,201 2,913
--------------------------------

Income before Income Taxes 688 330 1,557 1,192
--------------------------------

Provision for Income Taxes
Current 136 112 347 357
Future 142 16 303 299
--------------------------------
278 128 650 656
--------------------------------

Net Income before Non-Controlling Interests 410 202 907 536
Less: Net Income Attributable to
Non-Controlling Interests (7) (3) (15) (12)
--------------------------------

Net Income 403 199 892 524
--------------------------------
--------------------------------

Earnings Per Common Share ($/share)
Basic (Note 11) 0.77 0.38 1.69 1.00
--------------------------------
--------------------------------

Diluted (Note 11) 0.75 0.37 1.66 0.97
--------------------------------
--------------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Balance Sheet
Cdn$ millions, except share amounts
September 30 December 31
2007 2006
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 172 101
Restricted Cash and Margin Deposits 176 197
Accounts Receivable (Note 2) 2,683 2,951
Inventories and Supplies (Note 3) 628 786
Future Income Tax Assets 73 479
Other 77 67
------------------------------
Total Current Assets 3,809 4,581
------------------------------

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $6,539
(December 31, 2006 - $6,399) 12,291 11,739
Future Income Tax Assets 167 141
Deferred Charges and Other Assets (Note 4) 276 318
Goodwill 328 377
------------------------------
Total Assets 16,871 17,156
------------------------------
------------------------------

Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Borrowings (Note 6) - 158
Accounts Payable and Accrued Liabilities 3,408 3,879
Accrued Interest Payable 67 55
Dividends Payable 13 13
------------------------------
Total Current Liabilities 3,488 4,105
------------------------------

Long-Term Debt (Note 6) 4,565 4,673
Future Income Tax Liabilities 2,231 2,468
Asset Retirement Obligations (Note 7) 701 683
Deferred Credits and Other Liabilities
(Note 8) 396 516
Non-Controlling Interests 75 75

Shareholders' Equity (Note 10)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2007 - 527,429,968 shares
2006 - 525,026,412 shares 891 821
Contributed Surplus 3 4
Retained Earnings 4,825 3,972
Accumulated Other Comprehensive Income
(Note 1) (304) (161)
------------------------------
Total Shareholders' Equity 5,415 4,636
------------------------------
Commitments, Contingencies and Guarantees
(Note 14)

------------------------------
Total Liabilities and Shareholders' Equity 16,871 17,156
------------------------------
------------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Statement of Cash Flows
For the Three and Nine Months Ended September 30
Cdn$ millions

Three Months Nine Months
Ended Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating Activities
Net Income 403 199 892 524
Charges and Credits to Income not
Involving Cash (Note 12) 404 199 1,286 1,164
Exploration Expense 67 82 221 231
Changes in Non-Cash Working Capital
(Note 12) 253 212 (19) (92)
Other (30) (16) (253) (43)
----------------------------------
1,097 676 2,127 1,784

Financing Activities
Proceeds from Long-Term Notes - - 1,660 -
Proceeds from (Repayment of) Term
Credit Facilities, Net 188 136 (767) 551
Proceeds from Term Credit Facilities of
Canexus 12 6 45 4
Repayment of Medium-Term Notes (150) - (150) -
Proceeds from (Repayment of) Short-Term
Borrowings, Net (60) 37 (152) 122
Dividends on Common Shares (Note 10) (13) (13) (39) (39)
Issue of Common Shares and Exercise of
Stock Options 4 4 44 41
Other (8) (7) (43) (21)
----------------------------------
(27) 163 598 658

Investing Activities
Capital Expenditures
Exploration and Development (772) (844) (2,309) (2,330)
Proved Property Acquisitions (104) (9) (150) (12)
Chemicals, Corporate and Other (25) (26) (72) (88)
Business Acquisitions, Net of Cash
Acquired - - - (78)
Proceeds on Disposition of Assets - - - 25
Changes in Restricted Cash and Margin
Deposits (103) (52) (21) (40)
Changes in Non-Cash Working Capital
(Note 12) (33) 56 11 115
Other (1) (18) (15) (22)
----------------------------------
(1,038) (893) (2,556) (2,430)

Effect of Exchange Rate Changes on Cash
and Cash Equivalents (18) (1) (98) (29)
----------------------------------

Increase (Decrease) in Cash and Cash
Equivalents 14 (55) 71 (17)

Cash and Cash Equivalents - Beginning of
Period 158 86 101 48
----------------------------------

Cash and Cash Equivalents - End of
Period 172 31 172 31
----------------------------------
----------------------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Statement of Shareholders' Equity
For the Three and Nine Months Ended September 30
Cdn$ millions

Three Months Nine Months
Ended Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Common Shares
Balance at Beginning of Period 893 799 821 732
Issue of Common Shares 3 2 28 28
Proceeds from Options Exercised for Shares 1 2 16 13
Accrued Liability Relating to Options
Exercised for Shares (6) 6 26 36
-------------------------------
Balance at End of Period 891 809 891 809
-------------------------------
-------------------------------

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

Retained Earnings
Balance at Beginning of Period 4,435 3,722 3,972 3,423
Net Income 403 199 892 524
Dividends on Common Shares (13) (13) (39) (39)
-------------------------------
Balance at End of Period 4,825 3,908 4,825 3,908
-------------------------------
-------------------------------

Accumulated Other Comprehensive Income
Balance at Beginning of Period (253) (230) (161) -
Opening Cumulative Foreign Currency
Translation Adjustment (Note 1) - - - (161)
Opening Derivatives Designated as Cash Flow
Hedges (Note 1) - - 61 -
Other Comprehensive Income (51) (2) (204) (71)
-------------------------------
Balance at End of Period (304) (232) (304) (232)
-------------------------------
-------------------------------


Nexen Inc.
Unaudited Consolidated Statement of Comprehensive Income
For the Three and Nine Months Ended September 30
Cdn$ millions

Three Months Nine Months
Ended Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Net Income 403 199 892 524
Other Comprehensive Loss, Net of Income
Taxes:
Foreign Currency Translation Adjustment:
Net Losses on Investment in
Self-Sustaining Foreign Operations (327) - (822) (218)
Net Gains on Hedges of Self-Sustaining
Foreign Operations(1) 276 (2) 679 145
Realized Translation Adjustments
Recognized in Net Income(2) - - - 2
Cash Flow Hedges:
Realized Mark-to-Market Gains
Recognized in Net Income - - (61) -
-------------------------------
Other Comprehensive Loss (51) (2) (204) (71)
-------------------------------
Comprehensive Income 352 197 688 453
-------------------------------
-------------------------------

(1) Net of income taxes for the three months ended September 30, 2007 of $47
million (2006 - $nil) and for the nine months ended September 30, 2007
of $113 million (2006 - $18 million).
(2) Net of income taxes for the three months ended September 30, 2007 of nil
(2006 - $nil) and nine months ended September 30, 2007 of $nil (2006
$nil).

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 16. 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 September 30, 2007 and December 31, 2006 and the results of our operations and our cash flows for the three and nine months ended September 30, 2007 and 2006.

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 nine months ended September 30, 2007 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2007.

These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2006 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 2006 Annual Report on Form 10-K.

Change in Accounting Policies

On January 1, 2007, we adopted the following new accounting standards issued by the Canadian Accounting Standards Board (AcSB): Financial Instruments-Recognition and Measurement (Section 3855), Hedges (Section 3865) and Comprehensive Income (Section 1530).

Financial Instruments-Recognition and Measurement

Section 3855 requires all financial assets and liabilities to be carried at fair value in the balance sheet with the exception of loans and receivables, investments that are intended to be held to maturity and non-trading financial liabilities which are to be carried at cost or amortized cost.

Realized and unrealized gains and losses on financial assets and liabilities carried at fair value are recognized in the statement of income in the periods such gains and losses arise. Transaction costs related to these financial assets and liabilities are included in the statement of income when incurred. Unrealized gains and losses on financial assets and liabilities carried at cost or amortized cost are recognized in the statement of income when these assets or liabilities settle.

We hold financial instruments that were carried at fair value prior to the adoption of Section 3855 as described in Note 9. The valuation methods we use to determine the fair value of these financial instruments remain unchanged. Financial instruments we carry at cost or amortized cost include our accounts receivable, accounts payable, short-term and long-term debt. Upon adopting Section 3855 with respect to the amortized cost using the effective interest rate method of our long-term debt, we have reclassed deferred financing costs previously included in deferred charges and other assets as unamortized debt issue costs which reduce the carrying value of our long-term debt.

Hedges

Section 3865 prescribes new standards for hedge accounting.

For cash flow hedges, changes in the fair value of a financial instrument designated as a cash flow hedge are recognized in the statement of income in the same period as the hedged item. Any fair value change in the financial instrument before that period is recognized on the balance sheet. The effective portion of this fair value change is recognized in other comprehensive income with any ineffectiveness recognized in the statement of income during the period of change.

For fair value hedges, both the financial instrument designated as a fair value hedge and the underlying commitment are recognized on the balance sheet at fair value. Changes in the fair value of both are reflected in the statement of income.

Adoption of these new standards for hedge accounting required us to record unrealized mark-to-market gains on cash flow hedges that were previously not included on our Consolidated Balance Sheet at December 31, 2006 as an adjustment to the opening balance of accumulated other comprehensive income (see Note 9).

Comprehensive Income

Section 1530 provides for a new statement of comprehensive income and establishes accumulated other comprehensive income as a separate component of shareholders' equity. The statement of comprehensive income reflects changes in accumulated other comprehensive income and includes the effective portion of changes in the fair value of financial instruments designated as cash flow hedges, as well as changes in foreign currency translation amounts arising in respect of self-sustaining foreign operations together with the impact of any related hedges. Amounts included in accumulated other comprehensive income are reclassified to the statement of income when realized. On adoption of Section 1530, cumulative foreign currency translation adjustments relating to our self-sustaining foreign operations were reclassed to accumulated other comprehensive income and comparative amounts have been restated.

We adopted these standards prospectively. Comparative amounts for prior periods have not been restated with the exception of amounts related to cumulative foreign currency translation adjustments. Adoption of these standards as at January 1, 2007 had the following impact on our Unaudited Consolidated Balance Sheet:



January 1, 2007
Increase/(Decrease)
----------------------------------------------------------------------------
To Include Unrealized Mark-to-Market Gains on Cash
Flow Hedges at December 31, 2006:
Accounts Receivable 25
Accounts Payable and Accrued Liabilities (65)
Future Income Tax Liabilities 29
Accumulated Other Comprehensive Income 61

To Include Cumulative Foreign Currency Translation
in Accumulated Other Comprehensive Income:
Cumulative Foreign Currency Translation Adjustment 161
Accumulated Other Comprehensive Income (161)

To Include Unamortized Debt Issue Costs with
Long-Term Debt:
Deferred Charges and Other Assets (59)
Long-Term Debt (59)
--------------------


New Accounting Pronouncements

In December 2006, the Canadian Accounting Standards Board (AcSB) issued two new Sections in relation to financial instruments: Section 3862, Financial Instruments - Disclosures, and Section 3863, Financial Instruments - Presentation. Both sections will become effective for annual and interim periods beginning on or after October 1, 2007 and will require increased disclosure of financial instruments.

In December 2006, the AcSB issued Section 1535, Capital Disclosures, requiring disclosure of information about an entity's capital and the objectives, policies, and processes for managing capital. The standard is effective for annual periods beginning on or after October 1, 2007.

In June 2007, the AcSB issued Section 3031, Inventories, which replaces the existing guidance. The new section is harmonized with International Accounting Standards and provides additional guidance on the measurement and disclosure requirements for inventories. Specifically, Section 3031 requires inventories to be measured at the lower of cost and net realizable value. The new requirements are effective for fiscal years beginning on or after January 1, 2008. We do not expect the adoption of this section to have a material impact on our results of operations or financial position.



2. ACCOUNTS RECEIVABLE

September 30 December 31
2007 2006
----------------------------------------------------------------------------
Trade
Marketing 1,803 2,226
Oil and Gas 721 600
Chemicals and Other 42 58
--------------------------------
2,566 2,884
Non-Trade 127 80
--------------------------------
2,693 2,964
Allowance for Doubtful Receivables (10) (13)
--------------------------------
Total 2,683 2,951
--------------------------------
--------------------------------


3. INVENTORIES AND SUPPLIES

September 30 December 31
2007 2006
----------------------------------------------------------------------------
Finished Products
Marketing 490 609
Oil and Gas 13 21
Chemicals and Other 14 14
--------------------------------
517 644
Work in Process 4 5
Field Supplies 107 137
--------------------------------
Total 628 786
--------------------------------
--------------------------------


4. DEFERRED CHARGES AND OTHER ASSETS

September 30 December 31
2007 2006
----------------------------------------------------------------------------
Long-Term Marketing Derivative
Contracts (Note 9) 172 153
Deferred Financing Costs (Note 1) - 59
Asset Retirement Remediation Fund 14 13
Crude Oil Put Options (Note 9) 12 19
Other 78 74
--------------------------------
Total 276 318
--------------------------------
--------------------------------


5. SUSPENDED WELL COSTS

The following table shows the changes in capitalized exploratory well
costs during the nine month period ended September 30, 2007 and the year
ended December 31, 2006, and does not include amounts that were initially
capitalized and subsequently expensed in the same period. Capitalized
exploratory well costs are included in PP&E.


Nine Months Ended Year Ended
September 30 December 31
2007 2006
----------------------------------------------------------------------------
Balance at Beginning of Period 226 252
Additions to Capitalized Exploratory
Well Costs Pending the Determination
of Proved Reserves 125 129
Capitalized Exploratory Well Costs
Charged to Expense (6) (70)
Transfers to Wells, Facilities and
Equipment Based on Determination of
Proved Reserves (70) (84)
Effects of Foreign Exchange (28) (1)
--------------------------------
Balance at End of Period 247 226
--------------------------------
--------------------------------


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.


September 30 December 31
2007 2006
----------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 131 179
Capitalized for a Period of Greater than
One Year 116 47
--------------------------------
Balance at End of Period 247 226
--------------------------------
--------------------------------

Number of Projects that have Exploratory
Well Costs Capitalized for a Period
Greater than One Year 6 4
--------------------------------


As at September 30, 2007, we have exploratory costs that have been capitalized for more than one year relating to our interest in an exploratory block in the Gulf of Mexico ($50 million), our coalbed methane exploratory activities in Canada ($23 million), two exploratory wells on Block 51 in Yemen ($19 million), our interest in an exploratory block offshore Nigeria ($18 million) and an exploratory block in the North Sea ($6 million). We have capitalized costs related to successful wells drilled in Nigeria, Gulf of Mexico, North Sea, and at Block 51 in Yemen. In Canada, we have capitalized exploratory costs relating to our coalbed methane projects. 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. LONG-TERM DEBT AND SHORT-TERM BORROWINGS

September 30 December 31
2007 2006
----------------------------------------------------------------------------
Term Credit Facilities (US$146 million) (a) 146 1,078
Canexus LP Term Credit Facilities
(US$189 million) 188 174
Medium-Term Notes, due 2007 (1) - 150
Medium-Term Notes, due 2008 (2) 125 125
Notes, due 2013 (US$500 million) 498 583
Notes, due 2015 (US$250 million) 249 291
Notes, due 2017 (US$250 million) (b) 249 -
Notes, due 2028 (US$200 million) 200 233
Notes, due 2032 (US$500 million) 498 583
Notes, due 2035 (US$790 million) 787 920
Notes, due 2037 (US$1,250 million) (c) 1,246 -
Subordinated Debentures, due 2043
(US$460 million) 458 536
--------------------------------
4,644 4,673
Unamortized Debt Issue Costs (Note 1) (79) -
--------------------------------
Total Long-Term Debt 4,565 4,673
--------------------------------
--------------------------------

(1) Amounts due July 2007 were not included in current liabilities as we
refinanced this amount with our term credit facilities.
(2) Amounts due June 2008 are not included in current liabilities as we
expect to refinance this amount with our term credit facilities.


(a) Term credit facilities

We have committed, unsecured term credit facilities of $3.1 billion, which are available to 2012. At September 30, 2007, $146 million (US$146 million) was drawn on these facilities (December 31, 2006 - $1,078 million). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable monthly at floating rates. The weighted-average interest rate on our term credit facilities was 5.9% for the three months ended September 30, 2007 (2006 - 5.8%) and 5.9% for the nine months ended September 30, 2007 (2006 - 5.7%). At September 30, 2007, $346 million of these facilities were utilized to support outstanding letters of credit (December 31, 2006 - $294 million).

(b) Notes, due 2017

In May 2007, we issued US$250 million of 10 year notes. Interest is payable semi-annually at a rate of 5.65% and the principal is to be repaid in May 2017. We 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 term of the notes plus 0.2%. The proceeds were used to repay outstanding term credit facilities.

(c) Notes, due 2037

In May 2007, we issued US$1,250 million of 30 year notes. Interest is payable semi-annually at a rate of 6.40% and the principal is to be repaid in May 2037. We 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 term of the notes plus 0.35%. The proceeds were used to repay outstanding term credit facilities.



(d) Interest expense

Three Months Nine Months
Ended September 30 Ended September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Long-Term Debt 80 72 244 199
Other 5 5 14 15
-----------------------------------------------
85 77 258 214
Less: Capitalized (45) (62) (124) (179)
-----------------------------------------------
Total 40 15 134 35
-----------------------------------------------
-----------------------------------------------


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

(e) Short-term borrowings

Nexen has uncommitted, unsecured credit facilities of approximately $630 million, none of which were drawn at September 30, 2007 (December 31, 2006 - $158 million). We utilized $106 million of these facilities to support outstanding letters of credit at September 30, 2007 (December 31, 2006 - $252 million). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 5.8% for the three months ended September 30, 2007 (2006 - 5.5%) and 5.8% for the nine months ended September 30, 2007 (2006 - 5.3%).

7. ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of the asset retirement obligations associated with our property, plant and equipment for the nine months ended September 30, 2007 and the year ended December 31, 2006, are as follows:



Nine Months Ended Year Ended
September 30 December 31
2007 2006
----------------------------------------------------------------------------
Balance at Beginning of Period 704 611
Obligations Assumed with Development
Activities 69 75
Obligations Discharged with Disposed
Properties - (1)
Expenditures Made on Asset Retirements (18) (44)
Accretion 33 37
Revisions to Estimates (3) (10)
Effects of Foreign Exchange (63) 36
--------------------------------------
Balance at End of Period (1,2) 722 704
--------------------------------------
--------------------------------------

(1) Obligations due within 12 months of $21 million (December 31, 2006 -
$21 million) have been included in accounts payable and accrued
liabilities.
(2) Obligations relating to our oil and gas activities amount to $676
million (December 31, 2006 - $658 million) and obligations relating to
our chemicals business amount to $46 million (December 31, 2006 -
$46 million).


Our total estimated undiscounted asset retirement obligations amount to $1,785 million (December 31, 2006 - $1,770 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.7%. Approximately $103 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 lives of the assets are determinable.



8. DEFERRED CREDITS AND OTHER LIABILITIES

September 30 December 31
2007 2006
----------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts
(Note 9) 95 199
Deferred Transportation Revenue 83 89
Fixed-Price Natural Gas Contracts and Swaps
(Note 9) 57 76
Defined Benefit Pension Obligations 52 48
Capital Lease Obligations 50 48
Stock-Based Compensation Liability 7 6
Other 52 50
--------------------------------
Total 396 516
--------------------------------
--------------------------------


9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

We use derivatives in our marketing group for trading purposes and we also use derivatives to manage commodity price risk for non-trading purposes. Our derivative instruments are carried at fair value on the Unaudited Consolidated Balance Sheet. Our other financial instruments are carried at cost or amortized cost.

(a) Carrying value and estimated fair value of financial instruments

The carrying values, fair values, and unrecognized gains or losses on our outstanding derivatives and other financial liabilities are:



September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Carrying Fair Unrecognized Carrying Fair Unrecognized
Value Value Gain/(Loss) Value Value Gain/(Loss)
------------------------------ -----------------------------
Derivatives
Commodity Price
Risk
Non-Trading
Activities
Crude Oil Put
Options 12 12 - 19 19 -
Fixed-Price
Natural Gas
Contracts (68) (68) - (96) (96) -
Natural Gas Swaps (17) (17) - (8) (8) -

Trading Activities
Crude Oil and
Natural Gas 138 138 - 372 372 -
Future Sale of Gas
Inventory - - - - 25 25

Foreign Currency
Exchange Rate Risk
Non-Trading
Activities 1 1 - - - -
Trading Activities - - - (12) (12) -
------------------------------ -----------------------------
Total Derivatives 66 66 - 275 300 25
------------------------------ -----------------------------
------------------------------ -----------------------------

Other Financial
Liabilities
Long-Term Debt (4,565)(4,605) (40) (4,673) (4,728) (55)
------------------------------ -----------------------------
------------------------------ -----------------------------


The estimated fair value of all derivative instruments is based on quoted market prices and, if not available, on estimates from third-party brokers or dealers. Other financial assets used in the normal course of business include cash and cash equivalents, restricted cash and margin deposits and accounts receivable. Other financial liabilities include accounts payable, accrued interest payable, short-term borrowings and long-term debt. Fair value of long-term debt is estimated based on third-party brokers and quoted market prices.

(b) Commodity price risk management

Non-Trading Activities

We generally sell our crude oil and natural gas under short-term market based contracts.

Crude oil put options

In 2006, we purchased WTI crude oil put options to provide a base level of price protection without limiting our upside to higher prices. These options establish an annual average WTI floor price of US$50/bbl in 2007 on 105,000 bbls/d at a cost of $26 million. The crude oil put options are stated at fair value and are included in accounts receivable as they settle within 12 months. Any change in fair value is included in marketing and other on the Unaudited Consolidated Statement of Income.

During the second quarter of 2007, we purchased put options on 36 million barrels or about 100,000 bbls/d of our 2008 crude oil production. These options establish a Dated Brent floor price of US$50/bbl on these volumes and are settled annually. The put options were purchased for $24 million and are carried at fair value. Any change in fair value is included in marketing and other income on the Unaudited Consolidated Statement of Income.



Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(bbls/d) (US$/bbl) (Cdn$ millions)
WTI Crude Oil Put Options 105,000 2007 50 -
Dated Brent Crude Oil Put
Options 100,000 2008 50 12
----------------
12
----------------
----------------


Fixed-price natural gas contracts and natural gas swaps

In July and August 2005, we sold certain Canadian oil and gas properties and retained fixed-price natural gas sales contracts that were previously associated with those properties. Since these contracts are no longer used in the normal course of our oil and gas operations, they have been included in the Unaudited Consolidated Balance Sheet at fair value. Amounts settling within 12 months are included in accounts payable and amounts settling greater than 12 months are included in deferred credits and other liabilities. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income.



Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Fixed-Price Natural Gas
Contracts 15,514 2007-2008 2.46 (20)
15,514 2008-2010 2.56-2.77 (48)
---------------
(68)
---------------
---------------


Following the sale of the Canadian oil and gas properties, we entered into natural gas swaps to hedge our fixed price exposure with floating natural gas prices. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income. Amounts settling within 12 months are included in accounts receivable and amounts settling greater than 12 months are included in deferred charges and other assets.



Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Natural Gas Swaps 15,514 2007-2008 7.60 (8)
15,514 2008-2010 7.60 (9)
---------------
(17)
---------------
---------------


Trading Activities

Crude oil and natural gas

We enter into physical purchase and sales contracts as well as financial commodity contracts to enhance our price realizations and lock in our margins. The physical and financial commodity contracts (derivative contracts) are stated at fair value. The $138 million fair value of the derivative contracts at September 30, 2007 is included in the Unaudited Consolidated Balance Sheet and any change is included in marketing and other in the Unaudited Consolidated Statement of Income.

Future sale of gas inventory

In an attempt to mitigate the exposure to fluctuations in cash flow from changes in the price of natural gas we have certain NYMEX futures contracts and swaps in place, which effectively lock in our margins on the future sale of our natural gas inventory in storage. From time to time we have designated, in writing, some of these derivative contracts as cash flow hedges of the future sale of our storage inventory.

With the adoption of Section 3865 Hedges as described in Note 1, the effective portion of gains and losses relating to cash flow hedges are now included in other comprehensive income until the gains or losses are realized in net income. Prior to the adoption of Section 3865, gains and losses related to derivatives classified as cash flow hedges were unrecognized.

At December 31, 2006, we held NYMEX natural gas futures contracts and swaps that were designated as cash flow hedges on the future sale of natural gas inventory. On adoption of Section 3865, the fair value of $25 million related to these cash flow hedges was recognized in accounts receivable on January 1, 2007. The fair value gain of $16 million, net of income taxes, was included with the opening balance of accumulated other comprehensive income (AOCI). During the first quarter of 2007, the inventory was sold and as a result, gains on these cash flow hedges were recognized in marketing and other in the Unaudited Consolidated Statement of Income.

In late 2006, we de-designated certain futures contracts that had been designated as cash flow hedges of future sales of our natural gas in storage. These contracts were de-designated since it became uncertain that the future sales of natural gas would occur within the designated time frame. As it was reasonably possible that the future sales could have taken place as designated at the inception of the hedging relationship, gains of $65 million on the futures contracts were deferred in accounts payable at December 31, 2006. The adoption of Section 3865 required that the deferred gains ($45 million, net of income taxes) be reclassified to AOCI on January 1, 2007. The gains were recognized in marketing and other in the Unaudited Consolidated Statement of Income during the first quarter of 2007.

At September 30, 2007, there were no cash flow hedges in place.

(c) Foreign currency exchange rate risk management

Non-Trading Activities

US dollar call options - Canexus

The operations of Canexus are exposed to changes in the US-dollar exchange rate as a portion of their sales are denominated in US dollars and they periodically purchase financial contracts to reduce this exposure. During the quarter, Canexus purchased US-dollar call options, which allows them to sell US$5 million monthly and purchase Canadian dollars at an exchange rate of US$0.95 for the period September 2007 to February 2008. The fair value of these contracts at September 30, 2007 was $1 million. Changes in fair value are included in marketing and other in the Unaudited Consolidated Statement of Income.

Trading Activities

Our sales and purchases of crude oil and natural gas are generally transacted in or referenced to the US dollar, as are most of the financial commodity contracts used by our marketing group. However, we pay for many of our purchases in Canadian dollars. We enter into US-dollar forward contracts and swaps to manage this exposure. Gains and losses on our US-dollar forward contracts and swaps are included in the Unaudited Consolidated Balance Sheet, and any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income. At September 30, 2007, the fair value of our US-dollar forward contracts and swaps was immaterial.

(d) Total carrying value of derivative contracts related to trading activities

Amounts related to derivative instruments held by our marketing operation are equal to fair value as we use mark-to-market accounting. The amounts are as follows:



September 30 December 31
2007 2006
----------------------------------------------------------------------------
Accounts Receivable 329 731
Deferred Charges and Other Assets (1) 172 153
--------------------------------
Total Derivative Contract Assets 501 884
--------------------------------
--------------------------------

Accounts Payable and Accrued Liabilities 268 325
Deferred Credits and Other Liabilities (1) 95 199
--------------------------------
Total Derivative Contract Liabilities 363 524
--------------------------------
--------------------------------

Total Derivative Contract Net Assets (2) 138 360
--------------------------------
--------------------------------

(1) These derivative contracts settle beyond 12 months and are considered
non-current.
(2) Comprised of $138 million (2006 - $372 million) related to commodity
contracts and gains of $nil (2006 - losses of $12 million) related to
US-dollar forward contracts and swaps.


Our exchange-traded derivative contracts are subject to margin deposit requirements. In addition, we may be required to post margin with counterparties in order to satisfy their credit requirements. We have margin deposits of $176 million (December 31, 2006 - $197 million), which have been included in restricted cash and margin deposits on our Unaudited Consolidated Balance Sheet at September 30, 2007.

10. SHAREHOLDERS' EQUITY

Dividends

Dividends per common share for the three months ended September 30, 2007 were $0.025 (2006 - $0.025). Dividends per common share for the nine months ended September 30, 2007 were $0.075 (2006 - $0.075). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.

11. EARNINGS PER COMMON SHARE

Our shareholders approved a split of our issued and outstanding common shares on a two-for-one basis at our annual and special meeting on April 26, 2007. All common share and per common share amounts have been retroactively restated to reflect this share split.

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 Nine Months
Ended September 30 Ended September 30
(millions of shares) 2007 2006 2007 2006
----------------------------------------------------------------------------
Weighted-average number of
common shares outstanding 527.4 524.6 526.8 524.0
Shares issuable pursuant to
tandem options 25.7 27.2 27.0 28.2
Shares to be purchased from
proceeds of tandem options (15.3) (14.2) (15.2) (14.4)
-----------------------------------------------
Weighted-average number of
diluted common shares
outstanding 537.8 537.6 538.6 537.8
-----------------------------------------------
-----------------------------------------------


In calculating the weighted-average number of diluted common shares outstanding for the three and nine months ended September 30, 2007, we excluded 80,000 and 45,445 options respectively, because their exercise price was greater than the average common share market price in those periods. In calculating the weighted-average number of diluted common shares outstanding for the three and nine months ended September 30, 2006, all options were included because their exercise price was less than the average common share market price in those periods. During the periods presented, outstanding tandem options were the only potential dilutive instruments.



12. CASH FLOWS

(a) Charges and credits to income not involving cash

Three Months Nine Months
Ended September 30 Ended September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Depreciation, Depletion,
Amortization and Impairment 349 244 1,043 770
Stock-Based Compensation (106) (68) (132) 44
Future Income Taxes 142 16 303 299
Change in Fair Value of Crude
Oil Put Options 11 5 31 6
Net Income Attributable to
Non-Controlling Interests 7 3 15 12
Other 1 (1) 26 33
-----------------------------------------------
Total 404 199 1,286 1,164
-----------------------------------------------
-----------------------------------------------


(b) Changes in non-cash working capital

Three Months Nine Months
Ended September 30 Ended September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Accounts Receivable 122 (280) 55 557
Inventories and Supplies 200 11 21 (247)
Other Current Assets (29) (50) (18) (29)
Accounts Payable and Accrued
Liabilities (76) 603 (80) (240)
Accrued Interest Payable 3 (16) 14 (18)
-----------------------------------------------
Total 220 268 (8) 23
-----------------------------------------------
-----------------------------------------------

Relating to:
Operating Activities 253 212 (19) (92)
Investing Activities (33) 56 11 115
-----------------------------------------------
Total 220 268 (8) 23
-----------------------------------------------
-----------------------------------------------


(c) Other cash flow information

Three Months Nine Months
Ended September 30 Ended September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Interest Paid 77 87 233 217
Income Taxes Paid 127 109 284 317
-----------------------------------------------

13. MARKETING AND OTHER

Three Months Nine Months
Ended September 30 Ended September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Marketing Revenue, Net 219 229 750 959
Change in Fair Value of Crude
Oil Put Options (11) (5) (31) (6)
Interest 10 8 29 27
Foreign Exchange Losses (11) (1) (54) (49)
Other (1) 19 56 79 158
-----------------------------------------------
Total 226 287 773 1,089
-----------------------------------------------
-----------------------------------------------

(1) Other income for the three and nine months ended September 30, 2006
includes $50 million of business interruption insurance proceeds
relating to production losses caused by Gulf of Mexico Hurricanes in
2005. Other income for the nine months ended September 30, 2006
includes $74 million of business interruption insurance proceeds
relating to generator failures in 2005 at our UK oil and gas
operations.


14. COMMITMENTS, CONTINGENCIES AND GUARANTEES

As described in Note 15 to the Audited Consolidated Financial Statements included in our 2006 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.

15. 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 2006 Annual Report on Form 10-K.



Three months ended September 30, 2007

Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------------
Net Sales 280 101 137 608 42
Marketing and Other 2 - 1 7 -
----------------------------------------------------
Total Revenues 282 101 138 615 42
Less: Expenses
Operating 43 49 21 50 2
Depreciation,
Depletion,
Amortization and
Impairment 54 41 66 151 2
Transportation and
Other 2 5 - - -
General and
Administrative (3) (7) (10) 5 (2) (3)
Exploration - 4 33 12 18(4)
Interest - - - - -
----------------------------------------------------
Income (Loss)
before Income Taxes 190 12 13 404 23
Less: Provision for
(Recovery of) Income
Taxes 63(5) 4 4 206 (3)
Less: Non-Controlling
Interests - - - - -
----------------------------------------------------
Net Income (Loss) 127 8 9 198 26
----------------------------------------------------
----------------------------------------------------

Identifiable Assets 378 4,961(6) 1,786 4,616 272
----------------------------------------------------
----------------------------------------------------

Capital Expenditures
Development and Other 32 304 98 136 20
Exploration 1 42 90 31 6
Proved Property
Acquisitions - - 104(8) - -
----------------------------------------------------
33 346 292 167 26
----------------------------------------------------
----------------------------------------------------

Property, Plant and Equipment
Cost 2,148 6,265 2,921 4,576 243
Less: Accumulated DD&A 1,930 1,560 1,349 746 75
----------------------------------------------------
Net Book Value 218 4,705(6) 1,572 3,830 168
----------------------------------------------------
----------------------------------------------------


Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------

Net Sales 13 160 105 - 1,446
Marketing and Other 219 - 9 (12)(2) 226
----------------------------------------------------
Total Revenues 232 160 114 (12) 1,672
Less: Expenses
Operating 7 53 58 - 283
Depreciation,
Depletion,
Amortization and
Impairment 3 14 11 7 349
Transportation and
Other 211 4 10 6 238
General and
Administrative (3) 15 1 7 1 7
Exploration - - - - 67
Interest - - 3 37 40
----------------------------------------------------
Income (Loss)
before Income Taxes (4) 88 25 (63) 688
Less: Provision for
(Recovery of) Income
Taxes (1) 26 8 (29) 278
Less: Non-Controlling
Interests - - 7 - 7
----------------------------------------------------
Net Income (Loss) (3) 62 10 (34) 403
----------------------------------------------------
----------------------------------------------------

Identifiable Assets 2,983(7) 1,190 470 215 16,871
----------------------------------------------------
----------------------------------------------------

Capital Expenditures
Development and
Other 1 12 13 11 627
Exploration - - - - 170
Proved Property
Acquisitions - - - - 104
----------------------------------------------------
1 12 13 11 901
----------------------------------------------------
----------------------------------------------------

Property, Plant and Equipment
Cost 230 1,324 809 314 18,830
Less: Accumulated
DD&A 54 209 452 164 6,539
----------------------------------------------------
Net Book Value 176 1,115 357 150 12,291
----------------------------------------------------
----------------------------------------------------

(1) Includes results of operations from producing activities in Colombia.

(2) Includes interest income of $10 million, foreign exchange losses of $11
million and decrease in the fair value of crude oil put options of $11
million.

(3) Includes recovery of stock-based compensation of $77 million.

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

(5) Includes Yemen cash taxes of $65 million.

(6) Includes costs of $2,533 million related to our Long Lake project, which
are not being depreciated, depleted or amortized.

(7) Approximately 77% of Marketing's identifiable assets are accounts
receivable and inventories.

(8) Includes acquisition of producing properties in the Gulf of Mexico.

Nine months ended September 30, 2007

Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------------
Net Sales 811 329 453 1,544 106
Marketing and Other 8 4 1 35 -
----------------------------------------------------------------------------
Total Revenues 819 333 454 1,579 106
Less: Expenses
Operating 127 130 75 156 6
Depreciation,
Depletion,
Amortization and
Impairment 176 123 212 423 8
Transportation and
Other 6 18 - - -
General and
Administrative (3) (10) 30 19 - 22
Exploration 5 18 95 50 53(4)
Interest - - - - -
----------------------------------------------------
Income (Loss)
before Income Taxes 515 14 53 950 17
Less: Provision for
(Recovery of) Income
Taxes 176(5) 4 18 490 4
Less: Non-Controlling
Interests - - - - -
----------------------------------------------------

Net Income (Loss) 339 10 35 460 13
----------------------------------------------------
----------------------------------------------------

Identifiable Assets 378 4,961(6) 1,786 4,616 272
----------------------------------------------------
----------------------------------------------------

Capital Expenditures
Development and Other 95 976 365 434 35
Exploration 11 87 153 94 32
Proved Property
Acquisitions - - 104(8) 46(9) -
----------------------------------------------------
106 1,063 622 574 67
----------------------------------------------------
----------------------------------------------------

Property, Plant and
Equipment
Cost 2,148 6,265 2,921 4,576 243
Less: Accumulated DD&A 1,930 1,560 1,349 746 75
----------------------------------------------------
Net Book Value 218 4,705(6) 1,572 3,830 168
----------------------------------------------------
----------------------------------------------------

Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------

Net Sales 36 394 312 - 3,985
Marketing and Other 750 - 31 (56)(2) 773
----------------------------------------------------
Total Revenues 786 394 343 (56) 4,758
Less: Expenses
Operating 26 151 191 - 862
Depreciation,
Depletion,
Amortization and
Impairment 10 39 33 19 1,043
Transportation and
Other 620 13 29 8 694
General and
Administrative (3) 68 1 24 93 247
Exploration - - - - 221
Interest - - 9 125 134
----------------------------------------------------
Income (Loss)
before Income Taxes 62 190 57 (301) 1,557
Less: Provision for
(Recovery of) Income
Taxes 25 56 17 (140) 650
Less: Non-Controlling
Interests - - 15 - 15
----------------------------------------------------
Net Income (Loss) 37 134 25 (161) 892
----------------------------------------------------
----------------------------------------------------

Identifiable Assets 2,983(7) 1,190 470 215 16,871
----------------------------------------------------
----------------------------------------------------

Capital Expenditures
Development and
Other 2 27 39 31 2,004
Exploration - - - - 377
Proved Property
Acquisitions - - - - 150
----------------------------------------------------
2 27 39 31 2,531
----------------------------------------------------
----------------------------------------------------

Property, Plant and Equipment
Cost 230 1,324 809 314 18,830
Less: Accumulated
DD&A 54 209 452 164 6,539
----------------------------------------------------
Net Book Value 176 1,115 357 150 12,291
----------------------------------------------------
----------------------------------------------------

(1) Includes results of operations from producing activities in Colombia.

(2) Includes interest income of $29 million, foreign exchange losses of $54
million and decrease in the fair value of crude oil put options of $31
million.

(3) Includes recovery of stock-based compensation of $16 million.

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

(5) Includes Yemen cash taxes of $174 million.

(6) Includes costs of $2,533 million related to our Long Lake project, which
are not being depreciated, depleted or amortized.

(7) Approximately 77% of Marketing's identifiable assets are accounts
receivable and inventories.

(8) Includes acquisition of producing properties in the Gulf of Mexico.

(9) Includes acquisition of additional interests in the Scott and Telford
fields.


Three months ended September 30, 2006

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

Net Sales 337 118 154 104 41
Marketing and Other 2 1 51(2) 2 -
------------------------------------------------
Total Revenues 339 119 205 106 41
Less: Expenses
Operating 36 35 27 21 2
Depreciation, Depletion,
Amortization and
Impairment 80 40 51 43 3
Transportation and Other 1 11 - - -
General and
Administrative(4) (3) 5 (1) - 5
Exploration 1 4 63 5 9(6)
Interest - - - - -
------------------------------------------------
Income (Loss)
before Income Taxes 224 24 65 37 22
Less: Provision for
(Recovery of) Income Taxes 78(7) 8 22 9 8
Less: Non-Controlling
Interests - - - - -
------------------------------------------------
Net Income (Loss) 146 16 43 28 14
------------------------------------------------
------------------------------------------------

Identifiable Assets 539 3,601 1,539 5,029 185
------------------------------------------------
------------------------------------------------

Capital Expenditures
Development and Other 35 362 131 131 7
Exploration 13 89 43 10 6
Proved Property
Acquisitions - 9 - - -
------------------------------------------------
48 460 174 141 13
------------------------------------------------
------------------------------------------------

Property, Plant and Equipment
Cost 2,282 4,825 2,646 4,292 210
Less: Accumulated DD&A 2,003 1,403 1,243 358 73
------------------------------------------------
Net Book Value 279 3,422 1,403 3,934 137
------------------------------------------------
------------------------------------------------

Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------

Net Sales 12 130 101 - 997
Marketing and Other 229 - - 2(3) 287
------------------------------------------------
Total Revenues 241 130 101 2 1,284
Less: Expenses
Operating 6 42 60 - 229
Depreciation, Depletion,
Amortization and
Impairment 2 8 10 7 244
Transportation and Other 173 3 11 134(5) 333
General and
Administrative(4) 18 - 7 20 51
Exploration - - - - 82
Interest - - 3 12 15
------------------------------------------------
Income (Loss)
before Income Taxes 42 77 10 (171) 330
Less: Provision for
(Recovery of) Income Taxes 12 25 3 (37) 128
Less: Non-Controlling
Interests - - 3 - 3
------------------------------------------------
Net Income (Loss) 30 52 4 (134) 199
------------------------------------------------
------------------------------------------------

Identifiable Assets 3,030(8) 1,199 461 312 15,895
------------------------------------------------
------------------------------------------------

Capital Expenditures
Development and Other 9 17 4 13 709
Exploration - - - - 161
Proved Property
Acquisitions - - - - 9
------------------------------------------------
9 17 4 13 879
------------------------------------------------
------------------------------------------------

Property, Plant and Equipment
Cost 219 1,306 836 276 16,892
Less: Accumulated DD&A 44 179 483 144 5,930
------------------------------------------------
Net Book Value 175 1,127 353 132 10,962
------------------------------------------------
------------------------------------------------

(1) Includes results of operations from producing activities in Colombia.

(2) Includes $50 million of business interruption insurance proceeds
related to production losses caused by Gulf of Mexico hurricanes in
2005.

(3) Includes interest income of $8 million, foreign exchange losses of
$1 million and decrease in the fair value of crude oil put options of
$5 million.

(4) Includes stock-based compensation expense recovery of $23 million.

(5) Includes $134 million accrual with respect to the Block 51
arbitration.

(6) Includes exploration activities primarily in Nigeria and Colombia.

(7) Includes Yemen cash taxes of $76 million.

(8) Approximately 85% of Marketing's identifiable assets are accounts
receivable and inventories.


Nine months ended September 30, 2006

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

Net Sales 1,029 351 496 372 108
Marketing and Other 6 7 51(2) 81(3) 1
------------------------------------------------
Total Revenues 1,035 358 547 453 109
Less: Expenses
Operating 110 103 79 63 5
Depreciation, Depletion,
Amortization and
Impairment 248 115 155 168 8
Transportation and Other 4 22 - - -
General and
Administrative(6) 11 56 44 6 30
Exploration 1 18 140 33 39(7)
Interest - - - - -
------------------------------------------------
Income (Loss)
before Income Taxes 661 44 129 183 27
Less: Provision for
(Recovery of) Income Taxes 231(8) (18) 44 333(9) 10
Less: Non-Controlling
Interests - - - - -
------------------------------------------------
Net Income (Loss) 430 62 85 (150) 17
------------------------------------------------
------------------------------------------------

Identifiable Assets 539 3,601 1,539 5,029 185
------------------------------------------------
------------------------------------------------

Capital Expenditures
Development and Other 110 996 275 410 20
Exploration 28 206 155 35 21
Proved Property
Acquisitions - 11 - 1 -
------------------------------------------------
138 1,213 430 446 41
------------------------------------------------
------------------------------------------------

Property, Plant and Equipment
Cost 2,282 4,825 2,646 4,292 210
Less: Accumulated DD&A 2,003 1,403 1,243 358 73
------------------------------------------------
Net Book Value 279 3,422 1,403 3,934 137
------------------------------------------------
------------------------------------------------


Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------

Net Sales 26 328 306 - 3,016
Marketing and Other 959 - 12 (28)(4) 1,089
------------------------------------------------
Total Revenues 985 328 318 (28) 4,105
Less: Expenses
Operating 18 139 185 - 702
Depreciation, Depletion,
Amortization and
Impairment 6 19 30 21 770
Transportation and Other 591 14 31 134(5) 796
General and
Administrative(6) 93 - 20 119 379
Exploration - - - - 231
Interest - - 8 27 35
------------------------------------------------
Income (Loss)
before Income Taxes 277 156 44 (329) 1,192
Less: Provision for
(Recovery of) Income Taxes 113 51 14 (122) 656
Less: Non-Controlling
Interests - - 12 - 12
------------------------------------------------
Net Income (Loss) 164 105 18 (207) 524
------------------------------------------------
------------------------------------------------

Identifiable Assets 3,030(10) 1,199 461 312 15,895
------------------------------------------------
------------------------------------------------

Capital Expenditures
Development and Other 44 74 14 30 1,973
Exploration - - - - 445
Proved Property
Acquisitions - - - - 12
------------------------------------------------
44 74 14 30 2,430
------------------------------------------------
------------------------------------------------

Property, Plant and Equipment
Cost 219 1,306 836 276 16,892
Less: Accumulated DD&A 44 179 483 144 5,930
------------------------------------------------
Net Book Value 175 1,127 353 132 10,962
------------------------------------------------
------------------------------------------------

(1) Includes results of operations from producing activities in Colombia.

(2) Includes $50 million of business interruption insurance proceeds
related to production losses caused by Gulf of Mexico hurricanes in
2005.

(3) Includes proceeds of $74 million from business interruption insurance
claims for generator failures in 2005 at our UK oil and gas operations.

(4) Includes interest income of $27 million, foreign exchange losses of
$49 million and decrease in the fair value of crude oil put options
of $6 million.

(5) Includes $134 million accrual with respect to the Block 51 arbitration.

(6) Includes stock-based compensation expense of $133 million.

(7) Includes exploration activities primarily in Nigeria and Colombia.

(8) Includes Yemen cash taxes of $224 million.

(9) Includes future income tax expense of $277 million related to an
increase in the supplemental tax rate on oil and gas activities in the
United Kingdom.

(10) Approximately 85% of Marketing's identifiable assets are accounts
receivable and inventories.


16. 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 Nine Months ended September 30

Three Nine
Months Ended Months Ended
September 30, September 30,
(Cdn$ millions, except per share amounts) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,446 997 3,985 3,016
Marketing and Other (i) 226 298 771 1,111
-----------------------------------
1,672 1,295 4,756 4,127
-----------------------------------
Expenses
Operating (ii) 292 231 884 708
Depreciation, Depletion, Amortization
and Impairment 349 244 1,043 770
Transportation and Other 238 333 694 796
General and Administrative (iv) 18 69 268 412
Exploration 67 82 221 231
Interest 40 15 134 35
-----------------------------------
1,004 974 3,244 2,952
-----------------------------------

Income before Income Taxes 668 321 1,512 1,175
-----------------------------------
Provision for Income Taxes
Current 136 112 347 357
Deferred (i) - (iv) 137 290 290 294
-----------------------------------
273 402 637 651
-----------------------------------
Net Income (Loss) before Non-Controlling
Interests 395 (81) 875 524
Less: Net Income Attributable to
Non-Controlling Interests (7) (3) (15) (12)
-----------------------------------

Net Income (Loss) - US GAAP (1) 388 (84) 860 512
-----------------------------------
-----------------------------------
Earnings (Loss) Per Common Share
($/share)
Basic (Note 11) 0.74 (0.16) 1.63 0.98
-----------------------------------
-----------------------------------
Diluted (Note 11) 0.72 (0.16) 1.60 0.95
-----------------------------------
-----------------------------------

(1) Reconciliation of Canadian and US GAAP Net Income


Three Nine
Months Ended Months Ended
September 30, September 30,
2007 2006 2007 2006
----------------------------------------------------------------------------
Net Income - Canadian GAAP 403 199 892 524
Impact of US Principles, Net of
Income Taxes:
Ineffective Portion of Cash Flow
Hedges (i) - 7 (2) 14
Pre-operating Costs (ii) (7) (1) (15) (4)
Deferred Income Taxes (iii) - (277) - -
Liability-based Stock Compensation
Plans (iv) (8) (12) (15) (22)
------------------------------------
Net Income (Loss) - US GAAP 388 (84) 860 512
-----------------------------------
-----------------------------------

(b) Unaudited Consolidated Balance Sheet -- US GAAP

September 30 December 31
(Cdn$ millions, except share amounts) 2007 2006
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 172 101
Restricted Cash and Margin Deposits 176 197
Accounts Receivable 2,683 2,976
Inventories and Supplies 628 786
Deferred Income Tax Asset 73 479
Other 77 67
-----------------------------------
Total Current Assets 3,809 4,606
-----------------------------------

Property, Plant and Equipment
Net of Accumulated Depreciation,
Depletion, Amortization and Impairment
of $6,932 (December 31, 2006 - $6,792)
(ii); (vi) 12,222 11,692
Deferred Income Tax Assets 167 141
Deferred Charges and Other Assets 276 263
Goodwill 328 377
-----------------------------------
Total Assets 16,802 17,079
-----------------------------------
-----------------------------------
Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Borrowings - 158
Accounts Payable and Accrued
Liabilities (iv) 3,454 3,839
Accrued Interest Payable 67 55
Dividends Payable 13 13
-----------------------------------
Total Current Liabilities 3,534 4,065
-----------------------------------

Long-Term Debt 4,565 4,618
Deferred Income Tax Liabilities (i) - (vi) 2,178 2,427
Asset Retirement Obligations 701 683
Deferred Credits and Liabilities (v) 477 597
Non-Controlling Interests 75 75
Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2007 - 527,429,968 shares
2006 - 525,026,412 shares 891 821
Contributed Surplus 3 4
Retained Earnings (i) - (vi) 4,738 3,945
Accumulated Other Comprehensive
Income (i); (v) (360) (156)
-----------------------------------
Total Shareholders' Equity 5,272 4,614
-----------------------------------
Commitments, Contingencies and Guarantees

Total Liabilities and Shareholders' Equity 16,802 17,079
-----------------------------------
-----------------------------------

(c) Unaudited Consolidated Statement of Comprehensive Income -- US GAAP
For the Three and Nine Months Ended September 30

Three Nine
Months Ended Months Ended
September 30, September 30,
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net Income (Loss) - US GAAP 388 (84) 860 512
Other Comprehensive Income, Net of
Income Taxes:
Foreign Currency Translation Adjustment (51) (6) (143) (71)
Change in Mark to Market on Cash Flow
Hedges (i) - 46 (61) 66
-----------------------------------
Comprehensive Income (Loss) 337 (44) 656 507
-----------------------------------
-----------------------------------

(d) Unaudited Consolidated Statement of Accumulated Other Comprehensive
Income - US GAAP

September 30 December 31
(Cdn$ millions) 2007 2006
----------------------------------------------------------------------------
Foreign Currency Translation Adjustment (304) (161)
Mark to Market on Cash Flow Hedges (i) - 61
Unamortized Defined Benefit Pension Costs (v) (56) (56)
-----------------------------------
(360) (156)
-----------------------------------
-----------------------------------


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.

Cash flow hedges

Changes in the fair value of derivatives that are designated as cash flow hedges are recognized in earnings in the same period as the hedged item. Any fair value change in a derivative before that period is recognized on the balance sheet. The effective portion of that change is recognized in other comprehensive income with any ineffectiveness recognized in net income during the period of change.

Future sale of gas inventory: At December 31, 2006, accounts receivable includes gains of $25 million on futures contracts and swaps we used to hedge commodity price risk on the future sale of our gas inventory. Gains of $23 million ($16 million, net of income taxes) related to the effective portion and deferred in AOCI at December 31, 2006, were recognized in marketing and other in the first quarter of 2007. The ineffective portion of the gains of $2 million ($2 million, net of income taxes) was recognized in marketing and other in 2006 under US GAAP. Under Canadian GAAP, the ineffective portion was recognized in net income in the first quarter of 2007.

Our US GAAP net income for the nine months ended September 30, 2006 includes $22 million of gains ($14 million, net of income taxes) relating to the ineffective portion of cash flow hedges.

Also included in AOCI at December 31, 2006 are gains of $65 million ($45 million, net of income taxes) related to de-designated cash flow hedges. These gains were recognized in marketing and other in the first quarter of 2007. Under Canadian GAAP, these deferred gains are included in accounts payable and accrued liabilities at December 31, 2006 and have been recognized in marketing and other income in the first quarter of 2007.

At September 30, 2007, there were no cash flow hedges in place.

Fair value hedges

Both the derivative instrument and the underlying commitment are recognized on the balance sheet at their fair value. The change in fair value of both is reflected in earnings. At September 30, 2007 and at December 31, 2006, we had no fair value 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 $9 million and $22 million for the three and nine months ended September 30, 2007, respectively ($7 million and $15 million, respectively, net of income taxes) (2006 - $2 million and $6 million, respectively ($1 million and $4 million, respectively, net of income taxes)); and

- property, plant and equipment is lower under US GAAP by $50 million (December 31, 2006 - $28 million).

iii. Under US GAAP, enacted tax rates are used to calculate deferred income taxes, whereas under Canadian GAAP, substantively enacted rates are used. During the first quarter of 2006, the UK government substantively enacted increases to the supplementary tax on oil and gas activities from 10% to 20%, effective January 1, 2006. This created a $277 million future income tax expense during the first quarter of 2006 under Canadian GAAP. During the third quarter of 2006, the UK government enacted the revised tax rates and we recognized the $277 million deferred income tax expense in our US GAAP net income for the three months ended September 30, 2006.

iv. Under Canadian principles, we record obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. Under US principles, obligations for liability-based stock compensation plans are recorded using the fair-value method of accounting. 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:

- general and administrative expense is higher by $11 million and $21 million for the three and nine months ended September 30, 2007, respectively ($8 million and $15 million, respectively, net of income taxes) (2006 - higher by $18 million and $33 million, respectively ($12 million and $22 million, respectively, net of income taxes)); and

- accounts payable and accrued liabilities are higher by $46 million as at September 30, 2007 (December 31, 2006 - $25 million).

v. On December 31, 2006, we adopted FASB Statement 158 Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans (FAS 158). At September 30, 2007, the unfunded amount of our defined benefit pension plans was $81 million. This amount has been included in deferred credits and other liabilities and $56 million, net of income taxes has been included in AOCI. Prior to the adoption of FAS 158 on December 31, 2006, we included our minimum unfunded pension liability in deferred credits and other liabilities and in AOCI.

vi. 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.

Stock-based Compensation Expense for Retired and Retirement-Eligible Employees

Under US GAAP, we recognize stock-based compensation expense for our retired and retirement-eligible employees over an accelerated vesting period in accordance with the provisions of Statement 123® for stock-based awards granted to employees on or after January 1, 2006. For stock-based awards granted prior to the adoption of Statement 123®, stock-based compensation expense for our retired and retirement-eligible employees is recognized over a graded vesting period. If we applied the accelerated vesting provisions of Statement 123® to stock-based awards granted to our retired and retirement-eligible employees prior to the adoption of Statement 123®, there would be no material change to our stock-based compensation expense for the three and nine months ended September 30, 2007 and 2006.

CHANGES IN ACCOUNTING POLICIES - US GAAP

Income Taxes

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 September 30, 2007, the total amount of our unrecognized tax benefits was approximately $210 million, all of which, if recognized, would affect our effective tax rate. As at September 30, 2007, 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 $10 million. We had no interest or penalties in the US GAAP - Unaudited Consolidated Statement of Income for the first nine months of 2007. Our income tax filings are subject to audit by taxation authorities and as at September 30, 2007 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.

NEW US ACCOUNTING PRONOUNCEMENTS

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement 157, Fair Value Measurements. Statement 157 defines fair value, establishes a framework for measuring fair value under US generally accepted accounting principles and expands disclosures about fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position.

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 to have a material impact on our results of operations or financial position.

In February 2007, FASB issued Statement 159, The Fair Value Option for Financial Assets and Financial Liabilities. The statement allows for the elective measurement of eligible financial instruments and certain other items at fair value in order to mitigate volatility in reported earnings without having to apply complex and detailed hedge accounting rules. This statement is effective for fiscal years beginning after November 15, 2007. 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
    Sean Noe, P.Eng
    Analyst, Investor Relations
    (403) 699-4494
    or
    Nexen Inc.
    801 - 7th Ave SW
    Calgary, Alberta, Canada T2P 3P7
    Website: www.nexeninc.com