NEXEN INC - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
-----------------------------------------
WASHINGTON, D.C. 20549
FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934

FOR THE YEAR ENDED DECEMBER 31, 2002

COMMISSION FILE NUMBER 1-6702

[LOGO OMITTED]

NEXEN INC.
(FORMERLY CANADIAN OCCIDENTAL PETROLEUM LTD.)

Incorporated under the Laws of Canada

98-6000202
(I.R.S. Employer Identification No.)

801 - 7th Avenue S.W.
Calgary, Alberta, Canada T2P 3P7
Telephone - (403) 699-4000
Web site - www.nexeninc.com

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

TITLE EXCHANGE REGISTERED ON
----- ----------------------
Common shares, no par value The New York Stock Exchange
The Toronto Stock Exchange
Preferred Securities, due 2047 The New York Stock Exchange
Preferred Securities, due 2048 The New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None.

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months, and (2) has been subject to such filing requirements
for the past 90 days.
Yes [X] No______

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes [X] No______

On January 31, 2003, the aggregate market value of the voting shares held by
non-affiliates of the registrant was approximately Cdn $4.1 billion based on the
Toronto Stock Exchange closing price on that date. On January 31, 2003, there
were 123,123,189 common shares issued and outstanding.

TABLE OF CONTENTS

PART I PAGE

Items 1 and 2. Business and Properties
Background......................................................... 1
Operations......................................................... 2
Conventional Oil and Gas .................................... 2
Synthetic Crude Oil.......................................... 10
Reserves, Production and Related Information................. 12
Oil and Gas Marketing........................................ 14
Chemicals Operations......................................... 14
Additional Factors Affecting Business.............................. 16
Employees.......................................................... 18
Item 3. Legal Proceedings....................................................... 19
Item 4. Submission of Matters to a Vote of Security Holders..................... 19

PART II
Item 5. Market for the Registrant's Common Shares and
Related Stockholder Matters........................................ 20
Item 6. Selected Financial Data................................................. 21
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.......................................... 22
Item 7(A). Quantitative and Qualitative Disclosures About Market Risk.............. 47
Item 8. Financial Statements and Supplementary Financial Information............ 48
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................................ 85

PART III
Item 10. Directors and Executive Officers of the Registrant...................... 86
Item 11. Executive Compensation.................................................. 92
Item 12. Security Ownership of Certain Beneficial Owners
and Management..................................................... 100
Item 13. Certain Relationships and Related Transactions.......................... 100
Item 14. Controls and Procedures ................................................ 101

PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K........................................................ 102

Unless we indicate otherwise, all dollar amounts ($) are in Canadian dollars,
and production and reserves are our working interest after royalties.

Below is a list of terms specific to the oil and gas industry. They are used
throughout the Form 10-K.

/d = per day mboe = thousand barrels of oil equivalent
bbl = barrel mmboe = million barrels of oil equivalent
mbbls = thousand barrels mcf = thousand cubic feet
mmbbls = million barrels mmcf = million cubic feet
mmbtu = million British thermal units bcf = billion cubic feet
km = kilometre WTI = West Texas Intermediate
NGL = natural gas liquid

Oil equivalents are used to compare quantities of natural gas with crude oil by
expressing them in a common unit. To calculate equivalents, we use 1 bbl = 6 mcf
of natural gas.

The noon-day Canadian to US dollar exchange rates for Cdn $1.00, as reported by
the Bank of Canada, were:

(US$) DECEMBER 31 AVERAGE HIGH LOW
- --------------------------------------------------------------------------------
1998 0.6534 0.6743 0.7105 0.6343
1999 0.6929 0.6730 0.6929 0.6537
2000 0.6666 0.6733 0.6973 0.6413
2001 0.6279 0.6458 0.6695 0.6241
2002 0.6331 0.6369 0.6618 0.6199

On January 31, 2003, the noon-day exchange rate was US $0.6540 for Cdn. $1.00.

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

BACKGROUND

Nexen Inc. (Nexen, we or our), is a global energy and chemicals producer
incorporated under the laws of Canada. Our history is set out below:

DATE EVENT
- --------------------------------------------------------------------------------
July 12, 1971 We were formed under the name Canadian Occidental
Petroleum Ltd. (COPL) through a reorganization by
Occidental Petroleum Corporation (Occidental) of Los
Angeles, California, which combined the crude oil,
natural gas and sulphur operations of its 55% owned
subsidiary, Jefferson Lake Petrochemicals of Canada
Ltd., and the operations, including chemicals, of its
wholly owned subsidiary, New Hooker Canada Ltd.

May 20, 1983 We purchased Canada-Cities Service, Ltd. (Cities
Service) for $354 million. The acquisition doubled our
size, while substantially increasing reserves and
revenues partly through a 13.23% interest in the
Syncrude Project. COPL and Cities Service amalgamated
and continued under the name COPL on January 1, 1984.

February, 1984 We acquired Cities Offshore Production Co., a company
that held interests in producing oil and gas fields in
the Gulf of Mexico, offshore Louisiana, for US$132.5
million.

May 31, 1988 We purchased Moore McCormack Energy, Inc. a company
with mostly onshore operations in Texas, Louisiana and
Alabama.

During 1988 we sold 6% of the interest we acquired in
Syncrude through the Cities Service acquisition for
approximately $330 million. We retained a 7.23%
interest.

April 14, 1997 We acquired Wascana Energy Inc. (Wascana) as a result
of a take-over bid. The total purchase price for
Wascana was approximately $1.7 billion. Wascana became
a wholly-owned subsidiary as a result of an
amalgamation on June 30, 1997.

April 17, 2000 We entered into an agreement with Ontario Teachers'
Pension Plan Board (Teachers) and Occidental where
Occidental sold its 29% interest in COPL, which was
approved by a majority of shareholders other than
Occidental or Teachers. Teachers purchased 20.2 million
common shares, we repurchased the remaining 20 million
common shares for $605 million including associated
fees, and exchanged our oil and gas operations in
Ecuador for Occidental's 15% interest in our chemicals
operations.

November 2, 2000 Further to the sale of Occidental's interest we changed
our name to Nexen Inc.

Electronic copies of our filings with the Securities Exchange Commission (from
November 8, 2002 onward) are available, free of charge, on our website
(www.nexeninc.com). Filings prior to November 8, 2002 are available free of
charge, upon request, by contacting our investor relations department at (403)
699-5931.

1

OPERATIONS

Nexen has operations in four main areas:

o Conventional Oil and Gas
o Synthetic Crude Oil
o Oil and Gas Marketing
o Chemicals

For financial reporting purposes, these areas are defined as reportable
segments. Conventional oil and gas is further broken down into geographic
segments. Information on revenues, operating profit, capital expenditures and
identifiable assets for these segments for the past three years appears in note
15 to the Consolidated Financial Statements and in Management's Discussion and
Analysis of Financial Condition and Results of Operations (MD&A) in this report.

CONVENTIONAL OIL AND GAS

We explore for, develop and produce conventional crude oil, natural gas and
related products around the world. Our core assets are located in western
Canada, the United States (US) Gulf of Mexico and Yemen, with other producing
properties offshore Australia and Nigeria and onshore in Colombia. We are
developing new growth opportunities in Colombia, Nigeria, and Brazil. We
generally manage our operations on a country-by-country basis reflecting
differences in the regulatory environments and risk factors associated with each
country. The oil and gas industry is highly competitive and this is particularly
true when searching for, and developing, new sources of supply, and in
constructing and operating crude oil and natural gas pipelines and facilities.

[WORLD MAP]

Crude oil and natural gas commodities are sensitive to numerous worldwide
factors and are generally sold at contract or posted prices. Changes in world
crude oil and natural gas prices may significantly affect our net income and
cash generated from operating activities. Consequently, these prices may also
affect the carrying value of our oil and gas properties and our level of
spending for oil and gas exploration and development.

We have a broad customer base for our crude oil and natural gas. Alternative
customers are generally available, therefore, the loss of any one customer is
not expected to have a significant adverse effect. Oil and gas operations are
generally not seasonal, except for heavy oil differentials that tend to be
narrower in the summer months.

Our growth comes primarily through the drill bit, supplemented with strategic
acquisitions. This ensures consistent, low-cost growth. We are focused on
maximizing value, not volumes. Not all barrels have the same value so we also
focus on capturing high value barrels which provide high netbacks. Our future
growth will come from the deep-waters of the Gulf of Mexico, the Athabasca oil
sands, the Middle East and offshore West Africa. The basins in these areas offer
an optimal combination of

2

prospectivity, attractive fiscal terms and low costs. Technical innovation is a
key part of our value growth strategy and we are investing in low cost bitumen
upgrading, solvent extraction of heavy oil, coal bed methane, steam assisted
gravity drainage and deep-water operating technology.

YEMEN

[YEMEN MAP]

ACREAGE
(thousand acres) Developed Undeveloped Total
- ---------------------------------------------------------------------------
Gross 38 20,150 20,188
Net 20 10,365 10,385
- ---------------------------------------------------------------------------

PROVED RESERVES
(mmbbls) Before Royalties After Royalties
- ---------------------------------------------------------------------------
Masila Block 183 100
- ---------------------------------------------------------------------------

2002 PRODUCTION
(mmbbls/d) Before Royalties After Royalties
- ---------------------------------------------------------------------------
Masila Block 118.0 55.8
- ---------------------------------------------------------------------------

Yemen's Masila Project (the Project) represented about 36% of our cash flow in
2002. Our strategy in this country is to maintain high production rates from the
Masila fields, fully exploiting the project's remaining potential, while testing
our exploration portfolio of over 20 million acres of undeveloped land for
additional accumulations of hydrocarbons.

MASILA BLOCK

We have a 52% working interest in and operate the Masila Project. The Masila
Project is the largest single source of oil production in Yemen and has grown
steadily since discovery in 1990. To date, the 15 fields that comprise the
Project have produced over 665 million gross barrels of oil from total gross
recoverable reserves of just over one billion barrels. Nexen has the right to
produce oil from the Masila fields until 2011 and the right to negotiate a
five-year extension.

During 2002, $402 million ($209 million net) was invested to drill and equip 74
new development wells and expand existing infrastructure. Gross production was
maintained throughout the year at approximately 226,900 barrels per day, net of
fuel use.

Currently the majority of crude oil production comes from the Upper Qishn
formation. Oil has been identified in formations below the Upper Qishn including
the Lower Qishn, Upper Saar, Saar, Madbi, Basal Sand, and Basement formations.
In 2002, waterfloods in three fields were implemented to develop reserves in a
number of these formations. Waterfloods will be expanded in these and other
fields in 2003.

Production from the Masila Project is governed by a Production Sharing Contract
between the Government of Yemen and the Masila joint venture partners including
Nexen (Partners). Under the terms of the contract, production is divided into
cost recovery oil and profit oil. Cost recovery oil provides for the recovery of
all of the Project's exploration, development and operating costs which are
funded by the Partners. Costs are recovered from a maximum of 40% of production
each fiscal year, as follows:

COSTS RECOVERY
- --------------------------------------------------------------------------------
Operating 100% in year incurred
Exploration 25% per year for 4 years
Development 16.7% per year for 6 years

The remaining production is profit oil that is shared between the Partners and
the Government on a sliding scale based on production rates. The Partners'
profit oil share ranges from 20% to 33%. The Government's share includes
provision for Yemen income taxes payable by the Partners at a rate of 35%. In
2002, the Partners' share of production from the Masila Project, including
recovery of past costs, was approximately 33%.

The economics of Masila production are attractive. Historic finding and
development costs are approximately US $2 per barrel and operating costs have
averaged US $1 per barrel, resulting in excellent returns for shareholders. In
addition, the structure of the contract moderates the impact on the Partners'
cash flows during periods of low prices.

3

Yemen crude oil is sold based on reference prices, generally Dated Brent crude
oil (Brent), adjusted for transportation and quality. West Texas Intermediate
(WTI) normally trades at a premium to Brent, but the differential can vary
during the year. As the demand for Brent crude oil increases relative to WTI the
differential narrows, increasing the price of Brent on a relative basis. During
2002, we sold our Masila crude oil for an average discount of US $1.41/bbl to
WTI.

EXPLORATION BLOCKS

We are actively exploring outside the Masila Block. We hold interests in seven
exploration licenses comprising over 20 million acres of undeveloped land, the
majority of which are located in northeastern Yemen close to the Saudi Arabian
border. These blocks are governed by production sharing agreements that have
similar fiscal terms to the Masila Project.

BLOCK 50

We successfully farmed-out a portion of Block 50. A new partner is currently
funding an exploration program to earn an interest in the block. At the end of
the program our working interest will be 31.667%. We are currently evaluating
1,683 kilometres of 2D seismic acquired in the third quarter of 2002. Depending
on the results of this work, an exploration well may be drilled in 2003. To
date, all commitments have been fulfilled on this block.

BLOCK 51
Nexen has an 87.5% working interest in Block 51. We have participated in three
dry holes on the block. There is one remaining well commitment prior to block
expiry in October 2004. At this time we have not budgeted for any capital
spending on Block 51 for 2003, beyond annual fees.

NORTHERN BLOCKS

The Northern Blocks comprise five large exploration blocks (11, 12, 36, 54 and
59) that cover almost 13 million acres. They are located 250 km north of Masila
in an undeveloped frontier area bordering Saudi Arabia. We currently have a 57%
working interest on these blocks, except for Block 59 where we have a 55.8%
working interest. In 2002, an exploration well, Al Mawarid-1, was drilled on
Block 59. Although commercial quantities of hydrocarbons were not encountered,
the well provided valuable information to calibrate our seismic data and to
refine our geologic models for the region. In the third quarter of 2002, Nexen
received one-year extensions for Blocks 11, 12, 36, and 54, which were initially
due to expire in February 2003. This extension period will allow us to conduct
further technical work to evaluate the potential of the region.

CANADA

[CANADA MAP]

ACREAGE
(thousand acres) Developed Undeveloped Total
- ---------------------------------------------------------------------
Gross 968 2,870 3,838
Net 768 1,744 2,512
- ---------------------------------------------------------------------

Before After
PROVED RESERVES Royalties Royalties
- ---------------------------------------------------------------------
Crude Oil and NGLs
(mmbbls) 191 156
Natural Gas (bcf) 618 524
- ---------------------------------------------------------------------
Total (mmboe) 294 243

Before After
2002 PRODUCTION Royalties Royalties
- ---------------------------------------------------------------------
Light Oil (mbbls/d) 25.8 19.4
Heavy Oil (mbbls/d) 30.5 24.0
Natural Gas (mmcf/d) 167 128
- ---------------------------------------------------------------------
Total (mboe/d) 84.1 64.7
- ---------------------------------------------------------------------

Our strategy in Canada is to maximize value from our core operations while we
actively pursue emerging sources of supply in the western Canadian sedimentary
basin. These operations provide steady cash flow and earnings from our
established portfolio of light oil, heavy oil, and natural gas assets. We are
advancing three promising initiatives for future growth in our conventional
activities: high impact gas exploration, coal bed methane development and
enhanced recovery technology. Our exploration program targets high productivity
deep gas plays in northeast British Columbia and the foothills of Alberta. We
have a coal bed methane extraction pilot in central Alberta, and we are testing
enhanced oil recovery techniques on our heavy oil fields.

4

LIGHT OIL

We are the largest producer of light oil in southeast Saskatchewan where we have
a substantial land position in the Williston Basin. Production from the area is
characterized by medium depth, Mississippian age light oil. In 2002, 51 oil
wells were drilled on our lands. In 2003, we will sustain our operations through
selective development of our properties with horizontal drilling.

We continue to focus on the development and full exploitation of our Hay
property in northeast British Columbia. We discovered Hay in 1997 and brought
production on stream in April 2000; it is now the largest producing oil field in
British Columbia. In 2002, we produced our five millionth barrel from the field
and drilled 30 wells to increase productivity at low cost. In 2003, we will add
producing development wells to further exploit the existing pool. With the 2003
program, we plan to expand the existing water-handling capacity as well as drill
vertical wells to test the pool boundaries.

HEAVY OIL

There is a significant number of large heavy oil fields in western Canada and,
typically, finding costs for heavy oil are lower than for light oil. Heavy oil
is characterized by high specific gravity or weight, and high viscosity or
resistance to flow. Because of these features, heavy oil is more difficult to
extract, transport and refine than other types of oil. Additionally, heavy oil
reservoirs typically have lower recovery factors than conventional oil
reservoirs providing the opportunity for increased recovery with the application
of new technology. We are testing a number of different technologies to increase
oil recovery factors on our existing properties. Heavy oil yields a lower price
relative to light oil, because a smaller percentage of high value petroleum
products can be refined from a barrel of heavy oil than from a barrel of higher
quality crude without expensive refinery conversion capacity.

Our heavy oil operations are located in west central Saskatchewan. A strong
focus on finding and operating costs is fundamental to maximizing heavy oil
returns. Our large production base and existing infrastructure are important
factors in managing these costs. In 2002, a total of 51 heavy oil wells were
drilled and brought on production. A key success for heavy oil will be the
development of new technology to increase oil recovery.

NATURAL GAS

Approximately 48% of our natural gas production comes from shallow gas
properties. Shallow gas is natural gas produced from thin, shallow sand
formations predominantly located in southern areas of Alberta and Saskatchewan.
These reservoirs typically cover a broad geographical area yielding sweet,
low-pressure gas. In general, shallower gas targets are cheaper to drill and
develop, but have relatively smaller reserves and lower productivity per well.
During 2002, we drilled 130 shallow gas development wells. Our shallow gas
properties provide consistent returns and production as they approach full
development, and will continue to do so for years to come.

We are focused on gas exploration prospects in northeast British Columbia and
the foothills of Alberta, and the testing of coal bed methane for future growth.

DEEP GAS EXPLORATION

Northeast British Columbia is attractive because it is expected to contain
significant recoverable natural gas reserves. Winter-only access affects project
cycle time, but the area offers relatively good access to infrastructure, an
abundance of available acreage, and low drilling density. In 2002 and early
2003, we acquired an additional 9,000 net hectares of prospective lands. We
drilled three exploration wells that were unsuccessful. During the year we also
shot 200 km of 2D and 72 sq. km of 3D seismic and developed three deep
prospects. The winter program is in progress with three deep Slave Point wells
underway and a fourth planned for later in 2003 or early in 2004. Seismic
programs will also be undertaken on our lands this year.

In a highly competitive market, we have assembled a good land base in northwest
Alberta on trend with a number of foothills discoveries. In 2002, drilling
success in the foothills resulted in three high deliverability gas wells, each
capable of producing between 5 and 10 mmcf/d (gross). In 2003, we plan to drill
two exploratory wells to test multiple targets.

COAL BED METHANE

Coal bed methane (CBM) is an untapped resource for gas production in Canada, but
comprises 7% of the total gas supply in the United States. A given volume of
coal can hold anywhere from 2 to more than 10 times the volume of gas found in a
comparable conventional gas reservoir. Coal beds are usually saturated with
water, and in most cases, water must be produced before any gas can be produced.
De-watering the coal reduces pressure, allowing gas to "desorb" from the coal
and be produced. As the gas begins to drive water out, permeability to gas
increases, leading to increasing gas production rates. A typical CBM well shows
increasing gas production rates for a period of generally one to three years
before rates begin to decline.

5

Our CBM pilot project at Corbett is meeting expectations. We have increased our
understanding and land holdings in this exciting new resource. At Corbett we
strategically acquired an additional pilot project, increasing our total acreage
position to over 190 sections gross, of which we hold a 40% to 50% working
interest. We aligned ourselves with an experienced US CBM operator who has
recently moved into Canada, accelerating our understanding and operating
capabilities. Outside of Corbett, we have established a foothold in six new CBM
areas, positioning ourselves to rapidly accelerate our activities once we are
comfortable with the economic viability of the play.

ROYALTIES AND TAXES

In Canada, the federal and provincial governments impose royalties on oil and
gas production from lands where they own the mineral rights. Royalties vary
depending on factors such as well production volumes, selling prices, recovery
methods, drilling date of the well, and the date of initial production. Royalty
rates can range from 16% to 25%. Crown royalties are not deductible for tax
purposes as discussed below.

Some provinces also receive revenue by imposing taxes on production from lands
where they do not own the mineral rights. In addition, the Province of
Saskatchewan assesses a resource surcharge of 3.6% on gross Saskatchewan
resource sales. This surcharge has been reduced to 2.0% on wells completed after
October 1, 2002.

Profits earned in Canada from Canadian resource properties are subject to
federal and provincial income taxes. Canadian entities are also subject to
capital taxes. The federal capital tax rate is 0.225%. Provincial capital tax
rates vary from 0.15% to 0.64%. The federal income tax rate is 29% for resource
income allocated to Canadian provinces. Although crown royalties are not
deductible for tax purposes, a 25% deemed "resource allowance" on net Canadian
production income is deductible in computing taxes payable.

UNITED STATES

[UNITED STATES MAP]

ACREAGE
- ---------------------------------------------------------------------
(thousand acres) Developed Undeveloped Total
- ---------------------------------------------------------------------
Shallow-Water
Gross 175 162 337
Net 94 125 219
- ---------------------------------------------------------------------
Deep-Water
Gross 24 696 720
Net 9 286 295
- ---------------------------------------------------------------------
Total
Gross 199 858 1,057
Net 103 411 514
- ---------------------------------------------------------------------

Before After
PROVED RESERVES Royalties Royalties
- ---------------------------------------------------------------------
Crude Oil (mmbbls) 64 58
Natural Gas (bcf) 326 279
- ---------------------------------------------------------------------
Total (mmboe) 119 105
- ---------------------------------------------------------------------

Before After
2002 PRODUCTION Royalties Royalties
- ---------------------------------------------------------------------
Crude Oil (mbbls/d) 9.9 8.2
Natural Gas (mmcf/d) 112 93
- ---------------------------------------------------------------------
Total (mboe/d) 28.6 23.7
- ---------------------------------------------------------------------

Our oil and gas assets offshore in the US Gulf of Mexico are an important source
of production and reserves growth for Nexen. We currently hold interests ranging
from 3.7% to 100% in 190 federal lease blocks in the Gulf, 126 of which are
located in water depths exceeding 660 feet.

Our strategy is to fully exploit our assets in the shallow waters of the Gulf
while applying the expertise we have gained from over 20 years of operations in
the Gulf to explore deep-water leases and accelerate development of our
deep-water discoveries.

Royalties on our oil and gas production in the US average approximately 15% of
working interest volumes. Deep-water production including Aspen, qualifies for
royalty relief on the first 87.5 million equivalent barrels. Royalties on other
Gulf and state water properties range from 15% to 25%. Profits from our US
operations are subject to the US federal tax rate of 35%. State taxes in the
jurisdictions in which we operate range from 0% to 8%.

6

SHALLOW-WATER EXPLORATION AND PRODUCTION

Our shelf production comes from our shallow-water assets located offshore
Louisiana and Texas, primarily from our interests in three fields: Eugene Island
257/258/259, Vermilion 76 (consisting of blocks 57, 65, 66 and 67) and West
Cameron 148/170. We continue to exploit these assets, and to look for other
opportunities on the shelf.

In late 2001, we acquired 100% working interests at Vermilion 76 and at Eugene
Island 295. Since then we have drilled eight development wells at Vermilion 76,
and more than doubled field production to approximately 40 million cubic feet
per day.

In the second half of 2002, we experienced program delays and shut-in production
due to hurricane activity. Hurricane Lili caused extensive damage to our
production platform at Eugene Island 295, which has resulted in 100% of the
production being shut-in since October but is expected to return to producing
status during the first quarter of 2003.

In 2002, we signed an agreement with Shell Exploration and Production Company
(SEPCo) to jointly explore a 1,044 square-mile area on the shelf. We have a 40%
interest in this exploration area. The area of mutual interest (AMI) outlined in
the agreement is targeting natural gas in deep Miocene Age reservoirs. This play
is attractive as it has deep-water type reserve potential but is in close
proximity to existing infrastructure on the shelf. We drilled one exploratory
well in 2002 testing the deep Miocene Age reservoir but it resulted in a dry
hole.

DEEP-WATER EXPLORATION AND PRODUCTION

Over the past decade, the deep-water Gulf of Mexico has moved from an
exploration frontier to one of the most prospective sources of oil and gas
production in the world. The deep-water Gulf is generally characterized by
multiple productive horizons and high production rates, which greatly reduces
risk and improves economics. The technology to find, drill, and develop
deep-water discoveries is rapidly progressing and becoming more cost effective.
In addition, the deep-water Gulf is in close proximity to infrastructure and
continental US markets, allowing oil and gas discoveries to be quickly brought
on stream. Large discoveries, high success rates, production infrastructure and
attractive fiscal terms make this a premier exploration opportunity.

In 1997, we began building a deep-water acreage position, and are currently one
of the largest independent leaseholders. In 2000 and 2001, we had discoveries at
Aspen, Gunnison and Durango. Appraisal drilling justified proceeding with the
commercial development of both the Aspen and Gunnison sub-basins.

ASPEN

Aspen is located on Green Canyon Block 243 in 3,150 feet of water. In 2002, we
increased our interest from 20% to 60% and proceeded with development. The
project was developed using two subsea wells tied back to the Shell operated
Bullwinkle platform 16 miles away. Both wells were tied in and production
commenced in December 2002. In 2003, production is expected to average
approximately 25,000 equivalent barrels per day (15,000 net). Production from
Aspen is free of government royalties on the first 87.5 million equivalent
barrels. Netbacks here are expected to be about twice our corporate average. We
brought production on stream at Aspen just 19 months after the initial
discovery.

GUNNISON AND DURANGO DISCOVERIES (GUNNISON SUB-BASIN)

Gunnison, our second deep-water project in the Gulf, is on schedule for
production startup in early 2004. In 2001, our Board of Directors approved plans
to develop our 30% interest in the Gunnison and Durango Fields. This area is
located approximately 170 miles offshore Louisiana in water depths just over
3,100 feet, and includes Garden Banks Blocks 667, 668 and 669. Gunnison was
discovered in May 2000 on Garden Banks Block 668 and Durango was discovered in
June 2001 on Garden Banks Block 667. Gunnison is being developed using a truss
SPAR platform with design capacity of 40,000 barrels of oil per day and 200
million cubic feet of gas per day. The initial development plans include 10
wells connected to the SPAR, all of which have been drilled. We plan to fill
approximately 75% of the SPAR capacity with current development plans, leaving
room for growth. Production at Gunnison also benefits from the first 87.5
million equivalent barrels being free of government royalties.

We are continuing to explore the deep-water Gulf. In 2003, we plan to drill at
least five high-potential exploration wells, including deep-water tests in the
Alaminos Canyon, Green Canyon and Garden Banks areas, plus a deep Miocene gas
prospect on the shelf. Our Gotcha prospect in the Alaminos Canyon is of
particular interest, as it is adjacent to the recently discovered Great White
prospect. Additional wells could be drilled based on success and partner
priorities.

7

AUSTRALIA

[AUSTRALIA MAP]

ACREAGE
(thousand acres) Developed Undeveloped Total
- ---------------------------------------------------------------------
Gross 1 3,224 3,225
Net 1 3,224 3,225
- ---------------------------------------------------------------------

PROVED RESERVES
(mmbbls) Before Royalties After Royalties
- ---------------------------------------------------------------------
Buffalo Field 4 3
- ---------------------------------------------------------------------

2002 PRODUCTION
(mbbls/d) Before Royalties After Royalties
- ---------------------------------------------------------------------
Buffalo Field 12.8 10.3
- ---------------------------------------------------------------------

BUFFALO

The Buffalo field located offshore on the northwest shelf of Australia has been
an excellent source of short-term production growth. This field produces
high-quality crude oil that attracts a premium price. Production from Buffalo
began in December 1999 using a fixed wellhead platform linked to a leased
floating production storage and off-loading vessel (FPSO). In late 2000, we
acquired the remaining 50% interest in this field and became the operator.

As a result of an extensive 3D seismic reprocessing program in 2001, we
identified additional oil reserves that would not be recovered by the existing
production wells. In 2002, we successfully completed a two-well infill drilling
program which has allowed us to maximize our reserve recovery and has added
incremental recoverable reserves.

In Australia, profits from offshore production, less allowable capital
expenditures, are subject to Petroleum Resource Rent Tax (PRRT) at a rate of
40%. Any PRRT paid is deductible in computing corporate income tax. The
corporate income tax rate in Australia is 30%.

EXPLORATION PORTFOLIO

The experience, knowledge and infrastructure gained from our Buffalo operation
supports our exploration program in other basins offshore Australia.

In 2002, we completed our interpretation of 3,700 km of 2D seismic which
confirmed the existence of a prospect on NT/P59, a licence in the Money Shoals
Basin. We have a 100% working interest in this block. We relinquished licences
NT/P58 and NT/P60.

We have a 100% working interest in Block WA 239P in the Browse Basin, which
spans 1.2 million acres. In 2002, we continued interpretation of our 2D seismic
program and we have identified an exploration prospect.

We intend to find partners in 2003 to participate in further evaluation of these
prospects before committing to the next phase of the work program.

NIGERIA

[NIGERIA MAP]

ACREAGE
(thousand acres) Developed Undeveloped Total
- -------------------------------------------------------------------------
Gross 1 483 484
Net 1 108 109
- -------------------------------------------------------------------------

PROVED RESERVES
(mmbbls) Before Royalties After Royalties
- -------------------------------------------------------------------------
Ejulebe Field 1 1
- -------------------------------------------------------------------------

2002 PRODUCTION
(mmbbls/d) Before Royalties After Royalties
- -------------------------------------------------------------------------
Ejulebe Field 7.5 3.9
- -------------------------------------------------------------------------

8

BLOCK OML-109 - EJULEBE

We operate the Ejulebe field located in 45 feet of water on Block OML-109 in the
Niger Delta, approximately 15 km offshore Nigeria. Crude oil production from
Ejulebe is transported through a pipeline to a third-party owned FPSO where it
is made available for export. We operate the block under a risk service
contract, which requires us to provide exploration, development and operatorship
services and fund all costs in return for a service fee payable out of
production from the block.

BLOCK OPL-222

In 1998, we acquired a 20% interest in Block OPL-222, which includes 469,000
acres and is located approximately 50 miles offshore in water depths ranging
from 600 to 3,500 feet. In late 1998, the Ukot-1 exploration well, located in
approximately 2,600 feet of water, encountered three oil-bearing intervals and
flowed at a total rate of 13,900 barrels per day from two intervals. After an
extensive 3D seismic program, Usan-1 was drilled in 2002 as a follow-up to our
Ukot discovery. Usan was drilled to 9,000 feet in 2,500 feet of water and
contained several oil-bearing reservoirs. One zone was production tested and
flowed at a restricted rate of 5,000 barrels of oil per day. A multi-well
program to appraise and delineate our discoveries is in progress and is expected
to continue through the first half of 2003.

COLOMBIA

[COLOMBIA MAP]

ACREAGE
(thousand acres) Developed Undeveloped Total
- --------------------------------------------------------------------------
Gross 1 727 728
Net 1 548 549
- --------------------------------------------------------------------------

PROVED RESERVES
(mmbbls) Before Royalties After Royalties
- --------------------------------------------------------------------------
Guando 6 6
- --------------------------------------------------------------------------

2002 PRODUCTION
(mmbbls/d) Before Royalties After Royalties
- --------------------------------------------------------------------------
Guando 1.4 1.3
- --------------------------------------------------------------------------

BOQUERON BLOCK - GUANDO DISCOVERY

In 2000, we made our first discovery at Guando on the non-operated Boqueron
Block. Boqueron is located in the Upper Magdalena Basin of central Colombia,
approximately 45 km southwest of Bogota. Based on successful results from four
appraisal wells and three development wells, we submitted an application for
commerciality early in 2002. Our application was accepted by Ecopetrol, the
national oil company. Ecopetrol exercised their right to back into a 50%
interest in the development, reducing our interest from 40% to 20%. Under the
arrangement, our share of costs incurred on Ecopetrol's behalf before they
exercised their back-in right, are recoverable from future production.

Development drilling has been ongoing and a pilot program began in 2002 to test
waterflood opportunities. We expect water injection to begin early in 2003 with
results available as early as mid-year. Production from Guando is subject to a
5% to 25% royalty depending on daily production levels. The income tax rate in
Colombia is 35%.

EXPLORATION BLOCKS

In addition to Boqueron, we have interests in three exploration blocks in the
Upper Magdalena Basin, which together span 0.7 million gross acres. Villarrica,
Fusagasuga (Fusa) and El Descanso were acquired in 2000, Muisca in 2001 and
Andino in 2002. Fusa has been relinquished and El Descanso will be relinquished
in 2003. The table below describes activities that occurred in 2002:

9

BLOCK INTEREST (%) 2002 ACTIVITY
- -------------------------------------------------------------------------------------------------------------

Boqueron Exploration 40 Negotiated new terms for deeper pool exploration efforts
Villarrica 50 Conducted 2D seismic program
Fusa 50 Drilled Atadero-1 exploration well and relinquished the Block
El Descanso 50 Evaluated Orion-1 exploration well
Andino 100 Signed the Block in 2002
Muisca 100 Conducted surface geology program and relinquished a portion
of the Block

At Villarrica, evaluation of a recently acquired 2D seismic program is underway.
We also plan to conduct 2D seismic programs on Muisca, Andino and possibly
Boqueron subject to successful negotiations with Ecopetrol on new contractual
terms. On all blocks except Boqueron, which is subject to a 50% back-in,
Ecopetrol retains the right to back-in at the declaration of commerciality for a
30% interest. We have various exploration commitments on each block that
normally include initial seismic reprocessing, followed by a 2D seismic program,
and finally an exploration well. We have the right to exit each block at the end
of the exploration phase.

BRAZIL

In 2002, we acquired the right to earn a 20% interest in a 2,060 sq. km
exploration license in Block BC-20 located in the Campos Basin, approximately
100 km offshore Brazil, by way of a farm-in arrangement. This provides us with a
strategic entry into Brazil and enables us to build on our offshore knowledge in
an under-explored basin. Block BC-20 offers several 2D seismically defined
exploration prospects on trend with recent discoveries on adjacent blocks. The
first well in a two-well drilling commitment was drilled in late 2002. We
encountered no economic hydrocarbons. We plan to drill a second well on this
block in the first half of 2003. If this second well is successful, we are
committed to drill a third exploration well on the block.

SYNTHETIC CRUDE OIL

A key part of Nexen's strategy is the economic development of our bitumen
resource to provide low risk, stable future growth.

We have a 7.23% joint venture interest in Syncrude Canada Ltd. (Syncrude).
Syncrude mines shallow deposits of oil sands in Canada, extracts the bitumen and
upgrades it to produce synthetic crude oil. We also have interests in numerous
oil sands leases in the Athabasca region of northern Alberta and have acquired
the rights to proprietary, patent-protected technology to upgrade bitumen
recovered from these leases.

SYNCRUDE JOINT VENTURE

[SYNCRUDE MAP]

ACREAGE
(thousand acres) Developed Undeveloped Total
- -------------------------------------------------------------------------
Gross 106 152 258
Net 8 11 19
- -------------------------------------------------------------------------

PROVED RESERVES
(mmbbls) Before Royalties After Royalties
- -------------------------------------------------------------------------
264 226
- -------------------------------------------------------------------------

2002 PRODUCTION
(mmbbls/d) Before Royalties After Royalties
- -------------------------------------------------------------------------
16.6 16.5
- -------------------------------------------------------------------------

10

Our 7.23% interest was acquired in 1983. Syncrude was created in 1975 to mine
shallow deposits of oil sands and extract and upgrade crude oil bitumen into a
high-quality, light, synthetic crude oil. The oil sands are located on eight
leases spanning 258,000 acres north of Fort McMurray, Alberta. Since startup in
1978, Syncrude has produced over 1.3 billion barrels of synthetic crude oil. The
operating term for leases controlled by Syncrude currently extends to the year
2035. However, Syncrude can hold the leases for 80 years if there are plans to
develop them. Syncrude mines oil sands at three mines: Base, North and Aurora.
Approximately two tons of oil sands are required to produce one barrel of
synthetic crude oil. The oil sands must be mixed with water to form a slurry.
Air and certain chemicals are added to separate bitumen from the sand grains.
The process at the Base Mine involves hot water, steam and caustic soda to
create a slurry, while at the North Mine and the Aurora Mine the oilsands are
mixed with warm water to produce a slurry. The slurries are transported to
extraction facilities where they are treated to remove water and solids. The
bitumen product is fed into a vacuum distillation tower and two cokers for
primary upgrading. The resulting products are then separated into naphtha, light
gas oil and heavy gas oil streams. These streams are hydrotreated to remove
sulphur and nitrogen impurities and are mixed together to form light, sweet
synthetic crude oil. Sulphur and coke, which are by-products of the process, are
stockpiled for possible future sale.

The quality of Syncrude's synthetic crude oil typically allows it to be sold at
a premium to WTI, adjusted for transportation, quality and currency differences.

EXPANSIONS

In 1999, the Alberta Energy and Utilities Board (AEUB) approved an increase in
Syncrude's production capacity to 465,700 barrels per day. At the end of 2001,
Syncrude had increased its synthetic crude oil capacity to 246,500 barrels per
day with the development of the Aurora Mine. In 2001, the Syncrude owners
approved the third stage of the Syncrude expansion, which will increase capacity
to 356,000 barrels per day (25,750 barrels net) by early 2005. Due to higher
engineering, manufacturing, and construction costs, the estimated costs of the
Stage 3 expansion have increased from initial estimates of $4.1 billion ($320
million net) to $5.7 billion ($412 million net).

ROYALTIES

Syncrude pays a royalty to the Province of Alberta. Subsequent to 1987, this
royalty was equal to 50% of Syncrude's deemed net profits after deduction of
certain capital expenditures. In 1995, the Province announced generic royalty
terms for new oil sands projects that provide for a royalty rate of 25% on net
revenues after all costs have been recovered, subject to a minimum 1% gross
royalty. In 1997, the Province of Alberta and the Syncrude owners agreed to move
to the generic royalty terms when the total of all allowed capital costs
incurred after December 31, 1995 equaled $2.8 billion (gross). That total was
surpassed at the end of 2001, and so Syncrude moved to generic terms in January
2002.

During the transition period, the Province of Alberta's share of deemed net
profits was based on a weighted average blended rate comprising a 50% net
profits interest on base production of 74 million barrels per year, and a 25%
net profits interest on annual production over 74 million barrels. In addition,
43% of allowed capital costs were applied as a deduction from the Province of
Alberta's share of the deemed net profits.

2002 2001 2000
- ---------------------------------------------------------------------------
Effective annual Syncrude
royalty rates on gross production 1% 4% 17%

PREMIUM SYNTHETIC CRUDE OIL PROJECT AT LONG LAKE, ALBERTA

[NORTHERN ALBERTA MAP]

We have interests in numerous oil sands leases in the Athabasca region of
northern Alberta - one of the largest non-conventional oil deposits in the
world. These bitumen resources can be produced using Steam Assisted Gravity
Drainage (SAGD), a technology now being commercialized at several locations in
the region. SAGD involves the drilling of two parallel horizontal wells,
generally between 2,300 and 3,300 feet in length with about 16 feet of vertical
separation. Steam is injected into the shallower well, where it heats the
bitumen that then flows by gravity to the deeper producing well. Recovery
factors of 50% to 70% of the oil-in-place are possible with this technology. We
have interests in SAGD projects at various stages of development including a 50%
interest in a joint venture with OPTI Canada Inc. (OPTI).

11

OPTI JOINT VENTURE

In 2001, we formed a joint venture with OPTI to develop in-situ bitumen using
SAGD technology, and to construct a field upgrading facility on the Long Lake
property, incorporating OPTI's patented OrCrude(TM) technology. As part of the
agreement, Nexen acquired the exclusive right with OPTI to use the technology
within a radius of approximately 100 miles of the Long Lake property, and the
right to use the technology elsewhere in the world.

The OrCrude(TM) technology converts bitumen into partially upgraded sour crude
oil and liquid asphaltenes. A 500-barrel per day demonstration plant applying
this technology has been successfully upgrading bitumen from the Cold Lake and
Athabasca regions since April 2001. By coupling the OrCrude(TM) process with
commercially available hydrocracking and gasification technologies, the sour
crude will be upgraded to light (37(0) to 43(0) API) premium synthetic crude oil
and the asphaltenes will be converted to a low-energy, synthetic fuel gas
containing free hydrogen (for use in the upgrading process). We estimate the
capital costs of producing and upgrading bitumen based upon this technology will
be comparable to those of surface mining and upgrading on a barrel of daily
production basis. In addition, the project will have significantly lower price
risk on input costs, since it manufactures its hydrogen and fuel gas from
internally produced asphaltenes rather than purchased natural gas.

An application to construct a 70,000 barrel per day SAGD project and an
integrated 70,000 barrel per day input (60,000 barrel per day premium synthetic
crude output) upgrader at Long Lake (Lease 27) was submitted to the Province of
Alberta and regulatory approval is anticipated in 2003. In order to optimize
well design, a three-well pair SAGD pilot project at Long Lake is currently
under construction and we expect bitumen production to begin in June 2003.
Commercial production of bitumen is expected in the second half of 2006 before
the upgrader is constructed. Upon successful completion of engineering studies
now being carried out and the receipt of required approvals, engineering and
construction of the commercial project will commence, with a target completion
date in 2007. We are the operator of the Long Lake lease and will be responsible
for construction, development and operation of the SAGD projects. OPTI will be
responsible for design, construction and operation of the upgrader.

The royalty terms are consistent with the generic royalty terms for oil sands
projects that provide for a royalty rate of 25% on net revenues after all costs
have been recovered, subject to a minimum 1% gross royalty.

RESERVES, PRODUCTION AND RELATED INFORMATION

In addition to the tables below, we refer you to the Supplementary Financial
Information in this Form 10-K for information on our oil and gas producing
activities. Nexen has not filed with nor included in reports to any other United
States federal authority or agency, any estimates of total proved crude oil or
natural gas reserves since the beginning of the last fiscal year.

NET SALES BY PRODUCT

(Cdn$ millions) 2002 2001 2000
- --------------------------------------------------------------------------------
Conventional Crude Oil and Natural Gas Liquids 1,637 1,421 1,652
Synthetic Crude Oil 245 225 199
Natural Gas 347 497 425
--------------------------
2,229 2,143 2,276
==========================

Crude oil and natural gas liquids represent approximately 84% of oil and gas
sales, while natural gas represents the remaining 16%.

SALES PRICES AND PRODUCTION COSTS
(Based on working interest production after royalties)

AVERAGE SALES PRICE(1) AVERAGE PRODUCTION COSTS(1)
- ---------------------------------------------------------------- --------------------------------
2002 2001 2000 2002 2001 2000
------------------------------- --------------------------------

Crude Oil and NGLs ($/bbl)
Yemen 38.80 35.05 40.53 4.13 3.47 3.03
Canada 30.84 24.86 33.49 8.98 7.90 7.17
United States 38.87 38.35 44.18 10.95 7.24 6.04
Australia 40.30 38.71 41.05 12.14 14.38 6.92
Other Countries 38.96 37.35 40.13 10.69 9.94 9.69
Synthetic Crude Oil 40.89 39.90 44.84 19.26 20.29 22.20

Natural Gas ($/mcf)
Canada 3.57 5.02 4.38 0.70 0.54 0.62
United States 5.29 6.66 6.90 1.83 1.21 1.01

Note:
(1) Prices and unit production costs are calculated using our working interest
production after royalties.

12

PRODUCING OIL AND GAS WELLS

(number of wells) 2002
- --------------------------------------------------------------------------------------------------------------------
OIL GAS TOTAL
----------------------- ------------------------ ------------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)

Yemen 259 135 -- -- 259 135
Canada 3,886 2,402 2,364 2,081 6,250 4,483
United States 192 87 245 123 437 210
Colombia 19 4 -- -- 19 4
Australia 4 4 -- -- 4 4
Nigeria 3 3 -- -- 3 3
----------------------- ------------------------ ------------------------
Total 4,363 2,635 2,609 2,204 6,972 4,839
======================= ======================== ========================

Notes:
(1) Gross wells are the total number of wells in which an interest is owned.

(2) Net wells are the sum of fractional interests owned in gross wells.

OIL AND GAS ACREAGE

(thousands of acres) 2002
- ---------------------------------- -------------------------------------------------------------------------
DEVELOPED UNDEVELOPED(1) TOTAL
---------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net

Yemen (2) 38 20 20,150 10,365 20,188 10,385
Canada 968 768 2,870 1,744 3,838 2,512
United States 199 103 858 411 1,057 514
Australia 1 1 3,224 3,224 3,225 3,225
Nigeria(2)(3) 1 1 483 108 484 109
Colombia(4) 1 1 727 548 728 549
Brazil -- -- 509 102 509 102
----------- ---------- --------- ----------- --------- -----------
Conventional Total 1,208 894 28,821 16,502 30,029 17,396
=========== ========== ========= =========== ========= ===========

Synthetic Crude Total 106 8 152 11 258 19
=========== ========== ========= =========== ========= ===========

Notes:
(1) Undeveloped acreage is considered to be those acres on which wells have not
been drilled or completed to a point that would permit production of
commercial quantities of crude oil and natural gas regardless of whether or
not such acreage contains proved reserves.

(2) The acreage is covered by production sharing contracts.

(3) The acreage is covered by a risk service contract.

(4) The acreage is covered by an association contract.

DRILLING ACTIVITY

(number of net wells) 2002
- --------------------------- --------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
-------------------------------------- -------------------------------------------
Productive Dry Holes Total Productive Dry Holes Total Total

Yemen -- 0.6 0.6 38.0 1.0 39.0 39.6
Canada 16.0 4.0 20.0 225.0 8.0 233.0 253.0
United States -- 1.4 1.4 14.9 0.6 15.5 16.9
Australia -- -- -- 2.0 -- 2.0 2.0
Other Countries (1) 0.2 0.7 0.9 2.0 0.2 2.2 3.1
-------------------------------------- ------------------------------------------ ------------
Total 16.2 6.7 22.9 281.9 9.8 291.7 314.6
====================================== =======================================================

2001
- --------------------------- --------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
-------------------------------------- ------------------------------------------
Productive Dry Holes Total Productive Dry Holes Total Total

Yemen -- 1.5 1.5 30.7 1.6 32.3 33.8
Canada 38.6 20.8 59.4 369.9 8.3 378.2 437.6
United States 3.8 1.2 5.0 5.3 -- 5.3 10.3
Australia -- 0.4 0.4 -- -- -- 0.4
Other Countries (1) 1.2 2.9 4.1 1.8 0.4 2.2 6.3
------------ ------------- ----------- ------------- ------------- -------------- ------------
Total 43.6 26.8 70.4 407.7 10.3 418.0 488.4
============ ============= =========== ============= ============= ============== ============

13

DRILLING ACTIVITY (CONTINUED)

2000
- --------------------------- --------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
-------------------------------------- ------------------------------------------
Productive Dry Holes Total Productive Dry Holes Total Total

Yemen -- -- -- 13.5 2.1 15.6 15.6
Canada 39.5 20.2 59.7 379.4 16.5 395.9 455.6
United States 1.9 2.5 4.4 8.1 1.5 9.6 14.0
Australia -- 0.9 0.9 -- -- -- 0.9
Other Countries(1) 1.2 1.8 3.0 -- -- -- 3.0
------------ ------------- ----------- ------------- ------------- -------------- ------------
Total 42.6 25.4 68.0 401.0 20.1 421.1 489.1
============ ============= =========== ============= ============= ============== ============

Note:
(1) Other countries include drilling primarily in Nigeria, Colombia and Brazil.

At December 31, 2002, we were in the process of drilling 1 well (0.3 net) in the
United States, 8 wells (4.2 net) in Canada, 4 wells (2.1 net) in Yemen, 1 well
(0.2 net) in Nigeria, and 1 well (0.2 net) in Colombia.

OIL AND GAS MARKETING

Our marketing operation sells our own crude oil and natural gas production,
markets third-party crude oil and natural gas and engages in energy trading
through the use of both physical and financial contracts (energy trading
activities). These activities are intended to enhance price realizations from
selling both proprietary and third-party oil and gas production, provide market
and business intelligence in support of our oil and gas growth activities, and
contribute independent earnings and cashflow.

We focus on four key areas: domestic oil marketing and trading, domestic gas
marketing and trading, international oil marketing and trading, and producer
services and transportation. Each area is involved in the purchase, transport,
storage and sale of oil or natural gas from the point of production to end-use
customers. We also trade on active markets such as the New York Mercantile
Exchange and the International Petroleum Exchange as part of our total
portfolio. We have offices in Calgary, Houston, Denver, Detroit, and Singapore
to service our key market areas.

Our marketing operation also owns transportation assets and has investments in
third-party controlled gas-processing facilities. Transportation assets include
pipelines and batteries in the Lloydminster area as well as the Hay pipeline. In
addition, we manage various natural gas transportation commitments on behalf of
our Canadian oil and gas business segment and third-party clients. These
management arrangements help optimize our energy trading activities. Our
marketing operations are more fully described in Item 7.

CHEMICALS OPERATIONS

Over the past three years, we have made significant investments to grow our
capacity, expand internationally and lower our overall cost structure. These
investments have allowed us to maintain a strong position in the bleaching
chemicals industry. We manufacture, market and distribute sodium chlorate and
chlor-alkali products (chlorine, caustic soda and muriatic acid) in Canada, the
United States and Brazil. We also market a small amount of sodium chlorate and
caustic soda in Asia.

AVERAGE ANNUAL PRODUCTION CAPACITY 2002 2001 2000
- --------------------------------------------------------------------------------
Sodium Chlorate (short-tons)
North America 500,650 474,250 461,470
Brazil 57,320 42,550 39,000
- --------------------------------------------------------------------------------
Total 557,970 516,800 500,470
- --------------------------------------------------------------------------------
Chlor-alkali (short-tons)
North America 351,844 351,844 351,844
Brazil 97,462 90,078 75,055
- --------------------------------------------------------------------------------
Total 449,306 441,922 426,899
- --------------------------------------------------------------------------------

The key factors driving the bleaching chemicals market are reliability of supply
and technical service, and price. Our manufacturing facilities are modern and
reliable, and strategically located to capitalize on competitive power costs and
transportation infrastructure in order to minimize production and delivery
costs. Electricity is the single largest cost incurred by our operations,
representing over half of our cash costs. Other primary raw materials used in
the production of sodium chlorate and chlor-alkali products are salt and fresh
water. We secure long-term contracts for these materials to ensure sufficient
supply and competitive costs. Labour is also a significant component of the
manufacturing costs, with approximately 50% of our chemicals' workforce being
unionized. We have active collective agreements in place at all of our unionized
plants.

14

NORTH AMERICA

[NORTH AMERICA MAP]

We manufacture sodium chlorate at six facilities in North America: Nanaimo,
British Columbia; Bruderheim, Alberta; Brandon, Manitoba; Amherstburg, Ontario;
Beauharnois, Quebec; and Taft, Louisiana. We also manufacture chlor-alkali
products at North Vancouver, British Columbia.

In 1995, we combined our industrial chemicals operations in North America with
Occidental's sodium chlorate facility located at Taft, Louisiana. We held an 85%
interest in the venture and acted as managing partner. During 2000, we exchanged
our oil and gas operations in Ecuador for Occidental's 15% interest in our
chemicals operations. We now own 100% of our chemicals operations.

The pulp and paper industry consumes approximately 95% of sodium chlorate
production in North America. Our North American sodium chlorate production is
marketed to numerous pulp and paper mills under multi-year contracts that
contain price and volume provisions. Approximately 25% of this production is
sold in Canada and the remainder is sold in the US, with a small component
marketed offshore. In 2002, we completed an expansion of our Brandon plant in
Manitoba.

Our chlor-alkali facility in British Columbia manufactures caustic soda,
chlorine and muriatic acid. In British Columbia, almost all of our caustic soda
is consumed by local pulp and paper mills, while our chlorine is sold to various
customers in the polyvinyl chloride, water purification and petrochemicals
industries, primarily in the United States.

BRAZIL

[SOUTH AMERICA MAP]

In December 1999, we acquired a 39,000 short-ton per year sodium chlorate plant
and a 35,000 short-ton per year chlor-alkali plant in Brazil from Aracruz
Cellulose S.A., the leading manufacturer of pulp in Brazil. Substantially all of
our production is sold to Aracruz under a long-term sales agreement that has an
initial six year take-or-pay component. In 2002, we completed an expansion of
both the chlorate and chlor-alkali facilities to meet Aracruz's expansion needs.

OTHER ACTIVITIES

MOOSE JAW ASPHALT

Nexen owned Moose Jaw Asphalt Inc., which produced asphaltic paving products,
petroleum-derived fuels and specialty distillates. Effective January 2, 2002, we
sold Moose Jaw Asphalt. The financial results of this operation for 2001 and
2000 are included in Corporate and Other Items in note 15 to the Consolidated
Financial Statements.

POWER GENERATION FACILITY

In 2000, we committed to enter into a lease agreement upon the completion of
construction of a 106 Megawatt (MW) high-efficiency power start up generation
facility. The facility was constructed at our operated Balzac gas plant located
near Calgary, Alberta and began operations during the fourth quarter of 2001. In
2002, we refinanced the lease and purchased the facility for $67 million, which
was the cost of construction plus interest on advances during the construction
phase. We included this amount in capital expenditures for the year ended
December 31, 2002. The average load for 2002 was 17.8 MW which is expected to
increase in 2003. The financial results of the power generation facility are
included in Corporate and Other Items in note 15 to the Consolidated Financial
Statements.

15

ADDITIONAL FACTORS AFFECTING BUSINESS
See Item 7 of this Form 10-K.

GOVERNMENT REGULATIONS

Our operations are subject to various levels of government controls and
regulations in the countries in which we operate. These laws and regulations
include matters relating to land tenure, drilling, production practices,
environmental protection, marketing and pricing policies, royalties, various
taxes and levies including income tax, and foreign trade and investment, all of
which are subject to change from time to time. Current legislation is generally
a matter of public record, and we are unable to predict what additional
legislation or amendments may be proposed that will affect our operations or
when any such proposals, if enacted, might become effective. However, we do
participate in many industry and professional associations and otherwise monitor
the progress of proposed legislation and regulatory amendments.

ENVIRONMENTAL REGULATIONS

OIL AND GAS OPERATIONS

Our oil and gas operations are subject to government laws and regulations
designed to protect the environment in the countries where we operate. We
believe that our operations comply in all material respects with applicable
environmental laws.

CANADA

In Canada, these provisions, which are implemented principally by Environment
Canada, Transport Canada and comparable provincial agencies, govern the
management of hazardous waste, the discharge of pollutants, the construction of
new discharge sources and the transportation of dangerous goods. The laws
generally provide for civil and criminal penalties and fines, as well as
injunctive and remedial relief.

UNITED STATES

In the United States, these provisions, which are implemented principally by the
United States Environmental Protection Agency, the Department of Transportation,
the Department of the Interior and comparable state agencies, govern the
management of hazardous waste, the discharge of pollutants into the air and into
surface and underground waters, the construction of new discharge sources, the
manufacture, sale and disposal of chemical substances, and surface and
underground mining. These laws generally provide for civil and criminal
penalties and fines, as well as injunctive and remedial relief.

YEMEN

In Yemen, the Yemen Environmental Protection Law was ratified by Parliament and
issued by Presidential decree in October 1995. Yemen Republican Decree No. 11 in
respect of Protection of the Maritime Environment from Pollution was passed in
1993 and establishes the Public Corporation for Maritime Affairs as the
regulatory authority for maritime activities. Under the terms of an agreement
with the Government of Yemen in March 1996, we prepaid the dismantlement and
site restoration costs on the Masila Block Development Project, and were
released from any further obligation relating to these costs on this block.

NIGERIA

In Nigeria, we have a risk service contract on Block OML-109 with an indigenous
company. The indigenous company is responsible for obtaining all regulatory
approvals associated with development in Nigeria. Pollution control regulations
in oil and gas operations are governed by the Principal Legislation of Petroleum
Act 1969. The regulations are made pursuant to section 8(i)b(iii) of the
Petroleum Act. Revisions to existing regulations regarding waste discharges,
environmental management systems, audits, decommissioning and oil spillage
investigation were to have been issued before the end of 1999 but have been
delayed. In November 1999, the Federal Ministry of the Environment announced
that, pursuant to the Environmental Impact Assessment (EIA) Decree No. 86 of
1992, they have been charged with full responsibility for supervising all
aspects of the environmental management of the oil and gas industry, replacing
the environment division of the Department of Petroleum Resources and the
defunct Federal Environmental Protection Agency. The timing and implications of
these changes have yet to be determined.

16

AUSTRALIA

In Australia, the offshore petroleum industry is regulated by broadly consistent
Commonwealth, State and Territory legislation. The States and Northern Territory
have jurisdiction over onshore petroleum operations, including petroleum within
coastal waters. Petroleum operations beyond three nautical miles from the
territorial sea baseline are subject to the Commonwealth Petroleum (Submerged
Lands) Act 1967 (PSLA). The key subordinate and related legislation which impact
offshore health and safety are the Petroleum (Submerged Lands) (Management of
Safety on Offshore facilities) Regulations 1996 and the State and Northern
Territory OH&S Acts and Regulations, which are applied through Section 9 of the
PSLA. Other State and Territory laws are applied to offshore areas through
Section 11 of the PSLA. There are generally two administrative decision-making
bodies in respect of each offshore area; a Joint Authority, comprising the
Commonwealth Minister responsible for resources and the equivalent State or
Northern Territory Minister, which is the principle decision-making body, and a
Designated Authority, which handles the day-to-day administrative matters
relating to petroleum activities in the defined area. Titleholders under the
PSLA are responsible for all petroleum related activities (including safety) in
the permit/licence area. The designated representative of the titleholder is the
operator. In July of 2000, the Environmental Protection and Biodiversity
Conservation Act became law. Under this Commonwealth Act, operators are required
to assess their projects to determine whether an action is likely to have a
significant impact on matters of national environmental significance, and make a
decision respecting submission of that assessment to a public referral process.
The referral is expected to add some time to the existing approval process but
have little impact on most routine activities and operations.

COLOMBIA

In Colombia, operations are subject to environmental regulations under the
Ministry of the Environment. Community consultation is regulated by the Ministry
of the Interior. The basic process, which results in an average time to receipt
of license of between one and three years, starts with the Ministry of Interior
requirements for community consultation, followed by preparation of the required
environmental impact assessment and management plans, followed by review within
the Ministry of the Environment and the regional environmental authorities.
Recent attempts to streamline issuance of hydrocarbon licenses have been renewed
under the new Uribe government.

From time to time, we may conduct activities in countries where environmental
regulatory frameworks are in various stages of evolution. Where regulations are
lacking, we observe Canadian standards where applicable, as well as
internationally accepted industry environmental management practices.

KYOTO PROTOCOL

For a discussion of the Kyoto Protocol, see the Business Risk Management section
in Item 7.

SYNCRUDE OPERATIONS

Syncrude is regulated by the AEUB and the Alberta Department of Environment
(AENV). In 1999, the AEUB extended Syncrude's operating term through 2035 giving
the flexibility required for ongoing orderly development of the operation and
reclamation of the site. The AENV issued its approval under the Alberta
Environmental Protection and Enhancement Act effective December 21, 1995. The
approval is for the 10-year period through to December 2005, which is the
maximum term provided for in the legislation, and is a consolidated document
covering air, land, water and waste management matters. Land reclamation is
proceeding at a rate of approximately 200 hectares per year, thereby minimizing
annual future reclamation costs.

CHEMICALS OPERATIONS

We maintain an active environmental and safety program at our chemicals sites to
further our goal of excelling as a Responsible Care(R) Organization. Many of our
chemicals facilities (i.e. Amherstburg, Beauharnois, Brandon, Bruderheim,
Nanaimo, and North Vancouver) have completed quantitative risk assessments to
assist both the facilities and the communities in their emergency response and
risk management plans. The results of these reviews have been communicated to
each respective community.

Since 1972, our North Vancouver facility has been the British Columbia regional
control center for the North America Chlorine Emergency Plan. Through this plan,
we participate with other chlorine producers to provide professional and
responsive action in the event of a chlor-alkali related emergency anywhere in
their region of responsibility.

We have taken an active role in the Canadian Chemical Producers' Association
(CCPA), CAER (Community Awareness and Emergency Response) and TRANSCAER
(Transportation CAER) projects. In 1989, we and other members of the CCPA
expanded the CAER and TRANSCAER programs to the Responsible Care(R) initiative.
This initiative is based on the industry's commitment to the responsible
development, manufacture, transportation, handling, distribution, use and
ultimate disposal of chemicals so as to minimize adverse effects on people and
the environment. We successfully completed the

17

CCPA's Round 1 Responsible Care(R) verification process in 1995. In 1998, we
were the first company to undergo Round 2 verification of our Responsible
Care(R) management systems. In 2000, our Taft facility successfully completed a
third-party American Chemistry Council Responsible Care(R) Management System
Verification to ensure compliance to the Responsible Care(R) codes of practice
in the United States. In 2002, we completed a CCPA Round 3 Responsible Care(R)
reverification.

Regulations that apply to our pulp and paper customers are significant to our
chemicals operations. In January 1992, the Province of British Columbia amended
the PULP MILL AND PULP AND PAPER MILL LIQUID EFFLUENT CONTROL REGULATION to
require all British Columbia pulp mills to achieve a zero AOX (Absorbable
Organic Halogens) effluent discharge standard from their bleaching processes by
the end of 2002. In June 2002, the Province of British Columbia announced that
it would amend the Regulation to require all British Columbia pulp mills to meet
a new effluent discharge standard of 0.5 kilogram/Air Dried tonne AOX annual
average. Currently, all British Columbia pulp mills are complying with the new
standard.

Operations in the United States are also subject to various federal and state
laws and regulations which govern the management of hazardous waste, the
discharge of pollutants into the air and into surface and underground waters,
the construction of new discharge sources, and the manufacture, sale and
disposal of chemical substances.

The Aracruz facility in Brazil operates in accordance with a number of federal
and state laws and regulations, as well as a new civic environmental policy for
the city of Aracruz. These regulations address various aspects of environmental
management, including environmental zoning for industrial applications,
assessment of environmental impacts and licensing of activities that may impact
the environment.

Our Brazil chemicals operation is a member of the Brazilian Industrial Chemical
Association (ABIQUIM) and is committed to the ABIQUIM Responsible Care
initiative. We are currently implementing management systems in Brazil to
fulfill the Responsible Care Codes of Practice, with implementation scheduled
for completion in 2003.

OTHER ACTIVITIES

Our Balzac gas plant and power generation facility received Round 1 Responsible
Care(R) verification in 2002.

ENVIRONMENTAL PROVISIONS AND EXPENDITURES

At December 31, 2002, $205 million has been provided in the accounts for future
dismantlement and site restoration costs, which are currently estimated at
approximately $544 million for all of our oil and gas and chemicals facilities.
During 2002, we recorded a provision for future dismantlement and site
restoration costs of $43 million.

During 2002, our capital expenditures for environmental-related matters,
including environment control facilities, were approximately $20 million. Our
operating expenditures for environmental-related matters were approximately $6
million. Environmental related capital expenditures in 2003 are expected to be
similar to 2002.

EMPLOYEES

At December 31, 2002, we had 2,767 employees in the following operations - Oil
and Gas: Canada 575, United States 165, International 1,028 (Yemen 817, Canada
and other areas 211); Chemicals 459; Oil and Gas Marketing 105, Corporate 336
and Technical Services 99. These totals include 744 national employees in the
following countries - Colombia 25, Australia 16, Nigeria 25, Brazil 52, and
Yemen 626.

Approximately 50% of the employees of our Chemicals operations are unionized.
The unionized facilities are located at North Vancouver, Squamish, and Nanaimo,
British Columbia; Brandon, Manitoba; Beauharnois, Quebec and Aracruz, Brazil.
Union contracts at Nanaimo and Beauharnois are in effect until 2003 and until
2004 for Squamish, Brandon, and North Vancouver. Union contracts in Brazil are
renewed on an annual basis.

Approximately 10% of the employees of our Canadian oil and gas operations are
unionized. Unionized facilities are located at Balzac, Alberta, with a contract
in effect until 2004.

Information on our executive officers is presented in Item 10 of this report.

18

ITEM 3. LEGAL PROCEEDINGS

There are a number of lawsuits and claims pending against Nexen, the ultimate
results of which cannot be ascertained at this time. Management is of the
opinion that any amounts assessed against us would not have a material adverse
effect upon our consolidated financial position or results of operations.

Nexen received an order on February 17, 1999, under the British Columbia Waste
Management Act to conduct a comprehensive remediation program, including soil
and ground water remediation, with respect to our former chlor-alkali plant site
at Squamish, British Columbia. The Order is within the scope of contemplated and
accrued environmental remediation requirements for the former plant site and
does not constitute a fine or penalty upon Nexen. We are in compliance with the
Order.

Nexen's US operations have received, over the years, notices and demands from
the United States Environmental Protection Agency, state environmental agencies,
and certain third parties seeking to require investigation and remediation under
federal or state environmental statutes. Although no assurances can be made, we
believe our US operations are protected from any present or future material
liabilities that may arise from these sites because of Assumption and
Indemnification Agreements in place.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of Nexen's Security holders during the
fourth quarter of 2002.

19

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON SHARES AND RELATED STOCKHOLDER
MATTERS

Nexen's common shares are traded on the Toronto Stock Exchange and the New York
Stock Exchange under the symbol NXY.

On December 31, 2002, there were 1,372 registered holders of common shares and
122,965,830 common shares outstanding. The number of registered holders of
common shares is calculated excluding individual participants in securities
positions listings.

TRADING RANGE OF NEXEN'S COMMON SHARES
TORONTO NEW YORK
($/share) STOCK EXCHANGE STOCK EXCHANGE
- --------------------------------------------------------------------------------
HIGH LOW HIGH LOW
(cdn$) (US$)
2002
First Quarter 39.75 29.70 25.11 18.57
Second Quarter 42.50 37.20 28.04 23.30
Third Quarter 42.18 34.34 27.71 21.70
Fourth Quarter 37.78 31.00 23.85 19.79

2001
First Quarter 39.90 31.00 25.77 20.69
Second Quarter 40.65 32.40 26.61 20.60
Third Quarter 41.50 28.10 26.12 17.95
Fourth Quarter 35.21 29.51 22.39 18.73
---------------------------------------

QUARTERLY DIVIDENDS ON COMMON SHARES FIRST SECOND THIRD FOURTH
($/share) QUARTER QUARTER QUARTER QUARTER
- --------------------------------------------------------------------------------
2002 0.075 0.075 0.075 0.075
2001 0.075 0.075 0.075 0.075
---------------------------------------

Payment date for dividends was the first day of the next quarter.

The Income Tax Act of Canada requires us to deduct a withholding tax from all
dividends remitted to non-residents. In accordance with the Canada-US Tax
Treaty, we have deducted a withholding tax of 15% on dividends paid to residents
of the United States, except in the case of a company that owns at least 10% of
the voting stock where the withholding tax is 5%.

The Investment Canada Act requires that a "non-Canadian" (as defined) file
notice with Investment Canada and obtain government approval prior to acquiring
control of a "Canadian business" (as defined). Otherwise, there are no
limitations, either under the laws of Canada or in Nexen's charter on the right
of a non-Canadian to hold or vote Nexen's securities.

On February 3, 2000, at a Special Meeting of Shareholders, a Shareholder Rights
Plan was approved. On May 2, 2002, at the Annual General and Special Meeting of
Shareholders, an Amended and Restated Shareholder Rights Plan (Plan) was
approved. The Plan creates a right, which attaches to each present and future
outstanding common share. Each right entitles the holder to acquire additional
common shares during the term of the right. Prior to the separation date, the
rights are not separable from the common shares and no separate certificates are
issued. The separation date would typically occur at the time of an unsolicited
takeover bid, but our Board can defer the separation date.

The Plan creates a right, which can only be exercised when a person acquires 20%
or more of our common shares (a Flip-In Event), for each shareholder, other than
the 20% buyer, to acquire additional common shares at one-half of the market
price at the time of exercise. The Plan must be reapproved by shareholders on or
before our annual general meeting in 2005 to remain effective past that date.

On April 17, 2000, the shareholders approved the repurchase from Occidental and
cancellation of 20 million common shares.

20

Under the terms of our stock option plan, the Board of Directors may grant stock
options to directors, officers and employees. Nexen does not receive any
consideration when options are granted.

Equity Compensation Plan Information:

Number of securities
Number of securities to be Weighted-average remaining available for
issued upon exercise of exercise price of future issuance under
outstanding options outstanding options equity compensation plans
------------------------------- -------------------------- ----------------------------

Equity compensation plans approved
by shareholders 9,475,985 $30.00 9,759,545
------------------------------- -------------------------- ----------------------------

ITEM 6. SELECTED FINANCIAL DATA

FIVE YEAR SUMMARY OF SELECTED FINANCIAL DATA IN ACCORDANCE WITH US GAAP

(Cdn$ millions) 2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS

Net Sales(1) 2,606 2,593 2,705 1,646 1,472
Net Income (Loss) 352 365 522 63 (115)
Earnings (Loss) per Common Share ($/share)(2) 2.88 3.03 4.17 0.46 (0.84)

Production - Before Royalties (mboe/d)(3) 269 268 256 239 266
Production - After Royalties (mboe/d)(3) 176 184 171 163 200

FINANCIAL POSITION
Total Assets(2) 6,764 5,609 5,874 4,922 5,025
Long-Term Debt 2,575 2,242 2,238 1,997 1,777
Shareholders' Equity 1,812 1,414 1,050 1,130 1,074

Capital Expenditures 1,625 1,404 915 612 950

Dividends per Common Share ($/share) 0.30 0.30 0.30 0.30 0.30

Common Shares Outstanding (thousands)(1) 122,966 121,202 119,855 138,145 137,373
----------------------------------------------------

Notes:
(1) Certain transportation costs previously shown net in sales have been
reclassified to transportation and other. See note 1(r) to the Consolidated
Financial Statements.

(2) During 2000, we entered into an agreement to repurchase 20 million Nexen
common shares, as described in note 8 to the Consolidated Financial
Statements.

(3) In 1999, production and total assets decreased as we sold our North Sea
assets and certain producing assets in Canada. These North Sea assets were
producing 34 mmcf/d of gas and the Canadian assets were producing 40
mboe/d. In 2000, production increased as additional development wells were
brought on stream in Yemen and Buffalo in Australia began producing.

21

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL
STATEMENTS INCLUDED IN THIS REPORT. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE
BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP)
IN CANADA. THE IMPACT OF THE SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND UNITED
STATES (US) ACCOUNTING PRINCIPLES ON THE FINANCIAL STATEMENTS IS DISCLOSED IN
NOTE 16 TO THE CONSOLIDATED FINANCIAL STATEMENTS. UNLESS OTHERWISE NOTED,
TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS, AND SALES VOLUMES,
PRODUCTION VOLUMES AND RESERVES ARE BEFORE ROYALTIES. WE HAVE PRESENTED OUR
WORKING INTEREST BEFORE ROYALTIES AS WE MEASURE OUR PERFORMANCE ON THIS BASIS
CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. SEE THE OIL AND GAS
PRODUCING ACTIVITIES SECTION IN THE SUPPLEMENTARY FINANCIAL INFORMATION FOR OUR
PRODUCTION AND RESERVES AFTER ROYALTIES.

TABLE OF CONTENTS

PAGE
Highlights...................................................................23
Strategy.....................................................................23
2002 Capital Investment......................................................24
Financial Results
Year to Year Change in Net Income.....................................26
Oil and Gas
Production ..................................................27
Commodity Prices..............................................28
Operating Costs...............................................29
Depreciation, Depletion and Amortization......................30
Exploration Expense...........................................30
Oil and Gas Marketing.................................................31
Chemicals.............................................................33
Corporate Expenses....................................................34
Liquidity....................................................................35
Outlook for 2003.............................................................37
Contractual Obligations, Commitments and Contingencies.......................38
Business Risk Management.....................................................39
Market Risk Management.......................................................42
Critical Accounting Policies.................................................44
New Accounting Pronouncements................................................46

22

HIGHLIGHTS

(Cdn$ millions) 2002 2001 2000
- ---------------------------------------------------------------------------------------------

Net Income 452 450 602
Earnings per Common Share ($/share) 3.34 3.40 4.52
Cash Flow from Operations(1) 1,383 1,423 1,569

Oil & Gas Production (mboe/d)(2) 269 268 256

Capital Expenditures 1,625 1,404 915
Proved Reserve Additions, net of Dispositions (mmboe)(2) 102 135 132

Net Debt(3) 1,775 1,460 1,344
Net Debt to Cash Flow (times)(4) 1.4 1.1 0.9
------------------------------

Notes:
(1) 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.

(Cdn$ millions) 2002 2001 2000
- ---------------------------------------------------------------------------
Cash Flow from Operating Activities 1,322 1,566 1,329
Changes in Non-Cash Working Capital 46 (143) 243
Other 15 -- (3)
-----------------------------
Cash Flow from Operations 1,383 1,423 1,569
=============================

(2) Production and reserves include our working interest before royalties. We
have presented our working interest before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.

(3) Long-term debt less working capital.

(4) Net debt divided by cash flow from operations after dividends on Preferred
Securities.

STRATEGY

To succeed in the exploration and production business we must continue to locate
and develop economic oil and natural gas reserves. Our capital investments must
add new reserves to replace and grow existing production, and also add value. We
believe value-based growth is best delivered through full-cycle exploration and
development activities.

We pursue a predominantly grassroots, exploration-led strategy, supplemented by
targeted, strategic acquisitions and the development of innovative technology to
competitively exploit our bitumen resource. This strategy is supported by:

o solid core assets that provide free cash flow to finance new development
projects for near-term growth;

o an active exploration program aimed at longer-term growth; and

o a culture based on integrity and social responsibility.

Our fundamental goal is to grow shareholder value. We focus on per-share
performance and regularly report on cash flow and earnings per share. We target
to grow the physical deliverables to our shareholders that are independent of
price volatility. We allocate capital to projects based first on their
investment returns and strategic fit, and second on the potential to grow
reserves and production. To maximize returns, we try to operate the majority of
our core assets and control offsetting acreage and infrastructure for future
development.

Our global growth strategy focuses on four major areas: the deep-water Gulf of
Mexico, the Middle East, West Africa and the Athabasca region of western Canada.
The basins in these areas offer an optimal combination of prospectivity,
attractive commercial terms and low costs. In building our portfolio, we target
material opportunities with an attractive risk/reward balance and multiple
opportunities for organic growth, and those that build on our technical
strengths. Our strengths include: operating offshore, extensive experience with
oil sands, bitumen and heavy oil, operating in foreign jurisdictions such as the
Middle East, managing low pressure reservoirs, constructing and operating
large-scale facilities, operating in difficult and remote environments and our
strong marketing capabilities.

With our exploration success over the last three years, our focus in 2002
shifted to developing these successes. This included Aspen and Gunnison in the
deep-water Gulf of Mexico, Guando in Colombia, our Long Lake Synthetic Crude
Project in the Athabasca region of Alberta and the Syncrude expansion. With the
exception of Aspen, these projects have yet to contribute significantly to
production and cash flow as they are still in the development stage. Annual
proved reserve additions fluctuate due to timing of recognizing proved reserves,
dispositions and revisions.

23

Our strategy for maximizing value in our marketing operations is to grow our
business with lower-risk opportunities. For our chemicals business, our strategy
is to remain a low-cost producer in North America, while capturing an increasing
share of the growing markets in South America.

2002 CAPITAL INVESTMENT

We invested a record $1.6 billion in 2002, a 16% increase over 2001 levels:

o 41% was invested in core assets to maintain existing production levels;

o 43% was invested in our major development projects for near-term production
growth; and

o 16% was invested in exploration for longer-term production growth.

(Cdn$ millions) EXPLORATION DEVELOPMENT OTHER TOTAL
- --------------------------------------------------------------------------------
Oil & Gas
Yemen 22 209 -- 231
Canada 60 262 -- 322
United States 116 541 -- 657
Australia 3 46 -- 49
Other 58 23 -- 81
--------------------------------------------
259 1,081 -- 1,340
Syncrude -- 141 -- 141
Chemicals -- -- 45 45
Marketing, Corporate and Other(1) -- -- 99 99
--------------------------------------------
Total Capital 259 1,222 144 1,625
============================================

Note:
(1) Includes $67 million for our Balzac power generation facility.

In addition to maintaining production from our core assets (see Production
section in this MD&A), our 2002 capital program delivered the following:

UNITED STATES GULF OF MEXICO

ASPEN ONSTREAM

o Invested $311 million in 2002 to drill and complete two subsea development
wells and tie back to Shell's Bullwinkle production platform.

o First well onstream in early December after a six-week construction delay
due to hurricane activity; second well onstream late December 2002; both
wells added minimal production in 2002 given late start-up.

o Production is currently ramping up to expected rates of approximately
15,000 boe/d (net to us).

o No significant capital investment required in 2003.

GUNNISON DEVELOPMENT ON-TRACK

o Invested $111 million in 2002 to complete 55% of the SPAR production
facility and drill six development wells with a seventh in progress at
year-end.

o Development is on budget and on schedule for first production in early
2004.

o In 2003, we plan to invest $83 million to complete and tie-in the subsea
wells to the SPAR production platform arriving from Finland this summer.

EXPLOITATION OF 2001 ACQUISITIONS

o Invested $83 million in two offshore producing properties acquired late in
2001 - Vermilion 76 and Eugene Island 295.

o Drilled eight development wells and added compression at Vermilion 76 more
than doubling daily gas production to 40 million cubic feet per day in late
2002.

o Drilled one new well and added compression at Eugene Island 295 before the
field was extensively damaged by Hurricane Lili; field has been shut-in
since October but is expected to return to producing status during the
first quarter of 2003.

24

EXPLORATION FOR DEEP MIOCENE GAS

o Drilled first well, Fergana (40% interest), as part of our agreement with
Shell Exploration & Production Company to jointly explore the continental
Shelf for natural gas in Deep Miocene reservoirs.

o Well was abandoned and costs of $23 million were written off in the fourth
quarter.

o We plan to drill at least two more wells in the joint venture area in 2003
and 2004.

CANADA

LONG LAKE PILOT PROJECT COMMENCED

o Invested $80 million in 2002 to expand our recoverable resource potential
to 4 billion barrels for the Long Lake and Meadow Creek properties,
consulted with communities in support of our regulatory applications,
continued detailed design and construction of the SAGD pilot project and
carried out project design and cost estimation work.

o In 2003, we plan to invest $130 million to pilot-test SAGD technology at
Long Lake and finalize a comprehensive cost assessment based upon detailed
engineering design.

o Expect final regulatory approvals in fall 2003 and plan to decide on
full-scale commercial project by year-end.

CORE ASSET OPTIMIZATION CONTINUES

o Began field testing enhanced extraction technologies in an effort to
improve recoveries from some of our heavy oil properties.

o Built a strong land position targeting Coal Bed Methane (CBM) opportunities
and commenced CBM pilot project.

SYNCRUDE

STAGE 3 EXPANSION CONTINUES

o Invested $141 million to fund our 7.23% share of Stage 3 expansion.

o Engineering and design is 90% complete for the Mildred Lake upgrader
expansion (UE-1) and the second bitumen extraction train at the Aurora
mine; construction is 12% complete for UE-1 and 50% complete for the Aurora
train.

o In 2003, we plan to invest $150 million for the continued upgrader
expansion and completion of the Aurora train.

o Stage 3 is expected to add 101,500 barrels (7,300 barrels net) of daily
production in early 2005.

YEMEN

MASILA EXPLOITATION CONTINUES

o Invested $402 million ($209 million net) to drill and equip 74 new
development wells and expand facilities to maintain production at 226,900
barrels per day.

UNSUCCESSFUL WELL ON BLOCK 59

o Drilled the Al Mawarid-1 exploration well on Block 59 without encountering
commercial quantities of hydrocarbons.

AUSTRALIA

o Drilled two successful infill wells at Buffalo offshore Australia.

OTHER OIL & GAS

GUANDO DEVELOPMENT COMMENCES IN COLOMBIA

o Drilled 12 primary-recovery development wells and commenced installation of
waterflood pilot facilities to improve recoveries.

o Development drilling increased gross production to 7,300 barrels per day
(2,200 net) by year-end.

o In 2003, we plan to invest $35 million to drill 24 wells, complete pipeline
construction and evaluate the pilot waterflood performance.

EXPLORATION SUCCESS OFFSHORE NIGERIA

o Invested $4 million and discovered oil at Usan on Block OPL-222 in the
first quarter.

o Discovery well encountered several oil-bearing zones and tested at
restricted rates in excess of 5,000 barrels per day.

o Currently appraising Usan and our 1998 discovery at Ukot on the same block.
o In 2003, we are continuing a program to appraise and delineate our
discoveries.

25

UNSUCCESSFUL EXPLORATION WELL OFFSHORE BRAZIL

o Drilled an exploration well on Block BC-20 in the Campos Basin which did
not encounter commercial hydrocarbons and wrote off $5 million in the third
quarter.

o In early 2003, we plan to drill a second exploration well on Block BC-20.

CHEMICALS

o Expanded low-cost sodium chlorate capacity at Brandon by 60% or 70,000
tonnes per year to 195,000 tonnes per year.

o Expanded our sodium chlorate capacity in Brazil by 70% to 60,000 tonnes per
year and chlor-alkali capacity by 30% to 91,160 tonnes.

OTHER

o In 2002, we paid $67 million to refinance an operating lease related to the
construction of a natural gas-fired power generation facility at our Balzac
gas plant near Calgary.

FINANCIAL RESULTS

YEAR TO YEAR CHANGE IN NET INCOME

(Cdn$ millions) 2002 VS 2001 2001 VS 2000
- ------------------------------------------------------------------- -----------
NET INCOME FOR 2001 AND 2000 450 602
============= ===========
Favourable (unfavourable) variances:

Cash Items:
Production volumes, net of royalties:
Crude oil 28 123
Natural gas (18) 30

Commodity prices, net of royalties:
Crude oil 190 (308)
Natural gas (114) 22

Oil and gas operating expense:
Conventional (65) (66)
Synthetic (1) (16)

Marketing (23) 48
Chemicals 1 3
General and administrative (16) (19)
Interest expense 3 20
Current income taxes (7) 26
Other (18) (9)

------------- -----------
Total Cash Variance (40) (146)

Non-Cash Items:
Depreciation, depletion and amortization
Oil and Gas (85) 38
Other (10) 4
Exploration expense 76 (92)
Future income taxes 82 77
Other (21) (33)
------------- -----------
Total Non-Cash Variance 42 (6)

------------- -----------
NET INCOME FOR 2002 AND 2001 452 450
============= ===========

2002 VS 2001 - STABLE EARNINGS YEAR OVER YEAR

Net income remained strong due to narrow crude oil price differentials, stable
production and reduced dry hole expense. Weaker natural gas prices, cost
pressures and lower profits from Marketing offset the positive impact of crude
oil prices.

2001 VS 2000 - 25% DECREASE IN NET INCOME
Net income decreased largely as a result of a US $4.24 per barrel decrease in
WTI. Record production levels, excellent results from Marketing and lower costs
of financing helped mitigate the impact of crude oil price declines.

Significant variances in net income are explained further in the following
sections.

26

OIL AND GAS

PRODUCTION

2002 2001 2000
--------------------------- ------------------------------ -----------------------------
Before After Before After Before After
Royalties Royalties Royalties Royalties Royalties Royalties
--------------------------- ------------------------------ -----------------------------

Oil and Liquids (mbbls/d)
Yemen 118.0 55.8 118.3 55.5 111.9 50.7
Canada 56.3 43.4 58.0 48.3 53.9 44.0
United States 9.9 8.2 10.0 8.3 11.1 9.3
Australia 12.8 10.3 10.2 9.6 12.0 12.0
Other Countries 8.9 5.2 6.2 5.3 6.4 5.4
Syncrude 16.6 16.5 16.1 15.5 14.7 12.1
--------------------------- ------------------------------ -----------------------------
222.5 139.4 218.8 142.5 210.0 133.5
--------------------------- ------------------------------ -----------------------------
Natural Gas (mmcf/d)
Canada 167 128 174 147 161 135
United States 112 93 121 99 113 92
--------------------------- ------------------------------ -----------------------------
279 221 295 246 274 227
--------------------------- ------------------------------ -----------------------------

Total (mboe/d) 269 176 268 184 256 171
=========================== ============================== =============================

2002 VS 2001 - PRODUCTION ADDED $10 MILLION TO NET INCOME

2002 production before royalties grew modestly over 2001 volumes. A 2% increase
in crude oil volumes was partially offset by a 5% decrease in natural gas
volumes.

MASILA BLOCK IN YEMEN

o Maintained production through our on going development drilling, water
handling and throughput expansions.

o Experienced minor delays in tanker loadings but no impact on production or
cash flow when the supertanker Limburg was damaged near our Ash Shihr
export terminal.

o In 2003, we expect to maintain production through continued infill
drilling, facility enhancements and exploration focused on deeper targets.

CANADA

o We invested $240 million or about 15% of our total capital expenditures in
2002 to mitigate production declines.

o We are focused on our highest-return projects including Hay, while we
develop new sources of production in synthetic crude and coal bed methane.

o Hay set a new 8,000 barrel per day production record in 2002.

GULF OF MEXICO

o Production decreased due to development delays, weather-related shut-ins
and production declines on some of our shelf properties.

o Poor weather in the third and fourth quarters, including tropical storm
Isidore and Hurricane Lili, caused temporary shut-in of production, a
6-week delay at Aspen and damage to our Eugene Island 295 production
platform.

o All production, except Eugene Island 295, was restored in the fourth
quarter.

o Our Eugene Island 295 exploitation program was in progress at the time of
the storm; the field has been shut-in since October but is expected to
return to producing status during the first quarter of 2003.

o Aspen's first well came onstream in early December and the second well in
late December. We are ramping up production to expected rates of 15,000
equivalent barrels per day net to us.

o With Aspen onstream for the full year, we expect 2003 production before
royalties to increase by 65% to 46 mboe/d.

BUFFALO OFFSHORE AUSTRALIA

o Completed successful two-well infill drilling program that added
incremental production and reserves.

o Exited 2002 at 10,000 barrels per day; we expect Buffalo to be fully
depleted in 2004.

EJULEBE OFFSHORE NIGERIA

o Strong 2002 production as the reservoir continued to perform better than
anticipated.

o Exited 2002 at 4,700 barrels per day with water-cuts increasing; we expect
Ejulebe to be depleted in 2004.

27

SYNCRUDE

o Extended maintenance turnaround, unplanned coker maintenance and sulfur
dioxide emission restrictions reduced volumes during the first half of the
year.

o December production of 19,100 barrels per day set a new monthly record.

2001 VS 2000 - 5% PRODUCTION GROWTH ADDED $153 MILLION TO NET INCOME

o Masila set an annual production record for the sixth consecutive year with
gross rates of 227,500 barrels per day.

o In Canada, our exploitation activities included successful optimization of
our Hay assets with the doubling of production to an annual average of
5,400 barrels per day.

o Gulf of Mexico natural gas production grew 7% with the fourth quarter
acquisitions of Vermilion 76 and Eugene Island 295 and with successful
exploitation of our shallow-water assets.

o Australian crude oil production remained stable as the acquisition of the
remaining 50% interest in Buffalo offset natural production declines.

COMMODITY PRICES
(Prices based on working interest production before royalties)

2002 2001 2000
- --------------------------------------------------------------------------------
CRUDE OIL (Cdn$/bbl)
West Texas Intermediate (US$/bbl) 26.09 25.97 30.21
-------------------------------

Differentials (US$/bbl):

Masila 1.41 3.29 2.82
Heavy Oil 6.49 10.68 8.06

Producing Assets:
Yemen 38.80 35.05 40.53
Canada 31.13 24.86 33.49
United States 38.88 38.35 44.18
Syncrude 40.89 39.90 44.84
Australia 40.30 38.71 41.05
Other Countries 38.96 37.37 40.12

Corporate Average (Cdn$/bbl) 37.13 33.10 39.23
-------------------------------

NATURAL GAS (Cdn$/mcf)
New York Mercantile Exchange (US$/mmbtu) 3.37 4.00 4.31
-------------------------------

Canada 3.57 5.02 4.38
United States 5.29 6.66 6.90

Corporate Average (Cdn$/mcf) 4.25 5.69 5.42
-------------------------------

2002 VS 2001 - HIGHER REALIZED PRICES ADDED $76 MILLION TO NET INCOME

CRUDE OIL PRICES

o Average WTI was largely unchanged but narrow oil differentials added $180
million to net income, increasing our realized price 11%.

o At the beginning of 2002, WTI was US $19.73 per barrel strengthening
throughout the year to close at US $31.20.

o Early second quarter strength was driven by uncertainty in the Middle East,
OPEC's maintenance of production quotas and the threat of war between Iraq
and the US.

o WTI slid modestly early in the fourth quarter as quota cheating by OPEC
members increased and the war premium disappeared with Iraq cooperation.

o Despite the reduction of the war premium, WTI strengthened late in the year
as supply disruptions took place in Venezuela and OPEC took steps to
shore-up production quotas.

28

NARROW DIFFERENTIALS

o The strength of Brent relative to WTI combined with a short-term premium
for Masila mid-year, resulted in a narrower Masila differential. Low
inventory levels in Europe kept the Brent-WTI differential narrow
throughout most of the year.

o Heavy oil narrowed early in the year due to reduced supply, continued
narrow into the summer months due to normal seasonal demand and remained
narrow into the winter months due to the Venezuelan supply disruption.

o Realized crude oil prices for Canada and Yemen exceeded 2001 prices by 25%
and 11%, respectively.

o We expect the Masila differential to return to historical norms around US
$3.00 per barrel in 2003.

o We expect 2003 heavy oil differentials to remain narrow in the near-term
due to the ongoing disruptions in Venezuela.

NATURAL GAS PRICES

o Lower gas prices reduced net income by $114 million.

o Prices fell in the first part of 2002 from the record highs of 2001 as gas
inventories were higher, but strengthened late in 2002 as cold weather in
the eastern US drove up demand and caused supply concerns.

o We expect stronger gas prices in 2003 as production decline rates and a
lack of drilling should continue to reduce available supply levels.

2001 VS 2000 - LOWER REALIZED PRICES REDUCED NET INCOME BY $286 MILLION

o Lower crude oil prices in 2001.

o At the beginning of 2001, WTI was approximately US $29 per barrel and
closed the year at US $19.40 per barrel.

o Sluggish demand after September 11, 2001 and concerns over inventory levels
drove prices down late in the year.

o Natural gas prices softened as North American inventories rose.

OPERATING COSTS

(Unit operating costs based on working interest production before royalties)

(Cdn$/boe) 2002 2001 2000
- ----------------------------------------------------------------------------
Conventional Oil and Gas
Yemen 1.95 1.62 1.42
Canada 5.70 4.87 4.57
United States 9.09 6.01 5.00
Australia 9.76 13.50 6.92
Other Countries 6.21 8.07 7.58
Total Conventional 4.60 3.92 3.38
-----------------------------

Synthetic Crude Oil
Syncrude 19.09 19.43 18.36
Total Oil and Gas(1) 5.48 4.88 4.22
-----------------------------

Note:
(1) Operating costs per equivalent barrel are our total oil and gas operating
costs divided by our working interest production before royalties. We use
production before royalties to monitor our performance consistent with
other Canadian oil and gas companies. See Reserves, Production and Other
Information in Item 1 and 2 in this 10-K for unit operating costs based on
our production after royalties.

2002 VS 2001 - HIGHER OIL AND GAS OPERATING COSTS REDUCED NET INCOME BY $66
MILLION
Conventional operating costs increased $0.68 per equivalent barrel:

o Gulf of Mexico was a significant contributor as workovers and repairs on
the shelf increased costs and temporarily reduced production.
Weather-related shut-ins and storm damage also contributed to the increase.
One-time workovers and storm-related costs are not expected to continue in
2003.

o Costs are expected to decrease in 2003 with low-cost production from Aspen
making up a larger portion of our total Gulf production.

o In Canada, industry cost pressures and a maturing asset base increased per
unit costs. In addition, unexpected turnaround costs at our Balzac gas
plant caused a one-time increase in operating costs.

o In Yemen, increased water-handling and waterflood costs as well as one time
flood-related costs increased per-unit costs.

29

o In 2002, our floating production and storage off-loading vessel (FPSO)
costs in Australia decreased on a per-unit basis as fixed costs were spread
over more barrels and increased production levels attracted a lower
throughput cost. This decrease in FPSO unit costs was partly offset by
one-time field repair costs.

With respect to synthetic crude oil, our operating costs at Syncrude stabilized
in 2002 as second quarter maintenance activities improved reliability and
performance.

2001 VS 2000 - HIGHER OIL AND GAS OPERATING COSTS REDUCED NET INCOME BY $82
MILLION

o Conventional operating costs increased $0.54 per equivalent barrel.
Industry cost pressures from a sustained period of high commodity prices
and maturing assets contributed to the increase.

o Australia's costs increased as fixed costs were spread over fewer barrels
of production.

o Maintenance activities and higher energy prices caused an increase in
Syncrude's per-unit operating costs.

DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
(Based on working interest production before royalties)

(Cdn$/boe) 2002 2001 2000
- ------------------------------------------------------------------------------
Conventional Oil and Gas

Yemen 3.47 2.56 2.20
Canada 8.22 7.14 7.89
United States 12.74 10.59 12.70
Australia 10.45 16.61 21.05
Other Countries 13.22 15.11 15.88
Total Conventional 6.84 5.97 6.67
------------------------------

Synthetic Crude Oil

Syncrude 2.13 2.03 2.23
Total Oil and Gas(1) 6.55 5.73 6.41
------------------------------

Note:
(1) DD&A per equivalent barrel is our DD&A for oil and gas operations divided
by our working interest production before royalties. We use production
before royalties to monitor our performance consistent with other Canadian
oil and gas companies.

2002 VS 2001 - HIGHER OIL AND GAS DD&A REDUCED NET INCOME BY $85 MILLION
Conventional depletion rates increased $0.87 per equivalent barrel:

o Higher 2001 finding and development costs in Canada, Yemen and the Gulf
shelf comprise the majority of the increase.

o Changing production mix also contributed as a larger portion of production
came from more capital-intensive properties.

o Rates in Australia decreased as reserves were added with our successful
infill drilling program.

2001 VS 2000 - LOWER OIL AND GAS DD&A ADDED $38 MILLION TO NET INCOME

o Depletion rates for conventional production decreased as reserves were
added at low finding and development costs in 2000.

EXPLORATION EXPENSE

(Cdn$ millions) 2002 2001 2000
- -----------------------------------------------------------------------------

Seismic 80 79 74
Unsuccessful Drilling 63 135 54
Other 46 51 45
--------------------------------
Total Exploration Expense 189 265 173
================================
Total Exploration Capital 259 411 300
--------------------------------

30

2002 VS 2001 - LOWER EXPLORATION EXPENSE ADDED $76 MILLION TO NET INCOME

o Pursued exploration activities in Yemen, Nigeria, Brazil, Colombia, the
Gulf of Mexico and Canadian natural gas.

o Lower exploration expense as capital spending focused on development of
earlier successes.

o Drilled 68% fewer exploration wells.

o Successfully drilled an exploration well at Usan on Block OPL-222.

o Unsuccessful exploration wells include Block 59 in Yemen, Fusa in Colombia,
Block BC-20 offshore Brazil and Fergana in the Gulf of Mexico.

2001 VS 2000 - HIGHER EXPLORATION EXPENSE REDUCED NET INCOME BY $92 MILLION

o Higher exploration expense due to our largest-ever exploration program.

o Unsuccessful drilling costs include two high-risk exploration wells: Scout
in the deep-water Gulf of Mexico and Kayu Manis, offshore Indonesia.

OIL AND GAS MARKETING

(Cdn$ millions) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------

Revenue 496 438 179
Transportation (423) (342) (131)

---------------------------------
Net Revenue 73 96 48
=================================
Marketing contribution to Income before Income Tax 35 59 23
---------------------------------
Physical Sales Volumes (excluding intra-segment transactions)
Crude Oil (mboe/d) 412 400 294
Natural Gas (mmcf/d) 2,865 2,499 1,664

Value-at-Risk
Year-end 19 19 13
High 28 24 13
Low 12 6 2
Average 17 13 4
---------------------------------

2002 VS 2001 - LOWER NET MARKETING REVENUE REDUCED NET INCOME BY $23 MILLION

The energy trading industry experienced many challenges in 2002. Liquidity was
at an all-time low following the collapse of Enron and the exposure of
questionable accounting and valuation practices by a number of companies.
Numerous participants retrenched, consolidated or exited the industry
completely. Accounting standard setters and regulators made changes to the rules
and practices governing the industry, including improved and more transparent
disclosures, as well as changes to the mark-to-market accounting rules, which
are described more fully in note 1(r) to our Consolidated Financial Statements.

Our marketing operations had lower net revenue in 2002 compared to 2001 due to:

o Less price volatility in 2002.

o The reduced number of competitors allowed us to increase our marketed
volumes over 2001 levels.

o Excluding the one-time gains in the first quarter of 2001, margins grew
year over year. We expect margins to continue to grow in 2003 as industry
retrenchment continues.

2001 VS 2000 - HIGHER NET MARKETING REVENUE ADDS $48 MILLION TO NET INCOME

o We successfully capitalized on the significant price volatility early in
the year.

o Crude oil volumes increased with the acquisition of Northridge Energy
Marketing Ltd., which was purchased on July 31, 2000. Northridge marketed
approximately 90,000 barrels of oil per day.

31

DERIVATIVE ENERGY CONTRACTS

Our marketing operation engages in crude oil and natural gas marketing
activities to enhance prices from the sale of our own oil and gas production,
and for energy trading. We enter into contracts to purchase and sell crude oil
and natural gas. These contracts expose us to commodity price risk between the
time contracted volumes are purchased and sold. We actively manage this risk by
using energy-related futures, forwards, swaps and options, and by balancing
physical and financial contracts in terms of volumes, timing of performance and
delivery obligations. However, net open positions may exist, or we may establish
them to take advantage of market conditions.

Consistent with our management practices, we account for all derivative energy
contracts using mark-to-market accounting, and record the net gain or loss from
their revaluation in marketing and other income. The fair value of these
instruments is recorded as accounts receivable or payable. They are classified
as long-term or short-term based on their anticipated settlement date. On
October 25, 2002, as described in note 1(r) to the Consolidated Financial
Statements, generally accepted accounting principles followed by energy traders
eliminated mark-to-market accounting for inventories. As such, after October 25,
2002, inventories held by our marketing operation are accounted for at the lower
of cost or market value.

FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS

We value derivative energy trading contracts daily using:

o actively quoted markets such as the New York Mercantile Exchange and the
International Petroleum Exchange; and

o other external sources such as independent price publications and
over-the-counter broker quotes.

At December 31, 2002, the unrealized fair value of our derivative energy
contracts totalled $3 million. The following table shows the valuation methods
underlying these contracts together with details of contract maturity:

(Cdn$ millions) MATURITY
- --------------------------------------------------------------------------------------------------------------------------
Less Than Greater Than
1 year 1-3 years 4-5 years 5 years Total
--------------------------------------------------------------------

Prices:

Actively quoted 63 (40) (13) -- 10
From other external sources (67) 45 14 1 (7)
Based on models and other valuation methods -- -- -- -- --

--------------------------------------------------------------------

Total (4) 5 1 1 3
====================================================================

Contract maturities vary from a single day up to six years. A large number of
our contracts mature in less than one year. Those maturing beyond one year are
primarily from natural gas related positions. The relatively short maturity
position of our contracts lowers our portfolio risk.

Our accounting policy does not permit us to record income on transportation and
inventory using option valuation methods. As a result, we have not been subject
to write-downs due to the loss of liquidity and volatility caused by the
industry retrenchment in 2002.

CHANGES IN FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS

Contracts
Outstanding Contracts
at Beginning Entered Into
(Cdn$ millions) of Year During Year Total
- ------------------------------------------------------------------------------------------------------

Outstanding at December 31, 2001 19 -- 19
Change in fair value of contracts:
Outstanding at January 1, 2002 21 -- 21
Entered into during 2002 -- 37 37
Net gains realized on positions closed during the year (44) (30) (74)
Changes in valuation techniques and assumptions (1) -- -- --
------------------------------------------
Outstanding at December 31, 2002 (4) 7 3
==========================================

Note:
(1) Our valuation methodology has been applied consistently year over year.

32

COMPOSITION OF NET MARKETING REVENUE

(Cdn$ millions)
- --------------------------------------------------------------------------------
Derivative energy contracts 58
Non-derivative energy contracts 15
------
Net Marketing Revenue 73
======

Of the $73 million net marketing revenue recognized during 2002, only a net gain
of $3 million is unrealized at December 31, 2002.

NON-DERIVATIVE ENERGY CONTRACTS

Our marketing operation also manages various natural gas transportation
commitments on behalf of our Canadian oil and gas business and a number of
third-party customers. These activities optimize our trading operations. The
related commitments are outlined in the Contractual Obligations, Commitments and
Contingencies section. We earned $15 million from our non-derivative energy
activities in 2002.

CHEMICALS

(Cdn$ millions) 2002 2001 2000
- --------------------------------------------------------------------------------
Net Sales 367 373 336
Sales Volumes (thousand short tons)
Sodium chlorate 454 457 462
Chlor-alkali 375 365 407

Operating Profit(1) 100 99 96
Operating Margin (%) 27 27 29

Chemicals contribution to Income before Income Taxes 27 47 39

Capacity Utilization (%) 85 89 92
-------------------------

Note:
(1) Net sales less operating costs and transportation.

2002 VS 2001 - CHEMICALS OPERATING PROFIT ADDS $1 MILLION TO NET INCOME

We faced many challenges in 2002:

o Slow economic recovery in North America placed downward pressure on sodium
chlorate volumes and eroded market prices.

o Increasing energy costs in Louisiana put pressure on our Taft plant, and as
a result, the assets have recently been temporarily idled while we review
alternatives to manage these costs.

During 2002, margins remained strong due to lower overall energy costs and the
shifting of production from higher-cost to lower-cost facilities following the
expansion of our Brandon and Brazil facilities. The expansion of these plants
and the shifting of production to lower cost facilities increased our
depreciation.

Demand in 2003 is expected to improve for sodium chlorate as the economy
recovers. We expect to take advantage of the recovery with a full year of
production from our Brandon and Brazil expansions. We are continuing to take
steps towards improving our overall cost structure in North America.

2001 VS 2000 - CHEMICALS OPERATING PROFIT ADDS $3 MILLION TO NET INCOME

o Sales revenue increased 11% as price increases more than offset
recessionary conditions in North America.

o Operating costs as a percentage of sales were consistent with 2000 as high
natural gas prices fell late in 2001.

33

CORPORATE EXPENSES

GENERAL AND ADMINISTRATIVE

(Cdn$ millions) 2002 2001 2000
- ----------------------------------------------------------------------------

General and Administrative 152 136 117
===============================

2002 VS 2001 - HIGHER COSTS REDUCED NET INCOME BY $16 MILLION

o 70% of the increase was due to higher staffing levels, associated with our
record capital investment program and growth in our marketing operations.

o Increased pension expense due to poor equity market performance.

o We also experienced higher building lease costs and incremental expenses
associated with our stock appreciation rights plan.

2001 VS 2000 - HIGHER COSTS REDUCED NET INCOME BY $19 MILLION

o 60% of the increase related to the expansion of our marketing operations in
Calgary and Singapore.

o Remainder was due to increased staffing levels associated with a larger
capital investment program.

INTEREST

(Cdn$ millions) 2002 2001 2000
- --------------------------------------------------------------------------------
Interest 140 112 132
Less: Capitalized Interest (31) -- --
----------------------------
Net Interest Expense 109 112 132
============================

2002 VS 2001 - LOWER INTEREST EXPENSE ADDED $3 MILLION TO NET INCOME

o Total interest costs increased $28 million as a result of the higher
borrowing rate on our new 30-year notes.

o Net interest decreased as we capitalized interest on our major development
projects.

2001 VS 2000 - LOWER INTEREST EXPENSE ADDED $20 MILLION TO NET INCOME

o Lower interest rates and debt levels contributed to decrease from 2000.

INCOME TAXES

2002 VS 2001 - EFFECTIVE TAX RATE DECLINES FROM 40% TO 34%
Rate decreased due to:

o lower federal and provincial statutory tax rates for Canadian non-oil and
gas operations;

o higher portions of income coming from international operations where rates
are lower; and

o non-taxable capital gain on the sale of our Moose Jaw operations.

The majority of our 2002 current income taxes were paid in Yemen and Australia.
Current taxes include cash taxes in Yemen of $207 million (2001 - $191 million;
2000 - $217 million). In 2002, federal and provincial capital taxes were payable
in Canada. In 2001 and 2000, alternative minimum tax was payable in the US.

GAIN OR LOSS ON DISPOSITION OF ASSETS

Net loss in 2002 includes:

o $13 million gain on the sale of our asphalt operation in Moose Jaw,
Saskatchewan for proceeds of $27 million plus working capital; and

o $21 million loss on the sale of a non-operated property by our Canadian oil
and gas business segment for proceeds of $14 million.

Gains in 2001 related to the disposition of minor properties in Australia and
the United States. In 2000, gains related to the exchange of our 15% interest in
oil and gas assets in Ecuador for Occidental's 15% minority interest in our
chemicals operations and the disposition of non-core assets in Canada.

34

LIQUIDITY

CAPITAL STRUCTURE
(Cdn$ millions) 2002 2001
- -------------------------------------------------------------------------
Bank Debt -- 424
Senior Public Debt 1,844 1,060
---------------------
1,844 1,484
Less: Working Capital 69 24
---------------------
Net Debt(1) 1,775 1,460
=====================

Shareholders' Equity(2) 2,348 1,904
=====================

Notes:
(1) Long-term debt less working capital.

(2) Included in shareholders' equity are preferred securities of $724 million
(US $476 million). Under US generally accepted accounting principles, these
are considered long-term debt.

Our business strategy is focused on value-based growth through full-cycle
exploration and development, supplemented by strategic acquisitions when
appropriate. We rely on operating cash flow and borrowings under committed
credit facilities and public debt, including preferred securities, for our
liquidity and capital requirements. We build our opportunity portfolio to
provide a balanced mix of short-term, mid and longer-term growth. This enables
us to generate ongoing sustainable operating cash flows.

We enhanced our capital structure in 2002:

SHAREHOLDERS' EQUITY Continued to strengthen with strong
2002 operating and financial
results.

US $500 MILLION OF 7.875% DEBT Issued in March 2002 and maturing
in 30 years. Proceeds used to repay
existing bank debt and fund a
portion of our capital investment
program.

COMMITTED BANK FACILITIES All undrawn at year-end and
OF $1,576 MILLION available until 2007.

$500 MILLION CANADIAN SHELF PROSPECTUS Available until May 2003.

US $500 MILLION US SHELF PROSPECTUS Available until May 2004.

FAVOURABLE DEBT MATURITIES Over the next five years, $355
million matures in 2004, $108
million in 2006 and $150 million in
2007.

INCREASED TERM TO MATURITY Increased the average term to
maturity of our debt to 18 years,
an increase of 8 years from the end
of 2001.

$724 MILLION OF PREFERRED SECURITIES Provide fixed-rate financing for
another 45 years but can be
redeemed at par commencing in
October 2003 ($393 million) and
February 2004 ($331 million). The
Preferred Securities are
subordinated to Senior Debt and
interest payments may be deferred
for up to five years. Interest and
principal can be settled with
common shares.

The change in net debt in 2002 and 2001 resulted from:

(Cdn$ millions) 2002 2001
- ------------------------------------------------------------------------------
Capital Expenditures 1,625 1,404
Cash Flow from Operations (1,383) (1,423)
Dividends on Preferred Securities and Common Shares 109 107
Foreign Exchange - 57
Proceeds on Disposition of Assets (49) (5)
Other 13 (24)
------------------
Increase in Net Debt 315 116
==================

35

2002 - $315 MILLION INCREASE IN NET DEBT

o Capital expenditures and dividend payments exceeded cash flow from
operations.

2001 - $116 MILLION INCREASE IN NET DEBT

o Capital expenditures and dividend payments exceeded cash flow from
operations.

o The decline in the Canadian dollar relative to the US dollar also increased
net debt.

In 2002, we had working capital of $69 million compared to $24 million in 2001.
Our large natural gas storage position at year end caused the increase. The
value of this natural gas position has been fixed through financial derivatives.
At December 31, 2002, we sold $178 million of accounts receivable proceeds (2001
- - $100 million) to minimize our total cost of financing.

Our future debt levels are primarily dependent on our operating cash flows and
our capital investment programs. Currently, we expect our 2003 capital program
and dividend requirements to be funded by cash flow from operations. Our 2003
operating cash flows assume WTI is US $23 per barrel and natural gas is US $3.50
per mcf for the remainder of year. For every US $1 change in WTI or every US
$0.50 change in natural gas, we expect our cash flow from operations to change
by $67 million and $61 million, respectively. In addition, we have $1.6 billion
of additional unsecured credit facilities to draw on.

We declared common share dividends of $0.30 per common share in each of the last
three years.

LEVERAGE STATISTICS
2002 2001 2000
- -------------------------------------------------------------------------------
Net Debt to Cash Flow(1) (times) 1.4 1.1 0.9
Interest Coverage(2) (times) 10.7 13.7 12.9
Fixed Charge Coverage(3) (times) 7.2 8.4 8.5
---------------------------------

Notes:
(1) Cash Flow comprises cash flow from operations after dividends on Preferred
Securities. Under US regulations, preferred securities are considered
long-term debt. Our net debt to cash flow would be 1.9 times (2001 - 1.6;
2000 - 1.4).

(2) Cash flow from operations before interest expense divided by total
interest.

(3) Cash flow from operations before interest expense divided by total interest
plus dividends on Preferred Securities.

Our net debt is equal to 1.4 times our 2002 cash flow from operations after
dividends on preferred securities. This, together with our coverage ratios,
provides us with sufficient financial flexibility and liquidity to pursue our
business strategy.

CREDIT RATINGS

Currently, our senior debt is rated BBB-mid by Dominion Bond Rating Service, BBB
by Standard and Poor's and Baa2 by Moody's Investor Service, Inc. In addition,
all rating agencies currently have our rating outlook as stable. Our strong
financial results, low historical finding and development costs, ample liquidity
and financial flexibility will continue to support our current credit rating.

FINANCIAL ASSURANCE PROVISIONS IN COMMERCIAL CONTRACTS

The commercial agreements our marketing operations enter into often include
financial assurance provisions that allow Nexen and our counterparties to
effectively manage credit risk. The agreements generally provide for some type
of collateral in the event of deterioration in the creditworthiness of the
buyer. Credit ratings are frequently used in the agreements to provide an
objective measure of creditworthiness, with the agreement typically requiring
the posting of collateral (in the form of either cash or a Letter of Credit), if
a buyer's credit rating drops below investment grade. Based on contracts in
place and commodity prices at December 31, 2002, we would be required to post
collateral of $210 million in the event of a downgrade to non-investment grade.
This obligation is reflected in our balance sheet. The posting of collateral
merely accelerates the payment of such amounts. Our committed undrawn credit
facilities of $1.6 billion adequately cover any potential collateral
requirements. Just as we may be required to post collateral in the event of a
downgrade below investment grade, we have similar provisions in many of our
customer contracts that allow us to demand certain customers post collateral
with us if they are downgraded to non-investment grade.

36

OUTLOOK FOR 2003

2003 CAPITAL INVESTMENT PROGRAM

(Cdn$ millions) EXPLORATION DEVELOPMENT OTHER TOTAL
- ------------------------------------------------------------------------------------------------

Yemen 17 234 -- 251
Canada 40 328 -- 368
United States 136 182 -- 318
Syncrude -- 176 -- 176
Australia 3 3 -- 6
Other 90 43 -- 133
-----------------------------------------------------
Total Oil & Gas 286 966 -- 1,252

Chemicals -- -- 46 46
Marketing, Corporate and Other -- -- 34 34
-----------------------------------------------------
Total 286 966 80 1,332
=====================================================

Our 2003 capital program of $1.3 billion, our third largest ever, will build on
the success of last year. Our solid capital structure and surplus liquidity will
support this program. The following items show the expected distribution of our
2003 capital investment program:

o 40% to sustain and grow production and cash flow from our core assets;

o 30% to continue progress on our major development projects for near to
mid-term growth; and

o 20% on exploration to test almost 900 million barrels of unrisked resource
potential for long-term growth.

This program is consistent with our strategy to grow reserves and production
primarily through the drill bit.

CORE ASSET MAXIMIZATION

Our focus is to maintain production from our core assets to extract their
maximum value without overcapitalizing.

YEMEN

o We will continue exploring deeper carbonate sections, further develop the
main Qishn horizons and continue waterflood projects on the secondary
horizons to maintain production at 226,900 barrels per day.

GULF OF MEXICO

o We expect production growth from continued exploitation of our Vermilion
76, Eugene Island 257/258, Eugene Island 295 and Eugene Island 18
properties and a full year of operations from deep-water Aspen.

CANADA

o About 14% of our total 2003 investment program will be invested in Canadian
conventional exploration and production.

o We will focus on projects that provide the highest returns on invested
capital, while we transition to new sources of production growth such as
synthetic crude oil, coal bed methane and high-impact gas exploration.

DAILY PRODUCTION

We expect our core assets to generate daily production before royalties of
between 270,000 and 280,000 equivalent barrels in 2003. While production before
royalties will increase modestly, production after royalties is estimated to
grow 6% to 10%, to between 190,000 and 196,000 equivalent barrels per day, with
significant new royalty-free production from Aspen. Actual production rates will
depend upon numerous factors including commodity prices, the level of capital
expenditures, drilling success and well performance.

(mboe/d) 2003 ESTIMATE
- -------------------------------------------------------------------------------
BEFORE ROYALTIES AFTER ROYALTIES
------------------- ----------------------
Canada 77 - 82 61 - 64
Yemen 118 - 119 60 - 61
United States 46 - 52 39 - 45
Syncrude 17 - 18 17 - 18
Other International 12 - 16 11 - 14
------------------- ----------------------
270 - 280 190 - 196
=================== ======================

37

Over the next five years, production after royalties is expected to grow as our
production grows in the deep-water Gulf of Mexico and synthetic crude oil. Since
these projects have low or no royalties, lower costs and ultimately higher
returns than our current producing assets, this changing production mix will
improve profitability, despite lower anticipated oil prices. Using the mid-point
of our production range and assuming WTI averages US $23 per barrel and gas
prices average US $3.50 per thousand cubic feet in 2003, we expect cash flow
from operating activities of approximately $1.3 billion. For every dollar change
in WTI in 2003, our cash flow will change by $67 million. For every $0.50 change
in our North American natural gas price in 2003, our cash flow will change by
$61 million.

CHEMICALS AND MARKETING

We expect continuing strong performance from our chemicals and marketing
businesses in 2003. In our chemicals operation, increased demand for sodium
chlorate, higher margins for chlor-alkali, and operational efficiencies
resulting from our Brandon and Brazil expansions should improve cash flow. Our
oil and gas marketing business is growing in the fee for service segment and we
expect attractive margins, as many competitors have exited the sector.

MAJOR DEVELOPMENT PROJECTS

Details of the investment activities for each project are included in the 2002
Capital Investment section in this MD&A. Together these projects are expected to
add 55,000 to 65,000 equivalent barrels of daily production by 2007 as they
become core assets.

STRONG GRASS ROOTS EXPLORATION

Our 2003 exploration program is our highest quality ever as we plan to drill
prospects offsetting existing discoveries and extensions of play types we know
well. We expect to drill up to 18 high-impact wells. Our plans include:

GULF OF MEXICO

o We will invest approximately one-half of our exploration capital here.

o We plan to drill at least five high-impact exploration wells, including the
deep-water Gotcha prospect in the Alaminos Canyon area. This prospect
directly offsets the recently discovered Great White discovery. We will
also drill prospects in the Green Canyon and Garden Banks areas, and a Deep
Miocene gas prospect on the shelf.

o We plan to drill additional wells depending upon success and partner
priorities.

OTHER EXPLORATION

o In Yemen, we will continue interpreting seismic data on our exploration
blocks and drill at least one exploration well.

o Offshore Brazil, we plan to drill an exploration well on Block BC-20 in the
Campos Basin.

o In Canada, we will focus exploration on gas prospects in the foothills of
northwestern Alberta and in northeastern British Columbia.

CONTRACTUAL OBLIGATIONS, COMMITMENTS AND CONTINGENCIES

We have assumed various contractual obligations and commercial commitments in
the normal course of our operations and financing activities. Contractual
obligations include both financial and non-financial obligations. Financial
obligations are considered to represent known future cash payments that we are
required to make under existing contractual arrangements, such as debt and lease
arrangements. Non-financial obligations represent contractual obligations to
perform specified activities, such as work commitments. Commercial commitments
represent contingent obligations that become payable only if certain pre-defined
events occur.

CONTRACTUAL CASH OBLIGATIONS AND OTHER COMMERCIAL COMMITMENTS

(Cdn$ millions) Payments(1)
- --------------------------------------------------------------------------------------------------------------------

Total Less than 1 year 1-3 years 4-5 years More Than 5 years
----------------------------------------------------------------------------------

Long-Term Debt (1) 1,844 -- 355 258 1,231
Operating Leases 257 50 73 34 100
Transportation Commitments 428 180 72 63 113
Work Commitments 166 155 11 -- --
Other 9 7 2 -- --
----------------------------------------------------------------------------------
Total 2,704 392 513 355 1,444
==================================================================================

Notes:
(1) Payment obligations are not discounted and do not include related interest,
accretion or dividends.

38

o Long-term debt amounts are included in our December 31, 2002 Consolidated
Balance Sheet. Under US GAAP, $751 million of Preferred Securities due in
2047 and 2048 would be included in long-term debt. The fair value of these
securities is $756 million at December 31, 2002.

o Operating leases include leases for office space, rail cars, vehicles and
the lease of the FPSO in Australia.

o Our marketing operation manages various natural gas transportation
commitments on behalf of our Canadian oil and gas business and a number of
third-party customers. These activities help to optimize our trading
operations.

o Work commitments include non-discretionary capital spending related to
drilling and seismic commitments in our international operations and
development commitments at Gunnison and Syncrude. The remainder of our
capital spending in 2003, as discussed in the 2003 Outlook section in this
MD&A, is discretionary.

CONTINGENCIES

See note 10 to the Consolidated Financial Statements in Item 8, which is
incorporated herein by reference for a discussion of our contingencies.

BUSINESS RISK MANAGEMENT

The oil and gas industry is highly competitive, particularly in the following
areas:

o searching for and developing new sources of crude oil and natural gas
reserves;

o constructing and operating crude oil and natural gas pipelines and
facilities; and

o transporting and marketing crude oil, natural gas and other petroleum
products.

Our competitors include major integrated oil and gas companies and numerous
other independent oil and gas companies.

The pulp and paper chemicals market is also highly competitive. Key success
factors are:

o price and product quality;

o logistics and reliability of supply; and

o technical service.

We are one of the largest producers of sodium chlorate in North America and have
continent-wide supply capability.

OPERATIONAL RISK

Acquiring, developing and exploring for oil and natural gas involves many risks.
These include:

o encountering unexpected formations or pressures;

o premature declines of reservoirs;

o blow-outs, equipment failures and other accidents;

o craterings and sour gas releases;

o uncontrollable flows of oil, natural gas or well fluids;

o adverse weather conditions; and

o environmental risks.

Although we maintain insurance according to customary industry practice, we
cannot fully insure against all of these risks. Losses resulting from the
occurrence of these risks could have a material adverse impact.

Our future crude oil and natural gas reserves and production, and therefore our
operating cash flows and results of operations, are highly dependent upon our
success in exploiting our current reserve base and acquiring or discovering
additional reserves. Without reserve additions, our existing reserves and
production will decline over time as reserves are produced. The business of
exploring for, developing or acquiring reserves is capital intensive. To the
extent cash flows from operations are insufficient and external sources of
capital become limited or unavailable, our ability to make the necessary capital
investments to maintain and expand our oil and natural gas reserves will be
impaired.

UNCERTAINTY OF RESERVE ESTIMATES

Oil and gas reserve estimates are integral to making investment decisions
regarding oil and gas properties, such as whether development should proceed or
enhanced recovery methods should be undertaken. There are numerous uncertainties
inherent in estimating quantities of proved oil and natural gas reserves,
including many factors beyond our control. The reserve data included in the
Supplementary Financial Information in the Form 10-K represents estimates only.

39

In general, estimates of economically recoverable oil and natural gas reserves
and future net cash flows are based on a number of variable factors and
assumptions, such as:

o expected reservoir characteristics based on geological, geophysical and
engineering assessments;

o future production rates based on historical performance and expected future
operating and investment activities;

o future oil and gas prices and quality differentials;

o assumed effects of regulation by governmental agencies; and

o future development and operating costs.

We believe that the factors and assumptions used in estimating reserves are
reasonable based on the information available to us at the time the estimates
were prepared. Actual results could vary considerably, which could cause
material variances in the following:

o estimated quantities of proved oil and natural gas reserves in aggregate
and for any particular group of properties;

o reserve classification based on risk of recovery;

o future net revenues, including production, revenues, taxes, and development
and operating expenditures; and

o financial results including the annual rate of depletion and recognition of
property impairments.

Management is responsible for estimating the quantities of proved oil and
natural gas reserves. Estimates are prepared annually for each property by the
reservoir engineer associated with the property. Senior management, including
the Chief Executive Officer and Chief Financial Officer, meet with the reserves
managers for each division to review the estimates and changes therein.

We assess 100% of our reserve estimates internally each year. In addition, our
reserve estimates are assessed annually by independent qualified consultants.
Generally, the consultants assess at least 80% of our reserves. Given that the
reserves are estimates based on numerous assumptions and interpretations,
differences within 10% are considered to be immaterial. Differences greater than
10% are resolved.

The Board of Directors has established a Reserves Review Committee (Reserves
Committee) to assist the Board and the Audit and Conduct Review Committee of the
Board in fulfilling their oversight responsibilities with respect to the annual
review of our oil and gas reserves. The Reserves Committee is comprised of three
or more directors, the majority of whom must be independent, and each must have
a working familiarity with estimating oil and gas reserves. The Reserves
Committee meets with management periodically to review the reserves process,
results and related disclosures. The Reserves Committee also meets with the
consultants independent of management to review such things as the scope of
their work, their access to sufficient information, the nature and satisfactory
resolution of any differences of opinion, and their independence.

The estimated discounted future net cash flows from estimated proved reserves
included in the Supplementary Financial Information in the Form 10-K are based
on prices and costs as of the date of the estimate. Actual future prices and
costs may be materially higher or lower. Actual future net cash flows will also
be affected by factors such as actual production levels and timing, and changes
in governmental regulation or taxation and may differ materially from such
estimates. See the Critical Accounting Policies section of this MD&A for a
complete discussion of the impact of changes in our reserve estimates.

POLITICAL RISK

We operate in numerous countries, some of which may be considered politically
and economically unstable. Our operations and related assets are subject to the
risks of actions by governmental authorities, insurgent groups or terrorists. We
conduct our business and financial affairs to protect against political, legal,
regulatory and economic risks applicable to operations in the various countries
where we operate. However, there can be no assurance that we will be successful
in protecting ourselves from the impact of these risks.

In October 2002, there was an explosion and fire aboard the supertanker Limburg,
which was inbound for our Ash Shihr export terminal in Yemen. Our Masila block
operations were largely unaffected by this. Tanker loadings were delayed while
our tugboat secured the Limburg to prevent it from running aground. Loading then
resumed and oil exports continued as scheduled. This had no impact on our
production or cash flows.

Our Masila operations are important to Yemen, providing 50% of the country's oil
production. We are a responsible member of the Yemeni community; we build
relationships with its members and involve them in key decisions that impact
their lives. We also ensure that they benefit from our presence in their
country. Our strong relationship with the people and Government of Yemen has
allowed us to operate there without interruptions for almost 13 years and we
anticipate this continuing.

Our practices have enabled us to operate successfully, not only in Yemen, but
also other parts of the world. We have developed excellent practices to manage
the risks successfully.

40

ENVIRONMENTAL RISK

Environmental risks inherent in the oil and gas and chemicals industries are
becoming increasingly sensitive as related laws and regulations become more
stringent worldwide. Many of these laws and regulations require us to remove or
remedy the effect of our activities on the environment at present and former
operating sites, including dismantling production facilities and remediating
damage caused by the disposal or release of specified substances.

We manage our environmental risks through a comprehensive and sophisticated
Safety, Environmental and Social Responsibility (SESR) Management System that
meets or exceeds ISO14001 criteria and those of similar management systems.
Overall guidance and direction is provided by the SESR Committee of the Board of
Directors. In addition, senior management, including the CEO and CFO, regularly
meets with SESR management to review and approve SESR policies and procedures,
provide strategic direction, review performance and ensure that corrective
action is taken when necessary. We develop and implement proactive and
preventative measures designed to reduce or eliminate future environmental
liabilities, we are prudent and responsible in our management of existing
environmental liabilities, and we continuously seek opportunities for
performance improvement. In addition, we maintain an ongoing awareness of
external trends and emerging issues. These actions provide assurance that we
meet or exceed appropriate environmental standards worldwide.

o At December 31, 2002, $205 million has been provided in the Consolidated
Financial Statements for future dismantlement and site restoration costs,
which are currently estimated to be approximately $544 million for all of
our oil and gas and chemicals facilities.

o During 2002, we recorded a provision for future dismantlement and site
restoration costs of $43 million (2001 - $45 million; 2000 - $37 million).

o Actual site remediation expenditures for the year were $20 million (2001 &
2000 - $24 million). We anticipate actual site remediation expenditures in
2003 to approximate 2002 levels.

o We perform periodic internal and external assessments of our operations and
adjust our estimates and annual provision accordingly.

o During 2002, we conducted an external audit of our management system for
safety, environment and social responsibility issues. In general, the
review was very positive and the few minor recommendations for improvement
are being implemented.

KYOTO PROTOCOL

Canada was one of 160 countries that adopted the Kyoto Protocol in December
1997. This international treaty establishes commitments to reduce emissions of
greenhouse gases (GHG) that are believed to be responsible for increasing the
surface temperatures of the Earth and affecting the global climate. The Protocol
obliges approximately 38 countries (the Annex 1 countries) to meet national
targets that range from an increase of 10% to a reduction of 8% over a 1990
base. The overall reduction averages 5%, and these commitments are to be met
during the "first commitment period" of 2008 to 2012. Canada committed to a 6%
reduction over the 1990 base when it signed the Kyoto Protocol in April 1998.
Economic modelling studies have shown that if emission reductions are met
through domestic action in Annex 1 countries alone, there will be severe
negative impacts to these countries' economies, and in particular those such as
Canada whose economies are resource and energy intensive. The US Government's
decision to withdraw from the Kyoto Protocol has serious implications for Canada
in the context of a continental or hemispheric energy market, but we expect that
the US will develop a response to GHG strategies perhaps using the NAFTA model.

Nexen has been continually assessing, for over 8 years, the impact of climate
change developments on our various business interests. We have created a senior
management committee (The Climate Change Steering Group) to consider national
and international developments; hear from leading experts with respect to
science, business and risk issues; and consider investment opportunities. As
more details of Canada's domestic program have become available we have
undertaken cost analyses based on several carbon price and policy scenarios.
While the government has made concessions respecting price (a cap of $15 per
tonne) and volumes (a cap of 55 megatonnes for large industrial emitters), much
uncertainty remains for those investing in large, capital-intensive projects. We
have recreated a 1990 baseline and track and report our direct and indirect
emissions and GHG abatement/management activities via the Voluntary Challenge
and Registry (VCR). Our 2001 progress report is now posted on the VCR website
and the report shows further progress has been made toward reduction of our CO2
emissions and energy inputs per unit of production.

41

Nexen has looked to GHG emission reduction and to offset investments. In 1995,
we started capturing, compressing and selling methane gas from our Canadian
heavy oil operation instead of venting it to the atmosphere. Last year, we
captured about 950,000 tons of carbon dioxide equivalent (1,900,000 tons in
total since 1995); as a result, emissions in 2001 from our Canadian operations
were essentially the same as they were in 1990, despite growing production
volumes.

As a Canadian-based international oil and gas exploration and production
company, we have worked closely with the Canadian Clean Development
Mechanism/Joint Implementation Office of the Department of Foreign Affairs and
International Trade to ensure that Canadian companies get access to low
cost/high quality carbon offset investments. We continue to investigate
carbon-offset opportunities in each of our core countries in the belief that
there may be synergies between our oil and gas activities and carbon
investments. Investment opportunities considered to date have included
biological sequestration, renewable energy, process efficiency, flare and
fugitive emission reduction projects and fuel switching. We have invested in a
carbon sequestration project in Belize and a gasified power co-generation
facility at our Balzac gas plant. Both investments were expected to deliver
significant offsets, but may not provide the anticipated results due to evolving
domestic and international policies. We are also an investor in several research
and development projects investigating the technical and economic issues
associated with geological storage of CO2, including the use of CO2 for enhanced
coal bed methane recovery.

We continue to evaluate emission reduction and CO2 offset investment
opportunities. However, to date we have received no assurances from the federal
or provincial governments that credit will be given for actions already taken to
reduce direct emissions (i.e. methane previously vented from casing and tankage)
and indirect emissions (i.e. electricity from utilities). Further investment
opportunities will be considered against the risk of this evolving policy
framework and credit for early action. We continuously review the feasibility of
new and ongoing projects with respect to current social, political and economic
factors and will continue to take policy and requirements with respect to GHG
emissions into account when conducting these feasibility reviews.

We are committed to the principles of full disclosure and will continue to keep
our stakeholders apprised of how these issues affect us, when reasonably
determinable.

MARKET RISK MANAGEMENT

We are exposed to all of the normal market risks inherent within the oil and gas
and chemicals business, including commodity price risk, foreign-currency rate
risk, interest rate risk and credit risk. We manage our operations in a manner
intended to minimize our exposure, as described in note 6 to the Consolidated
Financial Statements, which is incorporated by reference here.

SENSITIVITIES

(Cdn$ millions) Cash Flow Net Income
- -----------------------------------------------------------------------------------------

Estimated 2003 impact:
Crude Oil - US $1.00/bbl change in WTI 67 49
Natural Gas - US $0.50/mcf change 61 38
Foreign Exchange - $0.01 change in US to Cdn Dollar 23 11
Interest Rates - 1% change 3 2
-------------------------

COMMODITY PRICE RISK

Commodity price risk related to conventional and synthetic crude oil prices is
our most significant market risk exposure. Crude oil prices and quality
differentials are influenced by worldwide factors such as OPEC actions,
political events and supply and demand fundamentals.

To a lesser extent we are also exposed to natural gas price movements. Natural
gas prices are generally influenced by North American supply and demand, and to
a lesser extent local market conditions.

NON-TRADING ACTIVITIES

The majority of our production is sold under short-term contracts, exposing us
to short-term price movements. The other energy contracts, we enter into also
expose us to commodity price risk between the time we purchase and sell
contracted volumes. At times, we actively manage these risks by using commodity
futures, forwards, swaps and options.

During 2002 and 2001, we purchased fixed-to-floating swaps to modify the terms
of certain fixed-price natural gas contracts as we prefer to receive an
index-based price for our natural gas. Under the terms of these contracts, we
must deliver four million cubic feet per day of natural gas to counterparties at
prices ranging from $3.06 to $6.08 per thousand cubic feet. On settlement, we
will receive or pay cash for the difference between the contract and floating
rates on the affected volumes. These swaps expire in 2003.

42

During 2001 and 2000, we purchased put options to establish a floor for the
price of crude oil, in order to mitigate the impact of potential crude oil price
declines. The put options effectively provided a minimum price per barrel equal
to the contract strike price for all hedged volumes if WTI crude oil price
averaged less than the strike price for the contract period. The contracts
expired unexercised, as WTI did not average less than the strike price during
the contract period.

TRADING ACTIVITIES

Our marketing operation is involved in the marketing and trading of crude oil
and natural gas, through the use of both physical and financial contracts
(energy trading activities). These activities expose us to commodity price risk.
Open positions exist where not all contracted purchases and sales have been
matched, in order to take advantage of market movements. These net open
positions allow us to generate income, but also expose us to risk of loss due to
fluctuating market prices (market risk) and credit exposure. We control the
level of market risk through daily monitoring of our energy-trading portfolio
relative to:

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

o nominal size of commodity positions;

o periodic loss; and

o stress testing.

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

o changes in commodity prices are normally distributed;

o price volatility remains stable; and

o price correlation relationships remain stable.

If a severe market shock was to occur, the key assumptions underlying our VaR
estimate could be violated and the potential loss could be greater than our VaR
estimate. There were no changes in the methodology we used to estimate VaR in
2002.

Stress testing complements our VaR estimate and measures the potential impact of
low probability extreme market shocks on the value of our energy-trading
portfolio. Stress test results are used to ensure that we are not exposed to
large losses that might result from infrequent but extreme market conditions
that are not captured by VaR.

We also have formal risk management policies relating to our energy trading
activities that have been approved by our Board of Directors. Market and credit
risks are monitored daily by a risk group that operates independently and
ensures compliance with our risk management policies. The Finance Committee of
the Board of Directors and our Risk Management Committee monitor our exposure to
the above risks and review the results of energy trading activities on a regular
basis.

FOREIGN-CURRENCY RATE RISK

A substantial portion of our operations are denominated in or referenced to US
dollars. These activities include:

o prices received for sales of crude oil, natural gas and certain chemicals
products;

o capital spending and expenses related to our oil and gas and chemicals
operations outside Canada; and

o short-term and long-term borrowings.

We manage our exposure to fluctuations between the US and Canadian dollar by
matching our expected net cash flows and borrowings in the same currency. Net
revenue from our foreign operations and our US-dollar borrowings are generally
used to fund US-dollar capital expenditures and debt repayments. Since the
timing of cash inflows and outflows is not necessarily interrelated,
particularly for capital expenditures, we maintain revolving US-dollar borrowing
facilities that can be used or repaid depending on expected net cash flows. We
have designated our long-term US-dollar borrowings as a hedge against our
US-dollar net investment in foreign operations.

We do not have any material exposure to highly inflationary foreign currencies.

We occasionally use derivative instruments to effectively convert cash flows
from Canadian to US dollars and vice versa. Information regarding our foreign
currency net investments, borrowings and related derivative instruments is
provided in note 6 to the Consolidated Financial Statements.

43

INTEREST RATE RISK

We are exposed to fluctuations in short-term interest rates as a result of the
use of floating-rate debt and, to a lesser extent, the use of derivative
instruments, as their market value is sensitive to interest rate fluctuations.
We maintain a portion of our debt capacity in revolving, floating rate bank
facilities with the remainder issued in fixed-rate borrowings. To minimize our
exposure to interest rate fluctuations, we occasionally use derivative
instruments as described in note 6 to the Consolidated Financial Statements.

At December 31, 2002, we had no floating-rate debt outstanding (2001 - $424
million, 2000 - $430 million).

CREDIT RISK

Credit risk is the risk of loss resulting from non-performance of contractual
obligations by a customer or counterparty. A substantial portion of our accounts
receivable are with customers in the energy industry and are subject to normal
industry credit risk. This concentration of risk within the energy industry is
mitigated through our broad domestic and international customer base. We are
also exposed to possible non-performance by derivative instrument
counterparties. We take the following measures to reduce this risk:

o we assess the financial strength of our customer and counterparty base
through a rigorous credit process;

o we limit the total exposure extended to individual counterparties, and may
require collateral from some counterparties;

o credit risk exposures, including concentrations of credit, are monitored
routinely and reported to our Risk Management Committee and the Finance
Committee of the Board;

o we set credit limits based on counterparty credit ratings and internal
models, which are based primarily on company and industry analysis;

o we review counterparty credit limits regularly; and

o we use standard agreements that allow for netting of positive and negative
exposures associated with a single counterparty.

We believe these measures minimize our overall credit risk. However, there can
be no assurance that these processes will protect us against all losses from
non-performance. At December 31, 2002:

o 90% of our counterparty exposures are investment grade; and

o only 4 customers individually made up greater than 5% of our exposure from
energy trading activities. All are investment grade.

CRITICAL ACCOUNTING POLICIES

As an oil and gas producer, there are a number of critical estimates underlying
the accounting policies applied in the preparation of our Consolidated Financial
Statements. These critical estimates are discussed below.

OIL AND GAS ACCOUNTING - RESERVES DETERMINATION

We follow the successful efforts method of accounting for our oil and gas
activities, as described in note 1 to our Consolidated Financial Statements.
Successful efforts accounting depends on the estimated reserves we believe are
recoverable from our oil and gas assets. The process of estimating reserves is
complex. It requires significant judgements and decisions based on available
geological, geophysical, engineering and economic data. These estimates may
change substantially as additional data from ongoing development and production
activities becomes available, and as economic conditions impacting oil and gas
prices and cost change. Our reserve estimates are based on current production
forecasts, prices and economic conditions. See Business Risk Management for a
complete discussion of our reserve estimation process.

Reserve estimates are critical to many of our accounting estimates, including:

o Determining whether or not an exploratory well has found economically
producible reserves. If successful, we capitalize the costs of the well,
and if not, we expense the costs immediately. In 2002, $189 million of our
total $259 million spent on exploration drilling was expensed in the year.
If none of our drilling had been successful, our net income would have
decreased by $46 million after tax.

o Calculating our unit-of-production depletion and asset retirement
obligation rates. Both proved and proved developed reserve(1) estimates are
used to determine rates that are applied to each unit-of-production in
calculating our depletion expense and our provision for dismantlement and
site restoration. Proved reserves are used where a property is acquired

- ---------------
(1) "Proved" oil and gas reserves are the estimated quantities of natural gas,
crude oil, condensate and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty can be recovered in
future years from known reservoirs under existing economic and operating
conditions. Reserves are considered "proved" if they can be produced
economically, as demonstrated by either actual production or conclusive
formation tests. "Proved developed" oil and gas reserves are expected to be
recovered through existing wells with existing equipment and operating
methods.

44

and proved developed reserves are used where a property is drilled and
developed. In 2002, oil and gas depletion and oil and gas dismantlement and
site restoration costs of $604 million and $43 million, respectively, were
recorded in depletion, depreciation and amortization expense. If our
reserve estimates changed by 10%, our depletion, depreciation and
amortization expense would have changed by approximately $45 million, after
tax, assuming no other changes to our reserve profile.

o Assessing, when necessary, our oil and gas assets for impairment. Estimated
future undiscounted cash flows are determined using proved reserves. The
critical estimates used to assess impairment, including the impact of
changes in reserve estimates, are discussed below.

As circumstances change and additional data becomes available, our reserve
estimates also change, possibly materially impacting net income. Estimates made
by our engineers are reviewed and revised, either upward or downward, as
warranted by the new information. Revisions are often required due to changes in
well performance, prices, economic conditions and governmental restrictions.

Although we make every reasonable effort to ensure that our reserve estimates
are accurate, the subjective decisions, new geological or production information
and changing environment may impact these estimates. Revisions to our reserve
estimates can arise from changes in year end oil and gas prices, and reservoir
performance. Such revisions can be either positive or negative. During the past
three years, revisions have been less than 10% of our total reserves and have
been largely related to price changes. Reserves information is shown in the
Supplementary Financial Information set out in Item 8 of this 10-K.

It would take a very significant decrease in our proved reserves to limit our
ability to borrow money under our term credit facilities, as previously
described in Liquidity.

OIL AND GAS ACCOUNTING - IMPAIRMENT

We evaluate our oil and gas properties for impairment if an adverse event or
change occurs. Among other things, this might include falling oil and gas
prices, a significant revision to our reserve estimates, or significant or
adverse political changes. If one of these occurs, we estimate undiscounted
future cash flows for affected properties to determine if they are impaired. If
the undiscounted future cash flows for a property are less than the carrying
amount of that property, we calculate its fair value using a discounted cash
flow approach. The property is then written down to its fair value. Our cash
flow estimates require assumptions about two primary elements - future prices
and reserves.

Our estimates of future prices require significant judgements about highly
uncertain future events. Historically, oil and gas prices have exhibited
significant volatility - over the last five years, prices for WTI and NYMEX gas
have ranged from US $10.35/bbl to US $37.80/bbl and US $1.61/mmbtu to US
$10.10/mmbtu, respectively. Our forecasts for oil and gas revenues are based on
a US $23 per barrel WTI and a US $3.50 per mcf gas price. These prices are
derived from a consensus of future price forecasts amongst industry analysts.
Our estimates of future cash flows generally assume our long-term price forecast
and current operating costs per barrel plus an inflation factor. Given the
significant assumptions required and the strong possibility that actual
conditions will differ, we consider the assessment of impairment to be a
critical accounting estimate. A change in this estimate would impact all except
our chemicals business.

We review all of our oil and gas properties for indications of impairment. Based
on this review, we have tested certain oil and gas properties for impairment
over the last two years. In each year, we determined that the sum of the
expected future cash flows, undiscounted, was greater than the carrying amount
of the properties. As a result, no impairment charges were recognized in net
income.

If we decreased our US $23 per barrel long-term forecast for WTI crude oil
prices by US $1.00-1.50/bbl at December 31, 2002, our initial assessment of
impairment indicators would not change. Furthermore, current crude oil prices
would have to fall over US $10 per barrel before our assessment would change.
Although oil and gas prices fluctuate a great deal in the short-term, they are
typically stable over a longer-time horizon. This mitigates the potential for
impairment.

It is difficult to determine and assess the impact of a decrease in our proved
reserves on our impairment tests. The relationship between the reserve estimate
and the estimated undiscounted cash flows, and the nature of the
property-by-property impairment test, is complex. As a result, we are unable to
provide a reasonable sensitivity analysis of the impact that a reserve estimate
decrease would have on our assessment of impairment. We do, however, have
confidence in our reserve estimates and we do not expect significant downward
revisions in the future.

A substantial increase in our estimated impairment provision would lower our net
income. We do not expect any significant impairment given that we expense all
unsuccessful exploration wells as they are drilled. This leaves us with very
little excess carrying value on our balance sheet.

45

We have discussed the development and selection of the critical accounting
estimates described above with the Audit and Conduct Review Committee of our
Board of Directors. The above disclosures have also been discussed with this
committee.

NEW ACCOUNTING PRONOUNCEMENTS

In December 2001, the Canadian Institute of Chartered Accountants (CICA) issued
Accounting Guideline 13, "Hedging Relationships" (AcG-13). AcG-13 establishes
certain conditions for when hedge accounting may be applied. The guideline is
effective for fiscal years beginning on or after July 1, 2003. Adoption of
AcG-13 is not expected to have a material impact on our financial position or
results of operations.

In September 2002, the CICA approved Section 3063, "Impairment of Long-Lived
Assets" (S.3063). S.3063 establishes standards for the recognition, measurement
and disclosure of the impairment of long-lived assets, and applies to long-lived
assets held for use. An impairment loss is recognized when the carrying amount
of a long-lived asset is not recoverable and exceeds its fair value. The new
Section is effective for fiscal years beginning on or after April 1, 2003.
Adoption of this Section is not expected to have a material impact on our
financial position or results of operations.

In December 2002, the CICA approved Section 3110, "Asset Retirement Obligations"
(S.3110). S.3110 requires liability recognition for retirement obligations
associated with our property, plant and equipment. These obligations are
initially measured at fair value, which is the discounted future value of the
liability. This fair value is capitalized as part of the cost of the related
asset and amortized to expense over its useful life. The liability accretes
until we expect to settle the retirement obligation. S.3110 is effective for
fiscal years beginning on or after January 1, 2004. The total impact on our
financial statements has not yet been determined.

The following standards and revisions issued by the CICA do not impact us:

o Amendments to S.3025 - "Impaired Loans", effective for asset foreclosures
on or after May 1, 2003

o Section 3475 - "Disposal of Long-Lived Assets and Discontinued Operations",
effective for disposal activities initiated by commitments to plans on or
after May 1, 2003.

In June 2001, the US Financial Accounting Standards Board (FASB) issued
Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS
143 requires liability recognition for retirement obligations associated with
our property, plant and equipment. These obligations are initially measured at
fair value, which is the discounted future value of the liability. This fair
value is capitalized as part of the cost of the related asset and amortized to
expense over its useful life. The liability accretes until we expect to settle
the retirement obligation. FAS 143 is effective for all fiscal years beginning
after June 15, 2002. The impact of adopting this standard is described in note
16(f) to the Consolidated Financial Statements.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45). FIN 45 elaborates on the disclosures we must
make about our obligations under certain guarantees that we have issued. It also
requires us to recognize, at the inception of a guarantee, a liability for the
fair value of the obligations we have undertaken in issuing the guarantee. The
initial recognition and initial measurement provisions are to be applied only to
guarantees issued or modified after December 31, 2002. Adoption of these
provisions will not have a material impact on our financial position or results
of operations. The disclosure requirements are effective for annual or interim
periods ending after December 15, 2002.

In January 2003, the FASB issued Statement No. 148 "Accounting for Stock-Based
Compensation - Transition and Disclosure, an Amendment of FASB Statement No.
123" (FAS 148). FAS 148 amends FAS 123 "Accounting for Stock-Based
Compensation", to provide alternative methods of transition for a voluntary
change to the fair-value based method of accounting for stock-based employee
compensation. In addition, FAS 148 amends the disclosure requirements of FAS 123
to require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. FAS 148 has no material impact on
us, as we do not plan to adopt the fair-value method of accounting for stock
options at the current time. We have included the required disclosures in note 8
to the Consolidated Financial Statements.

The following standards issued by the FASB do not impact us:

o Statement No. 145 - "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections" effective
for financial statements issued on or after May 15, 2002;

o Statement No. 146 - "Accounting for Costs Associated with Exit or Disposal
Activities" effective for exit or disposal activities initiated after
December 31, 2002;

o Statement No. 147 - "Acquisitions of Certain Financial Institutions - an
Amendment of FASB Statements No. 72 and 144 and FASB Interpretation No. 9"
effective for acquisitions on or after October 1, 2002; and

o Interpretation No. 46 - "Consolidation of Variable Interest Entities"
effective for financial statements issued after January 31, 2003.

46

ITEM 7(A). QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please refer to the Business and Marketing Risk Management sections of Item 7
for the required disclosures about Market Risk.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this report, including those appearing in Items 1 and 2 -
Business and Properties and Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operations, are forward-looking
statements.(1) Forward-looking statements are generally identifiable by terms
such as "plan", "expect", "estimate", "budget" or other similar words.

These 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. These risks, uncertainties and other factors include:

o market prices for oil, natural gas and chemicals products;

o our ability to produce and transport crude oil and natural gas to markets;

o the results of exploration and development drilling and related activities;

o foreign-currency exchange rates;

o economic conditions in the countries and regions in which we carry on
business;

o governmental actions that increase taxes, change environmental and other
laws and regulations;

o renegotiations of contracts; and

o political uncertainty, including actions by terrorists, insurgent groups or
war.

The above items and their possible impact are discussed more fully in the
section, titled "Business Risk Management" and "Market Risk Management" in Item
7.

The impact of any one risk, uncertainty or factors on a particular
forward-looking statement is not determinable with certainty as these factors
are interdependent and management's future course of action depends upon our
assessment of all information available at that time. Any statements regarding
the following are forward-looking statements:

o future crude oil, natural gas or chemicals prices;

o future production levels;

o future cost recovery oil revenues and our share of production from our
operations in Yemen;

o future capital expenditures and their allocation to exploration and
development activities;

o future sources of funding for our capital program;

o future debt levels;

o future cash flows and their uses;

o future drilling of new wells;

o ultimate recoverability of reserves;

o expected finding and development costs;

o expected operating costs;

o future demand for chemicals products;

o future expenditures and future allowances relating to environmental
matters; and

o dates by which certain areas will be developed or will come onstream.

We believe that the forward-looking statements made are reasonable based on
information available to us on the date such statements were made. However, no
assurance can be given as to future results, levels of activity and
achievements. All subsequent forward-looking statements, whether written or
oral, attributable to us or persons acting on our behalf are expressly qualified
in their entirety by these cautionary statements.

- ------------
(1) 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.

47

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION

REPORT OF MANAGEMENT...................................................... 49

REPORTS OF INDEPENDENT AUDITORS........................................... 50

CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Statement of Income .................................... 52
Consolidated Balance Sheet .......................................... 53
Consolidated Statement of Cash Flows ................................ 54
Consolidated Statement of Shareholders' Equity ...................... 55
Notes to Consolidated Financial Statements .......................... 56

SUPPLEMENTARY FINANCIAL INFORMATION (UNAUDITED)

Quarterly Financial Data in Accordance with Canadian and US GAAP..... 80
Oil and Gas Netbacks................................................. 81
Oil and Gas Producing Activities .................................... 82

48

REPORT OF MANAGEMENT

To the Shareholders of Nexen Inc.:

We are responsible for the preparation and integrity of all the information
contained in the accompanying consolidated financial statements. Fulfilling this
responsibility requires the preparation and presentation of our consolidated
financial statements in accordance with generally accepted accounting principles
in Canada with a reconciliation to generally accepted accounting principles in
the US. We have established disclosure controls and procedures, internal
controls and corporate-wide policies to ensure that Nexen's consolidated
financial position, results of operations and cash flows are presented fairly.

Our disclosure controls and procedures are designed to ensure timely disclosure
and communication of all material information required by regulators. We
oversee, with assistance from our Disclosure Review Committee, these controls
and procedures and all the required regulatory disclosures.

To gather and control financial data, we have established accounting and
reporting systems supported by internal controls and an internal audit program.
We believe that the existing internal controls provide reasonable assurance that
assets are safeguarded against loss from unauthorized use or disposition and
that the records are reliable for preparing consolidated financial statements
and other financial information. Financial information displayed in other
sections of this report has been reviewed to ensure consistency with the
consolidated financial statements.

To ensure the integrity of our financial statements, we carefully select and
train qualified personnel. We also ensure our organizational structure provides
appropriate delegation of authority and division of responsibilities. Our
policies and procedures are communicated throughout the organization including a
written ethics and integrity policy that applies to all employees including the
chief executive officer, chief financial officer and chief accounting officer or
controller.

Our Board of Directors approves the consolidated financial statements. Their
financial statement related responsibilities are fulfilled mainly through the
Audit and Conduct Review Committee (the Audit Committee) with assistance from
the Reserves Review Committee regarding the annual review of our crude oil and
natural gas reserves and from the Finance Committee regarding the assessment and
mitigation of risk. The Audit Committee is composed entirely of independent
directors, and includes three directors with financial expertise. The Audit
Committee meets regularly with management, the internal auditors, and external
auditors, to discuss reporting and control issues and ensures each party is
properly discharging its responsibilities. The Audit Committee also considers
the independence of the external auditors and reviews their fees. The internal
and external auditors have access to the Committee without the presence of
management.

On June 3, 2002, the Canadian firm of Deloitte & Touche LLP (Deloitte Canada)
completed a transaction with the Canadian firm of Arthur Andersen LLP (Andersen
Canada) to integrate the partners and staff of Andersen Canada into Deloitte
Canada. On July 11, 2002, Deloitte Canada, an independent firm of chartered
accountants, was appointed by the Board to audit the consolidated financial
statements, and to provide an independent professional opinion thereon.

/s Charles W. Fischer /s/ Marvin F. Romanow
- ------------------------------- ------------------------------
Charles W. Fischer Marvin F. Romanow
President and Chief Officer Executive Vice President,
and Chief Financial Officer

49

REPORT OF INDEPENDENT AUDITORS

To the Shareholders of Nexen Inc.:

We have audited the consolidated balance sheet of Nexen Inc. as at December 31,
2002 and the consolidated statements of income, cash flows and shareholders'
equity for the year then ended. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit.

We conducted our audit in accordance with generally accepted auditing standards
in Canada and the United States of America. Those standards require that we plan
and perform an audit to obtain reasonable assurance whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of Nexen Inc. as at December 31, 2002
and the results of its operations and its cash flows for the year then ended in
accordance with Canadian generally accepted accounting principles.

The consolidated financial statements of Nexen Inc. as at December 31, 2001 and
for each of the two years in the period ended December 31, 2001 were audited by
other auditors who have ceased operations. Those auditors expressed an opinion
without reservation on those consolidated financial statements in their report
dated January 23, 2002. As described in Note 1(r), certain amounts in these
consolidated financial statements have been reclassified to give effect to a
change in generally accepted accounting principles in 2002. We audited the
reclassification of amounts described in Note 1(r) that relate to the 2001 and
2000 consolidated financial statements. In our opinion, such reclassification is
appropriate and has been properly applied. However, we were not engaged to
audit, review or apply any procedures to the 2001 and 2000 consolidated
financial statements of Nexen Inc. other than with respect to such
reclassification and, accordingly, we do not express an opinion or any other
form of assurance on the 2001 and 2000 financial statements taken as a whole.

Calgary, Alberta /s/ Deloitte & Touche LLP
January 23, 2003 Chartered Accountants

50

THIS REPORT OF INDEPENDENT CHARTERED ACCOUNTANTS IS A COPY OF THE REPORT
PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED.

REPORT OF INDEPENDENT CHARTERED ACCOUNTANTS

To the Shareholders of Nexen Inc.:

We have audited the consolidated balance sheet of Nexen Inc. as at December 31,
2001 and 2000 and the consolidated statements of income, cash flows and
shareholders' equity for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards
in Canada and the United States. Those standards require that we plan and
perform an audit to obtain reasonable assurance whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.

In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 2001
and 2000 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2001 in accordance with generally
accepted accounting principles in Canada.

Calgary, Alberta /s/ Arthur Andersen LLP
January 23, 2002 Chartered Accountants

51

NEXEN INC.
CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2002
Cdn$ millions

2002 2001 2000
- -------------------------------------------------------------------------------------------------

REVENUES
Net Sales 2,606 2,593 2,705
Marketing and Other (Notes 1(r) and 12) 504 475 220
Gain (Loss) on Disposition of Assets (8) 5 42
-------------------------------
3,102 3,073 2,967
-------------------------------
EXPENSES
Operating 782 781 687
Transportation and Other (Note 1(r)) 469 400 182
General and Administrative 152 136 117
Depreciation, Depletion and Amortization 720 625 667
Exploration 189 265 173
Interest (Note 7) 109 112 132
-------------------------------
2,421 2,319 1,958
-------------------------------
INCOME BEFORE INCOME TAXES 681 754 1,009
-------------------------------
PROVISION FOR INCOME TAXES (Note 13)
Current 223 216 242
Future 6 88 165
-------------------------------
229 304 407
-------------------------------
NET INCOME 452 450 602

DIVIDENDS ON PREFERRED SECURITIES, NET OF INCOME TAXES (Note 8) 43 39 37
-------------------------------

NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 409 411 565
===============================

EARNINGS PER COMMON SHARE ($/share)
Basic (Note 9) 3.34 3.40 4.52
===============================
Diluted (Note 9) 3.30 3.36 4.46
===============================

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

52

NEXEN INC.
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2002 AND 2001
Cdn$ millions

2002 2001
- -------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 59 61
Accounts Receivable (Note 3) 988 609
Inventories and Supplies (Note 4) 256 189
Other 26 20
------------------
Total Current Assets 1,329 879

PROPERTY, PLANT AND EQUIPMENT (Note 5) 4,863 4,170
GOODWILL (Note 1) 36 36
FUTURE INCOME TAX ASSETS (Note 13) 263 212
DEFERRED CHARGES AND OTHER ASSETS 69 28
------------------

6,560 5,325
==================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings (Note 7) 18 51
Accounts Payable and Accrued Liabilities 1,194 773
Accrued Interest Payable 39 22
Dividends Payable 9 9
------------------
Total Current Liabilities 1,260 855
------------------

LONG-TERM DEBT (Note 7) 1,844 1,484
FUTURE INCOME TAX LIABILITIES (Note 13) 873 869
DISMANTLEMENT AND SITE RESTORATION 191 182
OTHER DEFERRED CREDITS AND LIABILITIES 44 31
SHAREHOLDERS' EQUITY (Note 8)
Preferred Securities 724 724
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2002 - 122,965,830 shares
2001 - 121,202,444 shares 440 389
Retained Earnings 1,069 697
Cumulative Foreign Currency Translation Adjustment 115 94
------------------
Total Shareholders' Equity 2,348 1,904
------------------

COMMITMENTS AND CONTINGENCIES (Note 10)
6,560 5,325
==================

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

Approved on behalf of the Board:

/s/ Charles W. Fischer /s/ David A. Hentschel
- ----------------------------- -----------------------------
Charles W. Fischer David A. Hentschel
Director Director

53

NEXEN INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 2002
Cdn$ millions

2002 2001 2000
- -----------------------------------------------------------------------------------------------------

OPERATING ACTIVITIES
Net Income 452 450 602
Charges and Credits to Income not Involving Cash (Note 14) 742 708 794
Exploration Expense 189 265 173
Changes in Non-Cash Working Capital (Note 14) (46) 143 (243)
Other (15) -- 3
-------------------------------
1,322 1,566 1,329
FINANCING ACTIVITIES
Proceeds from Long-Term Debt 882 315 2,467
Repayment of Long-Term Debt (511) (400) (2,284)
Proceeds from (Repayment of) Short-Term Borrowings, Net (33) (17) 59
Dividends on Preferred Securities (72) (70) (68)
Dividends on Common Shares (37) (37) (37)
Issue of Common Shares 51 39 45
Repurchase of Common Shares (Note 8) -- -- (605)
Changes in Non-Cash Working Capital (Note 14) -- -- (2)
Other (23) -- (2)
-------------------------------
257 (170) (427)
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (1,477) (1,162) (822)
Chemicals, Corporate and Other (144) (120) (58)
Proved Property Acquisitions (4) (122) (35)

Acquisition (Note 2) - -- (39)
Proceeds on Disposition of Assets 49 5 42
Changes in Non-Cash Working Capital (Note 14) 7 (18) 42
Other -- (52) (27)
-------------------------------
(1,569) (1,469) (897)
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
SHORT-TERM INVESTMENTS (12) 24 12
-------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM INVESTMENTS (2) (49) 17

CASH AND SHORT-TERM INVESTMENTS - BEGINNING OF YEAR 61 110 93
-------------------------------
CASH AND SHORT-TERM INVESTMENTS - END OF YEAR 59 61 110
===============================

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

54

NEXEN INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 2002
Cdn$ millions

CUMULATIVE
FOREIGN
CURRENCY
PREFERRED COMMON CONTRIBUTED RETAINED TRANSLATION
SECURITIES SHARES SURPLUS EARNINGS ADJUSTMENT
- --------------------------------------------- ------------- ---------------- ----------------- ---------------- -----------------
(Note 8) (Note 8)

DECEMBER 31, 1999 724 358 14 666 36
Exercise of Stock Options -- 25 -- -- --
Issue of Common Shares -- 20 -- -- --
Repurchase of Common Shares (Note 8) -- (53) (14) (535) --
Adoption of Liability Method of
Accounting for Income Taxes (Note 13) -- -- -- (336) --
Net Income -- -- -- 602 --
Dividends on Preferred Securities,
Net of Income Taxes -- -- -- (37) --
Dividends on Common Shares -- -- -- (37) --
Translation Adjustment,
Net of Income Taxes -- -- -- -- 27
------------- ---------------- ----------------- ---------------- -----------------
DECEMBER 31, 2000 724 350 -- 323 63
Exercise of Stock Options -- 16 -- -- --
Issue of Common Shares -- 23 -- -- --
Net Income -- -- -- 450 --
Dividends on Preferred Securities,
Net of Income Taxes -- -- -- (39) --
Dividends on Common Shares -- -- -- (37) --
Translation Adjustment,
Net of Income Taxes -- -- -- -- 31
------------- ---------------- ----------------- ---------------- -----------------
DECEMBER 31, 2001 724 389 -- 697 94
Exercise of Stock Options -- 27 -- -- --
Issue of Common Shares -- 24 -- -- --
Net Income -- -- -- 452 --
Dividends on Preferred Securities,
Net of Income Taxes -- -- -- (43) --
Dividends on Common Shares -- -- -- (37) --
Translation Adjustment,
Net of Income Taxes -- -- -- -- 21
------------- ---------------- ----------------- ---------------- -----------------

DECEMBER 31, 2002 724 440 -- 1,069 115
============= ================ ================= ================ =================

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

55

NEXEN INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions except as noted

1. ACCOUNTING POLICIES

The 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 Consolidated Financial
Statements is disclosed in Note 16. 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 Consolidated Financial
Statements, and revenues and expenses during the reporting period. Actual
results can differ from those estimates.

(A) PRINCIPLES OF CONSOLIDATION

The Consolidated Financial Statements include the accounts of Nexen Inc. and our
subsidiary companies and partnerships in which we have a controlling interest
(Nexen, we or our). All subsidiary companies and, effective April 18, 2000 all
partnerships, are wholly owned. All material intercompany accounts and
transactions have been eliminated. Substantially all exploration, development
and production activities related to our oil and gas business and the Syncrude
Joint Venture (Syncrude) are conducted jointly with others and our accounts
reflect only Nexen's proportionate interest.

(B) ACCOUNTS RECEIVABLE

Accounts receivable are recorded based on our revenue recognition policy (see
Note 1(i)). Our allowance for doubtful accounts provides for specific doubtful
receivables.

(C) INVENTORIES AND SUPPLIES

Inventories and supplies for our oil and gas and chemicals segments are stated
at the lower of cost or market value. Cost is determined on the first-in
first-out method or average basis.

After October 25, 2002, inventories held by our marketing operation are
accounted for at the lower of cost or market value determined on an average
basis. Prior to that these inventories were accounted for on a mark-to-market
basis. On October 25, 2002, generally accepted accounting principles followed by
energy traders eliminated mark-to-market accounting for inventories (see Note
1(r)).

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is recorded at cost. Improvements that increase
capacity or extend the useful lives of the related assets are capitalized. Major
maintenance or turnaround costs are expensed as incurred.

We follow successful efforts accounting for our oil and gas business. Under this
method, we capitalize the costs of resource property acquisitions, exploratory
drilling and all development. The cost of exploratory wells that are dry and all
other exploration costs, including geological and geophysical costs and annual
lease rentals, are charged to earnings.

We periodically evaluate our property, plant and equipment for impairment. If an
adverse event or change indicates possible impairment, we estimate the
undiscounted future cash flow for the related property. If the total
undiscounted future cash flow is less than the carrying amount of the property,
we calculate the fair value of the property using a discounted cash flow
approach and write down the property to that amount. The cash flow estimates
require assumptions about future commodity prices, operating costs and other
factors. Actual results can differ from those estimates.

(E) DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)

Under successful efforts accounting, oil and gas costs are depleted using the
unit-of-production method. Development costs are depleted over remaining proved
developed reserves and acquisition costs over proved reserves. Other plant and
equipment costs are depreciated using the straight-line method based on the
estimated useful lives of the assets, which range from 3 years to 30 years.
Unproved property costs and major projects that are under construction or
development are not depreciated, depleted or amortized.

(F) DISMANTLEMENT AND SITE RESTORATION

We provide for dismantlement and site restoration costs on our resource
properties, facilities, production platforms and pipelines and our chemicals
facilities. We estimate the total future dismantlement and site restoration
costs required to comply with current legislation and industry practices. We
then provide for those costs annually based on proved reserves or estimated
remaining asset lives. The annual provision is included in depreciation,
depletion and amortization. Expenditures are charged against the provision as
incurred.

56

(G) GOODWILL

On January 1, 2002, we adopted the new recommendations of the Canadian Institute
of Chartered Accountants (CICA). Under the new standard, goodwill and intangible
assets with an indefinite useful life are no longer amortized, but are tested
for impairment at least annually based on estimated future cash flows. No
goodwill impairment writedowns were required during the year. Our unamortized
goodwill at January 1, 2002 was $36 million. The following shows the adjusted
net income and earnings per common share had the new standard been applied in
2001 and 2000:

2002 2001 2000
- --------------------------------------------------------------------------------
Net Income Attributable to Common Shareholders
As Reported 409 411 565
Add: Goodwill Amortization - 6 5
-------------------------------
Adjusted 409 417 570
===============================

Earnings Per Common Share ($/share)
Basic as Reported 3.34 3.40 4.52
===============================
Adjusted 3.34 3.46 4.56
===============================

Diluted as Reported 3.30 3.36 4.46
===============================
Adjusted 3.30 3.42 4.50
===============================

(H) CARRIED INTEREST

According to our Masila Block agreement in Yemen (the Agreement), production
generated from the Masila Block (the Project) is shared between the Government
of Yemen (the Government), Nexen and the other Project participants. Production
is divided into cost recovery oil and profit oil.

Cost recovery oil provides for the recovery of operating, exploration and
development costs, based on a formula, and is limited to a maximum of 40% of
production during each fiscal year. Nexen and the other participants fund the
Government's share of exploration and development costs. Cost recovery oil
received by us is recorded as revenue, and includes a carried interest component
which allows us to recover the Government's share of exploration and development
costs we have incurred. Costs not recovered in the year may be recovered in
future years, and are included in property, plant and equipment. Recoveries of
capitalized carried costs are shown as depreciation or depletion expense.

Profit oil is the production remaining after deducting cost recovery oil. Profit
oil is shared by the Government and the Project participants on a sliding scale
based on production rates, and is accounted for using successful efforts
accounting. The Government's portion of profit oil includes an amount for
Nexen's income taxes payable under the laws of Yemen.

(I) REVENUE RECOGNITION

CRUDE OIL, NATURAL GAS AND CHEMICALS

Revenue is recognized when title passes to the customer. When we produce or sell
crude oil and natural gas above or below our working interest, production
overlifts and underlifts occur. Overlifts are recorded as liabilities, and
underlifts are recorded as assets. We settle these over time as liftings are
equalized, or in cash when production ceases.

MARKETING

Financial and physical commodity contracts (collectively derivative instruments)
held by our marketing operation are marked-to-market. Under mark-to-market
accounting, these contracts are recorded at fair value at the balance sheet
date. We record the net gain or loss on these contracts in marketing and other.
Prior to October 25, 2002 non-derivative instruments, including transportation
contracts, were also marked-to-market. As of October 25, 2002, costs relating to
these instruments are expensed as incurred. These costs are now recorded in
transportation and other (see Note 1(r)).

(J) INCOME TAXES

Effective January 1, 2000, we began following the liability method of accounting
for income taxes (see Note 13). This method recognizes income tax assets and
liabilities at enacted rates, based on differences between financial statement
reporting and tax amounts. The effect of a change in income tax rates on future
income tax assets and future income tax liabilities is recognized in income in
the period that the change occurs.

We do not provide for foreign withholding taxes on the undistributed earnings of
our foreign subsidiaries, since we intend to invest such earnings indefinitely
in foreign operations.

57

(K) PETROLEUM RESOURCE RENT TAX

Petroleum Resource Rent Tax with respect to our Australian oil and gas
operations is accounted for on the liability basis with a future liability or
asset recognized on temporary differences at the current enacted rate. Temporary
differences mainly relate to depletion, dismantlement and site restoration. We
treat the related cost as a royalty and deduct it from sales.

(L) FOREIGN CURRENCY TRANSLATION

Our foreign operations, which are considered financially and operationally
independent, are translated from their functional currency into Canadian dollars
as follows:

o assets and liabilities using exchange rates at the balance sheet dates; and

o revenues and expenses using the average exchange rates throughout the year.

Gains and losses resulting from this translation are included in the cumulative
foreign currency translation adjustment in shareholders' equity.

Monetary balances denominated in a currency other than a functional currency are
translated into the functional currency using exchange rates at the balance
sheet dates. Gains and losses arising from translation, except on our US-dollar
debt, are included in income. We have designated our US-dollar debt as a hedge
against our net investment in US-dollar based self-sustaining foreign
operations. Gains and losses resulting from the translation of the US-dollar
debt, to the extent they do not exceed our investment in foreign operations, are
included in the cumulative foreign currency translation adjustment in
shareholders' equity.

(M) CAPITALIZED INTEREST

We capitalize interest on qualifying assets until they are put into service,
using the weighted-average interest rate on all our borrowings.

(N) DERIVATIVE INSTRUMENTS

NON-TRADING ACTIVITIES

We use derivative instruments for non-trading purposes to manage fluctuations in
commodity prices, foreign currency exchange rates and interest rates, as
described in Note 6. Hedge accounting is used when there is a high degree of
correlation between price movements in the derivative instrument and the item
designated as being hedged. We recognize gains and losses in the same period as
the hedged item. If correlation ceases, hedge accounting is terminated and
future changes in the market value of the derivative instruments are recognized
as gains or losses in the period of change.

TRADING ACTIVITIES

Our marketing operation uses derivative instruments for marketing and trading
crude oil and natural gas. Derivative instruments used include:

o exchange-traded futures and options;

o non-exchange traded forwards, swaps and options; and

o commodity contracts settled with physical delivery.

We account for these instruments using mark-to-market accounting, and record the
net gain or loss in marketing and other. The fair value of these instruments is
recorded as accounts receivable or payable. They are classified as long term or
short term based on their anticipated settlement date.

(O) EMPLOYEE BENEFITS

The cost of pension benefits earned by employees in our defined benefit pension
plans is actuarially determined using the projected-benefit method prorated on
service and management's best estimate of the plans' investment performance,
salary escalations and retirement ages of employees. To calculate the plans'
expected returns, assets are measured at fair value. Past service costs arising
from plan amendments, and net actuarial gains and losses which exceed 10% of the
greater of the benefit obligation and the fair value of plan assets, are
amortized on a straight-line basis over the expected average remaining service
life of the employee group.

58

(P) STOCK-BASED COMPENSATION

We use the intrinsic value based method of accounting for stock options. Under
this method, no compensation expense has been recognized for stock options
granted to employees and directors. On January 1, 2002, we adopted the new CICA
recommendations. The new standard requires companies that do not recognize the
compensation expense determined under the fair-value based method to make pro
forma disclosures of net income and earnings per common share as if that method
of accounting had been applied (see Note 8).

We provide stock appreciation rights to employees as described in Note 8.
Obligations are accrued as compensation expense over the vesting period of the
stock appreciation rights.

(Q) CASH AND SHORT-TERM INVESTMENTS

Cash and short-term investments are instruments that mature within three months
of their purchase.

(R) CHANGES IN ACCOUNTING POLICIES - MARKETING ACTIVITIES

MARK-TO-MARKET

On October 25, 2002, regulators changed accounting principles, eliminating
mark-to-market accounting for our marketing inventories and our non-derivative
energy contracts. Under the new principles:

o we measure marketing inventories at the lower of cost or market; and

o we record non-derivative energy contracts, including our transportation and
storage capacity contracts, at cost as incurred.

We recorded the change to inventory prospectively as the effects on previous
periods cannot be determined. Inventories at October 25, 2002 have been
attributed a cost based on their market value on that date. Inventories
purchased after October 25, 2002 are recorded at cost. We removed the
mark-to-market on our transportation contracts from earnings retroactively to
the beginning of the year. The impact on previous years is immaterial. Under the
previous method, our results would have been:

2002
- -----------------------------------------------------------------------------
Net Income Attributable to Common Shareholders

As Reported 409
Mark-to-Market on inventory and transportation,
net of income taxes 4

--------

Adjusted 413
========

Earnings per Common Share ($/share)
Basic as Reported 3.34
========
Adjusted 3.37
========

Diluted as Reported 3.30
========
Adjusted 3.34
========

PRESENTATION OF TRANSPORTATION

During the year, we adopted the new interpretation of the Emerging Issues
Committee relating to the presentation of costs for which we are reimbursed. We
pay for the transportation of the crude oil, natural gas and chemicals products
that we market, and then bill our customers for the transportation. Under the
new interpretation, this transportation should be presented as a cost to us.
Previously, we netted this cost against our revenue. Effective October 1, 2002,
we show these costs as transportation and other on the consolidated statement of
income, resulting in the following increases:

2002 2001 2000
- -------------------------------------------------------------------------------

Net Sales 35 32 31
Marketing and Other 423 342 131

Transportation and Other 458 374 162

59

2. ACQUISITION

Effective July 31, 2000, our marketing business acquired Northridge Energy
Marketing Ltd. for cash consideration of $39 million. We used the purchase
method to account for the acquisition and included the results in our financial
statements from the acquisition date. The purchase consisted of the following:

Current Assets 172
Current Liabilities (155)
Goodwill 13
Property, Plant and Equipment 9
------
39
======

3. ACCOUNTS RECEIVABLE
2002 2001
- -----------------------------------------------------------------------------
Trade
Oil and Gas
Marketing 574 305
Other 330 220
Chemicals and Other 59 57
--------------------
963 582
Non-Trade 34 36
--------------------
997 618
Allowance for Doubtful Accounts (9) (9)
--------------------
988 609
====================

4. INVENTORIES AND SUPPLIES
2002 2001
- -----------------------------------------------------------------------------
Finished Products
Oil and Gas
Marketing 130 56
Other - 15
Chemicals and Other 13 15
--------------------
143 86
Work in Process 6 6
Field Supplies 107 97
--------------------
256 189
====================

60

5. PROPERTY, PLANT AND EQUIPMENT

2002 2001
- ---------------------------------------------------------------------------------------------------------------
Accumulated Net Book Accumulated Net Book
Cost DD&A Value Cost DD&A Value
------------------------------------- -----------------------------------------

Oil and Gas
Yemen 2,054 1,646 408 1,839 1,491 348
Canada 3,098 1,137 1,961 2,867 913 1,954
United States 2,186 959 1,227 1,636 848 788
Australia 209 184 25 167 144 23
Other Countries 305 198 107 271 166 105
Marketing 86 40 46 89 32 57
------------------------------------- -----------------------------------------
7,938 4,164 3,774 6,869 3,594 3,275
Syncrude 628 139 489 487 127 360
Chemicals 789 345 444 744 296 448
Corporate and Other 213 57 156 137 50 87
------------------------------------- -----------------------------------------

9,568 4,705 4,863 8,237 4,067 4,170
===================================== =========================================

The above table includes capitalized costs of $585 million (2001 - $251 million)
relating to unproved properties and projects under construction or development.
These costs are not being depreciated, depleted or amortized.

6. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

The nature of our operations and long-term debt expose us to fluctuations in
commodity prices, foreign-currency exchange rates, interest rates and credit
risk. We recognize these risks and manage our operations to minimize our
exposure to the extent practical and, to a lesser extent, using derivative
instruments. Our marketing operation uses derivative instruments to manage its
exposure to commodity price fluctuations and for trading purposes. We use
exchange-traded futures and options and non-exchange traded forwards, swaps and
options, which may be settled in cash or by delivery of the physical commodity.
The Finance Committee of the Board of Directors and our Risk Management
Committee monitor our exposure to the above risks and regularly review our
derivative activities and all outstanding positions.

(A) COMMODITY PRICE RISK MANAGEMENT

NON-TRADING ACTIVITIES

We generally sell our crude oil and natural gas under short-term market based
contracts. During 2001 and 2000, we purchased put options to establish a minimum
price for our crude oil to mitigate the impact of any price declines. This
minimum price per barrel equaled the contract strike price for all hedged
volumes if the West Texas Intermediate crude oil price (WTI) averaged less than
the strike price for the contract period. In 2001, we paid a US $13 million
premium for the put options. The contracts expired unexercised in 2002, as WTI
did not average less than the strike price during the contract period.

During 2002 and 2001, we purchased fixed-to-floating swaps to modify the terms
of certain fixed-price natural gas contracts as we prefer to receive an
index-based price for our natural gas. Under the terms of these contracts, we
must deliver 4 million cubic feet per day of natural gas to counterparties at
prices ranging from $3.06 to $6.08 per thousand cubic feet. On settlement, we
either pay or receive cash for the difference between the contract and floating
rates. These swaps expire in 2003.

TRADING ACTIVITIES

Our marketing operation engages in crude oil and natural gas marketing
activities to enhance prices from the sale of our own oil and gas production,
and for energy trading. We enter into contracts to purchase and sell crude oil
and natural gas. These contracts expose us to commodity price risk between the
time contracted volumes are purchased and sold. We actively manage this risk by
using energy-related futures, forwards, swaps and options, and by balancing
physical and financial contracts in terms of volumes, timing of performance and
delivery obligations. However, net open positions may exist, or we may establish
them to take advantage of market conditions.

61

Open positions enable our marketing operation to generate income based on
competitive information from marketing activities, but also expose us to risks
of loss from fluctuating market prices. Our exposure is restricted to prescribed
limits and is monitored daily using value-at-risk, stress testing and scenario
analysis. The value-at-risk calculation estimates the maximum probable loss,
given a 95% confidence level, that we would incur if our open positions were
unwound over two days. Our net margin from trading activities is as follows:

2002 2001 2000
- ------------------------------------------------------------------------------
Net Revenue 496 438 179
Less: Transportation 423 342 131
-------------------------------
73 96 48
===============================
Value-at-Risk
Year End 19 19 13
===============================
Average 17 13 4
===============================

(B) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

A substantial portion of our activities are transacted in or referenced to US
dollars. These activities include:

o prices received for sales of crude oil, natural gas and certain chemicals
products;

o capital spending and expenses related to our oil and gas and chemicals
operations outside Canada; and

o short-term and long-term borrowings.

We manage our exposure to fluctuations between the US and Canadian dollars by
minimizing the need to convert between the two currencies. Net revenue from our
foreign operations and our US-dollar borrowings are generally used to fund
US-dollar capital expenditures and debt repayments. Our US-dollar debt has been
designated as a hedge against our net investment in foreign operations. The
foreign exchange gains or losses realized on this debt are included in the
cumulative foreign currency translation adjustment in shareholders' equity. Our
net investment in foreign operations and our US-dollar long-term debt at
December 31 are as follows:

(US$ millions) 2002 2001
- --------------------------------------------------------------------------------
Net Investment in Foreign Operations 1,389 887
Long-Term Debt 962 728
-----------------

We do not have any material exposure to highly inflationary foreign currencies.

We occasionally use derivative instruments to effectively convert cash flows
from Canadian to US dollars and vice versa. At December 31, 2002, 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 (see Note 7).

(C) INTEREST RATE RISK MANAGEMENT

We use fixed and floating rate debt to finance our operations. The floating rate
debt exposes us to changes in interest payments as interest rates fluctuate. To
manage this exposure, we maintain a combination of fixed and floating rate
borrowings. At December 31, 2002, fixed-rate borrowings comprised 100% (2001 -
69%) of our long-term debt at an effective average rate of 7.4% (2001 - 7.0%).
During the year we periodically drew on our unsecured syndicated term credit
facilities. We had no interest rate swaps outstanding in 2002 or 2001.

(D) CREDIT RISK MANAGEMENT

A substantial portion of our accounts receivable are with customers in the
energy industry and are subject to normal industry credit risk. This
concentration of risk within the energy industry is reduced because of our broad
base of domestic and international customers. We are also exposed to possible
non-performance by derivative instrument counterparties. We assess the financial
strength of our customer and counterparty base, including those involved in
marketing and other commodity arrangements and we limit the total exposure to
individual counterparties. As well, a number of our contracts contain provisions
that allow us to demand the posting of collateral in the event downgrades to
non-investment grade occur. Credit risk, including credit concentrations are
routinely reported to our Risk Management Committee. We also use standard
agreements that net positive and negative exposures of a single counterparty. We
believe this minimizes our overall credit risk.

62

(E) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE INSTRUMENTS

Assets/(Liabilities) 2002 2001
- ------------------------------------------------------------------------------------------------------------------
Carrying Fair Unrealized Carrying Fair Unrealized
Value Value Gain/(Loss) Value Value Gain/(Loss)
---------------------------------------- ---------------------------------------

Long-Term Debt (1,844) (1,948) (104) (1,484) (1,465) 19
Currency Swap -- (3) (3) -- -- --
Preferred Securities (724) (756) (32) (724) (769) (45)
Crude Oil Put Options -- -- -- 2 -- (2)
Natural Gas Swaps -- 2 2 -- (7) (7)
---------------------------------------- ---------------------------------------

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 or
amounts derived from valuation models. The carrying value of cash and short-term
investments, amounts receivable and short-term obligations approximates their
fair value because the instruments are near maturity. Amounts receivable and
payable by our marketing operations related to derivative instruments are equal
to fair value as we use the mark-to-market method to value them. Amounts related
to derivative instruments included in deferred charges and other assets and
other deferred credits and liabilities are $14 million and $7 million,
respectively. These derivative instruments are held by our marketing operation
and settle beyond 2003.

7. LONG-TERM DEBT AND SHORT-TERM BORROWINGS

2002 2001
- --------------------------------------------------------------------------------
Unsecured Syndicated Term Credit Facilities (a) - 424
Unsecured Redeemable Notes, due 2004 (b) 355 358
Unsecured Redeemable Debentures, due 2006 (c) 108 109
Unsecured Redeemable Medium Term Notes, due 2007 (d) 150 150
Unsecured Redeemable Medium Term Notes, due 2008 (e) 125 125
Unsecured Redeemable Notes, due 2028 (f) 316 318
Unsecured Redeemable Notes, due 2032 (g) 790 -
------------------
1,844 1,484
==================

(A) UNSECURED SYNDICATED TERM CREDIT FACILITIES

Nexen has committed unsecured revolving term credit facilities totalling $1,576
million available for 5 years, and each lender has the option to extend them on
an annual basis. No repayments are required until the end of the availability
period. Borrowings are available in the form of Canadian bankers' acceptances,
LIBOR-based loans, Canadian prime loans or US-dollar base rate loans. Interest
is payable monthly at a floating rate. During 2002, the weighted average
interest rate was 2.5% (2001 - 6.0%).

(B) UNSECURED REDEEMABLE NOTES, DUE 2004

During February 1999, we issued US $225 million of notes. Interest is payable
semi-annually at a rate of 7.125%, and the principal is to be repaid in February
2004. 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.

(C) UNSECURED REDEEMABLE DEBENTURES, DUE 2006

During November 1996, we issued $100 million of unsecured 10-year redeemable
debentures. Interest is payable semi-annually at a rate of 6.85% and the
principal is to be repaid in November 2006. In December 1996, $50 million of
this obligation was effectively converted through a currency exchange contract
with a Canadian chartered bank to a US $37 million liability bearing interest at
6.75% for the term of the debentures. We may redeem part or all of the
debentures at any time. The redemption price will be the greater of par and an
amount that provides the same yield as a Government of Canada Bond having a term
to maturity equal to the remaining term of the debentures plus 0.1%.

(D) UNSECURED REDEEMABLE MEDIUM TERM NOTES, DUE 2007

During July 1997, we issued $150 million of notes. Interest is payable
semi-annually at a rate of 6.45% and the principal is to be repaid in July 2007.
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 Government of
Canada Bond having a term to maturity equal to the remaining term of the notes
plus 0.125%.

63

(E) UNSECURED REDEEMABLE MEDIUM TERM NOTES, DUE 2008

During October 1997, we issued $125 million of notes. Interest is payable
semi-annually at a rate of 6.3% and the principal is to be repaid in June 2008.
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 Government of
Canada Bond having a term to maturity equal to the remaining term of the notes
plus 0.125%.

(F) UNSECURED REDEEMABLE NOTES, DUE 2028

During April 1998, we issued US $200 million of notes. Interest is payable
semi-annually at a rate of 7.4% and the principal is to be repaid in May 2028.
We may redeem part or all of the notes 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
0.25%.

(G) UNSECURED REDEEMABLE NOTES, DUE 2032

During March 2002, we issued US $500 million of notes. Interest is payable
semi-annually at a rate of 7.875% and the principal is to be repaid in March
2032. 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 0.375%. Included in deferred charges and other assets is a debt
discount of US $14 million.

(H) DEBT REPAYMENTS

- ------------------------------------------------------------------
2003 -
2004 355
2005 -
2006 108
2007 150
Thereafter 1,231
-------
1,844
=======

(I) DEBT COVENANTS

The majority of our debt instruments contain covenants regarding certain
financial ratios and our ability to grant security. At December 31, 2002, we
were in compliance with all covenants.

(J) SHORT-TERM BORROWINGS

Nexen has unsecured operating loan facilities of approximately $301 million.
Interest is payable at floating rates and the facilities are subject to periodic
reviews. During 2002, the weighted average interest rate on short-term
borrowings was 2.3% (2001 - 5.5%).

Occasionally we sell the future proceeds of our accounts receivable; however, we
retain a 10% exposure to related credit losses. At December 31, 2002, we sold
$178 million (2001 - $100 million) of accounts receivable. The retained credit
exposure of $18 million (2001 - $10 million) is included in short-term
borrowings.

(K) INTEREST EXPENSE

2002 2001 2000
- ----------------------------------------------------------------------------
Long-Term Debt 134 106 125
Other 6 6 7
-------------------------
Total 140 112 132
Less: Capitalized 31 -- --
-------------------------
109 112 132
=========================

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

64

8. SHAREHOLDERS' EQUITY

(A) PREFERRED SECURITIES

Principal Amount Interest Rate Maturity Date Call Date
- -------------------------------------------------------------------------------------------------------------
(US$ millions) (%)

Preferred Securities 259 9.75 October 30, 2047 October 30, 2003
Preferred Securities 217 9.375 March 31, 2048 February 9, 2004
------------------------------------------------------------------------------

Nexen may redeem part or all of the preferred securities on or after their
redemption or call date. We may defer, subject to certain conditions, up to 20
consecutive quarterly interest payments and may satisfy our interest, principal
or redemption payments by issuing common shares. Interest is payable quarterly.

Since we have the unrestricted ability to settle the interest, principal and
redemption payments by issuing common shares, the preferred securities are
classified as equity. We record the principal amount in shareholders' equity and
interest payments, net of income taxes, are classified as dividends and charged
directly to retained earnings.

(B) AUTHORIZED CAPITAL

Authorized share capital consists of an unlimited number of common shares of no
par value, and an unlimited number of Class A preferred shares of no par value,
issuable in series.

(C) ISSUED COMMON SHARES AND DIVIDENDS

(thousands of shares) 2002 2001 2000
- -------------------------------------------------------------------------------
Beginning of Year 121,202 119,855 138,145
Issue of Common Shares for Cash:
Exercise of Stock Options 1,090 648 1,129
Dividend Reinvestment Plan 500 533 433
Employee Flow-through Shares 174 166 148
Repurchase of Common Shares - - (20,000)
--------------------------------
End of Year 122,966 121,202 119,855
================================
Dividends per Common Share ($/share) 0.30 0.30 0.30
================================
Cash Consideration (Cdn$ millions)
Exercise of Stock Options 27 16 25
Dividend Reinvestment Plan 17 17 14
Employee Flow-through Shares 7 6 6
--------------------------------
51 39 45
================================

At December 31, 2002, there were 1,783,968 (2001 - 489,329; 2000 - 1,022,545)
common shares reserved for issuance under the Dividend Reinvestment Plan.

In March 2000, Nexen, Ontario Teachers' Pension Plan Board (Teachers) and
Occidental Petroleum Corporation (Occidental) entered into an agreement where
Occidental would sell its 29% interest in Nexen. The agreement was approved by a
majority of Nexen shareholders other than Occidental and Teachers at a meeting
of shareholders on April 17, 2000. Under the agreement, Teachers purchased 20.2
million of Nexen's common shares. Nexen repurchased 20 million common shares for
$605 million, including associated fees. When repurchased, the common shares
were cancelled.

65

(D) STOCK OPTIONS GRANTED, EXERCISED AND FORFEITED

We have granted options to purchase common shares to directors, officers and
employees. Each option permits the holder to purchase one common share of Nexen
at the stated exercise price. Options granted prior to February 2001 vest over 4
years and are exercisable on a cumulative basis over 10 years. Options granted
after February 2001 vest over 3 years and are exercisable on a cumulative basis
over 5 years. At the time of grant, the exercise price is equal to the market
price. The following options have been granted:

Weighted-Average
Options Exercise Price
- -------------------------------------------------------------------------------
(thousands) ($/option)

DECEMBER 31, 1999 6,206 24
Granted 3,016 36
Exercised (1,129) 22
Forfeited (117) 25
----------
DECEMBER 31, 2000 7,976 29
Granted 1,645 31
Exercised (648) 24
Forfeited (142) 30
----------
DECEMBER 31, 2001 8,831 30
Granted 1,788 31
Exercised (1,090) 25
Forfeited (53) 30
----------
DECEMBER 31, 2002 9,476 30
==========

OPTIONS EXERCISABLE AT DECEMBER 31
2000 2,741 24
2001 4,232 27
2002 5,113 29
------------------------------

Common shares reserved for issuance under the stock option plan were 9,759,545
at December 31, 2002 (2001 - 10,896,060; 2000 - 8,044,680).

(E) EXERCISE PRICE RANGE

OUTSTANDING OPTIONS EXERCISABLE OPTIONS
- ----------------------------------------------------------------------------------------- --------------- ----------------
Weighted- Weighted- Weighted-
Average Average Average
Number of Exercise Years to Number of Exercise
Options Price Expiry Options Price
------------------------------------------- --------------- ----------------
(thousands) ($/option) (years) (thousands) ($/option)

$12.13 to $19.99 823 18 5 820 18
$20.00 to $24.99 272 23 4 272 23
$25.00 to $29.99 2,126 28 6 1,787 28
$30.00 to $34.99 3,474 33 4 624 31
$35.00 to $40.35 2,781 36 8 1,610 36
------------------------------------------- --------------- ----------------
9,476 5,113
=============== ===============

(F) ESTIMATED FAIR-VALUE OF STOCK OPTIONS

We determine the estimated fair value of stock options issued using the
Generalized Black-Scholes model under the following assumptions:

2002 2001 2000
- --------------------------------------------------------------------------------
Weighted-Average Fair Value ($/option) 9.08 12.24 13.06

Risk-Free Interest Rate (%) 3.6 5.1 5.8
Estimated Hold Period Prior to Exercise (years) 3 5 5
Volatility in the Price of Nexen's Common Shares (%) 35 40 34
Dividends per Common Share ($/share) 0.30 0.30 0.30
--------------------------

66

(G) PRO FORMA NET INCOME - FAIR-VALUE BASED METHOD OF ACCOUNTING FOR STOCK
OPTIONS

The following shows pro forma net income and earnings per common share had we
applied the fair-value based method of accounting to all stock options
outstanding.

2002 2001 2000
- -------------------------------------------------------------------------------
Net Income Attributable to Common Shareholders
As Reported 409 411 565
Less: Fair Value of Stock Options 22 25 14
----------------------------
Pro Forma 387 386 551
============================
Earnings Per Common Share ($/share)
Basic as Reported 3.34 3.40 4.52
============================
Pro Forma 3.16 3.20 4.41
============================
Diluted as Reported 3.30 3.36 4.46
============================
Pro Forma 3.13 3.16 4.35
============================

(H) STOCK APPRECIATION RIGHTS

We established a stock appreciation rights plan in 2001. Under this plan,
employees are entitled to cash payments equal to the excess of the market price
of the common shares over the exercise price of the right. The vesting period
and other terms of the plan are similar to the stock option plan. The total
rights granted and outstanding at any time cannot exceed 10% of Nexen's total
outstanding common shares.

(millions of rights) 2002 2001
- ------------------------------------------------------------------------------

Rights Granted 0.9 0.9
Rights Outstanding 1.8 0.9
Weighted Average Exercise Price ($/right) 33.94 31.17
Rights Expensed ($ millions) 2 --
------------------

9. EARNINGS PER COMMON SHARE

We calculate earnings per common share using Net Income Attributable to Common
Shareholders and the weighted average number of common shares outstanding. We
calculate diluted earnings per common share using Net Income Attributable to
Common Shareholders and the weighted-average number of diluted common shares
outstanding.

(millions of shares) 2002 2001 2000
- ------------------------------------------------------------------------------------------------

Weighted-average number of common shares outstanding 122.4 120.7 125.0
Shares issuable pursuant to stock options 8.1 4.7 5.5
Shares to be purchased from proceeds of stock options (6.7) (3.3) (3.7)
---------------------------------
Weighted-average number of diluted common shares outstanding 123.8 122.1 126.8
=================================

In calculating diluted earnings per common share for the year ended December 31,
2002, we excluded 46,167 options (2001 - 2,992,903; 2000 - 42,000), because the
exercise price was greater than the average market price of our common shares in
those periods. During these three years, outstanding stock options were the only
dilutive instrument.

10. COMMITMENTS AND CONTINGENCIES

2003 2004 2005 2006 2007 THEREAFTER
- -----------------------------------------------------------------------------------------

Operating leases 50 39 34 18 16 100
Transportation commitments 180 40 32 32 31 113

------------------------------------------------------
230 79 66 50 47 213
======================================================

In November 2000, we committed to enter into a lease agreement when construction
of a natural-gas-fired generating facility in Alberta was completed. On June 28,
2002, we exercised our option to buy out the lease for $67 million, which was
the cost of construction plus interest on advances during the construction
phase. We included this amount in capital expenditures for the year ended
December 31, 2002.

67

There are a number of lawsuits and claims pending including income tax
reassessments as described in Note 13, the ultimate results of which cannot be
ascertained at this time. We record costs as they are incurred or become
determinable. Management believes the resolution of these matters would not have
a material adverse effect upon our consolidated financial position or results of
operations.

11. PENSION AND OTHER POST RETIREMENT BENEFITS

Nexen has contributory and non-contributory defined benefit and defined
contribution pension plans, which together cover substantially all employees.
Syncrude has a defined benefit plan for its employees, and all of the Syncrude
information in this note is Nexen's proportionate interest. Under these plans,
we provide benefits to retirees based on their length of service and final
average earnings.

(A) DEFINED BENEFIT PENSION PLANS

The cost of pension benefits earned by employees is determined using the
projected-benefit method prorated on employment services and is expensed as
services are rendered. We fund this plan according to federal and provincial
government regulations by contributing to trust funds administered by an
independent trustee. These funds are invested primarily in equities and bonds.

2002 2001
- ----------------------------------------------------------------------------------------------------------------
Change in Benefit Obligation Nexen Syncrude Nexen Syncrude
-------------------------- -----------------------------

Beginning of Year 163 63 131 54
Service Cost 7 3 5 2
Interest Cost 10 4 9 4
Plan Participants' Contributions 2 -- 2 --
Actuarial Loss/(Gain) (11) -- 18 5
Benefits Paid (7) (2) (6) (2)
Plan Amendment -- -- 4 --
-------------------------- -----------------------------
End of Year 164 68 163 63
========================== =============================
Change in Fair Value of Plan Assets
Beginning of Year 136 41 148 43
Actual Return on Plan Assets (7) (3) (12) (2)
Employer's Contribution 3 1 4 2
Plan Participants' Contributions 2 -- 2 --
Benefits Paid (7) (2) (6) (2)
-------------------------- -----------------------------
End of Year 127 37 136 41
========================== =============================
Reconciliation of Funded Status
Funded Status (1) (37) (31) (27) (22)
Unamortized Transitional Obligation 1 -- 2 --
Unamortized Prior Service Costs 6 1 6 1
Unamortized Net Actuarial Loss 19 23 13 17
-------------------------- -----------------------------
Pension Liability (11) (7) (6) (4)
========================== =============================
Assumptions (%)
Discount Rate 6.75 6.50 6.25 6.50
Long-Term Rate of Employee Compensation
Increase 4.00 4.00 4.00 4.00
Long-Term Annual Rate of Return on Plan Assets 7.00 9.00 7.00 9.00
-------------------------- --- -----------------------------

Note:
(1) Included in the above amounts are unfunded obligations for supplemental
benefits to the extent that the benefit under the defined benefit pension
plan is limited by statutory guidelines. At December 31, 2002, the
projected benefit obligation for supplemental benefits was $26 million
(2001 - $25 million).

68

NET PENSION EXPENSE UNDER OUR DEFINED BENEFIT PENSION PLANS

2002 2001 2000
- --------------------------------------------------------------------------------
Nexen
Cost of Benefits Earned by Employees 7 5 5
Interest Cost on Benefits Earned 10 9 9
Expected Return on Plan Assets (10) (10) (9)
Net Amortization and Deferral 1 - -
-----------------------------
Net 8 4 5
-----------------------------
Syncrude
Cost of Benefits Earned by Employees 3 2 2
Interest Cost on Benefits Earned 4 4 3
Expected Return on Pension Plan Assets (4) (4) (4)
Net Amortization and Deferral 1 - -
-----------------------------
Net 4 2 1
-----------------------------
Total 12 6 6
=============================

(B) DEFINED CONTRIBUTION PENSION PLANS

Under these plans, pension benefits are based on plan contributions. During
2002, Canadian pension expense for these plans was $3 million (2001 - $3
million; 2000 - $2 million). During 2002, US pension expense for these plans was
$3 million (2001 - $3 million; 2000 - $2 million).

(C) POST-RETIREMENT BENEFITS

Nexen provides certain post-retirement benefits, including group life and
supplemental health insurance, to eligible employees and their dependents. These
costs are fully accrued as compensation in the period employees work; however,
these future obligations are not funded.

12. MARKETING AND OTHER

2002 2001 2000
- ------------------------------------------------------------------------------

Marketing Net Revenue (including Transportation) 496 438 179
Interest 7 17 21
Foreign Exchange Gains (Losses) (3) - 3
Other 4 20 17
----------------------------
504 475 220
============================

13. INCOME TAXES

(A) CHANGE IN ACCOUNTING POLICY

Effective January 1, 2000, we adopted the CICA's new recommendations on
accounting for income taxes and applied it retroactively without restating prior
periods. The new recommendations use the liability method. The change in
accounting policy increased (decreased) the following items on the Consolidated
Financial Statements as at January 1, 2000:

Future Income Tax Assets 450
Future Income Tax Liabilities 786
Retained Earnings (336)

Retained earnings decreased because of the future income tax cost of the Wascana
Energy Inc. (Wascana) acquisition in 1997, in which the acquired tax basis was
less than the purchase price.

69

(B) TEMPORARY DIFFERENCES

2002 2001
- ---------------------------------------------------------------------------------------------------------
Future Future Future Future
Income Tax Income Tax Income Tax Income Tax
Assets Liabilities Assets Liabilities
------------------------------- -------------------------------

Property, Plant and Equipment, Net 23 704 111 721
Tax Losses Carried Forward 226 -- 34 --
Deferred Income -- 177 -- 139
Foreign Exchange -- -- 1 3
Recoverable Taxes 14 -- 101 --
Other -- (8) 9 6
------------------------------- -------------------------------
263 873 256 869
Valuation Allowance(1) -- -- (44) --
------------------------------- -------------------------------
263 873 212 869
=============================== ===============================

(1) The future income tax asset valuation allowance related to foreign tax
credits being carried forward.

(C) CANADIAN AND FOREIGN INCOME TAXES

2002 2001 2000
- -------------------------------------------------------------------------------
Income before Income Taxes
Canadian 140 225 240
Foreign 541 529 769
-------------------------------
681 754 1,009
===============================
Provision for Income Taxes
Current
Canadian 4 6 7
Foreign 219 210 235
-------------------------------
223 216 242
===============================
Future
Canadian 38 81 119
Foreign (32) 7 46
-------------------------------
6 88 165
===============================

The Canadian and foreign components of the provision for income taxes are based
on the jurisdiction in which income is taxed. Foreign taxes relate mainly to
Yemen, the United States and Australia, and included Yemen cash taxes of $207
million (2001 - $191 million; 2000 - $217 million).

(D) RECONCILIATION OF EFFECTIVE TAX RATE TO THE CANADIAN FEDERAL TAX RATE

2002 2001 2000
- -------------------------------------------------------------------------------------------------------

Income before Income Taxes 681 754 1,009
================================
Provision for Income Taxes Computed at the Canadian Statutory Rate 269 317 449
Add (Deduct) the Tax Effect of:
Royalties and Rentals to Provincial Governments 57 66 79
Resource Allowance and Provincial Tax Rebates (67) (68) (81)
Lower Tax Rates on Foreign Operations (37) (15) (45)
Additional Canadian Tax on Canadian Resource Income 8 2 --
Federal and Provincial Capital Tax 4 5 6
Other (5) (3) (1)
--------------------------------
Provision for Income Taxes 229 304 407
================================

During 2002 and 2001, the federal and some provincial governments in Canada
reduced statutory income tax rates. This reduced our liability and provision for
future income taxes by $1 million (2001 - $5 million). The federal rate
reduction does not apply to our earnings from Canadian resource properties.

70

(E) AVAILABLE UNUSED TAX LOSSES AND TAX CONTINGENCIES

At December 31, 2002, we had unused tax losses totalling $534 million (2001 -
$71 million) of which the majority relate to our US operations.

Nexen's income tax filings are subject to audit by taxation authorities. There
are audits in progress and items under review, some that may increase our tax
liability. In addition, we have filed Notices of Objection with respect to
certain issues. While the results of these items cannot be ascertained at this
time, management believes there is adequate provision for income taxes based on
available information.

At the time of acquisition, Wascana had outstanding taxation issues in dispute
from prior taxation years. Wascana disagreed with issues raised and has filed
Notices of Objection. The value of the tax pools acquired at the time of
acquisition reflected management's evaluation of the potential impact of these
issues.

14. CASH FLOWS

(A) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH

2002 2001 2000
- -----------------------------------------------------------------------------------------------------

Depreciation, Depletion and Amortization 720 625 667
Loss (Gain) on Disposition of Assets 8 (5) (42)
Future Income Taxes 6 88 165
Other 8 -- 4
------------------------------
742 708 794
==============================

(B) CHANGES IN NON-CASH WORKING CAPITAL
2002 2001 2000
- -----------------------------------------------------------------------------------------------------

Operating Activities
Accounts Receivable (388) 471 (521)
Inventories and Supplies (73) 73 (120)
Other Current Assets (6) (5) 3
Accounts Payable and Accrued Liabilities 407 (399) 390
Accrued Interest Payable 17 1 (1)
Dividends Payable -- -- (1)
Effect of Foreign Exchange Rate Changes on Non-Cash Working
Capital (3) 2 7
------------------------------
(46) 143 (243)
Financing Activities
Accounts Payable and Accrued Liabilities -- -- (2)

Investing Activities
Accounts Payable and Accrued Liabilities 7 (18) 42
------------------------------
Total (39) 125 (203)
==============================

(C) OTHER CASH FLOW INFORMATION
2002 2001 2000
- -----------------------------------------------------------------------------------------------------

Interest Paid 117 106 133
Income Taxes Paid 238 211 236
------------------------------

71

15. OPERATING SEGMENTS AND RELATED INFORMATION

Nexen has three operating segments in various industries and geographic
locations:

OIL AND GAS: We explore for, develop and produce crude oil, natural gas and
related products around the world. We manage our operations to reflect
differences in the regulatory environments and risk factors for each country.
Our core operations are onshore in Yemen and Canada, and offshore in the US Gulf
of Mexico and Australia. Our other operations are primarily in Nigeria,
Colombia, and Brazil. Oil and gas also includes our marketing operations.
Marketing sells our own crude oil and natural gas, markets third party crude oil
and natural gas and engages in energy trading.

SYNCRUDE: We own 7.23% of the Syncrude Joint Venture, which develops and
produces synthetic crude oil from oil sands in northern Alberta, Canada.

CHEMICALS: We manufacture, market and distribute industrial chemicals,
principally sodium chlorate, chlorine and caustic soda. We produce sodium
chlorate at five facilities in Canada, one in the United States and one in
Brazil. We produce chlorine and caustic soda at chlor-alkali facilities in
Canada and Brazil.

The accounting policies of our operating segments are the same as those
described in Note 1. Net income of our operating segments excludes interest
income, interest expense, unallocated corporate expenses and foreign exchange
gains and losses. Identifiable assets are those used in the operations of the
segments.

72

2002 OPERATING AND GEOGRAPHIC SEGMENTS
(Cdn$ millions)

Corporate
and
Oil and Gas Syncrude Chemicals Other(a) Total
- ----------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(b) Marketing
----------------------------------------------------------

Net Sales (j) 789 656 296 165 78 -- 245 367(c) 10 2,606
Marketing and Other -- 2 -- -- -- 496 -- 2 4 504
Gain (Loss) on Disposition of
Assets -- (21)(d) -- -- -- -- -- -- 13 (e) (8)
-------------------------------------------------------------------------------------------------
Total Revenues 789 637 296 165 78 496 245 369 27 3,102
Operating 86 176 94 50 22 - 115 229 10 782
Transportation and Other -- -- 3 -- -- 423 -- 40 3 469
General and Administrative 4 22 11 1 19 30 1 21 43 152
Depreciation, Depletion and
Amortization 149 253 133 53 46 8 13 52 13 720
Exploration 21 38 82 3 45(f) -- -- -- -- 189
Interest -- -- -- -- -- -- -- -- 109 109
-------------------------------------------------------------------------------------------------
Income (Loss) before Income
Taxes 529 148 (27) 58 (54) 35 116 27 (151) 681
Less: Provision for (Recovery
of) Income Taxes(g) 188 59 (10) 19 (18) 12 37 9 (67) 229
-------------------------------------------------------------------------------------------------
Net Income (Loss) 341 89 (17) 39 (36) 23 79 18 (84) 452
=================================================================================================

Identifiable Assets 600 2,124 1,452 63 159 811(h) 536 538 277 6,560
=================================================================================================
Capital Expenditures
Development and Other 209 258 541 46 23 2 141 45 97(i) 1,362
Exploration 22 60 116 3 58 -- -- -- -- 259
Proved Property Acquisitions -- 4 -- -- -- -- -- -- -- 4
-------------------------------------------------------------------------------------------------
231 322 657 49 81 2 141 45 97 1,625
=================================================================================================
Property, Plant and Equipment
Cost 2,054 3,098 2,186 209 305 86 628 789 213 9,568
Less: Accumulated DD&A 1,646 1,137 959 184 198 40 139 345 57 4,705
------- ------- -------- ---------- ---------- ---------- --------- ---------- ---------- ------
Net Book Value (j) 408 1,961 1,227 25 107 46 489 444 156 4,863
=================================================================================================
Goodwill
Cost -- -- -- -- -- 60 -- -- -- 60
Less: Accumulated DD&A -- -- -- -- -- 24 -- -- -- 24
------- ------- -------- ---------- ---------- ---------- --------- ---------- ---------- ------
Net Book Value -- -- -- -- -- 36 -- -- -- 36
=================================================================================================

Notes:
(a) Includes results of operations from a natural gas-fired generating facility
in Alberta.

(b) Includes results of operations from producing activities in Nigeria and
Colombia.

(c) Net sales for our chemicals operations include:

Canada $ 251
United States 56
Brazil 60
--------
$ 367
========

(d) On December 30, 2002, we disposed of non-operated oil and gas properties
for proceeds of $14 million.

(e) On January 2, 2002, we disposed of our Moose Jaw Asphalt operation for
proceeds of $27 million plus working capital.

(f) Includes exploration activities primarily in Nigeria, Colombia and Brazil.

(g) The provision for (recovery of) income taxes for foreign locations is based
on in-country taxes on foreign income. For oil and gas locations with no
operating activities, the provision is based on the tax jurisdiction of the
entity performing the activity.

(h) Approximately 70% of Marketing's identifiable assets are accounts
receivable.

(i) Includes $67 million related to the buy out of lease agreement related to
the construction of a natural gas-fired generating facility in Alberta.

(j) Net sales made from all segments originating in Canada. $ 1,162
Property, plant and equipment located in Canada. $ 2,908

73

2001 OPERATING AND GEOGRAPHIC SEGMENTS
(Cdn$ millions)

Corporate
and
Oil and Gas Syncrude Chemicals Other(a) Total
- -----------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(b) Marketing
----------------------------------------------------------

Net Sales (g) 711 647 358 141 61 -- 225 373(c) 77 2,593
Marketing and Other -- 10 1 -- 6 438 -- 3 17 475
Gain on Disposition of Assets -- -- 1 3 -- -- -- -- 1 5
--------------------------------------------------------------------------------------------------
Total Revenues 711 657 360 144 67 438 225 376 95 3,073
Operating 71 155 66 52 19 - 114 243 61 781
Transportation and Other -- -- -- -- -- 342 -- 34 24 400
General and Administrative 3 25 8 1 21 23 1 18 36 136
Depreciation, Depletion and
Amortization 111 227 116 65 31 14 12 34 15 625
Exploration 25 44 101 13 82 (d) -- -- -- -- 265
Interest -- -- -- -- -- -- -- -- 112 112
-------------------------------------------------------------------------------------------------
Income (Loss) before Income
Taxes 501 206 69 13 (86) 59 98 47 (153) 754
Less: Provision for (Recovery
of) Income Taxes (e) 185 90 27 5 (24) 26 32 16 (53) 304
-------------------------------------------------------------------------------------------------
Net Income (Loss) 316 116 42 8 (62) 33 66 31 (100) 450
=================================================================================================

Identifiable Assets(f) 520 2,123 880 47 179 470 399 534 173 5,325
=================================================================================================

Capital Expenditures
Development and Other 185 367 120 (4) 23 -- 60 73 47 871
Exploration 44 84 197 12 74 -- -- -- -- 411
Proved Property Acquisitions -- 7 115 -- -- -- -- -- -- 122
-------------------------------------------------------------------------------------------------
229 458 432 8 97 -- 60 73 47 1,404
=================================================================================================

Property, Plant and Equipment
Cost 1,839 2,867 1,636 167 271 89 487 744 137 8,237
Less: Accumulated DD&A 1,491 913 848 144 166 32 127 296 50 4,067
-------------------------------------------------------------------------------------------------
Net Book Value (g) 348 1,954 788 23 105 57 360 448 87 4,170
=================================================================================================

Goodwill
Cost -- -- -- -- -- 60 -- -- -- 60
Less: Accumulated DD&A -- -- -- -- -- 24 -- -- -- 24
-------------------------------------------------------------------------------------------------
Net Book Value -- -- -- -- -- 36 -- -- -- 36
=================================================================================================

Notes:
(a) Includes results of our Moose Jaw Asphalt operation, which was disposed of
on January 2, 2002.

(b) Includes results of operations from producing activities in Nigeria.

(c) Net sales for our chemicals operations include:

Canada $ 241
United States 90
Brazil 42
-----------
$ 373
===========

(d) Includes exploration activities primarily in Nigeria, Indonesia, and
Colombia.

(e) The provision for (recovery of) income taxes for foreign locations is based
on in-country taxes on foreign income. For oil and gas locations with no
operating activities, the provision is based on the tax jurisdiction of the
entity performing the activity.

(f) Approximately 65% of Marketing's identifiable assets are accounts
receivable.

(g) Net sales made from all segments originating in Canada. $ 1,190

Property, plant and equipment located in Canada. $ 2,709

74

2000 OPERATING AND GEOGRAPHIC SEGMENTS
(Cdn$ millions)

Corporate
and
Oil and Gas Syncrude Chemicals Other(a) Total
- -----------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(b) Marketing
----------------------------------------------------------

Net Sales (h) 752 698 382 167 78 -- 199 336(c) 93 2,705
Marketing and Other 6 2 -- -- 1 179 -- 7 25 220
Gain on Disposition of Assets -- 23 1 -- 18(d) -- -- -- -- 42
------- ------- ------- --------- ----------- ---------- ---------- ----------- ---------- ------
Total Revenues 758 723 383 167 97 179 199 343 118 2,967
Operating 58 135 55 27 22 - 98 213 79 687
Transportation and Other -- -- -- -- -- 131 -- 34 17 182
General and Administrative 3 21 6 1 17 12 -- 17 40 117
Depreciation, Depletion and
Amortization 90 233 139 86 40 13 12 40 14 667
Exploration 14 40 60 23 36(e) -- -- -- -- 173
Interest -- -- -- -- -- -- -- -- 132 132
------- ------- ------- --------- ----------- ---------- ---------- ----------- ---------- ------
Income (Loss) before Income
Taxes 593 294 123 30 (18) 23 89 39 (164) 1,009
Less: Provision for (Recovery
of) Income Taxes (f) 219 129 50 11 (5) 9 29 16 (51) 407
------- ------- ------- --------- ----------- ---------- ---------- ----------- ---------- ------
Net Income (Loss) 374 165 73 19 (13) 14 60 23 (113) 602
======= ======= ======= ========= =========== ========== ========== =========== ========== ======
Identifiable Assets(g) 427 1,956 699 91 179 1,015 327 506 351 5,551
======= ======= ======= ========= =========== ========== ========== =========== ========== ======
Capital Expenditures
Development and Other 98 297 81 -- 9 2 37 31 25 580
Exploration 15 65 143 19 58 -- -- -- -- 300
Proved Property Acquisitions -- 28 4 3 -- -- -- -- -- 35
------- ------- ------- --------- ----------- ---------- ---------- ----------- ---------- ------
113 390 228 22 67 2 37 31 25 915
======= ======= ======= ========= =========== ========== ========== =========== ========== ======
Property, Plant and Equipment
Cost 1,555 2,497 1,242 151 245 88 429 667 89 6,963
Less: Accumulated DD&A 1,314 729 723 90 126 25 118 261 37 3,423
------- ------- ------- --------- ----------- ---------- ---------- ----------- ---------- ------
Net Book Value (h) 241 1,768 519 61 119 63 311 406 52 3,540
======= ======= ======= ========= =========== ========== ========== =========== ========== ======
Goodwill
Cost -- -- -- -- -- 60 -- -- -- 60
Less: Accumulated DD&A -- -- -- -- -- 18 -- -- -- 18
------- ------- ------- --------- ----------- ---------- ---------- ----------- ---------- ------
Net Book Value -- -- -- -- -- 42 -- -- -- 42
======= ======= ======= ========= =========== ========== ========== =========== ========== ======

Notes:
(a) Includes results of our Moose Jaw Asphalt operation which was disposed of
on January 2, 2002.

(b) Includes results of operations from producing activities in Nigeria and
Ecuador.

(c) Net sales from our chemicals operations include:

Canada $ 237
United States 76
Brazil 23
----------
$ 336
==========

(d) On April 18, 2000, Nexen exchanged its oil and gas operations in Ecuador
for Occidental's 15% interest in our chemicals operations. The exchange was
valued at $55 million. Results of operations from producing activities in
Ecuador have been included to April 18, 2000, and operations from the 15%
interest in our chemicals operations has been included since April 18,
2000.

(e) Includes exploration activities primarily in Nigeria and Indonesia.

(f) The provision for (recovery of) income taxes for foreign locations is based
on in-country taxes on foreign income. For oil and gas locations with no
operating activities, the provision is based on the tax jurisdiction of the
entity performing the activity.

(g) Approximately 70% of Marketing's identifiable assets are accounts
receivable.

(h) Net sales made from all segments originating in Canada. $ 1,227

Property, plant and equipment located in Canada. $ 2,472

75

16. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES

The Consolidated Financial Statements have been prepared in accordance with
Canadian GAAP. Canadian principles differ from US GAAP as follows:

(A) CONSOLIDATED STATEMENT OF INCOME

2002 2001 2000
- ---------------------------------------------------------------------------------------------------------

Net Income - Canadian GAAP 452 450 602
Impact of US Principles:
Dividends on Preferred Securities (i) (72) (70) (68)
Less: Associated Future Income Taxes 29 31 31
Depreciation (ii) (53) (46) (43)
Fair Value of Currency Swap, Net of Income Tax (v) (4) -- --
----------------------------------
Net Income - US GAAP (viii) 352 365 522
==================================
Earnings per Common Share - US GAAP ($/share)
Basic 2.88 3.03 4.17
----------------------------------
Diluted 2.84 2.99 4.12
----------------------------------
Pro forma Earnings - Fair-value Based Method of Accounting for
Stock Options
Net Income
As Reported 352 365 522
Less: Fair Value of Stock Options 22 25 14
----------------------------------
Pro Forma 330 340 508
======== =========================
Earnings Per Common Share ($/share)
Basic as Reported 2.88 3.03 4.17
Pro Forma 2.70 2.81 4.07
----------------------------------
Diluted as Reported 2.84 2.99 4.12
Pro Forma 2.67 2.79 4.01
----------------------------------

(B) CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
2002 2001 2000
- ---------------------------------------------------------------------------------------------------------
Net Income - US GAAP 352 365 522
Translation Adjustment, Net of Income Tax (i); (iv) 34 (3) --
Minimum Unfunded Pension Liability, Net of Income Tax (vii) (2) -- --
----------------------------------
Comprehensive Income 384 362 522
==================================

(C) CONSOLIDATED BALANCE SHEET
2002 2001
- ------------------------------------------------------------ ----------------------------------------------------------
Canadian US Canadian US
GAAP GAAP GAAP GAAP
-------------------------- --------------------------

Assets
Accounts Receivable (iii) 988 990 609 616
Property, Plant and Equipment, Net (ii) 4,863 5,064 4,170 4,424
Deferred Charges and Other Assets (i); (vi) 69 70 28 51

Liabilities and Shareholders' Equity
Accounts Payable and Accrued Liabilities (iii); (v) 1,194 1,200 773 780
Long-Term Debt (i); (vi) 1,844 2,575 1,484 2,242
Future Income Tax Liabilities (i); (ii) 873 876 869 878
Preferred Securities (i) 724 -- 724 --
Retained Earnings (i); (ii); (v) 1,069 1,280 697 965
Cumulative Foreign Currency Translation

Adjustment (iv) 115 -- 94 --
Accumulated Other Comprehensive Income (i);(iv) -- 92 -- 60
----------------------------------------------------------

76

(D) CONSOLIDATED STATEMENT OF CASH FLOWS

Under US principles, dividends on preferred securities of $72 million (2001 -
$70 million; 2000 - $68 million) that are included in financing activities would
be reported in operating activities.

Under US principles, geological and geophysical costs of $80 million (2001 - $79
million; 2000 - $74 million) that are included in investing activities would be
reported in operating activities.

(E) CHANGES IN ACCOUNTING PRINCIPLES

MARK-TO-MARKET

On October 25, 2002, we adopted EITF 02-03, which eliminated mark-to-market
accounting as previously defined by EITF 98-10. Mark-to-market accounting was
eliminated for our marketing inventories and transportation contracts. We have
adopted this change as described in note 1(r). Under EITF 98-10 our results
would have been:

2002
- ---------------------------------------------------------
Net Income
As Reported 352
Mark-to-Market on inventory and
transportation, net of income taxes 4
-------
Adjusted 356
=======
Earnings per Common Share ($/share)
Basic as Reported 2.88
-------
Adjusted 2.91
-------
Diluted as Reported 2.84
-------
Adjusted 2.88
-------

GOODWILL

On January 1, 2002, we adopted Financial Accounting Standards Board (FASB)
Statement No.142, which eliminates goodwill amortization but instead requires
annual impairment testing. No goodwill impairment writedowns were required
during the year. Our unamortized goodwill at January 1, 2002 was $36 million.
The following shows the adjusted net income and earnings per common share had
the new standard been applied in 2001 and 2000:

2002 2001 2000
- ---------------------------------------------------------------------------
Net Income
As Reported 352 365 522
Add: Goodwill Amortization - 6 5
-------------------------
Adjusted 352 371 527
=========================

Earnings Per Common Share ($/share)
Basic as Reported 2.88 3.03 4.17
Adjusted 2.88 3.07 4.22
-------------------------

Diluted as Reported 2.84 2.99 4.12
Adjusted 2.84 3.04 4.16
-------------------------

77

(F) RECENT DEVELOPMENTS IN US ACCOUNTING STANDARDS

In June 2001, FASB issued Statement No. 143, "Accounting for Asset Retirement
Obligations" (FAS 143). FAS 143 requires recognition of a liability for the
future retirement obligations associated with our property, plant and equipment.
These obligations are initially measured at fair value, which is the discounted
future value of the liability. This fair value is capitalized as part of the
cost of the related asset and amortized to expense over its useful life. The
liability accretes until we expect to settle the retirement obligation. FAS 143
is effective for all fiscal years beginning after June 15, 2002. The impact on
our financial statements at January 1, 2003, is as follows:

(Cdn$ millions) Increase /(Decrease)
- -----------------------------------------------------------------------------------------------------

Consolidated Balance Sheet
Property, Plant and Equipment 123
Asset Retirement Obligation 185
Future Income Tax Liability (25)

Consolidated Statement of Income
Cumulative Effect of Change in Accounting Principle, Net of Income Taxes 37
Depreciation, Depletion and Amortization, Net of Income Taxes 2
---------------------

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45). FIN 45 elaborates on the disclosures we must
make about our obligations under certain guarantees that we have issued. It also
requires us to recognize, at the inception of a guarantee, a liability for the
fair value of the obligations we have undertaken in issuing the guarantee. The
initial recognition and initial measurement provisions are to be applied only to
guarantees issued or modified after December 31, 2002. Adoption of these
provisions will not have a material impact on our financial position or results
of operations. The disclosure requirements are effective for annual or interim
periods ending after December 15, 2002.

In January 2003, the FASB issued Statement No. 148 "Accounting for Stock-Based
Compensation - Transition and Disclosure, an Amendment of FASB Statement No.
123" (FAS 148). FAS 148 amends FAS 123 "Accounting for Stock-Based
Compensation", to provide alternative methods of transition for a voluntary
change to the fair value based method of accounting for stock-based employee
compensation. In addition, FAS 148 amends the disclosure requirements of FAS 123
to require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. FAS 148 has no material impact on
us, as we do not plan to adopt the fair value method of accounting for stock
options at the current time. We have included the required disclosures in Note 8
to these financial statements.

The following standards issued by the FASB do not impact us:

o Statement No. 145 - "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections", effective
for financial statements issued on or after May 15, 2002;

o Statement No. 146 - "Accounting for Costs Associated with Exit or Disposal
Activities", effective for exit or disposal activities initiated after
December 31, 2002; and

o Statement No. 147 - "Acquisitions of Certain Financial Institutions - an
Amendment of FASB Statements No. 72 and 144 and FASB Interpretation No. 9",
effective for acquisitions on or after October 1, 2002.

o Interpretation No. 46 - "Consolidation of Variable Interest Entities",
effective for financial statements issued after January 31, 2003.

NOTES:

i. Under US principles, the preferred securities are classified as long-term
debt rather than shareholders' equity. The pre-tax dividends are included
in interest expense, and the related income tax is included in the
provision for income taxes in the Consolidated Statement of Income. The
related pre-tax issue costs are included in deferred charges and other
assets rather than as an after-tax charge to retained earnings. The
foreign-currency translation gains or losses are included in other
comprehensive income in the Consolidated Balance Sheet. The pre-tax
dividends are included in operating activities in the Consolidated
Statement of Cash Flows.

ii. Under US principles, the liability method of accounting for income taxes
was adopted in 1993 rather than January 1, 2000, as described in Note 13.
Under US principles, the adjustment on initial adoption was included in
property, plant and equipment rather than retained earnings. This increases
depreciation expense under US principles.

78

iii. On January 1, 2001, Nexen adopted FASB Statement No. 133 "Accounting for
Derivative Instruments and Hedging Activities", as modified by Statement
No. 138 "Accounting for Certain Derivative Instruments and Certain Hedging
Activities" (FAS 133). FAS 133 requires us to recognize all derivative
instruments 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. For cash
flow hedges, changes in the fair value of derivatives that are designated
as 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 and in other comprehensive income. For
fair value hedges, both the derivative instrument and the underlying
commitment are recognized on the balance sheet at their fair value. Any
changes in the fair value are reflected net in earnings. Included in both
accounts receivable and accounts payable at December 31, 2002 is $2
million (2001 - $7 million) related to fair value hedges. The hedges
convert fixed prices for physical delivery of natural gas into a floating
price through a fixed to floating swap. The impact on earnings is
immaterial.

iv. 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 from translation of our US-dollar long-term debt, net of income
taxes, is included in comprehensive income as it has been designated as a
hedge of the our foreign net investment. Cumulative amounts are included
in accumulated other comprehensive income in the Consolidated Balance
Sheet.

v. Under US principles, a derivative and a cash instrument cannot be
designated in combination as a net investment hedge. Changes in fair value
and foreign exchange gains and losses on our US $37 million currency swap
(see note 6) are included in earnings.

vi. 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.

vii. Under US principles, the amount by which our accrued pension cost is less
than the unfunded accumulated benefit obligation is included in
comprehensive income and accrued pension liabilities.

viii. Under US principles, gains and losses on the disposition of assets are
shown as operating expenses rather than revenues.

79

SUPPLEMENTARY FINANCIAL INFORMATION (UNAUDITED)

QUARTERLY FINANCIAL DATA IN ACCORDANCE WITH CANADIAN AND US GAAP

(Cdn$ millions) QUARTER ENDED
- ----------------------------------------------------------------------------------------------------------
March 31 June 30 September 30 December 31
2002 2001 2002 2001 2002 2001 2002 2001
-------------------------------------------------------------------

Net Sales 541 729 644 692 716 666 705 506
===================================================================
Operating Profit
Oil and Gas(1) 97 304 184 278 223 152 185 28
Syncrude(2) 20 26 9 23 47 23 40 26
Chemicals 3 6 4 13 11 17 9 11
-------------------------------------------------------------------
120 336 197 314 281 192 234 65
Interest and Other Corporate(3) 24 45 43 40 36 33 48 35
Income Tax Expense(4) 31 116 53 114 88 74 57 --
-------------------------------------------------------------------
Net Income in Accordance
with Canadian GAAP 65 175 101 160 157 85 129 30
US GAAP Adjustment (23) (22) (22) (21) (23) (21) (32) (21)
-------------------------------------------------------------------
Net Income in Accordance
with US GAAP 42 153 79 139 134 64 97 9
===================================================================
Per Common Share ($/share)
Net Income
(Canadian GAAP) 0.44 1.38 0.74 1.25 1.20 0.62 0.96 0.16
Net Income
(US GAAP) 0.35 1.27 0.65 1.15 1.09 0.53 0.79 0.08
Dividends Declared(5) 0.075 0.075 0.075 0.075 0.075 0.075 0.075 0.075
-------------------------------------------------------------------
Common Share Prices ($/share)
Toronto Stock Exchange
High 39.75 39.90 42.50 40.65 42.18 41.50 37.78 35.21
Low 29.70 31.00 37.20 32.40 34.34 28.10 31.00 29.51
New York Stock Exchange
High (US$) 25.11 25.77 28.04 26.61 27.71 26.12 23.85 22.39
Low (US$) 18.57 20.69 23.30 20.60 21.70 17.95 19.79 18.73
-------------------------------------------------------------------

Notes:
(1) A loss of $21 million was recorded on the disposition of non-operated oil
and gas properties during the fourth quarter of 2002.

(2) Plant turnarounds and unplanned coker maintenance in the second quarter of
2002 increased operating costs.

(3) A gain of $13 million was recorded on the disposition of our Moose Jaw
Asphalt operation during the first quarter of 2002.

(4) The fourth quarter of 2001 includes a statutory tax rate adjustment for
provincial rate reductions in Canada.

(5) In February 2003, the Board of Directors declared a regular quarterly
dividend of $0.075 per common share, payable April 1, 2003, to
shareholders of record on March 10, 2003.

(6) At December 31, 2002, there were 1,372 registered holders of common shares
and 122,965,830 common shares outstanding.

80

OIL AND GAS NETBACKS

(Sales prices, per unit costs and netbacks are calculated using our working
interest production before royalties.)

($/boe) 2002
- -------------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia Other Syncrude Total
-------------------------------------------------------------------------- -------------

Sales 38.80 27.90 34.21 40.30 38.96 40.89 35.14
Royalties and other (20.45) (6.53) (5.82) (7.88) (16.48) (0.36) (12.56)
Operating expense (1.95) (5.70) (9.09) (9.76) (6.21) (19.09) (5.48)
In-country taxes (4.81) -- -- -- -- -- (2.10)
-------------------------------------------------------------------------- -------------
Cash netback 11.59 15.67 19.30 22.66 16.27 21.44 15.00
========================================================================== =============

($/boe) 2001
- -------------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia Other Syncrude Total
-------------------------------------------------------------------------- -------------

Sales 35.05 26.60 39.42 38.71 37.37 39.90 33.28
Royalties and other (18.66) (6.26) (6.85) (2.36) (7.07) (1.72) (11.40)
Operating expense (1.62) (4.87) (6.01) (13.50) (8.07) (19.43) (4.88)
In-country taxes (4.40) -- -- -- -- -- (1.95)
-------------------------------------------------------------------------- -------------
Cash netback 10.37 15.47 26.56 22.85 22.23 18.75 15.05
========================================================================== =============

($/boe) 2000
- -------------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia Other Syncrude Total
-------------------------------------------------------------------------- -------------

Sales 40.53 31.10 42.43 41.05 40.12 44.84 38.05
Royalties and other (22.14) (7.48) (7.70) -- (8.62) (7.75) (13.67)
Operating expense (1.42) (4.57) (5.00) (6.92) (7.58) (18.36) (4.22)
In-country taxes (5.30) -- -- -- -- -- (2.34)
-------------------------------------------------------------------------- -------------
Cash netback 11.67 19.05 29.73 34.13 23.92 18.73 17.82
========================================================================== =============

81

OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following oil and gas information is provided in accordance with the US
Financial Accounting Standards Board Statement No. 69 "Disclosures about Oil and
Gas Producing Activities".

A. RESERVE QUANTITY INFORMATION

Our net proved reserves and changes in those reserves are disclosed below. The
net proved reserves represent management's best estimate of proved oil and
natural gas reserves after royalties. We assess 100% of our reserves estimates
internally each year and at least 80% of the reserves have been assessed by
independent consultants.

Estimates of conventional crude oil and natural gas proved reserves are
determined through analysis of geological and engineering data, demonstrating
with reasonable certainty that they are recoverable from known oil and gas
fields under economic and operating conditions that exist at year-end. See
Critical Accounting Policies and Business Risk Management sections in Item 7 for
a discussion of reserves estimation and the related risks.

United Other
Total Yemen(1) Canada States Australia Countries(2)
------------------------------------------------------------------------------------------
Oil reserves are in mmbbls and Conventional
natural gas reserves in bcf Oil Gas Syncrude(3) Oil Oil Gas Oil Gas Oil Oil
- -----------------------------------------------------------------------------------------------------------------------------------

Proved Developed and Undeveloped
Reserves(4)
------------------------------------------------------------------------------------------
December 31, 1999 291 614 188 104 150 455 19 159 8 10
------------------------------------------------------------------------------------------
Revisions of Previous Estimates 26 39 -- 20 6 18 1 21 (1) --
Purchases of Reserves in Place 7 3 -- -- 5 -- -- 3 2 --
Sales of Reserves In Place (5) (1) -- -- (1) (1) -- -- -- (4)
Extensions and Discoveries 26 101 19 2 22 86 2 15 -- --
Production (45) (83) (4) (19) (16) (49) (4) (34) (4) (2)
------------------------------------------------------------------------------------------
December 31, 2000 300 673 203 107 166 509 18 164 5 4
------------------------------------------------------------------------------------------
Revisions of Previous Estimates 1 -- -- 7 (14) (1) 2 1 1 5
Purchases of Reserves in Place 2 64 -- -- 2 3 -- 61 -- --
Sales of Reserves in Place -- (2) -- -- -- (2) -- -- -- --
Extensions and Discoveries 53 146 34 17 21 91 11 55 -- 4
Production (47) (90) (6) (20) (18) (54) (3) (36) (4) (2)
------------------------------------------------------------------------------------------
December 31, 2001 309 791 231 111 157 546 28 245 2 11
------------------------------------------------------------------------------------------
Revisions of Previous Estimates (6) (10) (12) (14) 7 (6) 1 (4) -- --
Purchases of Reserves in Place -- 1 -- -- -- 1 -- -- -- --
Sales of Reserves in Place (6) (1) -- -- (2) (1) -- -- -- (4)
Extensions and Discoveries 72 103 13 23 10 31 32 72 5 2
Production (45) (81) (6) (20) (16) (47) (3) (34) (4) (2)
------------------------------------------------------------------------------------------
December 31, 2002 324 803 226 100 156 524 58 279 3 7
==========================================================================================
Proved Developed Reserves(5)
December 31, 2000 223 613 183 77 120 463 17 150 5 4
==========================================================================================
December 31, 2001 223 676 212 70 126 505 18 171 2 7
==========================================================================================
December 31, 2002 246 702 196 61 131 487 46 215 3 5
==========================================================================================

Notes:
(1) Under the terms of the Masila production sharing contract, production is
divided into cost recovery oil and profit oil. Cost recovery oil provides
for the recovery of all our costs and those of our partners. Remaining
production is profit oil, which is shared between the partners and the
Government of Yemen based on production rates, with the partners' share
ranging from 20% to 33%. The Government's share of profit oil represents
their royalty interest and an amount for income taxes payable in Yemen.
Yemen's net proved reserves include our share of future cost recovery and
profit oil after the Government's royalty interest but before reserves
relating to income taxes payable. Under this method, reported reserves will
increase as oil prices decrease (and vice versa) since the barrels
necessary to achieve cost recovery change with prevailing oil prices.

(2) Represents reserves in Nigeria and Colombia. (2001 - Nigeria and Colombia;
2000 - Nigeria; 1999 - Nigeria and Ecuador.)

(3) US Securities and Exchange Commission regulations define these reserves as
mining-related and not part of conventional oil and gas reserves. For
management purposes, we view these reserves and their development as
integral to our oil and gas operations. These reserves are not considered
in the standardized measure of discounted future net cash flows, which
follows. In 2002, Syncrude moved to generic royalty terms that provide for
a royalty of 25% on net revenues after all costs have been recovered,
subject to a minimum 1% gross royalty. Under this royalty regime, reported
reserves will increase as oil prices decrease (and vice versa) since the
barrels necessary to recover costs change with prevailing oil prices.

(4) "Proved" oil and gas reserves are the estimated quantities of natural gas,
crude oil, condensate and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty can be recovered in
future years from known reservoirs under existing economic and operating
conditions. Reserves are considered "proved" if they can be produced
economically, as demonstrated by either actual production or conclusive
formation tests.

(5) "Proved developed" oil and gas reserves are expected to be recovered
through existing wells with existing equipment and operating methods.

82

B. CAPITALIZED COSTS

Accumulated
Depreciation,
Proved Unproved Depletion and Capitalized
(Cdn$ millions) Properties Properties Amortization Costs
- ------------------------------------------------------------ ---------------- ---------------- ----------------

December 31, 2002
Yemen 2,024 30 1,646 408
Canada 2,882 216 1,137 1,961
United States 2,061 125 959 1,227
Australia 209 - 184 25
Other Countries 251 54 198 107
Syncrude 628 - 139 489
----------- ---------------- ---------------- ----------------
Total 8,055 425 4,263 4,217
=========== ================ ================ ================

December 31, 2001
Yemen 1,808 31 1,491 348
Canada 2,750 117 913 1,954
United States 1,522 114 848 788
Australia 167 - 144 23
Other Countries 267 4 166 105
Syncrude 487 - 127 360
----------- ---------------- ---------------- ----------------
Total 7,001 266 3,689 3,578
=========== ================ ================ ================

December 31, 2000
Yemen 1,544 11 1,314 241
Canada 2,344 153 729 1,768
United States 1,154 88 723 519
Australia 151 - 90 61
Other Countries 184 61 126 119
Syncrude 429 - 118 311
----------- ---------------- ---------------- ----------------
Total 5,806 313 3,100 3,019
=========== ================ ================ ================

C. COSTS INCURRED

(Cdn$ millions) Total Conventional Oil and Gas
- ------------------------------------------------------------------------------------------------------------------------------
Conventional United Other
Oil and Gas Syncrude Yemen Canada States Australia Countries
--------------------------- ------------------------------------------------------

Year Ended December 31, 2002
Property Acquisition Costs
Proved 4 -- -- 4 -- -- --
Unproved 31 -- -- -- 31 -- --
Exploration Costs 228 -- 22 60 85 3 58
Development Costs 1,077 141 209 258 541 46 23
--------------------------- ------------------------------------------------------
1,340 141 231 322 657 49 81
=========================== ======================================================
Year Ended December 31, 2001
Property Acquisition Costs
Proved 122 -- -- 7 115 -- --
Unproved 37 -- 19 -- 18 -- --
Exploration Costs 374 -- 25 84 179 12 74
Development Costs 691 60 185 367 120 (4) 23
--------------------------- ------------------------------------------------------
1,224 60 229 458 432 8 97
=========================== ======================================================
Year Ended December 31, 2000
Property Acquisition Costs
Proved 35 -- -- 28 4 3 --
Unproved 39 -- -- -- 31 -- 8
Exploration Costs 261 -- 15 65 112 19 50
Development Costs 485 37 98 297 81 -- 9
--------------------------- ------------------------------------------------------
820 37 113 390 228 22 67
=========================== ======================================================

83

D. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES

(Cdn$ millions) Total Conventional Oil and Gas
- ------------------------------------------------------------------------------------------------------------------------------
Conventional United Other
Oil and Gas Syncrude Yemen Canada States Australia Countries
-------------------------- -------------------------------------------------------

Year Ended December 31, 2002
Net Sales 1,984 245 789 656 296 165 78
Production Costs 428 115 86 176 94 50 22
Exploration Expense 189 -- 21 38 82 3 45
Depreciation, Depletion
and Amortization 634 13 149 253 133 53 46
Other Expenses (Income) 79 1 4 41 14 1 19
-------------------------- -------------------------------------------------------
654 116 529 148 (27) 58 (54)
Income Tax Provision (Recovery) 238 37 188 59 (10) 19 (18)
-------------------------- -------------------------------------------------------
Results of Operations 416 79 341 89 (17) 39 (36)
========================== =======================================================

Year Ended December 31, 2001
Net Sales 1,918 225 711 647 358 141 61
Production Costs 363 114 71 155 66 52 19
Exploration Expense 265 -- 25 44 101 13 82
Depreciation, Depletion
and Amortization 550 12 111 227 116 65 31
Other Expenses (Income) 37 1 3 15 6 (2) 15
-------------------------- -------------------------------------------------------
703 98 501 206 69 13 (86)
Income Tax Provision (Recovery) 283 32 185 90 27 5 (24)
-------------------------- -------------------------------------------------------
Results of Operations 420 66 316 116 42 8 (62)
========================== =======================================================

Year Ended December 31, 2000
Net Sales 2,077 199 752 698 382 167 78
Production Costs 297 98 58 135 55 27 22
Exploration Expense 173 -- 14 40 60 23 36
Depreciation, Depletion
and Amortization 588 12 90 233 139 86 40
Other Expenses (Income) (3) -- (3) (4) 5 1 (2)
-------------------------- -------------------------------------------------------
1,022 89 593 294 123 30 (18)
Income Tax Provision (Recovery) 404 29 219 129 50 11 (5)
-------------------------- -------------------------------------------------------
Results of Operations 618 60 374 165 73 19 (13)
========================== =======================================================

E. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN

The following disclosure includes estimates of net proved reserves and the
period during which they are expected to be produced. Future cash inflows are
computed by applying year-end prices to our after royalty share of estimated
annual future production from proved conventional oil and gas reserves
(excluding Syncrude). Future development and production costs to be incurred in
producing and further developing the proved reserves are based on year-end cost
indicators. Future income taxes are computed by applying year-end statutory-tax
rates. These rates reflect allowable deductions and tax credits and are applied
to the estimated pre-tax future net cash flows.

Discounted future net cash flows are calculated using 10% mid-period discount
factors. The calculations assume the continuation of existing economic,
operating and contractual conditions. However, such arbitrary assumptions have
not proven to be the case in the past. Other assumptions could give rise to
substantially different results.

We believe that this information does not in any way reflect the current
economic value of our oil and gas producing properties or the present value of
their estimated future cash flows as:

o no economic value is attributed to probable and possible reserves;

o use of a 10% discount rate is arbitrary; and

o prices change constantly from year-end levels.

84

United Other
(Cdn$ millions) Total Yemen Canada States Australia Countries
- ------------------------------------------------------------------------------------------------------------------------------

December 31, 2002
Future Cash Inflows 18,687 4,662 9,067 4,516 144 298
Future Production and Development Costs 4,892 1,177 2,568 913 108 126
Future Income Tax 3,650 790 1,976 863 - 21
------------ --------------------------------------------------------------
Future Net Cash Flows 10,145 2,695 4,523 2,740 36 151
10% Discount Factor 3,776 819 2,081 818 1 57
------------ --------------------------------------------------------------
Standardized Measure 6,369 1,876 2,442 1,922 35 94
============ ==============================================================
December 31, 2001
Future Cash Inflows 10,337 3,068 5,034 1,880 64 291
Future Production and Development Costs 4,123 880 1,943 1,000 64 236
Future Income Tax 1,520 661 751 96 - 12
------------ --------------------------------------------------------------
Future Net Cash Flows 4,694 1,527 2,340 784 - 43
10% Discount Factor 1,607 385 1,004 202 - 16
------------ --------------------------------------------------------------
Standardized Measure 3,087 1,142 1,336 582 - 27
============ ==============================================================
December 31, 2000
Future Cash Inflows 15,173 3,552 8,113 3,166 220 122
Future Production and Development Costs 3,574 741 2,103 550 112 68
Future Income Tax 3,783 897 2,093 760 18 15
------------ --------------------------------------------------------------
Future Net Cash Flows 7,816 1,914 3,917 1,856 90 39
10% Discount Factor 2,825 507 1,835 474 4 5
------------ --------------------------------------------------------------
Standardized Measure 4,991 1,407 2,082 1,382 86 34
============ ==============================================================

CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The following are the principal sources of change in the standardized measure of
discounted future net cash flows:

(Cdn$ millions) 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------

Beginning of Year 3,087 4,991 3,801
Sales and Transfers of Oil and Gas Produced, Net of Production Costs (1,158) (2,012) (1,425)
Net Changes in Prices and Production Costs Related to Future Production 3,083 (2,871) 1,255
Extensions, Discoveries and Improved Recovery, Less Related Costs 1,929 691 536
Development Costs Incurred during the Period 322 61 341
Revisions of Previous Quantity Estimates 267 (33) 670
Accretion of Discount 409 736 534
Purchases of Reserves in Place 2 161 119
Sales of Reserves in Place (109) (1) (47)
Net Change in Income Taxes (1,463) 1,364 (793)
---------------------------------
End of Year 6,369 3,087 4,991
=================================

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

On June 3, 2002, the Canadian firm of Deloitte & Touche LLP (Deloitte Canada)
completed a transaction with the Canadian firm of Arthur Andersen LLP (Andersen
Canada) to integrate partners and staff of Andersen Canada into Deloitte Canada.
On July 11, 2002, our Board accepted the resignation of Andersen Canada and
appointed Deloitte Canada as our auditors until the next Annual General Meeting.

There were no disagreements with accountants on accounting and financial
disclosure.

85

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

DIRECTORS OF THE REGISTRANT

According to our Articles, Nexen must have between three and 15 directors. On
February 13, 2003, the directors determined that from May 6, 2003, until
changed, there will be ten directors.

Our By-Laws provide that directors will be elected at the annual general meeting
of shareholders each year and will hold office until their successors have been
duly elected. All of our current directors were elected at the last annual
general meeting except for Mr. O'Neill, who was appointed by the Board on
December 10, 2002. The following directors are management nominees for election
to the Board.

This table shows each director's principal occupation or employment during the
past five years and any other directorships they held in public companies as at
February 13, 2003.

PRINCIPAL OCCUPATION AND DIRECTOR
NAME (AGE) OTHER DIRECTORSHIPS SINCE
- -----------------------------------------------------------------------------------------------------------------------------

Charles W. Fischer (52) President and Chief Executive Officer of Nexen. 2000
Formerly, Executive Vice President and Chief Operating Officer.
- -----------------------------------------------------------------------------------------------------------------------------
Dennis G. Flanagan (63) Retired oil executive. Director of NAL Royalty Trust. 2000
- -----------------------------------------------------------------------------------------------------------------------------
David A. Hentschel (69) Retired Chairman and Chief Executive Officer of Occidental Oil and Gas
Corporation. Consultant to Occidental Petroleum Corporation and a director of 1985
Cimarex Energy Co.
- -----------------------------------------------------------------------------------------------------------------------------
S. Barry Jackson (50) Retired oil executive. Formerly, President and Chief Executive Officer and a 2001
director of Crestar Energy Inc. Director and Executive Chairman of Resolute
Energy Inc. and a director of TransCanada Pipelines Limited.
- -----------------------------------------------------------------------------------------------------------------------------
Kevin J. Jenkins (46) Formerly, President and Chief Executive Officer and a director of The Westaim 1996
Corporation.
- -----------------------------------------------------------------------------------------------------------------------------
Thomas C. O'Neill (57) Retired Chairman of PwC Consulting. Formerly, Chief Executive Officer of PwC 2002
Consulting. Prior to that, Chief Operating Officer of PricewaterhouseCoopers LLP,
Global. Prior to that, Chief Executive Officer of PricewaterhouseCoopers LLP,
Canada and, prior to that, Chairman and Chief Executive Officer of Price
Waterhouse Canada. Director of BCE Inc. and Ontario Teachers' Pension Plan
Board.
- -----------------------------------------------------------------------------------------------------------------------------
Francis M. Saville, Q.C. (64) Vice Chairman and Senior Partner of Fraser Milner Casgrain LLP, Barristers and 1994
Solicitors. Director of Mullen Transportation Inc.
- -----------------------------------------------------------------------------------------------------------------------------
Richard M. Thomson (69) Retired banking executive. Director of the Toronto-Dominion Bank, Prudential 1997
Financial Inc., INCO Limited, The Thomson Corporation, Trizec Properties Inc.
and Stuart Energy Systems Inc.
- -----------------------------------------------------------------------------------------------------------------------------
John M. Willson (63) Retired President and Chief Executive Officer of Placer Dome Inc. Formerly, 1996
President and Chief Executive Officer of Pegasus Gold Inc. Director of Finning
International Inc. and PanAmerican Silver Corp.
- -----------------------------------------------------------------------------------------------------------------------------
Victor J. Zaleschuk (59) Retired President and Chief Executive Officer of Nexen. Director of Cameco 1997
Corporation and Agrium Inc.
- -----------------------------------------------------------------------------------------------------------------------------

Mr. Gordon R. Wittman, age 72, retired President, Chief Operating Officer and a
director of Dupont Canada Inc., will not be standing for re-election to the
Board, as he has reached Nexen's mandatory retirement age. Mr. Wittman has been
a valued member of the Board since 1994. The Board and Management wish to thank
Mr. Wittman for his dedicated service to Nexen and its shareholders.

86

INDEPENDENCE AND BOARD COMMITTEES

The following table summarizes the independence of Board members and sets out
their Committee memberships as of February 13, 2003. Independence was
affirmatively determined by the Board in reference to the categorical standards
of independence adopted on February 13, 2003 (Categorical Standards). The
Categorical Standards are attached as Schedule B to Nexen's Proxy Statement and
Information Circular. The Categorical Standards are consistent with the Toronto
Stock Exchange guidelines for "outside" and "unrelated" directors, provisions of
the Sarbanes-Oxley Act of 2002 and proposed New York Stock Exchange rules.

CORPORATE SAFETY,
AUDIT AND GOVERNANCE COMPENSATION ENVIRONMENT
CONDUCT AND AND HUMAN RESERVES AND SOCIAL
REVIEW(1) NOMINATING FINANCE RESOURCES REVIEW RESPONSIBILITY
- ------------------------------------------------------------------------------------------------------------ -----------------

OUTSIDE DIRECTORS
- ------------------------------------------------------------------------------------------------------------ -----------------
INDEPENDENT
- ------------------------------------------------------------------------------------------------------------ -----------------
Dennis G. Flanagan (2)(3) 3 3 3 Chair
- ------------------------------------------------------------------------------------------------------------ -----------------
David A. Hentschel Chair 3 3 3
- ------------------------------------------------------------------------------------------------------------ -----------------
S. Barry Jackson(4) 3 3 3 3
- ------------------------------------------------------------------------------------------------------------ -----------------
Kevin J. Jenkins(2) 3 Chair 3 3
- ------------------------------------------------------------------------------------------------------------ -----------------
Thomas C. O'Neill(2) 3 3 3 3
- ------------------------------------------------------------------------------------------------------------ -----------------
Francis M. Saville, Q.C. Chair 3 3 3
- ------------------------------------------------------------------------------------------------------------ -----------------
Richard M. Thomson(2)(5) 3 3 3 3
- ------------------------------------------------------------------------------------------------------------ -----------------
John M. Willson 3 Chair 3 3
- ------------------------------------------------------------------------------------------------------------ -----------------
Gordon R. Wittman 3 3 3 Chair
- ------------------------------------------------------------------------------------------------------------ -----------------

NOT INDEPENDENT
- ------------------------------------------------------------------------------------------------------------ -----------------
Victor J. Zaleschuk(6) 3 3 3 3
- ------------------------------------------------------------------------------------------------------------ -----------------

INSIDE DIRECTORS
- ------------------------------------------------------------------------------------------------------------ -----------------
NOT INDEPENDENT
- ------------------------------------------------------------------------------------------------------------ -----------------
Charles W. Fischer(7)
- ------------------------------------------------------------------------------------------------------------ -----------------
MEETINGS IN 2002 6 5 5 4 3 4
- ------------------------------------------------------------------------------------------------------------ -----------------

Notes:

(1) All members of the Audit and Conduct Review Committee are also independent
under additional requirements for audit committee members.

(2) Qualifies as a "financial expert" under US regulatory requirements.

(3) Mr. Flanagan is a member of the Audit Committee of NAL Royalty Trust.

(4) Mr. Jackson is Executive Chairman of Resolute Energy Inc. (Resolute).
Annual sales from Resolute to Nexen are minimal in respect to Nexen, but
represent more than 1% and less than 5% of the annual revenues of Resolute.
As this exceeds the limit of presumed independence set out in section 2 of
the Categorical Standards, the directors who are presumed independent
considered the circumstances of the relationship between Nexen and
Resolute, as allowed for under section 3 of the Categorical Standards. They
determined that the relationship was not material and Mr. Jackson was
deemed to be independent. Among the circumstances considered by the
directors were: the ongoing competitive market for the commodities
purchased and the services provided by Nexen; the commodity prices are
based on indices at various delivery points, the price for services is
competitive and both are negotiated at arms-length; and Mr. Jackson had no
involvement in the negotiation of the purchase and services agreements. The
directors also confirmed that Mr. Jackson met the additional independence
requirements applicable to members of the Audit and Conduct Review
Committee.

(5) Mr. Thomson is a member of the Audit Committee of one other public company,
Trizec Properties Inc.

(6) Mr. Zaleschuk is not independent as he was the President and Chief
Executive Officer of Nexen until May 31, 2001. He will be independent after
June 1, 2006.

(7) Mr. Fischer is not independent as he is the President and Chief Executive
Officer of Nexen.

During 2002, there were nine meetings and two resolutions in writing of the
Board. There was 100% attendance at all Board and Committee meetings.

87

COMMITTEE RESPONSIBILITIES

Each Committee makes regular reports to the Board and, if required, other
Committees, concerning its activities. Each Committee is authorized to engage
independent counsel or other advisors as needed. Below is a description of the
responsibilities of each of the Board Committees.

The AUDIT AND CONDUCT REVIEW COMMITTEE assists the Board in fulfilling its
oversight responsibilities with respect to (i) the integrity of the annual and
quarterly financial statements to be provided to shareholders and regulatory
bodies; (ii) Nexen's compliance with accounting and finance based legal and
regulatory requirements; (iii) the independent auditor's qualifications and
independence; (iv) the system of internal accounting and financial reporting
controls that management has established; and (v) the performance of the
internal and external audit process and the independent auditor. In addition,
the Committee provides an avenue for communication between each of internal
audit, the independent auditors, financial and senior management and the Board.

The CORPORATE GOVERNANCE AND NOMINATING COMMITTEE assists the Board in
fulfilling its oversight responsibilities with respect to (i) the development
and implementation of principles and systems for the management of corporate
governance; and (ii) identifying qualified candidates and recommending nominees
for director and board committee appointments.

The FINANCE COMMITTEE assists the Board in fulfilling its oversight
responsibilities with respect to (i) financial policies and strategies including
capital structure; (ii) financial risk management practices; and (iii)
transactions or circumstances which could materially affect Nexen's financial
profile.

The COMPENSATION AND HUMAN RESOURCES COMMITTEE assists the Board in fulfilling
its oversight responsibilities with respect to (i) human resources policies;
(ii) executive management compensation; and (iii) executive management
succession and development.

The RESERVES REVIEW COMMITTEE assists the Audit and Conduct Review Committee and
the Board in fulfilling their oversight responsibilities with respect to the
annual review of Nexen's petroleum and natural gas reserves.

The SAFETY, ENVIRONMENT AND SOCIAL RESPONSIBILITY COMMITTEE assists the Board in
fulfilling its oversight responsibilities with respect to due diligence in the
development and implementation of systems for the management of safety,
environment and social responsibility.

Mandates for each of the Committees are reviewed annually and updated, as
appropriate, to reflect current responsibilities and practices. The mandates for
all of the Committees of the Board, together with the Board Mandate and the
Chair Mandate/Position Description, are attached as Schedule C to Nexen's Proxy
Statement and Information Circular.

ETHICS POLICY

Pursuant to Nexen's Ethics Policy all directors, officers and employees must
demonstrate a commitment to ethical business practices and behaviour in all
business relationships, both within and outside of Nexen. No employee,
regardless of his or her position, is ever expected to commit an unethical,
dishonest or illegal act or to instruct other employees to do so. We confirm
that our Ethics Policy has been adopted as a code of ethics applicable to our
principal executive officer, principal financial officer and principal
accounting officer or controller. Any waivers of or changes to the Ethics Policy
must be approved by the Board and appropriately disclosed.

Our Ethics Policy is available on our internet website at www.nexeninc.com and
it is our intention to provide disclosure in this manner.

AUDIT AND CONDUCT REVIEW COMMITTEE REPORT

The Audit and Conduct Review Committee is directly responsible for the
appointment (subject to shareholder approval), compensation and oversight of the
independent auditors. The independent auditors report directly to the Committee.
The Committee has a clear understanding with the independent auditors that they
must maintain an open and transparent relationship with the Committee and that
the ultimate accountability of the independent auditors is to the Committee, as
representatives of the shareholders. A copy of the mandate of the Committee is
included in Schedule C to Nexen's Proxy Statement and Information Circular.

The Committee is composed of six directors, all of whom are independent pursuant
to Nexen's categorical standards which include the additional requirements for
independence of audit committee members set out in the Sarbanes-Oxley Act of
2002.

Management is responsible for Nexen's internal controls and financial reporting
process. The independent auditors are responsible for performing and reporting
on an independent audit of Nexen's Consolidated Financial Statements in
accordance with generally accepted auditing standards. The Committee's
responsibility is to monitor and oversee these processes.

88

In connection with their responsibilities, the Committee:

o met with management and the independent auditors to review and discuss the
December 31, 2002 Consolidated Financial Statements;

o discussed with the independent auditors the matters required by Canadian
regulators in accordance with Section 5751 of the General Assurance and
Auditing Standards of the Canadian Institute of Chartered Accountants
"Communications with Those Having Oversight Responsibility for the
Financial Reporting Process" and by US regulators in accordance with the
Statement on Auditing Standards No. 61 "Communication with Audit
Committees" issued by the American Institute of Certified Public
Accountants;

o received written disclosures from the independent auditors required by the
US Securities and Exchange Commission in accordance with the Independence
Standards Board Standard No. 1 "Independence Discussions with Audit
Committees"; and

o discussed with the independent auditors that firm's independence.

CHANGE IN AUDITOR

On June 3, 2002, the Canadian firm of Deloitte & Touche LLP completed a
transaction with the Canadian firm of Arthur Andersen LLP to integrate partners
and staff of Arthur Andersen LLP (Canada) into Deloitte & Touche LLP (Canada).
On July 11, 2002, our Board accepted the resignation of Arthur Andersen LLP
(Canada) and appointed Deloitte & Touche LLP (Canada) as Nexen's auditors until
the next Annual General Meeting.

AUDIT FEES

Total audit related fees billed by Nexen's independent auditors, Deloitte &
Touche LLP, during 2002 were:

o $550,000 for the annual audit of Nexen's Consolidated Financial Statements
included in our 2002 Annual Report on Form 10-K;

o $31,000 for the second and third quarter reviews of Nexen's consolidated
financial statements included in our Form 10-Qs for the periods ended June
30, 2002 and September 30, 2002, respectively;

o $231,500 for the annual audits of subsidiary financial statements and
employee benefit plans; and

o $4,000 for comfort letters to commissions.

Total audit related fees billed by Nexen's former independent auditors, Arthur
Andersen LLP, during 2002 were:

o $13,000 for the first quarter review of Nexen's consolidated financial
statements included in our Form 10-Q for the period ended March 31, 2002;
and

o $88,300 for comfort letters to commissions.

FINANCIAL INFORMATION SYSTEMS DESIGN AND IMPLEMENTATION FEES

Deloitte & Touche LLP did not provide any financial information systems design
and implementation services as described in Paragraph (c)(4)(ii) of Rule 2-01 of
Regulation S-X under US federal securities laws for the fiscal year ended
December 31, 2002.

ALL OTHER FEES

Total fees billed by Deloitte & Touche LLP for other services during 2002 were:

o $72,550 for tax return preparation assistance and tax-related consultation.

Total fees billed by Arthur Andersen LLP for other services during 2002 were:

o $106,601 for tax preparation assistance and tax-related consultation; and

o $62,900 for assisting the internal audit group with its evaluation of the
implementation of an enterprise-wide resource system.

89

GENERAL

The Committee considered and is of the view that the provision of services by
Deloitte & Touche LLP described in "All Other Fees" above is compatible with
maintaining that firm's independence.

Based on the Committee's discussions with management and the independent
auditors, and its review of the representations of management and the
independent auditors, the Committee recommended that the Board include the
audited Consolidated Financial Statements in Nexen's Annual Report on Form 10-K
for the year ended December 31, 2002.

Submitted on behalf of the Audit and Conduct Review Committee:

David A. Hentschel, Chair
Dennis G. Flanagan
S. Barry Jackson
Thomas C. O'Neill
Richard M. Thomson
Gordon R. Wittman

DIRECTOR COMPENSATION

Since January 1, 2000, all directors who are not employees are paid:

o an annual retainer of $28,100 for services on the Board and $1,800 for each
Board meeting attended; and

o an annual retainer of $9,100 for service on each Committee and $1,800 for
each Committee meeting attended.

The Chair of the Board is paid an annual retainer of $108,000 and the Chair of
each Committee is paid an additional annual retainer of $5,300. Director
compensation was last reviewed in December 2001. At that time, retainers and
fees were not increased.

In 2001, a Deferred Share Unit (DSU) plan was approved as an alternative form of
compensation for non-employee directors. Under the plan, eligible directors may
elect, on an annual basis, to receive all or part of their fees in the form of
DSUs, rather than cash. A DSU is a bookkeeping entry which tracks the value of
one Nexen common share. DSUs are not paid out until the director leaves the
Board, thereby providing an ongoing equity stake in Nexen during the director's
term of service. Payments of DSUs may be made in cash or in Nexen common shares
purchased on the open market at the time of payment.

In December 2002, all directors who were not employees of Nexen were granted
5,500 stock options, except for the Chair of the Board, who was granted 8,300
stock options. The exercise price of the options was $33.93 and the options
expire December 9, 2007.

EXECUTIVE OFFICERS OF THE REGISTRANT

Past positions, in order from most recent to earliest, are set out for officers
who have not held their current executive positions with Nexen for more than 5
years. Start dates are indicated for officer positions with Nexen.

EFFECTIVE DATE OF EXECUTIVE
OFFICER (AGE) CURRENT AND PAST POSITION(S) WITH NEXEN CURRENT POSITION OFFICER SINCE
- -------------------------------------------------------------------------------------------------------------------------------

Charles W. Fischer (52) President and Chief Executive Officer and a Director June 1, 2001 1994
Formerly: Executive Vice President and Chief
Operating
Officer since May 14, 1997
- -------------------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow (47) Executive Vice President and Chief Financial Officer June 1, 2001 1997
Formerly: Senior Vice President, Finance since
February 19, 1999
Vice President, Finance and Chief Financial Officer
since February 27, 1998
Vice President, Finance since June 17, 1997
- -------------------------------------------------------------------------------------------------------------------------------
Laurence Murphy (52) Senior Vice President, International Oil and Gas January 1, 1999 1998
Formerly: Vice President, International since
February 27, 1998
President and General Manager of Yemen Operations
- -------------------------------------------------------------------------------------------------------------------------------
John B. McWilliams(1) (55) Senior Vice President, General Counsel and Secretary May 11, 1993 1987
- -------------------------------------------------------------------------------------------------------------------------------

90

EFFECTIVE DATE OF EXECUTIVE
OFFICER (AGE) CURRENT AND PAST POSITION(S) WITH NEXEN CURRENT POSITION OFFICER SINCE
- -------------------------------------------------------------------------------------------------------------------------------

Douglas B. Otten (60) Senior Vice President, United States Oil and Gas May 12, 1998 1990
Formerly: Senior Vice President since May 14, 1997
- -------------------------------------------------------------------------------------------------------------------------------
Thomas A. Sugalski (1)(59) Senior Vice President, Chemicals May 10, 1994 1988
- -------------------------------------------------------------------------------------------------------------------------------
Roger D. Thomas (50) Senior Vice President, Canadian Oil and Gas February 19, 1999 1998
Formerly: Vice President, Canada since May 12, 1998
Vice President since January 1, 1998
- -------------------------------------------------------------------------------------------------------------------------------
Nancy F. Foster (43) Vice President, Human Resources and Corporate July 11, 2000 2000
Services
Formerly: Division Vice President,
Finance - Canadian Oil and Gas
General Manager, Human Resources
Corporate Manager, Planning and Development
- -------------------------------------------------------------------------------------------------------------------------------
Gary H. Nieuwenburg (44) Vice President, Synthetic Crude July 11, 2002 2001
Formerly: Vice President, Corporate Planning and
Business Development since February 16, 2001
Division Vice President, Exploration and
Production - Canadian Oil and Gas
Division Vice President, Exploration and
Production Technology - Canadian Oil and Gas
- -------------------------------------------------------------------------------------------------------------------------------
Kevin J. Reinhart (44) Vice President, Corporate Planning and Business July 11, 2002 1994
Development
Formerly: Treasurer since October 20, 1998
Controller since May 10, 1994
- -------------------------------------------------------------------------------------------------------------------------------
Una M. Power(2) (38) Treasurer July 11, 2002 1998
Formerly: Controller and Director, Corporate
Insurance since May 2, 2002
Controller and Director, Risk Management since
December 1, 1998
Manager, Financial Reporting
- -------------------------------------------------------------------------------------------------------------------------------
Michael J. Harris (39) Controller December 10, 2002 2002
Formerly: Manager, Corporate Finance - Treasury
Division Vice President, Finance - International
- ------------------------------- ------------------------------------------------------- -------------------- -----------------

Notes:
(1) Officer has held the same executive position with Nexen for more than 5
years.

(2) Ms. Power concurrently maintained her position as Controller until December
10, 2002.

(3) The term of office of each executive officer is determined by the Board.

91

ITEM 11. EXECUTIVE COMPENSATION

SUMMARY COMPENSATION

This table summarizes the compensation earned by Nexen's Chief Executive Officer
and the four highest compensated officers other than the Chief Executive
Officer.

Annual Compensation Long-Term Compensation
---------- --------------- --------------- ------------------------
Awards
------------------------
Restricted
Securities Shares or
Underlying Restricted All Other
Other Annual Options Share Compensation
Name and Principal Salary Bonus(1) Compensation Granted Units ($)
Position Year ($) ($) ($) (#) ($)
- --------------------------------------------------------------------------------------------------------------------------

Charles W. Fischer 2002 637,500 300,000 -- 100,000 -- 38,250(3)
President and Chief 2001 540,667 400,000 -- 105,000 -- 32,440(3)
Executive Officer 2000 430,000 700,000(2) -- 70,000 -- 25,800(3)
- --------------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow 2002 418,000 310,000 -- 50,000 -- 25,080(3)
Executive Vice President 2001 376,333 225,000 -- 60,000 -- 22,582(3)
and Chief Financial 2000 322,500 570,000(2) -- 50,000 -- 19,350(3)
Officer
- --------------------------------------------------------------------------------------------------------------------------
Douglas B. Otten 2002 485,873 125,886 - 35,000 -- 29,156(3)/ 63,005(4)
Senior Vice President, 2001 456,783 405,685 -- 28,000 -- 27,407(3)/ 79,874(4)
United States Oil and Gas 2000 422,372 218,854 -- 40,000 -- 10,985(3)/ 56,648(4)
- --------------------------------------------------------------------------------------------------------------------------
Thomas A. Sugalski 2002 449,993 118,019 -- 30,000 -- 26,999(3)/ 60,889(5)
Senior Vice President, 2001 422,908 232,240 417,695(6) 25,000 -- 25,374(3)/ 76,059(5)
Chemicals 2000 390,547 194,870 -- 35,000 -- 15,290(3)/ 49,306(5)
- --------------------------------------------------------------------------------------------------------------------------
Laurence Murphy 2002 346,000 90,000 -- 35,000 -- 20,760(3)
Senior Vice President, 2001 329,250 180,000 -- 28,000 -- 19,758(3)
International Oil and Gas 2000 311,250 162,000 -- 40,000 -- 18,675(3)
- --------------------------------------------------------------------------------------------------------------------------

Notes:
(1) Bonuses for a year are determined based on performance during the year and
are paid to the employee in the following year. Bonuses are paid pursuant
to the Incentive Compensation Plan. The bonuses indicated were the payments
made in the year shown.

(2) Includes a special bonus of $400,000 in recognition of the successful share
repurchase transaction with Occidental Petroleum Corporation.

(3) Contributions to the Employee Savings Plan.

(4) Nexen contributed to a Qualified Defined Contribution Plan and a
Restoration Plan with Nexen Petroleum U.S.A. Inc. for Mr. Otten.

(5) Nexen contributed to a Qualified Defined Contribution Plan in 2001 and 2002
for Mr. Sugalski. Nexen contributed to the Occidental Petroleum Corporation
Senior Executive Supplemental Retirement Plan for Mr. Sugalski during 2000
and to the Nexen Chemicals U.S.A. Inc. Restoration Plan in 2001 and 2002.

(6) Represents a special settlement payment for termination from Occidental
Petroleum Corporation Non-Qualified Executive Benefit Plans.

92

STOCK OPTIONS

Pursuant to Nexen's Stock Option Plan, the Board, on the recommendation of the
Compensation and Human Resources Committee, may grant stock options to Nexen
directors, officers and employees. Nexen does not receive any consideration when
options are granted. The option exercise price is the market price of Nexen's
common shares on the Toronto Stock Exchange for Canadian based employees or the
New York Stock Exchange for US based employees, when the option is granted.

The Board determines the term of each option, to a maximum of ten years, and the
vesting schedule. For all options granted before December 31, 2000, each option
has a term of ten years; 20% of the grant vests after six months and then 20%
more vests each year for four years on the anniversary of the grant. In February
2001, the Compensation and Human Resources Committee and the Board approved an
amendment to the Stock Option Plan which sets out that each option granted has a
term of five years and the options vest one-third each year over three years.
Generally, if a change of control event occurs (as defined in the Stock Option
Plan), all issued but unvested options will become vested.

OPTION GRANTS DURING 2002

- ------------------------------------------------------------------------------------------------------------------------
Potential Realizable Value at
% of Total Assumed Annual Rates of Stock
Options/Stock Price Appreciation for Option Term
Securities Appreciation ----------------------------------
Underlying Rights Granted
Options to Employees in Exercise or
Granted Financial Base Price(1)
Name (#) Year ($/Security)(2) Expiration Date 5% ($) 10% ($)
- ------------------------------------------------------------------------------------------------------------------------

Charles W. Fischer 100,000 3.7 33.93 December 9, 2007 937,423 1,626,960
- ------------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow 50,000 1.9 33.93 December 9, 2007 468,712 813,480
- ------------------------------------------------------------------------------------------------------------------------
Douglas B. Otten 35,000 1.3 21.89 (USD) December 9, 2007 333,085 554,196
- ------------------------------------------------------------------------------------------------------------------------
Thomas A. Sugalski 30,000 1.1 21.89 (USD) December 9, 2007 285,501 475,025
- ------------------------------------------------------------------------------------------------------------------------
Laurence Murphy 35,000 1.3 33.93 December 9, 2007 328,098 569,436
- ------------------------------------------------------------------------------------------------------------------------

Notes:

(1) Equal to the market value of securities underlying options on the date of
grant.

(2) All values in Canadian dollars unless otherwise noted.

OPTION EXERCISES DURING 2002 AND FINANCIAL YEAR-END OPTION VALUES

- --------------------------------------------------------------------------------------------------------------------------
Number of Securities Value of Unexercised
Underlying Unexercised In-The-Money-Options at
Securities Acquired Options at Financial Financial Year-end
on Exercise Value Realized(1) Year-end ($)(2)
Name (#) ($)(2) (#)
Exercisable/Unexercisable Exercisable/Unexercisable
- --------------------------------------------------------------------------------------------------------------------------

Charles W. Fisher 8,000 204,000 328,100 / 211,300 2,799,840 / 292,360
- --------------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow 13,000 297,270 134,400 / 127,600 881,360 / 176,940
- -------------------------- ---------------------- -------------------- -------------------------- ------------------------
Douglas B. Otten -- -- 181,320 / 76,480 1,885,964 / 102,216
- -------------------------- ---------------------- -------------------- -------------------------- ------------------------
Thomas A. Sugalski 62,000 1,246,850 114,500 / 67,500 716,827 / 96,514
- -------------------------- ---------------------- -------------------- -------------------------- ------------------------
Laurence Murphy -- -- 134,520 / 76,480 1,014,722 / 117,118
- -------------------------- ---------------------- -------------------- -------------------------- ------------------------

Notes:
(1) Equals market price at the time of the exercise minus exercise price.

(2) All values in Canadian dollars.

93

BENEFIT PLANS

All named executive officers, except Mr. Sugalski and Mr. Otten, are members of
Nexen's Defined Benefit Pension Plan and of the Executive Benefit Plan.

DEFINED BENEFIT PENSION PLAN

Under this plan, participants must contribute 3% of their regular gross
earnings, up to an allowable maximum, to the pension plan. Upon retirement, they
receive a benefit equal to 1.7% of their average earnings for the 36 highest
paid consecutive months during the ten years before retirement, multiplied by
the number of years of credited service. The plan is integrated with the Canada
Pension Plan (CPP) in order to provide a maximum offset of one-half of the CPP
benefit.

Pension benefits earned prior to January 1, 1993 will be indexed on an ad hoc
basis. Pension benefits earned after December 31, 1992 will be indexed at an
amount equal to the greater of:

o 75% of the increase in the Canadian Consumer Price Index less 1% to a
maximum of 5%; and

o 25% of the increase in the Canadian Consumer Price Index.

Nexen contributed $1.9 million to the Defined Benefit Pension Plan in 2002.

EXECUTIVE BENEFIT PLAN

The plan provides supplemental benefits to the extent that benefits under the
pension plan are limited by statutory guidelines.

ESTIMATED PENSION BENEFIT

This table shows the estimated annual pension an executive officer who retired
on December 31, 2002 would receive, assuming that the amount in the Summary
Compensation Table above is the officer's final average salary. It includes
benefits from both the Defined Benefit Pension Plan and Executive Benefit Plan
and assumes a retirement age of 65. The normal form of benefit paid from this
plan is joint life with 66 2/3% to the surviving spouse.

YEARS OF SERVICE
---------------------------------------------------------------------------------------------
REMUNERATION 5 10 15 20 25 30 35
---------------------------------------------------------------------------------------------------------------------

$300,000 $24,824 $49,648 $74,472 $99,296 $124,120 $148,944 $173,768
---------------------------------------------------------------------------------------------------------------------
$350,000 $29,074 $58,148 $87,222 $116,296 $145,370 $174,444 $203,518
---------------------------------------------------------------------------------------------------------------------
$400,000 $33,324 $66,648 $99,972 $133,296 $166,620 $199,944 $233,268
---------------------------------------------------------------------------------------------------------------------
$450,000 $37,574 $75,148 $112,722 $150,296 $187,870 $225,444 $263,018
---------------------------------------------------------------------------------------------------------------------
$500,000 $41,824 $83,648 $125,472 $167,296 $209,120 $250,944 $292,768
---------------------------------------------------------------------------------------------------------------------
$550,000 $46,074 $92,148 $138,222 $184,296 $230,370 $276,444 $322,518
---------------------------------------------------------------------------------------------------------------------
$600,000 $50,324 $100,648 $150,972 $201,296 $251,620 $301,944 $352,268
---------------------------------------------------------------------------------------------------------------------
$650,000 $54,574 $109,148 $163,722 $218,296 $272,870 $327,444 $382,018
---------------------------------------------------------------------------------------------------------------------
$700,000 $58,824 $117,648 $176,472 $235,296 $294,120 $352,944 $411,768
---------------------------------------------------------------------------------------------------------------------
$750,000 $63,074 $126,148 $189,222 $252,296 $315,370 $378,444 $441,518
---------------------------------------------------------------------------------------------------------------------
$800,000 $67,324 $134,648 $201,972 $269,296 $336,620 $403,944 $471,268
---------------------------------------------------------------------------------------------------------------------
$850,000 $71,574 $143,148 $214,722 $286,296 $357,870 $429,444 $501,018
---------------------------------------------------------------------------------------------------------------------
$900,000 $75,824 $151,648 $227,472 $303,296 $379,120 $454,944 $530,768
---------------------------------------------------------------------------------------------------------------------
$950,000 $80,074 $160,148 $240,222 $320,296 $400,370 $480,444 $560,518
---------------------------------------------------------------------------------------------------------------------
$1,000,000 $84,324 $168,648 $252,972 $337,296 $421,620 $505,944 $590,268
---------------------------------------------------------------------------------------------------------------------
$1,050,000 $88,574 $177,148 $265,722 $354,296 $442,870 $531,444 $620,018
---------------------------------------------------------------------------------------------------------------------
$1,100,000 $92,824 $185,648 $278,472 $371,296 $464,120 $556,944 $649,768
---------------------------------------------------------------------------------------------------------------------
$1,150,000 $97,074 $194,148 $291,222 $388,296 $485,370 $582,444 $679,518
---------------------------------------------------------------------------------------------------------------------
$1,200,000 $101,324 $202,648 $303,972 $405,296 $506,620 $607,944 $709,268
---------------------------------------------------------------------------------------------------------------------

An executive officer's average earnings for purposes of the plan includes stated
salary and the lesser of the eligible target incentive bonus or the actual
incentive bonus paid.

Messrs. Fischer, Romanow and Murphy have 18.58, 15.50 and 16.67 years of
credited service, respectively.

94

EMPLOYEE SAVINGS PLAN

The Summary Compensation Table includes Nexen's contribution to the savings plan
made on behalf of executive officers. All regular employees may participate in
our Employee Savings Plan. Through payroll deductions, employees may contribute
any percentage of their regular earnings to purchase Nexen common shares and/or
mutual fund units. Nexen matches employee contributions to a maximum of 6% of
regular earnings. The extent of matching is based on the investment option
selected and the employee's length of participation in the plan. The full amount
of Nexen's contribution is invested in common shares and is fully vested
immediately. Employee and employer contributions may be allocated to registered
or non-registered accounts.

CHANGE OF CONTROL AGREEMENTS

Nexen has entered into Change of Control Agreements with Messrs. Fischer,
Romanow, Otten, Sugalski, Murphy and other key executives. The agreements were
effective October 1999, amended December 2000 and amended and restated December
2001. The agreements recognize that these executives are critical to Nexen's
ongoing business. They recognize the need to retain the executives, protect them
from employment interruption due to a change in control and treat them in a fair
and equitable manner, consistent with industry standards.

For the purposes of these agreements, a change of control includes any
acquisition of common shares or other securities that carry the right to cast
more than 35% of the votes attaching to all common shares and, in general, any
event, transaction or arrangement which results in a person or group exercising
effective control of Nexen.

If the named executives are terminated following a change in control, they will
be entitled to receive salary and benefits for a specified severance period. For
Mr. Fischer and Mr. Romanow, the severance period is 36 months. They may also
terminate their employment on a voluntary basis following a change of control
with severance periods of 36 and 30 months, respectively. For Messrs. Otten,
Sugalski and Murphy, the severance period is 30 months.

DIRECTORS' AND OFFICERS' LIABILITY INSURANCE

Nexen maintains a directors' and officers' liability insurance policy for the
benefit of our directors and officers. The policy provides coverage for costs
incurred to defend and settle claims against its directors and officers to an
annual limit of US $125 million with a US $1 million deductible per occurrence.
The cost of coverage for 2002 was approximately US $0.3 million.

REPORT OF THE COMPENSATION AND HUMAN RESOURCES COMMITTEE

The Compensation and Human Resources Committee administers Nexen's Incentive
Compensation Plan, Stock Option Plan, Stock Appreciation Rights Plan and Pension
Plan. It reviews and approves executive management's recommendations for the
annual salaries, bonuses and grants of stock options and stock appreciation
rights. The Committee consists of eight directors, seven who are independent
pursuant to Nexen's categorical standards and one who is not independent. Both
Mr. Hentschel and Mr. Zaleschuk were formerly President and Chief Executive
Officer of Nexen (Mr. Hentschel over five years ago). The Committee reports to
the Board and the Board gives final approval to compensation matters.

POLICIES OF THE COMMITTEE

Nexen is committed to pay for performance, improved shareholder returns and
external competitiveness. These principles are factored into the design,
development and administration of our compensation programs, as directed by the
Committee.

The Committee believes maximizing shareholder return is the most important
measure of success. At the operational level, this translates primarily into net
income, cash flow and net asset value growth. At the corporate headquarters
level, this results from successful implementation of necessary strategic
change. The Committee recognizes the need to attract and retain a stable and
focused leadership capable of managing Nexen's operations, finances and assets.
As appropriate, the Committee rewards exceptional individual contributions with
highly competitive compensation.

To ensure competitiveness, Nexen hires various independent compensation
consulting firms to compare our executive compensation practices to our peers,
primarily major Canadian oil and gas and, where relevant, chemical and marketing
companies.

Our compensation program has three components: salary, annual cash incentives
and long-term incentives.

BASE SALARIES

To determine base salaries, Nexen maintains a framework of job levels based on
internal comparability and external market data. The Committee's goal is to
provide total cash compensation for our top performing employees between the
50th and 75th percentile as compared to our peers.

95

ANNUAL INCENTIVES

The Board approves any annual cash incentives awarded under the Annual Incentive
Plan. The Committee determines the total amount of cash available for annual
incentive awards by evaluating a combination of financial and non-financial
criteria, including net income, operating cash flow and specific strategic goals
outlined in a balanced scorecard. The primary indicators, net income and cash
flow, are commonly used metrics in our industry and each represents one-third of
the overall assessment. The qualitative assessment of the balanced scorecard
performance indicators provides a comprehensive evaluation and accounts for the
final one-third of the overall performance assessment. Individual target award
levels increase in relation to job responsibilities so that the ratio of at-risk
versus fixed compensation is greater for higher levels of management. Individual
awards are intended to reflect a combination of overall Nexen, personal and
business unit performance, along with market competitiveness.

The incentive plan is reviewed annually to ensure the plan continues to attract,
motivate, reward and retain the high performing and high potential employees
needed to achieve Nexen's business objectives, while reflecting long-term fiscal
responsibility to our shareholders.

STOCK AND LONG-TERM INCENTIVES

The Board believes that employees should have a stake in Nexen's future and that
their interest should be aligned with the interest of our shareholders. To this
end, Nexen's contributions to employee savings plans are made in Nexen common
shares. In addition, the Committee selects those directors, officers and
employees whose decisions and actions can most directly impact business results
to participate in the Stock Option Plan and the Stock Appreciation Rights Plan.

Under these plans, participating directors, officers and employees receive
grants of stock options or stock appreciation rights as a long-term incentive to
increase shareholder value. The grants have a five-year term and vest one-third
each year of the first three years of the term on the anniversary date of the
grant. Awards of stock options and stock appreciation rights are supplementary
to the Annual Incentive Plan and are intended to increase the pay-at-risk
component for senior management.

The Stock Appreciation Rights Plan was introduced in 2001. For employees at or
below mid-level department managers, these rights are typically granted instead
of stock options.

To determine the number of stock options available for distribution, we consider
market information on stock options and the impact of the program on
shareholders. The focus in 2002 was on providing differentiated awards based on
performance, potential and retention risk.

Nexen's Stock Option Plan sets out that options granted to non-officer directors
will not exceed 0.25% of total outstanding shares. The Stock Option Plan also
sets out the total options granted and shares reserved for issuance under
stock-based compensation arrangements will not exceed 10% of the total
outstanding shares.

Nexen maintains share ownership guidelines for executive officers as a way of
aligning executive and shareholder interests. The Chief Executive Officer, Chief
Financial Officer and other executive officers are expected to own shares
representing three, two and one times annual base salary, respectively. In
determining compliance with the guidelines, share ownership includes the net
value of exercisable options.

PRESIDENT AND CHIEF EXECUTIVE OFFICER COMPENSATION

Competitive compensation information for our President and Chief Executive
Officer is determined based on assessments conducted by independent compensation
consulting firms which compare similar positions in oil and gas and in the
broader industrial sector. Target total cash compensation (base salary plus
incentive bonus) is at the low end of the range of the oil and gas comparator
group.

The award to Mr. Fischer under the Annual Incentive Plan, is a percentage of his
target bonus based on the composite performance rating approved by the Board
which takes into account the three components of the plan, the first two being
the targets for net income and cash flow and the last one being a qualitative
assessment. The qualitative assessment includes a scorecard of targets for
growth and operating performance, such as net asset value growth, cost
management, safety record, production volumes and reserve growth, among others.
An important measure in the scorecard is the extent to which the operations were
conducted in an environmentally safe and socially responsible manner.

96

Annual salary increases for Mr. Fischer are based on his performance against key
objectives using a broad selection of criteria including the following:

o overall achievement of corporate/financial performance;

o achievement of strategic objectives;

o progress on long term objectives;

o team building and succession planning;

o visionary leadership; and

o social responsibility.

Based on the Board assessment of Mr. Fischer's achievement of objectives in
2001, his base salary was increased to $650,000 in 2002 and he was awarded a
bonus of $300,000 under the Annual Incentive Plan.

Mr. Fischer was also granted options to purchase 100,000 shares at an exercise
price of $33.93 under the Nexen Stock Option Plan. Awards under the Stock Option
Plan are a direct link to the stock performance and form a part of the
competitive overall compensation package.

Submitted on behalf of the Compensation and Human Resources Committee:

Mr. John M. Willson, Chair
Mr. David A. Hentschel
Mr. S. Barry Jackson
Mr. Kevin J. Jenkins
Mr. Thomas C. O'Neill
Mr. Richard M. Thomson
Mr. Gordon R. Wittman
Mr. Victor J. Zaleschuk

97

NEW SHARE PERFORMANCE GRAPH

The following graph shows changes in the past five year period, ending December
31, 2002, in the value of $100 invested in our common shares, compared to the
S&P/TSX Composite Index (previously known as the TSE 300 Composite Index), the
S&P/TSX Energy Sector Index (as a replacement for the TSX Oil and Gas Index) and
the S&P/TSX Oil & Gas Exploration & Production Index (as a replacement for TSX
Oil and Gas Producers Index) as at December 31, 2002. Our common shares are
included in each of these indices.

TOTAL RETURN INDEX VALUES

[LINE GRAPH OMITTED]

1997 1998 1999 2000 2001 2002
- ------------------------------------------------------------------------------------------------------------------------

Nexen Inc. 100.00 49.79 90.38 118.27 100.25 111.36
S&P/TSX Energy Sector Index 100.00 70.12 88.96 131.39 140.47 159.77
S&P/TSX Oil & Gas Explor. & Prod.
Index 100.00 70.21 85.92 126.34 130.42 151.51
S&P/TSX Composite Index 100.00 98.42 129.63 139.23 121.73 106.59

Assuming an investment of $100 and the reinvestment of dividends

98

OLD SHARE PERFORMANCE GRAPH

The following graph shows changes in the past five year period, ending December
31, 2002, in the value of $100 invested in our common shares, compared to the
S&P/TSX Composite Index (previously known as the TSE 300 Composite Index) and
the TSX Oil and Gas and TSX Oil and Gas Producers Indices as at December 31,
2002. Our common shares are included in each of these indices.

In 2004, Nexen intends to abandon the TSX Oil and Gas and the TSX Oil and Gas
Producers Indices as they will not be maintained after May 2003 and they are not
accessible to shareholders. Nexen will continue to compare its shares to each of
the indices shown on the previous page, being the S&P/TSX Composite Index, the
S&P/TSX Energy Sector Index (as a replacement for the TSX Oil and Gas Index) and
the S&P/TSX Oil & Gas Exploration & Production Index (as a replacement for TSX
Oil and Gas Producers Index).

TOTAL RETURN INDEX VALUES

[LINE GRAPH OMITTED]

1997 1998 1999 2000 2001 2002
- ------------------------------------------------------------------------------------------------------------------

Nexen Inc. 100.00 49.79 90.38 118.27 100.25 111.36
TSX Oil and Gas Producers
Index 100.00 69.59 85.26 124.89 129.12 150.09
TSX Oil and Gas Index 100.00 70.15 89.27 131.43 140.64 159.95
S&P/TSX Composite Index 100.00 98.42 129.63 139.23 121.73 106.59

Assuming an investment of $100 and the reinvestment of dividends

99

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

Nexen's common shares are the only class of voting securities of Nexen. Based
upon information known to Nexen, the following table sets out the beneficial
ownership of each person or group who beneficially owns (pursuant to SEC
Regulations) more than 5% of the voting securities of Nexen as of December 31,
2002.

# OF SHARES
BENEFICIALLY
NAME AND ADDRESS OF BENEFICIAL OWNER(1) OWNED % OF CLASS
- ---------------------------------------------------------------- --------------
Jarislowsky Fraser Limited 19,781,235(2) 16.1
Suite 2005, 1010 Sherbrooke Street West
Montreal, Quebec, Canada, H3A 2R7
- ---------------------------------------------------------------- --------------
Ontario Teachers' Pension Plan Board 19,720,418(3) 16.0
5650 Yonge Street
Toronto, Ontario, Canada, M2M 4H5
- ---------------------------------------------------------------- --------------
Capital Research and Management Co. 9,052,520(4) 7.4
333 South Hope Street
Los Angeles, California, U.S.A., 90071-1447
- ---------------------------------------------------------------- --------------

Notes:
(1) Beneficial owners holding greater than 5% of the outstanding common shares
of Nexen are derived from public sources. There may exist Beneficial owners
who hold more than 5% of Nexen's common shares who are not subject to 13-D
and 13-G filing requirements.

(2) Of the 19,781,235 beneficially owned, the beneficial owner has sole voting
power over 18,638,418 shares; shared voting power over 1,142,817 shares;
and sole dispositive power over all of the 19,781,235 shares.

(3) The beneficial owner has sole voting and dispositive power over all of the
19,720,418 shares.

(4) The beneficial owner has sole dispositive power over all of the 9,052,520
shares and disclaims beneficial ownership pursuant to Rule 13d-4.

SECURITY OWNERSHIP OF MANAGEMENT

As of January 31, 2003, the following directors, certain executive officers and
all directors and executive officers as a group beneficially owned the following
common shares of Nexen (which are the only voting securities):

NUMBER OF EXERCISABLE
NAME OF BENEFICIAL OWNER SHARES(1) STOCK OPTIONS(1)(2)
- ------------------------------------------------------------------------------------------------------

Charles W. Fischer 22,806 328,100
- ------------------------------------------------------------------------------------------------------
Dennis G. Flanagan 3,001 11,210
- ------------------------------------------------------------------------------------------------------
David A. Hentschel 5,585 19,210
- ------------------------------------------------------------------------------------------------------
S. Barry Jackson 3,000 2,210
- ------------------------------------------------------------------------------------------------------
Kevin J. Jenkins 3,021 19,210
- ------------------------------------------------------------------------------------------------------
Thomas C. O'Neill 4,000 None
- ------------------------------------------------------------------------------------------------------
Francis M. Saville, Q.C. 3,151 19,210
- ------------------------------------------------------------------------------------------------------
Richard M. Thomson 13,001 28,832
- ------------------------------------------------------------------------------------------------------
John M. Willson 5,001 19,210
- ------------------------------------------------------------------------------------------------------
Gordon R. Wittman 3,001 19,210
- ------------------------------------------------------------------------------------------------------
Victor J. Zaleschuk 15,539 253,010
- ------------------------------------------------------------------------------------------------------
Laurence Murphy 19,305 134,520
- ------------------------------------------------------------------------------------------------------
Douglas B. Otten 12,148 181,320
- ------------------------------------------------------------------------------------------------------
Marvin F. Romanow 12,006 144,400
- ------------------------------------------------------------------------------------------------------
Thomas A. Sugalski 17 114,500
- ------------------------------------------------------------------------------------------------------
All directors and executive officers as a group (22 persons) 165,205 1,662,782
- ------------------------------------------------------------------------------------------------------

Notes:
(1) The number of shares and the number of stock options exercisable by each
beneficial owner represents less than 1% of the class outstanding.

(2) Includes all stock options exercisable within 60 days of January 31, 2003.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

CERTAIN BUSINESS RELATIONSHIPS

Mr. Saville, a director, is a senior partner of Fraser Milner Casgrain LLP,
Barristers and Solicitors, Calgary, Alberta. This firm has rendered legal
services to Nexen during each of the last five years. Mr. Saville is independent
pursuant to the categorical standards adopted by Nexen. The categorical
standards are attached as Schedule B to our Proxy Statement and Information
Circular.

100

ITEM 14. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer have evaluated the
effectiveness of our disclosure controls and procedures (as defined in Exchange
Act Rules 13a-14(c) and 15-d-14(c)) within 90 days prior to the filing of this
Form 10-K (Evaluation Date). They concluded that, as of the Evaluation Date, our
disclosure controls and procedures were adequate and effective in ensuring that
material information relating to the Company and its consolidated subsidiaries
would be made known to them by others within those entities, particularly during
the period in which this annual report was being prepared. Management recognizes
that any controls and procedures, no matter how well designed and operated, can
provide only reasonable assurance of achieving the desired control objectives,
and in reaching a reasonable level of assurance, management necessarily is
required to apply its judgment in evaluating the cost-benefit relationship of
possible controls and procedures.

CHANGES IN INTERNAL CONTROLS

We have continually had in place systems relating to internal controls and
procedures with respect to our financial information. While we were not of the
belief that our controls had any significant deficiencies or material
weaknesses, it was determined that taking advantage of new proven systems
technology could provide a competitive advantage. Accordingly, in 2002, we
introduced a significant change in our internal controls implementing a Systems,
Applications, and Products in Data Processing (SAP) system in Canada (January 1,
2002), in the Yemen Masila Project (April 1, 2002) and in the US (July 1, 2002).
SAP is being implemented in other locations throughout 2003 and beyond. SAP is
an integrated, real-time, multi-user, multi-location enterprise resource
planning system, which focuses on financial and management accounting, and
logistics. The conversion of data and the implementation and operation of SAP
has been continually monitored and reviewed. Based on these evaluations, there
were no significant deficiencies or material weaknesses in these internal
controls requiring corrective action. As a result, no corrective actions were
taken.

101

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

FINANCIAL STATEMENTS AND SCHEDULES

Reference is made to the Index to Financial Statements and Related Information
under Item 8 of this report where these documents are listed.

Schedules and separate financial statements of subsidiaries are omitted for the
reason that they are not required or are not applicable, or the required
information is shown in the Consolidated Financial Statements or notes thereto.

EXHIBITS

Exhibits filed as part of this report are listed below. Certain exhibits have
been previously filed with the Commission and are incorporated in this Form 10-K
by reference. Instruments defining the rights of holders of debt securities that
do not exceed 10% of Nexen's consolidated assets have not been included. A copy
of such instruments will be furnished to the Commission upon request.

3.5 Restated Certificate of Incorporation of the Registrant dated June 5,
1995, and Restated Articles of Incorporation (filed as Exhibit 3.5 to
Form 10-K for the year ended December 31, 1995, filed by the
Registrant).

3.6 Certificate of Amendment of the Articles of the Registrant dated May 9,
1996 (filed as Exhibit 3.6 to Form 10-K for the year ended December 31,
1996, filed by the Registrant).

3.7 Certificate of Amendment and Articles of Amendment of the Registrant
dated November 2, 2000, with respect to the name change to Nexen Inc.
(filed as Exhibit 3.7 to Form 10-K for the year ended December 31,
2000, filed by the Registrant).

3.8 By-Law No. 1 of the Registrant enacted February 15, 2002, being a
by-law relating generally to the transaction of the business and
affairs of the Registrant (filed as Exhibit 2 to Form 8A/A dated August
20, 2002, filed by the Registrant).

4.23 Indenture dated October 30, 1998, between the Registrant and IBJ
Stirred Bank & Trust Company pertaining to the issuance of US $259
million, 9.75 per cent junior subordinated debentures ("preferred
securities") due October 30, 2047, (filed as Exhibit 4.23 to Form 10-Q
for the quarterly period ended March 31, 1999, filed by the
Registrant).

4.24 Prospectus dated October 27, 1998, pertaining to US $259 million, 9.75
per cent preferred securities due October 30, 2047, (filed as Exhibit
4.24 to Form 10-Q for the quarterly period ended March 31, 1999, filed
by the Registrant).

4.25 Indenture dated February 9, 1999, between the Registrant and IBJ
Whitehall Bank & Trust Company pertaining to the issuance of US $218
million, 9.375 per cent preferred securities due March 31, 2048, (filed
as Exhibit 4.25 to Form 10-Q for the quarterly period ended March 31,
1999, filed by the Registrant).

4.26 Prospectus dated February 4, 1999, pertaining to US $218 million, 9.375
per cent preferred securities due March 31, 2048, (filed as Exhibit
4.26 to Form 10-Q for the quarterly period ended March 31, 1999, filed
by the Registrant).

4.29 Acquisition Agreement between the Registrant, Occidental Petroleum
Corporation and Ontario Teachers' Pension Plan Board, dated March 1,
2000, (filed as Exhibit 4.29 to Form 10-K for the year ended December
31, 1999, filed by the Registrant).

4.32 Amended and Restated Loan Agreement of December 29, 1988, between the
Registrant, the Toronto Dominion Bank, as Agent, and the Lenders, dated
November 17, 2000, amending the amount of the facility to $400 million
and providing for various conforming covenant amendments to the Loan
Agreement dated April 14, 1997, (as restated) thereto (filed as Exhibit
4.32 to Form 10-K for the year ended December 31, 2000, filed by the
Registrant).

4.33 Restated Loan Agreement of April 14, 1997, between the Registrant,
Toronto Dominion Bank, as Agent, and the Lenders dated October 16,
2000, reducing the amount of the facility to $975 million and splitting
the loan into 364 day (40%) and six year term (60%) portions, and other
various amendments thereto (filed as Exhibit 4.33 to Form 10-K for the
year ended December 31, 2000, filed by the Registrant).

4.36 First Amending Agreement to the October 16, 2000 Restated Loan
Agreement of April 14, 1997, between the Registrant, the Toronto
Dominion Banks, as Agent, and the Lenders, dated July 31, 2001 (filed
as Exhibit 4.36 to Form 10-K for the year ended December 31, 2001,
filed by the Registrant).

102

4.37 First Amending Agreement to the November 17, 2000 Amended and Restated
Loan Agreement of December 29, 1988, between the Registrant, the
Toronto Dominion Bank, as Agent, and the Lenders, dated August 1, 2001
(filed as Exhibit 4.37 to Form 10-K for the year ended December 31,
2001, filed by the Registrant).

4.38 Second Amending Agreement to the October 16, 2000 Restated Loan
Agreement of April 14, 1997, between the Registrant, the Toronto
Dominion Banks, as Agent, and the Lenders, dated July 30, 2002.

4.39 Second Amending Agreement to the November 17, 2000 Amended and Restated
Loan Agreement of December 29, 1988, between the Registrant, the
Toronto Dominion Bank, as Agent, and the Lenders, dated July 31, 2002.

4.40 Amended and Restated Shareholder Rights Plan Agreement dated May 2,
2002 between the Corporation and CIBC Mellon Trust Company, as Rights
Agent, which includes the Form of Rights Certificate as Exhibit A
(filed as Exhibit 3 to Form 8-A/A dated August 20, 2002, filed by the
Registrant).

4.41 Short Form Shelf Prospectus dated May 31, 2002, pertaining to US $500
million debt securities.

10.40 Amended and Restated Change of Control Agreements with Executive
Officers dated during December, 2001 (filed as Exhibit 10.41 to Form
10-K for the year ended December 31, 2001, filed by the Registrant).

10.41 Indemnification Agreements made between the Registrant and its
directors and officers during 2002.

11.2 Statement regarding the Computation of Per Share Earnings for the three
years ended December 31, 2002.

16.1 Letter re change in certifying accountant (filed as Exhibit 16.1 to
Form 8-K filed July 17, 2002 by the Registrant).

21 Subsidiaries of the Registrant.

23 Consent of Independent Chartered Accountants.

99.1 Certification of periodic report by Chief Executive Officer pursuant to
18 U.S.C., Section 1350, as adopted pursuant to Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.2 Certification of periodic report by Chief Financial Officer pursuant to
18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.

REPORTS ON FORM 8-K

During the fourth quarter of 2002, Nexen did not file a Current Report on Form
8-K.

103

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Company has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized, on February 24, 2003.

NEXEN INC.

By: /s/ Charles W. Fischer
-----------------------------------------
Name: Charles W. Fischer
Title: President, Chief Executive Officer
and Director (Principal Executive
Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities indicated on February 24, 2003.

/s/ Dennis G. Flanagan /s/ Charles W. Fischer
- ---------------------------------- ------------------------------------------
Dennis G. Flanagan, Director Charles W. Fischer
President, Chief Executive Officer
and Director (Principal Executive Officer)

/s/ Kevin J. Jenkins /s/ Marvin F. Romanow
- ---------------------------------- ------------------------------------------
Kevin J. Jenkins, Director Marvin F. Romanow
Executive Vice President and Chief Financial
Officer (Principal Financial Officer)

/s/ David A. Hentschel /s/ Michael J. Harris
- ---------------------------------- ------------------------------------------
David A. Hentschel, Director Michael J. Harris
Controller
(Principal Accounting Officer)

/s/ S. Barry Jackson /s/ John B. Mcwilliams
- ---------------------------------- ------------------------------------------
S. Barry Jackson, Director John B. McWilliams
Senior Vice President, General Counsel
and Secretary

/s/ Thomas C. O'Neill
- ----------------------------------
Thomas C. O'Neill, Director

/s/ Francis M. Saville
- ----------------------------------
Francis M. Saville, Director

/s/ Richard M. Thomson
- ----------------------------------
Richard M. Thomson, Director

/s/ John M. Willson
- ----------------------------------
John M. Willson, Director

/s/ Gordon R. Wittman
- ----------------------------------
Gordon R. Wittman, Director

/s/ Victor J. Zaleschuk
- ----------------------------------
Victor J. Zaleschuk, Director

104

CERTIFICATIONS

I, Charles W. Fischer, President and Chief Executive Officer, certify that:

1. I have reviewed this annual report on Form 10-K of Nexen Inc.

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;

(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the Evaluation Date); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

Date: February 24, 2003 /s/ Charles W. Fischer
---------------------------------------
Charles W. Fischer
President, and Chief Executive Officer

105

CERTIFICATIONS

I, Marvin F. Romanow, Executive Vice-President, and Chief Financial Officer,
certify that:

1. I have reviewed this annual report on Form 10-K of Nexen Inc.

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;

(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

Date: February 24, 2003 /s/ Marvin F. Romanow
----------------------------
Marvin F. Romanow
Executive Vice President,
and Chief Financial Officer

106