ITEMS 1 AND 2. BUSINESS AND PROPERTIES
TABLE OF CONTENTS
PAGE
About Us.......................................................................3
Strategy.......................................................................4
Understanding the Oil and Gas Business.........................................4
Oil and Gas Operations.........................................................4
Gulf of Mexico - United States..........................................5
North Sea - United Kingdom..............................................7
Middle East - Yemen.....................................................9
Offshore West Africa...................................................11
Other International....................................................12
Western Canada.........................................................13
Athabasca Oil Sands ...................................................15
Reserves, Production and Related Information..................................17
Syncrude Mining Operations....................................................19
Oil and Gas Marketing.........................................................21
Chemicals.....................................................................22
Additional Factors Affecting Business.........................................23
Government Regulations.................................................23
Environmental Regulations..............................................23
Employees.....................................................................24
2
ABOUT US
Nexen Inc. (Nexen, we or our) is an independent, Canadian-based, global energy
and chemicals company. Previously Canadian Occidental Petroleum Ltd., we were
formed in Canada in 1971 from the reorganization of two Occidental Petroleum
Corporation (Occidental) subsidiaries. We combined their Canadian crude oil,
natural gas, sulphur and chemical operations. We've grown from producing 10,700
boe/d before royalties with revenues of $26 million in 1971 to 249,600 boe/d
before royalties (including Syncrude production) and revenues of $3.9 billion in
2004. We achieved this growth through exploration success and strategic
acquisitions. Through over 30 years of operations, we have been profitable every
year, but one, and have been paying quarterly dividends consecutively since
1975.
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[Margin Text: Nexen - an independent, Canadian-based global energy and chemicals
company.]
In the 1970s, we expanded our Western Canadian assets and entered the US Gulf of
Mexico. We finished this decade with production of approximately 11,000 boe/d
before royalties and revenues of $126 million.
In the 1980s, we acquired Canada-Cities Service, Ltd. in 1983, which doubled our
size, and included an interest in the Syncrude Joint Venture, our entry into the
Athabasca oil sands. Acquisitions of Cities Offshore Production Co. in 1984, and
Moore McCormack Energy, Inc. in 1988, further increased our presence in the Gulf
of Mexico. We finished this decade with production of approximately 68,600 boe/d
before royalties and revenues of $591 million.
In the 1990s, we had two defining moments: discovering oil on the Masila block
in Yemen and acquiring Wascana Energy Inc. The first of 17 fields at Masila was
discovered in 1991, and Masila has produced over 825 million barrels since
start-up. Our 1997 purchase of Wascana Energy Inc. almost tripled our Canadian
production, with our Hay discovery in northern B.C. increasing this further. In
1998, we entered Australia with an interest in the offshore Buffalo field and
entered Nigeria as the operator of the Ejulebe field. Also in 1998, we
discovered Ukot on OPL-222, offshore Nigeria, the first of several discoveries
to date on the block. We finished this decade with production of approximately
239,200 boe/d before royalties and revenues of $1.7 billion.
[GRAPHICS OMITTED]
[Margin Graphic: Chart of Production before royalties 1971 - 2004]
[Margin Graphic: Chart of Revenues 1971 - 2004.]
So far in the 21st century, we have made a number of discoveries and two
strategic acquisitions. In 2000, we discovered Gunnison in the deep-water Gulf
of Mexico and Guando in Colombia. In that same year, we agreed with Ontario
Teachers' Pension Plan Board (Teachers) and Occidental, to purchase Occidental's
29% interest in us. Teachers purchased 20.2 million common shares and we
repurchased the remaining 20 million common shares for $605 million. We also
exchanged our oil and gas operations in Ecuador for Occidental's 15% interest in
our chemicals operations. In addition, we changed our name to Nexen Inc. The
following year, we discovered Aspen in the deep-water Gulf and signed a joint
venture agreement with OPTI Canada Inc. to develop, produce and upgrade bitumen
at Long Lake. On OPL-222, offshore Nigeria, we discovered Usan, the second
discovery on the block, in 2002. In 2003, we discovered two fields on Block 51
in Yemen. In December 2004, we acquired EnCana Corporation's U.K. subsidiary,
providing us with strategic operatorship of the Buzzard discovery and the
producing Scott and Telford fields in the North Sea. Now in 2005, we are
developing major projects and continuing an active exploration program for
future growth.
For financial reporting purposes, we report on four main segments:
o Oil and Gas
o Syncrude
o Oil and Gas Marketing and
o Chemicals
Our Oil and Gas operations are broken down geographically into the US Gulf of
Mexico, North Sea, Canada, Yemen and Other International (Colombia, offshore
West Africa, and Australia). Results from our Long Lake Project are included in
Canada. Syncrude is our 7.23% interest in the Syncrude Joint Venture. Marketing
includes our growing crude oil, natural gas and power marketing business in
North America and southeast Asia. Chemicals includes operations in North America
and Brazil that manufacture, market and distribute sodium chlorate, caustic soda
and chlorine.
Production, revenues, net income, capital expenditures and identifiable assets
for these segments appears in Note 18 to the Consolidated Financial Statements
and in Management's Discussion and Analysis of Financial Condition and Results
of Operations (MD&A) in this report.
3
STRATEGY
Our goal is to grow long-term value for shareholders. We define value growth
as increasing reserves, production and cash flow over the long term, measured on
a debt-adjusted per share basis. This basis reflects the true growth realized by
our shareholders. To accomplish this, we are creating sustainable businesses
through exploration, technology application, strategic acquisitions and capital
discipline.
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[Margin text: Our goal is to grow long-term value for shareholders.]
As conventional basins in North America mature, we are transitioning our
operations towards major projects in mature basins, exploration in less mature
basins and exploitation of unconventional resources. Projects are focussed in
the North Sea, Athabasca oil sands, Gulf of Mexico, offshore West Africa and the
Middle East - basins we believe have attractive fiscal terms and significant
remaining opportunity.
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[Margin text: We are transitioning our operations towards major projects in
generally less mature basins and unconventional resources.]
Our major projects typically have an extended period of time between sanctioning
and first production due to their location and scale. These time lags cause
non-linear growth year-over-year and significant up-front capital investment
prior to realizing any production or revenues. We fund projects by maximizing
cash flow from our producing assets, using various financial instruments, and
selling non-core assets into attractive markets. We intend to dispose
approximately $1.5 billion of assets in 2005 to help pay for our North Sea
acquisition.
We also continue an active exploration program for future growth. We primarily
explore in areas where we have existing production or infrastructure, or we have
had recent exploration success.
In creating sustainable businesses, we are committed to good corporate
governance and social responsibility. We believe companies that follow
sustainable business practices outperform those with narrower priorities. We
foster dialogue with stakeholders about our operational opportunities and
challenges, from exploration to production to reclamation. Our goal is to help
stakeholders become engaged participants in a continuing consultation process,
while balancing their multiple, and sometimes conflicting, goals.
UNDERSTANDING THE OIL AND GAS BUSINESS
The oil and gas industry is highly competitive. With strong global demand for
energy, there is intense competition to find and develop new sources of supply.
Yet, barrels from different reservoirs around the world do not have equal value.
Their value depends on the costs to find, develop and produce the oil or gas,
the fiscal terms of the host regime and the price products command at market
based on quality and marketing efforts. Our goal is to extract the maximum value
from each barrel of oil equivalent, so every dollar of capital we invest
generates an attractive return.
Numerous factors can affect this. Changes in 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 how much we invest in oil and gas exploration and
development. We attempt to mitigate these impacts by investing in projects that
we believe will generate positive returns at low commodity prices.
We also have a broad customer base for our crude oil and natural gas.
Alternative customers are generally available, and the loss of any one customer
is not expected to have a significant adverse effect on the price of our
products or our revenues. Oil and gas producing operations are generally not
seasonal. However, demand for certain of our products can have a seasonal
component, which can impact price. In particular, heavy oil generally
experiences higher demand in the summer months for its use in road construction
and natural gas generally experiences higher demand in the winter heating
months.
We manage our operations on a country-by-country basis reflecting differences in
the regulatory and competitive environments and risk factors associated with
each country.
OIL AND GAS OPERATIONS
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[Graphic-World map showing location of oil and gas operations around the world]
We have oil and gas operations in Western Canada, the US Gulf of Mexico, Yemen,
the North Sea, offshore West Africa, Colombia and Australia. We also have
operations in Canada's Athabasca oil sands which produce synthetic crude oil. We
operate most of our production, and continue to develop new growth opportunities
in each area, by actively exploring and applying technology.
[GRAPHIC OMITTED]
[Margin graphic: Pie chart 2004 production before royalties by area]
4
GULF OF MEXICO - UNITED STATES (US)
The Gulf of Mexico is Nexen's fastest growing region, with over 30,000 boe/d
before royalties of high margin production added from our deep-water Aspen and
Gunnison fields in the past two years.
[GRAPHICS OMITTED]
[Margin caption: In the US, we've added 30,000 boe/d before royalties of
high-margin production in the last two years.]
[Graphic: Gulf of Mexico map with Nexen's producing and exploration blocks]
Large discoveries, high success rates, production infrastructure and attractive
fiscal terms make the deep-water Gulf of Mexico one of the world's most
prospective sources for oil and gas. The deep-water prospects generally have
multiple productive horizons and high production rates, which reduces risk and
improves economics. Technology to find, drill, and develop discoveries is
rapidly progressing and becoming more cost effective. And, the deep-water Gulf
is relatively close to infrastructure and continental US markets, allowing
discoveries to be brought on stream in a reasonable period of time.
Our strategy in the Gulf is to explore for new reserves, acquire assets with
potential, and exploit our existing asset base. We focus our exploration program
on three strategic areas:
o deep-shelf gas prospects;
o deep-water prospects near existing infrastructure; and
o deep-water, sub-salt plays with potential to become new core areas.
These areas are relatively under-explored, have potential for large discoveries,
and have attractive fiscal terms. The shorter-cycle times for shelf gas and
deep-water prospects near infrastructure complement the longer-cycle times for
deep-water, sub-salt plays.
When we first entered the deep-water, we partnered with large experienced
operators to improve our skills and understanding. A trade-off of this strategy
was not controlling the timing of drilling programs. Our goal is to operate even
more of our own deep-water properties and exploration wells so that we can
manage the pace of activity. In 2004, we invested $400 million on exploration
and development activities to further our strategy. We plan to invest
approximately $315 million in 2005.
In 2004, we produced approximately 54,700 boe/d before royalties (47,500 after
royalties), representing about 22% of Nexen's total production. Proved reserves
of 88 mmboe (103 before royalties) at year-end 2004 were about 20% of Nexen's
total proved oil and gas reserves after royalties. Our production and reserves
in the Gulf are primarily concentrated in five shallow-water fields and two
deep-water fields. We operate most of this production, and hold varying
interests on 182 undeveloped federal lease blocks.
[GRAPHIC OMITTED]
[Margin graphic: US Production before royalties 2002-2004 chart,
separated by deep and shallow water]
US PRODUCTION
2004 2003 2002
---------------------------------------------------------------------------------------------------
Before After Before After Before After
(mboe/d) Royalties Royalties Royalties Royalties Royalties Royalties
---------------------- ----------------------- -----------------------
Shallow-water 22.6 18.8 28.5 23.7 28.1 23.2
Deep-water 32.1 28.7 24.0 21.7 0.5 0.5
---------------------- ----------------------- -----------------------
Total 54.7 47.5 52.5 45.4 28.6 23.7
======================= ======================= =======================
Royalty rates on our US production average 17% for shallow-water volumes and 10%
for deep-water volumes. We qualify for royalty relief at our deep-water Aspen
and Gunnison fields on the first 87.5 mmboe of production, making this
production very attractive. We are subject to royalties at Gunnison if the
annual commodity prices are higher than threshold prices set by the US
Department of the Interior's Minerals Management Service. Royalties on other
Gulf and state-water properties range from 12.5% to 25%. US taxable income is
subject to federal income tax of 35% and state taxes ranging from 0% to 8%.
Weather is a risk in the Gulf of Mexico, specifically tropical storms and
hurricanes. They can damage facilities, interrupt production, and delay
exploration and development programs, beyond the few days of the storm itself.
In September 2004, we shut-in 45,000 boe/d of production before royalties for
three days, as Hurricane Ivan passed through. No significant damage was
sustained at our facilities and full production was restored shortly thereafter.
In October 2002, we suffered extensive facilities damage at Eugene Island 295
from Hurricane Lili. Production was restored there in early 2003.
5
SHALLOW-WATER PRODUCTION
Our shelf producing assets are offshore Louisiana primarily in five 100% owned
fields: Eugene Island 18, Eugene Island 255/257/258/259, Eugene Island 295,
Vermilion 302/320 and Vermilion 76 (consisting of blocks 65, 66 and 67). We
continue to exploit these assets, and look for other opportunities on the shelf.
Most of our 2004 shelf development operations focused on increasing production
at Vermilion 76 and 302/320, through development drilling activities.
DEEP-WATER PRODUCTION
Our deep-water production comes from our 100% operated Aspen field and our 30%
non-operated Gunnison field. Our Gunnison SPAR production facility has excess
capacity, leaving room for growth from exploration and processing of third-party
volumes.
[GRAPHIC OMITTED]
[Margin text: Aspen achieved payout in just over 2 years.]
ASPEN
Aspen is located on Green Canyon Block 243 in 3,150 feet of water. The project
was developed using sub-sea wells tied back to the Shell-operated Bullwinkle
platform 16 miles away. Production began in December 2002. By tying-in a third
Aspen development well in July 2004, we increased 2004 production by 11,000
boe/d before royalties to 27,200 boe/d before royalties at year-end (24,600
after royalties), of which 14% was natural gas. There are no significant capital
plans for Aspen in 2005. We achieved payout on the full Aspen project in
early-2005, just over 2 years from first production.
GUNNISON
Gunnison is located in 3,100 feet of water, and includes Garden Banks Blocks
667, 668 and 669. The first discovery was in May 2000 on Garden Banks Block 668,
and the second in June 2001 on Garden Banks Block 667.
Gunnison began production in December 2003 through a truss SPAR platform that
can handle 40,000 barrels of oil per day and 200 million cubic feet of gas per
day. Our share of 2004 production before royalties was approximately 9,300 boe/d
(8,200 after royalties). During 2005, we plan to drill and tie-in two additional
development wells.
[GRAPHIC OMITTED]
[Graphic: Gunnison SPAR schematic with caption: Our Gunnison SPAR has capacity
for future discoveries and third-party volumes.]
EXPLORATION
In 2004, half of our exploration budget was invested in the Gulf. The results in
2004 were mixed with four small discoveries and five abandoned wells:
WELL LOCATION INTEREST (%) RESULTS
---------------------------------------------------------------------------------------------------------------------------
Dawson Deep Garden Banks 625 15 discovery expected to begin producing late-2005
through sub-sea tie-back to Gunnison
Tobago Alaminos Canyon 13.34 discovery temporarily abandoned; possibly part of
858/859 future regional development
Wrigley Mississippi Canyon 50 gas discovery expected to begin producing in
506 mid-2006
Anduin Mississippi Canyon 50 encountered oil shows; side-tracking to delineate
754/755
Shark South Timbalier 174 40 well abandoned
Crested Butte Green Canyon 242 100 well abandoned as oil shows were close to salt;
further work required to see if side-track
warranted
Main Pass 240 Main Pass 240 45 well abandoned; found non-commercial quantities
Fawkes Garden Banks 303 33 1/3 well abandoned; found non-commercial quantities
Wind River West Cameron 335 50 well abandoned
In 2004, we also increased our deep-water undeveloped land position to 148
blocks, by acquiring 19 blocks. We expect this acreage, plus new opportunities,
to sustain our current level of exploration drilling.
6
We are in the midst of our most active Gulf exploration program ever, with two
wells drilling and two more to begin drilling in the first half of 2005. Wells
currently drilling with results expected in the first half of 2005 include:
OPERATOR
WELL LOCATION INTEREST (%) STATUS STRATEGY
-----------------------------------------------------------------------------------------------------------------------
Big Bend Mustang Island A-110 50 non-operated deep-shelf gas
Vrede Atwater Valley 223/224/267/268 25 non-operated deep-water
We expect to drill other deep-shelf gas and deep-water prospects in 2005, the
most significant deep-water prospects are at Pathfinder (25% interest) and
Knotty Head (25% interest).
[GRAPHIC OMITTED]
[Margin text: We are in the midst of our strongest Gulf Exploration program
ever.]
NORTH SEA - UNITED KINGDOM (UK)
On December 1, 2004, we acquired assets in the UK North Sea for US$2.1 billion
in cash subject to certain adjustments. This acquisition was completed by
purchasing all outstanding shares of EnCana (UK) Limited. We acquired a 43.2%
operated interest in the Buzzard development, operated interests in the Scott
and Telford producing fields, the Scott production platform, interests in
several satellite discoveries and over 700,000 net undeveloped exploration
acres. We also acquired the management and technical teams that found and
continue to develop Buzzard. From this acquisition we booked 130 mmboe of proved
reserves (130 before royalties) comprising 29% of Nexen's total oil and gas
reserves after royalties.
[GRAPHIC OMITTED]
[Graphic: North Sea map with Nexen's producing and exploration blocks.]
INTEREST OPERATOR
FIELD LOCATION (%) STATUS COMMENTS
-----------------------------------------------------------------------------------------------------------------------
Buzzard Blocks 19/10, 20/6, 43.2 operated expected on stream late-2006 ramping up to
19/5a, 20/1s 80,000 boe/d our share in 2007
Scott Blocks 15/21a, 15/22 41 operated producing field with exploitation
opportunities
Telford Blocks 15/21a, 15/22 54.3 operated producing field with exploitation
opportunities
Ettrick Blocks 20/2a, 20/3a 80 operated discovery near Buzzard
Farragon Block 16/28 20 non- expected on stream late-2005 at 3,000
operated boe/d our share
Perth Block 15/21a 42 operated discovery near Scott
Black Horse Block 15/22 56 operated discovery near Scott
Bugle Block 15/23d 80 operated discovery near Scott
This acquisition establishes us as a significant regional player, with
concentrated assets, infrastructure and exploration and development potential
for future growth. It will add high-margin reserves and production, diversify
our world-wide portfolio by adding strong assets in a stable jurisdiction, and
complement the longer cycle-time projects we have in the Athabasca oil sands,
offshore West Africa, and the deep-water Gulf of Mexico.
[GRAPHIC OMITTED]
[Margin text: Our North Sea acquisition establishes us as a significant regional
player.]
Our UK strategy is focused on exploration and exploitation near existing
infrastructure. We have a number of exploitation opportunities in our existing
fields and smaller satellite discoveries close to infrastructure. Most of our
unexplored acreage is near Scott/Telford or Buzzard, and could be tied-in
quickly upon success.
The Scott field is subject to Petroleum Revenue Tax (PRT), although no PRT is
payable until available oil allowances have been fully utilized. No PRT is
expected to be payable before 2009. Once payable, PRT is levied at 50% of cash
flow after capital expenditures, operating costs and an oil allowance. PRT is
applicable to fields receiving development consent prior to March 1993, thereby
excluding both the Buzzard and Telford fields. PRT is deductible for corporate
income tax purposes. The UK corporate income tax rate is 30% of taxable income.
Income from oil and gas activities is also subject to a supplemental charge of
10%. Assuming WTI of US$30/bbl, we do not expect to pay current taxes until
2009. The amount and timing of income taxes payable depends on many factors
including price, production and capital investment levels.
7
BUZZARD
Buzzard is one of the largest discoveries in the UK North Sea in recent years.
Discovered in 2001, it is in the Outer Moray Firth, central North Sea,
approximately 100 km northeast of Aberdeen, in 100 metres of water.
Our Buzzard development involves contractors across Europe building a three
bridge-linked platform complex comprising wellhead, production and utilities
decks and topsides. The facilities will have capacities of 200,000 bbls/d of oil
and 60 mmcf/d of gas. Currently, we anticipate the field will produce through 27
production wells, eight pre-drilled and producing by late-2006. Reservoir
pressure will be maintained through an active water-flood program. We estimate
peak gross production rates in 2007 at 180,000 bbls/d of oil and approximately
30 mmcf/d of gas, with our share at 80,000 boe/d before royalties.
[GRAPHICS OMITTED]
[Graphic: Buzzard production facilities drawing]
[Margin text: Our share of royalty-free Buzzard production is expected to climb
to 80,000 boe/d in 2007.]
Work is well underway to construct jackets and topsides that will form the
Buzzard platform installation. At year-end 2004, the development project was
over 50% complete, on schedule and on budget. In 2005, we plan to invest $530
million to transport the three jackets to Buzzard, install them, install the
wellhead topsides, initiate drilling of the production wells, and install the
gas and oil export pipelines. In summer 2006, we plan to install the utilities
and production topsides and initiate hook-up and project commissioning.
Oil from Buzzard will be exported via the Forties Pipeline System to the
Grangemouth, Scotland refinery. Gas will be exported via the Frigg system to the
St. Fergus Gas Terminal in northeast Scotland.
SCOTT / TELFORD
Scott and Telford are both producing fields with additional exploitation
opportunities. Scott was discovered in 1987 and began producing in September
1993. Telford was discovered in 1991 and came on stream in 1996. Oil accounts
for over 85% of production at Scott and around 50% at Telford.
Oil and gas is produced through numerous subsea wells and from wells drilled
from the Scott platform. Oil is delivered to the Grangemouth, Scotland refinery
via the Forties pipeline. Gas is exported via the SAGE pipeline to a terminal at
St. Fergus in northeast Scotland.
In 2005, we plan to invest approximately $50 million to drill, complete, and
tie-in five development wells, work-over several existing wells, and
de-bottleneck and upgrade facilities on the Scott platform.
OTHER
We have a number of smaller discoveries on operated blocks near Scott, Buzzard
or third-party facilities. Ettrick could be developed using a floating
production facility, or tied-in to Buzzard (20 km away) once excess capacity is
available. Exploitation projects near Scott such as Perth, Black Horse and Bugle
are in various stages of evaluation. Farragon should begin producing in
late-2005, with our 20%, non-operated share of production expected to reach
between 3,000 and 4,000 boe/d before royalties in early 2006.
In 2005, we plan to drill at least four exploration wells and most are close to
Scott/Telford or Buzzard.
[GRAPHIC OMITTED]
[Margin text: We have a number of smaller discoveries near Scott, Buzzard or
third-party facilities.]
8
MIDDLE EAST - YEMEN
Yemen has been Nexen's most significant international region since first
production on the Masila Block in 1993. We operate the country's largest oil
project and have developed excellent relationships with the government and
communities near our operations. Our success and reputation in Yemen opens doors
elsewhere in the Middle East and around the world.
Our strategy here is to maximize value from our existing blocks while continuing
to search for new fields in deeper horizons. We have two producing blocks:
Masila (Block 14) and East Al Hajr (Block 51). In 2004, we produced 107,300
bbls/d before royalties (53,500 after royalties) of oil, representing
approximately 30% of 2004 cash flow. Proved reserves of 80 mmboe (133 before
royalties) comprise approximately 18% of Nexen's total proved oil and gas
reserves after royalties.
[GRAPHIC OMITTED]
[Graphic: Yemen map showing East Al Hajr block, Masila block,
and Ash Shihr terminal]
MASILA BLOCK (BLOCK 14)
We have a 52% working interest in and operate the Masila Project. Our share of
2004 production was 106,200 bbls/d before royalties (52,500 after royalties).
After more than 10 years of growth, our Masila fields have started maturing, but
significant value still remains. Due to terms in the production sharing
agreement, we still expect to generate approximately 40% of the total project
cash flow from the remaining 20% of reserves.
[GRAPHIC OMITTED]
[Margin text: We expect to generate approximately 40% of the total project cash
flow from the remaining 20% of the reserves.]
The first successful Masila exploratory well was drilled at Sunah in 1991, with
additional discoveries quickly following at Heijah and Camaal. Initial
production began in July 1993 with the first lifting of oil in August 1993.
Masila Blend oil averages 31(degree) API at very low gas-oil ratios. Most of the
oil is produced from the Upper Qishn formation, but we also produce from deeper
formations including the Lower Qishn, Upper Saar, Saar, Madbi, Basal Sand, and
basement formations.
We are managing our drilling pace to ensure we recover the remaining reserves in
the most efficient, cost-effective manner. We still see 150 drillable locations
and plan to drill 20 to 40 wells annually. In 2005, we plan to invest
approximately $70 million to drill at least 20 wells and test deeper horizons
where we have had recent success.
[GRAPHIC OMITTED]
[Graphic: Map of Masila block]
Masila is the largest oil project in Yemen. Each day, approximately 1.9 million
barrels of fluid are produced and collected at our Central Processing Facility
(CPF) through over 1,000 km of gathering lines. Water is separated at the field
or CPF and re-injected via water disposal wells in an environmentally sensitive
manner.
[GRAPHIC OMITTED]
[Margin text: Masila is the largest oil project in Yemen.]
Treated oil is pumped from the CPF via 138 km of pipeline to the export terminal
at Ash-Shihr. This pipeline ships Masila, East Al Hajr and third-party crude.
Oil is stored in one of six tanks (one 1,000,000 barrel tank and five 500,000
barrel tanks). From the tanks, oil travels through a sub-sea pipeline to a
pipeline end manifold (PLEM) 4 km offshore in 50 metres of water. The oil moves
through the PLEM up to a single point mooring buoy at the water surface and then
through two floating pipelines into tankers.
The oil is shipped to primary customers in Asia. Masila Blend crude oil enjoys a
strong market due to its quality, reliability of supply and a consolidated
marketing approach. During 2004, we sold our Masila crude oil at an average
discount of US$4.84/bbl to WTI.
9
Masila production is governed by a Production Sharing Agreement (PSA) signed in
1987 between the Government of Yemen and the Masila joint venture partners
(Partners), including Nexen. Under the PSA, we have the right to produce oil
from Masila into 2011 and to negotiate a five-year extension. Production is
divided into cost recovery oil and profit oil. Cost recovery oil provides for
the recovery of all exploration, development, and operating costs which are
funded by the Partners. Costs are recovered from a maximum of 40% of production
each 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 shared between the Partners and the
Government and is calculated on a sliding scale based on production. The
Partners' share of profit oil ranges from 20 to 33%. The structure of the
agreement moderates 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 74% of the profit oil, which includes a component for Yemen income
taxes payable by the Partners at 35%. In 2004, the Partners' share of Masila
production, including recovery of past costs, was approximately 38%.
[GRAPHIC OMITTED]
[Graphic: schematic of Masila Block PSA]
EAST AL HAJR BLOCK (BLOCK 51)
We have an 87.5% working interest in and operate East Al Hajr. The first
successful exploratory well was drilled at BAK-A in 2003, with the BAK-B
discovery quickly following. Early production began in November 2004 and the
field was producing 16,700 bbls/d before royalties at year-end. Full production
is expected to grow to 25,000 bbls/d before royalties in mid-2005.
[GRAPHICS OMITTED]
[Graphic: Map of East Al Hajr block]
[Margin text: Full production from Block 51 is expected to grow to 25,000 bbls/d
before royalties in mid-2005.]
Development of the BAK-A discovery began in 2004, and will initially include 16
wells, a central processing facility, a gathering system and a 22-km tieback to
our Masila export pipeline. Additional development wells are planned throughout
2005. The BAK-B field will initially be developed with seven wells and will come
on stream in late-2005.
In 2004, we drilled four exploration wells on the block. The first two wells
were abandoned. The third well, BAK-I, encountered oil shows and will be
production tested in early 2005 after we source the necessary testing equipment.
The fourth exploration well, BAK-J, was suspended after encountering oil and gas
shows associated with high formation pressures, and will be re-entered and
deepened when suitable equipment is located and high-pressure drilling equipment
is sourced.
In 2005, we plan to invest approximately $200 million to complete development of
the BAK-A and BAK-B fields and continue exploring the block with four
exploration wells.
10
This block is governed by a PSA between the Government of Yemen, and the
Partners: The Yemen Company (an entity owned by the Government of Yemen) (12.5%
interest) and Nexen (87.5% interest). The PSA expires in 2023 and we have the
right to negotiate a five-year extension. Under the terms of the PSA, the
Partners pay a royalty ranging from 3 to 10% to the Government depending on
production. 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, funded solely by Nexen. Costs are
recovered from a maximum of 50% of production each 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' share
of profit oil ranges from 20% to 30%. The Government's share of profit oil
includes a component for Yemen income taxes payable by the Partners at a rate of
35%.
[GRAPHIC OMITTED]
[Graphic: schematic of Block 51 PSA]
OTHER EXPLORATION BLOCKS
In 2004, we relinquished our interest in exploration Blocks 11, 12, 36, 50, 54,
and 59.
OFFSHORE WEST AFRICA
Offshore West Africa is a growing core area where we already have discoveries.
It offers prolific reservoirs and multiple opportunities to invest in this
oil-rich region. Our strategy here is to explore and develop our portfolio for
medium- to long-term growth. We have three exploration projects underway--
OPL-222 and OML-115, offshore Nigeria and Block K, offshore Equatorial Guinea.
We are also producing our final barrels from our Ejulebe field, offshore
Nigeria.
In 2004, we invested $69 million of capital offshore West Africa, and expect to
invest $84 million in 2005.
[GRAPHICS OMITTED]
[Graphic: Map of offshore West Africa showing Nexen production and
exploration blocks]
[Margin text: Offshore West Africa is a growing core area where we already have
discoveries.]
NIGERIA
BLOCK OML-109 - EJULEBE
Ejulebe is located in 45 feet of water on Block OML-109 in the Niger Delta,
approximately 15 km offshore Nigeria. Crude oil production is transported
through a pipeline to a third-party owned FPSO (floating production storage and
off-loading vessel) where it is made available for sale and export. We operate
the block under a risk service contract, requiring 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.
Ejulebe was still producing at year-end 2004. We expect to sell or abandon it in
2005. Abandonment would begin once government approvals have been obtained. No
capital expenditures are proposed for 2005 other than abandonment expenditures.
11
BLOCK OPL-222
In 1998, we acquired a 20% non-operated interest in Block OPL-222, which
includes 448,000 acres and is approximately 50 miles offshore in water depths
ranging from 600 to 3,500 feet. The ongoing appraisal of the block indicates
significant hydrocarbon accumulations based on the drilling results outlined
below:
YEAR WELL LOCATION RESULTS
-----------------------------------------------------------------------------------------------------------------
1998 Ukot-1 Ukot field discovery well encountered three oil-bearing intervals and flowed at
restricted rate of 13,900 bbls/d from two intervals
2002 Usan-1 Usan field discovery well encountered several oil-bearing intervals and flowed at
restricted rate of 5,000 bbls/d from one interval
2003 Usan-2 3 km west of discovery appraised up-dip portion of the fault block
2003 Usan-3 2 km northwest of discovery appraised separate fault block and flowed at restricted
rate of 5,600 bbls/d from one interval
2003 Ukot-2 3.5 km south of discovery encountered three oil-bearing intervals
2003 Usan-4 5 km south of discovery flowed at restricted rate of 4,400 bbls/d from first
interval and 6,300 bbls/d from second interval
2004 Usan-5 6 km west of discovery sampled oil in several intervals
2004 Usan-6 4 km south of Usan-5 flowed at restricted rate of 5,800 bbls/d from one
interval
[GRAPHICS OMITTED]
[Margin Graphic: Map of OPL-222 showing Nexen discoveries and prospects.]
[Margin Text: We have confirmed the presence of commercial quantities of
oil on OPL-222.]
Usan-4 confirmed the presence of commercial quantities of crude oil and Usan-5
and Usan-6 have built on this to the west. The operator has applied to convert
the block's licence to one or more Oil Mining Leases, which give 20 years to
appraise, develop and produce the reserves. A field development plan for Usan is
being prepared for submission to the government.
We plan additional exploration drilling on OPL-222 in 2005, and are now
determining which prospects will be drilled.
BLOCK OML-115
The Nigerian Government formally approved the Deed of Assignment for OML-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 between 90% and 95% of the revenues for
an initial ten-year period. In 2004, we drilled a well on the Ameena prospect
and did not find hydrocarbons. We expect to drill our next exploration well on
the block in the first half of 2005.
EQUATORIAL GUINEA - BLOCK K
In 2003, we acquired a 25% operated interest in Block K, a deep-water block
located 100 km offshore Equatorial Guinea. This interest was later increased to
50%. In 2004, we drilled a well on the Zorro prospect and found non-commercial
quantities of hydrocarbons. We expect to drill our next exploration well on the
block in the first half of 2005. We plan to meet all of the work commitments
under the production sharing contract before the initial exploration period ends
on June 1, 2005.
OTHER INTERNATIONAL
COLOMBIA
BOQUERON BLOCK - GUANDO
In 2000, we made our first discovery at Guando on our 20% non-operated Boqueron
Block. Boqueron is located in the Upper Magdalena Basin of central Colombia,
approximately 45 km southwest of Bogota. Our share of 2004 production averaged
4,800 bbls/d before royalties (4,400 after royalties), about 2% of Nexen's total
production.
Production from Guando is subject to a 5% to 25% royalty depending on daily
production levels. The corporate income tax rate is 38.5%.
[GRAPHIC OMITTED]
[Graphic: Map of Colombia showing Nexen producing and exploration blocks]
12
EXPLORATION BLOCKS
Exploration activities in Colombia are focused on assessing potential drilling
opportunities on captured blocks. In addition to Boqueron, we have interests in
three exploration blocks in the Upper Magdalena Basin. Villarrica was acquired
in 2000, El Queso in 2003 and Boqueron Deep in 2003.
BLOCK INTEREST (%) OPERATOR STATUS 2004 ACTIVITY
--------------------------------------------------------------------------------------------------------
Boqueron Deep 40 non-operated shot 80 km of seismic
Villarrica 50 operated received environmental license for possible
2005 exploration well
El Queso 50 operated shot 70 km of seismic
The fiscal policy structure in Colombia was revised in 2004 to make the terms
more competitive in the world market. In December 2004, El Queso was recognized
under the new terms. The exploration commitments have been completed for the
current phase of Villarrica. The seismic acquisition with Phase One at Boqueron
Deep is complete, with processing and interpretation activities carrying forward
in 2005. The Phase Two commitments at El Queso will be fulfilled in 2005 with
the budgeted seismic program.
In 2005, we plan to drill one exploration well and acquire additional seismic
information to help identify future drilling opportunities.
AUSTRALIA - BUFFALO
Since first production in 1999, the Buffalo field, offshore northwest Australia,
has produced 53(degree) API crude oil using a fixed wellhead platform linked to
a leased floating production storage and off-loading vessel.
We produced our final barrel of crude oil in late-2004, and averaged 2,700
bbls/d before royalties of oil for 2004. Field abandonment began in November
2004 and is expected to be completed in 2005. There were no capital expenditures
in 2004, and other than abandonment expenditures, no further expenditures are
expected in 2005 .
WESTERN CANADA
Our strategy in Canada is to maximize value from our core operations while we
actively pursue emerging sources of supply. We continue to manage our mature
conventional assets through selective development, cost control and asset
dispositions. In 2004, we produced 59,900 boe/d before royalties (47,000 after
royalties) from these assets, which was approximately 24% of Nexen's total
production. At year-end 2004, proved reserves of 141 mmboe (164 before
royalties) were approximately 31% of Nexen's total proved oil and gas reserves
after royalties.
Our Canadian operations are concentrated in geographical regions based on
commodity:
o light oil--in southeast Saskatchewan and northeast British Columbia;
o heavy oil--in west central Saskatchewan;
o natural gas--near Calgary, in northern Alberta foothills, southeast
Alberta and Saskatchewan.
We operate most of our producing properties and hold 1.7 million net acres of
undeveloped land across western Canada.
[GRAPHICS OMITTED]
[Margin text: Our Western Canadian strategy is to maximize value from core
operations while pursuing emerging sources of supply.]
[Graphic: Map of Western Canada showing Nexen areas of operations.]
The core assets provide predictable production and earnings while we advance
initiatives for future growth:
o coal bed methane (CBM) - focusing on Upper Mannville and Horseshoe Canyon
coals and applying our experience in shallow gas drilling and water
handling techniques
o enhanced oil recovery (EOR) - actively testing enhanced oil recovery
technologies to increase recovery in our heavy oil fields.
13
In 2004, we invested $175 million in Canada, with $148 million in our maturing
core assets. In 2005, we plan to invest approximately $200 million, with $140
million allocated to our maturing core assets. From 2003 to 2005, we will have
doubled our capital investment in CBM and EOR.
In Canada, the federal and provincial governments impose royalties on production
at varying rates, ranging between 15% and 40%, from lands where they own the
mineral rights. Some provinces also impose taxes on production from lands where
they do not own the mineral rights. The Saskatchewan government assesses a
resource surcharge on gross Saskatchewan resource sales of 3.6% that is reduced
to 2.0% if the well was completed after October 1, 2002.
Profits earned in Canada from resource properties are subject to federal and
provincial income taxes. In 2003, legislation was introduced to reduce the
federal corporate income tax rate on income from Canadian oil and gas activities
from 28% to 21% by 2007. Canadian entities are also subject to capital taxes.
[GRAPHIC OMITTED]
[Margin text: Our Western Canadian production is split: 20% light oil,
40% heavy oil and 40% natural gas.]
LIGHT OIL
Approximately 20% of our Canadian production is light oil.
We continue to develop and exploit our Hay property in northeast British
Columbia. We discovered Hay in 1997 and started producing in April 2000. Hay is
entering the final stage of development, with our focus on maximizing its value
and evaluating remaining reserve potential.
Our operations in southeast Saskatchewan are characterized by mature fields
producing medium-depth light oil. In 2004, we drilled 24 gross wells (19 net) as
part of our capital program. Our 2005 plans include ongoing exploitation of
these fields.
HEAVY OIL
Approximately 40% of our Canadian production is heavy 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
and expensive to extract, transport and refine than other types of oil. Heavy
oil also yields a lower price relative to light oil, as a smaller percentage of
high value petroleum products can be refined from heavy oil.
Our heavy oil operations are in west central Saskatchewan. To maximize heavy oil
returns, it is important to manage finding, development and operating costs. Our
large production base and existing infrastructure helps. In 2004, we drilled 63
gross wells (52 net) as part of our capital program. In 2005, we plan to
continue exploiting our existing fields through drilling and optimizing
operations.
NATURAL GAS
Approximately 40% of our Canadian production is natural gas, produced primarily
from shallow sweet reservoirs in southeast Alberta, southwest and northwest
Saskatchewan and from deep sour gas near Calgary and in the northern Alberta
foothills.
Shallow gas is natural gas produced from thin, shallow sand formations 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 have been producing sour natural gas from our Balzac field northeast of
Calgary since 1961. This sour gas is processed through our operated Balzac
plant. We also have natural gas production from our Findley properties in the
Alberta foothills and gas production associated with oil wells. In 2005, we
expect to drill 126 gross wells (117 net).
Limited gas exploration activity is focused in the foothills of Alberta and
in Montana and central Saskatchewan.
COAL BED METHANE (CBM)
CBM is commonly referred to as an unconventional form of natural gas because it
is primarily stored through adsorption by coal in coal deposits rather than in
the pore space of the rock like most conventional gas. The gas is released in
response to a drop in reservoir pressure. If the coal deposit is water
saturated, water generally needs to be extracted to reduce the pressure and
allow gas production to occur. If the coal does not produce water and is "dry",
gas will be produced from initial development. CBM fields are likely to require
between two and eight gas wells per section to efficiently extract the natural
gas. Regulatory approval is required to drill more than one well per section. As
a result, the timing of drilling programs and land development can be uncertain.
Water producing CBM wells in the United States generally show increasing gas
production rates for a period of approximately one to three years before gas
rates begin to decline.
At the end of 2004, our net undeveloped CBM land position was 285,000 acres.
Most of this land is in the Fort Assiniboine region of Alberta, where our
Corbett pilot project is located. We have also established positions in other
prospective CBM areas in Alberta.
14
[GRAPHIC OMITTED]
[Graphic: Alberta map showing Nexen lands and Corbett pilot location.]
Our CBM pilot at Corbett, operated by Trident Exploration, has established
techniques to produce natural gas from the wet Upper Mannville coals. Commercial
feasibility depends on achieving threshold production levels, which we hope to
achieve in 2005. These coals are generally deeper than the Horseshoe Canyon "dry
coal" play which is now being commercially developed in Alberta. During 2004, we
expanded our Corbett pilot from 15 to 49 producing wells.
In 2005, besides the potential of initiating commercial development at Corbett,
we will continue to evaluate other Mannville and Horseshoe Canyon CBM prospects
and pursue new opportunities in CBM. Our capital expenditures in 2004 were
approximately $30 million, and we plan to invest $45 million on CBM in 2005.
[GRAPHIC OMITTED]
[Margin text: A strong land position is critical to a successful CBM strategy.]
ENHANCED OIL RECOVERY (EOR)
Heavy oil reservoirs typically have lower recovery factors than conventional oil
reservoirs, leaving substantial amounts of oil in the ground. This creates an
opportunity to increase recovery factors by applying new technology. We are
researching various technologies to enhance our heavy oil recovery with ongoing
pilot projects in west central Saskatchewan.
ATHABASCA OIL SANDS
Our oil sands strategy is to economically develop our bitumen resource to
provide low-risk, stable, future growth. Our strategy involves integrating
bitumen production with field upgrading technology to produce a premium
synthetic crude oil. Our oil sands strategy also includes our 7.23% investment
in the Syncrude oil sands mining operation.
In 2001, we formed a 50/50 joint venture with OPTI Canada Inc. (OPTI Canada) to
develop the Long Lake property (Lease 27) using steam-assisted-gravity-drainage
(SAGD) for bitumen production and field upgrading with the OrCrude(TM) process,
a technology to which OPTI Canada has the exclusive Canadian license. OPTI
Canada has since reorganized its interest into OPTI Long Lake L.P. (OPTI). We
also acquired from OPTI the exclusive right to use the technology within
approximately 100 miles of Long Lake in collaboration with OPTI, and the right
to use the technology independently elsewhere in the world.
[GRAPHIC OMITTED]
[Graphic: Alberta map of Nexen bitumen acreage for Long Lake]
We have 199,000 net acres of bitumen-prone lands located in the Athabasca oil
sands of northeast Alberta, and plan to continue acquiring more. We plan to
develop our bitumen lands in a phased manner using our integrated upgrading
strategy. To begin exploiting this resource, we sanctioned and began development
of our Long Lake Project in 2004.
In 1995, Alberta 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. We expect to be subject to
this royalty on our bitumen production and not our upgraded synthetic crude oil
production.
[GRAPHIC OMITTED]
[Margin text: We continue to expand our bitumen holdings and plan to develop
them in a phased manner using our integrated upgrading strategy.]
15
LONG LAKE PROJECT
Our $3.5 billion Long Lake Project, the fourth and next major integrated oil
sands project in Canada, received regulatory approval in 2003. The project
consists of approximately 72,000 bbls/d of SAGD bitumen production integrated
with a field upgrading facility using the OrCrude(TM) process and commercially
available hydrocracking and gasification. The project is expected to produce
approximately 60,000 bbls/d of premium synthetic crude oil with low sulphur
content once the upgrader is on stream in the second half of 2007. The project
is designed to generate its own fuel and electricity, resulting in significant
operating cost savings compared to other bitumen production and upgrading
projects and significantly lower price risk on input costs. By upgrading the
bitumen to synthetic crude oil, we should also avoid price risk on the
production. 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. We will
share the production and operating costs of the project equally with OPTI.
[GRAPHIC OMITTED]
[Margin text: We expect our share of phase one production from Long Lake to be
30,000 bbls/d of premium synthetic crude oil.]
The SAGD and upgrader integration, along with the proprietary processes, allows
us to overcome three main economic hurdles of SAGD bitumen production: 1) cost
of natural gas, 2) cost of diluent, and 3) the realized price of bitumen. The
Project generates synthetic gas from internally produced asphaltenes for use as
fuel. This essentially eliminates the need for purchasing natural gas. With the
upgrading facilities located on site, expensive diluent is not required to
transport the produced bitumen to market. Upgrading the bitumen into a highly
desirable refinery feedstock or diluent supply enables the end product to
command significantly higher prices than raw bitumen.
We plan to produce bitumen using SAGD, a proven technology now being
commercialized at several locations in the region. SAGD involves drilling 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. To optimize the project's well design, a three-well pair SAGD pilot was
completed and is still operating. We also have interests in other SAGD projects
at various stages of assessment outside of Long Lake.
[GRAPHICS OMITTED]
[Margin text: Our SAGD and upgrader integration allows us to limit our exposure
to critical variables affecting the economics of SAGD bitumen production:
1) cost of natural gas, 2) cost of diluent, and 3) price of bitumen.]
[Graphic: schematic of SAGD production and well pair]
[Graphic: schematic of SAGD and Upgrader with OrCrude(TM) upgrading process]
16
The OrCrude(TM) technology, using distillation, solvent deasphalting and thermal
cracking, converts bitumen into partially upgraded sour crude oil and liquid
asphaltenes. By coupling the OrCrude(TM) process with commercially available
hydrocracking and gasification technologies, sour crude is upgraded to light
(39(degree) API) premium synthetic crude oil and the asphaltenes are converted
to a low-energy, synthetic fuel gas containing free hydrogen for use in the
upgrading process. The synthetic fuel will be burned in a co-generation plant to
produce steam for the SAGD operations and for on-site power. A 500-bbl/d
demonstration plant successfully separated asphaltenes and upgraded over 250,000
bbls of various types of bitumen from the Cold Lake and Athabasca regions,
including Long Lake bitumen. Combined SAGD, cogeneration, and upgrading
operating costs are expected to average between $7 and $9/bbl.
[GRAPHIC OMITTED]
[Margin text: Combined SAGD cogeneration and upgrading costs are expected to
average between $7 and $9/bbl.]
On February 12, 2004, our Board of Directors approved proceeding with commercial
development of the Long Lake Project. Field construction work on the SAGD and
upgrader facilities began in 2004, with above ground construction scheduled to
begin in the first half of 2005. Commercial SAGD drilling of 78 well pairs began
in September 2004, with expected completion by early 2006. At year-end,
procurement of major equipment was substantially complete, with pricing as
budgeted. First steam injection is scheduled to commence in 2006 and the
upgrader is scheduled to start-up in the second half of 2007. We expect peak
gross production to reach around 60,000 bbls/d before royalties of synthetic
crude oil. We expect to maintain this rate over the project's life, estimated at
40 years, by periodically drilling additional SAGD well pairs.
We expect the gross capital cost for the Long Lake Project, including upgrader
commissioning and start-up to total $3.5 billion ($1.75 billion, net to us).
This is $98 million higher ($49 million, net to us) than the estimate at the
time of sanctioning as we have accelerated the drilling of 13 well pairs to
ensure we have sufficient bitumen supply to fill the upgrader. In 2004, we
invested approximately $362 million and expect to invest $765 million in 2005.
The spending in 2005 increases substantially because we are entering the
construction phase of the commercial facilities. Ongoing sustaining capital is
expected to average $2.50/bbl. We estimate the capital costs of producing and
upgrading bitumen using this technology will be comparable to those for surface
mining and coking upgrading on a barrel of daily production basis.
[GRAPHIC OMITTED]
Margin text: Our share of Long Lake capital costs to upgrader start-up is
estimated at $1.75 billion.]
RESERVES, PRODUCTION AND RELATED INFORMATION
In addition to the tables below, we refer you to the Supplementary Data in Item
8 of this Form 10-K for information on our oil and gas producing activities.
Nexen has not filed with nor included in reports to any other United States
federal authority or agency, any estimates of total proved crude oil or natural
gas reserves since the beginning of the last fiscal year.
NET SALES BY PRODUCT FROM CONTINUING OPERATIONS (INCLUDING SYNCRUDE)
(Cdn$ millions) 2004 2003 2002
Conventional Crude Oil and Natural Gas Liquids 1,856 1,590 1,374
Synthetic Crude Oil 321 240 245
Natural Gas 607 618 345
2,784 2,448 1,964
Crude oil (including synthetic crude oil) and natural gas liquids represent
approximately 78% of our net sales, while natural gas represents the remaining
22%.
SALES PRICES AND PRODUCTION COSTS (EXCLUDING SYNCRUDE)
AVERAGE SALES PRICE (1) AVERAGE PRODUCTION COSTS (1)
----------------------------------------------------------- ----------------------------
2004 2003 2002 2004 2003 2002
------------------------ ----------------------------
Crude Oil and NGLs (Cdn$/bbl)
Yemen 47.59 39.45 38.80 5.64 4.37 4.13
Canada (2) 36.60 32.37 31.13 11.76 10.00 8.98
United States 46.60 37.68 38.88 6.09 5.08 10.95
Australia (2) 51.22 43.14 40.30 35.73 20.21 12.14
United Kingdom 46.81 -- -- 8.26 -- --
Other Countries 43.07 38.22 38.96 4.09 9.01 10.69
Natural Gas (Cdn$/mcf)
Canada (2) 5.76 5.64 3.57 0.85 0.65 0.70
United States 7.89 8.16 5.29 1.02 0.89 1.83
United Kingdom 8.28 -- -- -- -- --
------------------------ -------------------------------
Notes:
(1) Prices and unit production costs are calculated using our working interest
production after royalties.
(2) Includes results of discontinued operations. (See Note 11 to our
Consolidated Financial Statements).
17
PRODUCING OIL AND GAS WELLS
(number of wells) 2004
------------------------------------------------------------------------------------------------
OIL GAS TOTAL
------------------------ ---------------------- ----------------------
Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)
United States 196 89 208 129 404 218
Yemen 371 195 -- -- 371 195
United Kingdom 27 12 -- -- 27 12
Canada 2,831 2,041 2,536 2,201 5,367 4,242
Nigeria 1 1 -- -- 1 1
Colombia 74 16 -- -- 74 16
------------------------ ---------------------- ----------------------
Total 3,500 2,354 2,744 2,330 6,244 4,684
======================= ====================== ======================
Notes:
(1) Gross wells are the total number of wells in which we own an interest.
(2) Net wells are the sum of fractional interests owned in gross wells.
OIL AND GAS ACREAGE
(thousands of acres) 2004
-----------------------------------------------------------------------------------------------
DEVELOPED UNDEVELOPED (1) TOTAL
------------------ ------------------ ------------------
Gross Net Gross Net Gross Net
United States 182 102 1,020 494 1,202 596
Yemen (2) 45 24 761 633 806 657
Nigeria (2), (3), (4) 1 1 524 128 525 129
Equatorial Guinea -- -- 1,106 553 1,106 553
Canada 909 695 2,754 1,680 3,663 2,375
Colombia (5) 1 -- 787 552 788 552
United Kingdom 44 19 1,598 708 1,642 727
Australia 1 1 -- -- 1 1
------------------ ------------------ ------------------
Total 1,183 842 8,550 4,748 9,733 5,590
================== ================== ==================
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.
DRILLING ACTIVITY
(number of net wells) 2004
--------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
--------------------------------- ----------------------------------
Dry Dry
Productive Holes Total Productive Holes Total Total
United States 0.3 1.8 2.1 11.0 1.0 12.0 14.1
United Kingdom -- -- -- -- -- -- --
Yemen -- 2.0 2.0 37.3 0.5 37.8 39.8
Nigeria 0.4 1.0 1.4 -- -- -- 1.4
Canada 13.4 1.0 14.4 202.9 -- 202.9 217.3
Colombia -- -- -- 7.0 -- 7.0 7.0
Equatorial Guinea -- 0.5 0.5 -- -- -- 0.5
--------------------------------- -----------------------------------------------
Total 14.1 6.3 20.4 258.2 1.5 259.7 280.1
================================== ===============================================
2003
--------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
--------------------------------- ----------------------------------
Dry Dry
Productive Holes Total Productive 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
================================== ===============================================
18
2002
--------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
--------------------------------- ----------------------------------
Dry Dry
Productive Holes Total Productive 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
================================== ===============================================
Note:
(1) Other countries include drilling primarily in Nigeria, Colombia and Brazil.
WELLS IN PROGRESS
At December 31, 2004, we were in the process of drilling ten wells (5.7 net) in
the United States, 29 wells (15.5 net) in Canada, four wells in Yemen (3.0 net),
and one well in Colombia (0.2 net).
SYNCRUDE MINING OPERATIONS
We hold a 7.23% participating interest in Syncrude Canada Ltd. (Syncrude). This
joint venture was established in 1975 to mine shallow oil sands deposits using
open-pit mining methods, extract the bitumen from the oil sands, and upgrade the
bitumen to produce a high-quality, light (32(degree) API), sweet, synthetic
crude oil.
The Syncrude operation exploits a portion of the Athabasca oil sands deposit
which contains bitumen in the unconsolidated sands of the McMurray formation.
Ore bodies are buried beneath 50 to 150 feet of over-burden, have bitumen grades
ranging from 4 to 14 weight percent, and ore bearing sand thickness of 100 to
160 feet.
Syncrude's operations are located on eight leases (10, 12, 17, 22, 29, 30, 31,
and 34) covering 258,000 acres, 40 km north of Fort McMurray in northeast
Alberta.
Syncrude mines oil sands at three mines: Base, North, and Aurora North. These
locations are readily accessible by public road. At the Base Mine (lease 17), a
dragline, bucket wheel reclaimers, and belt conveyors are used for mining and
transporting oil sands. In the North Mine (leases 17 and 22) and in the Aurora
North Mine (leases 10, 12, and 34), a truck-and-shovel and hydro-transport
system is used.
The extraction facilities, which separate bitumen from oil sands, are capable of
processing more than 240 million tons of oil sands per year and about 110 mmbbls
of bitumen per year. To extract bitumen, the oil sands are 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 uses hot water, steam, and caustic soda to
create a slurry, while at the North Mine and the Aurora North Mine the oil sands
are mixed with warm water to produce a slurry.
The extracted bitumen 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 to form light, sweet synthetic crude oil.
Sulphur and coke, which are by-products of the process, are stockpiled for
possible future sale. In 2004, the upgrading process yielded 0.86 barrels of
synthetic crude oil per barrel of bitumen.
[GRAPHICS OMITTED]
[Graphic: Alberta map of Syncrude oil sands leases.]
[Margin text: The quality of Syncrude's synthetic crude oil typically allows it
to be sold at a premium to WTI.]
The quality of Syncrude's synthetic crude oil typically allows it to be sold at
a premium to WTI. In 2004, about 45% of the synthetic crude oil was sold to
Edmonton area refineries and the remaining 55% was sold to refineries in eastern
Canada and the mid-western United States.
Electricity is provided to Syncrude from two generating plants: a 270 MW plant
and an 80 MW plant. Both plants are located at Syncrude and are owned by the
Syncrude participants.
Since operations started in 1978, Syncrude has shipped more than 1.5 billion
barrels of synthetic crude oil to Edmonton, Alberta by Alberta Oil Sands
Pipeline Ltd. The pipeline was expanded in 2004 to accommodate increased
Syncrude production.
19
To the end of 2004, our total investment in the property, plant and equipment,
including surface mining facilities, transportation equipment, and upgrading
facilities is approximately $1 billion. Based on development plans, our share of
future expansion and equipment replacement costs over the next 35 years is
expected to be about $1.3 billion.
In 1999, the Alberta Energy and Utilities Board (AEUB) extended Syncrude's
operating license for the eight oil sands leases through to 2035. The licence
permits Syncrude to mine oil sands and produce synthetic crude oil from approved
development areas on the oil sands leases. The leases are automatically
renewable as long as oil sands operations are ongoing or the leases are part of
an approved development plan. All eight leases are included in a development
plan approved by the AEUB. There were no known commercial operations on these
leases prior to the start-up of operations in 1978.
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
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 equalled $2.8 billion (gross). That total was surpassed at the
end of 2001.
In 1999, the AEUB approved an increase in Syncrude's production capacity to
465,700 bbls/d. At the end of 2001, Syncrude had increased its synthetic crude
oil capacity to 246,500 bbls/d with the development of the Aurora North Mine
which involved extending mining operations to a new location about 25 miles
north of the main Syncrude site. In 2001, the Syncrude owners approved the third
stage of the Syncrude expansion, which will increase capacity to 360,000 bbls/d
in 2006. 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 to $7.8 billion. Nexen's share of the project costs was revised
in May 2004 to $565 million, of which $440 million was incurred by year-end
2004. Activities in 2005 are focused on completing the upgrader expansion, as
well as spending $415 million (Nexen's share is $30 million) to replace bitumen
production capacity that will be lost with the closure of the depleted southwest
quadrant of the Base Mine in early 2006.
[GRAPHIC OMITTED]
[Margin text: Syncrude's capacity expansion to 360,000 bbls/d should be complete
in 2006.]
In 2004, Syncrude's production of marketable synthetic crude oil was 238,000
bbls/d. Nexen's share was 17,200 bbls/d before royalties.
The following table sets out certain operating statistics for the Syncrude
operations:
2004 2003 2002
Total mined volume (1)
Millions of tons 389 380 375
Mined volume to oil sands ratio (1) 2.1 2.3 2.2
Oil sands processed
Millions of tons 188 168 173
Average bitumen grade (weight %) 11.1 11.0 11.2
Bitumen in mined oil sands
Millions of tons 21 18 19
Average extraction recovery (%) 87 89 90
Bitumen production (2)
Millions of barrels 103 92 98
Average upgrading yield (%) 86 86 86
Gross synthetic crude oil shipped (3)
Millions of barrels 87 77 84
Nexen's share of marketable crude oil
Millions of barrels before royalties 6.3 5.6 6.1
Millions of barrels after royalties 6.1 5.5 6.0
Notes:
(1) Includes pre-stripping of mine areas and reclamation volumes.
(2) Bitumen production in barrels is equal to bitumen in mined oil sands
multiplied by the average extraction recovery and the appropriate
conversion factor.
(3) Approximately 1.2% of the produced synthetic crude oil is used internally
at Syncrude. The remaining synthetic oil is sold externally.
[GRAPHIC OMITTED]
[Margin text: In 2004, approximately 1.8 tons of oil sand produced 1 barrel of
bitumen that was upgraded to 0.86 barrels of synthetic crude oil.]
20
OIL AND GAS MARKETING
Our marketing group sells proprietary and third-party natural gas, crude oil and
power in certain regional markets where we have built a solid physical asset
base. This includes access to transportation, storage and facilities, as well as
crude oil and natural gas we produce or acquire. We optimize the margin on our
base business by trading around our access to these physical assets when market
opportunities present themselves. We use financial and derivative contracts,
including futures, forwards, swaps and options for hedging and for trading
purposes.
Our marketing strategy is to:
o obtain competitive pricing on the sale of our own oil and gas production,
o provide market intelligence in support of our oil and gas operations,
o provide superior customer service to producers and consumers, and
o capitalize on market opportunities through low-risk trading based on our
transportation and storage capacity.
This strategy aligns with our corporate focus to extract full value from our
assets, and provides us with the market intelligence needed to deliver our
current and future oil and gas production to market at competitive pricing.
GAS MARKETING
The marketing and trading of natural gas is our marketing division's largest
revenue stream. We focus on key regional markets where we have a strategic
presence - solid customer relationships, in-depth understanding of the market or
established physical trading-based assets. We capture regional opportunities by
managing supply, transportation and storage assets for producers and end users.
In addition to the fee-for-service income we realize from managing these assets,
we generate further net revenue by:
o capitalizing on location spreads (differences in prices between market
locations) using our transportation assets, and
o capitalizing on time spreads (differences in price between summer and
winter) using our storage assets.
[GRAPHIC OMITTED]
[Margin text: The marketing and trading of natural gas is our marketing
division's largest revenue stream.]
We have offices in key regions including Calgary, Detroit and Houston. Our
Calgary office provides a variety of services including supply, storage, and
transportation management as well as netback pool arrangements and other
customer services. Our customers include producers and consumers in Western
Canada as well as consumers (including utilities) in Eastern Canada, the
Northeastern United States and the US mid-continent. Our Detroit office works
closely with Calgary to provide services to our customers. Our presence in
Houston has established us in the Gulf Coast region where we have our own
production.
We use our access to transportation and storage facilities to optimize returns
for ourselves as well as our customers.
[GRAPHIC OMITTED]
[Margin text: We use our access to transportation and storage facilities to
optimize returns.]
In 2004, we grew our asset base by acquiring physical gas purchase and sales
contracts, as well as natural gas transportation capacity on favourable terms.
This gave us access to new producer gas until 2008, as well as pipeline capacity
and gas purchase and sales contracts to the end of 2004. The majority of these
gas purchase and sales contracts have been renewed to the end of 2005. We also
added storage capacity in key regional locations.
Our position as a physical marketer at multiple delivery points in key markets
gives us the flexibility to capitalize on time and location spreads. With
pipeline capacity, we can move gas from producing regions to take advantage of
price differences. We can also use storage capacity to store less expensive
summer gas in the ground until the winter heating season arrives.
In addition to transportation and storage assets, we hold financial contracts
that allow us to capture profits around time and location spreads. The basis
risk we assume on these contracts is based on solid fundamental analysis and
in-depth knowledge of regional markets. The risk is managed proactively by our
product group teams and monitored closely by our risk group, with regular
reporting to management and the Board.
CRUDE OIL MARKETING
Our crude oil business focuses on marketing physical crude oil volumes to end
use refiners. The crude oil group markets our own production and over 100,000
bbls/d of third-party field production to refiners from producing regions where
we operate. In addition to physical marketing, we take advantage of quality
differentials and time spreads.
Our North American operations focus on key regions supported by our offices in
Calgary and Houston. In Western Canada, our producer services group concentrates
on the procurement of a diversified supply base, while the trading team seeks to
optimize the mix for sale to refiners. Traditionally, the
21
Chicago area has been the key market for Western Canadian crude. The recent
growth in our deep-water Gulf of Mexico crude oil production has given us the
opportunity to expand our presence in that market through our Houston office.
Internationally, we focus on the physical marketing of our Yemen crude oil. In
order to meet customer needs, we may occasionally market other regional crude
types. In addition to our own crude, we market production for our partners and
third parties in the Yemen region. By locating our international crude oil
marketing office in Singapore, we are well positioned to serve both the
producing region and the Asian refining market.
[GRAPHIC OMITTED]
[Margin text: Our international marketing group focuses on the physical
marketing of our Yemen crude oil.]
Our crude oil marketing group also holds financial contracts that allow us to
capture trading profits around time, quality and location spreads. The basis
risk assumed is, like gas marketing, based on solid fundamental analysis and
proprietary knowledge of regional markets, and it is managed and monitored
closely by our risk group.
POWER MARKETING
Our power marketing group is responsible for optimizing the use of our 100 MW
gas-fired combined-cycle power generation facility at Balzac, Alberta and for
marketing power to larger commercial, industrial and municipal clients within
Alberta. Our Balzac facility began operations in 2001. We expect to increase our
power generation capacity with a 170 MW co-generation facility at Long Lake in
2007, and through our 70 MW Soderglen wind power project in southern Alberta in
2006. We have a 50% interest in each project.
CHEMICALS
We manufacture sodium chlorate and chlor-alkali products (chlorine, caustic soda
and muriatic acid) in Canada and Brazil. This production is sold in North and
South America, with a small amount of sodium chlorate distributed in Asia. Our
manufacturing facilities are modern, reliable, and strategically located to
capitalize on competitive power costs or transportation infrastructure to
minimize production and delivery costs. This enables us to have reliable
supplies and low costs, key factors for marketing bleaching chemicals.
The bleaching chemicals we produce are subject to commodity pricing structures.
Our strategy for adding value in this business focuses on:
o improving our cost position,
o maintaining our market share,
o building a strong, sustainable North American customer base, and
o capturing new offshore opportunities.
Since 1999, we have made significant investments to grow our capacity, expand
internationally and lower our overall cost structure, allowing us to improve our
position in the bleaching chemicals industry.
The primary raw materials required to produce sodium chlorate and chlor-alkali
products are electricity, salt, and fresh water. Electricity is the single
largest operational cost, making up more than half of our cash costs. Labour is
also a significant component of our manufacturing costs. Approximately 50% of
our workforce is unionized, with collective agreements in place at all of our
unionized plants.
[GRAPHIC OMITTED]
[Margin text: Our chemical facilities are modern, reliable, and strategically
located to capitalize on competitive power costs or transporatation
infrastructure.]
AVERAGE ANNUAL PRODUCTION CAPACITY
2004 2003 2002
Sodium Chlorate (short-tons)
North America 446,617 432,812 500,650
Brazil 70,213 70,213 57,320
Total 516,830 503,025 557,970
Chlor-alkali (short-tons)
North America 356,002 356,002 351,844
Brazil 109,430 109,430 97,462
Total 465,432 465,432 449,306
22
NORTH AMERICA
[GRAPHIC OMITTED]
[Graphic: Canada map of chemical plant locations]
The North American pulp and paper industry consumes approximately 95% of local
sodium chlorate production. We market our sodium chlorate production to numerous
pulp and paper mills under multi-year contracts that contain price and volume
provisions. Approximately 30% of this production is sold in Canada, 60% in the
US, and the rest marketed offshore.
We are the third largest manufacturer of sodium chlorate in North America with
five Canadian facilities: Nanaimo, British Columbia; Bruderheim, Alberta;
Brandon, Manitoba; Amherstburg, Ontario; and Beauharnois, Quebec.
In October 2004, we completed an expansion of our Brandon, Manitoba plant by
increasing capacity 33% to 260,000 tonnes per year. This expansion replaced
higher-cost capacity idled in 2002 at Taft, Louisiana. Brandon is currently the
world's largest sodium chlorate facility, and has one of the lowest cost
structures in the industry, significantly enhancing our competitive position in
North America.
[GRAPHIC OMITTED]
[Margin comment: Our Brandon plant is the world's largest sodium chlorate plant
and one of the lowest cost producers in North America.]
Our chlor-alkali facility at North Vancouver, British Columbia manufactures
caustic soda, chlorine and muriatic acid. Almost all of our caustic soda is
consumed by local pulp and paper mills, while our chlorine is sold to various
customers in the polyvinyl chloride, water purification and petrochemicals
industries, primarily in the United States.
BRAZIL
We entered Brazil in 1999 by acquiring a sodium chlorate plant and a
chlor-alkali plant from Aracruz Cellulose S.A., the leading Brazil manufacturer
of pulp. The majority of the production is sold to Aracruz under a long-term
sales agreement that expires in 2024. This agreement has an initial six year
take-or-pay component that ends in 2005. Most of the chlorine and about 20% of
the sodium chlorate production is sold in the merchant market under shorter-term
contractual arrangements. In 2002, we completed expanding both facilities to
meet Aracruz's growing needs. Chlorate production capacity is now 70,213
short-tons per year and chlor-alkali capacity is 109,430 short-tons per year.
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
participate in many industry and professional associations and otherwise monitor
the progress of proposed legislation and regulatory amendments.
ENVIRONMENTAL REGULATIONS
Our oil and gas and chemical operations are subject to government laws and
regulations designed to protect and regulate the discharge of materials into the
environment in the countries where we operate. We believe that our operations
comply in all material respects with applicable environmental laws. To mitigate
our exposure we apply industry standards, codes and best practices to meet or
exceed these laws and regulations. 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.
We have an active Safety, Environment and Social Responsibility group that are
responsible for ensuring that our worldwide operations are conducted in a safe,
ethical and socially responsible manner. We have developed policies for
continuing compliance with environmental laws and regulations in the countries
in which we operate.
23
ENVIRONMENTAL PROVISIONS AND EXPENDITURES
The ultimate financial impact of environmental laws and regulations is not
clearly known nor can they be reasonably estimated as new standards continue to
evolve in the countries in which we operate. We estimate our future
environmental costs based on past experience and current regulations. At
December 31, 2004, $468 million ($770 million, undiscounted) has been provided
in our consolidated financial statements for asset retirement obligations
relating to our oil and gas, Syncrude and chemicals facilities. During 2004, we
increased our retirement obligations for future dismantlement and site
restoration by $146 million primarily due to the acquisition of oil and gas
properties in the North Sea.
During 2004, our capital expenditures for environmental-related matters,
including environment control facilities, were approximately $31 million. Our
operating expenditures for environmental-related matters were approximately $8
million. Environmental related and site restoration capital expenditures in 2005
are expected to be approximately $47 million, primarily from the remediation of
our Australia and Nigeria oil producing areas.
EMPLOYEES
We had 3,247 employees on December 31, 2004.
Information on our executive officers is presented in Item 10 of this report.
[GRAPHIC OMITTED]
[Margin text: See page 125 for details on our executive officers.]