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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, 2003
COMMISSION FILE NUMBER 1-6702
[GRAPHIC OMITTED]
[LOGO - NEXEN INC.]
NEXEN INC.
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
Subordinated Securities, due 2043 The New York Stock Exchange
The Toronto 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 June 30, 2003, the aggregate market value of the voting shares held by
non-affiliates of the registrant was approximately Cdn $4.2 billion based on the
Toronto Stock Exchange closing price on that date. On January 31, 2004, there
were 126,738,410 common shares issued and outstanding.
TABLE OF CONTENTS
PART I PAGE
Items 1 and 2. Business and Properties ..................................................... 1
Item 3. Legal Proceedings............................................................ 23
Item 4. Submission of Matters to a Vote of Security Holders.......................... 23
PART II
Item 5. Market for the Registrant's Common Shares and
Related Stockholder Matters............................................. 24
Item 6. Selected Financial Data...................................................... 25
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................... 26
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................... 59
Item 8. Financial Statements and Supplementary Financial Information................. 61
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure..................................... 105
Item 9A. Controls and Procedures...................................................... 105
PART III
Item 10. Directors and Executive Officers of the Registrant........................... 106
Item 11. Executive Compensation....................................................... 108
Item 12. Security Ownership of Certain Beneficial Owners
and Management.......................................................... 115
Item 13. Certain Relationships and Related Transactions............................... 116
Item 14. Principal Accounting Fees and Services ...................................... 116
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K............................................................. 117
SPECIAL NOTE TO CANADIAN INVESTORS - see page 60
Unless we indicate otherwise, all dollar amounts ($) are in Canadian dollars,
and oil and gas volumes, reserves and related performance measures are presented
on a working interest before royalties basis. Where appropriate, information on
an after-royalties basis is provided in tabular format.
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 convert 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
- --------------------------------------------------------------------------------
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
2003 0.7738 0.7135 0.7738 0.6350
On January 31, 2004, the noon-day exchange rate was US$0.7539 for Cdn $1.00.
Electronic copies of our filings with the Securities Exchange Commission (SEC)
and the Ontario Securities Commission (OSC) (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. As soon as reasonably
practicable, our filings are made available on our website once they are
electronically filed with the SEC or the OSC. Alternatively, the SEC and the OSC
each maintain a website (www.sec.gov and www.sedar.com) that contain our
reports, proxy and information statements and other published information that
have been filed or furnished with the SEC and the OSC.
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
TABLE OF CONTENTS
PAGE
Background.....................................................................2
Strategy.......................................................................3
Operations.....................................................................3
Conventional Oil and Gas..............................................3
United States - Gulf of Mexico...............................5
Middle East..................................................7
West Africa..................................................9
Other International.........................................10
Western Canada..............................................12
Athabasca Oil Sands..................................................14
Reserves, Production and Related Information.........................16
Oil and Gas Marketing................................................18
Chemicals Operations.................................................19
Additional Factors Affecting Business.........................................20
Government Regulations...............................................20
Environmental Regulations............................................20
Employees.....................................................................23
1
BACKGROUND
Nexen Inc. (Nexen, we or our) is a Canadian-based global energy and chemicals
company incorporated under the laws of Canada.
We are one of the largest independent Canadian oil and gas exploration and
production companies. We explore for, develop and produce conventional crude oil
and natural gas primarily in western Canada, the United States (US) Gulf of
Mexico, the Middle East and offshore West Africa. We develop and produce
synthetic crude oil in Canada's Athabasca oil sands region.
We also manage a growing crude oil and natural gas marketing business and
manufacture, market and distribute sodium chlorate, caustic soda and chlorine in
North and South America.
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 ($29.61
per share) 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.
2
STRATEGY
Our goal is to grow long-term shareholder value by generating an attractive
return on every dollar of capital we invest. In the oil and gas industry,
creating value means long-term growth per share in reserves, production, cash
flow and earnings, independent of price volatility.
We pursue a grassroots, exploration-led strategy supplemented by strategic
acquisitions and the development of innovative technology. Our value-based
strategy is supported by:
o solid core assets that provide free cash flow to finance our new growth
development projects;
o active exploration programs aimed at adding to our portfolio of new
growth projects; and
o a culture based on integrity and social responsibility.
We believe this strategy of full-cycle exploration and development can deliver
the best overall returns. To succeed, we continue to locate and develop economic
oil and natural gas reserves. We allocate capital to projects based first on
their investment returns and strategic fit, and second on the potential to grow
reserves and production. In building our portfolio, we target material
opportunities that balance risk and reward, have multiple opportunities for
continued growth and build on our technical skills. Our goal is to operate most
of our core assets and control offsetting acreage and infrastructure for future
development.
Recognizing some time ago that conventional North American basins were maturing,
we began transitioning to under-explored areas, and incorporating emerging
technologies in maturing regions. We positioned ourselves in four of the world's
most attractive areas for oil and gas exploration and development:
o the deep-water Gulf of Mexico;
o the Middle East;
o offshore West Africa; and
o the Canadian Athabasca oil sands.
These areas offer an optimal combination of prospectivity, attractive commercial
terms and low costs. Given our exploration success over the past several years,
we are now executing multi-year development projects in each area that are
starting to add significant value to Nexen.
We maximize value in our marketing operations by providing superior customer
service and growing our business with low-risk opportunities. Our marketing
group provides a key source of market intelligence that helps us make sound
investment decisions. For chemicals, our strategy is to remain a low-cost
producer in North America, while capturing an increasing share of the growing
markets in South America.
OPERATIONS
Nexen has operations in four main areas:
o Conventional Oil and Gas
o Athabasca Oil Sands
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 production, revenues, net income, 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 the United
States (US) Gulf of Mexico, Yemen and western Canada, with other producing
properties offshore Australia and Nigeria, and onshore in Colombia. We continue
to develop new growth opportunities in the Middle East and offshore West Africa.
3
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.
[GRAPHIC OMITTED]
[MAP]
[_] CANADA
[_] GULF OF MEXICO
[_] COLUMBIA
[_] BRAZIL
[_] WEST AFRICA
[_] YEMEN
[_] AUSTRALIA
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 can 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 which generally experiences higher
demand in the summer months.
4
UNITED STATES - GULF OF MEXICO
[GRAPHIC OMITTED]
[MAP]
ACREAGE
- --------------------------------------------------------------------------------
(thousand acres) Developed Undeveloped Total
- --------------------------------------------------------------------------------
Shallow-Water
Gross 168 152 320
Net 94 99 193
- --------------------------------------------------------------------------------
Deep-Water
Gross 23 734 757
Net 11 337 348
- --------------------------------------------------------------------------------
Total
Gross 191 886 1,077
Net 105 436 541
- --------------------------------------------------------------------------------
PROVED RESERVES Before Royalties After Royalties
- --------------------------------------------------------------------------------
Crude Oil (mmbbls) 75 67
Natural Gas (bcf) 304 256
- --------------------------------------------------------------------------------
Total (mmboe) 126 110
- --------------------------------------------------------------------------------
2003 PRODUCTION Before Royalties After Royalties
- --------------------------------------------------------------------------------
Shallow-Water
Crude Oil (mbbls/d) 7.8 6.5
Natural Gas (mmcf/d) 124 103
- --------------------------------------------------------------------------------
Total (mboe/d) 28.5 23.7
- --------------------------------------------------------------------------------
Deep-Water
Crude Oil (mbbls/d) 20.5 18.5
Natural Gas (mmcf/d) 21 19
- --------------------------------------------------------------------------------
Total (mboe/d) 24.0 21.7
- --------------------------------------------------------------------------------
Total (mboe/d) 52.5 45.4
- --------------------------------------------------------------------------------
Our oil and gas assets offshore in the US Gulf of Mexico are our single largest
source of cash flow. We currently hold interests ranging from 3.7% to 100% in
193 federal lease blocks in the Gulf, 133 of which are located in water depths
exceeding 1,000 feet.
Our strategy in the Gulf is to explore for new deep-water reserves and for new
deep gas trends on the shelf, acquire assets with upside, and exploit our
existing asset base.
Royalties on our oil and gas production in the US average approximately 15% of
working interest volumes. Aspen and Gunnison qualify for royalty relief on the
first 87.5 million equivalent barrels. The Gunnison leases are also subject to
price threshold limitations which could require annual royalty payments.
Royalties on other Gulf and state water properties range from 12.5% 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%.
SHALLOW-WATER EXPLORATION AND PRODUCTION
Our shelf production comes from our assets located offshore Louisiana and Texas,
primarily in four fields: Eugene Island 18, Eugene Island 255/257/258/259,
Eugene Island 295, and Vermilion 76 (consisting of blocks 65, 66 and 67). We
continue to exploit these assets, and look for other opportunities on the shelf.
In late 2001, we acquired 100% working interests at Vermilion 76 and Eugene
Island 295. Since then we have drilled 12 development wells at Vermilion 76,
meeting our growth expectations and more than doubling field production to
approximately 40 million cubic feet per day. In the first quarter of 2003, we
restored production at Eugene Island 295. The field was shut-in during the
second half of 2002 from extensive damage caused by Hurricane Lili. Daily field
production at year-end was approximately 22 million cubic feet of natural gas.
In 2002, we signed an agreement with Shell Exploration and Production Company
(Shell) to jointly explore a 1,044 square-mile area in the south Timbalier and
Ship Shoal areas on the shelf. We have a 40% interest in this exploration area.
We are targeting natural gas in deep shelf reservoirs. This play is attractive
because it has deep-water type reserve potential but is located within the shelf
infrastructure. We drilled a dry hole in 2002 in this play. We have recently
finished drilling the shark exploration well, located on South Timbalier 174, to
a depth of 25,743 feet. This is the deepest well drilled to date in the shelf.
No commercial hydrocarbons were encountered and the well is temporarily
abandoned while we evaluate the data collected from the well bore. We expect to
drill two additional deep shelf wells in 2004 in the Main Pass area.
5
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 shifted our
exploration focus from the shelf into the deep water, where we are one of the
largest independent leaseholders. In 2000 and 2001, we had discoveries in the
Gunnison and Aspen sub-basins. Appraisal drilling justified proceeding with the
commercial development of both sub-basins.
In 2003, we drilled Santa Rosa and Shiloh, exploratory wells located in the
eastern Gulf of Mexico in deep water. Both wells were written off. Shiloh
encountered hydrocarbons but in non-commercial quantities. The results were
promising, we acquired additional acreage in the area and exploration activity
is ongoing.
ASPEN
Aspen is located on Green Canyon Block 243 in 3,150 feet of water. The project
was developed using subsea wells tied back to the Shell-operated Bullwinkle
platform 16 miles away. Production commenced in December 2002. In March 2003, we
acquired the remaining 40% interest in Aspen and five exploration blocks in the
area for US$113 million. This acquisition established Nexen as a deep-water
operator and increased our exploration acreage in the greater Aspen area to over
80,000 net acres. Aspen is producing 22,000 boe per day, of which 15% is natural
gas. Returns from Aspen are attractive with cash netbacks twice our corporate
average.
We are currently drilling our third development well at Aspen. We plan to follow
up Aspen Well No. 3 with an exploratory well at Crested Butte, located on the
next block west of Aspen at Green Canyon Block 242.
GUNNISON
In 2001, our Board of Directors approved plans to develop our 30% interest in
the Gunnison sub-basin. 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. One discovery was located in May 2000 on Garden Banks Block
668 and a second discovery was located June 2001 on Garden Banks Block 667.
Gunnison began producing in December 2003 with the tie-in of three subsea wells.
Our share of production from the field at year-end was approximately 39 mmcf of
gas and 1,200 bbls of oil per day.
Gunnison produces from a truss SPAR platform with a design capacity of 40,000
barrels of oil per day and 200 million cubic feet of gas per day. A total of ten
wells will be tied-in to the SPAR. Production will continue to grow throughout
most of 2004 as the remaining seven wells are completed and brought on-stream.
Peak daily rates of 28,000 to 30,000 bbls of oil and 165,000 to 180,000 mcf of
gas are expected at the end of 2004. This would fill approximately 75% of the
capacity of the facility, leaving room for growth from exploration and the
processing of third-party volumes. The Dawson Deep exploration well on Garden
Banks Block 625 was drilled to a total depth of 24,450 feet. The well
encountered hydrocarbons and is currently sidetracking to delineate the extent
of the reservoirs. Dawson Deep is located in 2,900 feet of water, northeast of
our existing Gunnison facility.
OTHER
In 2003, we entered into an agreement with Shell to jointly explore a 1,116
square mile area of the deep-water eastern Gulf of Mexico. The area of mutual
interest consists of 124 blocks located in Mississippi and Desoto Canyon. Shiloh
was the first exploratory well to be drilled under the agreement. This well was
drilled to a total depth of over 24,000 feet and was abandoned.
We are continuing to explore in the deep-water Gulf and to increase our land
position. In 2003, we acquired an additional 21 blocks. In 2004, we plan to
drill at least three high-potential exploration wells.
6
MIDDLE EAST
YEMEN
[GRAPHIC OMITTED]
[MAP]
ACREAGE
(thousand acres) Developed Undeveloped Total
- --------------------------------------------------------------------------------
Gross 44 19,547 19,591
Net 23 9,798 9,821
- --------------------------------------------------------------------------------
PROVED RESERVES
(mmbbls) Before Royalties After Royalties
- --------------------------------------------------------------------------------
Masila Block 161 91
Block 51 31 19
- --------------------------------------------------------------------------------
192 110
- --------------------------------------------------------------------------------
2003 PRODUCTION
(mbbls/d) Before Royalties After Royalties
- --------------------------------------------------------------------------------
Masila Block 116.8 57.5
- --------------------------------------------------------------------------------
Our strategy in Yemen is to:
o maintain production rates and fully exploit the Masila Project;
o develop new growth on Block 51; and
o continue to explore on the Masila Block.
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 16 fields on the block have
produced 750 million gross barrels of oil from total gross recoverable reserves
of just over one billion barrels. We have the right to produce oil from the
Masila fields until 2011 and the right to negotiate a five-year extension.
The Production Sharing Agreement (PSA) governing the Masila Project was signed
with the Yemen Government in March 1987 with the first exploratory well drilled
at Sunah where oil was discovered in 1990. Additional discoveries quickly
followed at Heijah and Camaal. Commerciality was declared in December 1991 with
the development plan approved by the Government in May 1992. Initial production
began in July 1993 with the first lifting of oil in August 1993. Masila blend
oil is sweet and averages 31o API at very low gas oil ratios.
Facilities consist of over 600 km of flowlines from the individual wells, which
connect to larger gathering lines for transport of crude oil, water and gas to
the central processing facility. From there, the crude oil is transported by
pipeline over 138 km of rugged terrain to the export terminal located near Ash
Shihr on the Gulf of Aden.
The export terminal consists of one 1,000,000 barrel and five 500,000 barrel
storage tanks from which oil is pumped to an offshore loading buoy located in
150 feet of water for loading onto tankers.
Gross production was maintained throughout the year at approximately 224,500
barrels per day, net of fuel use of approximately 4,700 barrels per day.
Currently the majority of crude oil production comes from the Upper Qishn
formation. Oil is also produced from formations below the Upper Qishn including
the Lower Qishn, Upper Saar, Saar, Madbi, Basal Sand, and Basement formations.
7
Production from the Masila Project is governed by a PSA between the Government
of Yemen and the Masila joint venture partners including Nexen (Partners). Under
the terms of the agreement, 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 a
provision for Yemen income taxes payable by the Partners at a rate of 35%. In
2003, the Partners' share of production from the Masila Project, including
recovery of past costs, was approximately 37%.
The economics of Masila production are attractive. Over the past two years,
finding and development costs have averaged approximately US$6 per barrel and
operating costs have averaged US$1.40 per barrel, resulting in excellent returns
for shareholders. In addition, the structure of the agreement moderates the
impact on the Partners' cash flows during periods of low prices. We recover our
costs first, and then share any remaining profit oil with the Government. At
current production levels, the Government is entitled to approximately 73-74% of
the profit oil. If price goes down, we still recover the same amount of costs,
but the profit oil is decreased.
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
2003, we sold our Masila crude oil for an average discount of US$3.29/bbl to
WTI.
BLOCK 51
Block 51 is governed by a PSA between the Government of Yemen, and the partners
comprising The Yemen Company (TYCO) (an entity owned by the Government of Yemen)
and Nexen. The PSA expires in 2023 and we have the right to negotiate a
five-year extension.
Our most exciting drilling results to date come from exploration wells drilled
in 2003 at Baishir al Khair BAK-A (formerly Tammum) and BAK-B (formerly Amir).
Late in 2003, we declared commerciality on this block with approval from the
Yemen Government. On declaration of commerciality, 36% of the remaining block
was converted to a development area for a period of 20 years. The remainder of
the block was relinquished. The additional potential of the block will continue
to be evaluated in 2004.
Based on drilling results to date, we expect to develop at BAK-A in excess of 60
million barrels of reserves and add between 20,000 and 25,000 barrels per day of
production capacity in early 2005. Development of the BAK-A discovery will
commence in 2004. Initial development will include ten additional wells, a
central processing facility, a gathering system and a 22 km tieback to our
Masila export pipeline.
Under the terms of the PSA, a royalty ranging from 3% to 10% is payable to the
Government, after which the remaining 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 solely
by Nexen. Costs are recovered from a maximum of 50% of production each fiscal
year, as follows:
COSTS RECOVERY
- --------------------------------------------------------------------------------
Operating 100% in year incurred
Exploration 75% per year, declining balance
Development 75% per year, declining balance
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 30%, of which we are entitled to 87.5%. The
remaining 12.5% of the partner share is payable to TYCO. The Government's share
of profit oil includes provision for Yemen income taxes payable by the partners
at a rate of 35%.
In 2003, we also drilled a third prospect (HEK) 25 km northwest of BAK-B,
however, the well was dry. We also completed a 2D seismic program and have begun
processing the data. We will continue exploring the block and plan to drill at
least six exploration wells in 2004.
8
EXPLORATION BLOCKS
BLOCK 50
We successfully farmed out a portion of this block in 2002. Following completion
of the 2003 exploration program by the new partner, our interest was reduced to
33.337%. All commitments have been fulfilled and we plan to relinquish this
block in 2004.
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 60%
working interest in these blocks. We have evaluated these blocks and intend to
relinquish them in 2004.
WEST AFRICA
[GRAPHIC OMITTED]
[MAP]
ACREAGE
(thousand acres) Developed Undeveloped Total
- --------------------------------------------------------------------------------
Gross 1 1,630 1,631
Net 1 404 405
- --------------------------------------------------------------------------------
PROVED RESERVES
(mmbbls) Before Royalties After Royalties
- --------------------------------------------------------------------------------
Ejulebe Field -- --
- --------------------------------------------------------------------------------
2003 PRODUCTION
(mbbls/d) Before Royalties After Royalties
- --------------------------------------------------------------------------------
Ejulebe Field 2.2 1.6
- --------------------------------------------------------------------------------
Offshore West Africa, we have three projects underway, OPL-222 and OML-115,
offshore and Block K, offshore Equatorial Guinea. We also produce crude
oil offshore at Ejulebe on Block OML-109. Our strategy is to explore and
quickly develop our current portfolio. Our 2004 program for Nigeria includes
five exploration wells with the potential to deliver significant medium-term
growth.
NIGERIA
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 (floating
production storage and off-loading vessel) 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.
We expect the Ejulebe field to produce its final barrel of crude oil in early
2004. Abandonment will commence upon receipt of government approval. Since
government approval for field decommissioning in Nigeria is in the early stages
of development, official approval may take some time. No capital expenditures
are proposed for 2004.
BLOCK OPL-222
In 1998, we acquired a 20% interest in Block OPL-222, which includes 448,000
acres and is located approximately 80 km offshore in water depths ranging from
600 to 3,500 feet. Elf Petroleum Nigeria Limited, a subsidiary of Total, is the
operator. The ongoing appraisal of the block indicates significant hydrocarbon
accumulations based on the drilling results outlined below:
o In 1998, the Ukot-1 exploration well encountered three oil-bearing
intervals and flowed at a restricted rate of 13,900 bbls per day from
two intervals.
o In 2002, the Usan-1 exploration well encountered several oil-bearing
intervals and one zone flowed at a restricted rate of 5,000 bbls per
day.
o In 2003, the Usan-2 well was drilled three km west of the discovery
well, Usan-1, and appraised an up-dip portion of the fault block.
o In 2003, Usan-3 was drilled approximately two km northwest of the
discovery well and appraised a separate fault block. One zone in the
well was production tested and produced 5,600 bbls of oil per day under
restricted flow conditions.
9
o In 2003, Ukot-2 was drilled 3.5 km south of Ukot-1 and was not flow
tested.
o In 2003, the Usan-4 appraisal well flow tested two zones. They flowed
at restricted rates of 4,400 and 6,300 bbls of oil per day.
Usan-4 confirmed the presence of commercial quantities of crude oil. The
operator has applied to convert the block's licence to an Oil Mining Lease which
gives 20 years to appraise, develop and produce the reserves. A field
development plan is being prepared for submission to the government.
Priority to date has focused on the Usan field. We plan additional exploration
drilling on OPL-222 in 2004. The partners are currently in the process of
determining which prospects will be drilled.
BLOCK OML-115
The Nigerian Government formally approved the Deed of Assignment for Block 115
in December 2003, which assigned us a 40% interest in the block. Under the terms
of our Joint Operating Agreement with Oriental Energy Resources Limited, we have
a 100% paying interest and are entitled to 90 - 95% of the revenues for an
initial ten-year period. Existing 3D seismic is currently being evaluated to
finalize our first exploration well location. In January 2004, we commenced a
410 km2 3D seismic program on the block. Additional prospects identified by this
program will be pursued in 2005.
EQUATORIAL GUINEA
In 2003, we acquired a 25% interest and became the operator of Block K, a
deep-water block located 100 km offshore Equatorial Guinea. We expect to
interpret existing 3D seismic and drill two exploration wells in 2004. This
program will meet all work commitments under the production sharing contract
prior to the end of the initial exploration period on June 1, 2005.
OTHER INTERNATIONAL
COLOMBIA
[GRAPHIC OMITTED]
[MAP]
ACREAGE
(thousand acres) Developed Undeveloped Total
- --------------------------------------------------------------------------------
Gross 1 909 910
Net -- 674 674
- --------------------------------------------------------------------------------
PROVED RESERVES
(mmbbls) Before Royalties After Royalties
- --------------------------------------------------------------------------------
Guando 10 10
- --------------------------------------------------------------------------------
2003 PRODUCTION
(mbbls/d) Before Royalties After Royalties
- --------------------------------------------------------------------------------
Guando 3.2 3.0
- --------------------------------------------------------------------------------
BOQUERON BLOCK - GUANDO
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, we have recovered our share of costs incurred on Ecopetrol's behalf
before they exercised their back-in right, from production.
Development drilling and a waterflood pilot program began in 2002 and continued
in 2003. Given the results from the pilot, a full-field waterflood program was
approved in 2003. With a full-field waterflood and 24 planned development wells,
we expect our share of production will grow to 4,900 bbls per day by the end of
2004.
Production from Guando is subject to a 5% to 25% royalty depending on daily
production levels. The corporate income tax rate is 38.5%.
10
EXPLORATION BLOCKS
Exploration activities in Colombia are focused on assessing potential drilling
opportunities on captured blocks. In addition to Boqueron, we have interests in
four exploration blocks in the Upper Magdalena Basin. Villarrica was acquired in
2000, Andino in 2002, El Queso in 2003 and Boqueron Deep in 2003.
BLOCK INTEREST (%) 2003 ACTIVITY
- --------------------------------------------------------------------------------
Boqueron Deep 40 Signed the block in 2003
Villarrica 50 Interpreted seismic and submitted environmental
impact assessment
El Descanso 50 Relinquished the block
Andino 100 Drilled Andino-1 exploration well and evaluated
50 km of seismic
Muisca 100 Relinquished the block
El Queso 100 Signed the block in 2003 and evaluated 71 km of
seismic
The fiscal policy structure in Colombia is being revised to make the terms
competitive in the world market. The revised terms are to be finalized in early
2004 and the El Queso block will have the option to use the new terms. Boqueron
Deep has favourable terms, whereby Ecopetrol retains the right to back-in at the
declaration of commerciality for a 30% interest. The exploration commitments
have been completed for the current phase on all blocks except for Boqueron
Deep. A decision to renew or relinquish the blocks will be made by mid-2004.
At Andino, an exploration well was drilled in October 2003, which tested wet and
was abandoned. A 50 km 2D seismic program was also completed in 2003. The El
Queso Block, which we acquired in 2003, is highly prospective with eight leads
identified. We have completed a 71 km seismic program and will be evaluating the
data to determine our future plans on this block.
AUSTRALIA
[GRAPHIC OMITTED]
[MAP]
ACREAGE
(thousand acres) Developed Undeveloped Total
- --------------------------------------------------------------------------------
Gross 1 -- 1
Net 1 -- 1
- --------------------------------------------------------------------------------
PROVED RESERVES
(mmbbls) Before Royalties After Royalties
- --------------------------------------------------------------------------------
Buffalo Field 1 1
- --------------------------------------------------------------------------------
2003 PRODUCTION
(mbbls/d) Before Royalties After Royalties
- --------------------------------------------------------------------------------
Buffalo Field 6.1 5.6
- --------------------------------------------------------------------------------
BUFFALO
The Buffalo field located offshore on the northwest shelf of Australia has been
an excellent project. 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 allowed us to maximize our reserve recovery and to add incremental
recoverable reserves.
We expect to produce our final barrel of crude oil in late 2004. The final date
of production will be determined by the economics of the field as we continue to
maximize the remaining value through cost-effective operations. No capital
expenditures are expected in 2004. Field abandonment is scheduled to begin in
the fourth quarter of 2004 and finish by the end of 2005.
11
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%.
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. The first well in a
two-well drilling commitment was drilled in late 2002 and the second in 2003. We
encountered no economic hydrocarbons. This farm-in provided us with a strategic
entry into Brazil and has enabled us to build on our offshore knowledge in an
under-explored basin. We continue to evaluate our opportunities in this basin.
WESTERN CANADA
[GRAPHIC OMITTED]
[MAP]
ACREAGE
(thousand acres) Developed Undeveloped Total
- --------------------------------------------------------------------------------
Gross 902 2,511 3,413
Net 705 1,417 2,122
- --------------------------------------------------------------------------------
PROVED RESERVES Before Royalties After Royalties
- --------------------------------------------------------------------------------
Crude Oil and NGLs
(mmbbls) 119 101
Natural Gas (bcf) 470 405
- --------------------------------------------------------------------------------
Total (mmboe) 197 169
2003 PRODUCTION Before Royalties After Royalties
- --------------------------------------------------------------------------------
Light Oil (mbbls/d) 20.1 15.0
Heavy Oil (mbbls/d) 26.2 20.4
Natural Gas (mmcf/d) 158 125
- --------------------------------------------------------------------------------
Total (mboe/d) 72.6 56.2
- --------------------------------------------------------------------------------
Our strategy in western 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.
Additionally, we are advancing three promising initiatives for future growth in
western Canada: gas exploration, coal bed methane development and enhanced
recovery technology. Our exploration program targets high productivity deep gas
plays in the foothills of Alberta where we have production operations. We have a
coal bed methane extraction pilot in central Alberta, and we are actively
testing enhanced oil recovery techniques on our heavy oil fields.
LIGHT OIL
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 2003, we produced our eight millionth barrel from the field
and drilled 23 wells to increase productivity at low cost. In 2004, we will add
17 producing development wells to further exploit the existing pool and drill
five vertical wells to test the pool boundaries.
We also produce light oil in southeast Saskatchewan. Our operations in the area
are characterized by mature fields producing medium depth, Mississippian age
light oil. In 2003, we drilled 19 development wells on our light oil properties.
We also sold land holdings in the area during the year producing approximately
9,000 bbls of oil per day (7,000 bbls, net to us) for approximately $30,000 per
daily flowing barrel, realizing $268 million of net proceeds from the
transaction.
HEAVY OIL
There are a significant number of large heavy oil fields in western Canada.
Typically, finding and development costs for heavy oil are lower than 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.
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.
12
Our heavy oil operations are located in west central Saskatchewan. A strong
focus on managing 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 2003, a total of 54 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.
ENHANCED OIL RECOVERY
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 currently researching the use of solvent mixtures of
hydrocarbon gases to enhance our heavy oil recovery. Early field test results at
our Plover Lake field are encouraging.
NATURAL GAS
Our natural gas is primarily produced from shallow sweet assets in Alberta and
Saskatchewan, and from deep sour gas near Calgary and in the foothills of
Alberta.
Approximately 48% of our natural gas production comes from shallow low
permeability 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. We also have sweet gas operations from shallow high
permeability sands in northwest Saskatchewan. This is a mature area comprising
26% of our natural gas production. Our shallow gas properties provide production
and consistent returns as they approach full development, and will continue to
do so for years to come. During 2003, we drilled 78 shallow gas development
wells.
Our Balzac field produces 13% of our natural gas and we process it through our
Balzac plant, northeast of Calgary. The Balzac area has been in operation since
1961 and is characterized by long life reserves and consistent cash flows.
During the year, we drilled three development wells on our Balzac property.
The balance of our natural gas production comes from the Findley properties in
the Alberta foothills and gas production associated with oil wells.
Future growth in natural gas will come from gas exploration prospects in the
foothills of Alberta and Montana, and from the development of coal bed methane.
GAS EXPLORATION
In 2004, our gas exploration will concentrate on the foothills of west central
Alberta. In northeast British Columbia we are working to farmout out our
prospective acreage. At Lochend, located just outside Calgary, public
consultation for the drilling of a deep exploratory well will continue in 2004.
Our core foothills area is anchored by the producing Findley field where we
actively drilled for new reserves in 2003. We drilled five wells in the year,
the best of which flowed 8.5 mmcf/d (gross). Development drilling will continue
into 2004 along with facility expansion to handle the extra volume. In this
trend we have been able to assemble a good undeveloped land base and we plan to
drill three exploratory wells in 2004 to test multiple targets.
COAL BED METHANE
Coal bed methane (CBM) is becoming a significant gas resource in Canada. CBM is
commonly referred to as an unconventional form of natural gas because it is
primarily stored through absorption to the coal itself rather than in the pore
space of the rock, like most conventional gas. The gas is released in response
to a drop in pressure in the coal. If the coal is water saturated, water will
need to be extracted to initially reduce the pressure and allow gas production
to occur. If the coal is gas saturated, little or no water will be produced, and
gas will be produced from the onset of production. Typical water saturated CBM
wells show increasing gas production rates for a period of generally one to
three years before rates begin to decline. Although CBM production comprises
approximately 8% of the total domestic gas production in the United States,
Canadian CBM production is estimated to be only producing approximately 20 to 25
mmcf/d, or less than 0.2% of current gas production. The National Energy Board
forecasts that CBM production in Canada could be as much as 3 bcf/d by 2025.
Our CBM project at Corbett is still in the pilot phase and results are largely
meeting our expectations. We are partnered on this project with an experienced
US CBM operator. In 2003, we added 114 sections at 100% working interest of
prospective lands along the Corbett trend, increasing our total CBM land
position in this area to over 240 net sections. We are currently expanding our
pilot operation at Corbett from 15 to 49 producing wells. We plan to decide on
commerciality by the end of 2004. Outside of Corbett, we have established a
foothold in four other prospective CBM areas.
13
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%.
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. In 2003, legislation was introduced to
reduce the general federal corporate income tax rate on income from Canadian oil
and gas activities from 28% to 21% over a five-year period (2003-2007). The
federal capital tax rate is 0.225%. This tax is to be repealed by 2008 through a
combination of rate reductions and an increased exemption. Provincial capital
tax rates vary from 0.15% to 0.60%. Canadian entities are also subject to
capital taxes.
ATHABASCA OIL SANDS
A key part of Nexen's strategy is the economic development of our bitumen
resource to provide low risk, stable future growth. World events in the last
three years have highlighted the need to develop stable oil resources in various
areas of the world. The bitumen resource in northern Alberta has a significant
role to play in providing this stability.
The US Geological Survey now recognizes bitumen as reserves. It is estimated
that there are over 300 billion barrels of recoverable bitumen in northern
Alberta. 20% of this resource is recoverable by way of surface mining. The
remaining 80% is too deep for surfacing mining recovery and requires Steam
Assisted Gravity Drainage (SAGD) technology.
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. We are in the development stage of our synthetic
crude oil project at Long Lake.
SYNCRUDE
[GRAPHIC OMITTED]
[MAP]
ACREAGE
(thousand acres) Developed Undeveloped Total
- --------------------------------------------------------------------------------
Gross 117 141 258
Net 9 10 19
- --------------------------------------------------------------------------------
PROVED RESERVES
(mmbbls) Before Royalties After Royalties
- --------------------------------------------------------------------------------
285 248
- --------------------------------------------------------------------------------
2003 PRODUCTION
(mbbls/d) Before Royalties After Royalties
- --------------------------------------------------------------------------------
15.3 15.2
- --------------------------------------------------------------------------------
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 (10, 12, 17, 22, 29, 30, 31, 34)
spanning 258,000 acres north of Fort McMurray, Alberta. Since start-up in 1978,
Syncrude has produced nearly 1.5 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 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.
14
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.
EXPANSION
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 (17,820 barrels net) 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) in 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 ($296 million net) to $5.7 billion ($412 million net). Activities in
2004 will focus on completing the upgrader expansion and replacing bitumen
production capacity that will be lost with the mined-out southwest quadrant of
the Mildred Lake Base Mine in 2005.
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.
LONG LAKE SYNTHETIC CRUDE
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).
OPTI JOINT VENTURE
[GRAPHIC OMITTED]
[MAP]
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 patented OrCrude(TM) technology licensed to OPTI. As
part of the agreement, Nexen acquired the exclusive right with OPTI to use the
technology within 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 using this technology will be
comparable to those of surface mining and coking 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.
15
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 granted regulatory approval
in 2003. We are the operator of the Long Lake lease and are responsible for
construction, development and operation of the SAGD project, while OPTI is
responsible for the design, construction and operation of the upgrader.
The Long Lake SAGD and upgrader project will develop approximately 10% of our
Athabasca bitumen resource and will upgrade the bitumen into a high quality,
light, sweet synthetic crude oil. To optimize the project's well design, a
three-well pair SAGD pilot capable of producing 3,000 barrels per day of bitumen
was completed and commissioned. Wells were transitioned from the warm-up phase
to SAGD production to reach 1,500 bbls per day (gross) by year-end as we
expected.
On February 12, 2004, our Board of Directors approved proceeding with commercial
development of the Long Lake SAGD and upgrader project and as a result we have
booked 200 million barrels of new proved reserves in 2004. Field construction
work is expected to begin in 2004. Commercial production of bitumen is expected
in the second half of 2006 with synthetic crude oil production expected in 2007.
Peak production will reach 60,000 bbls per day (gross) of synthetic crude oil
and is expected to be maintained over the project's 35 plus year life. We expect
the gross capital cost to construct the Long Lake project to total $3.4 billion
($1.7 billion, net to us). Ongoing sustaining capital is expected to average
$2.50 per barrel. The project will generate its own fuel and electricity,
resulting in significant operating cost savings when compared to other bitumen
production and upgrading projects. Operating costs are expected to average $7 -
$9 per barrel. Assuming WTI oil prices average in the US$ mid-twenties per
barrel, the project will generate returns in the low to mid-teens.
RESERVES, PRODUCTION AND RELATED INFORMATION
In addition to the tables below, we refer you to the Supplementary Data in Item
8 of 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 FROM CONTINUING OPERATIONS
(Cdn$ millions) 2003 2002 2001
- -----------------------------------------------------------------------------------------
Conventional Crude Oil and Natural Gas Liquids 1,654 1,539 1,328
Synthetic Crude Oil 240 245 225
Natural Gas 618 345 494
-----------------------------------------
2,512 2,129 2,047
=========================================
Crude oil and natural gas liquids represent approximately 75% of oil and gas
sales, while natural gas represents the remaining 25%.
SALES PRICES AND PRODUCTION COSTS
(Based on working interest production after royalties)
AVERAGE SALES PRICE (1) AVERAGE PRODUCTION COSTS (1)
- ------------------------------------------------------------------------ ---------------------------------------------
2003 2002 2001 2003 2002 2001
---------------------------------------- ---------------------------------------------
Crude Oil and NGLs (Cdn$/bbl)
Yemen 39.45 38.80 35.05 4.37 4.13 3.47
Canada (2) 32.37 31.13 24.86 10.00 8.98 7.90
United States 37.68 38.88 38.35 5.08 10.95 7.24
Australia 43.14 40.30 38.71 20.21 12.14 14.38
Other Countries 38.22 38.96 37.35 9.01 10.69 9.94
Synthetic Crude Oil 43.36 40.89 39.90 22.18 18.21 20.29
Corporate Average 38.04 37.13 33.10 8.43 8.72 7.65
Natural Gas (Cdn$/mcf)
Canada (2) 5.64 3.57 5.02 0.65 0.70 0.54
United States 8.16 5.29 6.66 0.89 1.83 1.21
Corporate Average 6.85 4.25 5.69 0.75 1.10 0.81
Note:
(1) Prices and unit production costs are calculated using our working interest
production after royalties.
(2) Includes results of discontinued operations (See Note 9 of our Consolidated
Financial Statements.)
16
PRODUCING OIL AND GAS WELLS
(number of wells) 2003
- -------------------------------------------------------------------------------------------------------------------------------
OIL GAS TOTAL
---------------------------- --------------------------- ----------------------------
Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)
United States 192 86 200 120 392 206
Yemen 332 173 -- -- 332 173
Nigeria 2 2 -- -- 2 2
Canada 2,672 1,928 2,484 2,174 5,156 4,102
Colombia 51 11 -- -- 51 11
Australia 3 3 -- -- 3 3
---------------------------- --------------------------- ----------------------------
Total 3,252 2,203 2,684 2,294 5,936 4,497
============================ =========================== ============================
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) 2003
- ---------------------------------- --------------------------------------------------------------------------------------------
DEVELOPED UNDEVELOPED (1) TOTAL
---------------------------- --------------------------- ----------------------------
Gross Net Gross Net Gross Net
United States 191 105 886 436 1,077 541
Yemen (2) 44 23 19,547 9,798 19,591 9,821
Nigeria (2),(3),(4) 1 1 524 128 525 129
Equatorial Guinea -- -- 1,106 276 1,106 276
Canada 902 705 2,511 1,417 3,413 2,122
Colombia (5) 1 -- 909 674 910 674
Brazil -- -- 509 102 509 102
Australia 1 1 -- -- 1 1
---------------------------- --------------------------- ----------------------------
Conventional Total 1,140 835 25,992 12,831 27,132 13,666
============================ =========================== ============================
Syncrude 117 9 141 10 258 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 a joint venture agreement.
(5) The acreage is covered by an association contract.
17
DRILLING ACTIVITY
(number of net wells) 2003
- -------------------------------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
-------------------------------------- ------------------------------------------
Productive Dry Holes Total Productive Dry Holes Total Total
United States -- 0.5 0.5 8.3 0.1 8.4 8.9
Yemen 8.0 1.0 9.0 49.0 -- 49.0 58.0
Nigeria 0.6 -- 0.6 -- -- -- 0.6
Canada 15.4 1.7 17.1 157.7 2.5 160.2 177.3
Colombia -- 1.0 1.0 6.2 -- 6.2 7.2
Brazil -- 0.2 0.2 -- -- -- 0.2
-------------------------------------- --------------------------------------------------------
Total 24.0 4.4 28.4 221.2 2.6 223.8 252.2
====================================== ========================================================
2002
- -------------------------------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
-------------------------------------- ------------------------------------------
Productive Dry Holes Total Productive Dry Holes Total Total
United States -- 1.4 1.4 14.9 0.6 15.5 16.9
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
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
United States 3.8 1.2 5.0 5.3 -- 5.3 10.3
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
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
====================================== ========================================================
Note:
(1) Other countries include drilling primarily in Nigeria, Colombia and Brazil.
WELLS IN PROGRESS
At December 31, 2003, we were in the process of drilling three wells (1.6 net)
in the United States, nine wells (7.3 net) in Canada, and five wells in Yemen
(3.0 net).
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 power
marketing. We have offices in Calgary, Houston, Denver, Detroit, and Singapore
to service our primary markets.
The oil and gas areas are involved in the purchase, transport, storage and sale
of oil or natural gas from the point of production to end-use customers. Related
to this, our marketing operation 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 and storage
commitments for ourselves as well as third-party clients. These management
arrangements help optimize our energy trading activities. We also trade on
active markets such as the New York Mercantile Exchange and the International
Petroleum Exchange as part of our total portfolio.
18
Power marketing is involved in power production and marketing power to larger
commercial, industrial and municipal clients within Alberta. It is responsible
for optimizing the use of Nexen's power generation facility at Balzac, Alberta.
This facility began operations during the fourth quarter of 2001.
CHEMICALS OPERATIONS
AVERAGE ANNUAL PRODUCTION CAPACITY 2003 2002 2001
- --------------------------------------------------------------------------------
Sodium Chlorate (short-tons)
North America 432,812 500,650 474,250
Brazil 70,213 57,320 42,550
- --------------------------------------------------------------------------------
Total 503,025 557,970 516,800
- --------------------------------------------------------------------------------
Chlor-alkali (short-tons)
North America 356,002 351,844 351,844
Brazil 109,430 97,462 90,078
- --------------------------------------------------------------------------------
Total 465,432 449,306 441,922
- --------------------------------------------------------------------------------
Our global strategy is to add value by enhancing our cost position, maintaining
our market share, building a strong sustainable customer base in North America
and by capturing new opportunities offshore. Over the past four 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 sodium
chlorate and chlor-alkali products (chlorine, caustic soda and muriatic acid) in
Canada and Brazil for distribution in those countries and the US. We also market
a small amount of sodium chlorate in Asia.
The key factors for marketing bleaching chemicals are reliability of supply and
price. Our manufacturing facilities are modern, reliable, and strategically
located to capitalize on competitive power costs or 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.
NORTH AMERICA
[GRAPHIC OMITTED]
[MAP]
We manufacture sodium chlorate at five facilities in North America: Nanaimo,
British Columbia; Bruderheim, Alberta; Brandon, Manitoba; Amherstburg, Ontario;
and Beauharnois, Quebec. We also manufacture chlor-alkali products at North
Vancouver, British Columbia.
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 28% 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 Brandon, Manitoba plant is one of the lowest cost sodium chlorate
facilities in the industry. We are currently expanding this facility by 33% to
260,000 tonnes per year to replace higher cost capacity idled in 2002 at Taft,
Louisiana. When complete in the fourth quarter of 2004, this expansion will make
Brandon the largest sodium chlorate facility in the world, significantly
enhancing our competitive position in North America. In 2002, we idled our Taft,
Louisiana plant due to high operating costs and in 2003 we transferred those
assets to Brandon as part of the new expansion. Sodium chlorate production
capacity in North America decreased in 2003 as a result of this idling. Capacity
will increase in the fourth quarter of 2004 once our Brandon expansion is
complete.
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.
19
BRAZIL
[GRAPHIC OMITTED]
[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.
This expanded the chlorate production capacity by 70% and the chlor-alkali
capacity by 35%.
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. 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.
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.
20
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 which empowers the Minister of Petroleum Resources to make
regulations for the prevention of pollution of water sources and the atmosphere.
In 1981, the Department of Petroleum Resources (DPR) issued interim guidelines
concerning the monitoring, handling, treatment, and disposal of effluents, oil
spills and chemicals, drilling muds and cuttings by leases/oil operators.
Tentative allowable limits of waste discharges into fresh water, coastal waters
and offshore areas of operations were established. The guidelines were updated
in 2002 as the Environmental Guidelines and Standards for the Petroleum Industry
in Nigeria (EGASPIN).
In November 1999, the Federal Ministry of the Environment (FME) 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 DPR and the defunct Federal Environmental Protection
Agency. The timing and implications of these changes have yet to be determined.
Accordingly, approvals are usually required from the DPR and the FME for all
aspects of environmental management of the oil and gas industry.
AUSTRALIA
In Australia, the offshore petroleum industry is regulated by two environmental
regimes: firstly, broadly consistent, petroleum industry specific, Federal
(Commonwealth) and State/Territory legislation; and secondly, a non-industry
specific, Federal regime.
The States and Northern Territory have jurisdiction over their 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 (P(SL)A). The main
environmental regulations are the P(SL)A Management of Environment regulations,
1999, and the Dept of Environment & Heritage, (DEH), (formerly Environment
Australia), Environment Protection, Biodiversity, & Conservation (EPBC) Act. In
July of 2000, the EPBC Act became law. The EPBC Act requires separate
documentation to that required under the P(SL)A, and while the two Acts have
similar objectives, the processes are quite different.
Under the EPBC 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.
Under the P(SL)A, there are two administrative decision-making bodies in respect
of each offshore area; a Joint Authority, (which is the principal
decision-making body), comprising the Commonwealth Minister responsible for
resources, and the equivalent State or Northern Territory Minister, and a
Designated Authority, which handles the day-to-day administrative matters
relating to petroleum activities in the defined area. Titleholders under the
P(SL)A are responsible for all petroleum related activities (including safety &
environment matters) in the permit/licence area. The designated representative
of the titleholder is the operator.
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 four months and two 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 the issuance of hydrocarbon licenses
have resulted in some process improvements.
21
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 Alberta Energy and Utilities Board (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 has been extended beyond the original
10-year period such that it now expires December 31, 2006, and is a consolidated
document covering air, land, water, and waste management matters. Land
reclamation is proceeding at a rate of approximately 270 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. Our
chemicals facilities 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 (CHLOREP). 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 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
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(R) of Practice, with implementation scheduled
for completion in 2004.
For a discussion of the remediation of the site at Squamish, B.C., see the Legal
Proceedings section in Item 3.
OTHER ACTIVITIES
Our Balzac gas plant and power generation facility received Round 1 Responsible
Care(R) verification in 2002. This is the first oil and gas plant in the world
to implement Responsible Care(R) - an initiative originally found only in
chemical facilities.
22
ENVIRONMENTAL PROVISIONS AND EXPENDITURES
At December 31, 2003, $197 million has been provided in the accounts for future
dismantlement and site restoration costs, which are currently estimated at
approximately $514 million for all of our oil and gas and chemicals facilities.
During 2003, we recorded a provision for future dismantlement and site
restoration costs of $38 million.
During 2003, our capital expenditures for environmental-related matters,
including environment control facilities, were approximately $21 million. Our
operating expenditures for environmental-related matters were approximately $6
million. Environmental related capital expenditures in 2004 are expected to be
similar to 2003.
EMPLOYEES
We had 2,875 employees on December 31, 2003.
Information on our executive officers is presented in Item 10 of this report.
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
believes it has made adequate provisions for such lawsuits and claims.
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 as the land has been remediated and we have submitted a final report.
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.
A subsidiary of Occidental Petroleum Corporation (Occidental) has initiated a
request for arbitration at the International Court of Arbitration of the
International Chamber of Commerce regarding an Area of Mutual Interest Agreement
(Agreement) in the Republic of Yemen. Pursuant to the Agreement, if Nexen
proposed to conduct petroleum development operations within two small areas of
Block 51 in the Republic of Yemen (Heijah/Tawila Extension Lands), then we were
to offer Occidental the right to acquire 50% of its interest in those areas. The
Agreement expired on March 12, 2003, with Nexen not having proposed any such
operations. Occidental seeks a claim for declaratory relief under the Agreement,
claims compensation for breach of contract (50% of the net profits earned or to
be earned from the Heijah/Tawila Extension Lands), plus interest and costs.
Since the expiry of the Agreement, we commenced exploration activities within
Block 51, including the Heijah/Tawila Extension Lands and, in December 2003,
filed a notice of commercial discovery with the Yemen government. Given that the
agreement expired without Nexen having proposed to conduct petroleum development
operations, we believe Occidental's claim is without merit and we intend to
vigorously defend our contractual rights.
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 2003.
23
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, 2003, there were 1,420 registered holders of common shares and
125,606,107 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
($/share) TORONTO STOCK EXCHANGE NEW YORK STOCK EXCHANGE
- -------------------------------------------------------------------------------------------------------
HIGH LOW HIGH LOW
(Cdn $) (US $)
2003
First Quarter 34.85 29.30 22.55 19.89
Second Quarter 35.59 28.26 26.31 19.75
Third Quarter 39.68 33.02 29.00 24.03
Fourth Quarter 47.08 36.65 36.47 27.32
2002
First Quarter 39.75 29.70 25.11 18.57
Second Quarter 42.50 37.20 28.04 23.30
Third Quarter 42.18 34.34 27.71 21.70
Fourth Quarter 37.78 31.00 23.85 19.79
----------------------------------------------------------------
QUARTERLY DIVIDENDS ON COMMON SHARES FIRST SECOND THIRD FOURTH
($/share) QUARTER QUARTER QUARTER QUARTER
- -------------------------------------------------- ---------------- -- --------------- ----------------
2003 0.075 0.075 0.075 0.100
2002 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.
24
ITEM 6. SELECTED FINANCIAL DATA
FIVE YEAR SUMMARY OF SELECTED FINANCIAL DATA IN ACCORDANCE WITH US GAAP
(Cdn$ millions) 2003 2002 2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS
Net Sales (1) 2,908 2,506 2,497 1,533 1,411
Net Income from Continuing Operations 475 338 348 493 62
Basic Earnings per Common Share
from Continuing Operations ($/share) 3.83 2.77 2.89 3.94 0.45
Diluted Earnings per Common Share
from Continuing Operations ($/share) 3.80 2.73 2.85 3.88 0.45
Net Income 420 352 365 522 63
Basic Earnings per Common Share ($/share) 3.39 2.88 3.03 4.17 0.46
Diluted Earnings per Common Share ($/share) 3.36 2.84 2.99 4.12 0.46
Production - Before Royalties (mboe/d) (2) 269 269 268 256 239
Production - After Royalties (mboe/d) (2) 185 176 184 171 163
FINANCIAL POSITION
Total Assets (2) 7,703 6,764 5,609 5,874 4,922
Long-Term Debt (3), (4) 2,472 2,575 2,242 2,238 1,997
Shareholders' Equity 2,131 1,812 1,414 1,050 1,130
Capital Expenditures 1,494 1,625 1,404 915 612
Dividends per Common Share ($/share) (5) 0.325 0.30 0.30 0.30 0.30
Common Shares Outstanding (thousands) (6) 125,606 122,966 121,202 119,855 138,145
------- ------- ------- ------- -------
Notes:
(1) During 2003, we sold non-core conventional light oil assets in southeast
Saskatchewan in Canada producing 9,000 bbls/d. The results of these
operations are shown as discontinued operations as described in Note 9 of
our Consolidated Financial Statements.
(2) 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. In
2003, production increased from our deep-water Aspen development in the
Gulf of Mexico in the US.
(3) In February 2004, $575 million of Long-Tem Debt was repaid. At December 31,
2003, this amount was included in the current portion of Long-Term Debt on
the balance sheet.
(4) Under US GAAP, our Long-Term Debt, net of working capital, of $1,662
decreased by $848 million during 2003.
(5) Quarterly dividends were increased to 10(cent)in the fourth quarter of
2003.
(6) During 2000, we entered into an agreement to repurchase 20 million Nexen
common shares.
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
TABLE OF CONTENTS
PAGE
Executive Summary of 2003 Results...........................................27
Capital Investment..........................................................29
2003 Capital.........................................................30
2004 Estimated Capital...............................................30
Financial Results
Year to Year Change in Net Income....................................33
Oil and Gas
Production .................................................34
Commodity Prices.............................................36
Operating Costs..............................................38
Depreciation, Depletion and Amortization.....................39
Exploration Expense..........................................40
Oil and Gas Marketing................................................40
Chemicals............................................................43
Corporate Expenses...................................................44
Outlook for 2004............................................................45
Liquidity...................................................................46
Contingencies...............................................................50
Business Risk Management....................................................51
Market Risk Management......................................................54
Critical Accounting Estimates...............................................56
New Accounting Pronouncements...............................................58
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. OUR
DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND
GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON A WORKING
INTEREST BEFORE ROYALTIES BASIS. WE MEASURE OUR PERFORMANCE IN THIS MANNER
CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. WHERE APPROPRIATE, WE HAVE
PROVIDED INFORMATION ON AN AFTER-ROYALTY BASIS IN TABULAR FORMAT.
NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 60 WHICH HIGHLIGHTS DIFFERENCES BETWEEN OUR RESERVE ESTIMATES AND RELATED
DISCLOSURES THAT ARE OTHERWISE REQUIRED BY CANADIAN REGULATORY AUTHORITIES.
26
EXECUTIVE SUMMARY OF 2003 RESULTS
(Cdn$ millions) 2003 2002 2001
- -------------------------------------------------------------------------------
Net Income 639 452 450
Earnings per Common Share ($/share) 4.84 3.34 3.40
Cash Flow from Operations (1) 1,859 1,383 1,423
Production, before royalties (mboe/d) (2) 269 269 268
Production, after royalties (mboe/d) 185 176 184
Capital Expenditures 1,494 1,625 1,404
Proved Reserve Additions, net (mmboe) (2) 38 126 131
Finding and Development Costs ($/boe) (3) 11.64 12.41 9.24
Net Debt (4) 1,377 1,775 1,460
Net Debt to Cash Flow (times) (5) 0.8 1.4 1.1
-----------------------------
We achieved record financial results in 2003. As the variance table on page 33
shows, the three biggest drivers impacting net income growth were higher-margin
volumes primarily in the US, strong oil and gas prices and exceptional marketing
results. A strengthening Canadian dollar and an impairment charge largely
attributable to heavy oil assets reduced these gains. Overall net income grew
41% over 2002 to $639 million and our cash flow from operations reached a record
$1.9 billion.
Crude oil prices remained strong in 2003 as supply and demand fundamentals
supported higher prices. Instability in the Middle East, growing demand and low
inventory levels kept average WTI at US$31.04/bbl. Natural gas prices peaked
during the first quarter of the year and again in December, tracking weather
patterns in the US. Our marketing group was positioned to take advantage of
these fluctuations, benefiting from price differences between the west and the
east, as well as between the summer and winter months.
The strengthening Canadian dollar relative to the US dollar reduced our net
income by $130 million and cash flow from operations by $250 million. This is
because our foreign revenues and realized commodity prices, referenced in US
dollars, were lower when translated to Canadian dollars. However, we benefit to
the extent that our foreign operating costs and capital expenditures are also
reduced when translated. In addition, most of our fixed-rate debt is denominated
in US dollars so this debt is reduced with a strengthening Canadian dollar.
As a result of certain negative reserve revisions in Canada, our net income
includes a non-cash impairment charge of $175 million, after-tax, of which
almost 90% relates to heavy oil reserves. The revisions resulted from changes to
late field-life economic assumptions, a reduction in proved undeveloped reserves
based on drilling results and geological mapping, and reassessments of expected
future production profiles. The reduction does not affect our production
forecast for 2004. Our Canadian oil and gas properties will continue to be a
significant source of free cash flow for future investment since the future
estimated cash flow from our total conventional Canadian assets is approximately
2.5 times their related carrying value.
- --------------------
(1) We evaluate our performance and that of our business segments based on
earnings and cash flow from operations. Cash flow from operations is a
non-GAAP term that represents cash generated from operating activities
before changes in non-cash working capital and other. We consider it a key
measure as it demonstrates our ability and the ability of our business
segments to generate the cash flow necessary to fund future growth through
capital investment and repay debt.
(Cdn$ millions) 2003 2002 2001
- --------------------------------------------------------------------------------
Cash Flow from Operating Activities 1,469 1,322 1,566
Changes in Non-Cash Working Capital 320 46 (143)
Other 70 15 --
----------------------------
Cash Flow from Operations 1,859 1,383 1,423
============================
(2) Production, before royalties 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. We have used our year-end pricing assumptions.
(3) Finding and Development Costs is defined as oil and gas exploration and
development expenditures divided by total proved reserves additions on a
before-royalties basis, prior to acquisitions, dispositions and revisions.
(4) Long-term debt less net working capital
(5) Net debt divided by cash flow from operations after dividends on Preferred
Securities.
27
High-margin barrels from Aspen and now Gunnison replaced declining production in
North America and at Buffalo, offshore Australia and Ejulebe, offshore Nigeria -
both of which will be fully depleted in 2004. Canada's production was reduced
mid-year as we disposed of 9,000 boe/d of non-core light oil properties in
southeast Saskatchewan. The revenues and expenses associated with these disposed
properties are segregated as discontinued operations in our financial
statements. The shift from low-margin production in maturing areas to
high-margin production in new growth areas grew overall production after
royalties by 5% despite flat production before royalties. In 2004, we expect
production before royalties to average between 255,000 and 275,000 boe.
Production after royalties will continue to grow with more low-royalty volumes
from Gunnison and Aspen.
In 2003, we continued our strategy of growing long-term value primarily through
grassroots exploration and development. We focused on maximizing returns from
our capital investment program growing value beyond simply adding production
volumes. Targeting higher returns, we have shifted our capital investment away
from higher-cost, maturing North American conventional production into four key
basins with significant growth projects as described in Item 1 of this 10-K.
Below are highlights of our strategic progress in 2003:
One-third of our total $1.5 billion capital budget was invested in the Gulf of
Mexico, now our largest cash flow contributor. We advanced our deep-water
strategy in 2003 by acquiring the remaining 40% interest in Aspen and becoming
operator of our first deep-water project. Aspen's low cost and low royalty
production generated cash netbacks of US$23 per boe, nearly twice our corporate
average. We added to Aspen's high-margin production by bringing our second
deep-water project, Gunnison, on stream ahead of schedule in December 2003.
Production is ramping up at Gunnison through 2004 and we expect to tie-in a
third development well at Aspen, adding to our improving margins. Exploration
continues in 2004 on acreage in the Aspen and Gunnison areas, the eastern Gulf
and the shelf deep-gas trend.
In 2003, we invested $253 million in the Middle East: 87% on development and
exploitation at Masila and the remainder on exploration on Block 51, adjacent to
Masila, and in northern Yemen. Activities at Masila were focussed on maintaining
existing production rates. Extensions to Masila's Heijah and Tawila fields and
appraisal of Block 51 discoveries contributed 63 mmboe of proved reserves in
2003. In 2004, we plan additional delineation drilling on Block 51 to establish
even more reserves. With new production from Block 51 planned for 2005, we
expect to maintain strong production rates from Yemen for several years.
We invested $57 million to continue building our presence offshore West Africa.
On Block 222, offshore Nigeria, three appraisal wells at Usan delivered very
good results. In addition, one appraisal well was drilled at Ukot. A development
plan is being prepared for submission to the Nigerian government. Exploration
will continue on this block as well as on OML-115, offshore Nigeria and Block K,
offshore Equatorial Guinea - both attractive new prospects we acquired during
2003. To date, we have not booked any proved reserves for our Block 222
discoveries. Proved reserves will be booked once commercial development is
approved.
Our $96 million investment in the Long Lake project in the Athabasca oil sands
allowed us to continue detailed engineering, implement a SAGD pilot, and obtain
regulatory approval for the commercial project in 2003. With Board sanctioning
of the commercial project in February 2004, we have booked 200 million of proved
reserves in 2004. Only 3 million barrels of proved reserves were booked in 2003
related to the SAGD pilot. Construction of commercial facilities will begin this
summer. In 2003, we also invested $173 million in Syncrude's Stage 3 expansion,
which together with base operations added 26 million barrels of proved reserves
at a cost of $7.38 per boe. We expect this expansion to be completed in 2005,
adding 8,000 barrels per day of new production to Nexen.
Beyond these four basins, capital was invested in our core assets in Canada and
the shallow-water Gulf, in Colombia and in our chemicals operations as we expand
our Brandon facility and transfer sodium chlorate capacity there from our Taft,
Louisiana plant. In Canada, our exploration and development programs in Canada
added 16 mmboe of conventional proved reserves.
Overall, we added 38 mmboe of net proved reserves as follows:
(mmboe)
- --------------------------------------------------------------------------------
Additions (Extensions and Discoveries) 111
Acquisitions (Aspen) 24
Dispositions (primarily southeast Saskatchewan) (30)
Revisions (primarily in Canada) (67)
--------------
38
==============
28
Additions of 111 mmboe of proved reserves replaced 113% of our production at a
finding and development (F&D) cost of $11.64 per boe. Our F&D costs have trended
upwards over the past few years given the long-lead times associated with our
new growth projects. These projects consume large amounts of capital and
mismatches are created in the timing of reserve recognition. Over their lives
these projects are expected to generate attractive returns and low full-cycle
F&D costs.
In 2003, we took steps to improve our liquidity and financial flexibility to
ensure we are able to fund our multi-year development projects. Record cash
flow, disposition proceeds and a strong Canadian dollar reduced net debt and
preferred securities by $758 million. Net debt and preferred securities at
year-end was 1.0 times cash flow. We also took advantage of the low interest
rate environment and issued US$960 million of public debt, enabling us to fund
debt maturities, retire our preferred securities and reduce future financing
costs.
Going forward, we are well positioned for growth. Our 2004 oil and gas capital
program of $1.7 billion will continue to support progress on our major
development projects and fund an active exploration program, half of which is
directed to US exploration. Strong commodity prices are likely to continue
partially offset by the impact of a strong Canadian dollar on our US-dollar
denominated revenues. Removing the impact of price and exchange rate
fluctuations, we expect our improving margins in the US to grow our cash flow
from operations by 10% year-over-year.
CAPITAL INVESTMENT
(Cdn$ millions) 2003 2002 2001
- -------------------------------------------------------------------------------
Capital Investment
New Growth Exploration 329 259 411
New Growth Development 358 626 110
Core Asset Development 589 592 641
Property Acquisition 164 4 122
--------------------------------
Total Oil & Gas 1,440 1,481 1,284
Chemicals, Marketing and Other 54 144 120
--------------------------------
Total 1,494 1,625 1,404
================================
Our capital programs are focused on maximizing returns on every dollar of
capital invested. Investment dollars are allocated between:
o core assets for short-term growth and free cash flow to fund ongoing
capital programs;
o development projects that convert our discoveries into new production
and cash flow; and
o exploration projects for longer-term growth.
Given our exploration success over the past several years, we have made
significant investments in major development projects in our four key basins. In
2001, we invested in new development projects at Aspen and Gunnison in the
deep-water Gulf of Mexico and Syncrude's Stage 3 expansion. In 2002, we
continued developing these projects and began scoping out our Long Lake project.
We also made discoveries at Usan offshore Nigeria. In 2003, the first of these
projects, Aspen came onstream. We converted the discoveries on Block 51 in Yemen
into a development project. Late in 2003, our second deep-water project at
Gunnison came onstream, with cash netbacks that are twice our corporate average.
While our deep-water Gulf investments are already contributing high-value
production, driving our corporate margins, our growth projects in the other
basins have yet to contribute production and cash flow. Most of these are
long-lead time projects, with three to five years between discovery and first
production. Although these large capital investments have yet to generate cash
flow, the capital invested is not at risk. Over their lives, these projects are
expected to generate attractive returns and low full-cycle finding and
development costs.
The results of our capital programs are detailed below.
29
2003 CAPITAL
In 2003, we invested over $1.4 billion in oil and gas with:
o 41% in core assets to maintain existing production levels;
o 36% in new growth development projects, and;
o 23% in new growth exploration projects.
(Cdn$ millions) Development Exploration Other Total
- ----------------------------------------------------------------------------------------------------------------
Oil and Gas
United States 249 147 164 560
Yemen 219 34 -- 253
Nigeria -- 35 -- 35
Canada 259 51 -- 310
Syncrude 195 -- -- 195
Other Countries 25 62 -- 87
------------------------------------------------------------------
947 329 164 1,440
Chemicals - - 24 24
Marketing, Corporate and Other - - 30 30
------------------------------------------------------------------
Total Capital 947 329 218 1,494
==================================================================
In 2004, we plan to invest almost $1.7 billion in oil and gas with:
o 35% in core assets to maintain existing production levels;
o 45% in new growth development projects, and;
o 20% in new growth exploration projects.
2004 ESTIMATED CAPITAL
(Cdn$ millions) Development Exploration Other Total
- ----------------------------------------------------------------------------------------------------------------
Oil and Gas
United States 175 158 -- 333
Yemen 397 23 -- 420
Nigeria 19 59 -- 78
Canada 130 52 -- 182
Long Lake Synthetic 391 9 -- 400
Syncrude 182 -- -- 182
Other Countries 17 60 -- 77
--------------- ----------------- --------------- ----------------
1,311 361 -- 1,672
Chemicals -- -- 53 53
Marketing, Corporate and Other -- -- 41 41
--------------- ----------------- --------------- ----------------
Total Capital 1,311 361 94 1,766
=============== ================= =============== ================
GULF OF MEXICO
ASPEN
Our deep-water Gulf of Mexico strategy began paying off in 2003. After bringing
Aspen on-stream in December 2002, a record 19 months after discovery, we
acquired the remaining 40% interest in March 2003 from BP for $164 million. With
100% interest in Aspen, we are now deep-water operators and control the timing
of future exploration and development on our acreage in the Greater Aspen area.
Aspen's production has low royalties and operating costs, resulting in
high-margin production that has already recovered approximately 55% of our
investment of US$374 million. A third development well is drilling at Aspen.
GUNNISON
In 2003, production from our second deep-water project at Gunnison, discovered
in 2000, came on-stream. Gunnison's SPAR production facility was completed and
moved from Finland to the Gulf mid-summer. We installed the remaining equipment
on the production platform, and completed and tied-in the subsea wells.
Production came on-stream in December 2003. Gunnison will deliver equally
attractive returns as Aspen, with its low royalties and operating costs.
30
EXPLORATION
In 2003, we drilled three exploration wells in the Gulf, including a deep-water
dry hole at Santa Rosa. Under our first exploration venture with Shell, we have
recently finished drilling the Shark prospect on the shelf in search of natural
gas in deep shelf sands. No commercial hydrocarbons were encountered and the
well is temporarily abandoned while we evaulate the data collected from the well
bore.
In 2003, we entered into a second exploration venture with Shell to jointly
explore a 1,116 square mile area of the deep-water eastern Gulf of Mexico. The
area includes 124 blocks located in Mississippi Canyon and Desoto Canyon. Under
this exploration venture, we drilled the Shiloh-1 well on Desoto Canyon 269 to a
total depth of over 24,000 feet. At Shiloh, we encountered hydrocarbons in
non-commercial quantities so the well was written off. We have acquired
additional acreage in the area and will continue drilling in hopes of proving-up
commercial quantities in the region.
In 2004, almost half our exploration capital will be invested in the Gulf of
Mexico. Our plans include five high-potential exploration wells: two deep shelf
gas prospects on the shelf, Crested Butte offsetting Aspen, a well in Garden
Banks, and another in the eastern Gulf of Mexico.
MIDDLE EAST
MASILA
Our primary focus at Masila is to maintain production rates. During 2003, we
invested $219 million to drill 94 development wells, construct new facilities,
increase water handling capabilities, and perform additional workovers to
maintain production rates. We plan to spend US$176 million in 2004 on
development projects in the Masila field to drill 90 wells and complete facility
enhancements to partially offset the field's natural decline.
BLOCK 51
In 2003, we enjoyed exploration success with discoveries in the Baishir al Khair
Field (BAK) at BAK-A (formerly Tammum) and BAK-B (formerly Amir). Seven
appraisal wells were drilled, encountering oil in the Qishn and Saar horizons,
and we began commercial development late in the year. Initial development
includes completing the seven wells drilled, ten new development wells, a
central processing facility, a gathering system and a tieback to our Masila
export system. Based on drilling results to date, we expect to develop in excess
of 60 million barrels of reserves and add between 20,000 and 25,000 barrels per
day of production capacity in early 2005. The field has additional potential
that will be quantified by a 3D seismic program and further delineation drilling
in 2004. We are continuing to explore the Block and plan to drill at least six
exploration wells in 2004.
EXPLORATION
In addition to Block 51, we drilled the Husan El Kradis (HEK-1R) exploration
well 25 kilometres northwest of BAK-B to test for oil in fractured basement;
however, the well was dry. Further exploration is planned in the area.
OFFSHORE WEST AFRICA
NIGERIA
In 2003, we focused on developing our Usan and Ukot discoveries on Block
OPL-222. We drilled three appraisal wells at Usan and announced a significant
extension of that field. An additional appraisal well at Ukot was also drilled.
The operator is preparing a field development plan for submission to the
Nigerian government for approval and we expect first production around 2008. In
2004, we plan additional exploration drilling to test the Block's remaining
potential.
In December 2003, as part of our initiative to expand our position in West
Africa, we were assigned an interest in OML-115 offshore Nigeria. We commenced a
program to acquire 410 km2 of 3D seismic data over the block and plan to drill
one exploration well in 2004.
EQUATORIAL GUINEA
We acquired a 25% interest in Block K located 100 km offshore. The Block is on
trend with the 300-million barrel Ceiba field and other discoveries on Block G
to the north. In 2004, we plan to drill two wells to assess Equatorial Guinea's
ability to contribute to the growth of our West Africa region.
31
ATHABASCA OIL SANDS
SYNCRUDE
In 2003, the Stage 3 expansion proceeded as expected. The Aurora 2 bitumen train
was completed and successfully placed in production. The upgrader expansion at
Mildred Lake is 35% complete, on-track for start-up in 2005. We expect the Stage
3 expansion to increase our share of production to over 25,000 barrels per day.
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 ($296 million net) to $5.7 billion ($412 million net). Activities in
2004 will also focus on replacing bitumen production capacity that will be lost
when the southwest quadrant of the Mildred Lake Base Mine is depleted.
SYNTHETIC OIL AT LONG LAKE
The Long Lake project is progressing rapidly. In 2003, we commenced pilot
testing of SAGD technology at Long Lake, obtained Alberta Energy Utilities Board
approval and completed more than 15% of the detailed engineering.
On February 12, 2004, our Board of Directors approved the Phase 1 commercial
development plan. The project will develop approximately 10% of our Athabasca
bitumen resource, upgrading this bitumen into high-quality light, sweet
synthetic crude oil. As a result of the approval, we have booked 200 million
barrels of proved reserves in 2004.
In 2004, we expect to continue with detailed engineering, order long-lead time
equipment and commence construction at Long Lake to meet a 2006 start-up date
for bitumen production and a 2007 start-up date for synthetic crude oil
production. Gross capital costs are expected to total $3.4 billion.
OTHER EXPLORATION AND CORE ASSET DEVELOPMENT
CANADA - CONVENTIONAL
As our conventional assets in Western Canada mature, we are focusing on projects
that provide the highest return on invested capital. In 2003, we sold over 9,000
barrels of daily production at attractive prices. We've also continued our
transition to new sources of production growth such as synthetic crude oil and
coal bed methane.
CANADA - EXPLORATION
We increased our coal bed methane (CBM) land holdings and proceeded with our
Corbett pilot, drilling 24 wells. In 2004, we will significantly expand the size
of our CBM pilot project at Corbett and expect to decide on commerciality by
year-end. We will test four other Upper Mannville CBM prospects and drill a
number of gas exploration well in the Alberta foothills.
COLOMBIA
In 2003, we drilled 31 development wells to increase production rates and test
the viability of a waterflood program on the Guando field. In 2004, we plan to
drill 24 development wells and implement a full-field waterflood at Guando.
We continued exploration in Colombia. One exploration well drilled on the Andino
Block tested wet and was abandoned.
CHEMICALS
During 2003, we focused on increasing reliability and cost reduction at all of
our manufacturing facilities. We also began relocating the assets from our Taft
facility in Louisiana to Brandon, Manitoba, the lowest-cost sodium chlorate
production facility in North America. In 2004, we expect to complete our Brandon
expansion including the relocation and installation of the Taft assets. Upon
completion of this expansion, the Brandon plant will be the largest sodium
chlorate plant in the world.
MARKETING, CORPORATE AND OTHER
Capital spending in 2003 and planned spending in 2004 includes systems
development, computer hardware and software, office equipment and leasehold
improvements.
32
FINANCIAL RESULTS
YEAR TO YEAR CHANGE IN NET INCOME
(Cdn$ millions) 2003 VS 2002 2002 VS 2001
- ------------------------------------------------------------------------------------------------
NET INCOME FOR 2002 AND 2001 452 450
============================
Favourable (unfavourable) variances:
Cash Items:
Production volumes, net of royalties:
Crude oil 92 30
Natural gas 41 (18)
Change in inventory - crude oil sales, net of royalties (25) --
Realized commodity prices:
Crude oil 41 183
Natural gas 234 (113)
Oil and gas operating expense:
Conventional 37 (63)
Synthetic (14) 5
Marketing contribution 96 (23)
Chemicals contribution (5) 1
General and administrative (38) (16)
Interest expense 4 3
Current income taxes 13 (7)
Other -- (22)
----------------------------
Total Cash Variance 476 (40)
Non-Cash Items:
Depreciation, depletion and amortization:
Oil and Gas (327) (80)
Other (5) (10)
Exploration expense (19) 79
Future income taxes 28 79
Other 34 (26)
----------------------------
Total Non-Cash Variance (289) 42
------------- --------------
NET INCOME FOR 2003 AND 2002 639 452
============================
Significant variances in net income are explained in the sections that follow.
33
OIL AND GAS
PRODUCTION
2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------------------
Before After Before After Before After
Royalties Royalties Royalties Royalties Royalties Royalties
-------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 116.8 57.5 118.0 55.8 118.3 55.5
Canada (1) 46.3 35.4 56.3 43.4 58.0 48.3
United States 28.3 25.0 9.9 8.2 10.0 8.3
Australia 6.1 5.6 12.8 10.3 10.2 9.6
Other Countries 5.4 4.6 8.9 5.2 6.2 5.3
Syncrude 15.3 15.2 16.6 16.5 16.1 15.5
-------------------------------------------------------------------------------------------
218.2 143.3 222.5 139.4 218.8 142.5
-------------------------------------------------------------------------------------------
Natural Gas (mmcf/d)
Canada (1) 158 125 167 128 174 147
United States 145 122 112 93 121 99
-------------------------------------------------------------------------------------------
303 247 279 221 295 246
-------------------------------------------------------------------------------------------
Total (mboe/d) 269 185 269 176 268 184
===========================================================================================
Notes:
(1) Includes the following production from discontinued operations. See Note 9
to our Consolidated Financial Statements.
(mboe/d) 2003 2002 2001
--------------------------------------------------------------------------
Production
Before Royalties 6.2 10.5 11.0
After Royalties 4.6 7.8 8.0
----------------------------
2003 VS 2002 - 5% PRODUCTION GROWTH
AFTER ROYALTIES ADDED $133 MILLION TO NET INCOME
Production after royalties grew 5%, with new low-royalty deep-water production
from Aspen and more recently Gunnison, and more cost recovery barrels from
Masila in Yemen. At Masila, we received a greater percentage of gross production
to recover costs we incurred on the government's behalf.
Production before royalties was flat compared to 2002 as growth in our US
deep-water production was partially offset by dispositions in Canada, expected
production declines offshore Nigeria and Australia, and maturing conventional
assets. We expect 2004 production before royalties to average between 255,000
and 275,000 boe - similar to 2003 levels. Production after royalties will
continue to grow with more low-royalty volumes from Gunnison and Aspen.
MASILA BLOCK IN YEMEN
Production before royalties decreased slightly in 2003 consistent with the
overall decline in the field's base production. As Masila matures, we continue
to drill more development wells, perform more workovers and expand our water
handling capacity to manage the declines. Late in 2003, our expanded drilling
and workover efforts successfully increased production to 120,000 barrels per
day (net to us).
While the field's total production decreased in 2003, our share of production
after royalties grew due to the cost recovery mechanism in our production
sharing contract. We are entitled to recover the costs we have incurred on the
government's behalf (up to a 40% limit) through additional production volumes.
As recent development drilling, facilities expansion and infrastructure
modifications have increased our pool of recoverable costs, we receive a larger
portion of total production to recover these costs.
CANADA
Given the maturity of the Western Canadian Sedimentary Basin, production
additions are shrinking and declines are increasing. Our conventional Canadian
assets are no exception. We aggressively managed our assets by developing them
where we could add value or by selling them at attractive prices where we could
not. Our conventional volumes in Canada fell 12% excluding the sale of our
non-core properties in southeast Saskatchewan. We are investing the free cash
flow from our Canadian assets in more profitable, multi-year development
projects.
34
Crude oil production was down 18%. On August 28, 2003, we sold 9,000 boe/d of
non-core, light oil properties in the Williston Basin of southeast Saskatchewan
for net proceeds of $268 million. The remaining decrease was due to base
declines on our heavy oil properties as water cuts increased at Marsden and
wells at Edam sanded up.
Our natural gas volumes fell 5% as new production from drilling did not offset
the natural decline in our gas properties.
We expect conventional production to decline modestly in 2004 as our asset base
matures. However, this trend will reverse as our Long Lake project starts up
with the production of bitumen in 2006 and synthetic crude oil in 2007.
GULF OF MEXICO
A full year of deep-water Aspen production increased US production rates 84% to
record levels in 2003. Production adds and optimization activities at Eugene
Island 295 and Vermilion 76 offset declines on the shelf.
Aspen came on-stream and began delivering high-margin barrels in December 2002.
We then acquired the remaining 40% interest in late March 2003. This acquisition
contributed 8,000 boe per day at a cash return of $33.11 per boe in 2003. We
locked-in a portion of our return on the acquisition by selling approximately
60% of the acquired production forward to March 2004 at a weighted average price
of US$29.50 per boe. The forward sale of 10% of the acquired reserves
effectively pays for 70% of the purchase price.
Late in 2003, additional deep-water production came on-stream at Gunnison. Three
subsea wells were tied-in and were producing 7,200 boe per day at year-end. Our
total deep-water production for the year was 24,000 boe per day.
Our shelf production was consistent with 2002 levels as we optimized production
where possible. We restored production at hurricane-damaged Eugene Island 295
ahead of schedule in February 2003 and continued to deliver solid rates from our
Vermilion 76 development. These gains were offset, in part, by lower performance
at Eugene Island 18 and West Cameron 170.
We expect the deep-water Gulf of Mexico to remain our fastest growing area in
2004 with Gunnison production increasing to 17,000 boe per day. We estimate our
US production levels will reach over 70,000 boe per day by the end of the year.
OTHER COUNTRIES
Our production at Buffalo offshore Australia and at Ejulebe offshore Nigeria
declined as expected throughout 2003 as both fields approach the end of their
economic life. We expect final production from both in 2004.
Colombia production grew 131% with 31 new development wells. Our pilot test
confirmed the viability of a waterflood and we are moving to full-field
waterflood in 2004. We expect to see volumes increase by 50% in 2004.
SYNCRUDE
Production decreased 8% in 2003 as an extra turnaround was completed during the
year. A 37-day unplanned coker turnaround reduced volumes in the fourth quarter
to 14,800 bbls per day. The turnaround delivered greater operational reliability
immediately as we exited 2003 at 19,900 bbls per day. We expect the benefits of
this turnaround to continue and do not anticipate a coker turnaround in 2004.
2002 VS 2001 - HIGHER PRODUCTION ADDED $12 MILLION TO NET INCOME
Production from our core assets in Yemen, Canada and the US remained largely
stable year over year. On-going development activities at Masila in Yemen, at
Hay in Canada and on the shelf in the US Gulf of Mexico helped maintain
production rates. In the US, poor weather in the third and fourth quarters,
including tropical storm Isidore and Hurricane Lili caused the temporary shut-in
of production, a 6-week delay at Aspen and damage to our Eugene Island 295
production platform. All production, except Eugene Island 295, was restored in
the fourth quarter of 2002. Aspen's first well came on-stream in early December
2002 and the second well in late December.
Our non-core assets made significant contributions during the year. At Buffalo
offshore Australia a successful two-well infill drilling program contributed
7,500 boe per day of incremental production. Ejulebe offshore Nigeria
contributed a 27% increase as the reservoir continued to perform better than
anticipated. Both Buffalo and Ejulebe were declining at year-end as they were
approaching the end of their expected lives.
35
COMMODITY PRICES
(Prices based on working interest production before royalties)
2003 2002 2001
- --------------------------------------------------------------------------------------------
CRUDE OIL
West Texas Intermediate (US$/bbl) 31.04 26.09 25.97
-----------------------------------
Differentials (US$/bbl):
Masila 3.03 1.41 3.29
Heavy Oil 8.63 6.49 10.68
Mars 3.53 2.51 4.89
Producing Assets (Cdn$/bbl)
Yemen 39.45 38.80 35.05
Canada 32.37 31.13 24.86
United States 37.68 38.88 38.35
Syncrude 43.36 40.89 39.90
Australia 43.14 40.30 38.71
Other Countries 38.22 38.96 37.37
Corporate Average (Cdn$/bbl) 38.04 37.13 33.10
-----------------------------------
NATURAL GAS
New York Mercantile Exchange (US$/mmbtu) 5.60 3.37 4.00
AECO (Cdn$/mcf) 6.35 3.84 5.97
-----------------------------------
Producing Assets (Cdn$/mcf)
Canada 5.64 3.57 5.02
United States 8.16 5.29 6.66
Corporate Average (Cdn$/mcf) 6.85 4.25 5.69
-----------------------------------
AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 38.63 35.14 33.28
-----------------------------------
AVERAGE FOREIGN EXCHANGE RATE
Canadian to US Dollar 0.7135 0.6369 0.6458
-----------------------------------
2003 VS 2002 - HIGHER REALIZED PRICES ADDED $275 MILLION TO NET INCOME
Both crude oil and natural gas commodity prices reached near record levels in
2003 as supply and demand fundamentals supported strong prices. The positive
impact of strong crude oil and natural gas reference prices was offset in part
by the strengthening Canadian dollar and widening crude oil differentials.
All of our oil sales and most of our gas sales are denominated in or referenced
to US dollars. As a result, the strengthening Canadian dollar relative to the US
dollar reduced our realized crude oil price by $4.50 per bbl and our realized
natural gas price by $0.80 per mcf. In total, our net sales decreased $280
million from 2002 levels with the strengthening of the Canadian dollar. The
Canadian to US dollar exchange rate closed the year at 77(cent).
36
CRUDE OIL REFERENCE PRICES
Supply and demand fundamentals consistently supported strong reference prices
throughout 2003. WTI opened and closed the year around US$33 per bbl, with highs
of approximately US$38 per barrel and lows around US$25 per barrel.
[CHART OMITTED]
Overall, the higher average WTI prices were supported by:
o ongoing concerns over the security and stability of Iraqi production;
o higher political risk in the Middle East;
o labour disputes, and the resulting and threatened supply disruptions,
in Nigeria and Venezuela;
o OPEC's determination to hold production quotas in support of their
price band;
o growing demand in Asia, particularly China and India;
o low crude oil and product inventories in North America; and,
o the decline in value of the US dollar relative to other major world
currencies.
These factors, along with speculation around their severity and duration,
created volatility in world crude oil prices. In 2004, analysts expect crude oil
prices to fall to between US$25 to US$28, as non-OPEC supply from Russia and
Iraq grows. An OPEC production cut, escalated Middle East risk or a
greater-than-expected economic recovery would put upward pressure on these
forecasts.
CRUDE OIL DIFFERENTIALS
Crude oil differentials widened in 2003 largely in response to the overall
strength of WTI.
Our Masila differential continued to track the Brent/WTI spread. Despite the
strength in WTI during the year, the Brent differential actually remained
relatively narrow. Brent prices strengthened with high demand in Europe during
the exceptionally warm summer months and growing demand in Asia late in the
year. Unexpected platform turnarounds in the North Sea reduced supply, causing
the Brent/WTI differential to narrow even further. We expect the Masila
differential to remain around US$3 per bbl in 2004.
The wider heavy oil differential was largely due to an overall increase in
supply from new Canadian heavy oil projects and some temporary decreases in
demand from unexpected refinery turnarounds and the August blackout in parts of
eastern North America. The heavy oil differential is expected to remain around
US$8 per bbl in 2004.
The Mars differential impacts the pricing of our Aspen production and averaged
US$3.53 per bbl. Again, despite the strength in WTI, the Mars differential was
relatively narrow in 2003. The pricing of Mars blend is directly affected by the
pricing of sour blends. The instability of Iraqi supply and OPEC production cuts
improved the pricing of sour blends and allowed the Mars differential to remain
narrow.
37
NATURAL GAS REFERENCE PRICES
North American natural gas prices were exceptionally strong during both the
first quarter of 2003 and December 2003. Natural gas prices reached almost US$10
per mcf in the first quarter, but more notably did not dip below US$4.40 per mcf
throughout the rest of the year.
[CHART OMITTED]
Extended cold weather last winter and resulting low storage inventory levels
were the major reason for the initial price increase early in the year. Fears of
cold weather in the east increased gas prices in December. This also caused the
NYMEX/AECO basis to widen significantly late in the year as weather forecasts in
the west were suggesting above normal temperatures. We expect natural gas prices
to decline to around US$4.25 per mmbtu in 2004.
2002 VS 2001 - HIGHER REALIZED PRICES ADDED $70 MILLION TO NET INCOME
WTI contributed little to cash flow growth in 2002, however narrow crude oil
differentials contributed around $180 million. At the beginning of 2002, WTI was
US$19.73 per barrel and strengthened to close the year at US$31.20 per barrel.
Low inventory levels in Europe kept the Brent/WTI differential narrow throughout
most of the year. Given that our Masila crude tends to price off Brent, the
Masila differential remained narrow along with the Brent/WTI spread. The heavy
oil differential was narrow due to the unexpected disruption of heavy oil supply
from Venezuela late in 2002. Lower natural gas prices reduced net income by $113
million. Natural gas prices fell in the first part of 2002 as inventories were
high, but increased late in the year as cold weather hit the eastern US.
OPERATING COSTS
(Cdn$/boe) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------
Before After Before After Before After
Royalties(1) Royalties Royalties(1) Royalties Royalties(1) Royalties
--------------------------------------------------------------------------------------------
Conventional Oil and Gas
Yemen 2.16 4.37 1.95 4.13 1.62 3.47
Canada 6.00 7.76 5.70 7.45 4.87 5.82
United States 4.49 5.19 9.09 10.87 6.01 7.31
Australia 18.60 20.21 9.76 12.14 13.50 14.38
Other Countries 7.47 9.01 6.21 10.69 8.07 9.94
Average Conventional 4.17 6.24 4.60 7.24 3.92 5.88
--------------------------------------------------------------------------------------------
Synthetic Crude Oil
Syncrude 21.96 22.18 18.10 18.21 19.43 20.29
Average Oil and Gas 5.19 7.56 5.42 8.26 4.88 7.10
--------------------------------------------------------------------------------------------
Note:
(1) Operating costs per boe 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
Items 1 and 2 in this 10-K for unit operating costs based on our production
after royalties.
38
2003 VS 2002 - LOWER OIL AND GAS
OPERATING COSTS INCREASED NET INCOME BY $23 MILLION
Conventional unit operating costs decreased with the addition of low-cost
production from Aspen in the Gulf of Mexico and the strengthening of the
Canadian dollar relative to the US dollar. Increased workover and maintenance
activity in Yemen and higher water handling costs in Canada partially offset
this decrease.
Low-cost Aspen production reduced US operating costs by 50% and lowered our
corporate average unit operating costs by approximately $0.40 per boe. Aspen
production costs are about $1.05 per boe, $3.12 per boe lower than our corporate
average for conventional production as most of the costs in our deep-water are
capital related. Gunnison will produce at similar attractive operating costs.
The strengthening Canadian dollar decreased US-dollar denominated operating
costs, lowering our corporate average unit operating costs by approximately
$0.25 per boe. Higher repairs, increased maintenance and workover activity
resulted in a US$0.40 per barrel increase in Yemen operating costs. We expect
ongoing maintenance and workover activities at Masila to keep operating costs
around US$1.70 per barrel. As well, unit operating costs offshore Australia and
Nigeria increased as fixed costs were spread over declining production volumes.
Syncrude operating costs increased 21% due to higher natural gas input costs and
increased turnaround and maintenance activity in 2003. Lower volumes also
increased unit operating costs as more than 95% of the operating costs are
fixed.
2002 VS 2001 - HIGHER OIL AND GAS
OPERATING COSTS REDUCED NET INCOME BY $58 MILLION
Conventional operating costs increased $0.68 per equivalent barrel due to
industry cost pressures in Canada, increased workover and repair activity on the
shelf in the Gulf of Mexico and increased water-handling and waterflood costs in
Yemen. As well, weather-related shut-ins and storm damage in the Gulf of Mexico
and one time flood-related costs in Yemen contributed to the increase. In
Australia, per-unit operating costs decreased significantly as fixed costs were
spread over more barrels.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
(Cdn$/boe) 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------------
Before After Before After Before After
Royalties(2) Royalties Royalties(2) Royalties Royalties(2) Royalties
--------------------------------------------------------------------------------------------
Conventional Oil and Gas
Yemen 3.96 8.03 3.47 7.34 2.56 5.48
Canada (1) 9.10 11.76 8.22 10.72 7.14 8.53
United States 10.80 12.47 12.74 15.38 10.59 12.85
Australia 13.31 14.46 10.45 12.99 16.61 17.69
Other Countries 17.09 22.47 13.22 22.90 15.11 18.62
Average Conventional 7.37 11.04 6.84 10.81 5.97 8.98
--------------------------------------------------------------------------------------------
Synthetic Crude Oil
Syncrude 2.50 2.53 2.13 2.17 2.03 2.13
Average Oil and Gas 7.09 10.33 6.55 10.01 5.73 8.40
--------------------------------------------------------------------------------------------
Notes:
(1) DD&A per boe excludes the impairment charge described in Note 4 of the
Consolidated Financial Statements.
(2) DD&A per boe 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.
2003 VS 2002 - HIGHER OIL AND GAS DD&A REDUCED NET INCOME BY $327 MILLION
Conventional depletion rates increased with higher 2002 finding and development
costs and our changing production mix, as more capital-intensive properties like
Aspen contribute growing volumes. These properties, however, deliver
higher-margin returns making them a valuable part of our portfolio. We also
experienced higher depletion rates offshore Nigeria and Australia, as we prepare
to abandon these fields in 2004.
The strengthening Canadian dollar offset these increases as our depletion from
International and the US is denominated in US dollars. This lowered our
corporate average rate by approximately $0.48 per boe.
Our DD&A expense for 2003 includes an impairment charge of $269 million ($175
million after-tax) largely attributable to reserve revisions to Canadian heavy
oil properties. These reserve revisions were the result of changes to late
field-life assumptions with respect to estimated future operating costs, changes
to proved undeveloped reserves based on drilling results and geological mapping
and reassessments of future estimated production profiles.
39
2002 VS 2001 - HIGHER OIL AND GAS DD&A REDUCED NET INCOME BY $80 MILLION
Conventional depletion rates increased with higher 2001 finding and development
costs in Canada, Yemen and the Gulf of Mexico and our changing production mix. A
decrease in rates in Australia, resulting from successful infill drilling,
partially offset these increases.
EXPLORATION EXPENSE
(Cdn$ millions) 2003 2002 2001
- --------------------------------------------------------------------------------------------------------
Seismic 62 75 77
Unsuccessful Drilling 70 61 133
Other 68 45 50
---------------------------------------
Total Exploration Expense 200 181 260
=======================================
Total Exploration Capital 329 259 411
Exploration Expense as a % of Exploration Capital (%) 61 70 63
---------------------------------------
2003 VS 2002 - HIGHER EXPLORATION EXPENSE REDUCED NET INCOME $19 MILLION
Exploration expense grew consistent with an increase in our 2003 exploration
capital spending. Overall, our exploration program delivered excellent results
from the Gulf of Mexico, OPL-222 offshore Nigeria and Block 51 in Yemen.
Dry hole and seismic costs in the Gulf of Mexico accounted for over 40% of our
exploration expense. Exploration in the Gulf yielded some promising results at
Shiloh. At Shiloh, we found hydrocarbons but not commercial quantities, so the
well costs were written off. We still plan to actively pursue this prospect,
have acquired additional acreage in the area and hope to prove-up commercial
quantities in the region. We were unsuccessful at Santa Rosa but continue to
pursue opportunities in the area.
Dry hole costs also included three wells in the Alberta foothills of Canada, the
Andino-1 well in Colombia, the Escargot well offshore Brazil and the HEK well in
Yemen on Block 51. In addition, we acquired seismic over a number of prospects.
2002 VS 2001 - LOWER EXPLORATION EXPENSE ADDED $79 MILLION TO NET INCOME
Exploration expense was lower in 2002 as we spent less on exploration capital,
focusing our efforts on developing earlier exploration successes. Unsuccessful
exploration wells included Block 59 in Yemen, Fusa in Colombia, Block BC-20
offshore Brazil and Fergana in the Gulf of Mexico.
OIL AND GAS MARKETING
(Cdn$ millions) 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------
Revenue 568 496 438
Transportation (398) (423) (342)
Other (1) -- --
----------------------------------------
Net Revenue 169 73 96
========================================
Marketing contribution to Income from Continuing Operations before Income Tax 111 35 59
----------------------------------------
Physical Sales Volumes (excluding intra-segment transactions)
Crude Oil (mboe/d) 479 412 400
Natural Gas (mmcf/d) 3,301 2,865 2,499
Value-at-Risk
Year-end 21 19 19
High 31 28 24
Low 14 12 6
Average 20 17 13
----------------------------------------
40
2003 VS 2002 - RECORD NET MARKETING REVENUE INCREASED NET INCOME BY $96 MILLION
Marketing delivered record financial results growing their cash flow by 132%
over 2002. This achievement was driven primarily by exceptional results from our
gas marketing and trading group, supplemented by steady profits from our crude
oil trading and marketing group.
Our natural gas group successfully positioned themselves to benefit from price
differences between western Canada and eastern North America, and between summer
and winter months. We also added transportation and storage capacity to our
contract base. Added transportation capacity allowed us to take advantage of
price differences between receipt and delivery points while added storage
allowed us to take advantage of varying seasonal demand in the summer and winter
months.
The continued exit of competitors from the market in 2003 enabled us to acquire
contracts on favourable terms, including storage and transportation contracts
and natural gas contracts.
We also successfully mitigated earlier volatility related to our storage
positions by implementing a hedge accounting strategy. Until October 25, 2002,
mark-to-market gains on our storage positions were included in net income. New
accounting rules required us to exclude these gains from our results in 2003
until the inventory was sold despite having futures contracts in place that
locked-in the profit on our stored volumes. At the beginning of the third
quarter, we designated certain futures contracts as accounting hedges of the
future sale of our stored volumes. As a result, recognition of the
mark-to-market gain or loss on the futures contracts is deferred until the
inventory is sold. See Note 5 to the Consolidated Financial Statements for
further details.
2002 VS 2001 - LOWER NET MARKETING REVENUE REDUCED NET INCOME BY $23 MILLION
Marketing delivered solid results in 2002 despite having fewer opportunities.
Less price volatility in 2002 resulted in smaller margins. This was offset
somewhat by an increase in our marketed volumes, as there were fewer competitors
in the market.
COMPOSITION OF NET MARKETING REVENUE
(Cdn$ millions) 2003 2002
- -----------------------------------------------------------------------------
Derivative Energy Contracts 148 58
Non-Derivative Energy Contracts 21 15
-----------------------
169 73
=======================
DERIVATIVE ENERGY CONTRACTS
Our marketing operation engages in crude oil and natural gas marketing
activities to enhance prices from the sale of our own production, and for energy
marketing and 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 physical purchases and sales, 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 that are not designated as a hedge 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.
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 the Natural Gas Exchange, independent
price publications and over-the-counter broker quotes.
41
FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS
At December 31, 2003, the fair value of our derivative energy contracts not
designated as hedges totalled $106 million (2002 - $3 million). The following
table shows the valuation methods underlying these contracts together with
details of contract maturity:
(Cdn$ millions) MATURITY
- ------------------------------------------------------------------------------------------------------------------------------
less than more than
one year 1-3 years 4-5 years 5 years Total
--------------------------------------------------------------------
Prices
Actively Quoted Markets (9) 1 -- -- (8)
From Other External Sources 77 30 9 (2) 114
Based on Models and Other Valuation Methods -- -- -- -- --
--------------------------------------------------------------------
Total 68 31 9 (2) 106
====================================================================
More than 64% of the unrealized gain is related to contracts that will settle in
2004. Contract maturities vary from a single day up to six years. Those maturing
beyond one year are primarily from natural gas related positions. The relatively
short maturity position of our contracts lowers our portfolio risk.
At December 31, 2003, the unrecognized losses on our derivative energy contracts
accounted for as hedges of the future sale of our inventory totalled $11
million. The following table shows the valuation methods underlying these
contracts together with details of contract maturity:
(Cdn$ millions) MATURITY
- ------------------------------------------------------------------------------------------------------------------------------
less than more than
one year 1-3 years 4-5 years 5 years Total
--------------------------------------------------------------------
Price
Actively Quoted Markets (11) -- -- -- (11)
From Other External Sources -- -- -- -- --
Based on Models and Other Valuation Models -- -- -- -- --
-------------------------------------------------------------------
Total (11) -- -- -- (11)
===================================================================
Our accounting policy does not permit us to record income on transportation and
storage contracts using option valuation methods.
CHANGES IN FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS
Contracts
Contracts Contracts Entered into
Outstanding at Entered into During Year
Beginning of and Closed and Outstanding
(Cdn$ millions) Year During Year at End of Year Total
- -----------------------------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2002 3 -- -- 3
Change in Fair Value of Contracts 6 53 89 148
Net Losses (Gains) on Contracts Closed 2 (53) -- (51)
Derivative Energy Contracts Acquired -- -- 6 6
Changes in Valuation Techniques and Assumptions (1) -- -- -- -
-------------------------------------------------------------------
Fair Value at December 31, 2003 11 - 95 106
-------------------------------------------------------------------
Unrecognized Losses on Hedges of Future Sale
of Inventory at December 31, 2003 - - (11) (11)
-------------------------------------------------------------------
Total Outstanding at December 31, 2003 11 - 84 95
===================================================================
Note:
(1) Our valuation methodology has been applied consistently year over year.
42
TOTAL CARRYING VALUE OF DERIVATIVE ENERGY CONTRACTS
(Cdn$ millions) 2003 2002
- ------------------------------------------------------------------------------------------
Current Assets 102 42
Non Current Assets 63 14
-----------------------------
Total Derivative Energy Contract Assets 165 56
=============================
Current Liabilities 34 46
Non Current Liabilities 25 7
-----------------------------
Total Derivative Energy Contract Liabilities 59 53
=============================
Total Derivative Energy Contract Net Assets (1) 106 3
=============================
Note:
(1) Does not include effective hedges. We recognize gains and losses on
effective hedges in the same period as the hedged item.
Unrecognized losses on forward contracts for the future sale of oil and gas
production are disclosed in Note 5 of the Consolidated Financial Statements.
NON-DERIVATIVE ENERGY CONTRACTS
We enter into fee for service contracts related to transportation and storage of
third party oil and gas. We also earn income from our power generation facility.
We earned $21 million from our non-derivative energy activities in 2003 (2002 -
$15 million).
CHEMICALS
(Cdn$ millions) 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------
Net Sales 375 367 373
Sales Volumes (thousand short tons)
Sodium chlorate 478 454 457
Chlor-alkali 396 375 365
Operating Profit (1) 95 100 99
Operating Margin (%) 25 27 27
Chemicals contribution to Income from Continuing Operations before Income Taxes 28 27 47
Capacity Utilization (%) 95 85 89
---------------------------------------
Note:
(1) Total revenues less operating costs, transportation and other.
2003 VS 2002 - LOWER CHEMICALS OPERATING PROFIT REDUCED NET INCOME BY $5 MILLION
Many of the challenges we successfully managed in 2002 were replaced with new
challenges in 2003. Strong North American demand for chlor-alkali and sodium
chlorate helped boost sales volumes and prices in 2003. In North America, we
manufacture our products in Canada. Most of our sales, however, are into US
markets. As the Canadian dollar strengthened, our US-dollar denominated revenues
declined, lowering our operating profit by $13 million.
Higher natural gas prices in North America put pressure on electricity costs. To
deal with these cost pressures, we idled our Taft plant, our highest electricity
cost facility, and relocated the assets to Brandon. Our cost savings from idling
the plant were offset by product we purchased from other suppliers to satisfy
southeastern US customers. Once the assets are installed at Brandon, we expect
the savings to flow to our bottom line. The installation of the Taft assets at
Brandon should be completed in 2004 eliminating our need for purchased product.
2002 VS 2001 - CHEMICALS OPERATING PROFIT ADDS $1 MILLION TO NET INCOME
We faced many challenges in 2002. Slow economic recovery in North America placed
downward pressure on sodium chlorate volumes and eroded market prices. Also,
increasing energy costs in Louisiana put pressure on our Taft plant.
During 2002, margins remained strong due to lower overall energy costs and the
shifting of production from higher-cost to lower-cost facilities following the
expansion of our Brandon and Brazil facilities. The expansion of these plants
increased our depreciation.
43
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE
(Cdn$ millions) 2003 2002 2001
- --------------------------------------------------------------------------------
General and Administrative Expenses 190 152 136
-----------------------------
2003 VS 2002 - HIGHER COSTS AND LOWER
RECOVERIES REDUCED NET INCOME BY $38 MILLION
Approximately 75% of the G&A increase relates to higher variable compensation:
o Record 2003 results increased bonus compensation by $16 million; and
o Strong stock prices at year-end increased the value of our employee
stock appreciation rights and related expense by $13 million.
The continued expansion of our marketing group also increased our staffing costs
in 2003.
2002 VS 2001 - HIGHER COSTS REDUCED NET INCOME BY $16 MILLION
Approximately 70% of the increase was due to higher staffing levels associated
with our record capital investment program and growth in our marketing
operations. The remainder resulted from increased pension expense due to poor
equity market performance, higher building lease costs and incremental expenses
associated with our stock appreciation rights plan.
INTEREST
(Cdn$ millions) 2003 2002 2001
- --------------------------------------------------------------------------------
Interest 148 140 112
Less: Capitalized Interest 43 31 --
------------------------------
Net Interest Expense 105 109 112
==============================
Effective Rate (%) 7.2 7.1 7.6
------------------------------
2003 VS 2002 - LOWER INTEREST EXPENSE INCREASED NET INCOME BY $4 MILLION
Total interest costs increased $20 million due to:
o Full-year impact of our 30-year notes issued in March 2002, and;
o US$960 million issuance of new fixed-rate debt in November 2003.
This increase was offset by the strengthening Canadian dollar, which lowered our
US-dollar denominated interest expense by $10 million.
Net interest expense decreased as capitalized interest related to major
development projects costs continued to grow. Capitalized interest is expected
to increase in 2004 as we proceed with major development projects at Long Lake
and Syncrude.
2002 VS 2001 - LOWER INTEREST EXPENSE ADDED $3 MILLION TO NET INCOME
Higher borrowing rate on our new 30-year notes increased interest costs by $28
million. We continued to capitalize interest on our major development projects
resulting in lower net interest expense.
INCOME TAXES
(Cdn$ millions) 2003 2002 2001
- --------------------------------------------------------------------------------
Current 210 223 216
Future (40) (12) 67
---------------------------------
170 211 283
=================================
Effective Rate (%) 22 34 40
---------------------------------
44
2003 VS 2002 - EFFECTIVE TAX RATE DECLINES FROM 34% TO 22%
The 2003 effective tax rate fell primarily due to a reduction in tax rates for
Canadian resource activities that resulted in a recovery of future income taxes
of $76 million during the second quarter. The effective tax rate for 2004 is
expected to be 33%.
The majority of our 2003 current income taxes were paid in Yemen. Current taxes
include cash taxes in Yemen of $201 million (2002 - $207 million; 2001 - $191
million). During 2003 and 2002, federal and provincial capital taxes were
payable in Canada. In 2003, current income taxes also include alternative
minimum tax in the United States.
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.
GAIN OR LOSS ON DISPOSITION OF ASSETS
There was no gain or loss on the 2003 sale of our southeast Saskatchewan
properties as described in Note 9 to the Consolidated Financial Statements. The
net loss in 2002 includes a gain of $13 million on the sale of our asphalt
operation in Moose Jaw, Saskatchewan and a loss of $21 million on the sale of a
non-operated property by our Canadian oil and gas business segment.
OTHER INCOME
(Cdn$ millions) 2003 2002 2001
- --------------------------------------------------------------------------------
Foreign Exchange Gain (Loss) 6 (3) -
Business Interruption Insurance Proceeds 12 - -
Interest Income 9 7 17
Other 15 4 20
------------------------------
42 8 37
==============================
The business interruption insurance proceeds received in 2003 relate to damage
sustained in the Gulf of Mexico during tropical storm Isidore and hurricane Lili
in the third and fourth quarters of 2002.
OUTLOOK FOR 2004
Our largest ever-capital program of $1.8 billion will focus on advancing our
major development programs and high-quality exploration in four key basins. Our
solid capital structure and surplus liquidity will support this program. In
2004, we plan to invest almost $1.7 billion in oil and gas with:
o 35% in core assets to maintain existing production levels;
o 45% in new growth development projects, and;
o 20% in new growth exploration projects.
Details of our 2004 capital investment program are included in the Capital
Investment section in the MD&A. This program is consistent with our strategy to
grow reserves and production primarily through the drill bit.
45
DAILY PRODUCTION
Approximately 45% of our cash flow from core assets will be reinvested in those
assets to deliver production between 255,000 and 275,000 boe per day in 2004.
The remaining 55% of cash flow will be invested in new growth projects.
2004 ESTIMATED PRODUCTION
----------------------------------
(mboe/d) BEFORE ROYALTIES AFTER ROYALTIES
- ----------------------------------------------------------------------------------------
Gulf of Mexico (1) 60 - 65 55 - 57
Yemen, Masila 110 - 118 58 - 62
Canada Conventional (2) 57 - 65 46 - 53
Syncrude 16 - 18 16 - 17
Other International 7 - 9 6 - 8
-------------------------------------
Total 255 - 275 180 - 195
=====================================
Notes:
(1) US natural gas production is estimated to comprise 45% of total US
equivalent production in 2004.
(2) Canadian natural gas production is estimated to comprise 33% of total
Canadian equivalent production in 2004.
Our net production growth will be modest in 2004, as over half our cash flow is
invested in major growth projects coming on-stream in 2005 and beyond. Many of
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, even if oil prices trend lower.
We expect to generate around $1.3 billion in cash flow from operations in 2004
assuming the following:
- --------------------------------------------------------------------------------
WTI (US$/bbl) 25.00
NYMEX natural gas (US$/mmbtu) 4.25
US to Canadian dollar exchange rate 0.75
Changes in actual commodity prices and exchange rates will impact our annual
cash flow from operations as follows:
(Cdn$ millions)
- --------------------------------------------------------------------------------
WTI - US$ 1 change 53
NYMEX natural gas - US$0.50 change 60
Exchange rate - $0.01 change 21
In a price-neutral environment, cash flow from operations would grow by
approximately 10% over 2003 and we would see 11% growth in our corporate cash
netback.
In addition to strong cash flow from our oil & gas operations, we expect solid
performance from our chemicals and marketing businesses in 2004. Our chemicals
operations anticipate improved cash flow from growing production and lower unit
costs as we continue to consolidate production at our low-cost facility in
Brandon. Our marketing group also anticipates another profitable year as they
continue to increase their presence in core markets in the US midwest and
eastern Canada.
LIQUIDITY
SOURCES AND USES OF CASH
Our business strategy is focused on value-based growth through full-cycle
exploration and development, supplemented by strategic acquisitions when
appropriate. We rely on operating cash flows to fund capital requirements and
provide liquidity. We build our opportunity portfolio to provide a balance of
short-term, mid-term, and longer-term growth. This enables us to generate
ongoing sustainable operating cash flows as shown below:
(Cdn$ millions) 2003 2002 2001 2000 1999
- ------------------------------------------------------------------ -----------------------------------------------------------
Cash Flow from Operations 1,859 1,383 1,423 1,569 780
Capital Expenditures (1,494) (1,625) (1,404) (915) (612)
----------------------------------------- --------------------------
365 (242) 19 654 168
====================================================================
WTI (US $/bbl) 31.04 26.09 25.97 30.21 19.24
NYMEX natural gas (US $/mmbtu) 5.60 3.37 4.00 4.31 2.31
--------------------------------------------------------------------
46
The capital investment in our oil and gas operations is primarily funded by our
cash flow from operations. Although this spending is mostly discretionary, we
rely on prudent capital investment to generate future operating cash flows.
Given the long cycle time of some of our development projects, particularly
internationally, and the volatility of commodity prices, it is not unusual, in
any given year for capital expenditures to exceed our cash flow.
In 1998 and 1999, commodity prices were low and we reduced our capital
investment. In 2000, commodity prices improved, allowing us to generate
sufficient cash flow from operations to buy back 20 million common shares. In
2001 and 2002, we began to invest significantly in two deep-water Gulf of Mexico
prospects (Aspen and Gunnison), our Syncrude expansion and our Long Lake
project. In 2003, Aspen contributed significantly to our cash flow from
operations and in 2004, we expect additional significant contributions from
Gunnison. We anticipate cash flows from the Syncrude expansion and Long Lake to
commence in 2006 and 2007, respectively.
Given the cyclical nature of the upstream oil and gas business, we manage our
capital structure so that we are well positioned from a liquidity perspective
throughout both positive and negative commodity price cycles. Our capital
structure is characterized by a modest level of absolute debt, a long term to
maturity and undrawn committed credit facilities.
CAPITAL STRUCTURE
(Cdn$ millions) 2003 2002
- --------------------------------------------------------------------------------
Bank Debt -- --
Senior Public Debt 2,776 1,844
------------------
2,776 1,844
Less: Cash 1,087 59
Less: Non-Cash Working Capital (1) 312 10
------------------
Net Debt (2) 1,377 1,775
Preferred and Subordinated Securities 364 724
------------------
Net Debt, including Preferred and Subordinated Securities 1,741 2,499
==================
Shareholders' Equity (3), (4) 2,418 2,348
==================
Notes:
(1) Excludes current portion of long-term debt.
(2) Long-term debt less net working capital.
(3) Included in shareholders' equity are preferred and subordinated securities
of $364 million (2002 - $724 million). Under US generally accepted
accounting principles, these are considered long-term debt.
(4) At January 31, 2004, there were 126,738,410 common shares and US$460
million of unsecured subordinated securities outstanding. These
subordinated securities may be redeemed by the issuance of common shares at
our option after November 8, 2008. The number of shares to be issued will
depend upon the common share price on the redemption date.
We significantly enhanced our capital structure in 2003:
SHAREHOLDERS' EQUITY Continued to strengthen with record net income in 2003.
US$500 MILLION OF 5.05% DEBT Issued in November 2003 and maturing in 10 years. Proceeds were used to
repay US$225 million of long term debt early in February 2004, and to
fund a portion of our 2004 capital investment program.
US$460 MILLION OF 7.35% SUBORDINATED DEBENTURES Issued in November 2003 and maturing in 40 years. Proceeds were
partially used to redeem our 2047 preferred securities in December 2003
and our 2048 preferred securities in early February 2004.
COMMITTED BANK FACILITIES OF $1,656 MILLION All undrawn at year-end with 75% of the facilities available to the end
of 2008 and the remainder to the end of 2007.
US$1 BILLION UNIVERSAL DEBT SHELF PROSPECTUS Available until October 2005 in the US and Canada.
FAVOURABLE DEBT MATURITIES Pre-financed our 2004 debt maturity. Our remaining maturities over the
next five years are minimal. The average term to maturity of our debt is
20 years.
47
CHANGE IN WORKING CAPITAL
2003 2002 INCREASE/
Cdn$ millions (DECREASE)
- --------------------------------------------------------------------------------
Cash and Short-Term Investments 1,087 59 1,028
Accounts Receivable 1,423 988 435
Inventories and Supplies 270 256 14
Accounts Payable and Accrued Liabilities (1,404) (1,194) (210)
Other 23 (40) 63
-----------------------------------
1,399 69 1,330
===================================
Cash and short-term investments increased with our fourth quarter financing
activities. We received proceeds of US$960 million when we issued US$500 million
of notes and US$460 million of subordinated debentures in November 2003. We used
US$701 million of this cash to redeem US$259 million of preferred securities in
December 2003, US$217 million of preferred securities in early February 2004 and
US$225 million of senior notes in early February 2004. Accounts receivable
increased in part because there was no sale of receivables at the end of 2003
compared to the sale of $178 million at the end of 2002. The remainder of the
increase was due to higher commodity prices and growth in our marketing business
offset by the strengthening of the Canadian dollar relative to the US dollar.
The increase in other was related to the prepayment of natural gas storage
inventory in December.
NET DEBT
Our net debt levels are directly related to our operating cash flows and our
capital expenditure activities. During the year, we successfully reduced net
debt, including preferred and subordinated securities, by $758 million:
(Cdn$ millions) 2003 2002
- ------------------------------------------------------------------------------------------------------------------
Capital Expenditures 1,494 1,625
Cash Flow from Operations (1,859) (1,383)
-----------------------------
(365) 242
Dividends on Preferred Securities and Common Shares 104 109
Foreign Exchange Translation of US-dollar Debt and Cash (281) --
Proceeds on Disposition of Assets (293) (49)
Issue of Common Shares 73 51
Other 4 (38)
-----------------------------
Increase (Decrease) in Net Debt, including Preferred and Subordinated Securities (758) 315
=============================
The reduction in net debt has a positive impact on our leverage metrics:
2003 2002 2001
- --------------------------------------------------------------------------------------------------------------------
Net Debt, including Preferred Securities and Subordinated Securities,
to Cash Flow (1) (times) 1.0 1.9 1.6
Interest Coverage (2) (times) 13.3 10.7 13.7
Fixed Charge Coverage (3) (times) 9.5 7.2 8.4
---------------------------------
Notes:
(1) Cash flow comprises cash flow from operations after dividends on Preferred
Securities.
(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 and preferred securities are equal to 1.0 times our 2003 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.
48
FUTURE LIQUIDITY
Our future liquidity is primarily dependent on cash flows generated from our
operations, our capital investment programs and the flexibility of our capital
structure. Assuming WTI of US$25 per bbl for 2004, we expect our 2004 capital
investment program and dividend requirements to exceed our cash flow from
operations by almost $550 million.
Our cash flow from operations is sensitive to changes in commodity prices and
exchange rates. For 2004, we expect cash flow from operations of $1.3 billion,
assuming the following:
- --------------------------------------------------------------------------------
WTI (US$/bbl) 25.00
NYMEX natural gas (US$/mmbtu) 4.25
US to Canadian dollar exchange rate 0.75
Changes in commodity prices and exchange rates will impact our cash flow from
operations and our borrowing requirements. The impact of a variance, in any one
of the above assumptions, on our cash flow from operations is described in the
Outlook for 2004 section in the MD&A.
If we change our capital investment program, we may draw more or less on our
cash balances and our available facilities. We are currently entering a 4-year
period of investing in major development projects as we move forward with our
projects at Long Lake in Canada and on Block 51 in Yemen.
Given our stable operating cash flows, strong cash position and undrawn
committed credit facilities, we do not anticipate any problems in funding our
capital programs, dividend requirements, and debt repayments or in meeting the
obligations that arise from our day-to-day operations. In 2003, we declared
common share dividends of $0.325 per common share (2002 - $0.30, 2001 - $0.30).
We expect to declare common share dividends of $0.40 per common share in 2004.
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We have assumed various contractual obligations and commitments in the normal
course of our operations and financing activities. These obligations and
commitments have been considered when assessing our cash requirements in the
above discussion of future liquidity.
(Cdn$ millions) Payments (1)
- ------------------------------------------------------------------------------------------------------------------------------
less than more than
Total one year 1-3 years 4-5 years 5 years
-------------------------------------------------------------------------------
Long-Term Debt (1) 2,776 291 98 275 2,112
Preferred and Subordinated Securities (1) 364 331 -- -- 33
Operating Leases (2) 217 33 58 35 91
Transportation and Storage Commitments (2) 580 212 172 85 111
Work Commitments 81 64 17 -- --
Dismantlement and Site Restoration 514 18 28 32 436
Other 1 1 -- -- --
-------------------------------------------------------------------------------
Total 4,533 950 373 427 2,783
===============================================================================
Notes:
(1) Payment obligations are not discounted and do not include related interest,
accretion or dividends. At December 31, 2003, we had cash and short-term
investments of $1,087 million.
(2) Payments for operating leases and transportation commitments are deducted
from our cash flow from operations.
Contractual obligations include both financial and non-financial obligations.
Financial obligations 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.
o Long-term debt amounts are included in our December 31, 2003 Consolidated
Balance Sheet. The amount due in 2004 has been included in our current
liabilities. Under US GAAP, $331 million of preferred securities and $33
million of subordinated securities would be included in long-term debt.
o Operating leases include leases for office space, rail cars, vehicles, the
lease of the FPSO in Australia, and our processing agreement with Shell
that allows our Aspen production to flow through Shell's processing
facilities at the Bullwinkle platform. The terms of the processing
agreement give Shell an annual option to take payment in cash or in kind.
For 2004, Shell has elected to take payment in kind so the 2004 obligation
has been excluded from this table.
o Our marketing operation manages various natural gas transportation and
storage commitments on behalf of our Canadian oil and gas business and a
number of third-party customers.
49
o Work commitments include non-discretionary capital spending related to
drilling and seismic commitments in our international operations and
development commitments at Syncrude. The remainder of our 2004 capital
investment is discretionary.
o We have $514 million of future dismantlement and site restoration
obligations. As of December 31, 2003, $197 million of these obligations
have been provided for on our balance sheet (including $18 million of
current liabilities). The timing of any payments is difficult to determine
with certainty and the table has been prepared using our best estimates.
o We have unfunded obligations under our defined benefit pension and post
retirement benefit plans of $84 million. Our unfunded obligation is $43
million and our share of Syncrude's unfunded obligation is $41 million. Our
$43 million obligation includes $29 million that is unfunded as a result of
statutory limitations. These obligations are backed by letters of credit.
During 2003, we contributed $16 million to our defined benefit pension
plan. Post year-end positive equity markets have helped restore our defined
benefit plan to a fully funded position.
o We have excluded our normal purchase arrangements as they are discretionary
and are reflected in our expected cash flow from operations and our capital
expenditures for 2004.
From time to time we enter into contracts that require us to indemnify parties
against possible claims, particularly when these contracts relate to the sale of
assets. On occasion, we provide indemnifications to the purchaser. Generally, a
maximum obligation is not stated. Because the obligation is stated, the overall
maximum amount cannot be reasonably estimated. We have not made any significant
payments related to these indemnifications. Our Risk Management Committee
actively monitors our exposure to the above risks and obtains insurance coverage
to satisfy potential or future claims as necessary. We believe these matters
would not have a material adverse effect on our liquidity, financial condition
or results.
CREDIT RATINGS
Currently, our senior debt is rated BBB by Standard & Poor's, Baa2 by Moody's
Investor Service, Inc. and BBB by Dominion Bond Rating Service. In addition, all
rating agencies currently rate our outlook as stable. Our strong financial
results, ample liquidity and financial flexibility continue to support our
credit rating.
FINANCIAL ASSURANCE PROVISIONS IN COMMERCIAL CONTRACTS
The commercial agreements our marketing division enters into often include
financial assurance provisions that allow Nexen and our counterparties to
effectively manage credit risk. The agreements normally require posting
collateral (in the form of either cash or a letter of credit) if a buyer's
credit rating drops below investment grade, indicating their creditworthiness
has deteriorated. Based on the contracts in place and commodity prices at
December 31, 2003, we would be required to post collateral of $321 million if we
were downgraded 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 $1.7 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.
OFF-BALANCE SHEET ARRANGEMENTS
None.
CONTINGENCIES
See Note 10 to the Consolidated Financial Statements in Item 8, which is
incorporated herein by reference for a discussion of our contingencies.
50
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; and
o logistics and reliability of supply.
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, well bore collapse, 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 may 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. If cash
flow from operations is 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 could be impaired.
UNCERTAINTY OF RESERVE ESTIMATES
Oil and gas reserves are integral to assessing our expected future financial
performance, preparing our financial statements and making investment decisions.
There are numerous uncertainties inherit in estimating quantities of proved oil
and natural gas reserves, including many factors beyond our control. The
reserves included in this Form 10-K represent estimates only.
To estimate the economically recoverable oil and natural gas reserves and
related future net cash flows, we incorporate many factors and assumptions
including:
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 these factors and assumptions are reasonable based on the information
available to us at the time we prepared the estimates. However, actual results
could vary considerably, which could cause material variances in:
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.
51
Management is responsible for estimating the quantities of proved oil and
natural gas reserves and preparing related disclosures. Estimates and related
disclosures are prepared in accordance with SEC requirements, generally accepted
industry practices in the US as promulgated by the Society of Petroleum
Engineers, and the standards of the Canadian Oil and Gas Evaluation Handbook
modified to reflect SEC requirements.
Reserve estimates for each property are prepared at least annually by the
property's reservoir engineer. They are reviewed by engineers familiar with the
property and by divisional management. Senior management, including our CEO, CFO
and Board-appointed internal qualified reserves evaluator, meet with divisional
reserves personnel to review the estimates and any changes from previous
estimates.
The internal qualified reserves evaluator assesses whether our reserves
estimates and the Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein, included in the Supplementary Financial Information, have been
prepared in accordance with our reserve standards. His opinion stating that the
reserves information has, in all material respects, been prepared according to
our reserves standards is included in an exhibit to Form 10-K.
We also have at least 80% of our reserve estimates audited annually by
independent qualified reserves consultants. Given that the reserves estimates
are based on numerous assumptions and interpretations, differences in estimates
prepared by us and an independent reserves consultant within 10% are considered
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 to
oversee the annual review of our oil and gas reserves and related disclosures.
The Reserves Committee is comprised of three or more directors, the majority of
whom are independent, and each being familiar 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
appoints and meets with each of the internal qualified reserves evaluator and
independent reserves consultants independent of management to review the scope
of their work, whether they have had access to sufficient information, the
nature and satisfactory resolution of any material differences of opinion, and
in the case of the independent reserves consultants, their independence.
The Reserves Committee has reviewed Nexen's procedures for preparing the reserve
estimates and related disclosures. It has reviewed the information with
management, and met with the internal qualified reserves evaluator and the
independent qualified reserves consultants. As a result of this, the Reserves
Committee is satisfied that the internally-generated reserves are reliable and
free of material misstatement. Based on the recommendation of the Reserves
Committee, the Board has approved the reserves estimates and related disclosures
in the Form 10-K.
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 estimated
cash flows. See the Critical Accounting Estimates section of this MD&A where we
discuss 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.
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
beyond the revenue they receive from the production we operate. Our strong
relationship with the people and Government of Yemen has allowed us to operate
there without interruptions for almost 14 years and we anticipate this
continuing.
Our practices have enabled us to operate successfully, not only in Yemen, but
also in other parts of the world. We have developed excellent practices to
manage the risks successfully.
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.
52
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. We also maintain an ongoing awareness of external
trends, demands, commitments, events or uncertainties that may reasonably have a
material effect on revenues from continuing operations. These actions provide
assurance that we meet or exceed appropriate environmental standards worldwide.
o At December 31, 2003, $197 million has been provided in the
Consolidated Financial Statements for future dismantlement and site
restoration costs, currently estimated at $514 million for our oil and
gas and chemicals facilities.
o During 2003, we recorded a provision for future dismantlement and site
restoration costs of $38 million (2002 - $43 million; 2001 - $45
million).
o Actual site remediation expenditures for the year were $21 million
(2002 - $20 million; 2001 - $24 million). We anticipate actual site
remediation expenditures in 2004 to approximate 2003 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.
o During 2003, we commenced an external operational audit to confirm
whether our management system for safety, environment and social
responsibility issues is actually being followed. This work is
continuing into 2004, but initial reports are very positive.
CLIMATE CHANGE
The Kyoto Protocol, an agreement to reduce the concentration of certain man-made
gases (Green House Gases or GHG) that may be contributing to climate change, was
signed by approximately 160 countries since 1997. Canada ratified the Kyoto
Protocol in December 2002, but it will not come into effect until it is ratified
by Russia. The Kyoto Protocol obliges the Annex 1 countries to meet national
targets. Canada's target is an emission reduction of 6% below 1990 levels during
the First Commitment period of 2008 to 2012. Economic modeling studies have
shown that if emission reductions are met through domestic action in Annex I
countries alone, there will be severe negative impacts to those 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.
The Canadian government has addressed the uncertainty around ratification and
implementation of the Kyoto Protocol by providing the oil and gas sector with
limits on cost (a cap of $15 per tonne) and volume (a cap of 55 megatonnes for
large industrial emitters) as well as its position on long-term high capital
cost projects. However, the government has yet to enact national legislation
that will detail the obligations of Canadian industry with respect to emission
reduction and management, and it is uncertain at this time when those
obligations will be determined. The financial markets have viewed these
developments favourably and have issued various analyses in the aftermath of
these announcements indicating that implementation of GHG-related legislation
should not adversely affect the development of new energy projects such as the
oilsands.
For years, Nexen has been assessing 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 well, Nexen continues to
work closely with the Canadian and Alberta governments to assess the impact of
regulatory options and provide information on our business to assist governments
in their policy deliberations. Nexen maintains a wide range of business contacts
to ensure that a full slate of options is available to the corporation in order
to meet the obligations that may be imposed by future legislation.
Nexen is a Gold level reporter in Canada's Voluntary Challenge and Registry
(VCR); our 2002 VCR report includes the observation that we have voluntarily
reduced our direct emissions by almost 2 million tons of CO2 equivalent since we
started reporting in 1996. As well, progress has been made toward reduction of
our energy inputs per unit of production. In 2003, we initiated another gas
gathering project in heavy oil. We are still assessing our 2003 performance and
it will be reported to the VCR.
53
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. 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. Nexen has entered into discussions with the management of several
GHG investment pools and continues to evaluate the opportunities associated with
biological and geological sequestration of CO2 and the capture of methane from
landfills. 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. We continuously review the feasibility of new
and ongoing projects with respect to current social, political and economic
factors and will continue to take into account the policy and requirements with
respect to GHG when conducting these reviews .
We are committed to the principles of full disclosure and will keep our
stakeholders apprised of how these issues affect us. Since emission levels
applicable to our business operations have not been determined and there are no
reliable estimates of the costs of achieving those levels, premature disclosure
would be speculative and any financial estimates would be based on arbitrary
assumptions of emission levels; however, Canadian government assurances of cost
and volume limits suggest that incremental risks and liabilities attributable to
addressing climate change policies are manageable. Finally, any indirect risks
and liabilities attributable to GHG are too remote and unquantifiable at this
time.
MARKET RISK MANAGEMENT
We are exposed to normal market risks inherent in 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 to minimize our exposure, as
described in Note 5 to the Consolidated Financial Statements, which is
incorporated by reference here.
SENSITIVITIES
(Cdn$ millions) Cash Flow Net Income
- --------------------------------------------------------------------------------
Estimated 2004 impact:
Crude Oil - US$1.00/bbl change in WTI 53 41
Natural Gas - US$0.50/mcf change 60 38
Foreign Exchange - $0.01 change in US to Cdn Dollar 21 9
-----------------------
COMMODITY PRICE RISK
Commodity price risk related to conventional and synthetic crude oil prices is
our most significant market risk exposure. Crude oil prices and quality
differentials are influenced by worldwide factors such as OPEC actions,
political events and supply and demand fundamentals.
To a lesser extent we are also exposed to natural gas price movements. Natural
gas prices are generally influenced by oil prices and North American supply and
demand, and to a lesser extent local market conditions.
NON-TRADING ACTIVITIES
The majority of our production is sold under short-term contracts, exposing us
to short-term price movements. Other energy contracts we enter into also expose
us to commodity price risk between the time we purchase and sell contracted
volumes. From time to time, we actively manage these risks by using commodity
futures, forwards, swaps and options.
In March 2003, we sold WTI and NYMEX gas forward contracts for the next 12
months to lock-in part of the return on the remaining 40% interest acquired in
the Aspen field. The forward contracts fix our oil and gas prices at the
contract prices for the hedged volumes, less applicable price differentials as
follows:
Hedged Average
Volumes Term Price
- ------------------------------------------------------------------------------------------------
(US$)
Fixed WTI Price 5,000 bbls/d April 2003 - March 2004 28.50/bbl
Fixed NYMEX Price 12,000 mmbtu/d April 2003 - March 2004 5.35/mmbtu
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
were required to deliver four million cubic feet per day of natural gas to
counterparties at prices ranging from $3.06 to $6.08 per mcf. On settlement, we
received or paid cash for the difference between the contract and floating rates
on the affected volumes. These swaps expired in 2003.
54
MARKETING AND 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 stop loss limits; 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 occurred, the key assumptions underlying our VaR
estimate could be violated and the potential loss could be greater than our
estimate. There were no changes in the methodology we used to estimate VaR in
2003.
Stress testing complements our VaR estimate. It is used to ensure that we are
not exposed to large losses, not captured by VaR, which might result from
infrequent but extreme market conditions.
Our Board of Directors has approved formal risk management policies for our
energy trading activities. 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 regularly.
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
designate 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 5 to the Consolidated Financial Statements.
INTEREST RATE RISK
We are exposed to fluctuations in short-term interest rates from our
floating-rate debt and, to a lesser extent, 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 5 to the Consolidated Financial Statements.
At December 31, 2003, we had no floating-rate debt outstanding (2002 - $nil;
2001 - $424 million).
55
CREDIT RISK
Credit risk is the risk of loss if customers or counterparties do not fulfill
their contractual obligations. Most of our receivables are with customers in the
energy industry requiring our products on an ongoing basis. These customers 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. It is also possible that derivative instrument counterparties
will not fulfill their contractual obligations. 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 we routinely monitor credit risk exposures, including sector,
geographic and corporate concentrations of credit, and report these 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, 2003:
o 90% of our counterparty exposures were investment grade; and
o only five customers individually made up greater than 5% of our
exposure from energy trading activities. All were investment grade.
CRITICAL ACCOUNTING ESTIMATES
As an oil and gas producer, there are a number of critical estimates underlying
the accounting policies we apply when preparing 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 properties. 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 activities and
production performance becomes available and as economic conditions impacting
oil and gas prices and costs change. Our reserve estimates are based on current
production forecasts, prices and economic conditions. See Business Risk
Management for a complete discussion of our reserves 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 2003, $70
million of our total $180 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 $72 million after tax.
o Calculating our unit-of-production depletion and asset retirement
obligation rates. Both proved and proved developed reserve (6)
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 and proved developed reserves are
used where a property is drilled and developed. In 2003, oil and gas
depletion, before impairment charges, and oil and gas dismantlement and
site restoration costs of $636 million and $34 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 $50 million,
after tax, assuming no other changes to our reserve profile.
- --------------------
(6) "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 recoverable
in future years from known reservoirs under existing economic and operating
conditions. Reservoirs are considered "proved" if economic producability is
supported by either actual production or a conclusive formation test.
"Proved developed" oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and
operating methods.
56
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, reserve estimation is an inferential science. As a result, the
subjective decisions, new geological or production information and a 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. Reserves information is shown
in the Supplementary Financial Information set out in Item 8 of this Form 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, changes in operating
costs, 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.
We assessed our oil and gas properties for impairment following the 2003
revisions to our reserve estimates. As a result of this assessment, it was
determined that certain Canadian oil and gas properties were impaired. These
properties were written down to their fair value which resulted in an impairment
charge of $175 million, after-tax. See Note 4 to the Consolidated Financial
Statements for further information.
Our cash flow estimates for purposes of our impairment assessments 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/bbl to US$38/bbl and US$2/mmbtu to US$10/mmbtu,
respectively. Our forecasts for oil and gas revenues are based on prices derived
from a consensus of future price forecasts amongst industry analysts and our own
assessments. Our estimates of future cash flows generally assume our long-term
price forecast and forecast operating costs. Given the significant assumptions
required and the 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.
If we decreased our long-term forecast for WTI crude oil prices by
US$1.00-1.50/bbl, our initial assessment of impairment indicators would not
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.
Any impairment charges would lower our net income.
57
NEW ACCOUNTING PRONOUNCEMENTS
CANADIAN 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 as we are already in compliance with Financial Accounting
Standards Board (FASB) Statement No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS
AND HEDGING ACTIVITIES.
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. S.3063 is
effective for fiscal years beginning on or after April 1, 2003. Adoption of
S.3063 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
liabilities. This fair value is capitalized as part of the cost of the related
assets and amortized to expense over their useful life. The liabilities accrete
until we expect to settle the retirement obligations. S.3110 is effective for
fiscal years beginning on or after January 1, 2004. The impact on our
consolidated balance sheet at January 1, 2004, will be as follows:
- -------------------------------------------------------------------------------
(Cdn$ millions) Increase/(Decrease)
- -------------------------------------------------------------------------------
Property, Plant and Equipment 81
Asset Retirement Obligation 126
Future Income Tax Liability (16)
Retained Earnings (29)
In February 2003, the CICA issued Accounting Guideline 14, DISCLOSURE OF
GUARANTEES (AcG-14). AcG-14 establishes the disclosures required for obligations
we may have under certain guarantees that we have issued. The disclosure
requirements are effective for interim and annual periods beginning on or after
January 1, 2003. We adopted FASB Interpretation No. 45, GUARANTOR'S ACCOUNTING
AND DISCLOSURE REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF
INDEBTEDNESS TO OTHERS, the US equivalent of AcG-14 for the year ended December
31, 2002. We have disclosed our guarantees in Note 10. There were no material
guarantees outstanding at December 31, 2003.
In November 2003, the CICA approved an amendment to Section 3860, FINANCIAL
INSTRUMENTS - DISCLOSURE AND PRESENTATION, to clarify the difference between an
equity and liability instrument. An equity instrument exists only when an
instrument is settled in shares. This amendment is effective for fiscal years
beginning on or after November 1, 2004. Once adopted, our preferred and
subordinated securities would be reclassified from equity to long term debt, and
the dividends paid would be classified as interest expense. Adoption of this
amendment at December 31, 2003, would increase long term debt by $313 million,
decrease preferred and subordinated securities by $364 million and increase the
cumulative translation adjustment by $51 million.
The following standards or revisions issued by the CICA do not impact us:
o Section 1100, GENERAL ACCOUNTING PRINCIPLES effective for years
beginning on or after October 31, 2003.
o Section 1400, GENERAL STANDARDS OF FINANCIAL STATEMENT PRESENTATION
effective for years beginning on or after October 31, 2003.
o Accounting Guideline 15, CONSOLIDATION OF VARIABLE INTEREST ENTITIES,
effective for annual and interim periods beginning on or after January
1, 2004.
US PRONOUNCEMENTS
The following standards issued by the FASB do not impact us:
o Statement No. 149, AMENDMENT OF STATEMENT 133 ON DERIVATIVE INSTRUMENTS
AND HEDGING ACTIVITIES, effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated
after June 30, 2003.
o Interpretation No. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES,
effective for financial statements issued after January 31, 2003.
58
ITEM 7A. 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.
(7) Forward-looking statements are generally identifiable by terms such as
ANTICIPATE, BELIEVE, INTEND, PLAN, EXPECT, ESTIMATE, BUDGET, OUTLOOK 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 or
other groups or armed other conflict, including conflict between
states.
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 factor on a particular
forward-looking statement is not determinable with certainty as these 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 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 on-stream.
We believe that any 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. We undertake no obligation to update publicly or revise any
forward-looking statements contained in this report. 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.
- --------------------
(7) 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.
59
SPECIAL NOTE TO CANADIAN INVESTORS
Nexen is a US Securities and Exchange Commission (SEC) registrant and a Form
10-K and related forms filer. Therefore, our reserves estimates and securities
regulatory disclosures generally follow SEC requirements.
In 2003, certain Canadian regulatory authorities adopted NATIONAL INSTRUMENT
51-101 - STANDARDS OF DISCLOSURE FOR OIL AND GAS ACTIVITIES (NI 51-101) which
prescribe that Canadian companies follow certain standards for the preparation
and disclosure of reserves and related information. We have been granted the
following exemptions permitting us to:
o substitute our SEC disclosures for much of the annual disclosure
required by NI 51-101;
o prepare our reserves estimates and related disclosures in accordance
with SEC requirements, generally accepted industry practices in the US
as promulgated by the Society of Petroleum Engineers, and the standards
of the Canadian Oil and Gas Evaluation Handbook (COGE Handbook)
modified to reflect SEC requirements;
o dispense with the requirement to have our reserves estimates and the
Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein, included in the Supplementary Financial Information, evaluated
or audited by independent qualified reserves evaluators; and
o not disclose certain prescribed information pertaining to prospects if
such disclosures would result in the contravention of a legal
obligation, would likely be detrimental to our competitive interests or
the information does not exist.
As a result of these exemptions, Canadian investors should note the following
fundamental differences in reserves estimates and related disclosures contained
in the Form 10-K:
o SEC registrants apply SEC reserves definitions and prepare their
reserves estimates in accordance with SEC requirements and generally
accepted industry practices in the US whereas NI 51-101 requires
adherence to the definitions and standards promulgated by the COGE
Handbook;
o the SEC mandates disclosure of proved reserves and the Standardized
Measure of Discounted Future Net Cash Flows and Changes Therein
calculated using year-end constant prices and costs only whereas NI
51-101 also requires disclosure of reserves and related future net
revenues using forecast prices;
o the SEC mandates disclosure of proved and proved producing reserves by
country only whereas NI 51-101 requires disclosure of more reserve
categories and product types;
o the SEC does not require separate disclosure of proved undeveloped
reserves or related future development costs whereas NI 51-101 requires
disclosure of more information regarding proved undeveloped reserves,
related development plans and future development costs;
o the SEC does not prescribe standards for calculating finding and
development costs per boe of proved reserves additions whereas NI
51-101 requires that finding and development costs per boe be
calculated by dividing the aggregate of exploration and development
costs incurred in the current year and the change in estimated future
development costs relating to proved reserves by the additions to
proved reserves in the current year. However, this will generally not
reflect full cycle finding and development costs related to reserve
additions for the year. Instead, we have calculated finding and
development costs by dividing exploration and development costs
incurred in the current year by the additions to proved reserves in the
current year (F&D); and
o the SEC leaves the engagement of independent qualified reserves
evaluators to the discretion of a company's board of directors whereas
NI 51-101 requires issuers to engage such evaluators and to file their
reports.
The foregoing is a general description of the principal differences only.
NI 51-101 requires that we make the following disclosures:
o we use oil equivalents (boes) to express quantities of natural gas and
crude oil in a common unit. A conversion ratio of 6 mcf of natural gas
to 1 barrel of oil is used. Boes may be misleading, particularly if
used in isolation. The conversion ratio is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.
60
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION
TABLE OF CONTENTS
REPORT OF MANAGEMENT...................................................... 62
REPORTS OF INDEPENDENT AUDITORS........................................... 63
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statement of Income .................................... 65
Consolidated Balance Sheet .......................................... 66
Consolidated Statement of Cash Flows ................................ 67
Consolidated Statement of Shareholders' Equity ...................... 68
Notes to Consolidated Financial Statements .......................... 69
SUPPLEMENTARY FINANCIAL INFORMATION (UNAUDITED)
Quarterly Financial Data in Accordance with Canadian and US GAAP..... 99
Oil and Gas Netbacks................................................. 100
Oil and Gas Producing Activities .................................... 101
61
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 over financial reporting 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 over financial reporting and an
internal audit program. We believe that the existing internal controls over
financial reporting 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. We believe our policies and procedures provide reasonable assurance
that our consolidated financial statements are prepared in accordance with
applicable securities rules and regulations. 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 four 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, reviews their fees and (subject to
applicable securities laws) pre-approves the retention of the external auditors
for any significant permitted non-audit services and the fee for such services.
The internal and external auditors have access to the Committee without the
presence of management.
/s/ Charles W. Fischer /s/ Marvin F. Romanow
- ------------------------------------- --------------------------------
President and Chief Executive Officer Executive Vice President
and Chief Financial Officer
62
REPORT OF INDEPENDENT AUDITORS
To the Shareholders of Nexen Inc.:
We have audited the consolidated balance sheet of Nexen Inc. as at December 31,
2003 and 2002 and the consolidated statements of income, cash flows and
shareholders' equity for each of the years 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 audits.
We conducted our audits 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, 2003
and 2002 and the results of its operations and its cash flows for each of the
years then ended in accordance with Canadian generally accepted accounting
principles.
The financial statements of Nexen Inc. for the year ended December 31, 2001 were
audited by other auditors who have ceased operations. Those auditors expressed
an opinion without reservation on those financial statements in their report
dated January 23, 2002. As described in Note 9, those financial statements have
been revised to give effect to the discontinued operations. We audited the
amounts reclassified as discontinued operations in the 2001 financial
statements. Also, as described in Note 1(s), certain amounts in the 2001
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(s) that relates to the 2001
financial statements. In our opinion, the adjustments related to discontinued
operations for 2001, and the reclassification of the amounts described in Note
1(s) are appropriate and have been properly applied. However, we were not
engaged to audit, review or apply any procedures to the 2001 financial
statements of Nexen Inc., other than with respect to the adjustments and
disclosures related to discontinued operations and the reclassification of the
amounts described in Note 1(s), and accordingly, we do not express an opinion or
any other form of assurance on the 2001 financial statements taken as a whole.
Calgary, Alberta /s/ Deloitte & Touche LLP
February 9, 2004 Chartered Accountants
63
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
64
NEXEN INC.
CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2003
Cdn$ millions, except per share amounts
2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------
REVENUES
Net Sales 2,908 2,506 2,497
Marketing and Other (Note 12) 610 504 475
Gain (Loss) on Disposition of Assets -- (8) 5
-------------------------------------------
3,518 3,002 2,977
-------------------------------------------
EXPENSES
Operating 751 751 758
Transportation and Other 461 475 400
General and Administrative 190 152 136
Depreciation, Depletion and Amortization (Note 4) 1,017 685 595
Exploration 200 181 260
Interest (Note 6) 105 109 112
-------------------------------------------
2,724 2,353 2,261
-------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 794 649 716
-------------------------------------------
PROVISION FOR INCOME TAXES (Note 13)
Current 210 223 216
Future (40) (12) 67
-------------------------------------------
170 211 283
-------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS 624 438 433
Net Income from Discontinued Operations (Note 9) 15 14 17
-------------------------------------------
NET INCOME 639 452 450
Dividends on Preferred Securities, Net of Income Taxes (Note 7) 40 43 39
-------------------------------------------
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 599 409 411
===========================================
EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
Basic (Note 8) 4.72 3.23 3.26
===========================================
Diluted (Note 8) 4.67 3.19 3.22
===========================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 8) 4.84 3.34 3.40
===========================================
Diluted (Note 8) 4.79 3.30 3.36
===========================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
65
NEXEN INC.
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2003 AND 2002
Cdn$ millions, except share amounts
2003 2002
- -----------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 1,087 59
Accounts Receivable (Note 2) 1,423 988
Inventories and Supplies (Note 3) 270 256
Other 79 26
--------------------------
Total Current Assets 2,859 1,329
PROPERTY, PLANT AND EQUIPMENT (Note 4) 4,469 4,863
GOODWILL 36 36
FUTURE INCOME TAX ASSETS (Note 13) 108 263
DEFERRED CHARGES AND OTHER ASSETS 153 69
--------------------------
7,625 6,560
==========================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings (Note 6) -- 18
Current Portion of Long-Term Debt (Note 6) 291 --
Accounts Payable and Accrued Liabilities 1,404 1,194
Accrued Interest Payable 44 39
Dividends Payable 12 9
--------------------------
Total Current Liabilities 1,751 1,260
--------------------------
LONG-TERM DEBT (Note 6) 2,485 1,844
FUTURE INCOME TAX LIABILITIES (Note 13) 724 873
DISMANTLEMENT AND SITE RESTORATION 179 191
OTHER DEFERRED CREDITS AND LIABILITIES 68 44
SHAREHOLDERS' EQUITY (Note 7)
Preferred and Subordinated Securities 364 724
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2003 - 125,606,107 shares
2002 - 122,965,830 shares 513 440
Contributed Surplus 1 --
Retained Earnings 1,659 1,069
Cumulative Foreign Currency Translation Adjustment (119) 115
--------------------------
Total Shareholders' Equity 2,418 2,348
--------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 10 and 13)
7,625 6,560
==========================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Approved on behalf of the Board:
/s/ Charles W. Fischer /s/ David A. Hentschel
- ---------------------- ----------------------
Director Director
66
NEXEN INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 2003
Cdn$ millions
2003 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income from Continuing Operations 624 438 433
Net Income from Discontinued Operations 15 14 17
Charges and Credits to Income not Involving Cash (Note 14) 1,020 750 713
Exploration Expense 200 181 260
Changes in Non-Cash Working Capital (Note 14) (320) (46) 143
Other (70) (15) --
--------------------------------------------
1,469 1,322 1,566
FINANCING ACTIVITIES
Proceeds from Long-Term Notes and Debentures (Note 6) 651 790 --
Repayment of Long-Term Notes and Debentures -- -- (75)
Proceeds from (Repayment of) Term Credit Facilities, Net 93 (419) (10)
Repayment of Short-Term Borrowings, Net (18) (33) (17)
Proceeds from Subordinated Securities (Note 6) 613 -- --
Redemption of Preferred Securities (Note 7) (340) -- --
Dividends on Preferred Securities (64) (72) (70)
Dividends on Common Shares (40) (37) (37)
Issue of Common Shares 73 51 39
Other (26) (23) --
--------------------------------------------
942 257 (170)
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (1,276) (1,477) (1,162)
Proved Property Acquisitions (164) (4) (122)
Chemicals, Corporate and Other (54) (144) (120)
Proceeds on Disposition of Assets 293 49 5
Changes in Non-Cash Working Capital (Note 14) (18) 7 (18)
Other -- -- (52)
--------------------------------------------
(1,219) (1,569) (1,469)
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
SHORT-TERM INVESTMENTS (164) (12) 24
--------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM INVESTMENTS 1,028 (2) (49)
CASH AND SHORT-TERM INVESTMENTS - BEGINNING OF YEAR 59 61 110
--------------------------------------------
CASH AND SHORT-TERM INVESTMENTS - END OF YEAR 1,087 59 61
============================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
67
NEXEN INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 2003
Cdn$ millions
CUMULATIVE
PREFERRED FOREIGN
AND CURRENCY
SUBORDINATED COMMON CONTRIBUTED RETAINED TRANSLATION
SECURITIES SHARES SURPLUS EARNINGS ADJUSTMENT
- ---------------------------------------------------------------------------------------------------------------------------------
(Note 7) (Note 7)
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
Exercise of Stock Options -- 50 -- -- --
Issue of Common Shares -- 23 -- -- --
Redemption of Preferred Securities
(Note 7) (393) -- -- -- --
Gain on Redemption of Preferred
Securities, Net of Income Taxes
(Note 7) -- -- -- 31 --
Issue of Subordinated Securities
(Note 7) 33 -- -- -- --
Net Income -- -- -- 639 --
Dividends on Preferred Securities,
Net of Income Taxes -- -- -- (40) --
Dividends on Common Shares -- -- -- (40) --
Stock Based Compensation Expense
(Note 7) -- -- 1 -- --
Translation Adjustment,
Net of Income Taxes -- -- -- -- (234)
----------------- -------------- ----------------- ---------------- -----------------
DECEMBER 31, 2003 364 513 1 1,659 (119)
================= ============== ================= ================ =================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
68
NEXEN INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions except as noted
1. ACCOUNTING POLICIES
Our 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. We make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the 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 (Nexen, we or our). All subsidiary companies are wholly
owned and all material intercompany accounts and transactions have been
eliminated. We conduct most exploration, development and production activities
in our oil and gas business and Syncrude 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 operations are stated
at the lower of cost and net realizable value. Cost is determined on the
first-in, first-out method or average basis.
After October 25, 2002, inventories for our marketing operation are accounted
for at the lower of cost and net realizable value determined on an average
basis. Prior to that, these inventories were reported at market value.
(d) PROPERTY, PLANT AND EQUIPMENT (PP&E)
Property, plant and equipment is recorded at cost and includes only recoverable
costs that directly result in an identifiable future benefit. Unrecoverable
costs, major maintenance and turnaround costs are expensed as incurred.
Improvements that increase capacity or extend the useful lives of the related
assets are capitalized to PP&E.
We follow successful efforts accounting for our oil and gas business. All
property acquisition costs are initially capitalized to PP&E as unproved
property costs. Once proved reserves are discovered, the acquisition costs are
reclassified to proved property acquisition costs. Exploration drilling costs
are capitalized until we determine whether the well is successful. If
successful, the costs are reclassified to proved property costs. If
unsuccessful, the exploration drilling costs are expensed to earnings. All other
exploration costs, including geological and geophysical and annual lease rentals
are expensed to earnings as incurred. All development costs are capitalized as
proved property costs. General and administrative costs that directly relate to
acquisition, exploration and development activities are capitalized to PP&E.
We engage in research and development activities to develop or improve processes
and techniques to extract oil and gas. Research involves investigating new
knowledge. Development involves translating that knowledge into a new technology
or process. Research costs are expensed as incurred. Development costs are
deferred once technical feasibility is established and we intend to proceed with
development. We defer these costs in PP&E until the commencement of commercial
operations or production. Otherwise, development costs are expensed as incurred.
Development costs include pre-operating revenues and costs.
We periodically evaluate our PP&E to ensure that the carrying value of
properties on the balance sheet is recoverable. If carrying value exceeds the
sum of undiscounted future cash flows, the property's value is impaired. The
property is assigned a fair value equal to its estimated total future cash
flows, discounted for the time value of money, and we expense the excess
carrying value to depreciation, depletion and amortization. Our 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, we deplete oil and gas costs using the
unit-of-production method. Development and exploration drilling and equipping
costs are depleted over remaining proved developed reserves and proved property
acquisition costs over proved reserves. We depreciate other plant and equipment
costs, including our chemicals facilities, using the straight-line method based
on the estimated useful lives of the assets, which range from 3 years to 30
years.
69
Unproved property costs and major projects that are under construction or
development are not depreciated, depleted or amortized.
(f) CARRIED INTEREST
We conduct certain international operations jointly with foreign governments in
accordance with production sharing agreements. Under these agreements, we pay
both our share and the government's share of operating and capital costs. We
recover the government's share of these costs from future revenues or production
over several years. The government's share of operating costs are recorded in
operating expense when incurred and capital costs are recorded in PP&E and are
expensed to DD&A in the year recovered. All recoveries are recorded as revenue
in the year of recovery.
(g) DISMANTLEMENT AND SITE RESTORATION
We provide for dismantlement and site restoration costs on our resource
properties, facilities, production platforms, pipelines and chemicals facilities
based on estimates established by current legislation and industry practices. We
record an annual provision for these costs in DD&A based on proved reserves or
estimated remaining asset lives. Actual dismantlement and site restoration
expenditures incurred in the year reduce the provision.
(h) GOODWILL
Goodwill and intangible assets with an indefinite useful life are recorded at
cost and are not amortized. We test for impairment at least annually based on
estimated future cash flows. No goodwill impairment writedowns were required.
(i) REVENUE RECOGNITION
CRUDE OIL AND NATURAL GAS
Revenue from the production of crude oil and natural gas is recognized when
title passes to the customer. In Canada and the US, our customers typically take
title when the crude oil and natural gas reaches the end of the pipeline. For
our international operations, our customers take title when the crude oil is
loaded onto the tanker. When we produce or sell more or less oil or natural gas
than our share, production overlifts and underlifts occur. We record overlifts
as liabilities, and underlifts as assets. We settle these over time as liftings
are equalized, or in cash when production ends.
Revenue represents Nexen's share and is recorded net of royalty payments to
governments and other mineral interest owners. For our international operations,
all government interests, except for income taxes, are considered royalty
payments. Our revenue also includes the recovery of costs paid on behalf of
foreign governments in international locations. See Note 1(f).
CHEMICALS
Revenue from our chemicals operations is recognized when our products reach our
customers.
MARKETING
Substantially all of the physical purchase and sale contracts entered into by
our marketing operation are considered to be derivative instruments.
Accordingly, financial and physical commodity contracts (collectively derivative
instruments) held by our marketing operation are stated at fair value on the
balance sheet date. We record any change in fair value as a gain or loss in
marketing and other. Any margin realized by our marketing department on the sale
of our proprietary oil and gas production is included in marketing and other.
(j) INCOME TAXES
We follow the liability method of accounting for income taxes (see Note 13).
This method recognizes income tax assets and liabilities at current rates, based
on temporary differences in reported amounts for financial statement and tax
purposes. The effect of a change in income tax rates on future income tax assets
and future income tax liabilities is recognized in income when substantively
enacted.
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.
(k) PETROLEUM RESOURCE RENT TAX
We treat Petroleum Resource Rent Tax on our Australian oil and gas operations as
a royalty and deduct it from sales. Any temporary differences between financial
statement and tax reported amounts, including depletion, dismantlement and site
restoration, are recorded as a future liability or asset using current tax
rates.
70
(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 designated
US-dollar debt, are included in income. We have designated 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 designated
US-dollar debt are included in the cumulative foreign currency translation
adjustment in shareholders' equity. If our US-dollar debt, net of income taxes,
exceeds our US-dollar investment in foreign operations, then the gains or losses
attributable to such excess are included in marketing and other in the
Consolidated Statement of Income.
(m) CAPITALIZED INTEREST
Prior to commercial production, we capitalize interest on major development
projects using the weighted-average interest rate on all of our borrowings.
Capitalized interest cannot exceed the actual interest expense.
(n) DERIVATIVE INSTRUMENTS
NON-TRADING ACTIVITIES
We use derivative instruments such as physical purchase and sales, forwards,
futures, swaps and options for non-trading purposes to manage fluctuations in
commodity prices, foreign currency exchange rates and interest rates (see Note
5). Hedge accounting is used when there is a high degree of correlation between
price movements in the derivative instruments and the items designated as being
hedged. Nexen formally documents all hedges and the risk management objectives.
We recognize gains and losses on the derivative instruments in the same period
as the gains or losses on the hedged items are recognized. If effective
correlation ceases, hedge accounting is terminated and future changes in the
market value of the derivative instrument are included as gains or losses in
marketing and other in the period of change.
TRADING ACTIVITIES
Our marketing operation uses derivative instruments for marketing and trading
crude oil and natural gas including:
o commodity contracts settled with physical delivery;
o exchange-traded futures and options; and
o non-exchange traded forwards, swaps and options.
We record these instruments at fair value at the balance sheet date and record
changes in market value as net gains or losses in marketing and other during the
period of change. The fair value of these instruments is recorded as accounts
receivable or payable if we anticipate settling the instruments within a year of
the balance sheet date. If we anticipate settling the instruments beyond 12
months we record them as deferred charges and other assets or other deferred
credits and liabilities.
(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 our 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 accrued benefit obligation and the fair value of plan assets, are
expensed in equal amounts over the expected average remaining service life of
the employee group. We measure the plan assets and the accrued benefit
obligation on October 31 each year.
(p) STOCK-BASED COMPENSATION
We estimate the fair value of stock options on the grant date using the
Generalized Black-Scholes option pricing model with the assumptions described in
Note 7(f). For options granted prior to January 1, 2003, we use the intrinsic
value based method and recognize no compensation expense. For options granted
after January 1, 2003, we use the fair-value based method and expense them over
the vesting period.
We provide stock appreciation rights to employees as described in Note 7.
Obligations are accrued as compensation expense over the vesting period of the
stock appreciation rights.
71
(q) CASH AND SHORT-TERM INVESTMENTS
Cash and short-term investments are instruments that mature within three months
of their purchase.
(r) TRANSPORTATION
We pay to transport the crude oil, natural gas and chemicals products that we
market, and then bill our customers for the transportation. This transportation
is presented in our Consolidated Financial Statements as a cost to us and is
recorded as transportation and other.
(s) CHANGES IN ACCOUNTING PRINCIPLES
STOCK BASED COMPENSATION
During the year, we prospectively adopted the fair-value method of accounting
for stock options granted to employees and directors. We record stock based
compensation expense on the Consolidated Statement of Income as general and
administrative expense for all options granted on or after January 1, 2003, with
a corresponding increase recorded as contributed surplus. Compensation expense
for options granted during 2003 is based on the estimated fair values at the
time of the grant and we recognize the expense over the vesting period of the
option. We recognized $1 million of compensation expense for options granted
during 2003. For options granted prior to January 1, 2003, we continue to
disclose the pro forma earnings impact of related stock based compensation
expense (see Note 7(g)).
PRESENTATION OF TRANSPORTATION
During 2002, 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
- -------------------------------------------------------------------------------
Net Sales 35 32
Marketing and Other 423 342
Transportation and Other 458 374
(t) RECLASSIFICATION
Certain information provided for prior years has been reclassified to conform to
the presentation adopted in 2003.
2. ACCOUNTS RECEIVABLE
2003 2002
- -------------------------------------------------------------------------------
Trade
Oil and Gas
Marketing 1,078 574
Other 263 330
Chemicals and Other 47 59
-------------------
1,388 963
Non-Trade 50 34
-------------------
1,438 997
Allowance for Doubtful Receivables (15) (9)
-------------------
1,423 988
===================
72
3. INVENTORIES AND SUPPLIES
2003 2002
- -------------------------------------------------------------------------------
FINISHED PRODUCTS
Oil and Gas
Marketing 138 130
Other 16 -
Chemicals and Other 12 13
-------------------
166 143
Work in Process 6 6
Field Supplies 98 107
-------------------
270 256
===================
4. PROPERTY, PLANT AND EQUIPMENT
2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Accumulated Net Book Accumulated Net Book
Cost DD&A Value Cost DD&A Value
----------------------------------------- -----------------------------------------------
Oil and Gas
Yemen 656 489 167 711 531 180
Yemen - Carried Interest 1,242 1,008 234 1,343 1,115 228
Canada 2,879 1,428 1,451 3,098 1,137 1,961
United States 2,095 854 1,241 2,186 959 1,227
Australia 172 168 4 209 184 25
Other Countries 313 198 115 305 198 107
Marketing 157 56 101 86 40 46
----------------------------------------- -----------------------------------------------
7,514 4,201 3,313 7,938 4,164 3,774
Syncrude 811 141 670 628 139 489
Chemicals 760 371 389 789 345 444
Corporate and Other 168 71 97 213 57 156
----------------------------------------- -----------------------------------------------
9,253 4,784 4,469 9,568 4,705 4,863
========================================= ===============================================
The above table includes capitalized costs of $630 million (2002 - $585 million)
relating to unproved properties and projects under construction or development.
These costs are not being depreciated, depleted or amortized.
Our 2003 depreciation, depletion and amortization expense in the Consolidated
Statement of Income includes an impairment charge of $269 million ($175 million
net of income tax) relating to certain Canadian oil and gas properties. The
impairment results from negative reserve revisions and is largely attributable
to Canadian heavy oil properties. The revisions resulted from changes in late
field-life economic assumptions, changes in proved undeveloped reserves based on
drilling results and geological mapping, and reassessments of estimated future
production profiles. Even though we expect to recover the carrying value of our
Canadian oil and gas properties in aggregate from their future cash flows, under
successful efforts accounting, we are required to make impairment assessments on
a property-by-property basis. The impairment charge represents the write-down of
the carrying value of the impaired properties to their estimated fair value. We
have determined the estimated fair value of the impaired properties based on the
present value of the expected future net cash flows we expect to receive from
the properties.
We incurred $20 million (2002 - $6 million) related to research and development
activity. Costs of $14 million (2002 - $6 million) were recorded in other
expense on the Consolidated Statement of Income. The remaining costs have been
deferred and are included in PP&E.
2003 2002
- --------------------------------------------------------------------------------
Development Costs Deferred, Beginning of Year -- --
Deferred in the Year 6 --
Amortized in the Year -- --
----------------------
Development Costs Deferred, End of Year 6 --
======================
73
5. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
The nature of our operations and long-term debt expose us to fluctuations in
commodity prices, foreign-currency exchange rates, interest rates and credit
risk. We recognize these risks and manage our operations to minimize our
exposure to the extent practical and, to a lesser extent, using derivative
instruments. Our marketing operation uses derivative instruments to manage its
exposure to commodity price fluctuations and for trading purposes. We use
physical purchases and sales contract, exchange-traded futures and options and
non-exchange traded forwards, swaps and options, which may be settled in cash or
by delivery of the physical commodity. The Finance Committee of the Board of
Directors and our Risk Management Committee monitor our exposure to the above
risks and regularly review our derivative activities and all outstanding
positions.
The carrying value, fair value, and unrecognized gains or losses on our
outstanding derivatives and long-term financial assets and liabilities at
December 31 are:
Cdn$ millions 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Carrying Fair Unrecognized Carrying Fair Unrecognized
Net Assets/(Liabilities) Value Value Gain/(Loss) Value Value Gain/(Loss)
----------------------------------------- -------------------------------------
Commodity Price Risk -
Non-Trading Activities
Natural Gas Swaps -- -- -- -- 2 2
Future Sale of Oil and Gas
Production -- (3) (3) -- -- --
Commodity Price Risk--
Trading Activities
Crude Oil and Natural Gas 106 106 -- 3 3 --
Future Sale of Gas Inventory -- (11) (11) -- -- --
Foreign Currency Risk -- (1) (1) -- (3) (3)
----------------------------------------- -------------------------------------
Total Derivatives 106 91 (15) 3 2 (1)
========================================= =====================================
Financial Assets and Liabilities
Long-Term Debt (2,485) (2,706) (221) (1,844) (1,948) (104)
Preferred and Subordinated
Securities (364) (319) 45 (724) (756) (32)
----------------------------------------- -------------------------------------
(2,849) (3,025) (176) (2,568) (2,704) (136)
========================================== ======================================
The estimated fair value of all derivative instruments is based on quoted market
prices and, if not available, on estimates from third-party brokers or dealers.
The carrying value of cash and short-term investments, amounts receivable and
short-term obligations approximates their fair value because the instruments are
near maturity.
(a) COMMODITY PRICE RISK MANAGEMENT
NON-TRADING ACTIVITIES
We generally sell our crude oil and natural gas under short-term market based
contracts.
NATURAL GAS SWAPS
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
were required to deliver 4 million cubic feet per day of natural gas to
counterparties at prices ranging from $3.06 to $6.08 per thousand cubic feet. On
settlement, we either paid or received cash for the difference between the
contract and floating rates. These swaps expired in 2003.
74
FUTURE SALE OF OIL AND GAS PRODUCTION
In March 2003, we sold WTI and NYMEX gas forward contracts for the next 12
months to lock-in part of the return on the remaining 40% interest acquired in
the Aspen field. The forward contracts fix our oil and gas prices at the
contract prices for the hedged volumes, less applicable price differentials.
Unrecognized losses on these contracts are:
Hedged Average Unrecognized
Volumes Term Price Loss
- ------------------------------------------------------------------------------------------------------------------------------
(US$) (Cdn$ millions)
Fixed WTI Price 5,000 bbls/d April 2003 - March 2004 28.50/bbl (2)
Fixed NYMEX Price 12,000 mmbtu/d April 2003 - March 2004 5.35/mmbtu (1)
------------
(3)
============
TRADING ACTIVITIES
CRUDE OIL AND NATURAL GAS
Our marketing operation engages in crude oil and natural gas marketing
activities to enhance prices from the sale of our oil and gas production, and
for energy trading. As part of our strategy:
o we enter into contracts to purchase and sell crude oil and natural gas;
o we inject and withdraw natural gas into and from storage to take
advantage of seasonal changes in demand; and
o we create net open positions to take advantage of market conditions.
These contracts and positions expose us to changes in market prices. To mitigate
this price risk, we use energy-related futures, forwards, swaps and options. We
also balance physical and financial contracts in terms of volumes, timing of
performance and delivery obligations.
TOTAL CARRYING VALUE OF DERIVATIVE ENERGY CONTRACTS
Amounts related to derivative energy instruments held by our marketing operation
are equal to fair value as we use mark-to-market accounting, and are as follows
at December 31:
Cdn $millions 2003 2002
- -------------------------------------------------------------------------------
Accounts Receivable 102 42
Deferred Charges and Other Assets (1) 63 14
-------------------
Total Derivative Energy Contract Assets 165 56
===================
Accounts Payable and Accrued Liabilities 34 46
Other Deferred Credits and Liabilities (1) 25 7
-------------------
Total Derivative Energy Contract Liabilities 59 53
===================
Total Derivative Energy Contract Net Assets 106 3
===================
Note:
(1) These derivative instruments settle beyond 12 months and are considered
non-current.
75
FUTURE SALE OF GAS INVENTORY
Our marketing inventory is carried at the lower of cost and net realizable value
while generally our derivative contracts are stated at market value. To better
match our accounting with our economic exposure, we began designating certain
NYMEX natural gas futures contracts and AECO/NYMEX basis swaps in July 2003 as
hedges of our price risk on the future sale of our inventory. We have designated
in writing some of our financial contracts as cash flow hedges. The principal
terms of these outstanding contracts and the unrecognized losses at December 31,
2003 are:
Hedged Average Unrecognized
Volumes Month Price Loss
- -------------------------------------------------------------------------------------------------------
(mmcf) (US$ mcf) (Cdn$ millions)
NYMEX Natural Gas Futures 5,610 January 2004 4.91 - 6.19 (6)
3,850 February 2004 4.93 - 6.09 (3)
150 March 2004 4.85 --
1,500 April 2004 4.76 (1)
AECO/NYMEX Basis Swaps 380 January 2004 5.51 (1)
300 February 2004 5.15 --
------------
(11)
============
Our marketing strategy enables our marketing operation to generate income using
competitive information from marketing activities, but it exposes us to risks of
loss from fluctuating market prices. Our exposure is restricted to prescribed
limits and is monitored daily using value-at-risk measures, 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 margins from trading activities and our
value-at-risk are:
2003 2002 2001
- ----------------------------------------------------------------------------
Net Revenue 568 496 438
Less: Transportation (398) (423) (342)
Other (1) -- --
--------------------------------
169 73 96
================================
Value-at-Risk
Year End 21 19 19
================================
Average 20 17 13
================================
(b) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
Many of our activities are transacted in or referenced to US dollars including:
o sales of crude oil, natural gas and certain chemicals products;
o capital spending and expenses for 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
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. Until 2003, all of our
US-dollar debt was designated as a hedge against our net investment in foreign
operations. In early 2003, we de-designated our unsecured syndicated term credit
facilities from the hedge as funds drawn were used to fund US-dollar working
capital in our Canadian operations. Our remaining US-dollar debt continued to be
designated as a hedge against our net investment in foreign operations. In the
third quarter of 2003, we re-designated our unsecured syndicated term credit
facilities, as US-dollar funds drawn were no longer funding working capital in
our Canadian operations. The US-dollar debt issued in November 2003 to
re-finance existing designated US-dollar debt was designated as part of the
hedge in February 2004.
76
The foreign exchange gains or losses related to the designated debt are included
in the cumulative foreign currency translation adjustment in shareholders'
equity. The exchange gains and losses on the unsecured syndicated term credit
facilities during the de-designated period were included in marketing and other.
Foreign exchange gains or losses on the November 2003 debt issues were included
in marketing and other. Our net investment in foreign operations and our
designated US-dollar long-term debt at December 31 are as follows:
(US$ millions) 2003 2002
- ----------------------------------------------------------------------------
Net Investment in Foreign Operations 1,574 1,389
Long-Term Debt 925 962
--------------------
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, 2003, 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 6).
(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 and facilities. At December 31, 2003, fixed-rate borrowings comprised
100% (2002 - 100%) of our long-term debt at an effective average rate of 6.8%
(2002 - 7.4%). During the year we periodically drew on our floating rate
unsecured syndicated term credit facilities. We had no interest rate swaps
outstanding in 2003 or 2002.
(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 credit ratings 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.
6. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
2003 2002
- ------------------------------------------------------------------------------
Unsecured Syndicated Term Credit Facilities (a) -- --
Unsecured Redeemable Notes, due 2004 (b) 291 355
Unsecured Redeemable Debentures, due 2006 (c) 98 108
Unsecured Redeemable Medium Term Notes, due 2007 (d) 150 150
Unsecured Redeemable Medium Term Notes, due 2008 (e) 125 125
Unsecured Redeemable Notes, due 2013 (f) 646 --
Unsecured Redeemable Notes, due 2028 (g) 258 316
Unsecured Redeemable Notes, due 2032 (h) 646 790
Unsecured Subordinated Debentures, due 2043 (i) 562 --
-----------------
2,776 1,844
Less: Current Portion of Long-Term Debt 291 --
-----------------
2,485 1,844
=================
(a) UNSECURED SYNDICATED TERM CREDIT FACILITIES
Nexen has committed, unsecured, revolving term credit facilities totalling
$1,656 million, $410 million of which is available until 2007 and $1,246 million
until 2008. The lenders have the option to extend the terms annually. No
repayments are required until the end of the availability periods. Borrowings
are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian
prime loans or US-dollar base rate loans. Interest is payable monthly at a
floating rate. During 2003, the weighted average interest rate was 2.0% (2002 -
2.5%).
77
(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 was repaid at par in
February 2004. The notes have been included as a current liability on the
Consolidated Balance Sheet.
(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%.
(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 2013
During November 2003, we issued US$500 million of notes. Interest is payable
semi-annually at a rate of 5.05% and the principal is to be repaid in November
2013. We may redeem part or all of the notes at any time. The redemption price
will be the greater of par and an amount that provides the same yield as a US
Treasury security having a term to maturity equal to the remaining term of the
notes plus 0.2%. Included in deferred charges and other assets at December 31,
2003 are issue costs of US$8 million which are amortized to earnings over the
term of the issue.
(g) 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%.
(h) 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 at December 31,
2003 is a debt discount of US$13 million (2002 - US$14 million) which is
amortized to earnings over the term of the debt issue.
(i) UNSECURED SUBORDINATED DEBENTURES, DUE 2043
On November 4, 2003, we issued US$460 million of unsecured subordinated
debentures. Interest is payable quarterly in cash. We may redeem part or all of
the debentures at any time on or after November 8, 2008. The redemption price is
equal to the par value of the principal amount plus any accrued and unpaid
interest to the redemption date. We may choose to redeem the principal amount
with either cash or common shares. As a result, we are required to classify the
carrying value of the debentures into debt and equity components. The debt
component of US$435 million represents the present value of future interest
payments. The remaining US$25 million represents the equity component and has
been recorded in shareholders' equity (see Note 7(a)). Included in deferred
charges and other assets at December 31, 2003 are issue costs of US$12 million
which are amortized to earnings over the term of the issue.
78
(j) DEBT REPAYMENTS
- -----------------------------------------------------------------------------
2004 291
2005 -
2006 98
2007 150
2008 125
Thereafter 2,112
--------
2,776
========
(k) DEBT COVENANTS
Most of our debt instruments contain covenants with respect to certain financial
ratios and our ability to grant security. At December 31, 2003, we were in
compliance with all covenants.
(l) SHORT-TERM BORROWINGS
Nexen has unsecured operating loan facilities of approximately $328 million.
Interest is payable at floating rates and the facilities are subject to periodic
reviews. During 2003, the weighted average interest rate on short-term
borrowings was 2.4% (2002 - 2.3%).
Occasionally, we sell the future proceeds of our accounts receivable; however,
we retain a 10% exposure to related credit losses. At December 31, 2003, we did
not sell any of our accounts receivable proceeds. At December 31, 2002 we sold
$178 million of accounts receivable and retained a credit exposure of $18
million which was included in short-term borrowings. During 2003, this credit
exposure was eliminated as the receivable proceeds were fully collected.
(m) INTEREST EXPENSE
2003 2002 2001
- -------------------------------------------------------------------------------
Long-Term Debt 140 134 106
Other 8 6 6
------------------------------
Total 148 140 112
Less: Capitalized 43 31 --
------------------------------
105 109 112
==============================
Capitalized interest relates to and is included as part of the cost of oil and
gas properties. The capitalization rates are based on our weighted-average cost
of borrowings.
7. SHAREHOLDERS' EQUITY
(a) PREFERRED AND SUBORDINATED SECURITIES
Principal Amount Interest Rate Maturity Date First Call Date
- ------------------------------------------------------------------------------------------------------------------------------
(US$ millions) (%)
Preferred Securities 259 9.75 October 30, 2047 October 30, 2003
Preferred Securities 217 9.375 March 31, 2048 February 9, 2004
Subordinated Securities (Note 6(i)) 25 7.35 November 4, 2043 November 8, 2008
-------------------------------------------------------------------------------------
Nexen may redeem part or all of the preferred securities at any time on or after
their 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.
On December 15, 2003, we redeemed $393 million (US$259 million) of preferred
securities at par. On redemption we realized a gain of $31 million, net of
income tax, for the difference between the carrying value and the settlement
amount. This gain related to the change in foreign exchange rates between the
date of issue and settlement, and has been included in retained earnings.
79
On January 9, 2004, we gave notice to redeem our US$217 million preferred
securities. These securities were redeemed at par on February 9, 2004. The
realized foreign exchange gain of $34 million, net of income taxes, for the
difference between the carrying value and the settlement amount was included in
retained earnings in 2004.
(b) AUTHORIZED CAPITAL
Authorized share capital consists of an unlimited number of common shares of no
par value, and an unlimited number of Class A preferred shares of no par value,
issuable in series.
(c) ISSUED COMMON SHARES AND DIVIDENDS
(thousands of shares) 2003 2002 2001
- --------------------------------------------------------------------------------
Beginning of Year 122,966 121,202 119,855
Issue of Common Shares for Cash:
Exercise of Stock Options 1,964 1,090 648
Dividend Reinvestment Plan 476 500 533
Employee Flow-through Shares 200 174 166
---------------------------------
End of Year 125,606 122,966 121,202
=================================
Dividends per Common Share ($/share) 0.325 0.30 0.30
=================================
Cash Consideration (Cdn$ millions)
Exercise of Stock Options 50 27 16
Dividend Reinvestment Plan 15 17 17
Employee Flow-through Shares 8 7 6
---------------------------------
73 51 39
=================================
At December 31, 2003, there were 1,307,305 (2002 - 1,783,968; 2001 - 489,329)
common shares reserved for issuance under the Dividend Reinvestment Plan.
(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 Nexen common share 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 equals the market price.
The following options have been granted:
Weighted-Average
Options Exercise Price
- --------------------------------------------------------------------------------
(thousands) ($/option)
DECEMBER 31, 2000 7,976 29
Granted 1,645 31
Exercised (648) 24
Forfeited (142) 30
-----------
DECEMBER 31, 2001 8,831 30
Granted 1,788 31
Exercised (1,090) 25
Forfeited (53) 30
-----------
DECEMBER 31, 2002 9,476 30
Granted 1,877 44
Exercised (1,964) 28
Forfeited (186) 32
-----------
DECEMBER 31, 2003 9,203 34
===========
OPTIONS EXERCISABLE AT DECEMBER 31
2001 4,232 27
2002 5,113 29
2003 5,067 30
-----------------------------------
80
At December 31, 2003 there were 9,787,833 (2002 - 9,759,545; 2001 - 10,896,060)
common shares reserved for issuance under the stock option plan and there were
9,203,121 (2002 - 9,475,985; 2001 - 8,831,235) outstanding options.
(e) EXERCISE PRICE RANGE
Outstanding Options Exercisable Options
- ------------------------------------------------------------------------------------------------------------------------------
Weighted- Weighted- Weighted-
Average Average Average
Number of Exercise Years to Number of Exercise
Options Price Expiry Options Price
------------------------------------------- --------------------------------
(thousands) ($/option) (years) (thousands) ($/option)
$12.13 to $19.99 416 18 5 416 18
$20.00 to $24.99 176 23 3 176 23
$25.00 to $29.99 1,828 28 5 1,709 28
$30.00 to $34.99 2,729 33 4 1,151 32
$35.00 to $39.99 2,169 36 7 1,607 36
$40.00 to $44.99 1,885 44 5 8 40
------------------------------------------- --------------------------------
9,203 5,067
=============== ===============
(f) ESTIMATED FAIR-VALUE OF STOCK OPTIONS
We estimate the fair value of stock options issued using the Generalized
Black-Scholes option pricing model under the following assumptions:
2003 2002 2001
- ------------------------------------------------------------------------------------------------------
Weighted-Average Fair Value ($/option) 10.10 9.08 12.24
Risk-Free Interest Rate (%) 3.6 3.6 5.1
Estimated Hold Period Prior to Exercise (years) 3 3 5
Volatility in the Price of Nexen's Common Shares (%) 30 35 40
Dividends per Common Share ($/share) 0.40 0.30 0.30
-----------------------------------
(g) PRO FORMA NET INCOME - FAIR-VALUE METHOD OF ACCOUNTING FOR STOCK
OPTIONS
The following shows pro forma net income and earnings per common share had we
applied the fair-value method to account for all stock options outstanding that
were granted up to December 31, 2002. Stock options granted after that date have
been expensed as general and administrative costs.
2003 2002 2001
- ------------------------------------------------------------------------------------------------------
Fair Value of Stock Options Granted 25 22 25
Less: Fair Value of Stock Options Expensed (1) - -
-----------------------------------
24 22 25
Net Income Attributable to Common Shareholders
As Reported 599 409 411
-----------------------------------
Pro Forma 575 387 386
===================================
Earnings Per Common Share ($/share)
Basic as Reported 4.84 3.34 3.40
===================================
Pro Forma 4.65 3.16 3.20
===================================
Diluted as Reported 4.79 3.30 3.36
===================================
Pro Forma 4.60 3.13 3.16
===================================
81
(h) STOCK APPRECIATION RIGHTS
Under our stock appreciation rights plan established in 2001, 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.
2003 2002 2001
- --------------------------------------------------------------------------------
Weighted Average Exercise Price ($/right) 42.67 33.94 31.17
Rights Expensed ($ millions) 14 2 --
-----------------------------
The following stock appreciation rights have been granted:
Rights
- ------------------------------------------------------------------------------
(thousands)
DECEMBER 31, 2000 --
Granted 915
------------
DECEMBER 31, 2001 915
Granted 908
Exercised (3)
Forfeited (8)
------------
DECEMBER 31, 2002 1,812
Granted 1,017
Exercised (363)
Forfeited (62)
------------
DECEMBER 31, 2003 2,404
============
8. EARNINGS PER COMMON SHARE
We calculate basic earnings per common share from continuing operations using
net income from continuing operations less dividends on preferred securities,
net of income taxes, divided by weighted average number of common shares
outstanding. We calculate basic 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 from
continuing operations and diluted earnings per common share in the same manner
as basic, except we use the weighted-average number of diluted common shares
outstanding in the denominator.
(millions of shares) 2003 2002 2001
- --------------------------------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 123.8 122.4 120.7
Shares issuable pursuant to stock options 6.2 8.1 4.7
Shares to be purchased from proceeds of stock options (5.1) (6.7) (3.3)
------------------------------------------
Weighted-average number of diluted common shares outstanding 124.9 123.8 122.1
==========================================
In calculating diluted earnings per common share for the year ended December 31,
2003, we excluded 2,817,023 options (2002 - 46,167; 2001 - 2,992,903), because
the exercise price was greater than the annual average market price of our
common shares in those periods. During these three years, outstanding stock
options were the only dilutive instrument.
82
9. DISCONTINUED OPERATIONS
On August 28, 2003, we sold certain non-core conventional light oil properties
in southeast Saskatchewan in Canada. Net proceeds were $268 million and there
was no gain or loss on the sale. The results of operations from these properties
are detailed below and shown as discontinued operations in our Consolidated
Statement of Income.
2003 2002 2001
- -------------------------------------------------------------------------------
Revenues
Net Sales 66 100 96
Expenses
Operating 16 25 23
Depreciation, Depletion and Amortization 20 35 30
Exploration 1 8 5
------------------------------
Income before Income Taxes 29 32 38
Future Income Taxes 14 18 21
------------------------------
Net Income from Discontinued Operations 15 14 17
==============================
Earnings Per Common Share ($/share)
Basic (Note 8) 0.12 0.11 0.14
==============================
Diluted (Note 8) 0.12 0.11 0.14
==============================
Assets and liabilities on the Consolidated Balance Sheet include the following
amounts for discontinued operations.
December 31 December 31
2003 2002
- --------------------------------------------------------------------------------
Accounts Receivable -- 12
Property, Plant and Equipment -- 289
Accounts Payable and Accrued Liabilities -- 9
Dismantlement and Site Restoration -- 10
---------------------------
10. COMMITMENTS, CONTINGENCIES AND GUARANTEES
2004 2005 2006 2007 2008 THEREAFTER
- -----------------------------------------------------------------------------------------------------------
Operating leases 33 38 20 19 16 91
Transportation commitments 212 94 78 52 33 111
-----------------------------------------------------------------------
245 132 98 71 49 202
=======================================================================
We have a number of lawsuits and claims pending including income tax
reassessments (see Note 13), for which we currently cannot determine the
ultimate result. We record costs as they are incurred or become determinable. We
believe the resolution of these matters would not have a material adverse effect
on our liquidity, consolidated financial position or results of operations.
During 2003, total rental expense was $49 million (2002 - $47 million; 2001 -
$42 million).
From time to time we enter into certain types of contracts that require us to
indemnify parties against possible third party claims particularly when these
contracts relate to divestiture transactions. On occasion we may provide routine
indemnifications. The terms of such obligations vary and generally, a maximum is
not explicitly stated. Because the obligations in these agreements are often not
explicitly stated, the overall maximum amount of the obligations cannot be
reasonably estimated. Historically, we have not been obligated to make
significant payments for these obligations. Our Risk Management Committee
actively monitors our exposure to the above risks and obtains insurance coverage
to satisfy potential or future claims as necessary. We believe that payments, if
any, related to such matters would not have a material adverse effect on our
liquidity, financial condition or results of operations.
83
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 we disclose only our
share of this plan. Under these defined benefit plans, we provide benefits to
retirees based on their length of service and final average earnings. Benefits
paid out of Nexen's defined benefit plan are indexed to 75% of the annual rate
of inflation.
(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 these plans 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.
2003 2002
- ---------------------------------------------------------------------------------------------------------------------------
Change in Projected Benefit Obligation (PBO) Nexen Syncrude Nexen Syncrude
------------------------------ --------------------------------
Beginning of Year 164 68 163 63
Service Cost 7 3 7 3
Interest Cost 11 4 10 4
Plan Participants' Contributions 2 - 2 -
Actuarial Loss/(Gain) 14 6 (11) -
Benefits Paid (6) (2) (7) (2)
------------------------------ --------------------------------
End of Year (1) 192 79 164 68
------------------------------ --------------------------------
Change in Fair Value of Plan Assets
Beginning of Year 127 37 136 41
Actual Return on Plan Assets 15 7 (7) (3)
Employer's Contribution 16 2 3 1
Plan Participants' Contributions 2 - 2 -
Benefits Paid (6) (2) (7) (2)
------------------------------ --------------------------------
End of Year 154 44 127 37
------------------------------ --------------------------------
Reconciliation of Funded Status
Funded Status (2) (38) (35) (37) (31)
Unamortized Transitional Obligation 1 - 1 -
Unamortized Prior Service Costs 5 - 6 1
Unamortized Net Actuarial Loss 26 25 19 23
------------------------------ --------------------------------
Pension Liability (6) (10) (11) (7)
------------------------------ --------------------------------
Pension Liability Recognized:
Deferred Charges and Other Assets 15 - 7 -
Other Deferred Credits and Liabilities (21) (10) (18) (7)
------------------------------ --------------------------------
Pension Liability (6) (10) (11) (7)
------------------------------ --------------------------------
Assumptions (%)
Discount Rate 6.25 (4) 6.00 (4) 6.75 (3) 6.50 (3)
Long-Term Rate of Employee Compensation
Increase 4.00 (4) 4.00 (4) 4.00 (3) 4.00 (3)
Long-Term Annual Rate of Return on Plan Assets (5) 7.00 (4) 9.00 (4) 7.00 (3) 9.00 (3)
---------------------------------------------------------------------
Notes:
(1) Nexen's employee pension plan's accumulated benefit obligation (the
projected benefit obligation excluding future salary increases) was $139
million at December 31, 2003. Nexen's supplemental pension plan's
accumulated benefit obligation was $19 million at December 31, 2003.
Nexen's share of Syncrude's employee pension plan's accumulated benefit
obligation was $56 million at December 31, 2003.
(2) Includes unfunded obligations for supplemental benefits to the extent that
the benefit is limited by statutory guidelines. At December 31, 2003, the
PBO for supplemental benefits was $29 million (2002 - $26 million).
(3) The assumptions have been used to calculate the October 31, 2002 PBO and
the 2003 recognized expense.
(4) The assumptions have been used to calculate the October 31, 2003 PBO and
the 2004 recognized expense for Nexen. There were no changes to the
assumptions between the measurement date and December 31, 2003. Syncrude's
measurement date was December 31, 2003.
(5) The long-term rate of return on plan assets assumption is based on a mix of
historical market returns from debt and equity securities.
84
NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS
2003 2002 2001
- -------------------------------------------------------------------------------
Nexen
Cost of Benefits Earned by Employees 7 7 5
Interest Cost on Benefits Earned 11 10 9
Expected Return on Plan Assets (9) (10) (10)
Net Amortization and Deferral 1 1 -
-------------------------------
Net 10 8 4
-------------------------------
Syncrude
Cost of Benefits Earned by Employees 3 3 2
Interest Cost on Benefits Earned 4 4 4
Expected Return on Pension Plan Assets (3) (4) (4)
Net Amortization and Deferral 1 1 -
-------------------------------
Net 5 4 2
-------------------------------
-------------------------------
Total 15 12 6
===============================
(b) PLAN ASSET ALLOCATION AT DECEMBER 31
Our investment goal for the assets in our defined benefit pension plan is to
preserve capital and earn a long-term rate of return on assets, net of all
management expenses, in excess of the inflation rate. Investment funds are
managed by external fund managers based on policies mandated by our Board of
Directors and Pension Committee. Nexen's investment strategy is to diversify
plan assets between debt and equity securities of Canadian and non-Canadian
corporations, that are traded on recognized stock exchanges. A fund's market
value may not exceed a maximum in any one issuer at the time of purchase, as set
out by our investment policy provided to fund managers. Allowable and prohibited
investment types are also prescribed in Nexen's investment policy.
Syncrude's pension plan is governed and administered separately from ours.
Syncrude's investment assets are subject to a similar investment goal, policy
and strategy.
EXPECTED
(%) 2004 2003 2002
- -----------------------------------------------------------------------------
Nexen
Equity Securities 60 52 54
Debt Securities 40 40 42
Real Estate - - -
Other - 8 4
---------------------------------------------
Total 100 100 100
=============================================
Syncrude
Equity Securities 70 72 70
Debt Securities 30 28 30
Real Estate - - -
Other - - -
---------------------------------------------
Total 100 100 100
=============================================
(c) DEFINED CONTRIBUTION PENSION PLANS
Under these plans, pension benefits are based on plan contributions. During
2003, Canadian pension expense for these plans was $4 million (2002 - $3
million; 2001 - $3 million). During 2003, US pension expense for these plans was
$3 million (2002 - $3 million; 2001 - $3 million).
(d) 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. The present value of Nexen employees'
future post retirement benefits in 2003 was $5 million (2002 - $4 million).
Nexen's share of post-retirement and post-employment benefits related to
Syncrude in 2003 was $6 million (2002 - $6 million).
85
(e) EMPLOYER FUNDING CONTRIBUTIONS AND BENEFIT PAYMENTS
Canadian regulators have prescribed funding requirements for our defined benefit
plans. Our funding contributions over the last three years have met these
requirements and also included additional discretionary contributions permitted
by law. For our defined contribution plans, we always match the employee
contribution and no further obligation exists. Our funding contributions for the
defined benefit plans are:
EXPECTED
2004 2003 2002
- -----------------------------------------------------------------------------
Nexen
Defined Benefit 6 15 2
Other -- 1 1
---------------------------------------
Total Funding Contributions 6 16 3
=======================================
Syncrude
Defined Benefit 4 2 1
Other -- -- --
---------------------------------------
Total Funding Contributions 4 2 1
=======================================
Our most recent funding valuation was prepared as of June 30, 2003. Our next
funding valuation is required by June 30, 2006. Syncrude's most recent funding
valuation was prepared as of January 1, 2001. Syncrude's next funding valuation
is January 1, 2004.
Our total benefit payments in 2003, were $6 million (2002 - $7 million). Our
share of Syncrude's total benefit payments in 2003 was $2 million (2002 - $2
million). Our estimated future payments are as follows:
Defined Benefit Other
- ----------------------------------------------------------------------------
Nexen Syncrude Nexen Syncrude
----------------------------------------------
2004 7 2 1 --
2005 8 2 1 --
2006 8 3 1 --
2007 9 3 1 --
2008 9 3 2 --
2009 - 2013 60 23 10 2
12. MARKETING AND OTHER
2003 2002 2001
- -------------------------------------------------------------------------------
Marketing Revenue, Net 568 496 438
Interest 9 7 17
Foreign Exchange Gains (Losses) 6 (3) -
Other 27 4 20
----------------------------------
----------------------------------
610 504 475
==================================
For 2003, other includes $12 million of business interruption proceeds received
from our insurers. The proceeds result from damage sustained in the Gulf of
Mexico during tropical storm Isidore and Hurricane Lili in the third and fourth
quarters of 2002.
86
13. INCOME TAXES
(a) TEMPORARY DIFFERENCES
2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Future Future Future Future
Income Tax Income Tax Income Tax Income Tax
Assets Liabilities Assets Liabilities
---------------------------------- --------------------------------
Property, Plant and Equipment, Net 26 523 23 704
Tax Losses Carried Forward 69 -- 226 --
Deferred Income -- 200 -- 177
Recoverable Taxes 13 -- 14 --
Other -- 1 -- (8)
---------------------------------- --------------------------------
108 724 263 873
================================== ================================
(b) CANADIAN AND FOREIGN INCOME TAXES
2003 2002 2001
- -------------------------------------------------------------------------------
Income before Income Taxes:
From Continuing Operations
Canadian (173) 108 187
Foreign 967 541 529
-----------------------------------
794 649 716
From Discontinued Operations 29 32 38
-----------------------------------
823 681 754
===================================
Provision for Income Taxes:
Current
Canadian 5 4 6
Foreign 205 219 210
-----------------------------------
210 223 216
-----------------------------------
Future
From Continuing Operations
Canadian (105) 20 60
Foreign 65 (32) 7
-----------------------------------
(40) (12) 67
From Discontinued Operations 14 18 21
-----------------------------------
(26) 6 88
===================================
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 include Yemen cash taxes of $201
million (2002 - $207 million; 2001 - $191 million). Income taxes from our
discontinued operations are Canadian.
87
(c) RECONCILIATION OF EFFECTIVE TAX RATE TO THE CANADIAN FEDERAL TAX RATE
2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
Income before Income Taxes
From Continuing Operations 794 649 716
From Discontinued Operations 29 32 38
------------------------------------------
823 681 754
==========================================
Provision for Income Taxes Computed at the Canadian Statutory Rate 304 269 317
Add (Deduct) the Tax Effect of:
Royalties and Rentals to Provincial Governments 51 57 66
Resource Allowance and Provincial Tax Rebates (55) (67) (68)
Lower Tax Rates on Foreign Operations (54) (37) (15)
Additional Canadian Tax on Canadian Resource Income 12 8 2
Federal and Provincial Capital Tax 4 4 5
Revaluation of the Future Tax Liability for the Reductions in the Statutory (76) (1) (5)
Rates
Other (2) (4) 2
------------------------------------------
Provision for Income Taxes 184 229 304
==========================================
During the last three years, the federal and some provincial governments in
Canada reduced statutory income tax rates. In 2003, this reduced our liability
and provision for future income taxes by $76 million (2002 - $1 million; 2001 -
$5 million).
(d) AVAILABLE UNUSED TAX LOSSES AND TAX CONTINGENCIES
At December 31, 2003, we had unused tax losses totalling $195 million (2002 -
$534 million) mostly from 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, we believe we have an 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 our evaluation of the potential impact of these issues.
14. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
2003 2002 2001
- -------------------------------------------------------------------------------------------------------
Depreciation, Depletion and Amortization 1,017 685 595
Loss (Gain) on Disposition of Assets -- 8 (5)
Future Income Taxes (40) (12) 67
Non-Cash Items included in Discontinued Operations 35 61 56
Other 8 8 --
------------------------------------------
1,020 750 713
==========================================
88
(b) CHANGES IN NON-CASH WORKING CAPITAL
2003 2002 2001
- -------------------------------------------------------------------------------------------------------
Operating Activities
Accounts Receivable (488) (388) 471
Inventories and Supplies (45) (73) 73
Other Current Assets (59) (6) (5)
Accounts Payable and Accrued Liabilities 260 404 (397)
Accrued Interest Payable 9 17 1
Dividends Payable 3 -- --
------------------------------------------
(320) (46) 143
Investing Activities
Accounts Payable and Accrued Liabilities (18) 7 (18)
------------------------------------------
Total (338) (39) 125
==========================================
(c) OTHER CASH FLOW INFORMATION
2003 2002 2001
- -------------------------------------------------------------------------------------------------------
Interest Paid 133 117 106
Income Taxes Paid 211 238 211
------------------------------------------
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. Our other operations are primarily in West Africa, Australia and
Colombia. 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 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.
89
2003 OPERATING AND GEOGRAPHIC SEGMENTS
(Cdn$ millions)
Corporate
and
Oil and Gas Syncrude Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(1) Marketing(2)
-------------------------------------------------------------
Net Sales (3) 827 609 707 64 65 21 240 375 (4) -- 2,908
Marketing and Other 6 5 14 -- -- 568 -- 2 15 (5) 610
Gain (Loss) on Disposition of -- -- -- -- -- -- -- -- -- --
Assets
------------------------------------------------------------------------------------------------------
Total Revenues 833 614 721 64 65 589 240 377 15 3,518
Less: Expenses
Operating 92 143 86 30 15 22 123 240 -- 751
Transportation and Other 5 4 -- -- -- 398 11 42 1 461
General and Administrative 5 27 13 -- 20 43 1 21 60 190
Depreciation, Depletion and
Amortization 168 490(11) 207 22 38 15 14 46 17 1,017
Exploration 17 34 89 1 59 (6) -- -- -- -- 200
Interest -- -- -- -- -- -- -- -- 105 105
------------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 546 (84) 326 11 (67) 111 91 28 (168) 794
Less: Provision for (Recovery
of) Income Taxes (7) 191 (96) 115 (2) (1) 39 25 10 (111) 170
------------------------------------------------------------------------------------------------------
Net Income (Loss) from 355 12 211 13 (66) 72 66 18 (57) 624
Continuing Operations
Add: Net Income from
Discontinued Operations - 15(8) -- -- -- -- -- -- -- 15
------------------------------------------------------------------------------------------------------
Net Income (Loss) 355 27 211 13 (66) 72 66 18 (57) 639
======================================================================================================
Identifiable Assets 574 2,136 1,420 28 165 1,518(9) 712 471 601 7,625
======================================================================================================
Capital Expenditures
Development and Other 219 259 249 1 24 1 195 24 29 1,001
Exploration 34 51 147 1 96 -- -- -- -- 329
Proved Property Acquisitions -- -- 164(10) -- -- -- -- -- -- 164
------------------------------------------------------------------------------------------------------
253 310 560 2 120 1 195 24 29 1,494
======================================================================================================
Property, Plant and Equipment
Cost 1,898 2,879 2,095 172 313 157 811 760 168 9,253
Less: Accumulated DD&A 1,497 1,428 854 168 198 56 141 371 71 4,784
------------------------------------------------------------------------------------------------------
Net Book Value (3) 401 1,451 1,241 4 115 101 670 389 97 4,469
======================================================================================================
Goodwill
Cost -- -- -- -- -- 60 -- -- -- 60
Less: Accumulated DD&A -- -- -- -- -- 24 -- -- -- 24
------------------------------------------------------------------------------------------------------
Net Book Value -- -- -- -- -- 36 -- -- -- 36
======================================================================================================
Notes:
(1) Includes results of operations from producing activities in Nigeria and
Colombia.
(2) Includes results of operations from a natural gas-fired generating facility
in Alberta. In 2002, these results were included in Corporate and Other.
(3) Net sales made from all segments originating in Canada. 1,218
Property, Plant and equipment located in Canada. $ 2,566
(4) Net sales for our chemicals operations include:
Canada $ 282
United States 13
Brazil 80
--------
$ 375
========
(5) Includes interest income of $9 million and foreign exchange gains of $6
million.
(6) Includes exploration activities primarily in West Africa, Colombia and
Brazil.
(7) 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.
(8) In August 2003, we sold non-core conventional light oil assets in southeast
Saskatchewan for net proceeds of $268 million. No gain or loss was
recognized on the sale.
(9) Approximately 80% of Marketing's identifiable assets are accounts
receivable and inventories.
(10) On March 27, 2003, we acquired the residual 40% interest in Aspen in the
Gulf of Mexico for US$109 million.
(11) Includes impairment charge of $269 million as discussed in Note 4.
90
2002 OPERATING AND GEOGRAPHIC SEGMENTS
(Cdn$ millions)
Corporate
and
Oil and Gas Syncrude Chemicals Other(1) Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(2) Marketing
------------------------------------------------------------
Net Sales (3) 789 556 296 165 78 -- 245 367(4) 10 2,506
Marketing and Other -- 2 -- -- -- 496 -- 2 4(5) 504
Gain (Loss) on Disposition of
Assets -- (21)(6) -- -- -- -- -- -- 13(7) (8)
------------------------------------------------------------------------------------------------------
Total Revenues 789 537 296 165 78 496 245 369 27 3,002
Less: Expenses
Operating 86 151 94 50 22 -- 109 229 10 751
Transportation and Other -- -- 3 -- -- 423 6 40 3 475
General and Administrative 4 22 11 1 19 30 1 21 43 152
Depreciation, Depletion and
Amortization 149 218 133 53 46 8 13 52 13 685
Exploration 21 30 82 3 45(8) -- -- -- -- 181
Interest -- -- -- -- -- -- -- -- 109 109
------------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 529 116 (27) 58 (54) 35 116 27 (151) 649
Less: Provision for (Recovery
of) Income Taxes (9) 188 41 (10) 19 (18) 12 37 9 (67) 211
------------------------------------------------------------------------------------------------------
Net Income (Loss)
from Continuing Operations 341 75 (17) 39 (36) 23 79 18 (84) 438
Add: Net Income from
Discontinued Operations -- 14(10) -- -- -- -- -- -- -- 14
------------------------------------------------------------------------------------------------------
Net Income (Loss) 341 89 (17) 39 (36) 23 79 18 (84) 452
======================================================================================================
Identifiable Assets 600 2,124 1,452 63 159 811(11) 536 538 277 6,560
======================================================================================================
Capital Expenditures
Development and Other 209 258 541 46 23 2 141 45 97(12) 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 3 408 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:
(1) Includes results of operations from a natural gas-fired generating facility
in Alberta.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) Net sales made from all segments originating in Canada. $ 1,162
Property, Plant and equipment located in Canada. $ 2,908
(4) Net sales for our chemicals operations include:
Canada $ 251
United States 56
Brazil 60
--------
$ 367
========
(5) Includes interest income of $7 million and foreign exchange losses of $3
million.
(6) On December 30, 2002, we disposed of non-operated oil and gas properties
for proceeds of $14 million.
(7) On January 2, 2002, we disposed of our Moose Jaw Asphalt operation for
proceeds of $27 million plus working capital.
(8) Includes exploration activities primarily in Nigeria, Colombia and Brazil.
(9) 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.
(10) In August 2003, we sold non-core conventional light oil assets in southeast
Saskatchewan for net proceeds of $268 million. No gain or loss was
recognized on the sale.
(11) Approximately 87% of Marketing's identifiable assets are accounts
receivable and inventories.
(12) Includes $67 million related to the buy out of the lease agreement related
to the construction of a natural gas-fired generating facility in Alberta.
91
2001 OPERATING AND GEOGRAPHIC SEGMENTS
(Cdn$ millions)
Corporate
and
Oil and Gas Syncrude Chemicals Other(1) Total
- -----------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(2) Marketing
------------------------------------------------------------
Net Sales (3) 711 551 358 141 61 -- 225 373(4) 77 2,497
Marketing and Other -- 10 1 -- 6 438 -- 3 17(5) 475
Gain on Disposition of Assets -- -- 1 3 -- -- -- -- 1 5
-----------------------------------------------------------------------------------------------------
Total Revenues 711 561 360 144 67 438 225 376 95 2,977
Less: Expenses
Operating 71 132 66 52 19 -- 114 243 61 758
Transportation and Other -- -- -- -- -- 342 -- 34 24 400
General and Administrative 3 25 8 1 21 23 1 18 36 136
Depreciation, Depletion and
Amortization 111 197 116 65 31 14 12 34 15 595
Exploration 25 39 101 13 82(6) -- -- -- -- 260
Interest -- -- -- -- -- -- -- -- 112 112
-----------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 501 168 69 13 (86) 59 98 47 (153) 716
Less: Provision for (Recovery
of) Income Taxes (7) 185 69 27 5 (24) 26 32 16 (53) 283
-----------------------------------------------------------------------------------------------------
Net Income (Loss) from
Continuing Operations 316 99 42 8 (62) 33 66 31 (100) 433
Add: Net Income from
Discontinued Operations -- 17(8) -- -- -- -- -- -- -- 17
-----------------------------------------------------------------------------------------------------
Net Income (Loss) 316 116 42 8 (62) 33 66 31 (100) 450
======================================================================================================
Identifiable Assets 520 2,123 880 47 179 470(9) 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 (3) 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:
(1) Includes results of our Moose Jaw Asphalt operation, which was disposed of
on January 2, 2002.
(2) Includes results of operations from producing activities in Nigeria.
(3) Net sales made from all segments originating in Canada. $ 1,190
Property, Plant and equipment located in Canada. $ 2,709
(4) Net sales for our chemicals operations include:
Canada $ 241
United States 90
Brazil 42
--------
$ 373
========
(5) Includes interest income of $17 million.
(6) Includes exploration activities primarily in Nigeria, Indonesia, and
Colombia.
(7) 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.
(8) In August 2003, we sold non-core conventional light oil assets in southeast
Saskatchewan for net proceeds of $268 million. No gain or loss was
recognized on the sale.
(9) Approximately 78% of Marketing's identifiable assets are accounts
receivable and inventories.
92
16. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Consolidated Financial Statements have been prepared in accordance with
Canadian GAAP. US GAAP Consolidated Financial Statements and summaries of
differences from Canadian GAAP are as follows:
(a) CONSOLIDATED STATEMENT OF INCOME - US GAAP FOR THE THREE YEARS ENDED
DECEMBER 31, 2003
(Cdn$ millions except per share amounts) 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------------
REVENUES
Net Sales (xi) 2,908 2,506 2,497
Marketing and Other (iii); (v); (x) 623 498 475
--------------------------------------------
3,531 3,004 2,972
--------------------------------------------
EXPENSES
Operating (xi) 757 751 758
Transportation and Other (i); (viii); (xi) 489 483 395
General and Administrative 190 152 136
Depreciation, Depletion and Amortization (ii); (ix) 1,130 738 641
Exploration 200 181 260
Interest (i) 169 181 182
--------------------------------------------
2,935 2,486 2,372
--------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 596 518 600
--------------------------------------------
PROVISION FOR INCOME TAXES
Current 210 223 216
Deferred (i) - (xi) (89) (43) 36
--------------------------------------------
121 180 252
--------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES 475 338 348
Net Income (Loss) from Discontinued Operations (ii) (7) 14 17
Cumulative Effect of Changes in Accounting Principles,
Net of Income Taxes (ix); (x) (48) -- --
--------------------------------------------
NET INCOME - US GAAP 1 420 352 365
============================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 8)
Net Income from Continuing Operations 3.83 2.77 2.89
Net Income (Loss) from Discontinued Operations (0.06) 0.11 0.14
Cumulative Effect of Changes in Accounting Principles (0.38) -- --
--------------------------------------------
3.39 2.88 3.03
============================================
Diluted (Note 8)
Net Income from Continuing Operations 3.80 2.73 2.85
Net Income (Loss) from Discontinued Operations (0.06) 0.11 0.14
Cumulative Effect of Changes in Accounting Principles (0.38) -- --
--------------------------------------------
3.36 2.84 2.99
============================================
Note:
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
(Cdn$ millions) 2003 2002 2001
-------------------------------------------------------- ---------------- ------------- -----------------
Net Income - Canadian GAAP 639 452 450
Impact of US Principles, Net of Income Taxes:
Fair Value of Currency Swap (v) 3 (4) --
Fair Value of Preferred Securities (x) 7 -- --
Depreciation, Depletion and Amortization (ii); (ix) (92) (53) (46)
Dividends on Preferred Securities (i) (40) (43) (39)
Issue Costs on Preferred Securities Redeemed (i) (21) -- --
Natural Gas Futures and Basis Swaps(iii) (2) -- --
Research and Development Costs (xi) (4) -- --
Loss on Disposition (ii) (22) -- --
Cumulative Effect of Changes in Accounting (48) -- --
Principles (ix); (x)
---------------- ------------- -----------------
Net Income - US GAAP 420 352 365
================ ============= =================
93
(b) CONSOLIDATED BALANCE SHEET - US GAAP
December 31 December 31
(Cdn$ millions, except share amounts) 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 1,087 59
Accounts Receivable (iii) 1,423 990
Inventories and Supplies 270 256
Other 79 26
---------------------------------
Total Current Assets 2,859 1,331
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion and
Amortization of $5,330 (December 31, 2002 - $4,992) (ii); (ix); (xi) 4,583 5,064
GOODWILL 36 36
DEFERRED INCOME TAX ASSETS 108 263
DEFERRED CHARGES AND OTHER ASSETS (i); (vi) 117 70
---------------------------------
7,703 6,764
=================================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term Borrowings -- 18
Current Portion of Long-Term Debt 575 --
Accounts Payable and Accrued Liabilities (iii) 1,418 1,200
Accrued Interest Payable 44 39
Dividends Payable 12 9
---------------------------------
Total Current Liabilities 2,049 1,266
---------------------------------
LONG-TERM DEBT (i); (vi); (x) 2,472 2,575
DEFERRED INCOME TAX LIABILITIES (i) - (xi) 676 876
DISMANTLEMENT AND SITE RESTORATION (ix) -- 191
ASSET RETIREMENT OBLIGATION (ix) 305 --
OTHER DEFERRED CREDITS AND LIABILITIES (vii) 70 44
SHAREHOLDERS' EQUITY
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2003 -- 125,606,107 shares
2002 -- 122,965,830 shares 513 440
Contributed Surplus 1 --
Retained Earnings (i)-- (xi) 1,660 1,280
Accumulated Other Comprehensive Income (i); (iii); (iv); (vii) (43) 92
---------------------------------
Total Shareholders' Equity 2,131 1,812
---------------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES
7,703 6,764
=================================
(C) CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP FOR THE THREE
YEARS ENDED DECEMBER 31, 2003
(Cdn$ millions) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP 420 352 365
Other Comprehensive Income, net of income taxes:
Translation Adjustment (i); (iv) (127) 34 (3)
Unrealized Mark-to-Market Gain (Loss) (iii) (7) - -
Minimum Unfunded Pension Liability (vii) (1) (2) -
---------- ---------------- ----------------
Comprehensive Income 285 384 362
========== ================ ================
94
(d) CONSOLIDATED STATEMENT OF CASH FLOWS
Under US principles, dividends on preferred securities of $64 million (2002 -
$72 million; 2001 - $70 million) that are included in financing activities would
be reported in operating activities.
Under US principles, geological and geophysical costs of $62 million (2002 - $80
million; 2001 - $79 million) that are included in investing activities would be
reported in operating activities.
(e) OTHER SUPPLEMENTARY INFORMATION
2003 2002 2001
- --------------------------------------------------------------------------------- ---------------------------------------
Pro Forma Earnings - Fair-Value Method of Accounting for Stock Options
Net Income - US GAAP
As Reported 420 352 365
Plus: Fair Value of Stock Options Granted after December 31, 2002 1 -- --
Less: Fair Value of Stock Options Awarded 25 22 25
---------------------------------------
396 330 340
=======================================
Earnings per Common Share ($/share)
Basic as Reported 3.39 2.88 3.03
=======================================
Pro Forma 3.19 2.70 2.81
=======================================
Diluted as Reported 3.36 2.84 2.99
=======================================
Pro Forma 3.16 2.67 2.79
=======================================
(f) CHANGES IN ACCOUNTING PRINCIPLES
ASSET RETIREMENT OBLIGATIONS
On January 1, 2003 we adopted Financial Accounting Standards Board (FASB)
Statement No. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS (FAS 143) for US
GAAP reporting purposes. FAS 143 requires recognition of a liability for the
future retirement obligations associated with our property, plant and equipment,
which includes oil and gas wells and facilities, and chemicals plants. These
obligations, which generally relate to dismantlement and site restoration, 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.
This change in accounting policy has been reported as a cumulative effect
adjustment in the Consolidated Statement of Income as a loss of $37 million, net
of income taxes of $25 million. Under the old accounting rules, our results
would have been:
2003
- --------------------------------------------------------------------------------
Net Income - US GAAP
As Reported 420
Cumulative Effect of Change in Accounting Principle 37
Depreciation, Depletion, Amortization, and Accretion 10
---------
Adjusted 467
=========
Earnings per Common Share ($/share)
Basic as Reported 3.39
=========
Adjusted 3.76
=========
Diluted as Reported 3.36
=========
Adjusted 3.73
=========
95
Had FAS 143 been applied during all periods presented, our asset retirement
obligation, including current obligations of $18 million at December 31, 2003
and $14 million at December 31, 2002, would have been reported as follows:
As Reported Pro-forma
- -------------------------------------------------------------------------------
January 1, 2002 182 364
December 31, 2002 205 390
December 31, 2003 323 323
---------------------------
The change in our asset retirement obligation since the beginning of the year is
as follows:
2003
- -------------------------------------------------------------------------------
Asset Retirement Obligation at January 1 390
Obligation Incurred 6
Abandonment Expenditures (20)
Property Disposition (27)
Accretion 22
Revision in Estimate (19)
Effect of Foreign Exchange (29)
----------
Asset Retirement Obligation at December 31 323
==========
We own interests in several assets for which the fair value of the asset
retirement obligation cannot be reasonably determined because the assets
currently have an indeterminate life. These assets include our interests in one
gas plant and our interest in Syncrude's upgrader and sulfur pile. The asset
retirement obligation for these assets will be recorded in the first year in
which the lives of the assets are determinable.
Had FAS 143 been applied during all periods presented, our December 31, 2002 and
2001 results would have been reported as follows:
2002 2001
- -------------------------------------------------------------------------------
Net Income - US GAAP
As Reported 352 365
Depreciation, Depletion, Amortization, and Accretion 2 1
-----------------
Adjusted 350 364
=================
Earnings per Common Share ($/share)
Basic as Reported 2.88 3.03
=================
Adjusted 2.86 3.02
=================
Diluted as Reported 2.84 2.99
=================
Adjusted 2.82 2.98
=================
FAIR VALUE OF INSTRUMENTS WITH EQUITY AND LIABILITY COMPONENTS
In May 2003, FASB issued Statement No. 150, ACCOUNTING FOR CERTAIN INSTRUMENTS
WITH CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY that establishes standards
for classifying and measuring certain financial instruments with characteristics
of both liabilities and equity. Certain financial instruments, including our
preferred securities, must be recorded at fair value with changes in fair value
recognized through net income. The change in fair value of our preferred
securities up to June 30, 2003 increased the carrying value of our long-term
debt by $16 million and was recognized as a loss of $11 million, net of income
taxes of $5 million. This was reported as a cumulative effect of a change in an
accounting principle. Since adopting this change in accounting principle at the
beginning of the third quarter, the fair value of our preferred securities has
decreased by $12 million and this gain was included in marketing and other. The
tax effect of $5 million on this gain increased our deferred income tax
provision.
96
NOTES TO THE CONSOLIDATED US GAAP FINANCIAL STATEMENTS:
i. Under US principles, the preferred and subordinated securities are
classified as long-term debt rather than shareholders' equity. The
pre-tax dividends on the preferred securities 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
accumulated other comprehensive income (AOCI) as the preferred
securities have been designated as a hedge of our foreign net
investments. The pre-tax dividends are included in operating activities
in the Consolidated Statement of Cash Flows.
On December 15, 2003, we redeemed our US$259 million preferred
securities. Under Canadian principles, a foreign exchange gain of $31
million, net of income tax, was recognized in retained earnings. Under
US principles, the preferred securities have been revalued each
reporting period and the gains and losses have been included in AOCI.
Issue costs of $27 million have been expensed to other expense.
ii. Under US principles, the liability method of accounting for income
taxes was adopted in 1993. In Canada, the liability method was adopted
in 2000. In 1997, we acquired certain oil and gas assets and the amount
paid for these assets differed from the tax basis acquired. Under US
principles, this difference was recorded as a deferred tax liability
with an increase to property, plant and equipment rather than a charge
to retained earnings. As a result, depreciation expense under US
principles is higher.
During the third quarter of 2003, some of these assets were sold as
described in Note 9. With the carrying value of these assets higher
under US GAAP, the sale resulted in a loss on disposition of $22
million, net of income taxes of $10 million. This loss is included in
the income (loss) from discontinued operations on the Consolidated
Statement of Income.
Included in depreciation, depletion and amortization expense for 2003
is an impairment charge of $315 million ($205 million after tax) as
described in Note 4. The amount is higher under US GAAP as we have
higher US GAAP carrying values for the assets impaired resulting from
differences in adopting the liability method of accounting for income
taxes as previously described.
iii. Under US principles, all derivative instruments are recognized on the
balance sheet as either an asset or a liability measured at fair value.
Changes in the fair value of derivatives are recognized in earnings
unless specific hedge criteria are met.
CASH FLOW HEDGES: Changes in the fair value of derivatives that are
designated as cash flow hedges are deferred and recognized in earnings
in the same period as the hedged item. The effective portion of the
change is deferred in other comprehensive income with any
ineffectiveness of the hedge recognized immediately on the income
statement.
Included in accounts payable at December 31, 2003 is a $3 million loss
(December 31, 2002 - $nil) on the forward contracts we used to hedge
the future sale of a portion of our production from the Aspen field as
described in Note 5. The contracts limit our exposure to fluctuations
in commodity prices by fixing our cash flow from the hedged sale
production. We deferred this loss ($2 million, net of income tax) in
AOCI until the underlying production is sold. All of these deferred
losses will be reclassified to net sales in the next twelve months as
the production is sold.
Included in accounts payable at December 31, 2003 are losses of $11
million (December 31, 2002 - $nil) on the futures and basis swap
contracts we used to hedge the future sale of our gas inventory as
described in Note 5. The effective portion of these losses is deferred
to AOCI until the underlying gas inventory is sold ($5 million after
taxes of $3 million). The ineffective portion of the losses is
recognized immediately in marketing and other ($2 million after taxes
of $1 million). All of the deferred losses in AOCI will be reclassified
to marketing and other in the next twelve months as the gas inventory
is sold.
FAIR VALUE HEDGES: Both the derivative instrument and the underlying
commitment are recognized on the balance sheet at their fair value. The
change in the fair value of both are reflected in earnings. Included in
both accounts receivable and accounts payable at December 31, 2003 is
$nil (December 31, 2002 - $2 million) related to fair value hedges. The
hedges converted fixed prices for physical delivery of natural gas into
a floating price through a fixed to floating swap. The contracts
expired in November 2003. The impact on earnings was 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, net of income taxes, from the translation of our US-dollar
long-term debt designated as a hedge of our foreign net investment are
included in comprehensive income. Cumulative amounts are included in
AOCI in the Consolidated Balance Sheet.
97
v. Under US principles, a derivative and a cash instrument cannot be
designated in combination as a net investment hedge. The $4 million
gain in fair value and foreign exchange gains and losses during the
year (2002 - loss of $5 million; 2001 - $nil) on our US$37 million
currency swap were included in marketing and other.
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. This amount was
$2 million at December 31, 2003 (December 31, 2002 - $4 million).
viii. Under US principles, gains and losses on the disposition of assets are
shown as other expense.
ix. On January 1, 2003, we adopted Financial Accounting Standards Board
(FASB) Statement No. 143, "Accounting for Asset Retirement Obligations"
(FAS 143) as described under Changes in Accounting Principles. Under
Canadian GAAP, we will adopt similar standards effective January 1,
2004.
x. On July 1, 2003, we adopted FASB Statement No. 150, "Accounting for
Certain Instruments with Characteristics of Both Liabilities and
Equity" as described under Changes in Accounting Principles.
xi. Under Canadian principles, we defer certain development costs and all
pre-operating revenues and costs to PP&E. Under US principles, these
costs are charged to earnings as incurred. In 2003, we recognized $6
million of pre-operating expenses in earnings rather than defer them.
xii. On January 1, 2002, we adopted FASB Statement No. 142, which eliminated
goodwill amortization and instead required annual impairment testing.
No goodwill impairment writedowns were required during the year. Our
unamortized goodwill at January 1, 2002 was $36 million. The following
shows the adjusted net income and earnings per common share had the new
standard been applied in 2001:
2003 2002 2001
- ------------------------------------------------------------------------------
Net Income
As Reported 420 352 365
Add: Goodwill Amortization -- -- 6
--------------------------------
Adjusted 420 352 371
================================
Earnings Per Common Share ($/share)
Basic as Reported 3.39 2.88 3.03
================================
Adjusted 3.39 2.88 3.07
================================
Diluted as Reported 3.36 2.84 2.99
================================
Adjusted 3.36 2.84 3.04
================================
NEW ACCOUNTING PRONOUNCEMENTS
The following standards issued by the FASB do not impact us:
o Statement No. 149, AMENDMENT OF STATEMENT 133 ON DERIVATIVE INSTRUMENTS
AND HEDGING ACTIVITIES, effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated
after June 30, 2003.
o Interpretation No. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES,
effective for financial statements issued after January 31, 2003.
98
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
2003 2002 2003 2002 2003 2002 2003 2002
-------------------------------------------------------------------------------------
Net Sales (1) 806 517 726 621 716 687 660 681
=====================================================================================
Operating Profit
Oil and Gas (1),(2),(3) 379 91 261 180 260 210 (57) 176
Syncrude (4) 28 20 18 9 32 47 13 40
Chemicals 3 3 9 4 12 11 4 9
-------------------------------------------------------------------------------------
410 114 288 193 304 268 (40) 225
Interest and Other Corporate (5) 45 24 27 43 35 36 61 48
Income Tax Expense (6) 121 28 3 49 91 82 (45) 52
-------------------------------------------------------------------------------------
Net Income from Continuing
Operations in accordance with
Canadian GAAP 244 62 258 101 178 150 (56) 125
US GAAP Adjustment (25) (23) (99) (22) (11) (23) (14) (32)
-------------------------------------------------------------------------------------
Net Income from Continuing
Operations in accordance
with US GAAP 219 39 159 79 167 127 (70) 93
=====================================================================================
Net Income in accordance with
Canadian GAAP 251 65 263 101 181 157 (56) 129
US GAAP Adjustment (62) (23) (99) (22) (44) (23) (14) (32)
-------------------------------------------------------------------------------------
Net Income in accordance with
US GAAP 189 42 164 79 137 134 (70) 97
=====================================================================================
Net Income from Continuing
Operations per Common
Share ($/share)
Canadian GAAP 1.89 0.42 2.01 0.74 1.36 1.13 (0.52) 0.94
US GAAP 1.78 0.32 1.29 0.65 1.35 1.03 (0.56) 0.77
Net Income per Common
Share ($/share)
Canadian GAAP 1.95 0.44 2.05 0.74 1.38 1.20 (0.52) 0.96
US GAAP 1.53 0.35 1.33 0.65 1.11 1.09 (0.56) 0.79
Dividends Declared (7) 0.075 0.075 0.075 0.075 0.075 0.075 0.100 0.075
-------------------------------------------------------------------------------------
Common Share Prices ($/share)
Toronto Stock Exchange
High 34.85 39.75 35.59 42.50 39.68 42.18 47.08 37.78
Low 29.30 29.70 28.26 37.20 33.02 34.34 36.65 31.00
New York Stock Exchange
High (US$) 22.55 25.11 26.31 28.04 29.00 27.71 36.47 23.85
Low (US$) 19.89 18.57 19.75 23.30 24.03 21.70 27.32 19.79
-------------------------------------------------------------------------------------
Notes:
(1) Excludes results of the non-core conventional light oil assets in southeast
Saskatchewan that were sold. These results are shown as discontinued
operations (see Note 9 of the Consolidated Financial Statements).
(2) A loss of $21 million was recorded on the disposition of non-operated oil
and gas properties during the fourth quarter of 2002.
(3) Includes impairment charge of $269 million (see Note 4 of the Consolidated
Financial Statements).
(4) Plant turnarounds and unplanned coker maintenance in the second quarter of
2002 and the fourth quarter of 2003 increased operating costs and
temporarily reduced production volumes.
(5) A gain of $13 million was recorded on the disposition of our Moose Jaw
Asphalt operation during the first quarter of 2002.
(6) Canadian GAAP net income includes a reduction in tax rates for Canadian
resource activities in the second quarter of 2003. This reduction was
recognized in the fourth quarter of 2003 for US GAAP.
(7) In February 2004, the Board of Directors declared a regular quarterly
dividend of $0.10 per common share, payable April 1, 2004, to shareholders
of record on March 10, 2004.
(8) At December 31, 2003, there were 1,420 registered holders of common shares
and 125,606,107 common shares outstanding.
99
OIL AND GAS NETBACKS BEFORE ROYALTIES
(Sales prices, per unit costs and netbacks are calculated using our working
interest production before royalties.)
($/boe) 2003
- ------------------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia Other Syncrude Total
---------------------------------------------------------------------------------------------
Sales 39.45 32.99 42.88 43.14 38.22 43.36 38.63
Royalties and other (19.98) (7.53) (5.91) (3.44) (5.69) (0.48) (12.14)
Operating expense (2.16) (6.00) (4.49) (18.60) (7.47) (21.96) (5.19)
In-country taxes (4.73) -- -- -- -- -- (2.06)
---------------------------------------------------------------------------------------------
Cash netback 12.58 19.46 32.48 21.10 25.06 20.92 19.24
=============================================================================================
($/boe) 2002
- ------------------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia Other Syncrude Total
---------------------------------------------------------------------------------------------
Sales 38.80 27.90 34.21 40.30 38.96 40.89 35.14
Royalties and other (20.45) (6.53) (5.82) (7.88) (16.48) (0.36) (12.56)
Operating expense (1.95) (5.70) (9.09) (9.76) (6.21) (18.10) (5.42)
In-country taxes (4.81) -- -- -- -- -- (2.10)
---------------------------------------------------------------------------------------------
Cash netback 11.59 15.67 19.30 22.66 16.27 22.43 15.06
=============================================================================================
($/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
=============================================================================================
OIL AND GAS NETBACKS AFTER ROYALTIES
(Sales prices, per unit costs and netbacks are calculated using our working
interest production after royalties.)
($/boe) 2003
- ------------------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia Other Syncrude Total
---------------------------------------------------------------------------------------------
Sales 39.45 32.99 42.88 43.14 38.22 43.36 38.63
Operating expense (4.37) (7.76) (5.19) (20.21) (9.01) (22.18) (7.56)
In-country taxes (9.58) -- -- -- -- -- (3.00)
---------------------------------------------------------------------------------------------
Cash netback 25.50 25.23 37.69 22.93 29.21 21.18 28.07
=============================================================================================
($/boe) 2002
- ------------------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia Other Syncrude Total
---------------------------------------------------------------------------------------------
Sales 38.80 27.90 34.21 40.30 38.96 40.89 35.14
Operating expense (4.13) (7.45) (10.87) (12.14) (10.69) (18.21) (8.26)
In-country taxes (10.17) -- -- -- -- -- (3.20)
---------------------------------------------------------------------------------------------
Cash netback 24.50 20.45 23.34 28.16 28.27 22.68 23.68
=============================================================================================
($/boe) 2001
- ------------------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia Other Syncrude Total
---------------------------------------------------------------------------------------------
Sales 35.05 26.60 39.42 38.71 37.35 39.90 33.28
Operating expense (3.47) (5.82) (7.31) (14.38) (9.94) (20.29) (7.10)
In-country taxes (9.41) -- -- -- -- -- (2.86)
---------------------------------------------------------------------------------------------
Cash netback 22.17 20.78 32.11 24.33 27.41 19.61 23.32
=============================================================================================
100
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. Reserve estimates for each property are
prepared internally each year and at least 80% of the reserves have been
assessed by independent qualified reserves consultants.
Estimates of conventional crude oil and natural gas proved reserves are
determined through analysis of geological and engineering data, and demonstrate
reasonable certainty that they are recoverable from known reservoirs under
economic and operating conditions that existed 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.
Conventional oil and Syncrude
reserves are in mmbbls and natural
gas reserves in bcf Total United Other
- ----------------------------------- Conventional Yemen(1) Canada States Countries(2)
Syncrude(3) Oil Gas Oil Oil Gas Oil Gas Oil
---------- --------------------------------------------------------------------
Proved Developed and Undeveloped
Reserves (4)
December 31, 2000 203 300 673 107 166 509 18 164 9
----------- --------------------------------------------------------------------
Revisions of Previous Estimates -- 1 -- 7 (14) (1) 2 1 6
Purchases of Reserves in Place -- 2 64 -- 2 3 -- 61 --
Sales of Reserves In Place -- -- (2) -- -- (2) -- -- --
Extensions and Discoveries 34 53 146 17 21 91 11 55 4
Production (6) (47) (90) (20) (18) (54) (3) (36) (6)
----------- --------------------------------------------------------------------
December 31, 2001 231 309 791 111 157 546 28 245 13
----------- --------------------------------------------------------------------
Revisions of Previous Estimates (12) (6) (10) (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 13 72 103 23 10 31 32 72 7
Production (6) (45) (81) (20) (16) (47) (3) (34) (6)
----------- --------------------------------------------------------------------
December 31, 2002 226 324 803 100 156 524 58 279 10
----------- --------------------------------------------------------------------
Revisions of Previous Estimates 5 (31) (99) (5) (28) (88) (2) (11) 4
Purchases of Reserves in Place -- 19 21 -- -- -- 19 21 --
Sales of Reserves in Place -- (24) (7) -- (24) (6) -- (1) --
Extensions and Discoveries 22 48 33 36 10 20 1 13 1
Production (5) (47) (90) (21) (13) (45) (9) (45) (4)
----------- --------------------------------------------------------------------
December 31, 2003 248 289 661 110 101 405 67 256 11
=========== ====================================================================
Proved Developed Reserves (5)
December 31, 2001 212 223 676 70 126 505 18 171 9
=========== ====================================================================
December 31, 2002 196 246 702 61 131 487 46 215 8
=========== ====================================================================
December 31, 2003 192 216 576 63 91 367 54 209 8
=========== ====================================================================
Notes:
(1) Under the terms of the Masila and the Block 51 production sharing
contracts, 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 Australia, Nigeria and Colombia.
(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 test.
(5) "Proved developed" oil and gas reserves are expected to be recovered
through existing wells with existing equipment and operating methods.
101
B. CAPITALIZED COSTS
Accumulated
Depreciation,
Proved Unproved Depletion and Capitalized
(Cdn$ millions) Properties Properties Amortization Costs
- -----------------------------------------------------------------------------------------------------------
December 31, 2003
Yemen 1,881 17 1,497 401
Canada 3,271 129 1,863 1,537
United States 2,034 123 892 1,265
Other Countries 454 85 420 119
Syncrude 819 -- 144 675
------------------------------------------------------------
Total 8,459 354 4,816 3,997
============================================================
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
Other Countries 460 54 382 132
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
Other Countries 434 4 310 128
Syncrude 487 -- 127 360
------------------------------------------------------------
Total 7,001 266 3,689 3,578
============================================================
C. COSTS INCURRED
(Cdn$ millions) Total Conventional Oil and Gas
- ------------------------------------------------------------------------------------------------------------------------------
Conventional United Other
Oil and Gas Syncrude Yemen Canada States Countries
---------------------------------------------------------------------------
Year Ended December 31, 2003
Property Acquisition Costs
Proved 164 -- -- -- 164 --
Unproved 38 -- -- -- 38 --
Exploration Costs 291 -- 34 51 109 97
Development Costs 752 195 219 259 249 25
Asset Retirement Costs 185 8 -- 69 62 54
---------------------------------------------------------------------------
1,430 203 253 379 622 176
===========================================================================
Year Ended December 31, 2002
Property Acquisition Costs
Proved 4 -- -- 4 -- --
Unproved 31 -- -- -- 31 --
Exploration Costs 228 -- 22 60 85 61
Development Costs 1,077 141 209 258 541 69
---------------------------------------------------------------------------
1,340 141 231 322 657 130
===========================================================================
Year Ended December 31, 2001
Property Acquisition Costs
Proved 122 -- -- 7 115 --
Unproved 37 -- 19 -- 18 --
Exploration Costs 374 -- 25 84 179 86
Development Costs 691 60 185 367 120 19
---------------------------------------------------------------------------
1,224 60 229 458 432 105
===========================================================================
102
D. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
(Cdn$ millions) Total Conventional Oil and Gas
- ------------------------------------------------------------------------------------------------------------------------------
Conventional United Other
Oil and Gas Syncrude Yemen Canada States Countries
---------------------------------------------------------------------------
Year Ended December 31, 2003
Net Sales 2,338 240 827 675 707 129
Production Costs 382 123 92 159 86 45
Exploration Expense 201 -- 17 35 89 60
Depreciation, Depletion and Amortization 1,057 15 168 613 207 69
Other Expenses (Income) 87 12 4 64 (1) 20
---------------------------------------------------------------------------
611 90 546 (196) 326 (65)
Income Tax Provision (Recovery) 188 25 191 (112) 115 (6)
---------------------------------------------------------------------------
Results of Operations 423 65 355 (84) 211 (59)
===========================================================================
Year Ended December 31, 2002
Net Sales 1,984 245 789 656 296 243
Production Costs 428 115 86 176 94 72
Exploration Expense 189 -- 21 38 82 48
Depreciation, Depletion and Amortization 634 13 149 253 133 99
Other Expenses (Income) 79 1 4 41 14 20
---------------------------------------------------------------------------
654 116 529 148 (27) 4
Income Tax Provision (Recovery) 238 37 188 59 (10) 1
---------------------------------------------------------------------------
Results of Operations 416 79 341 89 (17) 3
===========================================================================
Year Ended December 31, 2001
Net Sales 1,918 225 711 647 358 202
Production Costs 363 114 71 155 66 71
Exploration Expense 265 -- 25 44 101 95
Depreciation, Depletion and Amortization 550 12 111 227 116 96
Other Expenses (Income) 37 1 3 15 6 13
---------------------------------------------------------------------------
703 98 501 206 69 (73)
Income Tax Provision (Recovery) 283 32 185 90 27 (19)
---------------------------------------------------------------------------
Results of Operations 420 66 316 116 42 (54)
===========================================================================
E. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN
The following disclosure is based on 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 proved to be the case in the past. Other assumptions could give rise to
substantially different results.
We believe 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.
103
(Cdn$ millions) United Other
Total Yemen Canada States Countries
- ------------------------------------------------------------------------------------------------------------------------------
December 31, 2003
Future Cash Inflows 14,660 4,416 5,319 4,470 455
Future Production Costs 3,651 868 1,980 666 137
Future Development Costs 788 412 102 249 25
Future Dismantlement and Site Restoration Costs, Net 309 - 112 137 60
Future Income Tax 2,152 574 656 854 68
--------- -------------------------------------------------
Future Net Cash Flows 7,760 2,562 2,469 2,564 165
10% Discount Factor 2,243 620 879 691 53
--------- -------------------------------------------------
Standardized Measure 5,517 1,942 1,590 1,873 112
========= =================================================
December 31, 2002
Future Cash Inflows 18,687 4,662 9,067 4,516 442
Future Production Costs 3,943 881 2,375 535 152
Future Development Costs 722 296 169 228 29
Future Dismantlement and Site Restoration Costs, Net 227 - 24 150 53
Future Income Tax 3,650 790 1,976 863 21
--------- -------------------------------------------------
Future Net Cash Flows 10,145 2,695 4,523 2,740 187
10% Discount Factor 3,776 819 2,081 818 58
--------- -------------------------------------------------
Standardized Measure 6,369 1,876 2,442 1,922 129
========= =================================================
December 31, 2001
Future Cash Inflows 10,337 3,068 5,034 1,880 355
Future Production Costs 3,104 597 1,694 633 180
Future Development Costs 790 283 202 231 74
Future Dismantlement and Site Restoration Costs, Net 229 - 47 136 46
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
========= =================================================
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) 2003 2002 2001
- --------------------------------------------------------------------------------------------------------------------------
Beginning of Year 6,369 3,087 4,991
Sales and Transfers of Oil and Gas Produced, Net of Production Costs (2,298) (1,158) (2,012)
Net Changes in Prices and Production Costs Related to Future Production (1,249) 3,083 (2,871)
Extensions, Discoveries and Improved Recovery, Less Related Costs 740 1,929 691
Changes in Estimated Future Development and Dismantlement Costs (279) (103) (382)
Previous Estimated Future Development and Dismantlement Costs
Incurred during the Period 456 425 443
Revisions of Previous Quantity Estimates (291) 267 (33)
Accretion of Discount 884 409 736
Purchases of Reserves in Place 354 2 161
Sales of Reserves in Place (252) (109) (1)
Net Change in Income Taxes 1,083 (1,463) 1,364
-----------------------------------------
End of Year 5,517 6,369 3,087
=========================================
104
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 2003 Annual General Meeting
(AGM). Deloitte Canada was re-appointed as our auditors at the 2003 AGM until
the next AGM in 2004.
There were no disagreements with accountants on accounting and financial
disclosure.
ITEM 9A. 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-15(e) and 15-d-15(e)) as of the end of the period covered by this
report. They concluded that, as of the end of the period covered by this report,
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 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 judgement 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 control over
financial reporting. There has not been any change in the Company's internal
control over financial reporting during the fourth quarter of 2003 that has
materially affected, or is reasonably likely to materially affect, the Company's
internal control over financial reporting.
105
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
According to our Articles, Nexen must have between three and 15 directors. On
January 5, 2004, the directors determined that, until changed, there will be 11
directors.
Our By-Laws provide that directors will be elected at the annual general meeting
of shareholders (AGM) each year and will hold office until their successors are
elected. All of our current directors were elected at the last AGM except Mr.
Newell, who was appointed by the Board on January 5, 2004.
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 12, 2004. The following directors are management nominees for election
to the Board.
PRINCIPAL OCCUPATION AND DIRECTOR
NAME (AGE) OTHER DIRECTORSHIPS SINCE
- -----------------------------------------------------------------------------------------------------------------------------
Charles W. Fischer (53) President and Chief Executive Officer (CEO) of Nexen. 2000
Formerly, Executive Vice President and Chief Operating Officer (COO).
- -----------------------------------------------------------------------------------------------------------------------------
Dennis G. Flanagan 1, 2 (64) Retired oil executive. Director of NAL Oil and Gas Trust. 2000
- -----------------------------------------------------------------------------------------------------------------------------
David A. Hentschel 1 (70) Retired oil executive. Formerly, Chairman and CEO of Occidental Oil and Gas 1985
Corporation. A director of Cimarex Energy Co.
- -----------------------------------------------------------------------------------------------------------------------------
S. Barry Jackson 1 (51) Retired oil executive. Formerly, President and CEO of Crestar Energy Inc. 2001
Director and Executive Chairman of Resolute Energy Inc. and a director of TransCanada
Corporation, and TransCanada Pipelines Limited and Deer Creek Energy Limited.
- -----------------------------------------------------------------------------------------------------------------------------
Kevin J. Jenkins 1, 2 (47) Managing Director of TriWest Capital Management Corp. Formerly, President and 1996
CEO and a director of The Westaim Corporation.
- -----------------------------------------------------------------------------------------------------------------------------
Eric P. Newell, O.C. (59) Retired Chairman and CEO of Syncrude Canada Ltd. Director of Canfor 2004
Corporation.
- -----------------------------------------------------------------------------------------------------------------------------
Thomas C. O'Neill 1, 2 (58) Retired Chairman of PwC Consulting. Formerly, CEO of PwC Consulting. Prior to 2002
that, COO of PricewaterhouseCoopers LLP, Global. Prior to that, CEO of
PricewaterhouseCoopers LLP, Canada and, prior to that, Chairman and CEO of Price
Waterhouse Canada. Director of BCE Inc., Loblaw Companies Limited, Dofasco Inc.
- -----------------------------------------------------------------------------------------------------------------------------
Francis M. Saville, Q.C. (65) Counsel to Fraser Milner Casgrain LLP, Barristers and Solicitors. Formerly, 1994
Senior Partner of Fraser Milner Casgrain LLP, Barristers and Solicitors.
Director of Mullen Transportation Inc.
- -----------------------------------------------------------------------------------------------------------------------------
Richard M. Thomson, O.C. Retired banking executive. Director of the Toronto-Dominion Bank, Prudential 1997
1, 2 (70) Financial Inc., INCO Limited, The Thomson Corporation, Trizec Properties Inc.
and Stuart Energy Systems Corporation.
- -----------------------------------------------------------------------------------------------------------------------------
John M. Willson (64) Retired Vice Chairman of Placer Dome Inc. Formerly, CEO of Placer Dome Inc., 1996
and, prior to that, President and CEO of Placer Dome Inc. Director of Finning
International Inc. and PanAmerican Silver Corp.
- -----------------------------------------------------------------------------------------------------------------------------
Victor J. Zaleschuk (60) Retired President and CEO of Nexen. Director of Cameco Corporation and 1997
Agrium Inc.
- -----------------------------------------------------------------------------------------------------------------------------
Notes:
(1) Members of Nexen's Audit and Conduct Review Committee. All members of the
Committee are independent pursuant to Nexen's Categorical Standards for
Director Independence which meet or exceed all requirements under
applicable regulations of the US Securities and Exchange Commission, the
SARBANES-OXLEY ACT OF 2002 and the New York Stock Exchange.
(2) Financial Experts on Nexen's Audit and Conduct Review Committee.
106
EXECUTIVE OFFICERS
The Board of Directors determines the term of office for each executive officer.
Below are Nexen's officers. Prior offices and non-executive positions 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 (53) 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 (49) 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
- ---------------------------------------------------------------------------------------------------------------------------------
Laurence Murphy(1) (53) Senior Vice President, International Oil and Gas January 1, 1999 1998
- ---------------------------------------------------------------------------------------------------------------------------------
John B. McWilliams Q.C. (1) (56) Senior Vice President, General Counsel and Secretary May 11, 1993 1987
- ---------------------------------------------------------------------------------------------------------------------------------
Douglas B. Otten(1) (60) Senior Vice President, United States Oil and Gas May 12, 1998 1990
- ---------------------------------------------------------------------------------------------------------------------------------
Thomas A. Sugalski(1) (60) Senior Vice President, Chemicals May 10, 1994 1988
- ---------------------------------------------------------------------------------------------------------------------------------
Roger D. Thomas (51) Senior Vice President, Canadian Oil and Gas February 19, 1999 1998
Formerly: Vice President, Canada since May 12, 1998
- ---------------------------------------------------------------------------------------------------------------------------------
Nancy F. Foster (44) Vice President, Human Resources and Corporate July 11, 2000 2000
Services
Formerly: Division Vice President, Finance - Canadian
Oil and Gas
General Manager, Human Resources
- ---------------------------------------------------------------------------------------------------------------------------------
Gary H. Nieuwenburg (45) 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
- ---------------------------------------------------------------------------------------------------------------------------------
Kevin J. Reinhart (45) Vice President, Corporate Planning and Business July 11, 2002 1994
Development
Formerly: Treasurer since October 20, 1998
- ---------------------------------------------------------------------------------------------------------------------------------
Una M. Power(2) (39) Treasurer July 11, 2002 1998
Formerly: Controller and Director, Corporate
Insurance since May 2, 2002
Controller and Director, Risk Management since
December 1, 1998
- ---------------------------------------------------------------------------------------------------------------------------------
Michael J. Harris (40) Controller December 10, 2002 2002
Formerly: Manager, Corporate Finance - Treasury
Division Vice President, Finance - International
General Manager - New Ventures Finance
- ---------------------------------------------------------------------------------------------------------------------------------
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.
107
ETHICS POLICY
Under 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. An employee,
regardless of his or her position, is not permitted to commit an unethical,
dishonest or illegal act or to instruct other employees to do so. 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 of Directors and appropriately disclosed.
Our Ethics Policy is available on our internet website at www.nexeninc.com,
under "Our Commitment", and it is our intention to provide disclosure in this
manner.
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
------------------------
Other Annual Securities Underlying All Other
Name and Principal Salary Bonus (1) Compensation Options Granted Compensation
Position Year ($) ($) ($) (#) ($)
- -------------------------------------------------------------------------------------------------------------------------------
Charles W. Fischer 2003 725,000 600,000 - 100,000 43,500 (2)
President and Chief 2002 637,500 300,000 - 100,000 38,250 (2)
Executive Officer 2001 540,667 400,000 - 105,000 32,440 (2)
- -------------------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow 2003 440,500 267,000 - 55,000 26,430 (2)
Executive Vice President 2002 418,000 310,000 - 50,000 25,080 (2)
and Chief Financial 2001 376,333 225,000 - 60,000 22,582 (2)
Officer
- -------------------------------------------------------------------------------------------------------------------------------
Douglas B. Otten 2003 416,152 226,170 - 37,000 24,969 (2) / 60,221 (3)
Senior Vice President, 2002 485,873 125,886 - 35,000 29,156 (2) / 63,005 (3)
United States Oil and Gas 2001 456,783 405,685 - 28,000 27,407 (2) / 79,874 (3)
- -------------------------------------------------------------------------------------------------------------------------------
Thomas A. Sugalski 2003 384,439 156,380 - 30,000 23,066 (2) / 53,395 (3)
Senior Vice President, 2002 449,993 118,019 - 30,000 26,999 (2) / 60,889 (3)
Chemicals 2001 422,908 232,240 417,695 (4) 25,000 25,374 (2) / 76,059 (3)
- -------------------------------------------------------------------------------------------------------------------------------
Laurence Murphy 2003 366,500 196,000 - 37,000 21,990 (2)
Senior Vice President, 2002 346,000 90,000 - 35,000 20,760 (2)
International Oil and Gas 2001 329,250 180,000 - 28,000 19,758 (2)
- -------------------------------------------------------------------------------------------------------------------------------
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) Contributions to the Employee Savings Plan.
(3) Nexen contributed to a Qualified Defined Contribution Plan and a
Restoration Plan with Nexen Petroleum U.S.A. Inc. for Mr. Otten and Mr.
Sugalski.
(4) Represents a special settlement payment for termination from Occidental
Petroleum Corporation Non-Qualified Executive Benefit Plans.
108
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
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. Options granted before February 2001 have 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. Options granted after February 2001
have a term of five years and 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 2003
- -------------------------------------------------------------------------------------------------------------------------------
% of Total Potential Realizable Value at
Options/Stock Assumed Annual Rates of Stock
Appreciation Price Appreciation for Option Term
Rights ------------------------------------
Securities Granted to
Underlying Employees
Options in Exercise or
Granted Financial Base Price (1)
Name (#) Year ($/Security) (2) Expiration Date 5% ($) 10% ($)
- -------------------------------------------------------------------------------------------------------------------------------
Charles W. Fischer 100,000 3.5 43.50 December 9, 2008 1,201,825 2,655,719
- -------------------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow 55,000 1.9 43.50 December 9, 2008 661,004 1,460,645
- -------------------------------------------------------------------------------------------------------------------------------
Douglas B. Otten 37,000 1.3 33.38 (US$) December 9, 2008 417,161 921,816
- -------------------------------------------------------------------------------------------------------------------------------
Thomas A. Sugalski 30,000 1.1 33.38 (US$) December 9, 2008 357,566 790,128
- -------------------------------------------------------------------------------------------------------------------------------
Laurence Murphy 37,000 1.3 43.50 December 9, 2008 444,675 982,616
- -------------------------------------------------------------------------------------------------------------------------------
Notes:
(1) Equal to the market value of securities underlying options on the date of
grant.
(2) All values in Canadian dollars unless otherwise noted.
OPTIONS EXERCISED DURING 2003 AND FINANCIAL YEAR-END OPTION VALUES
- ----------------------------------------------------------------------------------------------------------------------------------
Number of Securities
Underlying Unexercised Value of Unexercised
Securities Acquired Options at Financial In-The-Money-Options at
on Exercise Value Realized (1) Year-end Financial Year-end
Name (#) ($) (2) (#) ($)(2)
Exercisable / Unexercisable Exercisable / Unexercisable
- ----------------------------------------------------------------------------------------------------------------------------------
Charles W. Fisher - - 424,750 / 214,650 8,267,883 / 1,871,016
- ----------------------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow - - 199,200 / 117,800 3,012,334 / 920,106
- ----------------------------------------------------------------------------------------------------------------------------------
Douglas B. Otten 71,329 1,240,978 146,131 / 75,340 2,370,825 / 742,312
- ----------------------------------------------------------------------------------------------------------------------------------
Thomas A. Sugalski 51,000 578,078 95,950 / 65,050 1,545,036 / 1,088,696
- ----------------------------------------------------------------------------------------------------------------------------------
Laurence Murphy - - 170,660 / 77,340 3,199,051 / 658,699
- ----------------------------------------------------------------------------------------------------------------------------------
Notes:
(1) Equals market price at the time of the exercise minus exercise price.
(2) All values in Canadian dollars.
109
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 $14 million to the Defined Benefit Pension Plan in 2003.
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, 2003 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
---------------------------------------------------------------------------------------------------------------------
$500,000 $41,681 $83,363 $125,044 $166,726 $208,407 $250,089 $291,770
---------------------------------------------------------------------------------------------------------------------
$550,000 $45,931 $91,863 $137,794 $183,726 $229,657 $275,589 $321,520
---------------------------------------------------------------------------------------------------------------------
$600,000 $50,181 $100,363 $150,544 $200,726 $250,907 $301,089 $351,270
---------------------------------------------------------------------------------------------------------------------
$650,000 $54,431 $108,863 $163,294 $217,726 $272,157 $326,589 $318,020
---------------------------------------------------------------------------------------------------------------------
$700,000 $58,681 $117,363 $176,044 $234,726 $293,407 $352,089 $410,770
---------------------------------------------------------------------------------------------------------------------
$750,000 $62,931 $125,863 $188,794 $251,726 $314,657 $377,589 $440,520
---------------------------------------------------------------------------------------------------------------------
$800,000 $67,181 $134,363 $201,544 $268,726 $335,907 $403,089 $470,270
---------------------------------------------------------------------------------------------------------------------
$850,000 $71,431 $142,863 $214,294 $285,726 $357,157 $428,589 $500,020
---------------------------------------------------------------------------------------------------------------------
$900,000 $75,681 $151,363 $227,044 $302,726 $378,407 $454,089 $529,770
---------------------------------------------------------------------------------------------------------------------
$950,000 $79,931 $159,863 $239,794 $319,726 $399,657 $479,589 $559,520
---------------------------------------------------------------------------------------------------------------------
$1,000,000 $84,181 $168,363 $252,544 $336,726 $420,907 $505,089 $589,270
---------------------------------------------------------------------------------------------------------------------
$1,050,000 $88,431 $176,863 $265,294 $353,726 $442,157 $530,589 $619,020
---------------------------------------------------------------------------------------------------------------------
$1,100,000 $92,681 $185,363 $278,044 $370,726 $463,407 $556,089 $648,770
---------------------------------------------------------------------------------------------------------------------
$1,150,000 $96,931 $193,863 $290,794 $387,726 $484,657 $581,589 $678,520
---------------------------------------------------------------------------------------------------------------------
$1,200,000 $101,181 $202,363 $303,544 $404,726 $505,907 $607,089 $708,270
---------------------------------------------------------------------------------------------------------------------
$1,250,000 $105,431 $210,863 $316,294 $421,726 $527,157 $632,589 $738,020
---------------------------------------------------------------------------------------------------------------------
$1,300,000 $109,681 $219,363 $329,044 $438,726 $548,407 $658,089 $767,770
---------------------------------------------------------------------------------------------------------------------
$1,350,000 $113,931 $227,863 $341,794 $455,726 $569,657 $683,589 $797,520
---------------------------------------------------------------------------------------------------------------------
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 19.58, 16.50 and 17.67 years of
credited service, respectively.
110
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.
DIRECTOR COMPENSATION
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 was paid an annual retainer of $108,000 until the end of
2003. The Chair of each Committee is paid an additional annual retainer of
$5,300. In October 2003, all director compensation was reviewed and the annual
retainer for the Chair of the Board was increased to $150,000.
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 annually 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,
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 2003, the Board adopted a policy setting out that non-executive directors
would no longer be granted stock options. Non-executive directors will not be
eligible to receive stock options under the proposed amendments to the Stock
Option Plan. Deferred Stock Units have since been employed as an alternate
method of performance-based compensation. In December 2003, all directors who
were not employees of Nexen were granted 2,100 DSUs, except for the Chair of the
Board, who was granted 3,200 DSUs.
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 2003 was approximately US$0.6 million.
SHARE OWNERSHIP GUIDELINES FOR DIRECTORS
The Board believes it is important that directors demonstrate their commitment
through share ownership. The Board has approved guidelines setting out that
directors are expected to own or control at least 3,000 shares, to be
accumulated over three years. Specific arrangements may be made when a qualified
candidate might be precluded from serving by these guidelines. The guidelines
are reviewed by the Board from time to time.
111
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 reports to the Board and the Board gives final approval to
compensation matters. The Committee evaluates the performance of the CEO and
recommends his compensation which is approved by the independent directors of
the Board.
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.
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-quarter
of the overall assessment. The qualitative assessment of the balanced scorecard
performance indicators provides a comprehensive evaluation and accounts for the
remaining one-half 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 interests 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 for 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 variable pay
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 2003 was on providing differentiated awards based on
performance, potential and retention risk.
112
The total options granted and shares reserved for issuance under our stock-based
compensation arrangements will not, at any time, exceed 10% of our 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, flow-through shares, shares purchased and held
within the Nexen Savings Plan and any other personal holdings.
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.
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
2002, his base salary was increased to $750,000 in 2003 and he was awarded a
bonus of $600,000 under the Annual Incentive Plan.
Mr. Fischer was also granted options to purchase 100,000 shares at an exercise
price of $43.50 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:
John Willson, Chair
Dave Hentschel
Barry Jackson
Francis Saville, Q.C.
Dick Thomson, O.C.
Vic Zaleschuk
113
SHARE PERFORMANCE GRAPH
The following graph shows changes in the past five year period, ending December
31, 2003 in the value of $100 invested in our common shares, compared to the
S&P/TSX Composite Index, the S&P/TSX Energy Sector Index and the S&P/TSX Oil &
Gas Exploration & Production Index as at December 31, 2003. Our common shares
are included in each of these indices.
TOTAL RETURN INDEX VALUES
[CHART OMMITTED]
1998/12 1999/12 2000/12 2001/12 2002/12 2003/12
- ------------------------------------------------------------------------------------------------------------------------
Nexen Inc. 100.00 181.55 237.58 201.38 223.69 309.16
S&P/TSX Energy Sector Index 100.00 126.86 187.36 200.31 227.84 284.72
S&P/TSX Oil & Gas Explor. & Prod. Index 100.00 122.38 179.94 185.75 215.78 259.26
S&P/TSX Composite Index 100.00 131.71 141.47 123.69 108.30 137.25
Assuming an investment of $100 and the reinvestment of dividends
114
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. Based on
information known to Nexen, the following table shows each person or group who
beneficially owns (pursuant to SEC Regulations) more than 5% of Nexen's voting
securities at December 31, 2003.
# OF SHARES
NAME AND ADDRESS OF BENEFICIAL OWNER BENEFICIALLY OWNED % OF SHARES
- ----------------------------------------------------------------------------------------------------
Jarislowsky Fraser Limited (1) 21,565,906 17.2
Suite 2005, 1010 Sherbrooke Street West
Montreal, Quebec, Canada, H3A 2R7
- ----------------------------------------------------------------------------------------------------
Ontario Teachers' Pension Plan Board (2) 19,533,318 15.6
5650 Yonge Street
Toronto, Ontario, Canada, M2M 4H5
- ----------------------------------------------------------------------------------------------------
Capital Research and Management Co. (3) 7,080,010 5.6
333 South Hope Street
Los Angeles, California, U.S.A., 90071-1447
- ----------------------------------------------------------------------------------------------------
Notes:
(1) The beneficial owner has sole voting power over 19,262,406 shares, shared
voting power over 2,303,500 shares; and sole power to dispose of all of the
shares.
(2) The beneficial owner has sole voting and power to dispose all of the
shares.
(3) The beneficial owner has sole power to dispose all of the shares and
disclaims beneficial ownership pursuant to Rule 13d-4.
SECURITY OWNERSHIP OF MANAGEMENT
At December 31, 2003, the following directors, certain executive officers, and
all directors and executive officers as a group beneficially owned the following
Nexen common shares:
NUMBER OF EXERCISABLE
NAME OF BENEFICIAL OWNER SHARES (1) STOCK OPTIONS (2)
- ------------------------------------------------------------------------------------------------------------------
Charles W. Fischer 28,096 424,750
- ------------------------------------------------------------------------------------------------------------------
Dennis G. Flanagan 3,001 18,225
- ------------------------------------------------------------------------------------------------------------------
David A. Hentschel 5,615 28,225
- ------------------------------------------------------------------------------------------------------------------
S. Barry Jackson 6,000 6,225
- ------------------------------------------------------------------------------------------------------------------
Kevin J. Jenkins 3,044 28,225
- ------------------------------------------------------------------------------------------------------------------
Eric P. Newell, O.C. Nil Nil
- ------------------------------------------------------------------------------------------------------------------
Thomas C. O'Neill 4,000 1,870
- ------------------------------------------------------------------------------------------------------------------
Francis M. Saville, Q.C. 3,151 28,225
- ------------------------------------------------------------------------------------------------------------------
Richard M. Thomson, O.C. 23,001 42,388
- ------------------------------------------------------------------------------------------------------------------
John M. Willson 5,001 28,225
- ------------------------------------------------------------------------------------------------------------------
Victor J. Zaleschuk 15,612 297,025
- ------------------------------------------------------------------------------------------------------------------
Laurence Murphy 19,480 170,660
- ------------------------------------------------------------------------------------------------------------------
Douglas B. Otten 17,200 146,131
- ------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow 19,627 199,200
- ------------------------------------------------------------------------------------------------------------------
Thomas A. Sugalski 9,663 95,950
- ------------------------------------------------------------------------------------------------------------------
All directors and executive officers as a group (22 persons) 212,435 2,005,874
- ------------------------------------------------------------------------------------------------------------------
Notes:
(1) The number of shares held and stock options exercisable by each beneficial
owner represents less than 1% of the shares outstanding.
(2) Includes all stock options exercisable within 60 days of December 31, 2003.
Under the terms of our stock option plan, the Board of Directors may grant stock
options to officers and employees and, when previously allowed for, to
directors. Nexen does not receive any consideration when options are granted.
115
Equity Compensation Plan Information:
(a) (b) (c)
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 9,203,121 $34.00 9,787,853
---------------------------------------------------------------------------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CERTAIN BUSINESS RELATIONSHIPS
Mr. Saville, a director, was a senior partner of Fraser Milner Casgrain LLP
(FMC), Barristers and Solicitors, Calgary, Alberta until the end of January
2004. Beginning on February 1, 2004, he is counsel with the firm. FMC has
rendered legal services to Nexen during each of the last five years. Mr. Saville
is independent pursuant to the Categorical Standards for Director Independence
(Categorical Standards) adopted by Nexen.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
AUDIT FEES
Fees billed by Deloitte & Touche LLP were:
o $596,000 for 2003 ($550,000 for 2002) for the audit of the Consolidated
Financial Statements included in our Annual Report on Form 10-K.
o $42,000 for the 2003 first, second and third quarter reviews ($31,000
for the 2002 second and third quarter reviews) for the Consolidated
Financial Statements included on Form 10-Qs.
Fees billed by Arthur Andersen LLP during 2002 were $13,000 for the 2002 first
quarter review of the Consolidated Financial Statements included on our form
10-Q.
AUDIT-RELATED FEES
Fees billed by Deloitte & Touche LLP, were:
o $322,000 for 2003 ($231,500 for 2002) for the annual audits of our
subsidiary financial statements and employee benefit plans.
o $87,000 for 2003 ($4,000 for 2002) for comfort letters to commissions.
Fees billed by Arthur Andersen LLP during 2002 were $88,300 for comfort letters
to commissions.
TAX FEES
Fees billed by Deloitte & Touche LLP, were $160,000 for 2003 ($72,550 for 2002)
for tax return preparation assistance and tax-related consultation. Fees billed
by Arthur Andersen LLP during 2002 were $106,601 for tax return preparation
assistance and tax-related consultation.
ALL OTHER FEES
No other fees were billed by Deloitte & Touche LLP during 2003. Fees billed by
Arthur Andersen LLP during 2002 were $62,900 for assisting the internal audit
group with its evaluation of the implementation of an enterprise-wide resource
system.
AUDIT COMMITTEE APPROVAL
Before Deloitte & Touche LLP is engaged by Nexen or our subsidiaries to render
audit or non-audit services, the engagement is approved by Nexen's Audit
Committee. All audit-related and tax services provided by Deloitte & Touche LLP
after May, 6, 2003 were approved by our Audit Committee.
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PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
FINANCIAL STATEMENTS AND SCHEDULES
We refer you 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 because
they are not required or applicable, or the required information is shown in the
Consolidated Financial Statements or notes.
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).
3.9 By-Law No. 2 of the Registrant enacted December 9, 2003, being a by-law
relating generally to the transaction of the business and affairs of
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) (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 (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).
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 (filed
as Exhibit 4.38 to Form 10-K for the year ended December 31, 2002,
filed by the Registrant).
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
(filed as Exhibit 4.39 to Form 10-K for the year ended December 31,
2002, filed by the Registrant).
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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).
4.42 Trust Indenture dated April 28, 1998 between the Registrant and CIBC
Mellon Trust Company providing for the issue of debt securities from
time to time.
4.43 First Supplemental Indenture dated April 28, 1998 to the Trust
Indenture dated April 28, 1998 between the Registrant and CIBC Mellon
Trust Company pertaining to the issuance of US $200 million, 7.40%
notes due 2028.
4.44 Third Amending Agreement dated July 29, 2003 to the October 16, 2000
Restated Loan Agreement of April 14, 1997 between the Registrant, the
Toronto Dominion Banks, as Agent, and the Lenders.
4.45 Third Amending Agreement dated July 29, 2003 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.
4.46 Third Supplemental Indenture dated March 11, 2002 to the Trust
Indenture dated April 28, 1998 between the Registrant and CIBC Mellon
Trust Company pertaining to the issuance of $500 million, 7.85% notes
due 2032.
4.47 Subordinated Debt Indenture dated November 4, 2003 between the
Registrant and Deutsche Bank Trust Company Americas, pertaining to the
issue of subordinated notes from time to time.
4.48 Officer's Certificate dated November 4, 2003 pursuant to the
Subordinated Debt Indenture dated November 4, 2003 between the
Registrant and Deutsche Bank Trust Company Americas, pertaining to the
issuance of US $460 million, 7.35% subordinated notes due 2043.
4.49 Fourth Amending Agreement dated November 4, 2003 to the October 16,
2003 Restated Loan Agreement of April 14, 1997, between the Registrant,
the Toronto Dominion Banks, as Agent, and the Lenders.
4.50 Fourth Amending Agreement dated November 4, 2003 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.
4.51 Fourth Supplemental Indenture dated November 20, 2003 to the Trust
Indenture dated April 28, 1998, between the Registrant and CIBC Mellon
Trust Company pertaining to the issuance of US $500 million, 5.05%
notes due 2013.
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 (filed as Exhibit 10.41 to Form 10-K
for the year ended December 31, 2002, filed by the Registrant).
10.42 Indemnification Agreement made between the Registrant and one of its
directors, Eric P. Newell, as of January 5, 2004.
11.2 Statement regarding the Computation of Per Share Earnings for the three
years ended December 31, 2003.
16.1 Letter re change in certifying accountant (filed as Exhibit 16.1 to
Form 8-K filed July 17, 2002 by the Registrant).
21.0 Subsidiaries of the Registrant.
23.0 Consent of Independent Chartered Accountants.
31.1 Certification of Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 Certification of periodic report by Chief Executive Officer pursuant to
18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 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.
99.1 Opinion of Internal Qualified Reserves Evaluator on National Instrument
51-101 Form F2 as required by certain Canadian securities regulatory
authorities.
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REPORTS ON FORM 8-K
During the quarter ended December 31, 2003, we filed or furnished the following
report on Form 8-K:
o Current report on Form 8-K dated October 16, 2003, to furnish our press
release announcing our 2003 third quarterly results.
Up until the filing of this Form 10-K, during 2004, we filed or furnished the
following reports on Forms 8-K:
o Current report on Form 8-K dated February 5, 2004, to file our press
release announcing our reserves as at December 31, 2003.
o Current report on Form 8-K dated February 13, 2004, to furnish our
press release announcing our 2003 annual results.
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 20, 2004.
NEXEN INC.
By: /s/ Charles W. Fischer
-------------------------
Charles W. Fischer
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 20, 2004.
/s/ Dennis G. Flanagan /s/ Charles W. Fischer
- --------------------------------- ---------------------------------
Dennis G. Flanagan, Director Charles W. Fischer
President, Chief Executive Officer
and Director
/s/ David A. Hentschel (Principal Executive Officer)
- ---------------------------------
David A. Hentschel, Director
/s/ Marvin F. Romanow
/s/ S. Barry Jackson ---------------------------------
- --------------------------------- Marvin F. Romanow
S. Barry Jackson, Director Executive Vice President and
Chief Financial Officer
/s/ Kevin J. Jenkins (Principal Financial Officer)
- ---------------------------------
Kevin J. Jenkins, Director /s/ Michael J. Harris
---------------------------------
/s/ Eric P. Newell Michael J. Harris
- --------------------------------- Controller
Eric P. Newell, Director (Principal Accounting Officer)
/s/ Thomas C. O'Neill /s/ John B. Mcwilliams
- --------------------------------- ---------------------------------
Thomas C. O'Neill, Director John B. McWilliams
Senior Vice President, General
/s/ Francis M. Saville Counsel and Secretary
- ---------------------------------
Francis M. Saville, Director /s/ Kevin J. Reinhart
---------------------------------
/s/ Richard M. Thomson Kevin J. Reinhart
- --------------------------------- Vice President, Corporate Planning
Richard M. Thomson, Director and Business Development
/s/ John M. Willson
- ---------------------------------
John M. Willson, Director
/s/ Victor J. Zaleschuk
- ---------------------------------
Victor J. Zaleschuk, Director
119