Nexen Inc.
TSX : NXY
NYSE : NXY

Nexen Inc.

April 26, 2007 06:30 ET

Nexen Reports First Quarter Results-2007 Production Growth on Track

CALGARY, ALBERTA--(CCNMatthews - April 26, 2007) -

First Quarter Highlights:

- Production after royalties increases almost 20% over Q4 2006 to 191,000 boe/d (238,000 boe/d before royalties)--on track for approximately 50% growth in 2007

- Buzzard ramping up--production expected to reach peak rates of 85,000 boe/d net by mid year

- Steam injection begins at Long Lake--project on track for bitumen production in Q3 and upgrader start up late in the year; capital costs projected to increase

- Cash flow of $2.27 per share; earnings of $0.46 per share

- Ettrick development progressing well--expected to be on stream in mid 2008

- Exploration successes at Golden Eagle and Kildare in the UK North Sea



Three Months Three Months
Ended Ended
March 31 December 31
-------------- --------------
(Cdn$ millions) 2007 2006 2006
----------------------------------------------------------------------------
Production (mboe/d)(1)
Before Royalties 238 222 207
After Royalties 191 159 161
Net Sales 1,140 980 920
Cash Flow from Operations(2) 598 673 673
Per Common Share ($/share)(2) 2.27 2.57 2.56
Net Income (Loss) 121 (83) 77
Per Common Share ($/share) 0.46 (0.32) 0.29
Capital Investment, including Acquisitions 811 753 900
----------------------------------------------------------------------------

(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. 7.


Nexen delivered solid financial results in the first quarter with cash flow of $598 million and net income of $121 million. These results reflect increased production, strong commodity prices and narrow product differentials. With Buzzard ramping up during the quarter, our production after royalties increased 20% year over year. Net income is up significantly as we reported a $277 million charge for an increase in the UK tax rate in the first quarter of 2006.

The contribution from our marketing group was substantially lower than reported last year. Economically our marketing division added value for the quarter, however for accounting purposes they broke even. We were unable to recognize gains on the increased value of our marketing inventories and transportation assets. These can only be recognized when the inventories are sold and the transportation assets are used. We expect to recognize these gains over the next 12 months. In the first quarter of 2006, marketing contributed $108 million after tax to our earnings as they took advantage of volatile gas markets in late 2005.

Since the beginning of the year, our share price has increased 10%, adding almost $2 billion in shareholder value. Our employees shared in approximately 7% of this additional value as we recognized $116 million ($80 million after tax, $0.30/share) of stock-based compensation expense during the quarter. Approximately 60% of this expense was cash related.

"We made good progress on our major development projects during the first quarter," commented Charlie Fischer, Nexen's President and Chief Executive Officer. "We recently started injecting steam at Long Lake and Buzzard is ramping up as expected. Over the coming months, production will continue to rise creating significant growth and value for our shareholders."



Oil and Gas Production

Production before Production after
Royalties Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) Q1 2007 Q4 2006 Q1 2007 Q4 2006
--------------------------------------------------------- ------------------
Yemen 77 84 45 52
North Sea 58 24 58 24
Canada 38 38 30 31
United States 38 33 34 28
Other Countries 6 6 5 6
Syncrude 21 22 19 20
------------------ ------------------
Total 238 207 191 161
------------------ ------------------


Our first quarter production averaged 238,000 boe/d (191,000 boe/d after royalties) as the Buzzard field in the North Sea came on stream in early January. Buzzard is ramping up as expected and contributed 36,000 boe/d to our quarterly volumes. We are starting to see daily rates in excess of 162,000 boe (70,000 boe net) and are on track to achieve peak rates of 200,000 boe/d (85,000 boe/d net) by mid year.

"We are currently producing approximately 260,000 boe/d," stated Fischer. "As Buzzard ramps up to peak rates over the next few months and Long Lake comes on stream in the second half of the year, we are on track to grow production after royalties by 50% this year."

Long Lake Project Update

Our Long Lake project achieved a major milestone as we began injecting steam into two of our 10 well pads in April. Over the next several months we will continue to circulate steam into the injection and producing wells to heat up the reservoir and establish communication between the wells. Our plan is to commission a new pad (3 to 12 well pairs per pad) at a rate of one pad per week until all wells are circulating steam. We expect all 81 SAGD well pairs (10 pads) to be circulating steam by the end of the second quarter.

Bitumen production is expected to be minimal until the third quarter when we convert the wells to SAGD operation. During the initial ramp up period, we expect steam-to-oil ratios will be high from initial steam circulation and will decline with time as bitumen production ramps up to peak rates over a 12 to 24 month period. Over the project life, we expect our steam-to-oil ratio to average approximately 3.0. Depending on production ramp up and new facility uptime, we expect bitumen production to reach between 35,000 and 45,000 bbls/d (between 17,500 and 22,500 bbls/d net) by the end of 2007.

Upgrader module fabrication is now complete, all modules are on site and construction of the upgrader is approximately 85% complete. Peak output of premium synthetic crude oil is expected within 18 months of upgrader start up and we expect to exit 2007 producing between 28,000 and 36,000 bbls/d (between 14,000 and 18,000 bbls/d net) of synthetic crude. Production capacity for the first phase of Long Lake is approximately 60,000 bbls/d (30,000 bbls/d net to Nexen) of premium synthetic crude which we expect to reach by late 2008 or early 2009.

The current commodity price environment is fueling the high rate of oil sands activity. This is resulting in unprecedented demand for supplies and services in the Athabasca region, causing inflationary pressure on costs. In addition, skilled labour shortages are affecting productivity. These pressures are impacting our Long Lake project. It has taken additional hours to complete the SAGD central processing facility and system turnover to operations has taken longer than anticipated. On the upgrader, progress and productivity has been less than expected on the sulphur and air separation plants, putting pressure on both cost and schedule. After a review of all trends, the projected cost of Long Lake has increased from $4.6 billion to approximately $5 billion ($2.5 billion net to Nexen). In addition, a contingency reserve of $300 million ($150 million net to Nexen) has been created for cost and productivity pressures over and above current trends.

"The cost increase is disappointing," stated Fischer. "However, the real value of the project lies in the production of synthetic crude oil for decades, where we enjoy an estimated $10/bbl operating cost advantage over existing technologies."

We are planning to increase synthetic crude oil production to 240,000 bbls/d (120,000 bbls/d net) over the next decade. We plan to sequentially develop our 5.5 billion barrel recoverable resource with additional 60,000 bbls/d (30,000 bbls/d net) phases using the same technology and design as Long Lake. This process significantly reduces our need to purchase natural gas, a key cost driver in competing technologies and results in a significant cost advantage for us.

"We are currently investing in Phase 2 development," commented Fischer. "While we are planning on sanctioning this project in 2008, the ultimate timing depends on achieving sufficient production history from Phase 1 and receiving clarity on fiscal and regulatory policies related to oil sands development and climate change."

Ettrick Development Progressing for First Oil in 2008

Development of the Ettrick field in the North Sea where we have an 80% operated working interest is progressing well. The project consists of three production wells and one water injector tied back to a leased floating production, storage and offloading (FPSO) vessel which is almost 60% complete. 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. During the quarter, we began drilling the first development well. Production from the field is expected to commence by mid 2008 with our share averaging approximately 9,000 boe/d for the year.

Gulf of Mexico Update

At Aspen, we began producing from an additional development well in late December. With this well on stream, our production from the field averaged approximately 16,500 boe/d for the first quarter of 2007 compared to 10,400 boe/d a year ago. We have identified other opportunities in the field and we are currently sidetracking Aspen 1 to exploit a number of deeper sands. We expect this well to come on stream mid year. Our 2007 annual production from the Aspen field is expected to average between 15,000 and 20,000 boe/d. We have a 100% operated working interest in Aspen.

In May, we anticipate producing from Wrigley on Mississippi Canyon Block 506 where we have a 50% non-operated interest. The well flow tested at 62 mmcf/d (31 mmcf/d net to Nexen) during completion operations.

In 2006, we had discoveries at Alaminos Canyon Block 856 (Great White West) and Ringo on Mississippi Canyon Block 546. We are currently evaluating development options at Great White West. At Ringo we have an appraisal well planned for the fourth quarter. We recently pooled our acreage at Ringo with adjacent Block 502, as we believe the structure is situated on both blocks. We have a 25% non-operated interest in Ringo and Block 502. The operator has renamed this discovery Longhorn.

At Knotty Head, we are moving forward to secure a rig to drill an appraisal well. One of our partners has access to a deep-water drilling rig which they are prepared to make available late this year or early next year. We are currently verifying the rig's capabilities and reviewing contractual arrangements. Our current estimate of resource for the field is between 200 and 500 mmboe. We have a 25% operated interest in the field.

Coalbed Methane (CBM) Development Continues

In Canada, we continue to develop CBM from Mannville coals in the Fort Assiniboine area. Well performance continues to meet expectations, however capital spending has been less than planned due to partner constraints. We are taking action as permitted by our agreements to mitigate these constraints and move ahead with the capital program. Our production from this area averaged 21 mmcf/d for the quarter. We expect this to double by year-end and continue to grow as we develop additional sections of land in the Corbett, Thunder and Doris fields using multiple leg-horizontal wells.

"Although our current capital program has been constrained, we are committed to the development of CBM," said Fischer. "Well performance is in line with expectations and we are confident in our plan to increase our CBM production to at least 150 mmcf/d by 2011."

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 floating production, storage and offloading vessel (FPSO) with a two million barrel storage capacity. Recommendations have been prepared for award of the major deep-water facilities and drilling contracts, subject to final government and partner approval to proceed. These contracts provide for fabrication and integration of a portion of these facilities within Nigeria, reflecting the project's support of local content initiatives established by the Nigerian government. We expect the Usan development to be formally sanctioned this year, with first production as early as 2010. We have a 20% interest in exploration and development on this block.

Drilling Update--Successes in the UK North Sea

During the quarter, we had successes in the UK North Sea at Golden Eagle and Kildare. Golden Eagle is located on Block 20/1N. The discovery well was drilled to a depth of approximately 7,500 feet and encountered 123 feet of net pay. A successful sidetrack well was drilled to appraise the accumulation and we are currently evaluating development options. Our current estimate of gross resource for the field is between 20 and 50 mmboe. We have a 34% operated interest in Golden Eagle. Kildare is located on Block 15/26b. The discovery well was drilled to a depth of approximately 14,100 feet and encountered approximately 91 feet of net pay. We are currently analyzing the results from the well. We have a 50% non-operated interest in Kildare.

We are currently drilling two exploration wells. For the remainder of the year, we expect to drill an additional 12 to 15 exploration wells with the majority in the Gulf of Mexico and the UK North Sea. We have rigs lined up for all but one of these wells.

"This is a landmark year for Nexen as we expect our production to grow substantially," commented Fischer. "However the growth does not stop there. Projects like Ettrick in the UK, Usan, offshore West Africa, Knotty Head in the Gulf of Mexico, CBM and additional phases of Long Lake in Canada will ensure production growth into the future."

Two-for-One Share Split

At our annual meeting today, we expect our shareholders to approve our previously announced two-for-one share split. Following the share split, we will have approximately 526 million common shares outstanding.

Quarterly Dividend

The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable July 1, 2007, to shareholders of record on June 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 Marvin Romanow, Executive
Vice-President and CFO, will host a conference call to discuss our
financial and operating results and expectations for the future.

Date: April 26, 2007
Time: 12:30 p.m. Mountain Time (2:30 p.m. Eastern Time)

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

416-340-8010 (Toronto)
866-540-8136 (North American toll-free)
800-8989-6323 (Global toll-free)

A replay of the call will be available for two weeks starting at 2:30
p.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053
(toll-free) passcode 3220058 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 "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, West Africa projects 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; the ability to explore, develop, produce and transport crude oil and natural gas to markets; the results of exploration and development drilling and related activities; foreign-currency exchange rates; economic conditions in the countries and regions where Nexen carries on business; actions by governmental authorities including increases in 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 groups, including conflict between states. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors, and management's course of action would depend on its assessment of the future considering all information then available. Any statements as to possible future 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, 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
Ended March 31
(Cdn$ millions) 2007 2006
----------------------------------------------------------------------------
Net Sales 1,140 980
Cash Flow from Operations 598 673
Per Common Share ($/share) 2.27 2.57
Net Income (Loss) 121 (83)
Per Common Share ($/share) 0.46 (0.32)
Capital Investment, including Acquisitions (1) 811 753
Net Debt (2) 4,939 3,697
Common Shares Outstanding (millions of shares) 263.2 261.7
----------------------------------------------------------------------------

(1) Includes oil and gas development, exploration, and expenditures for
other property, plant and equipment.
(2) Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.


Cash Flow from Operations (1)

Three Months
Ended March 31
(Cdn$ millions) 2007 2006
----------------------------------------------------------------------------
Oil & Gas and Syncrude
Yemen (2) 158 221
Canada 44 54
United States 133 142
United Kingdom 291 113
Other Countries 7 21
Marketing 1 175
Syncrude 67 25
----------------------
701 751
Chemicals 23 22
----------------------
724 773
Interest and Other Corporate Items (110) (58)
Income Taxes (3) (16) (42)
----------------------
Cash Flow from Operations (1) 598 673
----------------------
----------------------

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

Three Months
Ended March 31
(Cdn$ millions) 2007 2006
----------------------------------------------------------------------------
Cash Flow from Operating Activities 448 734
Changes in Non-Cash Working Capital (32) (73)
Other 189 31
Amortization of Premium for Crude Oil Put Options (7) (19)
----------------------
Cash Flow from Operations 598 673
----------------------
----------------------

Weighted-average Number of Common Shares Outstanding
(millions of shares) 263.0 261.6
----------------------
Cash Flow from Operations Per Common Share ($/share) 2.27 2.57
----------------------
----------------------

(2) After in-country cash taxes of $44 million for the three months ended
March 31, 2007 (2006 - $67 million).
(3) Excludes in-country cash taxes in Yemen.


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

Three Months
Ended March 31
2007 2006
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
Yemen 77.1 102.4
Canada 17.8 22.2
United States 21.6 19.3
United Kingdom 55.6 15.7
Other Countries 5.8 5.8
Syncrude (mbbls/d) (2) 21.4 14.8
----------------------
199.3 180.2
----------------------
Natural Gas (mmcf/d)
Canada 118 106
United States 101 120
United Kingdom 14 23
----------------------
233 249
----------------------

Total Production (mboe/d) 238 222
----------------------
----------------------


Production Volumes (after royalties)

Three Months
Ended March 31
2007 2006
Crude Oil and NGLs (mbbls/d)
Yemen 45.0 53.7
Canada 14.2 17.8
United States 19.3 17.0
United Kingdom 55.6 15.7
Other Countries 5.4 5.3
Syncrude (mbbls/d) (2) 18.9 13.4
----------------------
158.4 122.9
----------------------
Natural Gas (mmcf/d)
Canada 95 89
United States 86 102
United Kingdom 14 23
----------------------
195 214
----------------------

Total Production (mboe/d) 191 159
----------------------
----------------------

Notes:
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Considered a mining operation for US reporting purposes.


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

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

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

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

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

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

Price Received ($/bbl) 70.03 69.95 79.50 77.53 63.37 72.32
Royalties & Other 8.26 6.68 7.95 8.54 4.79 6.93
Operating Costs 24.40 40.12 27.84 21.69 24.42 27.53
----------------------------------------------------------------------------
Netback 37.37 23.15 43.71 47.30 34.16 37.86
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 21.6 19.3 17.8 16.7 14.6 17.0
Price Received ($/bbl) 58.49 63.73 70.23 70.23 58.09 65.80
Natural Gas:
Sales (mmcf/d) 101 120 107 105 111 111
Price Received ($/mcf) 8.58 9.06 7.51 7.18 7.56 7.86
Total Sales Volume (mboe/d) 38.4 39.3 35.6 34.1 33.0 35.5

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

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

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

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

Price Received ($/boe) 59.13 61.11 66.78 66.82 56.95 62.92
Royalties & Other 12.26 18.04 18.95 19.25 14.38 17.68
Operating Costs 9.67 8.78 8.21 8.72 9.40 8.77
In-country Taxes 2.05 3.31 4.17 4.08 3.33 3.72
----------------------------------------------------------------------------
Netback 35.15 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 (Loss)
For the Three Months Ended March 31
Cdn$ millions, except per share amounts

2007 2006
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,140 980
Marketing and Other (Note 13) 248 426
----------------------
1,388 1,406
----------------------

Expenses
Operating 290 250
Depreciation, Depletion, Amortization and Impairment 334 266
Transportation and Other 246 260
General and Administrative 202 220
Exploration 49 103
Interest (Note 6) 48 9
----------------------
1,169 1,108
----------------------

Income before Income Taxes 219 298
----------------------

Provision for Income Taxes
Current 60 109
Future 35 269
----------------------
95 378
----------------------

Net Income (Loss) before Non-Controlling Interests 124 (80)
Net Income Attributable to Non-Controlling Interests (3) (3)
----------------------

Net Income (Loss) 121 (83)
----------------------
----------------------

Earnings (Loss) Per Common Share ($/share)
Basic (Note 11) 0.46 (0.32)
----------------------
----------------------

Diluted (Note 11) 0.45 (0.32)
----------------------
----------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Balance Sheet
Cdn$ millions, except share amounts

March 31 December 31
2007 2006
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 110 101
Restricted Cash and Margin Deposits 181 197
Accounts Receivable (Note 2) 2,853 2,951
Inventories and Supplies (Note 3) 665 786
Future Income Tax Assets 426 479
Other 71 67
----------------------
Total Current Assets 4,306 4,581
----------------------

Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $6,530 (December 31,
2006 - $6,399) 12,183 11,739
Goodwill 374 377
Future Income Tax Assets 138 141
Deferred Charges and Other Assets (Note 4) 312 318
----------------------
Total Assets 17,313 17,156
----------------------
----------------------

Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Borrowings (Note 6) 107 158
Accounts Payable and Accrued Liabilities 3,814 3,879
Accrued Interest Payable 36 55
Dividends Payable 13 13
----------------------
Total Current Liabilities 3,970 4,105
----------------------

Long-Term Debt (Note 6) 4,942 4,673
Future Income Tax Liabilities 2,431 2,468
Asset Retirement Obligations (Note 7) 691 683
Deferred Credits and Other Liabilities (Note 8) 423 516
Non-Controlling Interests 73 75

Shareholders' Equity (Note 10)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2007 - 263,188,018 shares
2006 - 262,513,206 shares 866 821
Contributed Surplus 4 4
Retained Earnings 4,080 3,972
Accumulated Other Comprehensive Income (Note 1) (167) (161)
----------------------
Total Shareholders' Equity 4,783 4,636
----------------------
Commitments, Contingencies and Guarantees (Note 14)

----------------------
Total Liabilities and Shareholders' Equity 17,313 17,156
----------------------
----------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Statement of Cash Flows
For the Three Months Ended March 31
Cdn$ millions

2007 2006
----------------------------------------------------------------------------

Operating Activities
Net Income (Loss) 121 (83)
Charges and Credits to Income not Involving Cash
(Note 12) 435 672
Exploration Expense 49 103
Changes in Non-Cash Working Capital (Note 12) 32 73
Other (189) (31)
----------------------
448 734

Financing Activities
Proceeds from (Repayment of) Term Credit Facilities,
Net 366 (4)
Proceeds from (Repayment of) Short-Term Borrowings,
Net (48) 35
Proceeds from Term Credit Facilities of Canexus 18 -
Dividends on Common Shares (13) (13)
Issue of Common Shares 29 13
Other (7) (7)
----------------------
345 24

Investing Activities
Capital Expenditures
Exploration and Development (790) (719)
Proved Property Acquisitions (1) (3)
Chemicals, Corporate and Other (20) (10)
Business Acquisitions, Net of Cash Acquired - (21)
Changes in Restricted Cash 16 (54)
Changes in Non-Cash Working Capital (Note 12) 28 23
Other (4) 7
----------------------
(771) (777)

Effect of Exchange Rate Changes on Cash and Cash
Equivalents (13) 1
----------------------

Increase (Decrease) in Cash and Cash Equivalents 9 (18)

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

Cash and Cash Equivalents - End of Period 110 30
----------------------
----------------------

See accompanying notes to the Unaudited Consolidated Financial Statements.


Nexen Inc.
Unaudited Consolidated Statement of Shareholders' Equity
For the Three Months Ended March 31
Cdn$ millions

2007 2006
----------------------------------------------------------------------------
Common Shares
Balance at Beginning of Period 821 732
Issue of Common Shares 21 5
Proceeds from Options Exercised for Shares 8 8
Accrued Liability Relating to Options Exercised for
Shares 16 18
----------------------
Balance at End of Period 866 763
----------------------
----------------------

Contributed Surplus
Balance at Beginning of Period 4 2
Stock-Based Compensation Expense - -
----------------------
Balance at End of Period 4 2
----------------------
----------------------

Retained Earnings
Balance at Beginning of Period 3,972 3,435
Net Income (Loss) 121 (83)
Dividends on Common Shares (13) (13)
----------------------
Balance at End of Period 4,080 3,339
----------------------
----------------------

Accumulated Other Comprehensive Income
Balance at Beginning of Period (161) -
Opening Cumulative Foreign Currency Translation
Adjustment (Note 1) - (161)
Opening Derivatives Designated as Cash Flow Hedges
(Note 1) 61 -
Other Comprehensive Income (67) (6)
----------------------
Balance at End of Period (167) (167)
----------------------
----------------------


Nexen Inc.
Unaudited Consolidated Statement of Comprehensive Income
For the Three Months Ended March 31
Cdn$ millions

2007 2006
----------------------------------------------------------------------------
Net Income (Loss) 121 (83)
Other Comprehensive Income, Net of Income Taxes:
Foreign Currency Translation Adjustment:
Net Gains (Losses) on Investment in Self-Sustaining
Foreign Operations (58) 2
Net Gains (Losses) on Hedges of Self-Sustaining
Foreign Operations (1) 50 (7)
Realized Translation Adjustments Recognized in Net
Income (2) 2 (1)
Cash Flow Hedges:
Realized Mark to Market Gains Recognized in Net
Income (61) -
----------------------
Other Comprehensive Income (67) (6)
----------------------
Comprehensive Income 54 (89)
----------------------
----------------------

Notes:
(1) Net of income taxes of $9 million (2006 - $1 million)
(2) Net of income taxes of $1 million (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 March 31, 2007 and the results of our operations and our cash flows for the three months ended March 31, 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 months ended March 31, 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 Unaudited Consolidated 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 Unaudited Consolidated Statement of Income in the periods such gains and losses arise. Transaction costs related to these financial assets and liabilities are included in the Unaudited Consolidated Statement of Income when incurred. Unrealized gains and losses on financial assets and liabilities carried at cost or amortized cost are recognized in the Unaudited Consolidated 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 Unaudited Consolidated 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 Unaudited Consolidated Balance Sheet. The effective portion of this fair value change is recognized in other comprehensive income with any ineffectiveness recognized in the Unaudited Consolidated 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 Unaudited Consolidated Balance Sheet at fair value. Changes in the fair value of both are reflected in the Unaudited Consolidated 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 Unaudited 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 Unaudited Consolidated Statement of Comprehensive Income reflects changes in accumulated other comprehensive income and comprises changes in the fair value of financial instruments designated as cash flow hedges, to the extent they are effective, 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 Unaudited Consolidated 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
Cdn$ millions 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)
----------------------


2. ACCOUNTS RECEIVABLE

March 31 December 31
2007 2006
----------------------------------------------------------------------------
Trade
Marketing 2,092 2,226
Oil and Gas 647 600
Chemicals and Other 58 58
----------------------
2,797 2,884
Non-Trade 69 80
----------------------
2,866 2,964
Allowance for Doubtful Receivables (13) (13)
----------------------
Total 2,853 2,951
----------------------
----------------------


3. INVENTORIES AND SUPPLIES

March 31 December 31
2007 2006
----------------------------------------------------------------------------
Finished Products
Marketing 535 609
Oil and Gas 6 21
Chemicals and Other 7 14
----------------------
548 644
Work in Process 5 5
Field Supplies 112 137
----------------------
Total 665 786
----------------------
----------------------


4. DEFERRED CHARGES AND OTHER ASSETS

March 31 December 31
2007 2006
----------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 9) 210 153
Deferred Financing Costs (Note 1) - 59
Asset Retirement Remediation Fund 14 13
Crude Oil Put Options (Note 9) 3 19
Other 85 74
----------------------
Total 312 318
----------------------
----------------------


5. SUSPENDED WELL COSTS

The following table shows the changes in capitalized exploratory well costs during the three month period ended March 31, 2007 and the year ended December 31, 2006, and does not include amounts that were initially capitalized and subsequently expensed in the same period.



Three Months Year
Ended Ended
March 31 December 31
2007 2006
----------------------------------------------------------------------------
Balance at Beginning of Period 226 252
Additions to Capitalized Exploratory Well Costs
Pending the Determination of Proved Reserves 26 129
Capitalized Exploratory Well Costs Charged to
Expense - (70)
Transfers to Wells, Facilities and Equipment
Based on Determination of Proved Reserves (13) (84)
Effects of Foreign Exchange (1) (1)
----------------------
Balance at End of Period 238 226
----------------------
----------------------


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.



March 31 December 31
2007 2006
----------------------
Capitalized for a Period of One Year or Less 119 179
Capitalized for a Period of Greater than One Year 119 47
----------------------
Balance at End of Period 238 226
----------------------
----------------------

Number of Projects that have Exploratory Well Costs
Capitalized for a Period Greater than One Year 5 4
----------------------


As at March 31, 2007, we have exploratory costs that have been capitalized for more than one year relating to our interest in an exploratory block, offshore Nigeria ($21 million), our interest in an exploratory block in the Gulf of Mexico ($56 million), our coalbed methane exploratory activities in Canada ($23 million), an exploratory well on Block 51 in Yemen ($12 million) and an exploratory block in the North Sea ($7 million). We have capitalized costs related to successful wells drilled in Nigeria, the Gulf of Mexico, the 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
March 31 December 31
2007 2006
----------------------------------------------------------------------------
Term Credit Facilities (US$1,235 million) (c) 1,424 1,078
Canexus LP Term Credit Facilities (US$164 million) 189 174
Medium-Term Notes, due 2007 (1) 150 150
Medium-Term Notes, due 2008 125 125
Notes, due 2013 (US$500 million) 577 583
Notes, due 2015 (US$250 million) 288 291
Notes, due 2028 (US$200 million) 230 233
Notes, due 2032 (US$500 million) 577 583
Notes, due 2035 (US$790 million) 911 920
Subordinated Debentures, due 2043 (US$460 million) 530 536
----------------------
5,001 4,673
----------------------
Unamortized Debt Issue Costs (Note 1) (59) -
----------------------
Total Long-Term Debt 4,942 4,673
----------------------
----------------------
Note:
(1) Amounts due July 2007 are not included in current liabilities as we
expect to refinance this amount with our term credit facilities.


(a) Interest expense
Three Months
Ended March 31
2007 2006
----------------------------------------------------------------------------
Long-Term Debt 81 62
Other 5 4
----------------------
86 66
Less: Capitalized (38) (57)
----------------------
Total 48 9
----------------------
----------------------


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

(b) Short-term borrowings

Nexen has uncommitted, unsecured credit facilities of approximately $632 million, of which $107 million (US$93 million) was drawn at March 31, 2007 (December 31, 2006 - $158 million). We have also utilized $181 million of these facilities to support outstanding letters of credit at March 31, 2007 (December 31, 2006 - $252 million). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 5.9% for the three months ended March 31, 2007 (2006 - 4.8%).

(c) Term Credit Facilities

We have committed, unsecured term credit facilities of $3.5 billion, which are available to 2011. At March 31, 2007, $1,424 million (US$1,235 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 March 31, 2007 (2006 - 5.2%). At March 31, 2007, $224 million of these facilities were utilized to support outstanding letters of credit (December 31, 2006 - $294 million).

7. ASSET RETIREMENT OBLIGATIONS

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



Three Months Year
ended ended
March 31 December 31
2007 2006
----------------------------------------------------------------------------
Balance at Beginning of Period 704 611
Obligations Assumed with Development Activities 11 75
Obligations Discharged with Disposed Properties - (1)
Expenditures Made on Asset Retirements (7) (44)
Accretion 11 37
Revisions to Estimates (3) (10)
Effects of Foreign Exchange (4) 36
----------------------
Balance at End of Period (1),(2) 712 704
----------------------
----------------------
Notes:

(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 $666
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 $1,792 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 $91 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
March 31 December 31
2007 2006
----------------------------------------------------------------------------
Deferred Transportation Revenue 90 89
Long-Term Marketing Derivative Contracts (Note 9) 87 199
Fixed-Price Natural Gas Contracts (Note 9) 77 74
Capital Lease Obligations 51 48
Defined Benefit Pension Obligations 48 48
Stock-Based Compensation Liability 15 6
Other 55 52
----------------------
Total 423 516
----------------------
----------------------


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

Cdn$ millions March 31, 2007
----------------------------------------------------------------------------
Carrying Fair Unrecognized
Value Value Gain/(Loss)
--------------------------------
Derivatives
Commodity Price Risk
Non-Trading Activities
Crude Oil Put Options 3 3 -
Fixed-Price Natural Gas Contracts (109) (109) -
Natural Gas Swaps 11 11 -

Trading Activities
Crude Oil and Natural Gas 88 88 -
Future Sale of Gas Inventory - - -

Foreign Currency Exchange Rate Risk
Trading Activities - - -
--------------------------------
Total Derivatives (7) (7) -
--------------------------------
--------------------------------

Other Financial Liabilities
Long-Term Debt (4,942) (5,058) (116)
--------------------------------
--------------------------------

Cdn$ millions December 31, 2006
----------------------------------------------------------------------------
Carrying Fair Unrecognized
Value Value Gain/(Loss)
--------------------------------
Derivatives
Commodity Price Risk
Non-Trading Activities
Crude Oil Put Options 19 19 -
Fixed-Price Natural Gas Contracts (96) (96) -
Natural Gas Swaps (8) (8) -

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

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

Other Financial Liabilities
Long-Term Debt (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.



Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(bbls/d) (US$/bbl) (Cdn$ millions)
WTI Crude Oil Put Options 105,000 2007 50 3
---------------
---------------


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 (32)
15,514 2008-2010 2.56-2.77 (77)
---------------
(109)
---------------
---------------


Following the sale of the Canadian oil and gas properties, we entered into natural gas swaps to economically hedge our exposure to the fixed-price natural gas sales contracts. 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 4
15,514 2008-2010 7.60 7
---------------
11
---------------
---------------


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 $88 million fair value of the derivative contracts at March 31, 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 three months of 2007, the inventory was sold and as a result, gains on these cash flow hedges were recognized in marketing and other on 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. During the first three months of 2007, the gains were recognized in marketing and other on the Unaudited Consolidated Statement of Income.

At March 31, 2007, there were no cash flow hedges in place.

(c) Foreign currency exchange rate risk management

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 March 31, 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:



March 31 December 31
(Cdn$ millions) 2007 2006
----------------------------------------------------------------------------
Accounts Receivable 339 731
Deferred Charges and Other Assets (1) 210 153
----------------------
Total Derivative Contract Assets 549 884
----------------------
----------------------
Accounts Payable and Accrued Liabilities 374 325
Deferred Credits and Other Liabilities (1) 87 199
----------------------
Total Derivative Contract Liabilities 461 524
----------------------
----------------------
Total Derivative Contract Net Assets (2) 88 360
----------------------
----------------------
Notes:

(1) These derivative contracts settle beyond 12 months and are considered
non-current.

(2) Comprised of $88 million (2006 - $372 million) related to commodity
contracts and losses of nil (2006 - losses of $12 million) related to
US-dollar forward contracts and swaps.


As a physical energy marketer, we match the contract months of our derivative instruments with the contract months of our physical sales and purchases. As a result, our disclosure with respect to derivative instruments includes amounts with no ongoing commodity price or foreign exchange risk as at March 31, 2007. Excluding such amounts, derivative contracts included in accounts receivable at March 31, 2007 amounted to $284 million (December 31, 2006 - $460 million) and derivative contracts included in accounts payable and accrued liabilities amounted to $350 million (December 31, 2006 -$312 million).

Our exchange-traded derivative contracts are subject to margin deposit requirements. We are required to advance cash to counterparties in order to satisfy their requirements. We have margin deposits of $181 million (December 31, 2006 - $197 million), which have been included in restricted cash and margin deposits on our Unaudited Consolidated Balance Sheet at March 31, 2007.

10. SHAREHOLDERS' EQUITY

Dividends

Dividends per common share for the three months ended March 31, 2007 were $0.05 (2006 - $0.05). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.

11. EARNINGS PER COMMON SHARE

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



Three Months
Ended March 31
(millions of shares) 2007 2006
----------------------------------------------------------------------------
Weighted-average number of common shares outstanding 263.0 261.6
Shares issuable pursuant to tandem options 14.2 -
Shares to be purchased from proceeds of tandem options (7.9) -
-------------------
Weighted-average number of diluted common shares
outstanding 269.3 261.6
-------------------
-------------------


In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2007, all options were included because their exercise price was less than the quarterly average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2006, all options were excluded because they have an anti-dilutive impact on the loss per share amounts. During the periods presented, outstanding stock options were the only potential dilutive instruments.



12. CASH FLOWS

(a) Charges and credits to income not involving cash
Three Months
Ended March 31
2007 2006
----------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment 334 266
Stock-Based Compensation 44 108
Future Income Taxes 35 269
Change in Fair Value of Crude Oil Put Options 16 4
Net Income Attributable to Non-Controlling Interests 3 3
Other 3 22
----------------------
Total 435 672
----------------------
----------------------

(b) Changes in non-cash working capital

Three Months
Ended March 31
2007 2006
----------------------------------------------------------------------------
Accounts Receivable 75 829
Inventories and Supplies 65 (150)
Other Current Assets (4) 5
Accounts Payable and Accrued Liabilities (58) (571)
Accrued Interest Payable (18) (17)
----------------------
Total 60 96
----------------------
----------------------
Relating to:
Operating Activities 32 73
Investing Activities 28 23
----------------------
Total 60 96
----------------------
----------------------

(c) Other cash flow information
Three Months
Ended March 31
2007 2006
----------------------------------------------------------------------------
Interest Paid 101 80
Income Taxes Paid 57 70
----------------------


13. MARKETING AND OTHER
Three Months
Ended March 31
2007 2006
----------------------------------------------------------------------------
Marketing Revenue, Net 247 437
Decrease in Fair Value of Crude Oil Put Options (16) (4)
Interest 9 9
Foreign Exchange Losses (5) (21)
Other 13 5
----------------------
Total 248 426
----------------------
----------------------


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 March 31, 2007

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

Net Sales 243 115 168 344 29
Marketing and Other 3 1 - 4 -
----------------------------------------------------
Total Revenues 246 116 168 348 29
Less: Expenses
Operating 42 39 28 53 2
Depreciation,
Depletion,
Amortization and
Impairment 58 41 84 114 3
Transportation and
Other 3 7 - - -
General and
Administrative(3) 1 32 19 5 24
Exploration 3 5 13 20 8(4)
Interest - - - - -
----------------------------------------------------
Income (Loss) from
Continuing
Operations before
Income Taxes 139 (8) 24 156 (8)
----------------------------------------------------
----------------------------------------------------
Less: Provision for
Income Taxes(5)
Less:
Non-Controlling
Interests
Net Income

Identifiable Assets 521 4,279 1,668 5,356 248
----------------------------------------------------
----------------------------------------------------

Capital Expenditures
Development and
Other 32 356 139 140 8
Exploration 5 33 14 46 10
Proved Property
Acquisitions - - - 1 -
----------------------------------------------------
37 389 153 187 18
----------------------------------------------------
----------------------------------------------------

Property, Plant and
Equipment
Cost 2,414 5,601 2,982 4,834 256
Less: Accumulated
DD&A 2,121 1,485 1,491 528 81
----------------------------------------------------
Net Book Value 293 4,116 1,491 4,306 175
----------------------------------------------------
----------------------------------------------------


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



Net Sales 16 119 106 - 1,140
Marketing and Other 247 - 5 (12)(2) 248
-------------------------------------------------------
Total Revenues 263 119 111 (12) 1,388
Less: Expenses
Operating 13 47 66 - 290
Depreciation,
Depletion,
Amortization and
Impairment 4 13 11 6 334
Transportation and
Other 220 5 11 - 246
General and
Administrative(3) 30 - 9 82 202
Exploration - - - - 49
Interest - - 3 45 48
-------------------------------------------------------
Income (Loss) from
Continuing
Operations before
Income Taxes (4) 54 11 (145) 219
------------------------------------------------
------------------------------------------------
Less: Provision for
Income Taxes(5) 95
Less:
Non-Controlling
Interests 3
-------
Net Income 121
-------
-------

Identifiable Assets 3,372(6) 1,196 467 206 17,313
-------------------------------------------------------
-------------------------------------------------------

Capital Expenditures
Development and
Other - 7 12 8 702
Exploration - - - - 108
Proved Property
Acquisitions - - - - 1
-------------------------------------------------------
- 7 12 8 811
-------------------------------------------------------
-------------------------------------------------------

Property, Plant and
Equipment
Cost 230 1,305 797 294 18,713
Less: Accumulated
DD&A 49 185 436 154 6,530
-------------------------------------------------------
Net Book Value 181 1,120 361 140 12,183
-------------------------------------------------------
-------------------------------------------------------

Notes:
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $9 million, foreign exchange losses of $5
million and decrease in the fair value of crude oil put options of $16
million.
(3) Includes stock-based compensation expense of $116 million.
(4) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(5) Includes Yemen cash taxes of $44 million.
(6) Approximately 78% of Marketing's identifiable assets are accounts
receivable and inventories.


Three months ended March 31, 2006

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

Net Sales 328 111 181 134 28
Marketing and Other 3 1 - 2 -
----------------------------------------------------
Total Revenues 331 112 181 136 28
Less: Expenses
Operating 36 34 30 22 2
Depreciation,
Depletion,
Amortization and
Impairment 77 37 55 71 2
Transportation and
Other 2 10 - - -
General and
Administrative(3) 14 42 35 4 16
Exploration - 6 62 20 15(4)
Interest - - - - -
----------------------------------------------------
Income (Loss) from
Continuing
Operations before
Income Taxes 202 (17) (1) 19 (7)
----------------------------------------------------
----------------------------------------------------
Less: Provision for
Income Taxes(5),(6)
Less:
Non-Controlling
Interests
Net Loss

Identifiable Assets 630 2,789 1,414 4,966 188
----------------------------------------------------
----------------------------------------------------

Capital Expenditures
Development and
Other 47 325 64 120 9
Exploration 5 46 40 19 7
Proved Property
Acquisitions - 2 - 1 -
----------------------------------------------------
52 373 104 140 16
----------------------------------------------------
----------------------------------------------------

Property, Plant and
Equipment
Cost 2,299 3,991 2,491 4,139 256
Less: Accumulated
DD&A 1,921 1,334 1,213 275 120
----------------------------------------------------
Net Book Value 378 2,657 1,278 3,864 136
----------------------------------------------------
----------------------------------------------------


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



Net Sales 7 84 107 - 980
Marketing and Other 437 - - (17)(2) 426
-------------------------------------------------------
Total Revenues 444 84 107 (17) 1,406
Less: Expenses
Operating 7 53 66 - 250
Depreciation,
Depletion,
Amortization and
Impairment 3 5 10 6 266
Transportation and
Other 232 6 10 - 260
General and
Administrative(3) 36 - 7 66 220
Exploration - - - - 103
Interest - - 2 7 9
-------------------------------------------------------
Income (Loss) from
Continuing
Operations before
Income Taxes 166 20 12 (96) 298
------------------------------------------------
------------------------------------------------
Less: Provision for
Income Taxes(5),(6) 378
Less:
Non-Controlling
Interests 3

-------
Net Loss (83)
-------
-------

Identifiable Assets 2,743(7) 1,146 470 152 14,498
-------------------------------------------------------
-------------------------------------------------------

Capital Expenditures
Development and
Other 1 37 2 7 612
Exploration - - - - 117
Proved Property
Acquisitions - - - - 3
-------------------------------------------------------
1 37 2 7 732
-------------------------------------------------------
-------------------------------------------------------

Property, Plant and
Equipment
Cost 185 1,275 829 251 15,716
Less: Accumulated
DD&A 74 173 466 129 5,705
-------------------------------------------------------
Net Book Value 111 1,102 363 122 10,011
-------------------------------------------------------
-------------------------------------------------------

Notes:
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $8 million, foreign exchange losses of $21
million and decrease in the fair value of crude oil put options of $4
million.
(3) Includes stock-based compensation expense of $145 million.
(4) Includes exploration activities primarily in Nigeria and Colombia.
(5) Includes Yemen cash taxes of $67 million.
(6) 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.
(7) Approximately 77% 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:
0


(a) Unaudited Consolidated Statement of Income - US GAAP
For the Three Months ended March 31

(Cdn$ millions, except per share amounts) 2007 2006
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,140 980
Marketing and Other (i) 246 436
----------------------
1,386 1,416
----------------------
Expenses
Operating (ii) 296 252
Depreciation, Depletion, Amortization and Impairment 334 266
Transportation and Other 246 260
General and Administrative (iv) 199 221
Exploration 49 103
Interest 48 9
----------------------
1,172 1,111
----------------------
Income before Income Taxes 214 305
----------------------
Provision for Income Taxes
Current 60 109
Deferred (i) - (iv) 33 (6)
----------------------
93 103
----------------------
Net Income before Non-Controlling Interests 121 202
Net Income Attributable to Non-Controlling Interests (3) (3)
----------------------
Net Income - US GAAP (1) 118 199
----------------------
----------------------
Earnings Per Common Share ($/share)
----------------------
Basic (Note 11) 0.45 0.76
----------------------
----------------------
Diluted (Note 11) 0.44 0.74
----------------------
----------------------
Note:
(1) Reconciliation of Canadian and US GAAP Net Income


Three Months
Ended March 31
(Cdn$ millions) 2007 2006
----------------------------------------------------------------------------
Net Income - Canadian GAAP 121 (83)
Impact of US Principles, Net of Income Taxes:
Ineffective Portion of Cash Flow Hedges (i) (2) 6
Pre-operating Costs (ii) (3) (1)
Deferred Income Taxes (iii) - 277
Liability-based Stock Compensation Plans (iv) 2 -
----------------------
Net Income - US GAAP 118 199
----------------------
----------------------


(b) Unaudited Consolidated Balance Sheet - US GAAP

March 31 December 31
(Cdn$ millions, except share amounts) 2007 2006
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 110 101
Restricted Cash and Margin Deposits 181 197
Accounts Receivable 2,853 2,976
Inventories and Supplies 665 786
Deferred Income Tax Asset 426 479
Other 71 67
----------------------
Total Current Assets 4,306 4,606
----------------------
Property, Plant and Equipment
Net of Accumulated Depreciation,
Depletion, Amortization and Impairment
of $6,923 (December 31, 2006 - $6,792)
(ii); (vi) 12,130 11,692
Goodwill 374 377
Deferred Income Tax Assets 138 141
Deferred Charges and Other Assets 312 263
----------------------
Total Assets 17,260 17,079
----------------------
----------------------
Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Borrowings 107 158
Accounts Payable and Accrued Liabilities (iv) 3,836 3,839
Accrued Interest Payable 36 55
Dividends Payable 13 13
----------------------
Total Current Liabilities 3,992 4,065
----------------------

Long-Term Debt 4,942 4,618
Deferred Income Tax Liabilities (i) - (vi) 2,389 2,427
Asset Retirement Obligations 691 683
Deferred Credits and Liabilities (v) 504 597
Non-Controlling Interests 73 75
Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2007 - 263,188,018 shares
2006 - 262,513,206 shares 866 821
Contributed Surplus 4 4
Retained Earnings (i) - (vi) 4,022 3,945
Accumulated Other Comprehensive Income (i); (v) (223) (156)
----------------------
Total Shareholders' Equity 4,669 4,614
----------------------
Commitments, Contingencies and Guarantees

Total Liabilities and Shareholders' Equity 17,260 17,079
----------------------
----------------------


(c) Unaudited Consolidated Statement of Comprehensive Income - US GAAP
For the Three Months Ended March 31

(Cdn$ millions) 2007 2006
----------------------------------------------------------------------------
Net Income - US GAAP 118 199
Other Comprehensive Income, Net of Income Taxes:
Foreign Currency Translation Adjustment (6) (2)
Change in Mark to Market on Cash Flow Hedges (i) (61) 14
----------------------
Comprehensive Income 51 211
----------------------
----------------------

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

March 31 December 31
(Cdn$ millions) 2007 2006
----------------------------------------------------------------------------
Foreign Currency Translation Adjustment (167) (161)
Mark to Market on Cash Flow Hedges (i) - 61
Unamortized Defined Benefit Pension Costs (v) (56) (56)
----------------------
(223) (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 three months ended March 31, 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 2007.

In the first quarter of 2006, our US GAAP net income includes $10 million ($6 million, net of income taxes) related 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 three months ended March 31, 2007.

At March 31, 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 March 31, 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 $6 million for the three months ended March 31, 2007 ($3 million, net of income taxes) (2006 - $2 million ($1 million, net of income taxes)); and

- property, plant and equipment is lower under US GAAP by $34 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.

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 lower by $3 million ($2 million, net of income taxes) for the three months ended March 31, 2007 (2006 - higher by $1 million (nil, net of income taxes)); and

- accounts payable and accrued liabilities are higher by $22 million as at March 31, 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 March 31, 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 months ended March 31, 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 January 1 and March 31, 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 January 1 and March 31, 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 $9 million. We had no interest or penalties in the US GAAP - Unaudited Consolidated Statement of Income for the first quarter of 2007. Our income tax filings are subject to audit by taxation authorities and as at January 1 and March 31, 2007 the following tax years remained subject to examination; (i) Canada - 1985 to date, (ii) United Kingdom - 2002 to date and (iii) United States - 2003 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 will 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 are currently evaluating the provisions of Statement 159 and have not yet determined the impact this statement will have on our results from 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