Nexen Delivers Strong Cash Flow and Operating Results

CALGARY, Canada, April 27 /PRNewswire/ -- First Quarter Highlights:

- Cash flow of Cdn$4.01 per share, earnings of Cdn$0.29 per share

- Production averages 260,000 boe/d

- Major projects continue on schedule and on budget - production before royalties expected to grow to between 300,000 and 350,000 boe/d in 2007

- Major field construction about to begin at Long Lake

- Buzzard's recoverable resource increases 15%

Three Three Months Ended Months Ended March 31 December 31 -------------------------- ------------ (Cdn$ millions) 2005 2004 2004 ------------------------------------------------------------------------- Production (mboe/d)(1) Before Royalties 260 258 256 After Royalties 183 176 183 Net Sales 916 715 866 Cash Flow from Operations(2) 520 414 592 Per Common Share ($/share)(2) 4.01 3.25 4.58 Net Income 37 184 246 Per Common Share ($/share) 0.29 1.44 1.90 Business Acquisitions - - 2,583 Capital Expenditures 599 325 668 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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.

Calgary, Alberta, April 27, 2005 - Strong production and commodity prices generated $520 million of cash flow and $37 million of net income. Income was reduced by $173 million ($114 million after tax) to reflect the market value of our crude oil put options and $125 million ($83 million after tax) related to stock-based compensation. These items also reduced cash flow from operations by $42 million.

Following our North Sea acquisition late last year, we purchased put options on 60,000 bbls/d of oil production for 2005 and 2006, for $144 million, to ensure base cash flow over the next two years to support our investment in major development projects. These options create an average floor price for this production of US$43.17/bbl in 2005 and US$38.17/bbl in 2006. Accounting rules require that these options be recorded at fair value throughout their term. As a result, changes in forward crude oil prices cause gains or losses to be recorded on these options each quarter. While a gain of $56 million ($38 million after tax) was recorded in the fourth quarter of 2004, a significant increase in forward crude oil prices during the first quarter of 2005 resulted in an expense of $173 million ($114 million after tax). The carrying value of these options at the end of the first quarter was $27 million.

"Unlike other hedging strategies, the maximum cost of our put strategy is limited to the price we paid last year. This strategy allows us to realize the benefits of higher crude oil prices on all of our production while receiving protection against lower prices," said Charlie Fischer, Nexen's President and Chief Executive Officer. "Although accounting for these options adds volatility to our earnings quarter over quarter, it does not change the fundamentals of the strategy, which cost $144 million to implement. The volatility will decrease as these instruments get closer to their expiry."

We have a broad stock-based compensation plan to attract and retain quality employees in a highly-competitive environment and have recognized stock-based compensation expense since 2003. Changes in the price of our shares will result in increases or decreases to net income. During the first quarter, our stock price increased 36% or $17.50/share, adding $2.3 billion in shareholder value. As a result, $125 million ($83 million after tax) of stock- based compensation expense was recognized. The $83 million expense represents 3.6% of the increase in shareholder value. Approximately 20% of this expense was in cash, while the balance represents the change in value of our accrued stock based compensation.

Oil and Gas Production Update - Continued Strong Production

Production before Production Crude Oil, NGLs and Royalties after Royalties Natural Gas (mboe/d) Q1 2005 Q4 2004 Q1 2005 Q4 2004 ----------------------------------------------------- ------------------- Yemen 114 106 58 55 North Sea 20 8 20 8 Canada 59 60 46 47 United States 50 59 43 51 Other Countries 6 7 5 7 Syncrude 11 16 11 15 ------------------- ------------------- Total 260 256 183 183 ------------------- ------------------- ------------------- -------------------

Production before royalties increased compared to the fourth quarter of 2004, with higher rates from Yemen and the North Sea and a solid quarter from Canada, more than offsetting shortfalls from the US and Syncrude.

The growth in the North Sea and Yemen reflects a full quarter of production from the recently acquired Scott/Telford fields in the North Sea and the recently commissioned BAK-A field on Block 51 in Yemen, as well as better than expected performance from these fields. In Yemen, Block 51 production averaged 17,700 bbls/d through an early production system. We anticipate this increasing to approximately 30,000 bbls/d following completion of permanent production facilities.

Production from the Gulf of Mexico decreased 15% from last quarter. This was largely due to lower production at our Aspen field where we experienced increased water production. We are evaluating a number of options to increase production, including drilling another well there. Our Aspen field achieved pay-out of our investment in January 2005, just over two years from first production, and produced approximately 21,000 boe/d during the quarter. At Syncrude, unsuccessful start-up of a hydrogen plant at the end of January limited hydrotreating capacity for the remainder of the quarter. As a result, to minimize overall downtime of the facility, the turnaround of Coker 8-2 and associated upgrading units was advanced from April to early February. The volumes deferred during the first quarter should be recovered over the next six months. We continue to expect our share of Syncrude's production to average between 16,000 and 18,000 bbls/d in 2005. The Stage 3 expansion is progressing well, with our share of production projected to increase by approximately 8,000 bbls/d in 2006.

"Overall, our quarterly production was very strong from most areas of the business," said Fischer. "With the coker turnaround at Syncrude behind us and production gains from Block 51 and the North Sea in the first quarter, we continue to expect our production to average between 230,000 and 250,000 boe/d, but now we should be able to achieve these volumes even after completing our disposition program later this year."

Long Lake Update - Major Field Construction to Start in Second Quarter

The Long Lake Project continues to progress well and is on schedule and on budget. To date, approximately 45% of the project's total costs have been committed, with approximately 28% of these incurred. Cost experience is in line with our original estimates.

The detailed engineering for the facilities is approaching the 80% engineered completion milestone, which will facilitate above-ground mechanical construction commencing on schedule in the second quarter. The SAGD facilities are expected to be completed in late-2006 and the upgrader in late-2007, with synthetic crude oil production ramping up to approximately 60,000 bbls/d. Nexen has a 50% interest in the project.

"We will commence major field construction on schedule and with detailed plans in place," said Fischer. "With almost half our costs committed and a good degree of certainty around many other costs, we are confident in the soundness of our original project budget and schedule."

Commercial SAGD drilling remains ahead of schedule, with close to half our horizontal wells drilled. Drilling of all 78 well pairs is expected to be completed during the first quarter of 2006.

Our acreage in the Athabasca region of northern Alberta contains approximately five billion barrels of recoverable bitumen resource. The Long Lake Project will only develop about 10% of that resource. Looking ahead, we are already formulating plans to capitalize on the talent and expertise we are gaining at Long Lake, to capture the value of this vast resource through sequential development of high-quality properties like Kinosis, Leismer and Cottonwood in a continuous manner. "With long-life reserves that have virtually no exploration risk, this is the type of opportunity we can build a long-term and growing business around," commented Fischer.

Buzzard Update - Platform Jackets Complete, Installation Begins in Second Quarter

Our Buzzard development in the North Sea remains on budget and on schedule. During the quarter, we completed construction of the three platform jackets and finalized the detailed design of the facilities. The wellhead deck fabrication is also nearing completion. Through the spring and summer, we plan to install the jackets and the wellhead deck and begin laying the sub-sea pipelines. Development drilling is planned to begin in the third quarter. Overall, the Buzzard development is approximately 65% complete.

As a result of a new 3-D seismic survey and mapping work at Buzzard, we have increased our estimate of Buzzard's oil-in-place by approximately 15%. This change will increase our gross recoverable resource estimate for the field from 480 million barrels to approximately 550 million barrels. As a result, our share of Buzzard's recoverable resource will increase from 207 million barrels to approximately 237 million barrels.

First production from Buzzard is expected in late-2006, with our share of peak production reaching approximately 80,000 boe/d in 2007. We have a 43.2% operated interest in the field.

Our Farragon field development remains on schedule to begin producing late this year at between 3,000 and 4,000 boe/d, net to Nexen. We have a 20% non-operated interest here.

"With Buzzard, Long Lake and our other development projects on schedule, we expect to be producing between 300,000 and 350,000 boe/d before royalties in 2007," commented Fischer. "Much of this growth will come from projects where we pay little or no royalties, generating annual growth rates between 15% and 20% on an after royalties basis between now and 2007. With oil prices at US$40, we expect cash flow to be in excess of $3 billion for 2007, approximately 50% higher than we expect for 2005."

Exploration Update - Three High-Impact Wells Drilling in the Gulf of Mexico

In the Gulf of Mexico, we are evaluating our Anduin discovery, formulating development plans for our Wrigley discovery, and are currently drilling the Vrede, Knotty Head and Big Bend prospects. Both Knotty Head and Vrede are significant deep-water, sub-salt prospects in the Green Canyon and Atwater Valley areas, respectively. Big Bend is a deep-shelf gas prospect in the Mustang Island area. Results from these wells are expected during the second quarter.

Pathfinder, a third significant deep-water, sub-salt prospect will commence drilling on Green Canyon 390, following rig release at Vrede. We have a 25% non-operated interest in Pathfinder.

The Castleton prospect, on Garden Banks 668, is a potential tie-back to the Gunnison facilities where we have additional production capacity. This deep-water well should commence drilling in the second quarter, with results expected in the third quarter. We have a 30% non-operated interest here.

On Block 51 in Yemen, we finished testing the BAK-I well. The well encountered non-commercial quantities of oil and has been suspended. We are encouraged by the presence of oil on this part of the block. We are conducting additional seismic and plan to drill another well to further evaluate this prospect. At BAK-J, we are still waiting for the necessary high pressure drilling equipment before re-entering the well and re-commencing drilling activities. We plan to drill four additional exploration wells on Block 51 this year.

In the North Sea, we began drilling the Saracen prospect on Block 21/2 in early April, with results expected late in the second quarter. We have a 50% operated interest in Saracen. During the second quarter, we expect to begin drilling our Polecat prospect on Block 20/4a, where we have a 40% operated interest. We plan to drill between two and four more exploration wells in the North Sea this year.

Offshore West Africa, we plan to drill three or four exploration wells prior to year-end. On OPL-222, offshore Nigeria, we approved drilling the Efere prospect and expect to commence drilling in the second quarter. As well, we agreed with partners to launch basic engineering for the development of Usan on a floating production and storage facility. Both are subject to the approval of the authorities. "We have a very high-quality exploration program this year, led by our prospects in the Gulf of Mexico," commented Fischer. "All of the equipment and services to carry out our global exploration program have been contracted and we are looking forward to some great results."

Disposition Update - Canadian Conventional Properties and Chemicals are Being Marketed

We plan to raise at least $1.5 billion through the sale of assets in 2005 and we are currently marketing our chemicals assets and certain Canadian conventional oil and gas properties (Hay, Findley, Balzac, SE Saskatchewan, and NW Saskatchewan), which currently produce approximately 22,000 boe/d. The data rooms opened in early April and we expect to complete sales in the second and third quarters of this year. The proceeds from these sales will be used to reduce our outstanding debt and fund future capital investment.

Quarterly Dividend - 120th Consecutive Dividend Declared

The Board of Directors has declared the regular quarterly dividend of $0.10 per common share (pre-split) payable July 1, 2005, to shareholders of record on June 10, 2005.

Nexen Inc. is an independent, Canadian-based global energy and chemicals 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 West Africa. We add value for shareholders through successful full-cycle oil and gas exploration and development, a growing industrial bleaching chemicals business, 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 27, 2005 Time: 12:30 p.m. Mountain Time (2:30 p.m. Eastern Time) To listen to the conference call, please call one of these two lines: +1-416-640-4127 (Toronto or International) +1-800-814-4860 (North American toll-free) A replay of the call will be available for two weeks starting at 4:30 p.m. Eastern Time, April 27 by calling +1-416-640-1917 passcode 21121541 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 future production associated with our Long Lake, North Sea and West Africa 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, changes in environmental and other laws and regulations; renegotiations of contracts; and political uncertainty, including actions by insurgent or other armed groups or other conflict. 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 commerciality, development plans, capacity expansions, drilling of new wells, ultimate recoverability of reserves, future production rates, cash flows or ability to execute on the disposition of assets or businesses, 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 7 and 7A in our 2004 Annual Report on Form 10-K for further discussion of the risk factors. Cautionary Note to U.S. 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 2004 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) 2005 2004 ------------------------------------------------------------------------- Net Sales 916 715 Cash Flow from Operations(1) 520 414 Per Common Share ($/share) 4.01 3.25 Net Income(1) 37 184 Per Common Share ($/share) 0.29 1.44 Capital Expenditures(2) 599 325 Net Debt(3) 4,348 1,566 Common Shares Outstanding (millions of shares) 130.0 128.2 ------------------------------------------------------------------------- (1) Includes discontinued operations as discussed in Note 12 to our Unaudited Consolidated Financial Statements. (2) Includes oil and gas development, exploration, and expenditures for other property, plant and equipment. (3) Net Debt is defined as long-term debt less working capital. Cash Flow from Operations(1) Three Months Ended March 31 (Cdn$ millions) 2005 2004 ------------------------------------------------------------------------- Cash Flow from Operations Oil & Gas and Syncrude Yemen(2) 189 132 Canada 84 91 United States 169 155 United Kingdom 77 - Other Countries(3) 10 17 Marketing 36 19 Syncrude 23 44 --------------- 588 458 Chemicals 23 20 --------------- 611 478 Interest and Other Corporate Items (71) (57) Income Taxes(4) (20) (7) --------------- Cash Flow from Operations(1) 520 414 --------------- --------------- (1) Defined as cash generated 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. Three Months Ended March 31 (Cdn$ millions) 2005 2004 --------------------------------------------------------------------- Cash Flow from Operating Activities 441 538 Changes in Non-Cash Working Capital 53 (120) Other 43 (4) Amortization of Premium for Crude Oil Put Options (17) - --------------- Cash Flow from Operations 520 414 --------------- --------------- Weighted-average Number of Common Shares Outstanding (millions of shares) 129.7 127.5 --------------- Cash Flow from Operations Per Common Share ($/share) 4.01 3.25 --------------- --------------- (2) After in-country cash taxes of $59 million for the three months ended March 31, 2005 (2004 - $46 million). (3) Includes discontinued operations as discussed in Note 12 to our Unaudited Consolidated Financial Statements. (4) Excludes in-country cash taxes in Yemen. Nexen Inc. Production Volumes (before royalties)(1) Three Months Ended March 31 2005 2004 ------------------------------------------------------------------------- Crude Oil and NGLs (mbbls/d) Yemen 114.3 114.1 Canada 34.7 36.8 United States 28.5 26.7 United Kingdom 14.9 - Australia(2) - 4.5 Other Countries 5.9 4.9 Syncrude(3) (mbbls/d) 11.4 18.3 --------------- 209.7 205.3 --------------- Natural Gas (mmcf/d) Canada 143 149 United States 127 167 United Kingdom 29 - --------------- 299 316 --------------- Total Production (mboe/d) 260 258 --------------- --------------- Production Volumes (after royalties) Three Months Ended March 31 2005 2004 ------------------------------------------------------------------------- Crude Oil and NGLs (mbbls/d) Yemen 57.7 54.0 Canada 27.5 28.6 United States 25.2 23.5 United Kingdom 14.9 - Australia(2) - 4.2 Other Countries 5.4 4.2 Syncrude(3) (mbbls/d) 11.3 18.1 --------------- 142.0 132.6 --------------- Natural Gas (mmcf/d) Canada 111 120 United States 108 142 United Kingdom 29 - --------------- 248 262 --------------- Total Production (mboe/d) 183 176 --------------- --------------- Notes: (1) We have presented production volumes before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies. (2) Includes discontinued operations as discussed in Note 12 to our Unaudited Consolidated Financial Statements. (3) Considered a mining operation for US reporting purposes. Nexen Inc. Oil and Gas Prices and Cash Netback(1) Quarters Total - 2005 Quarters - 2004 Year (all Dollar amounts in ------------------------------------------------- Cdn$ unless noted) 1st 1st 2nd 3rd 4th 2004 ------------------------------------------------------------------------- PRICES: WTI Crude Oil (US$/bbl) 49.85 35.15 38.32 43.88 48.28 41.40 Nexen Average - Oil (Cdn$/bbl) 51.33 40.22 44.75 50.98 47.98 45.90 NYMEX Natural Gas (US$/mmbtu) 6.48 5.73 6.16 5.56 7.30 6.19 Nexen Average - Gas (Cdn$/mcf) 6.98 6.63 7.17 6.55 7.02 6.85 ------------------------------------------------------------------------- ------------------------------------------------------------------------- NETBACKS: Canada - Light Oil and NGLs Sales (mbbls/d) 11.5 12.4 13.6 12.0 11.5 12.4 Price Received ($/bbl) 55.37 41.31 46.37 51.82 51.47 47.64 Royalties & Other 12.08 9.41 10.60 12.30 10.10 10.60 Operating Costs 9.77 9.09 6.52 6.22 6.27 7.03 ------------------------------------------------------------------------- Netback 33.52 22.81 29.25 33.30 35.10 30.01 ------------------------------------------------------------------------- Canada - Heavy Oil Sales (mbbls/d) 22.7 23.7 22.9 23.0 23.4 23.2 Price Received ($/bbl) 26.15 27.92 30.12 36.75 28.15 30.71 Royalties & Other 6.05 6.00 6.73 8.77 5.65 6.78 Operating Costs 10.55 9.98 10.44 10.05 10.70 10.29 ------------------------------------------------------------------------- Netback 9.55 11.94 12.95 17.93 11.80 13.64 ------------------------------------------------------------------------- Canada - Total Oil Sales (mbbls/d) 34.2 36.1 36.5 35.0 34.9 35.6 Price Received ($/bbl) 35.99 32.51 36.18 41.94 35.83 36.60 Royalties & Other 8.12 7.21 8.19 10.03 7.02 8.11 Operating Costs 10.29 9.68 8.98 8.73 9.24 9.16 ------------------------------------------------------------------------- Netback 17.58 15.62 19.01 23.18 19.57 19.33 ------------------------------------------------------------------------- Canada - Natural Gas Sales (mmcf/d) 143 149 145 141 147 146 Price Received ($/mcf) 5.80 5.59 5.97 5.43 6.02 5.76 Royalties & Other 1.17 1.10 1.11 1.04 0.95 1.06 Operating Costs 0.71 0.59 0.69 0.83 0.65 0.69 ------------------------------------------------------------------------- Netback 3.92 3.90 4.17 3.56 4.42 4.01 ------------------------------------------------------------------------- Yemen Sales (mbbls/d) 115.0 115.3 105.6 101.5 104.0 106.6 Price Received ($/bbl) 54.38 41.88 45.88 53.80 49.52 47.59 Royalties & Other 27.08 22.10 22.53 27.40 24.15 23.98 Operating Costs 3.33 2.72 2.55 2.91 3.04 2.80 In-country Taxes 5.67 4.41 5.88 6.97 6.17 5.82 ------------------------------------------------------------------------- Netback 18.30 12.65 14.92 16.52 16.16 14.99 ------------------------------------------------------------------------- Syncrude Sales (mbbls/d) 11.4 18.3 16.6 17.6 16.4 17.2 Price Received ($/bbl) 65.15 45.54 52.46 55.58 58.16 52.80 Royalties & Other 0.65 0.45 0.52 0.55 6.08 1.84 Operating Costs 39.91 17.41 20.01 18.87 23.58 19.89 ------------------------------------------------------------------------- Netback 24.59 27.68 31.93 36.16 28.50 31.07 ------------------------------------------------------------------------- United States Crude Oil: Sales (mbbls/d) 28.5 26.5 25.7 32.9 34.4 30.0 Price Received ($/bbl) 50.90 38.99 46.31 49.90 49.44 46.60 Natural Gas: Sales (mmcf/d) 127 167 134 144 147 148 Price Received ($/mcf) 8.32 7.63 8.47 7.64 7.93 7.89 Total Sales Volume (mboe/d) 49.6 54.4 48.0 56.9 58.8 54.5 Price Received ($/boe) 50.48 42.47 48.38 48.19 48.67 46.94 Royalties & Other 6.48 5.90 6.98 6.22 6.16 6.29 Operating Costs 4.91 4.13 4.84 7.60 4.52 5.30 ------------------------------------------------------------------------- Netback 39.09 32.44 36.56 34.37 37.99 35.35 ------------------------------------------------------------------------- Australia Sales (mbbls/d) - 7.5 4.8 - 5.1 4.3 Price Received ($/bbl) - 42.60 49.84 - 63.78 51.22 Royalties & Other - 2.11 2.28 - 7.42 4.00 Operating Costs - 22.88 34.28 - 46.38 32.94 ------------------------------------------------------------------------- Netback - 17.61 13.28 - 9.98 14.28 ------------------------------------------------------------------------- United Kingdom Crude Oil: Sales (mbbls/d) 17.5 - - - 6.3 1.6 Price Received ($/bbl) 54.53 - - - 46.81 46.81 Natural Gas: Sales (mmcf/d) 26 - - - 11 3 Price Received ($/mcf) 6.92 - - - 8.28 8.28 Total Sales Volume (mboe/d) 21.9 - - - 8.1 2.1 Price Received ($/boe) 51.92 - - - 47.45 47.45 Royalties & Other - - - - - - Operating Costs 12.59 - - - 8.26 8.26 ------------------------------------------------------------------------- Netback 39.33 - - - 39.19 39.19 ------------------------------------------------------------------------- Other Countries Sales (mbbls/d) 5.6 4.1 5.8 5.0 5.4 5.1 Price Received ($/bbl) 46.63 37.07 44.75 46.22 42.95 43.07 Royalties & Other 3.68 1.73 4.94 3.46 3.33 3.49 Operating Costs 2.32 2.70 6.28 2.93 2.65 3.76 ------------------------------------------------------------------------- Netback 40.63 32.64 33.53 39.83 36.97 35.82 ------------------------------------------------------------------------- Company-Wide Oil and Gas Sales (mboe/d) 261.6 260.5 241.5 239.5 257.2 249.7 Price Received ($/boe) 49.55 40.11 44.41 48.66 46.82 44.94 Royalties & Other 14.94 12.76 13.34 15.30 13.29 13.65 Operating Costs 6.94 5.67 6.06 6.25 6.63 6.15 In-country Taxes 2.49 1.95 2.57 2.96 2.49 2.48 ------------------------------------------------------------------------- Netback 25.18 19.73 22.44 24.15 24.41 22.66 ------------------------------------------------------------------------- (1) Defined as average sales price less royalties and other, operating costs, and in-country taxes in Yemen. Nexen Inc. Unaudited Consolidated Statement of Income For the Three Months Ended March 31 Cdn$ millions, except per share amounts 2005 2004 ------------------------------------------------------------------------- Restated for Changes in Accounting Principles Note 1 Revenues Net Sales 916 715 Marketing and Other (Note 11) 72 158 ----------------------- 988 873 ----------------------- Expenses Operating 225 179 Depreciation, Depletion, Amortization and Impairment 256 174 Transportation and Other 208 142 General and Administrative 181 60 Exploration 28 28 Interest (Note 5) 34 45 ----------------------- 932 628 ----------------------- Income from Continuing Operations before Income Taxes 56 245 ----------------------- Provision for Income Taxes Current 79 53 Future (60) 12 ----------------------- 19 65 ----------------------- Net Income from Continuing Operations 37 180 Net Income from Discontinued Operations (Note 12) - 4 ----------------------- Net Income 37 184 ----------------------- ----------------------- Earnings Per Common Share from Continuing Operations ($/share) Basic (Note 9) 0.29 1.41 ----------------------- ----------------------- Diluted (Note 9) 0.28 1.39 ----------------------- ----------------------- Earnings Per Common Share ($/share) Basic (Note 9) 0.29 1.44 ----------------------- ----------------------- Diluted (Note 9) 0.28 1.42 ----------------------- ----------------------- See accompanying notes to the Unaudited Consolidated Financial Statements. Nexen Inc. Unaudited Consolidated Balance Sheet Cdn$ millions, except share amounts March 31 December 31 2005 2004 ------------------------------------------------------------------------- Assets Current Assets Cash and Cash Equivalents 70 74 Accounts Receivable (Note 2) 2,075 2,136 Inventories and Supplies (Note 3) 455 351 Other 38 42 ----------------------- Total Current Assets 2,638 2,603 ----------------------- Property, Plant and Equipment Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $5,578 (December 31, 2004 - $5,344) 9,001 8,643 Goodwill 377 375 Future Income Tax Assets 353 333 Deferred Charges and Other Assets (Note 4) 267 429 ----------------------- 12,636 12,383 ----------------------- ----------------------- Liabilities and Shareholders' Equity Current Liabilities Short-Term Borrowings 94 100 Accounts Payable and Accrued Liabilities 2,414 2,416 Accrued Interest Payable 41 34 Dividends Payable 13 13 ----------------------- Total Current Liabilities 2,562 2,563 ----------------------- Long-Term Debt (Note 5) 4,424 4,259 Future Income Tax Liabilities 2,095 2,131 Asset Retirement Obligations (Note 6) 433 421 Deferred Credits and Other Liabilities 173 142 Shareholders' Equity (Note 8) Common Shares, no par value Authorized: Unlimited Outstanding: 2005 - 129,990,330 shares 2004 - 129,199,583 shares 684 637 Contributed Surplus 1 - Retained Earnings 2,359 2,335 Cumulative Foreign Currency Translation Adjustment (95) (105) ----------------------- Total Shareholders' Equity 2,949 2,867 ----------------------- Commitments, Contingencies and Guarantees (Note 13) 12,636 12,383 ----------------------- ----------------------- See accompanying notes to the Unaudited Consolidated Financial Statements. Nexen Inc. Unaudited Consolidated Statement of Cash Flows For the Three Months Ended March 31 Cdn$ millions 2005 2004 ------------------------------------------------------------------------- Restated for Changes in Accounting Principles Note 1 Operating Activities Net Income from Continuing Operations 37 180 Net Income from Discontinued Operations - 4 Charges and Credits to Income not Involving Cash (Note 10) 472 202 Exploration Expense 28 28 Changes in Non-Cash Working Capital (Note 10) (53) 120 Other (43) 4 ----------------------- 441 538 Financing Activities Proceeds from Term Credit Facilities, Net 138 - Proceeds from Long-Term Debt (Note 5) 1,253 - Repayment of Long-Term Debt (Note 5) (1,241) (300) Repayment of Short-Term Borrowings, Net (10) - Redemption of Preferred Securities - (289) Dividends on Common Shares (13) (13) Issue of Common Shares 32 82 Other (16) - ----------------------- 143 (520) Investing Activities Capital Expenditures Exploration and Development (594) (314) Proved Property Acquisitions (1) - Chemicals, Corporate and Other (4) (11) Proceeds on Disposition of Assets 2 - Changes in Non-Cash Working Capital (Note 10) (14) 8 Other 16 - ----------------------- (595) (317) Effect of Exchange Rate Changes on Cash and Cash Equivalents 7 12 ----------------------- Increase (Decrease) in Cash and Cash Equivalents (4) (287) Cash and Cash Equivalents - Beginning of Period 74 1,087 ----------------------- Cash and Cash Equivalents - End of Period 70 800 ----------------------- ----------------------- See accompanying notes to the Unaudited Consolidated Financial Statements. Nexen Inc. Unaudited Consolidated Statement of Shareholders' Equity For the Three Months Ended March 31, 2005 and March 31, 2004 Cdn$ millions 2005 2004 ------------------------------------------------------------------------- Restated for Changes in Accounting Principles Note 1 Common Shares Balance at January 1 637 513 Issue of Common Shares 32 82 Previously Recognized Liability Relating to Stock Options Exercised 15 - ----------------------- Balance at March 31 684 595 ----------------------- ----------------------- Contributed Surplus Balance at January 1 - 1 Stock Based Compensation Expense 1 1 ----------------------- Balance at March 31 1 2 ----------------------- ----------------------- Retained Earnings Balance at January 1 2,335 1,594 Net Income 37 184 Dividends on Common Shares (13) (13) ----------------------- Balance at March 31 2,359 1,765 ----------------------- ----------------------- Cumulative Foreign Currency Translation Adjustment Balance at January 1 (105) (33) Translation Adjustment, Net of Income Taxes 10 3 ----------------------- Balance at March 31 (95) (30) ----------------------- ----------------------- 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 The Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and 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, 2005 and the results of our operations and our cash flows for the three months ended March 31, 2005 and 2004. Management makes 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 litigation, asset retirement obligations, income taxes 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, 2005 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2005. These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2004 Annual Report on Form 10-K. The accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2004 Annual Report on Form 10-K. Changes in Accounting Principles Financial Instruments In the fourth quarter of 2004, we retroactively adopted the changes to Canadian Institute of Chartered Accountants (CICA) standard S.3860, Financial Instruments. These changes require that fixed-amount contractual obligations that can be settled by issuing a variable number of equity instruments be classified as a liability. Our US-dollar denominated preferred and subordinated securities have these characteristics and accordingly have been reclassified as long-term debt. Dividends and interest on these securities have been included in interest expense and issue costs previously charged to retained earnings have been amortized over the life of the securities. Unamortized issue costs have been expensed on the redemption of the preferred securities in 2004. Foreign exchange gains or losses from translation of the US-dollar amounts have been included as cumulative foreign currency translation adjustments. The change was adopted retroactively and all prior periods presented have been restated. This change in accounting principle has no effect on our Unaudited Consolidated Financial Statements for the three months ended March 31, 2005. Generally Accepted Accounting Principles In 2004, we adopted CICA standard S.1100, Generally Accepted Accounting Principles which eliminated general practice in Canada as a component of GAAP. Our accounting policy is to include geological and geophysical costs as operating cash outflows in our Unaudited Consolidated Statement of Cash Flows. For previous years, we included geological and geophysical costs as investing cash outflows consistent with industry practice in Canada. In our Unaudited Consolidated Statement of Cash Flows for the three months ended March 31, 2005, we included $5 million (March 31, 2004 - $18 million) of geological and geophysical costs as other operating cash outflows. This change in accounting policy was adopted prospectively. Impact of Changes in Accounting Principles The impact of the changes on our Unaudited Consolidated Statement of Income for the three months ended March 31, 2004 resulted in additional interest expense of $3 million for dividends on preferred securities, additional transportation and other expense of $11 million for the unamortized issue costs on the redemption of preferred securities, and a corresponding reduction in the provision for income taxes of $6 million. The impact of these changes in accounting principles on our Unaudited Consolidated Statement of Income and Earnings per Common Share for the three months ended March 31, 2004, are shown below. Unaudited consolidated statement of income for the three months ended March 31, 2004 2004 ------------------------------------------------------------------------- Transportation and Other Expense as Reported 131 Plus: Unamortized Issue Costs on Redemption of Preferred Securities 11 ----------- Transportation and Other Expense as Restated 142 ----------- Interest Expense as Reported 42 Plus: Dividends on Preferred Securities 3 ----------- Interest Expense as Restated 45 ----------- Provision for Future Income Taxes as Reported 18 Plus: Tax Effect of Changes in Accounting Principles (6) ----------- Provision for Future Income Taxes as Restated 12 ----------- Net income and earnings per common share for the three months ended March 31, 2004 2004 ------------------------------------------------------------------------- Net Income Attributable to Common Shareholders As Reported 190 Less: Unamortized Issue Costs on Redemption of Preferred Securities, Net of Income Taxes (6) ----------- As Restated 184 ----------- ----------- Earnings per Common Share ($/share) Basic as Reported 1.49 ----------- ----------- Restated 1.44 ----------- ----------- Diluted as Reported 1.47 ----------- ----------- Restated 1.42 ----------- Reclassification Certain comparative figures have been reclassified to ensure consistency with current period presentation. 2. ACCOUNTS RECEIVABLE March 31 December 31 2005 2004 ------------------------------------------------------------------------- Trade Marketing 1,275 1,452 Oil and Gas 671 593 Chemicals and Other 56 57 ----------------------- 2,002 2,102 Non-Trade 80 49 ----------------------- 2,082 2,151 Allowance for Doubtful Accounts (7) (15) ----------------------- Total 2,075 2,136 ----------------------- ----------------------- 3. INVENTORIES AND SUPPLIES March 31 December 31 2005 2004 ------------------------------------------------------------------------- Finished Products Marketing 275 199 Oil and Gas 9 6 Chemicals and Other 11 13 ----------------------- 295 218 Work in Process 5 4 Field Supplies 155 129 ----------------------- Total 455 351 ----------------------- ----------------------- 4. DEFERRED CHARGES AND OTHER ASSETS March 31 December 31 2005 2004 ------------------------------------------------------------------------- Crude Oil Put Options 21 200 Long-Term Marketing Derivative Contracts 115 91 Defined Benefit Pension Plan Asset 11 13 Deferred Financing Costs 71 67 Other 49 58 ----------------------- Total 267 429 ----------------------- ----------------------- 5. LONG-TERM DEBT AND SHORT-TERM BORROWINGS March 31 December 31 2005 2004 ------------------------------------------------------------------------- Acquisition Credit Facilities (US$473 million drawn) 572 1,806 Term Credit Facilities (US$180 million drawn) 218 87 Debentures, due 2006(1) 93 93 Medium-Term Notes, due 2007 150 150 Medium-Term Notes, due 2008 125 125 Notes, due 2013 (US$500 million) 605 602 Notes, due 2015 (US$250 million)(a) 302 - Notes, due 2028 (US$200 million) 242 241 Notes, due 2032 (US$500 million) 605 602 Notes, due 2035 (US$790 million)(b) 956 - Subordinated Debentures, due 2043 (US$460 million) 556 553 ----------------------- 4,424 4,259 ----------------------- ----------------------- Note: (1) Includes $50 million of principal that was effectively converted through a currency exchange contract to US$37 million. (a) Notes, due 2015 In March 2005, we issued US$250 million of notes. Interest is payable semi-annually at a rate of 5.20% and the principal is to be repaid in March 2015. 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 0.15%. The proceeds were used to repay a portion of the Acquisition Credit Facilities. (b) Notes, due 2035 In March 2005, we issued US$790 million of notes. Interest is payable semi-annually at a rate of 5.875% and the principal is to be repaid in March 2035. 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 a portion of the Acquisition Credit Facilities. (c) Interest expense Three Months Ended March 31 2005 2004 ------------------------------------------------------------------------- Long-Term Debt 62 49 Other 5 3 ----------------------- 67 52 Less: Capitalized (33) (7) ----------------------- Total 34 45 ----------------------- ----------------------- Capitalized interest relates to and is included as part of the cost of our oil and gas property, plant and equipment. The capitalization rates are based on our weighted-average cost of borrowings. 6. ASSET RETIREMENT OBLIGATIONS Changes in carrying amounts of the asset retirement obligations associated with our property, plant and equipment are as follows: March 31 December 31 2005 2004 ------------------------------------------------------------------------- Balance at Beginning of Period 468 323 Obligations Assumed with Development Activities 8 12 Obligations Assumed with Business Acquisition - 134 Obligations Discharged with Disposed Properties - (4) Expenditures Made on Asset Retirements (17) (31) Accretion 6 17 Revisions to Estimates - 24 Effects of Foreign Exchange 1 (7) ----------------------- Balance at End of Period(1) 466 468 ----------------------- ----------------------- Note: (1) Obligations due within 12 months of $33 million (2004 - $47 million) have been included in accounts payable and accrued liabilities. Our total estimated undiscounted asset retirement obligations amount to $766 million (December 31, 2004 - $770 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.7%. Approximately $107 million included in our asset retirement obligations will be settled over the next five years. The remaining obligations settle beyond five years and will be funded by future cash flows from our operations. We own interests in assets for which the fair value of the asset retirement obligations cannot be reasonably determined because the assets currently have an indeterminate life and we cannot determine when remediation activities would take place. These assets include our interest in Syncrude's upgrader and sulphur pile. The estimated future recoverable reserves at Syncrude are significant and given the long life of this asset, we are unable to determine when asset retirement activities would take place. Furthermore, the Syncrude plant can continue to run indefinitely with ongoing maintenance activities. The retirement obligations for these assets will be recorded in the first year in which the lives of the assets are determinable. 7. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (a) Carrying value and estimated fair value of derivative and financial instruments The carrying value, fair value, and unrecognized gains or losses on our outstanding derivatives and long-term financial assets and liabilities are: Cdn$ millions March 31, 2005 December 31, 2004 ------------------------------------------------------------------------- Unrecog- Unrecog- nized nized Carrying Fair Gain/ Carrying Fair Gain/ Value Value (Loss) Value Value (Loss) -------------------------- -------------------------- Commodity Price Risk - Non-Trading Activities Crude Oil Put Options 27 27 - 200 200 - Trading Activities Crude Oil and Natural Gas 58 58 - 83 83 - Future Sale of Gas Inventory - (1) (1) - 6 6 Foreign Currency Risk Non-Trading Activities 11 11 - 7 7 - Trading Activities 8 8 - 10 10 - -------------------------- -------------------------- Total Derivatives 104 103 (1) 300 306 6 -------------------------- -------------------------- -------------------------- -------------------------- Financial Assets and Liabilities Long-Term Debt (4,424) (4,576) (152) (4,259) (4,503) (244) -------------------------- -------------------------- -------------------------- -------------------------- 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. The carrying value of cash and cash equivalents, amounts receivable and short-term obligations approximates their fair value because the instruments are near maturity. (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 We purchased WTI crude oil put options to manage the commodity price risk exposure of a portion of our oil production in 2005 and 2006. These options establish an annual average WTI floor price of US$43/bbl in 2005 and US$38/bbl in 2006 at a cost of $144 million and are stated at fair value on our balance sheet. Any change in fair value is included in marketing and other on the Unaudited Consolidated Statement of Income. Average Notional Price Market Volumes Term (WTI) Value ------------------------------------------------------------------------- (bbls/d) (US$/bbl) (Cdn$ millions) WTI Crude Oil Put Options 30,000 2005 44 4 20,000 2005 43 2 10,000 2005 41 - 30,000 2006 39 12 20,000 2006 38 7 10,000 2006 36 2 ---------- 27 ---------- ---------- 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 market value. The $58 million fair value of the contracts has been recognized in net income. Future Sale of Gas Inventory We have certain NYMEX futures contracts and swaps in place, which effectively lock-in our margins on the future sale of our natural gas inventory in storage. We have designated, in writing, some of these derivative contracts as cash flow hedges of the future sale of our storage inventory. As a result, gains and losses on these designated futures contracts and swaps are recognized in net income when the inventory in storage is sold. The principal terms of these outstanding contracts and the unrecognized losses at March 31, 2005 are: Hedged Average Unrecognized Volumes Month Price Loss ------------------------------------------------------------------------- (mmcf) (US$/mcf) (Cdn$ millions) NYMEX Natural Gas Futures 5,780 January 8.67 (1) 2006 ---------- (1) ---------- ---------- (c) Foreign currency exchange rate risk management Non-Trading Activities We occasionally use derivative instruments to effectively convert cash flows from Canadian to US dollars and vice versa. At March 31, 2005, we held a foreign currency derivative instrument that obligates us and the counterparty to exchange principal and interest amounts. In November 2006, we will pay US$37 million and receive Cdn$50 million. We have recognized a gain of $7 million for the change in fair value of this derivative instrument. Our Buzzard development project in the North Sea creates foreign currency exposure as a portion of the capital costs are denominated in British pounds and Euros. In order to reduce our exposure to fluctuations in these currencies relative to the US dollar, we purchased foreign currency call options in early 2005 which effectively set a ceiling on most of our British pound and Euro spending exposure from March 2005 through to the end of 2006. Any change in fair value is included in marketing and other on the Unaudited Consolidated Statement of Income. Market Amount Term Rate Value ------------------------------------------------------------------------- (for (Cdn$ US$1.00) millions) Foreign Currency Call Options pnds stlg 246 million 2005-2006 1.95-2.00 4 (euro) 44 million 2005 1.40 - ---------- 4 ---------- ---------- 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. We enter into forward contracts to sell US dollars. When combined with certain commodity sales contracts, either physical or financial, these forward contracts allow us to lock-in our margins on the future sale of crude oil and natural gas. The fair value of our US dollar forward contracts at March 31, 2005 was $8 million. This fair value has been recognized in net income and settles within one year. (d) Total carrying value of derivative contracts related to trading activities Amounts related to derivative contracts held by our marketing operation are equal to fair value as we use mark-to-market accounting. The amounts are as follows: March 31 December 31 Cdn$ millions 2005 2004 ------------------------------------------------------------------------- Accounts Receivable 151 177 Deferred Charges and Other Assets(1) 115 91 ----------------------- Total Derivative Contract Assets 266 268 ----------------------- Accounts Payable and Accrued Liabilities 152 129 Deferred Credits and Other Liabilities(1) 48 46 ----------------------- Total Derivative Contract Liabilities 200 175 ----------------------- ----------------------- Total Derivative Contract Net Assets 66 93 ----------------------- ----------------------- Note: (1) These derivative contracts settle beyond 12 months and are considered non-current. 8. SHAREHOLDERS' EQUITY Dividends Dividends per common share for the three months ended March 31, 2005 were $0.10 (2004 - $0.10). 9. EARNINGS PER COMMON SHARE We calculate basic earnings per common share from continuing operations using net income from continuing operations divided by the weighted-average number of common shares outstanding. 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 from continuing operations and 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) 2005 2004 ------------------------------------------------------------------------- Weighted-average number of common shares outstanding 129.7 127.5 Shares issuable pursuant to stock options 7.4 7.4 Shares to be purchased from proceeds of stock options (5.3) (5.6) ----------------------- Weighted-average number of diluted common shares outstanding 131.8 129.3 ----------------------- ----------------------- In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2005 and March 31, 2004, all options were included because their exercise price was less than the quarterly average common share market price in the period. During the periods presented, outstanding stock options were the only potential dilutive instruments. 10. CASH FLOWS (a) Charges and credits to income not involving cash Three Months Ended March 31 2005 2004 ------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 256 174 Stock Based Compensation 100 2 Future Income Taxes (60) 12 Change in Fair Value of Crude Oil Put Options 173 - Non-Cash Items included in Discontinued Operations - 8 Unamortized Issue Costs on Redemption of Preferred Securities - 11 Other 3 (5) ----------------------- Total 472 202 ----------------------- ----------------------- (b) Changes in non-cash working capital Three Months Ended March 31 2005 2004 ------------------------------------------------------------------------- Accounts Receivable 67 115 Inventories and Supplies (99) (16) Other Current Assets 4 46 Accounts Payable and Accrued Liabilities (45) (10) Accrued Interest Payable 6 (7) ----------------------- Total (67) 128 ----------------------- ----------------------- Relating to: Operating Activities (53) 120 Investing Activities (14) 8 ----------------------- Total (67) 128 ----------------------- ----------------------- (c) Other cash flow information Three Months Ended March 31 2005 2004 ------------------------------------------------------------------------- Interest Paid 56 56 Income Taxes Paid 62 49 ----------------------- ----------------------- 11. MARKETING AND OTHER Three Months Ended March 31 2005 2004 ------------------------------------------------------------------------- Marketing Revenue, Net 229 147 Change in Fair Value of Crude Oil Put Options (173) - Interest 3 2 Foreign Exchange Gains 10 6 Other 3 3 ----------------------- Total 72 158 ----------------------- ----------------------- 12. DISCONTINUED OPERATIONS During the fourth quarter of 2004, we concluded production from our Buffalo field, offshore Australia as anticipated. The results of our operations in Australia have been treated as discontinued operations, as we have no plans to continue operations in the country. Remediation and abandonment of the field has been virtually completed and no gain or loss is expected from these activities. Three Months Ended March 31 2005 2004 ------------------------------------------------------------------------- Revenues Net Sales - 28 Expenses Operating - 16 Depreciation, Depletion, Amortization and Impairment - 8 ----------------------- Income before Income Taxes - 4 Future Income Taxes - - ----------------------- Net Income from Discontinued Operations - 4 ----------------------- ----------------------- Earnings Per Common Share ($/share) Basic (Note 9) - 0.03 ----------------------- ----------------------- Diluted (Note 9) - 0.03 ----------------------- ----------------------- Assets and liabilities on the Unaudited Consolidated Balance Sheet include the following amounts for discontinued operations. March 31 December 31 2005 2004 ------------------------------------------------------------------------- Cash and Cash Equivalents 3 1 Accounts Receivable 8 8 Other Current Assets - 1 Accounts Payable and Accrued Liabilities 8 25 ----------------------- 13. COMMITMENTS, CONTINGENCIES AND GUARANTEES As described in Note 12 to the Audited Consolidated Financial Statements included in our 2004 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. 14. PENSION AND OTHER POST RETIREMENT BENEFITS (a) Net pension expense recognized under our defined benefit pension plans Three Months Ended March 31 2005 2004 ------------------------------------------------------------------------- Nexen Cost of Benefits Earned by Employees 2 2 Interest Cost on Benefits Earned 3 3 Actual Return on Plan Assets (4) (4) Actuarial Losses 3 4 ----------------------- Pension Expense Before Adjustments for the Long- Term Nature of Employee Future Benefit Costs 4 5 Difference Between Actual and Expected Return 2 1 Difference Between Actual and Recognized Actuarial Gains (Losses) (3) (4) Difference Between Actual and Recognized Past Service Costs 1 - ----------------------- Net Pension Expense 4 2 ----------------------- Syncrude Cost of Benefits Earned by Employees 1 1 Interest Cost on Benefits Earned 2 1 Actual Return on Plan Assets (2) (2) Actuarial Losses 2 2 ----------------------- ----------------------- Pension Expense Before Adjustments for the Long- Term Nature of Employee Future Benefit Costs 3 2 Difference Between Actual and Expected Return 1 1 Difference Between Actual and Recognized Actuarial Gains (Losses) (2) (2) Difference Between Actual and Recognized Past Service Costs - - ----------------------- Net Pension Expense 2 1 ----------------------- Total 6 3 ----------------------- ----------------------- (b) Employer Funding Contributions Our expected total funding contributions for 2005 disclosed in Note 13(e) to the Audited Consolidated Financial Statements in our 2004 Annual Report on Form 10-K have not changed for both our Nexen defined benefit pension plan and our share of Syncrude's defined benefit pension plan 15. OPERATING SEGMENTS AND RELATED INFORMATION Nexen is involved in activities relating to Oil and Gas, Syncrude and Chemicals in various geographic locations as described in Note 18 to the Audited Consolidated Financial Statements included in our 2004 Annual Report on Form 10-K. Three months ended March 31, 2005 (Cdn$ millions) Oil and Gas ------------------------------------------------------------------------- Other United United Countries Market Yemen Canada States Kingdom (2) -ing --------------------------------------------------- Net Sales 283 146 197 102 22 4 Marketing and Other 1 1 - - - 229 --------------------------------------------------- Total Revenues 284 147 197 102 22 233 Less: Expenses Operating 35 41 22 25 1 6 Depreciation, Depletion, Amortization and Impairment 65 52 66 46 4 3 Transportation and Other 1 5 - - - 177 General and Administrative(4) 1 32 18 - 28 17 Exploration 1 6 10 3 8(5) - Interest - - - - - - --------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 181 11 81 28 (19) 30 --------------------------------------------------- --------------------------------------------------- Less: Provision for Income Taxes(6) Add: Net Income from Discontinued Operations Net Income Identifiable Assets 758 2,172 1,387 4,538 202 2,020(7) --------------------------------------------------- --------------------------------------------------- Capital Expenditures Development and Other 63 214 19 140 4 1 Exploration 8 20 72 3 7 - Proved Property Acquisitions - 1 - - - - --------------------------------------------------- 71 235 91 143 11 1 --------------------------------------------------- --------------------------------------------------- Property, Plant and Equipment Cost 2,123 3,696 2,299 3,655 542 158 Less: Accumulated DD&A 1,623 1,667 1,064 65 412 67 ----------------------------------------------------- Net Book Value 500 2,029 1,235 3,590 130 91 ----------------------------------------------------- ----------------------------------------------------- Corporate Syncrude and (Cdn$ millions) (1) Chemicals Other Total ------------------------------------------------------- Net Sales 66 96 - 916 Marketing and Other - 1 (160)(3) 72 --------------------------------- Total Revenues 66 97 (160) 988 Less: Expenses Operating 40 55 - 225 Depreciation, Depletion, Amortization and Impairment 4 10 6 256 Transportation and Other 3 10 12 208 General and Administrative(4) - 15 70 181 Exploration - - - 28 Interest - - 34 34 --------------------------------- Income (Loss) from Continuing Operations before Income Taxes 19 7 (282) 56 ------------------------ ------------------------ Less: Provision for Income Taxes(6) 19 Add: Net Income from Discontinued Operations - ------- Net Income 37 ------- ------- Identifiable Assets 954 494 111 12,636 --------------------------------- --------------------------------- Capital Expenditures Development and Other 44 1 2 488 Exploration - - - 110 Proved Property Acquisitions - - - 1 --------------------------------- 44 1 2 599 --------------------------------- --------------------------------- Property, Plant and Equipment Cost 1,074 829 203 14,579 Less: Accumulated DD&A 158 425 97 5,578 ------------------------------------ Net Book Value 916 404 106 9,001 ------------------------------------ ------------------------------------ Notes: (1) Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at March 31, 2005 includes mineral rights of $6 million. (2) Includes results of operations from producing activities in Nigeria and Colombia. (3) Includes interest income of $3 million, foreign exchange gains of $10 million and decrease in the fair value of crude oil put options of $173 million. (4) Includes stock based compensation expense of $125 million. (5) Includes exploration activities primarily in Nigeria and Colombia. (6) Includes Yemen cash taxes of $59 million. (7) Approximately 77% of Marketing's identifiable assets are accounts receivable and inventories. Three months ended March 31, 2004(1) (Cdn$ millions) Oil and Gas ------------------------------------------------------------------------- Other United Countries Market Yemen Canada States (3) -ing ------------------------------------------ Net Sales 207 144 181 13 3 Marketing and Other 1 1 - - 147 ------------------------------------------ Total Revenues 208 145 181 13 150 Less: Expenses Operating 28 40 20 1 4 Depreciation, Depletion, Amortization and Impairment 38 49 62 4 2 Transportation and Other 1 2 - - 116 General and Administrative(5) 1 12 6 7 11 Exploration - 7 9 12(6) - Interest - - - - - ------------------------------------------ Income (Loss) from Continuing Operations before Income Taxes 140 35 84 (11) 17 ------------------------------------------ ------------------------------------------ Less: Provision for Income Taxes(7) Add: Net Income from Discontinued Operations Net Income Identifiable Assets 686 1,641 1,657 389 1,280(8) ------------------------------------------ ------------------------------------------ Capital Expenditures Development and Other 47 91 93 6 - Exploration 2 4 16 5 - ------------------------------------------ 49 95 109 11 - ------------------------------------------ ------------------------------------------ Property, Plant and Equipment Cost 1,973 3,049 2,289 548 153 Less: Accumulated DD&A 1,556 1,510 957 426 56 ------------------------------------------ Net Book Value 417 1,539 1,332 122 97 ------------------------------------------ ------------------------------------------ Corporate Syncrude and (Cdn$ millions) (2) Chemicals Other Total ---------------------------------------------------------------- Net Sales 75 92 - 715 Marketing and Other - 1 8(4) 158 --------------------------------- Total Revenues 75 93 8 873 Less: Expenses Operating 29 57 - 179 Depreciation, Depletion, Amortization and Impairment 4 10 5 174 Transportation and Other 2 10 11 142 General and Administrative(5) - 6 17 60 Exploration - - - 28 Interest - - 45 45 --------------------------------- Income (Loss) from Continuing Operations before Income Taxes 40 10 (70) 245 ------------------------ ------------------------ Less: Provision for Income Taxes(7) 65 Add: Net Income from Discontinued Operations 4 ------- Net Income 184 ------- ------- Identifiable Assets 769 469 532 7,423 --------------------------------- --------------------------------- Capital Expenditures Development and Other 50 6 5 298 Exploration - - - 27 --------------------------------- 50 6 5 325 --------------------------------- --------------------------------- Property, Plant and Equipment Cost 868 783 173 9,836 Less: Accumulated DD&A 145 391 77 5,118 --------------------------------- Net Book Value 723 392 96 4,718 --------------------------------- --------------------------------- Notes: (1) Restated to give effect to changes in accounting principles (see Note 1). (2) Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at March 31, 2004 includes mineral rights of $6 million (3) Includes results of operations from producing activities in Australia, Nigeria and Colombia. (4) Includes interest income of $2 million and foreign exchange gains of $6 million. (5) Includes stock based compensation expense of $6 million. (6) Includes exploration activities primarily in Nigeria and Colombia. (7) Includes Yemen cash taxes of $46 million. (8) Approximately 82% of Marketing's identifiable assets are accounts receivable and inventories 16. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and Balance Sheet and summaries of differences from Canadian GAAP are as follows: (a) Unaudited Consolidated Statement of Income - US GAAP For the Three Months ended March 31 (Cdn$ millions, except per share amounts) 2005 2004 ------------------------------------------------------------------------- Revenues Net Sales 916 715 Marketing and Other (ii); (ix) 72 164 ------------------ 988 879 ------------------ Expenses Operating (iv) 227 181 Depreciation, Depletion, Amortization and Impairment (i) 266 185 Transportation and Other 208 140 General and Administrative 181 60 Exploration 28 28 Interest 34 45 ------------------ 944 639 ------------------ Income from Continuing Operations before Income Taxes 44 240 ------------------ Provision for Income Taxes Current 79 53 Deferred (ii); (iv); (viii) (61) 27 ------------------ 18 80 ------------------ Net Income from Continuing Operations 26 160 Net Income from Discontinued Operations - 4 ------------------ Net Income - US GAAP(1) 26 164 ------------------ ------------------ Earnings Per Common Share ($/share) Basic (Note 9) Net Income from Continuing Operations 0.20 1.26 Net Income from Discontinued Operations - 0.03 ------------------ 0.20 1.29 ------------------ ------------------ Diluted (Note 9) Net Income from Continuing Operations 0.19 1.24 Net Income from Discontinued Operations - 0.03 ------------------ 0.19 1.27 ------------------ ------------------ Note: (1) Reconciliation of Canadian and US GAAP Net Income Three Months Ended March 31 (Cdn$ millions) 2005 2004 --------------------------------------------------------------------- Net Income - Canadian GAAP 37 184 Impact of US Principles, Net of Income Taxes: Depreciation, Depletion, Amortization and Impairment (i) (10) (11) Future Income Taxes (viii) - (15) Fair Value of Preferred Securities (ix) - 4 Other (ii); (iv) (1) 2 ------------------ Net Income - US GAAP 26 164 ------------------ ------------------ (b) Unaudited Consolidated Balance Sheet - US GAAP March 31 December 31 (Cdn$ millions, except share amounts) 2005 2004 ------------------------------------------------------------------------- Assets Current Assets Cash and Cash Equivalents 70 74 Accounts Receivable 2,075 2,142 Inventories and Supplies 455 351 Other 38 42 ------------------- Total Current Assets 2,638 2,609 ------------------- Property, Plant and Equipment Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $6,036 (December 31, 2004 - $5,792) (i); (iv); (vii) 8,984 8,638 Goodwill 377 375 Deferred Income Tax Assets 353 333 Deferred Charges and Other Assets (v) 208 384 ------------------- 12,560 12,339 ------------------- ------------------- Liabilities and Shareholders' Equity Current Liabilities Short-Term Borrowings 94 100 Accounts Payable and Accrued Liabilities (ii) 2,415 2,416 Accrued Interest Payable 41 34 Dividends Payable 13 13 ------------------- Total Current Liabilities 2,563 2,563 ------------------- Long-Term Debt (v) 4,365 4,214 Deferred Income Tax Liabilities (i) - (ix) 2,062 2,101 Asset Retirement Obligations 433 421 Deferred Credits and Liabilities (vi) 179 148 Shareholders' Equity Common Shares, no par value Authorized: Unlimited Outstanding: 2005 - 129,990,330 shares 2004 - 129,199,583 shares 684 637 Contributed Surplus 1 - Retained Earnings (i); (ii); (iv); (vii); (viii); (ix) 2,373 2,360 Accumulated Other Comprehensive Income (ii); (iii); (vi) (100) (105) ------------------- Total Shareholders' Equity 2,958 2,892 ------------------- Commitments, Contingencies and Guarantees 12,560 12,339 ------------------- ------------------- (c) Unaudited Consolidated Statement of Comprehensive Income - US GAAP For the Three Months Ended March 31 (Cdn$ millions) 2005 2004 ------------------------------------------------------------------------- Net Income - US GAAP 26 164 Other Comprehensive Income, Net of Income Taxes: Translation Adjustment (iii) 10 3 Unrealized Mark-to-Market Gain/(Loss) (ii) (5) 6 ------------------- Comprehensive Income 31 173 ------------------- Notes: i. Under US principles, the liability method of accounting for income taxes was adopted in 1993. In Canada, the liability method was adopted in 2000. In 1997, we acquired certain oil and gas assets and the amount paid for these assets differed from the tax basis acquired. Under US principles, this difference was recorded as a deferred tax liability with an increase to property, plant and equipment rather than a charge to retained earnings. As a result: - additional depreciation, depletion, amortization and impairment of $10 million (2004 - $11 million) was included in net income; and - property, plant and equipment is higher under US GAAP by $19 million (December 31, 2004 - $29 million). ii. Under US principles, 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. 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. Future sale of gas inventory: Included in accounts receivable at December 31, 2004, was $6 million of gains on the futures and basis swap contracts we used to hedge the commodity price risk on the future sale of our gas inventory as described in Note 7. These contracts effectively lock-in profits on our stored gas volumes. Gains of $6 million ($4 million, net of income taxes) related to the effective portion and deferred in accumulated other comprehensive income (AOCI) at December 31, 2004, were recognized in marketing and other during the quarter. At March 31, 2005, losses of $1 million ($1 million, net of income taxes) were included in accounts payable and deferred in AOCI until the underlying gas inventory is sold. The losses will be reclassified to marketing and other as they settle over the next 12 months. At March 31, 2005, the ineffective portion was $nil. 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 are reflected in earnings. At March 31, 2005 and at December 31, 2004, we had no fair value hedges in place. iii. Under US principles, exchange gains and losses arising from the translation of our net investment in self-sustaining foreign operations are included in comprehensive income. Additionally, exchange gains and losses, net of income taxes, from the translation of our US-dollar long-term debt designated as a hedge of our foreign net investment are included in comprehensive income. Cumulative amounts are included in AOCI in the Unaudited Consolidated Balance Sheet - US GAAP. iv. Under Canadian principles, 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 $2 million ($1 million, net of income taxes) (2004 - $2 million ($1 million, net of taxes)); and - property, plant and equipment is lower under US GAAP by $17 million (December 31, 2004 - $15 million). v. Under US principles, discounts on long-term debt are classified as a reduction of long-term debt rather than as deferred charges and other assets. Discounts of $59 million (December 31, 2004 - $45 million) have been included in long-term debt. vi. Under US principles, the amount by which our accrued pension cost is less than the unfunded accumulated benefit obligation is included in AOCI and accrued pension liabilities. This amount was $6 million ($4 million, net of income taxes) at March 31, 2005 (December 31, 2004 - $6 million ($4 million, net of income taxes.)) vii. On January 1, 2003 we adopted FASB Statement No. 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 resulted in our property, plant and equipment under US GAAP being lower by $19 million. viii. Under US principles, enacted tax rates are used to calculate future income taxes, whereas under Canadian GAAP, substantively enacted tax rates are used. Substantively enacted changes in Canadian provincial income tax rates created a $15 million future income tax recovery during the first quarter of 2004. ix. In May 2003, FASB issued Statement No. 150, Accounting for Certain Instruments with Characteristics of Both Liabilities and Equity that requires certain financial instruments, including our preferred securities, to be valued at fair value with changes in fair value recognized through net income. (Cdn$ millions) Gain Tax Net Gain ------------------------------------------------------------------- Fair value change from January 1, 2004 to February 9, 2004(1),(2) 4 - 4 ------------------------ Notes: (1) Included in marketing and other. (2) Redemption date of preferred securities. NEW ACCOUNTING PRONOUNCEMENTS In November 2004, the Financial Accounting Standards Board (FASB) issued Statement 151, Inventory Costs. This statement amends ARB 43 to clarify that: - abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage) should be recognized as current-period charges; and - requires the allocation of fixed production overhead to inventory based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We do not expect the adoption of this statement will have any material impact on our results of operations or financial position. In December 2004, the FASB issued Statement 123(R), Share-Based Payments. This statement revises Statement 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion 25, Accounting for Stock Issued to Employees. Statement 123(R) requires all stock-based awards issued to employees to be measured at fair value and to be expensed in the income statement. This statement is effective for fiscal years beginning after June 15, 2005. We are currently expensing stock-based awards issued to employees using the fair value method for equity based awards and the intrinsic method for liability based awards. Adoption of this standard will change our expense under US GAAP for tandem options and stock appreciation rights as these awards will be measured using the fair value method rather than the intrinsic method. We are currently evaluating the provisions of Statement 123(R) and have not yet determined the full impact this statement will have on our results of operations or financial position under US GAAP. In December 2004, the FASB issued Statement 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29, Accounting for Nonmonetary Transactions. This amendment eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under Statement 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance test and fair value is determinable, the transaction must be accounted for at fair value resulting in the recognition of any gain or loss. This statement is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. We do not expect the adoption of this statement will have any material impact on our results of operations or financial position. In March 2005, the FASB issued Financial Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). FIN 47 clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. In March 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry. In the mining industry, companies may be required to remove overburden and other mine waste materials to access mineral deposits. The EITF concluded that the costs of removing overburden and waste materials, often referred to as "stripping costs", incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. Issue No. 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005, with early adoption permitted. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. In April 2005, the Financial Accounting Standards Board (FASB) issued FASB staff position 19-1 (FSP 19-1) on accounting for suspended well costs. FSP 19-1 amends FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, for companies using the successful efforts method of accounting. FSP 19-1 concludes that exploratory well costs should continue to be capitalized when a well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the well. FSP 19-1 also requires certain disclosures with respect to capitalized exploratory well costs. This new guidance is effective for the first reporting period beginning after April 4, 2005 and is to be applied prospectively to existing and newly capitalized exploratory well costs. As at March 31, 2005, we have exploratory costs that have been capitalized for more than one year relating to our interest in an exploratory block, offshore Nigeria. Exploratory costs were first capitalized in 1998 and we have subsequently drilled a further seven successful wells on the block. We are preparing a field development plan for the block with our partners for submission to the Nigerian government for approval. Once we obtain this approval and the project has been sanctioned, we will book proved reserves. Capitalized costs relating to this exploration block as at March 31, 2005 were $79 million (December 31, 2004 - $77 million). We do not expect the adoption of this statement will have a material impact on our capitalized costs, our results of operations or financial position.