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.
[GRAPHIC OMITTED]
[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.
[GRAPHIC OMITTED]
[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.
[GRAPHIC OMITTED]
[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
[GRAPHIC OMITTED]
[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 $1.75 billion.]
RESERVES, PRODUCTION AND RELATED INFORMATION
In addition to the tables below, we refer you to the Supplementary Data in Item
8 of this Form 10-K for information on our oil and gas producing activities.
Nexen has not filed with nor included in reports to any other United States
federal authority or agency, any estimates of total proved crude oil or natural
gas reserves since the beginning of the last fiscal year.
NET SALES BY PRODUCT FROM CONTINUING OPERATIONS (INCLUDING SYNCRUDE)
Crude oil (including synthetic crude oil) and natural gas liquids represent
approximately 78% of our net sales, while natural gas represents the remaining
22%.
SALES PRICES AND PRODUCTION COSTS (EXCLUDING SYNCRUDE)
AVERAGE SALES PRICE (1) AVERAGE PRODUCTION COSTS (1)
----------------------------------------------------------- ----------------------------
2004 2003 2002 2004 2003 2002
------------------------ ----------------------------
Crude Oil and NGLs (Cdn$/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.]
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. We
believe we have made adequate provisions for such lawsuits and claims.
Certain of our US oil and gas operations have received, over the years, notices
and demands from the United States Environmental Protection Agency, state
environmental agencies, and certain third parties with respect to certain sites
seeking to require investigation and remediation under federal or state
environmental statutes. In addition, notices, demands, and suits have been
received for certain sites related to historical operations and activities in
the US for which, although no assurances can be made, we believe that certain
assumption and indemnification agreements protect our US operations from any
present or future material liabilities that may arise from these particular
sites.
On June 25, 2003, a subsidiary of Occidental Petroleum Corporation (Occidental)
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 our 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. Subsequent to 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 are vigorously defending 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 2004.
24
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 (TSX) and the New
York Stock Exchange (NYSE) under the symbol NXY.
On December 31, 2004, there were 1,329 registered holders of common shares and
129,199,583 common shares outstanding. The number of registered holders of
common shares is calculated excluding individual participants in securities
positions listings. During the year, we made no purchases of our own equity
securities.
[GRAPHIC OMITTED]
[Margin text: Symbol: NXY, Traded on the TSX and NYSE with 129.2 million common
shares outstanding.]
TRADING RANGE OF NEXEN'S COMMON SHARES
($/share) TSX (CDN$) NYSE (US$)
--------------------------------------------------------------------------------
HIGH LOW HIGH LOW
2004
First Quarter 53.35 45.00 40.61 34.10
Second Quarter 56.50 46.80 42.29 34.49
Third Quarter 53.70 44.34 42.13 33.88
Fourth Quarter 58.66 48.17 46.56 39.20
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
-------------------------------------
[GRAPHIC OMITTED]
[Margin text: On the TSX in 2004, we traded from a
low of $44.34 in Q3 to a high of
$58.66 in Q4.]
QUARTERLY DIVIDENDS ON COMMON SHARES FIRST SECOND THIRD FOURTH
($/share) QUARTER QUARTER QUARTER QUARTER
--------------------------------------------------------------------------------
2004 0.10 0.10 0.10 0.10
2003 0.075 0.075 0.075 0.10
---------------------------------------
[GRAPHIC OMITTED]
[Margin text: We increased our quarterly dividend to $0.10/share in Q4 2003.]
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.
25
ITEM 6. SELECTED FINANCIAL DATA
FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA IN ACCORDANCE WITH US GAAP
(Cdn$ millions) 2004 2003 2002 2001 2000
--------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS
Net Sales (1) 3,176 2,844 2,341 2,356 1,366
Net Income from Continuing Operations 775 462 299 340 474
Basic Earnings per Common Share
from Continuing Operations ($/share) 6.03 3.73 2.45 2.82 3.79
Diluted Earnings per Common Share
from Continuing Operations ($/share) 5.95 3.70 2.41 2.78 3.74
Net Income 788 420 352 365 522
Basic Earnings per Common Share ($/share) 6.13 3.39 2.88 3.03 4.17
Diluted Earnings per Common Share ($/share) 6.05 3.36 2.84 2.99 4.12
Production before Royalties (mboe/d) (2) 250 269 269 268 256
Production after Royalties (mboe/d) (2) 174 185 176 184 171
FINANCIAL POSITION
Total Assets (2) 12,339 7,703 6,764 5,609 5,874
Long-Term Debt (3) 4,214 2,470 2,575 2,242 2,238
Shareholders' Equity 2,892 2,131 1,812 1,414 1,050
Capital Investment, including Acquisitions 4,264 1,432 1,545 1,325 841
Dividends per Common Share ($/share) (4) 0.40 0.325 0.30 0.30 0.30
Common Shares Outstanding (thousands) 129,200 125,606 122,966 121,202 119,855
------------------------------------------------- -----------
Notes:
(1) During 2003, we sold non-core conventional light oil assets in southeast
Saskatchewan in Canada producing 9,000 bbls/d. In late 2004, we concluded
production from our Buffalo field, offshore Australia as anticipated. The
results of these operations have been shown as discontinued operations.
(2) In 2003, production increased from our deep-water Aspen development in the
Gulf of Mexico in the United States. In 2004, production declined from our
maturing assets in Yemen at Masila, in Canada, and in the United States on
the Gulf of Mexico Shelf. In late 2004, we acquired North Sea assets and
commenced production from Block 51 in Yemen.
(3) In December 2004, we drew US$1,500 million on unsecured acquisition credit
facilities to finance the purchase of North Sea assets. The remainder of
the purchase price was funded from cash on hand.
(4) Quarterly dividends were increased to 10(cent) per share in the fourth
quarter of 2003.
[GRAPHIC OMITTED]
[Margin text: See page 108 for differences between Canadian & US GAAP.]
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
TABLE OF CONTENTS
PAGE
Executive Summary of 2004 Results.............................................29
Capital Investment............................................................31
2004 Investment Program................................................31
2005 Estimated Capital.................................................32
Financial Results
Year to Year Change in Net Income......................................35
Oil & Gas and Syncrude
Production ...................................................36
Commodity Prices...............................................39
Operating Costs................................................42
Depreciation, Depletion, Amortization and Impairment...........43
Exploration Expense............................................44
Oil & Gas and Syncrude Netbacks........................................45
Oil and Gas Marketing..................................................46
Chemicals .............................................................48
Corporate Expenses.....................................................49
Impact of Foreign Exchange on Operations...............................51
Outlook for 2005..............................................................51
Liquidity and Capital Resources...............................................53
Business Risk Management .....................................................58
Critical Accounting Estimates.................................................64
New Accounting Pronouncements.................................................67
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 SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND UNITED
STATES (US) ACCOUNTING PRINCIPLES ON THE FINANCIAL STATEMENTS IS DISCLOSED IN
NOTE 19 TO THE CONSOLIDATED FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS
FEBRUARY 7, 2005.
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 72 WHICH HIGHLIGHTS DIFFERENCES BETWEEN OUR RESERVE ESTIMATES AND RELATED
DISCLOSURES THAT ARE OTHERWISE REQUIRED BY CANADIAN REGULATORY AUTHORITIES.
28
EXECUTIVE SUMMARY OF 2004 RESULTS
(Cdn$ millions) 2004 2003 2002
--------------------------------------------------------------------------------
Net Income 793 578 409
Earnings per Common Share ($/share) 6.17 4.67 3.34
Cash Flow from Operating Activities 1,607 1,405 1,250
Production before Royalties (mboe/d) (1) 250 269 269
Production after Royalties (mboe/d) 174 185 176
Capital Investment, including Acquisitions 4,264 1,494 1,625
Net Debt (2) 4,219 1,690 2,527
Average Foreign Exchange Rate (Canadian to US dollar) 0.77 0.71 0.64
-----------------------
Notes:
(1) Production before royalties reflects our working interest before royalties
and includes production of synthetic crude oil from Syncrude. We have
presented our working interest before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Long-term debt less net working capital.
[GRAPHIC OMITTED]
[Margin graph: Graph: Net Income (Cdn$ millions)]
In 2004, we had our best year ever financially. Strong oil and gas prices,
outstanding results from marketing, and late-year production additions in Yemen
and the North Sea fuelled our financial results. A stronger Canadian dollar,
declining base production and increasing costs moderated these results.
Nevertheless, net income has almost doubled since 2002. Over the same period,
our average realized oil and gas price only increased 28%. This is, in part, the
result of a strategic transition towards higher margin production, particularly
in the deep-water Gulf of Mexico where we have added over 30,000 boe/d of
low-royalty, low-cost production since 2002.
Margin text: Record financial results were fuelled by strong prices, outstanding
marketing results and new production from Yemen and the North Sea.
WTI averaged US$41.40/bbl in 2004, with crude oil prices spiking to new levels
throughout the year. The gains made from high prices were partially offset by a
strengthening Canadian dollar, relative to the US dollar. Our foreign revenues
and realized commodity prices were impacted when translated into Canadian
dollars, reducing cash flow from operating activities by $200 million and our
net income by $105 million.
To a lesser extent, the strengthening dollar positively affected our results.
Our foreign operating costs and capital expenditures were reduced when
translated into Canadian dollars. Additionally, most of our debt is US dollar
denominated, so the Canadian dollar debt equivalent was also decreased.
In total, we invested $4.3 billion in 2004 and made significant progress on the
many longer-cycle time development projects in our portfolio. In the Athabasca
oil sands, the Syncrude Stage 3 expansion is on schedule for production start-up
in mid-2006 and our Long Lake Project is on budget and on schedule to commence
bitumen production in 2006 and upgrading operations in 2007. In Yemen,
production from the BAK-A field on Block 51 came on stream in November, just 11
months after sanctioning and we had encouraging results from our exploration
program on the block. Offshore West Africa, drilling on OPL-222, offshore
Nigeria, resulted in a significant extension of the Usan discovery. We also
began exploration of OML-115, offshore Nigeria, and Block K, offshore Equatorial
Guinea.
In the fourth quarter, we acquired EnCana Corporation's UK North Sea assets for
US$2.1 billion in cash, subject to certain adjustments. The assets include the
Buzzard development, Scott and Telford producing fields, several undeveloped
discoveries, over 700,000 net exploratory acres and the team that built these
assets.
[GRAPHIC OMITTED]
[Margin text: Our US$2.1 billion North Sea acquisition establishes a new core
area for us.]
This acquisition creates a new core area for us. The Buzzard development is
currently on schedule to deliver oil volumes in late-2006. Scott and Telford are
currently producing approximately 19,000 boe/d before royalties and there are
opportunities in these fields and surrounding acreage to increase production
over the next few years.
29
In 2004, we saw production increases from our deep-water Gulf of Mexico
properties, Syncrude, and late-year contributions from Block 51, Scott and
Telford--all higher margin assets. However, these increases were not able to
overcome the declines from our maturing asset base at Masila in Yemen, in
Canada, and in the shallow-water Gulf of Mexico. We reached final production
from our Buffalo field in Australia in the fourth quarter. In addition, our 2003
production volumes included 6,200 boe/d before royalties of production relating
to Canadian assets sold in August 2003.
We added 123 mmboe of proved oil and gas reserves after royalties, including 13
million barrels relating to our Syncrude operations. Most of these additions
related to the North Sea acquisition and Syncrude expansion, offset by some
negative revisions in Yemen and Canada. At our Long Lake oil sands project, SEC
regulations require us to represent bitumen reserves for this project rather
than upgraded synthetic crude oil reserves we plan to sell from the lease. As a
result, we recognized 241 million barrels of proved bitumen reserves on
sanctioning. At year-end, low bitumen prices and high diluent and natural gas
prices resulted in the write-off of our proved bitumen reserves. However, our
Long Lake Project is designed to produce and upgrade bitumen into high-quality
synthetic crude oil in a fully integrated process which requires no diluent or
purchased natural gas. As a result, the economic returns from this process are
not dependent on bitumen, diluent and natural gas prices. This write-off has no
impact on our decision to proceed with this project.
[GRAPHIC OMITTED]
[Margin text: We added 123 mmboe of proved reserves after royalties, mostly in
the North Sea and at Syncrude. No proved reserves were booked at Long Lake.]
We financed our North Sea acquisition with cash on hand and bridge financing
facilities, increasing our net debt by about $2.6 billion. Historically, we have
used leverage to finance major expansions of our business, such as the Yemen
Masila project in 1993, the Wascana acquisition in 1997, and the Aspen
acquisition in 2002. In all cases, we have successfully used cash flow from
these assets to subsequently reduce our net debt. In 2005, we plan to reduce net
debt with approximately $1.5 billion in asset dispositions.
Our planned 2005 capital program of $2.6 billion is focussed on progressing our
major development projects and drilling over 20 high-potential exploration wells
in the Gulf of Mexico, offshore West Africa, North Sea and in Yemen. Less than
20% will be re-invested in our core assets to sustain production and cash flow.
Going forward, we are well positioned for growth. At the end of 2004, we had
over $3 billion of capital invested in multi-year development projects not yet
producing oil or cash flow. This amount is expected to peak in late-2006 at
approximately $5 billion, as we bring Buzzard and Long Lake on-stream. We expect
net debt to decrease significantly once these projects start contributing cash
flow in late-2006 and in 2007, respectively.
[GRAPHIC OMITTED]
[Margin text: By late-2006, we'll have almost $5 billion invested in multi-year
projects not yet producing oil or cash flow.]
Our share of incremental production and cash flow from this investment is
expected to be significant. Block 51 in Yemen is expected to reach close to
25,000 bbls/d before royalties, in mid-2005. Syncrude's Stage 3 expansion is
expected to come on stream in early-2006 adding an incremental 8,000 bbls/d
before royalties. Buzzard is on schedule for production start-up planned for
late-2006 with production ramping up to 80,000 boe/d before royalties in 2007.
At Long-Lake, bitumen production is planned to begin in late-2006. In the second
half of 2007, this bitumen will be upgraded to 30,000 bbls/d of premium
synthetic crude oil when the upgrader comes on stream. Later in the decade, we
expect to see significant new production volumes from OPL-222, offshore Nigeria.
Overall, we expect our oil and gas production before royalties to grow to
between 300,000 and 350,000 boe/d in 2007, after projected asset sales and base
declines. We have assumed exploration success contributes little volume to these
estimates.
Most of our new production is subject to little or no royalty payments and
generates significantly higher cash margins than our current production. As a
result, we expect our production after royalties to grow to between 260,000 and
300,000 boe/d in 2007.
[GRAPHIC OMITTED]
[Margin text: In 2007, we expect to produce between 300,000 and 350,000 boe/d
before royalties.]
30
CAPITAL INVESTMENT
ESTIMATED
(Cdn$ millions) 2005 2004 2003
---------------------------------------------------------------------------------------------
New Growth Development 1,675 682 358
New Growth Exploration 435 266 329
Core Asset Development 435 634 589
-----------------------------------
2,545 1,582 1,276
Acquisitions -- 2,587 164
-----------------------------------
Total Oil & Gas and Syncrude 2,545 4,169 1,440
Chemicals, Marketing and Other 50 95 54
-----------------------------------
Total Capital 2,595 4,264 1,494
===================================
Our strategy and capital programs are focused on growing long-term value for
shareholders. To maximize value, we invest in:
o core assets for short-term production and free cash flow to fund ongoing
capital programs and repay debt;
o development projects that convert our discoveries into new production and
cash flow; and
o exploration projects for longer-term growth.
As conventional basins in North America mature, we are transitioning our
operations towards less mature basins and unconventional resources in more
mature basins. These include the North Sea, Athabasca oil sands, Gulf of Mexico,
offshore West Africa and the Middle East - basins which we believe have
attractive fiscal terms and significant remaining opportunity.
[GRAPHIC OMITTED]
[Margin text: Our capital program supports short, mid and long-term growth.]
[Margin text: We are shifting our capital: investing less in maturing core
assets and more in attractive multi-year projects.]
2004 INVESTMENT PROGRAM
In 2004, we invested almost $4.3 billion, comprising $1.7 billion in capital
expenditures and $2.6 billion related to our North Sea acquisition. Excluding
this acquisition, most of our capital was invested in multi-year development
projects and long cycle-time exploration. Here is the breakdown of our capital
investment:
NEW GROWTH NEW GROWTH CORE ASSET
(Cdn$ millions) DEVELOPMENT EXPLORATION DEVELOPMENT TOTAL
---------------------------------------------------------------------------------------------
Oil and Gas
Synthetic (mainly Long Lake) 343 19 -- 362
North Sea 46 4 7 57
Yemen 112 19 155 286
United States -- 133 267 400
Canada 17 27 131 175
Other Countries -- 64 24 88
Syncrude 164 -- 50 214
-------------------------------------------------
682 266 634 1,582
Chemicals -- -- 58 58
Marketing, Corporate and Other -- -- 37 37
-------------------------------------------------
Total Capital 682 266 729 1,677
=================================================
As a % of Total Capital 41% 16% 43% 100%
-------------------------------------------------
[GRAPHIC OMITTED]
[Chart: 2004 Capital and 2005 Estimated Capital.]
31
2005 ESTIMATED CAPITAL
In 2005, we are managing our largest development and exploration program ever.
We plan to invest over $2.5 billion on our oil and gas and Syncrude assets
before considering the impact of dispositions. Around 65% of this is focused on
multi-year development projects, with the remainder split equally between new
growth exploration and our core assets.
NEW GROWTH NEW GROWTH CORE ASSET
(Cdn$ millions) DEVELOPMENT EXPLORATION DEVELOPMENT TOTAL
---------------------------------------------------------------------------------------------
Oil and Gas
Synthetic (mainly Long Lake) 765 -- -- 765
North Sea 590 50 45 685
Yemen 200 -- 70 270
United States -- 215 100 315
Canada -- 60 140 200
Other Countries -- 110 25 135
Syncrude 120 -- 55 175
-------------------------------------------------------
1,675 435 435 2,545
Chemicals -- -- 17 17
Marketing, Corporate and Other -- -- 33 33
-------------------------------------------------------
Total Capital 1,675 435 485 2,595
=======================================================
As a % of Total Capital 65% 17% 18% 100%
-------------------------------------------------------
[GRAPHIC OMITTED]
[Margin text: We'll invest over 80% of 2005 capital on major projects and
exploration.]
NEW GROWTH DEVELOPMENT
LONG LAKE PROJECT
Almost half our new growth development capital is being invested at Long Lake.
The project remains on schedule and on budget. Drilling of the commercial SAGD
wells began in late-2004 and will continue throughout 2005. Construction of the
SAGD and upgrader facilities is expected to begin in 2005, with the SAGD
facilities to be completed in late-2006 and the upgrader in 2007. The upgrader
is expected to come on stream in the second half of 2007 with our share of
bitumen production ramping up to 36,000 bbls/d (approximately 30,000 bbls/d of
synthetic crude oil production).
We are continuing to operate the three well-pair SAGD pilot to optimize
performance and gain a better understanding of our operating requirements. To
date, we have experienced higher than expected steam-to-oil ratios primarily as
a result of the existence of lean zones which absorb the steam without
increasing the oil flow. Late in 2004, we shut in one well-pair and reduced the
operating pressure of the remaining two well-pairs to see if we could reduce
fluid losses into the lean zones. As a result, we have seen fluid losses
decline, and our steam to oil ratio is continuing to drop. Production is now
averaging 500 to 600 bbls/d per well-pair, in line with industry experience and
our expectations given the reduced operating pressures.
As a result of our core hole and horizontal drilling for the commercial
SAGD wells, we are confident that the lean zone density in the commercial area
is lower than the pilot area. We expect to operate most of our commercial wells
at higher pressures than the current operating pressures of the SAGD pilot.
Higher operating pressures increase well productivity.
To ensure certainty and reliability of bitumen production when we begin
upgrading, we are accelerating one well pad consisting of 13 well pairs. This
pad will be drilled and tied-in after the current 65 well pairs, for a gross
cost of $98 million. While there is no change to total project costs,
accelerating this drilling capital increases the total gross capital to upgrader
start-up from $3.4 billion to $3.5 billion. We expect to have sufficient bitumen
supply to fill our upgrader to capacity as a result of the accelerated drilling
of the well pairs and the lower lean zone density.
To the end of December, approximately 35% of the project's total costs are
committed and 20% of these costs have been incurred. Costs to date are
consistent with our original estimates and the project is on time and on budget.
NORTH SEA DEVELOPMENT
Following our acquisition in the North Sea, we invested $46 million in Buzzard.
In 2005, we plan to invest approximately $530 million for development drilling,
pipeline installation and facility construction. This development is on budget
and on schedule to begin production in late-2006, with our share of production
expected to ramp up to 80,000 boe/d before royalties during 2007.
We also plan to evaluate and start developing a number of smaller discoveries on
our North Sea acreage. These discoveries contribute to the expected doubling of
non-Buzzard production in the North Sea by 2008. The first of these projects,
Farragon, is scheduled to come on stream in late-2005, with our share of
production reaching between 3,000 and 4,000 boe/d before royalties by
early-2006.
[GRAPHICS OMITTED]
[Margin text: Our Long Lake and Buzzard developments are on schedule and on
budget.]
[Margin text: North Sea should be producing about 120,000 boe/d after royalties
in 2008.]
32
YEMEN BLOCK 51
At Block 51, we began first oil production ahead of schedule in mid-November.
Production from the BAK-A field was producing 16,700 bbls/d before royalties at
year-end. Early production from several development wells is handled through
temporary production facilities and a new 22-km oil pipeline that connects to
the existing Masila export pipeline. We expect to reach full production of
25,000 bbls/d before royalties late in the second quarter of 2005. Another 15
development wells are planned throughout 2005.
We are developing our second Block 51 discovery, BAK-B. The field will initially
be developed with five wells and is expected to come on stream in late-2005. We
expect the BAK-A and BAK-B fields to maintain production at approximately 25,000
bbls/d before royalties, through 2007. We also expect to have sufficient
capacity with our production facilities to handle any additional growth that may
come from exploration success on the block.
SYNCRUDE STAGE 3 EXPANSION
We expect the Syncrude expansion to be completed in early-2006, adding 8,000
bbls/d before royalties of synthetic crude net to our 7.23% interest in the
joint venture. In 2005, we will focus on completing and commissioning the
upgrader expansion and increasing bitumen production supply.
NEW GROWTH EXPLORATION
We remain committed to exploration for longer-term growth. Like other aspects of
our business, our exploration portfolio has undergone a transition. Once
characterized by non-operated, high-risk prospects, our program is focussing
more on prospects that are operated, so we control timing, and have lower risk.
We have a balance of short and longer cycle-time prospects. Many are also
located near existing infrastructure, allowing for relatively quick tie-in upon
success.
[GRAPHIC OMITTED]
[Margin text: We remain committed to exploration for longer-term growth and have
both short and longer cycle-time prospects.]
We had a very active exploration program in 2004. We had success on OPL-222 in
Nigeria, and in the Gulf of Mexico at Tobago, Dawson Deep and most recently
Wrigley and Anduin. We will book proved reserves for these discoveries once
commercial projects are sanctioned.
Below are the results of our 2004 exploration program:
WELL LOCATION INTEREST WELL RESULTS
-------------------------------------------------------------------------------------------------------------------
NIGERIA
Usan 5 OPL-222 20% non-operated sampled oil in several intervals
Usan 6 OPL-222 20% non-operated flowed at restricted rate of 5,800 bbls/d
from one interval
Ameena OML-115 40% operated well abandoned
EQUATORIAL GUINEA
Zorro Block K 50% operated well abandoned
YEMEN
BAK-C Block 51 87.5% operated well abandoned
BAK-E Block 51 87.5% operated well abandoned
BAK-I Block 51 87.5% operated encountered oil shows; testing in
progress
US GULF OF MEXICO
Shark South Timbalier 174 40% non-operated well abandoned
Dawson Deep Garden Banks 625 15% non-operated discovery expected to begin producing in
late-2005 through sub-sea tie-back to the
Gunnison SPAR
Tobago Alaminos Canyon 858/859 13.34% non-operated discovery temporarily abandoned; possibly
part of future regional development
Crested Butte Green Canyon 242 100% operated 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% non-operated well abandoned
Fawkes Garden Banks 303 33 1/3% non-operated well abandoned
Wind River West Cameron 335 50% non-operated well abandoned
Wrigley Mississippi Canyon 506 50% non-operated gas discovery expected on stream
mid-2006
Anduin Mississippi Canyon 50% operated encountered oil shows; side-tracking to
754/755 delineate
-------------------------------------------------------------------------------------------------------------------
Our US program was delayed in 2004 due to rig delays and storms, but we plan to
drill up to 10 exploration wells in the Gulf in the next year. This includes
major deep-water, sub-salt prospects at Vrede, Knotty Head and Pathfinder. Most
of the drilling rigs are lined up, partner approvals are in place and we are
looking forward to the results of this program.
Overall, we expect to drill more than 20 high-potential wells in 2005, with most
of these to be drilled in the first half of the year. Internationally, we are
planning to drill exploration wells offshore West Africa, at least four wells in
the North Sea and four wells on Block 51 in Yemen.
[GRAPHIC OMITTED]
[Margin text: In 2005, we plan to drill more than 20 high-potential wells.]
We already have three wells underway with results expected in the first half of
2005:
REGION WELL LOCATION INTEREST
-----------------------------------------------------------------------------------------
US Gulf of Mexico Big Bend Mustang Island A-110 50% non-operated
US Gulf of Mexico Vrede Atwater Valley 25% non-operated
223/224/267/268
Yemen BAK-J Block 51 87.5% operated
In Canada, we continue to focus on large unconventional resource opportunities.
We expect to establish commerciality of our Upper Mannville CBM pilot at Corbett
in 2005, setting the stage for full field development, and to continue
evaluating other Upper Mannville and Horseshoe Canyon CBM prospects. We also
plan to continue a number of enhanced oil recovery pilot projects on our heavy
oil properties in west central Saskatchewan. These projects are evaluating
technologies to increase recovery of our extensive heavy oil properties.
CORE ASSETS
We are limiting our capital investment in core assets: the Gulf of Mexico shelf,
Masila in Yemen, and Western Canada. Generally, only 20% of the cash flow they
generate is being reinvested back into these assets. Our goal is to maximize
value from these assets in the form of returns, not necessarily increasing
reserves or production. By maximizing value, we also generate significant free
cash flow from these assets to help fund our major development projects and new
growth exploration.
[GRAPHIC OMITTED]
[Margin text: Core asset investment is focussed on maximizing returns, not just
increasing production or reserves.]
In the Gulf of Mexico, we tied-in the third development well at Aspen and the
remaining development wells at Gunnison. In 2005, our development program will
focus on a number of shallow-water gas opportunities in the Eugene Island and
Vermilion areas. In the deep-water, we intend to drill and tie back two sub-sea
wells and the Dawson Deep discovery to the Gunnison SPAR.
In the North Sea, we plan to drill, complete and tie-in five development wells
in the Scott/Telford area, work-over several existing wells and de-bottleneck
and upgrade production facilities on the Scott platform in 2005.
In Yemen, the Masila Block continues to generate value. At the end of 2004, we
have produced approximately 80% of Masila's expected reserves and have generated
more than US$1.5 billion of free cash flow, net to us. As we continue to deplete
the remaining reserves, we expect to recover more than US$1 billion of
additional free cash flow before the primary term of our production sharing
agreement expires in 2011.
The Masila fields are maturing and we are managing the pace of our drilling
program to between 20 and 40 wells per year to ensure we recover the remaining
reserves in the most economic and prudent manner. In 2005, we plan to drill at
least 20 wells to further develop existing fields and test deeper horizons where
we have had recent success. We expect our share of Masila production to be
between 74,000 and 84,000 bbls/d before royalties and to generate approximately
$300 million of free cash flow.
In Canada, we continue focusing on maximizing value from our existing assets
through infill drilling, optimizing production from existing wells and reducing
operating costs.
34
CHEMICALS
In the fourth quarter, our Brandon chemicals operations completed their sixth
expansion using relocated equipment from our idled Louisiana facility. The
expansion increased sodium chlorate production by 65,000 tonnes per year,
raising the annual plant capacity to over 260,000 tonnes. The Brandon plant is
now the largest sodium chlorate plant in the world, and we are one of the
largest and lowest cost producers of sodium chlorate in North America. Low input
and operating costs here are expected to help lower our overall manufacturing
cost of sodium chlorate. Activities in 2005 will focus on maintaining existing
infrastructure and limiting plant downtimes.
[GRAPHIC OMITTED]
[Margin comment: The expansion at Brandon makes it the world's largest sodium
chlorate plant.]
MARKETING, CORPORATE AND OTHER
In 2004, we continued implementing and realizing full benefits from our SAP and
other information technology platforms.
FINANCIAL RESULTS
YEAR TO YEAR CHANGE IN NET INCOME
MDA PAGE
(Cdn$ millions) 2004 VS 2003 2003 VS 2002 REFERENCE
-------------------------------------------------------------------------------------------------
NET INCOME FOR 2003 AND 2002 (1) 578 409
===========================
Favourable (unfavourable) variances:
CASH ITEMS:
Production volumes, after royalties:
Crude oil (116) 51
Natural gas (8) 41
Change in crude oil inventory 40 (25)
---------------------------
Total volume variance (84) 67 page 36
---------------------------
Realized commodity prices:
Crude oil 365 48
Natural gas -- 234
---------------------------
Total price variance 365 282 page 39
---------------------------
Oil and gas operating expense:
Conventional (55) 46
Synthetic (2) (14)
---------------------------
Total operating expense variance (57) 32 page 42
---------------------------
Marketing contribution (14) 96 page 46
Chemicals contribution 10 (5) page 48
General and administrative (39) (34) page 49
Interest expense 26 12 page 50
Current income taxes (38) 13 page 50
Other (22) 21 page 51
---------------------------
TOTAL CASH VARIANCE 147 484
---------------------------
NON-CASH ITEMS:
Depreciation, depletion, amortization and impairment:
Oil & Gas and Syncrude 271 (312) page 43
Other 13 (5)
Exploration expense (45) (12) page 44
General and administrative (70) (4) page 49
Future income taxes (176) 34 page 50
Other 75 (16) page 51
---------------------------
TOTAL NON-CASH VARIANCE 68 (315)
---------------------------
---------------------------
NET INCOME FOR 2004 AND 2003 793 578
===========================
Note:
(1) Includes results of discontinued operations (see Note 11 to our
Consolidated Financial Statements).
Significant variances in net income are explained in the sections that follow.
The impact of foreign exchange on our operations is summarized on page 51.
35
OIL & GAS AND SYNCRUDE
PRODUCTION
All volumes discussed below are our working interest volumes.
2004 2003 2002
-----------------------------------------------------------------------------------------------------------------------------
Before After Before After Before After
Royalties (1) Royalties Royalties (1) Royalties Royalties (1) Royalties
----------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 107.3 53.5 116.8 57.5 118.0 55.8
Canada (2) 36.2 28.2 46.3 35.4 56.3 43.4
United States 30.0 26.5 28.3 25.0 9.9 8.2
Australia (3) 2.7 2.5 6.1 5.6 12.8 10.3
United Kingdom 1.5 1.5 -- -- -- --
Other Countries 5.3 4.7 5.4 4.6 8.9 5.2
Syncrude (mmbls/d) (4) 17.2 16.6 15.3 15.2 16.6 16.5
----------------------------------------------------------------------------------------------
200.2 133.5 218.2 143.3 222.5 139.4
----------------------------------------------------------------------------------------------
Natural Gas (mmcf/d)
Canada (2) 146 115 158 125 167 128
United States 148 126 145 122 112 93
United Kingdom 3 3 -- -- -- --
----------------------------------------------------------------------------------------------
297 244 303 247 279 221
----------------------------------------------------------------------------------------------
Total (mboe/d) 250 174 269 185 269 176
==============================================================================================
Notes:
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Includes the following production from discontinued operations. See Note 11
to our Consolidated Financial Statements.
(mboe/d) 2004 2003 2002
-------------------------------------------------------------
Production
Before Royalties -- 6.2 10.5
After Royalties -- 4.6 7.8
--------------------------
(3) Comprises production from discontinued operations. See Note 11 to our
Consolidated Financial Statements.
(4) Considered a mining operation for US reporting purposes.
2004 VS 2003 - LOWER PRODUCTION DECREASED NET INCOME BY $84 MILLION
Production after royalties decreased 6% from 2003. Our 2003 production included
volumes from our non-core Canadian light oil properties in southeast
Saskatchewan that were sold in August 2003. Excluding these volumes, our
production after royalties decreased 3%. This table summarizes the change:
Before After
(mboe/d) Royalties Royalties
-----------------------------------------------------------------------------------------------------------------------------
2003 Production 269 185
Sale of non-core Canadian properties (6) (5)
-------------------------------
263 180
Production changes:
Masila Block in Yemen (11) (5)
Block 51 in Yemen 1 1
Canada (6) (4)
Gulf of Mexico - deep-water 8 7
Gulf of Mexico - shallow-water (6) (5)
Australia (3) (3)
North Sea 2 2
Syncrude 2 1
--------------- ---------------
2004 Production 250 174
=============== ===============
[GRAPHICs OMITTED]
[Margin text: Production dropped 6% after royalties and 7% before royalties as
new volumes did not offset declines in maturing fields.]
[Margin graphic: Bar graph: Oil and Gas Production before royalties (mmboe/d)]
36
Production before royalties decreased 7% as new volumes from the deep-water Gulf
of Mexico, the North Sea and Block 51 did not offset declines in our maturing
conventional assets and late-life assets offshore Nigeria and Australia and the
sale of Canadian properties in 2003. Our known future production increases are
expected to come from Block 51 in Yemen in 2005, Syncrude in early-2006, first
production from Buzzard in the North Sea in late-2006, and from bitumen
production in 2006 and synthetic crude in 2007 from the Long Lake Project.
YEMEN
Production decreased 8% compared to 2003. The shortfall resulted from declining
base production, lower drilling success rates and delays in approvals for our
development drilling program. As a result, we drilled 73 development wells
rather than the 90 planned, and this drilling was unable to keep up with base
declines. In 2005, we plan to drill at least 20 wells.
First production from Block 51 commenced in November 2004 with initial rates
around 4,000 bbls/d. By mid-2005, we expect production to ramp up to
approximately 25,000 bbls/d before royalties as permanent production facilities,
including water handling facilities, are commissioned.
[GRAPHIC OMITTED]
[Margin text: First oil from Block 51 was achieved ahead of schedule.]
We expect production from Masila and Block 51 to average between 90,000 and
100,000 bbls/d before royalties in 2005.
CANADA
Production was down 9% from 2003, after adjusting for the August 2003 sale of
non-core, light-oil properties in southeast Saskatchewan. To maximize value, we
continue to manage our maturing conventional assets in Western Canada through
selective development, cost control and asset dispositions. In 2005, we expect
them to produce between 52,000 and 56,000 boe/d before royalties, net to us.
Looking ahead, we expect increases as the Long Lake Project starts up with
bitumen production in 2006 and synthetic crude in 2007. We are considering the
sale of certain Canadian oil and gas properties in 2005. Any sale of assets
would reduce our 2005 production volumes.
GULF OF MEXICO
Production averaged an all-time high of 54,700 boe/d before royalties, 4% higher
than last year, due to new deep-water volumes at Aspen and Gunnison.
Our deep-water production grew 8,000 boe/d before royalties over 2003 levels.
These high-margin volumes contribute cash netbacks almost twice our corporate
average. The third Aspen development well, brought on stream in July, is
currently producing 16,200 boe/d before royalties. However, we experienced
higher water cuts on our Aspen-1 well and completed an intervention, attempting
to reduce these cuts. The well was shut-in for most of August to complete this
work. To date, the response has not met our expectations as there has been no
increase in oil production or decrease in water production. We are currently
producing 24,500 boe/d before royalties from all three wells.
[GRAPHIC OMITTED]
[Margin text: We added 8,000 boe/d before royalties of high-margin barrels in
the deep water. These fuelled our corporate netbacks. See page 45.]
We completed the tie-in of the remaining wells at Gunnison which added 9,000
boe/d before royalties in 2004. These volumes were less than expected as one
well sanded up in early May and another encountered tar on completion. We
successfully re-completed the well that sanded up and brought it back on stream
in mid-August. A sidetrack on the tar well was completed and this well started
producing from one of three intervals in mid-December. We expect to produce from
all three intervals by the end of February 2005.
Our shallow-water production declined 6,000 boe/d before royalties compared to
2003, caused by base declines and delays in our development program. We had
planned an expanded development program in the second half of the year, but it
was delayed due to rig delivery, storms and drilling problems. Development
drilling at Vermilion 302/320, West Cameron 170 and Vermilion 76 helped mitigate
declines.
We expect production from the Gulf of Mexico to average between 50,000 and
60,000 boe/d in 2005.
37
NORTH SEA
The acquired Scott and Telford fields contributed production for December 2004,
adding 2,000 boe/d before royalties to our annual average. In 2005, we expect
these fields to produce between 14,000 and 18,000 boe/d before royalties, net to
us.
OTHER COUNTRIES
Australia produced its final barrel in November and abandonment activities are
proceeding. We expect abandonment activities to be completed in 2005. Production
from Colombia grew 50% from 2003 to 4,800 bbls/d before royalties as we continue
to implement our development program at Guando. We continue to produce small
volumes from the Ejulebe field offshore Nigeria, but we expect final production
in the first half of 2005.
[GRAPHIC OMITTED]
[Margin text: Australia is fully depleted and Nigeria is to be depleted in
2005.]
SYNCRUDE
Syncrude achieved a new annual production record despite operating problems
towards the end of the year. In November, we experienced an unscheduled coker
shut-down. After the coker had returned to full capacity in early December, a
major electrical interruption led to the shut-down of the LC finer for the rest
of the year. The LC finer has returned to full capacity. Turnarounds on the
coker and hydrotreater units in early-2005 are expected to cause first quarter
production to be lower than planned by 25%. We expect 2005 Syncrude volumes of
between 16,000 and 18,000 bbls/d before royalties, net to us.
[GRAPHIC OMITTED]
[Margin text: Syncrude produced a record 17.2 mboe/d before royalties,
net to us.]
2003 VS 2002 - 5% PRODUCTION GROWTH AFTER ROYALTIES ADDED $67 MILLION TO NET
INCOME
Production after royalties grew 5%, with new low-royalty, deep-water production
from Aspen and Gunnison, and more cost recovery barrels from Masila in Yemen. At
Masila, we received a greater percentage of gross production to recover costs
incurred.
Production before royalties was flat compared to 2002 as growth in our US
deep-water production was partially offset by dispositions in Canada, production
declines offshore Nigeria and Australia, and maturing conventional assets.
Production from the Masila block in Yemen decreased slightly in 2003 consistent
with the overall decline in the field's base production. In Canada, we
aggressively managed our assets by developing them where we could add value or
by selling them at attractive prices where this maximized value. A full year of
deep-water Aspen production increased US production rates 84% to record levels
in 2003. Production adds and optimization activities at Eugene Island 295 and
Vermilion 76 offset declines on the Shelf.
Our production at Buffalo, offshore Australia and at Ejulebe, offshore Nigeria
declined as expected throughout 2003 as both fields approached the end of their
economic life. Syncrude production decreased 8% in 2003 as an unplanned
additional coker turnaround was completed during the year.
38
COMMODITY PRICES
2004 2003 2002
--------------------------------------------------------------------------------
CRUDE OIL
West Texas Intermediate (US$/bbl) 41.40 31.04 26.09
--------------------------
Differentials (1) (US$/bbl)
Masila 4.84 3.03 1.41
Heavy Oil 13.53 8.63 6.49
MARS 6.15 3.53 2.51
Producing Assets (Cdn$/bbl)
Yemen 47.59 39.45 38.80
Canada 36.60 32.37 31.13
United States 46.60 37.68 38.88
Syncrude 52.80 43.36 40.89
Australia 51.22 43.14 40.30
North Sea 46.81 -- --
Other Countries 43.07 38.22 38.96
Corporate Average (Cdn$/bbl) 45.90 38.04 37.13
--------------------------
NATURAL GAS
New York Mercantile Exchange (US$/mmbtu) 6.19 5.60 3.37
AECO (Cdn$/mcf) 6.44 6.35 3.84
--------------------------
Producing Assets (Cdn$/mcf)
Canada 5.76 5.64 3.57
United States 7.89 8.16 5.29
North Sea 8.28 -- --
Corporate Average (Cdn$/mcf) 6.85 6.85 4.25
--------------------------
NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 44.94 38.63 35.14
--------------------------
AVERAGE FOREIGN EXCHANGE RATE
Canadian to US Dollar 0.7683 0.7135 0.6369
--------------------------
Note:
(1) These differentials are a discount to WTI.
[GRAPHIC OMITTED]
[Margin graphic: Chart of Nexen's average realized oil and gas price 2002-2004]
2004 VS 2003 - HIGHER REALIZED PRICES ADDED $365 MILLION TO NET INCOME
Crude oil prices reached record levels in 2004, supported by supply concerns,
high demand and speculative traders increasing volatility to all-time highs. The
positive impact of strong crude oil reference prices was offset in part by the
weakening US dollar and widening crude oil quality differentials.
All of our oil sales and most of our gas sales are denominated in or referenced
to US dollars. As a result, a stronger Canadian dollar relative to the US dollar
reduced our realized crude oil price by $3.50/bbl and our realized natural gas
price by $0.50/mcf. In total, our net sales decreased $220 million from 2003 due
to the weakening US dollar. The Canadian to US dollar exchange rate closed the
year at 83(cent).
[GRAPHIC OMITTED]
[Margin text: A stronger Canadian dollar reduced our realized oil and gas prices
and dropped net sales by $220 million.]
39
CRUDE OIL REFERENCE PRICES
Crude oil prices reached record highs in 2004 and West Texas Intermediate (WTI)
averaged US$41.40/bbl in 2004, 33% higher than its 2003 average of US$31.04/bbl.
At its peak, WTI broke through US$55/bbl. Strong demand and concerns around
supply disruptions and inventories, coupled with significant volatility,
contributed to the increase.
Strong global demand, led by China and India, prevailed throughout much of 2004.
Even as WTI reached successive record highs late in the year, demand for crude
oil, particularly sweet blends, remained strong globally. While global demand
drove crude oil prices up, actual and potential supply concerns supported major
price moves:
o terrorist activities in Iraq continued throughout the year, disrupting
supply on several occasions;
o attacks in Saudi Arabia called into question not only the security of
current supply, but also the security of the only significant spare
capacity globally;
o on-going civil unrest in Nigeria and Venezuela impacted their ability to
export crude;
o labour disputes and safety concerns in the North Sea disrupted supply on
several occasions, increasing concerns around already tight European
supply;
o Hurricane Ivan disrupted supply from the Gulf of Mexico in the third
quarter and increased concern over low inventory levels in the US; and
o the Yukos bankruptcy crisis reduced expected production increases from
Russia.
OPEC responded by increasing output on several occasions, but these increases
were not enough to change the perception that there was insufficient stable
supply to meet demand.
These events caused significant oil price volatility. As a result, traders and
longer-term commodity investors flocked to the market, pushing daily trading
bands higher than previously observed. Traders' positions and related
profit-taking created more volatility. With supply concerns, growing speculation
and continued volatility, we expect to see high crude oil prices continue into
2005.
[GRAPHICS OMITTED]
[Margin text: WTI oil price was 33% higher than in 2003, reflecting supply
concerns.]
[Margin text: We expect strong crude oil prices in 2005.]
CRUDE OIL DIFFERENTIALS
Crude oil differentials were wide in 2004 due mostly to strong benchmark prices.
Growing global demand for diesel and gasoline has created a premium for light,
sweet crudes. Incremental heavy, sour barrels brought on by OPEC throughout the
year widened out the light/heavy differentials even further. The Canadian heavy
oil differential widened to average US$13.53/bbl, as light, sweet blends
increased in value relative to heavy, sour blends. Although differentials were
wide, the normal seasonal patterns held true which narrows the heavy oil
differential through the summer when there is increased demand due to road
construction. Heavy oil differentials reached a record-wide US$22.67/bbl in
December from these factors.
[GRAPHIC OMITTED]
[Margin text: Widening differentials reduced the price we received for our
heavy oil, Masila and Aspen volumes.]
40
The WTI/Brent differential (relevant for our Masila crude and North Sea
production) widened to average US$3.19/bbl in 2004 compared to US$2.20 in 2003.
Higher freight rates due to increased production out of the Middle East made
Brent more expensive to purchase, thereby decreasing its value relative to WTI.
The Masila differential tracked the Brent/WTI spread very closely through the
first eight months of the year, but widened relative to both WTI and Brent late
in the year. As with Canadian heavy oil differentials, our Masila barrels were
impacted by the increased supply of heavy, sour oil from the Middle East later
in the year and strong demand by Asian refiners for lighter blends. The
differential reached US$7.84/bbl in the fourth quarter, compared to its annual
average of US$4.84.
Similar to Canadian heavy oil and Masila, the MARS differential (relevant for
Aspen) widened on the strength of WTI and the increased supply of world heavies.
NATURAL GAS REFERENCE PRICES
Natural gas prices remained strong in 2004, buoyed by high crude oil prices and
tight long-term supply and demand fundamentals. In 2004, NYMEX averaged
US$6.19/mcf, 11% higher than 2003. Weather was reasonably mild in North America,
causing a strong build in inventory levels into winter.
[GRAPHIC OMITTED]
[LINE CHART - 2004 Natural Gas Prices (NYMEX Monthly Average)]
At year-end, inventory levels were 3% higher than 2003 and 11% higher than the
five-year average. Despite this, long-term concerns remain around the ability of
supply to keep up with demand from North American utilities. As a result, we
expect prices to remain above US$5/mmbtu into the future. Even with short-term
bearish fundamentals, prices tracked their normal seasonal pattern and remained
relatively strong into winter, consistent with higher heating oil prices.
[GRAPHICS OMITTED]
[Margin text: NYMEX gas price was 11% higher than in 2003, reflecting concerns
that supply could not keep pace with demand.]
[Margin text: We expect prices to remain above US$5/mcf into the future]
2003 VS 2002 - HIGHER REALIZED PRICES ADDED $282 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 stronger Canadian dollar and wider crude oil differentials.
Since all of our oil sales and most of our gas sales are denominated in or
referenced to US dollars, the strengthening Canadian dollar relative to the US
dollar reduced our realized crude oil price by $4.50/bbl and our realized
natural gas price by $0.80/mcf. In total, our net sales decreased $280 million
from 2002 levels because of the stronger Canadian dollar. The Canadian to US
dollar exchange rate closed the year at 77(cent).
41
OPERATING COSTS
(Cdn$/boe) 2004 2003 2002
-----------------------------------------------------------------------------------------------------------------------------
Before After Before After Before After
Royalties (1) Royalties Royalties (1) Royalties Royalties (1) Royalties
--------------------------------------------------------------------------------------------
Conventional Oil and Gas
Yemen 2.80 5.64 2.16 4.37 1.95 4.13
Canada 7.12 8.98 6.00 7.76 5.70 7.45
United States 5.30 6.12 4.49 5.19 9.09 10.87
Australia 32.94 35.73 18.60 20.21 9.76 12.14
United Kingdom 8.26 8.26 -- -- -- --
Other Countries 3.76 4.09 7.47 9.01 6.21 10.69
Average Conventional 5.13 7.59 4.17 6.24 4.60 7.24
--------------------------------------------------------------------------------------------
Synthetic Crude Oil
Syncrude 19.89 20.61 21.96 22.18 18.10 18.21
Average Oil and Gas 6.15 8.83 5.19 7.56 5.42 8.26
--------------------------------------------------------------------------------------------
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.
2004 VS 2003 - HIGHER OIL AND GAS OPERATING COSTS DECREASED NET INCOME BY $57
MILLION
Our operating costs have increased as a result of high-cost, late-life barrels
in Australia, higher maintenance costs in Yemen and Canada, more workover and
remediation activity in the Gulf of Mexico and the spread of fixed costs over
fewer barrels.
[GRAPHIC OMITTED]
[Margin text: Higher operating costs per boe reflect lower volumes and
increased maintenance and workovers.]
Flow line replacements, higher water handling costs and increased maintenance at
Masila in Yemen increased our corporate unit operating costs by 30(cent)/boe.
However, these increased Yemen costs only reduce our corporate netbacks by
5(cent)/boe as a result of the cost recovery mechanism contained in our
production sharing agreement.
Operating costs in Canada were slightly lower than 2003, but because of
declining volumes, our corporate average unit costs increased by 25(cent)/boe.
We expect our unit costs to continue to increase with increased water handling,
higher labour costs and declining volumes.
Aspen-1 intervention costs of $12 million were expensed during the year. They
were higher than expected as storm activity in the Gulf extended the work. These
costs, together with higher workover activities on the Shelf, contributed a
28(cent)/boe increase to our corporate unit costs.
Australia produced its final barrel in November. These expensive late-life
barrels increased our corporate unit costs by 30(cent)/boe but high crude prices
allowed us to produce them economically.
The incremental North Sea barrels added 7(cent)/boe to our corporate average for
the year.
The strength of the Canadian dollar reduced our US-dollar denominated operating
costs, contributing a 25(cent)/boe reduction to our corporate unit costs.
Syncrude's operating costs were flat compared to 2003, but because of increased
volumes, unit costs decreased 9%. Higher natural gas input costs were offset by
lower maintenance costs in 2004 since there was not a major coker turnaround. As
more expensive Syncrude barrels were a larger portion of our total corporate
production in the year, our corporate unit operating costs increased by
17(cent)/boe.
2003 VS 2002 - LOWER OIL AND GAS OPERATING COSTS INCREASED NET INCOME BY $32
MILLION
Conventional unit operating costs decreased as we added low-cost Aspen
production in the Gulf of Mexico and the Canadian dollar strengthened relative
to the US dollar. Increased workover and maintenance activity in Yemen and
higher water handling costs in Canada partially offset this decrease.
Low-cost Aspen production reduced US operating costs by 50% and lowered our
corporate average unit operating costs by approximately 40(cent)/boe. Aspen
production costs are lower than our corporate average for conventional
production as most of the costs in the deep-water are capital related.
42
The strengthening Canadian dollar decreased US-dollar denominated operating
costs, lowering our corporate average unit operating costs by approximately
25(cent)/boe. Higher repairs, increased maintenance and workover activity
resulted in a 55(cent)/bbl increase in Yemen operating costs. However, these
increased Yemen costs only reduced our corporate netbacks by 14(cent)/boe as a
result of the cost recovery mechanism contained in our production sharing
agreement. As well, unit operating costs offshore Australia and Nigeria
increased as fixed costs were spread over declining production volumes.
Syncrude operating costs increased 21% due to higher natural gas input costs and
increased turnaround and maintenance activity in 2003. Lower volumes also
increased unit operating costs as more than 95% of the operating costs are
fixed.
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
(Cdn$/boe) 2004 2003 2002
-----------------------------------------------------------------------------------------------------------------------------
Before After Before After Before After
Royalties (2) Royalties Royalties (2) Royalties Royalties (2) Royalties
--------------------------------------------------------------------------------------------
Conventional Oil and Gas
Yemen 4.35 8.77 3.96 8.03 3.47 7.34
Canada (1) 9.02 11.37 9.10 11.76 8.22 10.72
United States 12.93 14.93 10.80 12.47 12.74 15.38
Australia 5.82 6.31 13.31 14.46 10.45 12.99
United Kingdom 22.44 22.44 -- -- -- --
Other Countries 9.90 10.77 17.09 22.47 13.22 22.90
Average Conventional 7.87 11.64 7.37 11.04 6.84 10.81
--------------------------------------------------------------------------------------------
Synthetic Crude Oil
Syncrude 2.75 2.85 2.50 2.53 2.13 2.17
Average Oil and Gas 7.52 10.80 7.09 10.33 6.55 10.01
--------------------------------------------------------------------------------------------
Notes:
(1) 2003 DD&A per boe excludes the impairment charge described in Note 5 to 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.
2004 VS 2003 - LOWER OIL AND GAS DD&A INCREASED NET INCOME BY $271 MILLION
Our DD&A expense in 2003 included an impairment charge of $269 million largely
attributable to Canadian heavy oil property negative reserve revisions.
Excluding this charge from our 2003 per unit DD&A costs, our per unit corporate
depletion rate has increased. Higher depletion from our more capital-intensive
deep- water properties in the Gulf of Mexico has increased corporate rates by
70(cent)/boe. These properties, however, benefit from low royalties and lower
unit operating costs as most of the costs are capital in nature.
Yemen increased our corporate rate by 30(cent)/boe mainly due to the additional
volumes from Block 51, offset slightly by lower volumes at Masila. The North Sea
volumes increased our corporate rate by 20(cent)/boe. Our UK depletion rate of
$22.44/boe reflects the depletion of the portion of the acquisition cost
allocated to our interests in the Scott/Telford fields on a before-tax basis.
Syncrude depletion rates increased reflecting the depletable costs of the Aurora
2 bitumen train which came into service in late-2003.
By way of offset, we benefited from the strong Canadian dollar as the depletion
of our US and International assets is denominated in US dollars. This lowered
our depletion rate by 45(cent)/boe. As well, the depletable costs on our
Canadian heavy oil properties were reduced at year-end 2003 and both Australia
and Nigeria are nearly fully depleted. The write down of our Canadian heavy oil
properties reduced our depletion rate by 31(cent)/boe and lower volumes in
Canada, Australia and Nigeria contributed a combined reduction of 65(cent)/boe.
[GRAPHIC OMITTED]
[Margin text: Our DD&A rate is increasing because of more capital-intensive
areas includiong the Gulf of Mexico and the North Sea.]
2003 VS 2002 - HIGHER OIL AND GAS DD&A REDUCED NET INCOME BY $312 MILLION
Conventional depletion rates increased with higher 2002 finding and development
costs and our changing production mix, as more capital-intensive properties like
Aspen contributed production 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
prepared to abandon these fields.
43
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 48(cent)/boe.
Our 2003 DD&A expense includes an impairment charge of $269 million largely
attributable to reserve revisions to Canadian heavy oil properties. These
revisions reflected our more conservative view of production profiles for
certain properties, proven undeveloped reserves we were no longer certain we
could recover and changes in end-of-life economic assumptions.
EXPLORATION EXPENSE (1)
(Cdn$ millions) 2004 2003 2002
--------------------------------------------------------------------------------
Seismic 73 62 80
Unsuccessful Drilling 125 70 61
Other 48 69 48
--------------------
Total Exploration Expense 246 201 189
====================
New Growth Exploration 266 267 179
Geological and Geophysical Costs 73 62 80
--------------------
Total Exploration Expenditures 339 329 259
====================
Exploration Expense as a % of Exploration Expenditures 73% 61% 73%
--------------------
Note:
(1) Includes exploration expense from discontinued operations. See Note 11 to
our Consolidated Financial Statements.
2004 VS 2003 - HIGHER EXPLORATION EXPENSE REDUCED NET INCOME BY $45 MILLION
Increased exploration expense reflected the increase in our 2004 exploration
capital expenditures. We had further success at Usan on OPL-222, offshore
Nigeria, Block 51 in Yemen and at Dawson Deep, Tobago, Wrigley and Anduin in the
deep-water Gulf of Mexico. However, unsuccessful drilling included dry holes in
the Gulf of Mexico, offshore Nigeria and Equatorial Guinea, and in Yemen.
[GRAPHIC OMITTED]
[Margin text: Increased 2004 exploration expense reflects higher exploration
capital. See 2004 drilling results on page 33.]
In the Gulf of Mexico, we had five dry holes: Crested Butte, Main Pass 240,
Shark, Fawkes and Wind River. At our 100%-owned Crested Butte well on Green
Canyon Block 242, we found oil-bearing sands in many horizons, but the volumes
were not commercial so we abandoned the well. Further work is required to
determine if a sidetrack is warranted. We expensed $39 million of well costs in
the fourth quarter. In 2004, we drilled Main Pass 240 and found the objective
sand wet. This well was abandoned in December 2004. Shark was an
ultra-deep-shelf gas test on South Timbalier 174 that finished drilling during
the first quarter of 2004. Following our evaluation, we expensed $25 million of
well costs. While the well has been abandoned, we can re-enter it if required.
Fawkes and Wind River, located in deep water, completed drilling and were
abandoned in January 2005, resulting in a write-off of $13 million in 2004.
Overall, dry hole and seismic costs in the Gulf of Mexico accounted for over 50%
of our exploration expense.
[GRAPHIC OMITTED]
[Margin text: Gulf of Mexico accounts for half our 2004 dry-hole and seismic
costs.]
Dry hole costs also included the Ameena prospect on OML-115, offshore Nigeria,
the Zorro-1 prospect, offshore Equatorial Guinea and two unsuccessful
exploration wells on Block 51 in Yemen.
2003 VS 2002 - HIGHER EXPLORATION EXPENSE REDUCED NET INCOME $12 MILLION
Exploration expense was higher in light of our increased 2003 exploration
capital expenditures. We had success in the Gulf of Mexico, OPL-222, offshore
Nigeria and Block 51 in Yemen.
Dry hole and seismic costs in the Gulf of Mexico accounted for over 40% of our
exploration expense. Exploration in the Gulf yielded some promising results at
Shiloh where we found hydrocarbons but not commercial quantities, so the well
costs were written off. We were unsuccessful at Santa Rosa.
Dry hole costs also included three wells in the Alberta foothills of Canada, the
Andino-1 well in Colombia, the Escargot well offshore Brazil and the HEK well in
Yemen on Block 51.
44
OIL & GAS AND SYNCRUDE NETBACKS
Netbacks are the cash margins we receive for every equivalent barrel sold. Below
are the sales prices, per unit costs and netbacks for our producing assets,
calculated using our working interest production before and after royalties.
BEFORE ROYALTIES
($/boe) 2004
---------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia UK Other Syncrude Total
----------------------------------------------------------------------------------------------
Sales 47.59 35.76 46.94 51.22 47.45 43.07 52.80 44.94
Royalties and other (23.98) (7.40) (6.29) (4.00) -- (3.49) (1.84) (13.65)
Operating expenses (2.80) (7.12) (5.30) (32.94) (8.26) (3.76) (19.89) (6.15)
In-country taxes (5.82) -- -- -- -- -- -- (2.48)
----------------------------------------------------------------------------------------------
Cash netback 14.99 21.24 35.35 14.28 39.19 35.82 31.07 22.66
==============================================================================================
($/boe) 2003
---------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia UK Other Syncrude Total
----------------------------------------------------------------------------------------------
Sales 39.45 32.99 42.88 43.14 -- 38.22 43.36 38.63
Royalties and other (19.98) (7.53) (5.91) (3.44) -- (5.69) (0.48) (12.14)
Operating expenses (2.16) (6.00) (4.49) (18.60) -- (7.47) (21.96) (5.19)
In-country taxes (4.73) -- -- -- -- -- -- (2.06)
----------------------------------------------------------------------------------------------
Cash netback 12.58 19.46 32.48 21.10 -- 25.06 20.92 19.24
==============================================================================================
($/boe) 2002
---------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia UK 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 expenses (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
==============================================================================================
AFTER ROYALTIES
($/boe) 2004
---------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia UK Other Syncrude Total
----------------------------------------------------------------------------------------------
Sales 47.59 35.76 46.94 51.22 47.45 43.07 52.80 44.94
Operating expenses (5.64) (8.98) (6.12) (35.73) (8.26) (4.09) (20.61) (8.83)
In-country taxes (11.72) -- -- -- -- -- -- (3.57)
----------------------------------------------------------------------------------------------
Cash netback 30.23 26.78 40.82 15.49 39.19 38.98 32.19 32.54
==============================================================================================
($/boe) 2003
---------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia UK Other Syncrude Total
----------------------------------------------------------------------------------------------
Sales 39.45 32.99 42.88 43.14 -- 38.22 43.36 38.63
Operating expenses (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
==============================================================================================
($/boe) 2002
---------------------------------------------------------------------------------------------------------------------
Yemen Canada US Australia UK Other Syncrude Total
----------------------------------------------------------------------------------------------
Sales 38.80 27.90 34.21 40.30 -- 38.96 40.89 35.14
Operating expenses (4.13) (7.45) (10.87) (12.14) -- (10.69) (18.21) (8.26)
In-country taxes (10.17) -- -- -- -- -- -- (3.20)
----------------------------------------------------------------------------------------------
Cash netback 24.50 20.45 23.34 28.16 -- 28.27 22.68 23.68
==============================================================================================
[GRAPHIC OMITTED]
[Margin text: With little or no royalties, new production from the deep-water
Gulf of Mexico and North Sea is driving our corporate netbacks.]
45
OIL AND GAS MARKETING
(Cdn$ millions) 2004 2003 2002
-----------------------------------------------------------------------------------------
Revenue 623 568 496
Transportation (466) (398) (423)
Other (2) (1) --
-------------------------
Net Revenue 155 169 73
=========================
Marketing Contribution to Income from Continuing Operations
before Income Taxes 87 111 35
-------------------------
Natural Gas
Physical Sales Volumes (bcf/d) (1) 4.9 3.3 2.9
Transportation Capacity (bcf/d) 3.5 2.0 1.2
Storage Capacity (bcf) 27 18 9
Crude Oil
Physical Sales Volumes (mbbls/d) (1) 465 479 412
Storage Capacity (mbbls) 408 -- --
Value-at-Risk
Year-end 21 21 19
High 42 31 28
Low 17 14 12
Average 29 20 17
-------------------------
Note:
(1) Excludes intra-segment transactions.
[GRAPHIC OMITTED]
[Margin graphic: Oil and Gas Volumes Marketed (boe/d)]
2004 VS 2003 - NET MARKETING REVENUE DECREASED NET INCOME BY $14 MILLION
Although more profitable in 2003, marketing had another exceptional year in
2004, with net revenue of $155 million. Gas marketing contributed $95 million to
net revenue from asset-based trading, our energy services business, and from
transportation and commodity contracts acquired on favourable terms.
[GRAPHIC OMITTED]
[Margin text: Gas marketing contributed 61% of marketing revenue.]
During the year, we took advantage of market inefficiencies and seasonal
variations. In particular, our transportation and storage capacity gave us the
flexibility to capitalize on weather events by allowing us to move gas to where
it was needed most. We also held financial contracts that allowed us to capture
trading profits around time and location spreads.
North American crude oil contributed $25 million to net revenue as varying
degrees of backwardation (declining prices) in the forward price curve
throughout the year allowed us to capitalize on calendar spreads. In addition,
we took advantage of quality spreads and arbitrage opportunities to capture
favourable price differences.
International crude oil contributed $24 million, three times higher than last
year. Throughout the year, we successfully capitalized on the pricing of
purchases relative to sales as we took advantage of backwardation in the forward
price curve.
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.
In marketing, we enter into contracts to purchase and sell crude oil and natural
gas. We also use financial and derivative contracts, including futures,
forwards, swaps and options for hedging and trading purposes.
We account for all derivative contracts, not designated as hedges for accounting
purposes, 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 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.
[GRAPHIC OMITTED]
[Margin text: We mark-to-market all derivative contracts not designated as
hedges. The gain or loss is recorded in marketing and other income.]
FAIR VALUE OF DERIVATIVE CONTRACTS
At December 31, 2004, the fair value of our derivative contracts not designated
as hedges totalled $93 million (2003 - $106 million). Below is a breakdown of
this fair value by valuation method and contract maturity:
(Cdn$ millions) MATURITY
----------------------------------------------------------------------------------------------------------
(less than)1 year 1-3 years 4-5 years (more than)5 years Total
---------------------------------------------------------------------
Prices
Actively Quoted Markets 5 (3) -- -- 2
From Other External Sources 43 40 9 (1) 91
Based on Models and
Other Valuation Methods -- -- -- -- --
---------------------------------------------------------------------
Total 48 37 9 (1) 93
=====================================================================
More than 50% of the unrealized fair value relates to contracts that will settle
in 2005. 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.
[GRAPHIC OMITTED]
[Margin text: More than 50% of our unrealized fair value is for contracts
settling in 2005. This helps reduce our risk.]
At December 31, 2004, we had $6 million of unrecognized gains on our derivative
contracts designated as accounting hedges of the future sale of our gas
inventory. These gains will be recognized in income when the inventory is sold.
These contracts were valued from actively quoted markets and settle within 12
months.
We do not use option valuation methods to record income on transportation and
storage contracts.
47
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
Contracts
Contracts Contracts Entered into
Outstanding at Entered into During Year
Beginning of and Closed and Outstanding
(Cdn$ millions) Year During Year at End of Year Total
-----------------------------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2003 106 -- -- 106
Change in Fair Value of Contracts (26) 77 82 133
Net Losses (Gains) on Contracts Closed (69) (77) -- (146)
Changes in Valuation Techniques
and Assumptions (1) -- -- -- --
-------------------------------------------------------------------
Fair Value at December 31, 2004 11 -- 82 93
====================================================
Unrecognized Gains on Hedges of
Future Sale of Inventory
at December 31, 2004 6
---------------
Total Outstanding at December 31, 2004 99
===============
Note:
(1) Our valuation methodology has been applied consistently year-over-year.
TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS
(Cdn$ millions) 2004 2003
----------------------------------------------------------------------------------------------------------------------------
Current Assets 177 102
Non-Current Assets 91 63
-----------------------------
Total Derivative Contract Assets 268 165
=============================
Current Liabilities 129 34
Non-Current Liabilities 46 25
-----------------------------
Total Derivative Contract Liabilities 175 59
=============================
Total Derivative Contract Net Assets (1) 93 106
=============================
Note:
(1) Does not include effective hedges. We recognize gains and losses on
effective hedges in the same period as the hedged item.
NON-TRADING ACTIVITIES
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 $22 million from our non-trading activities in 2004 (2003 - $21
million).
In 2003 and 2004, we increased our transportation capacity and were paid to
assume future obligations associated with the capacity. We included $53 million
of deferred revenue on our balance sheet to recognize the liability associated
with these obligations. This deferred revenue will be amortized to earnings as
the capacity is used.
[GRAPHIC OMITTED]
[Margin text: We enter into fee-for-service contracts related to transportation
and storage, and increased our transportation capacity in 2003 and 2004.]
CHEMICALS
(Cdn$ millions) 2004 2003 2002
------------------------------------------------------------------------------------------------------------------------
Net Sales 378 375 367
Sales Volumes (thousand short tons)
Sodium chlorate 506 478 454
Chlor-alkali 403 396 375
Operating Profit (1) 105 95 100
Operating Margin (2) 28% 25% 27%
Chemicals Contribution to Income from Continuing Operations
Before Income Taxes 40 28 27
Capacity Utilization 95% 95% 85%
------------------------------------
Notes:
(1) Total revenues less operating costs, transportation and other.
(2) Operating profit divided by net sales.
[GRAPHIC OMITTED]
[Margin text: Chemicals contribution to income before taxes 2002 - 2004]
48
2004 VS 2003 - HIGHER CHEMICALS OPERATING PROFIT INCREASED NET INCOME BY $10
MILLION
Our chemicals business benefited from strong demand for bleaching chemicals in
North and South America. Solid North American demand for chlor-alkali and sodium
chlorate throughout 2004 resulted in strong pricing for our products. A stronger
Canadian dollar lowered our sales by $15 million in 2004, as most of our sales
are denominated in US dollars while our costs are primarily in Canadian dollars.
[GRAPHIC OMITTED]
[Margin text: Solid demand for bleaching chemicals resulted in strong prices for
our products in 2004.]
We successfully completed the expansion of our Brandon, Manitoba plant in
October, making it the largest sodium chlorate production facility in the world.
This expansion minimizes our exposure to the rising electricity costs faced in
other provinces, as Manitoba enjoys stable, regulated electricity markets. We
expect further margin and cash flow improvement in 2005 as we produce more of
our product from this low-cost plant.
At our Brazil plant, production improvements allowed us to take advantage of
strong market demand. We are changing our electricity source for our facilities
and expect to contract longer-term electricity supply for most of our
requirements. We expect lower annual electricity costs in 2005 when these
contracts are in place.
We are considering the sale of our chemicals business in 2005. Any such sale
would reduce contributions from this business to our 2005 net income.
2003 VS 2002 - LOWER CHEMICALS OPERATING PROFIT REDUCED NET INCOME BY $5 MILLION
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. A stronger Canadian
dollar lowered our operating profit by $13 million, as most of our sales are
denominated in US dollars.
Higher natural gas prices in North America put pressure on electricity costs. To
deal with these cost pressures, we idled our Taft plant, our highest electricity
cost facility, and relocated the assets to Brandon. Our cost savings from idling
the plant were offset by product we purchased from other suppliers to satisfy
southeastern US customers.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A) (1)
(Cdn$ millions) 2004 2003 2002
--------------------------------------------------------------------------------------------------------------------------
General and Administrative Expense before Stock Based Compensation 206 176 150
Stock Based Compensation (2) 93 14 2
-------------------------------------
Total General and Administrative Expense 299 190 152
=====================================
Notes:
(1) Includes G&A from discontinued operations. See Note 11 to our Consolidated
Financial Statements.
(2) Includes tandem option plan, stock options for our US-based employees and
stock appreciation rights.
2004 VS 2003 - HIGHER COSTS REDUCED NET INCOME BY $109 MILLION
During the second quarter, our shareholders approved modifying our stock option
plan to a tandem option plan, creating a one-time G&A expense of $82 million.
Our tandem option obligations are accrued on a graded vesting basis and
represent the difference between the market value of our common shares and the
exercise price of the options. These obligations are revalued each reporting
period based on the change in the market value of our common shares and the
number of graded vested options outstanding.
[GRAPHIC OMITTED]
[Margin text: Modifying our stock option plan to a tandem option plan added a
one-time $82 million charge to G&A in 2004.]
Other G&A costs include increased variable incentive compensation in light of
our record results, increased headcount due to increased capital investment, and
higher regulatory compliance costs, including costs associated with our
Sarbanes-Oxley internal control documentation project.
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.
Note:
(1) Includes dividends on preferred securities. See Note 1(r) to our
Consolidated Financial Statements.
2004 VS 2003 - LOWER INTEREST EXPENSE INCREASED NET INCOME BY $26 MILLION
In late-2003 and early-2004, we refinanced our preferred securities with lower-
cost debt. We also repaid US$225 million of bonds in February 2004. The
refinancing of our preferred securities and the repayment of the bonds reduced
interest expense in 2004.
[GRAPHIC OMITTED]
[Margin text: Our effective rate dropped to 6.6% as we refinanced our preferred
securities with lower-cost debt and repaid bonds. See page 53 for details on
our capital structure.]
In December 2004, we drew US$1.5 billion on our acquisition credit facilities to
assist the financing of our North Sea acquisition in the UK. This increased our
interest expense by $5 million.
The strong Canadian dollar lowered our US-dollar denominated interest expense by
$6 million.
We capitalized interest on our Syncrude Stage 3 expansion, the Long Lake Project
in Canada, our Block 51 development in Yemen and our Buzzard development in the
North Sea.
2003 VS 2002 - LOWER INTEREST EXPENSE ADDED $4 MILLION TO NET INCOME
The full year impact of our 30-year notes issued in March 2002, together with
the refinancing of our preferred securities with lower-cost debt in November
2003 and the impact of a strong Canadian dollar on our US-dollar denominated
interest expense kept our interest costs flat.
We capitalized interest on our Syncrude Stage 3 expansion and our Gunnison
development project in the Gulf of Mexico.
INCOME TAXES
(Cdn$ millions) 2004 2003 2002
--------------------------------------------------------------------------------
Current 248 214 207
Future 122 (73) (44)
---------------------------
Total Provision for Income Taxes 370 141 163
===========================
Effective Rate 32% 20% 31%
---------------------------
2004 VS 2003 - EFFECTIVE TAX RATE INCREASES FROM 20% TO 32%
In 2004, a 1% reduction in Alberta's corporate income tax rate resulted in a $15
million recovery of future income taxes. The low effective tax rate for 2003
resulted from reduced federal tax rates for Canadian resource activities which
generated a recovery of future income taxes of $76 million. The effective tax
rate for 2005 is expected to be 33%.
Most of our current income taxes are cash taxes paid in Yemen. In 2004, these
totalled $227 million (2003 - $201 million; 2002 - $207 million). In 2004 and
2003, federal and provincial capital taxes were payable in Canada. In both
years, current income taxes also include alternative minimum tax in the United
States.
[GRAPHIC OMITTED]
[Margin text: See page 102 for breakdown of income taxes. We estimate our 2005
tax rate to be consistent with 2004.]
2003 VS 2002 - EFFECTIVE TAX RATE DECLINES FROM 31% TO 20%
The low 2003 effective tax rate was due to reduced federal tax rates for
Canadian resource activities. This resulted in a recovery of future income taxes
of $76 million during the second quarter of 2003.
50
OTHER INCOME
(Cdn$ millions) 2004 2003 2002
--------------------------------------------------------------------------------
Unrealized Mark-to-Market Gains on WTI Put Options 56 -- --
Gains (Losses) on Disposition of Assets 24 -- (8)
Foreign Exchange Gains (Losses) (13) 6 (3)
Business Interruption Insurance Proceeds 10 12 -
Interest Income 12 9 7
Other 17 15 4
--------------------------
Total Other Income 106 42 --
==========================
We purchased WTI put options in the fourth quarter of 2004 to manage the
commodity price risk exposure on part of our oil production in 2005 and 2006.
These options are carried at fair value and an unrealized gain of $56 million
was recognized in the fourth quarter as WTI forward prices declined late in the
year.
[GRAPHIC OMITTED]
[Margin text: Unrealized mark-to-market gains on our put options make up
approximately 50% of other income. These options will be revalued quarterly.]
Gains on the disposition of assets in 2004 resulted from selling minor oil and
gas assets in Canada. There was no gain or loss on the 2003 sale of our
southeast Saskatchewan properties as described in Note 11 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. The business interruption insurance proceeds received in 2004 and 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.
Foreign exchange losses in 2004 mainly relate to the impact of a stronger
Canadian dollar on our US-dollar cash balances. Foreign exchange gains on our
US-dollar debt portfolio are not recognized in our net income as our US-dollar
debt has been designated as a hedge of our net investment in foreign operations.
These gains are recorded on our balance sheet as cumulative foreign currency
translation adjustments.
IMPACT OF FOREIGN EXCHANGE ON OPERATIONS
The strengthening Canadian dollar relative to the US dollar reduced cash flow
from operating activities by $200 million and our net income by $105 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 the Canadian dollar equivalent of this debt is
reduced with a strengthening Canadian dollar. We have designated our US-dollar
denominated debt as a hedge of our net investment in foreign operations. As a
result, unrealized foreign exchange gains on the translation of this debt are
not included in our net income. These unrealized gains are included as
cumulative foreign currency translation adjustments on our balance sheet. The
tax effect of unrealized foreign exchange gains on our US-dollar debt results in
a decrease to our future income tax assets. This decrease in our future income
tax assets is offset by a decrease to our cumulative translation adjustment
account.
[GRAPHIC OMITTED]
[Margin text: A stronger Canadian dollar negatively impacts our realized
commodity prices, and positively impacts our US-dollar denominated fixed-rate
debt, operating costs and capital expenditures.]
OUTLOOK FOR 2005
In 2005, we plan to invest approximately $2.6 billion in capital projects, an
increase of over $900 million compared to 2004, excluding acquisitions.
Approximately 20% of this capital will be directed toward sustaining production
and cash flow from our producing oil, gas and other assets in the short term.
The majority, however, will be invested in longer cycle-time growth
opportunities that we expect to begin contributing production and cash flow in
2006 and beyond. In 2005, our oil and gas capital program is expected to be
invested as follows:
o 65% in new growth development projects;
o 18% in core assets to maintain existing production levels; and
o 17% in new growth exploration projects.
Details of our 2005 capital investment program are included in the Capital
Investment section of the MD&A.
[GRAPHIC OMITTED]
[Margin text: See page 32 for details of our 2005 capital program.]
We plan to raise $1.5 billion in 2005 by selling assets which may include, among
other things, our chemicals business and certain conventional Canadian oil and
gas assets. The capital, cash flow and production guidance which follows does
not take into account any dispositions.
51
DAILY PRODUCTION
Approximately 20% of our cash flow from core assets will be reinvested in those
assets in 2005. This will deliver production before royalties of between 230,000
and 250,000 boe/d (170,000-185,000 after royalties) in 2005 before planned asset
sales.
2005 ESTIMATED PRODUCTION
---------------------------------------
(mboe/d) BEFORE ROYALTIES AFTER ROYALTIES
--------------------------------------------------------------------------------
Gulf of Mexico (1) 50 - 60 43 - 53
UK North Sea 14 - 18 14 - 18
Yemen 90 - 100 52 - 58
Canada (2) 52 - 56 40 - 44
Syncrude 16 - 18 16 - 17
Colombia 4 - 6 4 - 5
---------------------------------------
Total 230 - 250 170 - 185
=======================================
Notes:
(1) US natural gas production is estimated to comprise 46% of total US
equivalent production in 2005.
(2) Canadian natural gas production is estimated to comprise 44% of total
Canadian equivalent production in 2005.
[GRAPHIC OMITTED]
[Margin text: In 2005, we expect to modestly grow production after royalties and
generate over $2 billion in cash flow from operating activities.]
We expect our production after royalties to grow modestly in 2005, while we
continue to invest in major development projects which are expected to come on
stream in 2006 and beyond. Many of these have low or no royalties, lower costs
and ultimately higher margins and returns than our current producing assets.
This changing production mix is expected to improve profitability, even if oil
prices trend somewhat lower.
CASH FLOW AND SENSITIVITIES
We expect to generate over $2 billion in cash flow from operating activities in
2005 (before asset sales, site restoration and geological and geophysical
expenditures), assuming the following:
---------------------------------------------------------------------------
WTI (US$/bbl) 40.00
NYMEX natural gas (US$/mmbtu) 6.50
US to Canadian dollar exchange rate 0.80
We have purchased put options on 60,000 bbls/d of our oil production in both
2005 and 2006. These options establish an average WTI floor price for this
production of US$43.17/bbl in 2005 and US$38.17 in 2006. Changes in actual
commodity prices and exchange rates impact our annual cash flow from operating
activities as follows:
In addition to strong cash flow from our oil and gas operations, we expect
continued strong performance from our chemicals and marketing businesses in
2005. Our chemicals operations expect another year of solid stable cash flow and
net income as we continue to see strong demand and pricing for our products. Our
Brandon plant will provide lower cost operations. Our marketing group also
anticipates another profitable year as they continue to maximize the value of
their asset base.
[GRAPHIC OMITTED]
[Margin text: A US$1 change in WTI above $43/bbl will change cash flow from
operating activities by $50 million.]
52
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL STRUCTURE
(Cdn$ millions) 2004 2003
--------------------------------------------------------------------------------
NET DEBT (1)
Bank Debt 1,993 --
Public Senior Notes 1,813 2,214
------------------
Senior Debt 3,806 2,214
Subordinated Debt 553 594
Preferred Securities -- 281
------------------
Total Debt 4,359 3,089
Less: Cash and Cash Equivalents (74) (1,087)
Less: Non-Cash Working Capital (2) (66) (312)
------------------
TOTAL NET DEBT 4,219 1,690
==================
SHAREHOLDERS' EQUITY (3) 2,867 2,075
==================
Notes:
(1) Includes all of our debt and is calculated as long-term debt less net
working capital.
(2) Excludes current portion of long-term debt and short-term borrowings.
(3) At January 31, 2005, there were 129,415,565 common shares and US$460
million of unsecured subordinated securities outstanding. These
subordinated securities may be redeemed by issuing common shares at our
option after November 8, 2008. The number of shares issuable depends on the
common share price on the redemption date.
[GRAPHIC OMITTED]
[Margin text: Net debt is long-term debt less working capital. We use it to
monitor the strength of our balance sheet]
NET DEBT
We use net debt as a key indicator of our leverage levels and to monitor the
strength of our balance sheet. Our net debt levels are directly related to our
operating cash flows, our capital investment activities and disposition
programs. We ended the year with net debt at $4.2 billion, an increase of $2.5
billion over 2003 year-end levels. This reflects our North Sea acquisition on
December 1, 2004, which was financed with US$1.5 billion of debt and US$600
million of cash on hand. Changes in net debt related to:
(Cdn$ millions) 2004 2003
----------------------------------------------------------------------------------------
Capital Investment (including North Sea acquisition) 4,264 1,494
Cash Flow from Operating Activities (1,607) (1,405)
-----------------
Excess of Capital Investment over Cash Flow 2,657 89
Dividends on Common Shares 52 40
Proceeds on Disposition of Assets (34) (293)
Issue of Common Shares (primarily exercise of employee stock options) (124) (73)
Foreign Exchange Translation of US-Dollar Debt and Cash (78) (281)
Other 56 (240)
-----------------
Increase (Decrease) in Net Debt 2,529 (758)
=================
[GRAPHIC OMITTED]
[Margin text: We financed the North Sea acquisition with US$600 million in cash
and US$1.5 billion of debt.]
The increase in net debt has impacted our leverage metrics:
(times) 2004 2003 2002
----------------------------------------------------------------------------------------
Net Debt to Cash Flow from Operating Activities 2.6 1.2 2.0
Interest Coverage (1) 11.9 10.1 7.9
--------------------------
Note:
(1) Earnings before interest, taxes, DD&A and exploration expense divided by
interest expense (before capitalized interest).
Our business strategy is focused on value-based growth through full-cycle
exploration and development, supplemented by strategic acquisitions when
appropriate. To grow our company, we used leverage to develop the Masila project
in Yemen in 1993, acquire Wascana in 1997 and acquire the remaining interest in
Aspen in 2002. Each time, we exceeded our internal net debt to cash flow target
band, however, we successfully brought our leverage back down once these
projects began generating cash flow. In 2004, we again elevated our leverage
levels as a result of our North Sea acquisition. We plan to sell $1.5 billion of
assets in 2005 to reduce our leverage. Leverage is expected to be reduced
further when our Buzzard and Long Lake projects come on stream and contribute
cash flow in 2006 and 2007.
53
CHANGE IN WORKING CAPITAL
INCREASE/
(Cdn$ millions) 2004 2003 (DECREASE)
-----------------------------------------------------------------------------------------------
Cash and Cash Equivalents 74 1,087 (1,013)
Accounts Receivable 2,136 1,423 713
Inventories and Supplies 351 270 81
Accounts Payable and Accrued Liabilities (2,416) (1,404) (1,012)
Other (5) 23 (28)
-----------------------------------
140 1,399 (1,259)
===================================
Cash and cash equivalents decreased by over $1 billion during the year as we:
o repaid US$225 million of senior debt in February;
o redeemed US$217 million of preferred securities in February; and
o paid US$600 million relating to our North Sea acquisition.
Accounts receivable and accounts payable increased, reflecting higher commodity
prices and increased activity for our gas marketing business. We also acquired
accounts receivable and accounts payable as part of our North Sea acquisition.
Capital accruals were higher at year-end from our Buzzard and Long Lake
development projects, and as a result of increased exploration activity in the
Gulf of Mexico. Inventory levels in the marketing group were up at year-end
given higher activity during the last part of 2004.
[GRAPHIC OMITTED]
[Margin text: Increased payables and receivables reflect higher commodity prices
and increased activity for our gas marketing business.]
LIQUIDITY
We generally 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. Given the long cycle-time of some
of our development projects and the volatility of commodity prices, it is not
unusual, in any given year, for capital expenditures to exceed our cash flow.
When this happens, we draw on available credit facilities, as we maintain
significant undrawn committed credit facilities. From time to time, we access
the capital markets to meet our financing needs. We also use various financial
instruments to minimize our exposure to fluctuations in foreign exchange and
commodity prices. For example, we purchased WTI put options for 2005 and 2006 to
mitigate liquidity risk and reduce cash flow volatility. Overall, we manage our
capital structure to maintain flexibility so we can fund our capital programs
throughout the highs and lows of the price cycles inherent in the oil and gas
business.
[GRAPHIC OMITTED]
[Margin text: We manage our capital structure to maintain flexibility so we can
fund our capital program through the commodity price cycles.]
The following table shows how we use our cash flow from operating activities to
fund our investing activities. When our operating cash flows exceed our
investment requirements, we generally pay down debt. We generally borrow to fund
investment requirements in excess of our operating cash flows.
In 2000, strong commodity prices allowed us to generate sufficient cash flow to
buy back 20 million common shares. In 2001 and 2002, we began to invest
significantly in two deep-water Gulf of Mexico projects (Aspen and Gunnison),
our Syncrude expansion and our Long Lake project. In 2001, we used our cash flow
and in 2002, we accessed the public debt markets to fund this investment
activity. In 2003, Aspen contributed significantly to our cash flow and in
late-2003, we pre-funded debt repayments by raising over $1 billion in senior
and subordinated debt. We used these funds in 2004 to repay higher cost debt,
and coupled with our acquisition credit facilities, acquired the North Sea
assets.
54
FUTURE LIQUIDITY
Our future liquidity is primarily dependent on cash flows generated from our
operations, our capital programs and the flexibility of our capital structure.
Assuming WTI of US$40/bbl in 2005, we expect our 2005 capital investment program
and dividend requirements to exceed our cash flow by almost $600 million. We are
planning to raise $1.5 billion from asset dispositions in 2005 and we expect to
use the proceeds to fund the shortfall and to retire debt.
Our cash flow is sensitive to changes in commodity prices and exchange rates.
For 2005, we expect to generate cash flow of over $2.0 billion (before asset
sales, remediation and geological and geophysical expenditures) assuming the
following:
--------------------------------------------------------------------------
WTI (US$/bbl) 40.00
NYMEX natural gas (US$/mmbtu) 6.50
US to Canadian dollar exchange rate 0.80
Changes in commodity prices and exchange rates will impact our cash flow and our
borrowing requirements. The impact of a variance in any one of the above
assumptions on our cash flow is described in the Outlook for 2005 section of the
MD&A.
[GRAPHIC OMITTED]
[Margin text: See page 52 for our commodity price and foreign exchange
sensitivities.]
We are in the midst of developing a number of major projects. Much of our
planned capital spending over the next three years will be allocated to Long
Lake, the Buzzard project in the North Sea and Syncrude Stage 3.
Our anticipated spending on these projects in 2005, 2006 and 2007 is as follows:
(Cdn$ millions)
---------------------------------------------------------------------------
2005 1,388
2006 1,125
2007 415
-------
Total Capital Investment 2,928
=======
Given our reliance on cash flows to fund these projects, we executed a cash flow
protection strategy using WTI crude oil put options in late-2004. These put
options provide us with an annual average WTI floor price of US$43.17/bbl in
2005 and US$38.17 in 2006 on 60,000 bbls of oil per day each year. This strategy
reduces the downside risk to our future cash flows in 2005 and 2006 when our
capital requirements are high, yet still allows us to realize price upside.
[GRAPHIC OMITTED]
[Margin text: Our put options reduce downside price risk in 2005 and 2006 yet
enable us to realize price upside.]
Our Buzzard project creates foreign currency exposure as a portion of the
capital costs are denominated in British pounds and Euros. In order to reduce
our exposure to fluctuations in these currencies, we purchased foreign currency
call options in early 2005 which effectively set a ceiling on most of our
British pound and Euro spending exposure from March 2005 through to the end of
2006.
While these development projects lack exploration risk, they are subject to
execution risk, the risk of higher than anticipated spending or delayed
start-up. We minimize the financial impact of these risks by maintaining undrawn
committed credit facilities. These facilities extend beyond the expected
start-up dates of our Syncrude expansion, our Long Lake project and the Buzzard
development. Undrawn amounts on these facilities at December 31, 2004 were
almost $1.6 billion. We also have a committed credit facility available until
late-2007 which may be used to finance the development and operation of our
North Sea assets including Buzzard. At December 31, 2004, US$500 million was
available on this facility.
In addition to our operating cash flows and our sizeable undrawn committed
credit facilities, we have a US$1 billion shelf registration available in the US
and Canada to allow us to access the debt capital markets.
[GRAPHIC OMITTED]
[Margin text: If required, we have more than $2 billion in undrawn credit
facilities and a US$1 billion shelf registration in the US and Canada to access
debt markets.]
55
At December 31, 2004, the average term to maturity of our long-term debt was
11.9 years. We have the following debt maturities in the next five years:
Note:
(1) Undrawn amounts of $0.4 billion available until 2008 and $1.2 billion
available until 2009.
We may retire our debt maturities with a portion of the proceeds from planned
asset sales or we may refinance the maturities with longer term debt. In
addition, we have sufficient capacity on our term credit facilities to refinance
a portion of these maturities, if need be.
In light of our cash flow streams, our commodity price and foreign exchange
hedging strategies and our current levels of liquidity, we expect to have no
difficulties funding our planned capital programs, dividend requirements and
debt repayments or in meeting the obligations that arise from our day-to-day
operations.
In 2004, we declared common share dividends of $0.40 per common share (2003 -
$0.325, 2002 - $0.30). We expect to declare common share dividends of $0.40 per
common share in 2005.
[GRAPHIC OMITTED]
[We expect to declare common share dividends of $0.40 per common share in 2005.]
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We assume various contractual obligations and commitments in the normal course
of our operations and financing activities. These obligations and commitments
are considered in assessing our cash requirements, as noted in the above
discussion of future liquidity. They include:
(Cdn$ millions) PAYMENTS
-----------------------------------------------------------------------------------------------------------------
(less than) (more than)
Total 1 year 1-3 years 4-5 years 5 years
--------------------------------------------------------------
Short and Long-Term Debt 4,359 1,003 1,168 190 1,998
Interest on Short and Long-Term Debt 3,789 221 401 278 2,889
Operating Leases (1) 248 31 53 45 119
Energy Commodity Contracts 175 129 42 4 --
Transportation and Storage Commitments (1) 780 366 200 84 130
Work Commitments and Purchase Obligations (2) 1,794 958 832 4 --
Asset Retirement Obligations 770 47 32 42 649
Other 5 1 1 1 2
--------------------------------------------------------------
Total 11,920 2,756 2,729 648 5,787
==============================================================
Notes:
(1) Payments for operating leases and transportation commitments are deducted
from our cash flow from operating activities.
(2) The vast majority of these payments relate to work commitments cancellable
at our option without penalties or additional fees.
Contractual obligations can be financial or non-financial. Financial obligations
are known future cash payments that we must make under existing contracts, such
as debt and lease arrangements. Non-financial obligations are contractual
obligations to perform specified activities such as work commitments. Commercial
commitments are contingent obligations that become payable only if certain
pre-defined events occur.
o Short and long-term debt amounts are included on our December 31, 2004
Consolidated Balance Sheet.
o Operating leases include the minimum lease payment obligations associated
with leases for office space, rail cars, vehicles 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 2005, Shell has elected to take payment in kind so the 2005
obligation has been excluded from this table. Instead, it is shown as a
royalty and excluded from reserves and production.
o Energy commodity contracts include the purchase and sale of physical
quantities of oil and natural gas, and financial derivatives used to manage
our exposure to commodity prices. For contracts where the price is based on
an index, the amount is based on forward market prices at December 31,
2004. For certain contracts, we may net settle rather than pay cash.
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.
[GRAPHIC OMITTED]
[Margin text: Our long-term debt accounts for almost 70% of our contractual
obligations and commitments.]
56
o Work commitments include non-discretionary capital spending related to
drilling, seismic, construction of facilities and other development
commitments in our international operations, at Long Lake ($274 million),
the Buzzard project in the North Sea ($1 billion) and at Block 51 ($189
million). The timing of certain payments is difficult to determine with
certainty. The table has been prepared using our best estimates; the
remainder of our 2005 capital investment is discretionary.
o We have $770 million of undiscounted asset retirement obligations. As of
December 31, 2004, the estimated fair value ($468 million) of these
obligations has been provided for in our consolidated financial statements
(including $47 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 $46 million and our share of Syncrude's
unfunded obligation is $41 million. Our $46 million obligation includes $34
million that is unfunded as a result of statutory limitations. These
obligations are backed by irrevocable letters of credit. During 2004, we
contributed $6 million to our defined benefit pension plan. We currently
are not anticipating any funding requirements in 2005 for our defined
benefit pension plan.
o We have excluded our unvested obligations on our stock option and stock
appreciation rights programs as the amount and timing of the cash payments
are indeterminable.
o We have excluded our normal purchase arrangements as they are discretionary
and are reflected in our expected cash flow from operating activities and
our capital expenditures for 2005.
o We have excluded our future income tax liabilities as the amount and timing
of any cash payments for income taxes are based primarily on taxable income
for each discrete fiscal year in the various jurisdictions in which we
operate.
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, therefore, 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 (S&P), Baa2 by
Moody's Investor Service, Inc. and BBB by Dominion Bond Rating Service (DBRS).
In addition, S&P currently rates our outlook as stable while Moody's and DBRS
have a negative outlook. 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 group enters into often include
financial assurance provisions that allow Nexen and our counterparties to
effectively manage credit risk. The agreements normally require posting
collateral 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, 2004, we would be required to post collateral
of approximately $780 million if we were downgraded to non-investment grade.
These obligations are reflected on our balance sheet. The posting of collateral
merely accelerates the payment of such amounts. Our committed undrawn credit
facilities available for general corporate purposes of $1.6 billion adequately
cover any potential collateral requirements. Just as we may be required to post
collateral in the event of a downgrade below investment grade, we have similar
provisions in many of our contracts that allow us to demand certain
counterparties post collateral with us if they are downgraded to non-investment
grade.
OFF-BALANCE SHEET ARRANGEMENTS
None.
CONTINGENCIES
We have no contingencies that would have a material adverse effect on our
liquidity, consolidated financial position or results of operations. See Note 12
to the Consolidated Financial Statements in Item 8, which is incorporated herein
by reference for a discussion of our contingencies.
57
BUSINESS RISK MANAGEMENT
Our operations are exposed to various risks, some of which are common to others
in our industry and some of which are unique to our operations. We attempt to
mitigate the risks to an acceptable level but many of these risks are beyond our
control so we cannot provide any assurances that they will not result in
negative financial consequences.
COMPETITION
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 petroleum industry also competes
with other industries in supplying energy, fuel and related products to
customers.
The pulp and paper chemicals market is also highly competitive. Key success
factors are:
o price;
o 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.
Competitive forces may result in shortages of prospects to drill, services to
carry out exploration, development or operating activities, and infrastructure
to produce and transport production. It may also result in an oversupply of
crude oil and natural gas. Each of these factors could have a negative impact on
costs and prices and, therefore, our financial results.
OPERATIONAL RISKS
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; and
o environmental risks.
We operate two facilities that are located in close proximity to populated
areas, and each processes materials of potential harm to the local populations.
At Balzac, just north of Calgary, we operate a gas plant that processes sour
gas. In North Vancouver, we operate a chlor-alkali plant that produces chlorine.
We have undertaken several initiatives to mitigate the potential risks
associated with these operations. First, we have instituted operating procedures
that have allowed each to be verified as Responsible Care(R) facilities by the
Canadian Chemical Producers Association, with our Balzac plant being the first
oil and gas facility in the world to be so certified. Also, at North Vancouver,
we conducted extensive quantified risk analysis complying with guidelines of the
Major Industrial Accidents Council of Canada (MIACC). As a result, substantial
changes to operating and inventory practices were implemented. The risk is now
consistent with Responsible Care(R) and MIACC guidelines. Also, at both
facilities, we work with surrounding communities to keep them informed of our
operations and have invited them to tour our facilities. Finally, we continually
work with local municipalities to maintain appropriate emergency response and
evacuation plans in the event of an accidental release of chemicals from the
facilities.
Although we maintain insurance according to customary industry practice, we may
not be fully insured against all of these risks. Losses resulting from the
occurrence of these risks may have a material adverse impact on our financial
results.
OFFSHORE OPERATIONS
Offshore operations are subject to a variety of operating risks peculiar to the
marine environment, such as damage or loss from hurricanes or other adverse
weather conditions. These conditions can cause substantial damage to facilities
and interrupt production. When possible, we take precautionary measures of
temporarily shutting-in production, de-manning facilities and ceasing drilling
operations. We carry insurance to compensate us for physical damage and business
interruption, subject to normal deductions, resulting from such weather
conditions.
Our operations in the Gulf of Mexico have been suspended, from time to time, due
to hurricanes or tropical storms. While operations are generally restored
quickly and production losses are not material, we have had one instance in the
last five years where production was suspended for an extended period of time
and substantial damage to facilities was incurred. In 2002, our facilities at
Eugene Island 295 were damaged during Hurricane Lili. Production from this field
was suspended for about four months while temporary production facilities were
put in place. During this period, production volumes were reduced by
approximately 2,500 boe/d. Production was restored at a reduced rate through
temporary facilities for approximately six months while installation of new
permanent facilities was completed. It is estimated that volumes were reduced by
approximately 1,800 boe/d during this period. There was no significant financial
impact after business interruption and property insurance claims.
58
UNCERTAINTY OF RESERVES ESTIMATES
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 through exploration, acquisition
or development activities, our reserves and production will decline over time as
reserves are produced. The business of exploring for, developing or acquiring
reserves is capital intensive. To the extent cash flows from operations are
insufficient and external sources of capital become limited or unavailable, our
ability to make the necessary capital investments to maintain and expand our oil
and natural gas reserves will be impaired.
Over the past three years, we experienced net negative revisions of 337 million
boe to our proved reserves (including Syncrude and before royalties). This
includes 239 million boe related to changes in year-end prices, of which 246
million boe relates to the write-off of the reserves at our Long Lake oil sands
project as a result of low bitumen prices at the end of 2004. Positive price
revisions of 7 million boe related primarily to our Canadian heavy oil
properties. The remaining negative revisions of 98 million boe, representing
about 12% of worldwide proved reserves, occurred primarily on our producing
properties in Canada and Yemen. In Canada, the majority of the negative
revisions of 64 million boe occurred in 2003 as result of an ongoing assessment
of the future production profiles of our properties and a reduction of proved
undeveloped reserves based on drilling results and updated geological mapping.
In Yemen, the negative revisions of 37 million boe occurred largely in 2003 and
2004 and resulted primarily from lower-than-expected production performance,
drilling results and updated geological mapping.
About two-thirds of the 98 million boe of net negative revisions were recognized
as proved reserves based on projected future production performance of producing
properties. These projections considered historical performance and expected
future changes in production using all available engineering and geological
data. However, subsequent production performance did not meet our projections
due to such factors as sand production, steeper than expected declines due to
higher water cuts and the drilling of some infill locations which proved to have
already been swept. The remainder of the reserves were recognized as proved
undeveloped reserves based on production performance, well control and geologic
mapping using seismic and other data. Lower than expected production, greater
sweep efficiencies, and unsuccessful drilling caused us to revise our proved
reserves estimates downward.
Under SEC rules, we recognize our oil sands as bituman reserves. As a result, we
expect price-related revisions, both positive and negative, to occur in the
future as the economic producibility of our bitumen and heavy oil reserves are
sensitive to year-end prices. In particular, since we recognize our oil sands as
bitumen reserves and they are related to one project, all or none of the
reserves will likely be considered economic depending on the year-end prices of
bitumen, diluent and natural gas. The impact of year-end prices on our heavy oil
reserves is expected to be immaterial.
INCREASED LEVERAGE
Our overall indebtedness has increased as a result of acquiring the North Sea
assets. Additional borrowings may be necessary to fund the field development
plan for the Buzzard field as well as for the development of the Long Lake
project. While we believe that our overall indebtedness can be reduced through
proceeds from the disposition of non-core assets, no assurance can be given that
we will be able to implement such transactions.
HEAVY OIL OPERATIONS
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 and gas, as a smaller
percentage of high-value petroleum products can be refined from heavy oil. As a
result, our heavy oil operations are exposed to the following risks:
o additional costs may be incurred to purchase diluent to transport heavy
oil;
o there could be a shortfall in the supply of diluent which may cause its
price to increase; and
o the market for heavy oil is more limited than for light oil making it more
susceptible to supply and demand fundamentals which may cause the price to
decline.
Any one or combination of these factors could cause some of our heavy oil
properties to become uneconomic to produce and/or result in negative reserve
revisions.
Additional risk factors relating to our Long Lake oil sands project are provided
under "Risk Factors Relating to Long Lake".
RISK FACTORS RELATING TO LONG LAKE
Our Long Lake Project is planned as a fully integrated production, upgrading and
co-generation facility. We intend to use Steam Assisted Gravity Drainage (SAGD)
technology to recover bitumen from oil sands. As designed, the bitumen will be
partially upgraded using the proprietary OrCrude(TM) process, followed by
conventional hydrocracking to produce a sweet, premium synthetic crude oil. The
OrCrude(TM) process also yields liquid asphaltines that will be gasified into a
syngas. This syngas will be used as a fuel source for the SAGD process, a source
of hydrogen for use in the upgrading process, and to generate electricity
through a co-generation facility.
We have a 50% working interest in this project, and our share of the
construction cost is estimated to be $1.75 billion ($3.5 billion gross). Given
the higher initial investment and operating costs to produce and upgrade
bitumen, the payout period for the project is longer and the economic return is
lower than a conventional light oil project with an equal volume of reserves.
59
Risks associated with our Long Lake oil sands project include the following:
STATUS OF THE LONG LAKE PROJECT
The Long Lake Project is currently in the construction stage. There is a risk
that actual costs may be higher than expected or that the project may not be
completed on time or at all due to many factors, including:
o construction performance falling below expected levels of output or
efficiency;
o labour disputes, disruptions or declines in productivity;
o increases in materials or labour costs;
o inability to attract sufficient numbers of qualified workers;
o design errors;
o contractor or operator errors;
o non-performance by third-party contractors;
o changes in project scope;
o delays in obtaining, or conditions imposed by, regulatory approvals;
o breakdown or failure of equipment or processes;
o violation of permit requirements;
o catastrophic events such as fires, earthquakes, storms or explosions; and
o disruption in the supply of energy.
Actual costs to construct and develop the project will vary from our estimates,
and such variances may be significant. Our estimate of the cost associated with
developing the Long Lake Project has been developed with an expected range of
accuracy of approximately +/- 15%. In the formative stage of the project, our
capital cost estimate was approximately $2.3 billion (gross). After completing
further project definition, engineering and reviewing pilot results, we changed
the scope of the project to include co-generation facilities, planned for
certain redundancies within the upgrader, and applied more conservative
estimates to labour productivity. As a result, the capital cost estimate at the
time of our Board's sanctioning the project in February 2004 was $3.4 billion
(gross). Our current capital cost estimate for completing the project is $3.5
billion (gross) reflecting the acceleration of drilling of an additional well
pad consisting of 13 well pairs to ensure certainty and reliability of bitumen
production at the commencement of upgrader operations.
SAGD BITUMEN RECOVERY PROCESS
SAGD has been used in Western Canada to increase recoveries from conventional
heavy oil reservoirs for over a decade. However, application of SAGD to the
in-situ recovery of bitumen from oil sands is relatively new. Most of the SAGD
oil sands applications to date have been pilot projects and the process is in
the early stages of application in commercial oil sands projects.
Our estimates for performance and recoverable volumes for the Long Lake Project
are based primarily on our three well-pair SAGD pilot and industry performance
from SAGD operations in the McMurray formation in the Athabasca oilsands. Using
this data, our assumptions included average well-pair productivity of 900 bbls/d
of bitumen and a steam-to-oil ratio of 2.5. We commenced steaming the reservoir
for our SAGD pilot in May 2003 and commenced production in September 2003. The
pilot is currently producing at a rate of about 600 barrels of bitumen per day
per well-pair and a steam-to-oil ratio of about 3.5. Since September 2003, the
pilot has recovered less than 2% of the original bitumen in place. While we
expect actual performance to improve as the steam chamber grows in the
reservoir, there can be no assurance that our SAGD operation will produce
bitumen at the expected levels or steam-to-oil ratio. If the assumed production
rates or steam-to-oil ratio are not achieved, we might have to drill additional
wells to maintain optimal production levels, construct additional steam
generating capacity and/or purchase natural gas for additional steam generation.
These could have a significant adverse impact on the future activities and
economic return of the Long Lake Project.
BITUMEN UPGRADING PROCESS
The proprietary OrCrude(TM) process we are using to upgrade raw bitumen to
synthetic crude will be the first commercial application of the process although
we have operated it in a 500 bbls/d demonstration plant. All the individual
components of the technology used in this process, are currently used in
commercial applications around the world, however, there can be no assurance
that the commercial upgrader being constructed at Long Lake will achieve the
same or similar results as the demonstration plant or the results which are
forecast. If we are unable to upgrade the bitumen for any reason we may decide
to sell it as bitumen without upgrading it, which would expose us to the
following risks:
o the market for bitumen is limited;
o additional costs would be incurred to purchase diluent for blending and
transporting bitumen;
o there could be a shortfall in the supply of diluent which may cause its
price to increase;
o the market price for bitumen is relatively low reflecting its quality
differential; and
o additional costs would be incurred to purchase natural gas for use in
generating steam for the SAGD process since we would not be producing
syngas from the upgrading process.
These factors could have a significant adverse impact on the future activities
and returns of the Long Lake Project.
If any of these factors arise, our operating costs would increase and our
revenues would decrease from those we have assumed. This would cause a material
decrease in expected earnings from the project and the project may not be
profitable under these conditions.
60
At December 31, 2004, a shortage of diluent caused the price of diluent products
to rise substantially above prices seen in the past. These conditions could be
repeated in the future as the demand for diluents increases with the expected
increase in production of bitumen from the Canadian oil sands.
DEPENDENCE ON OPTI CANADA
We are undertaking the Long Lake Project jointly with OPTI Canada (OPTI)
pursuant to a joint venture agreement governing the construction, ownership and
joint operation of the project. The agreement provides for the creation of a
management committee that is responsible for the supervision and direction of
the management and operation of the project, the supervision and control of the
operators and all other matters relating to the development of the project. If
our interest in any element of the project falls below 25%, OPTI may be able to
make decisions respecting that element without our input, which may adversely
affect our operations.
DEPENDENCE UPON PROPRIETARY TECHNOLOGY
The success of the project and our investment in the project depends to a
significant extent on the proprietary technology of OPTI and proprietary
technology of third parties that has been, or is required to be, licensed by
OPTI. OPTI currently relies on intellectual property rights and other
contractual or proprietary rights, including (without limitation) copyright,
trademark laws, trade secrets, confidentiality procedures, contractual
provisions, licenses and patents, to secure the rights to utilize its
proprietary technology and the proprietary technology of third parties. OPTI may
have to engage in litigation in order to protect the validity of its patents or
other intellectual property rights, or to determine the validity or scope of the
patents or proprietary rights of third parties. This kind of litigation can be
time-consuming and expensive, regardless of whether or not OPTI is successful.
The process of seeking patent protection can itself be long and expensive, and
there can be no assurance that any currently pending or future patent
applications of OPTI or such third parties will actually result in issued
patents, or that, even if patents are issued, they will be of sufficient scope
or strength to provide meaningful protection or any commercial advantage to
OPTI. Furthermore, others may develop technologies that are similar or superior
to the technology of OPTI or such third parties or design around the patents
owned by OPTI and/or such third parties. There is also a risk that OPTI may not
be able to enter into licensing arrangements with third parties for the
additional technologies required for the possible further expansion of the Long
Lake upgrader.
OPERATIONAL HAZARDS
The operation of the project will be subject to the customary hazards of
recovering, transporting and processing hydrocarbons, such as fires, explosions,
gaseous leaks, migration of harmful substances, blowouts and oil spills. A
casualty occurrence might result in the loss of equipment or life, as well as
injury or property damage. We may not carry insurance with respect to all
potential casualty occurrences and disruptions. It cannot be assured that our
insurance will be sufficient to cover any such casualty occurrences or
disruptions. The project could be interrupted by natural disasters or other
events beyond our control. Losses and liabilities arising from uninsured or
under-insured events could have a material adverse effect on the project and on
our business, financial condition and results of operations.
Recovering bitumen from oil sands and upgrading the recovered bitumen into
synthetic crude oil and other products involve particular risks and
uncertainties. The project is susceptible to loss of production, slowdowns, or
restrictions on its ability to produce higher value products due to the
interdependence of its component systems. Severe climatic conditions can cause
reduced production and in some situations result in higher costs. SAGD bitumen
recovery facilities and development and expansion of production can entail
significant capital outlays. The costs associated with synthetic crude oil
production are largely fixed and, as a result, operating costs per unit are
largely dependent on levels of production.
The Long Lake SAGD operation and upgrader will process large volumes of
hydrocarbons at high-pressure and at high temperatures and will handle large
volumes of high pressure steam. Equipment failures could result in damage to the
project's facilities and liability to third parties against which we may not be
able to fully insure or may elect not to insure because of high premium costs or
for other reasons.
Certain components of the Long Lake Project will produce sour gas, which is gas
containing hydrogen sulphide (H2S). Sour gas is a colourless, corrosive gas that
is toxic at relatively low levels to plants and animals, including humans. The
project will include integrated facilities for handling and treating the sour
gas, including the use of gas sweetening units, sulphur recovery systems and
emergency flaring systems. Failures or leaks from these systems or other
exposure to sour gas produced as part of the project could result in damage to
other equipment, liability to third parties, adverse effect to humans, animals
and the environment, or the shut down of operations.
The Long Lake Project will produce carbon dioxide emissions. Carbon dioxide is a
greenhouse gas that will be regulated by the Kyoto Protocol, which is expected
to come into effect in Canada in 2008. We will be required to purchase carbon
dioxide credits in connection with these emissions, which we have budgeted at
approximately $0.20/bbl of oil produced. If the cost of carbon dioxide credits
reaches the Canadian cap, our actual cost would increase to approximately
$0.40/bbl of oil produced.
ABORIGINAL CLAIMS
Aboriginal peoples have claimed aboriginal title and rights to a substantial
portion of Western Canada. Certain aboriginal peoples have filed a claim against
the Government of Canada, the Province of Alberta, certain governmental entities
and the regional municipality of Wood Buffalo (which includes the city of Fort
McMurray, Alberta) claiming, among other things, aboriginal title to large areas
of lands surrounding Fort McMurray, including the lands on which the project and
most of the other oil sands operations in Alberta are located. Such claims, if
successful, could have a significant adverse effect on the project and on us.
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COMPETITION
The Canadian and international petroleum industry is highly competitive in all
aspects, including the exploration for, and the development of, new sources of
supply, the acquisition of oil interests and the distribution and marketing of
petroleum products. The Long Lake Project competes with other producers of
synthetic crude oil blends and other producers of conventional crude oil. Some
of the conventional producers have lower operating costs than the project is
anticipated to have. The petroleum industry also competes with other industries
in supplying energy, fuel and related products to consumers.
A number of companies other than OPTI and us have announced plans to enter the
oil sands business and begin production of synthetic crude oil, or expand
existing operations. Expansion of existing operations and development of new
projects could materially increase the supply of synthetic crude oil and other
competing crude oil products in the marketplace. Depending on the levels of
future demand, increased supplies could have a negative impact on prices.
CONCENTRATION OF PRODUCING ASSETS
A portion of our production is generated from highly productive individual wells
or central production facilities. Examples include:
o central processing facility, oil pipeline, and export terminal at our Yemen
operations;
o Gunnison SPAR production platform in the Gulf of Mexico;
o highly productive Aspen wells tied-in to a third-party processing facility
in the Gulf of Mexico; and
o Scott production platform in the North Sea.
As significant production is generated from each of these assets, any single
event causing an interruption to these operations could result in the loss of
production. We carry insurance to compensate us for physical damage and business
interruption arising from most circumstances but it does not provide for losses
arising from equipment failures.
COAL BED METHANE
Coal bed methane (CBM) is commonly referred to as an unconventional form of
natural gas because it is primarily stored through adsorption by 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 generally needs to be extracted to reduce the pressure and
allow gas production to occur. CBM wells typically have lower producing rates
and reserves per well than conventional gas wells, although this varies by area.
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.
We are testing the feasibility of gas production from the Mannville coals in the
Fort Assiniboine region of Alberta. These coals are deeper than other producing
CBM projects and are water saturated. These projects require significant
up-front capital investment in the form of land acquisition and drilling and
completion costs. A significant period of time may be required to sufficiently
de-water the coals to determine if commercial production is feasible. As a
result, we may have to invest significant capital in CBM assets before they
achieve commercial rates of production. The wells may never achieve commercial
rates of production as there are no commercially proven Mannville CBM projects
in operation.
CBM projects in some areas of the United States have had negative public
reaction due to certain water disposal practices. In Canada, as in the United
States, water disposal practices are regulated to ensure public safety and water
conservation. Nevertheless, negative public perception around CBM production
could impede our access to the resource.
COMMITMENTS TO PROJECTS UNDER DEVELOPMENT
We have significant commitments in connection with various development
activities currently underway. The Syncrude Stage 3 expansion is currently 74%
complete and is expected to commence production in mid-2006. Development and
construction activities on the Buzzard field are approximately 60% complete and
is expected to commence production in late-2006. Detailed project engineering on
our Long Lake SAGD and upgrading project near Fort McMurray, Alberta is
currently approximately 60% complete. Bitumen production from the Long Lake
Project is expected to be achieved in the second half of 2006 and the first
commercial production of upgraded synthetic crude oil is expected to be achieved
in mid-2007. Our combined capital commitments for these projects are anticipated
to be $1,388 million in 2005 and $1,125 million in 2006. In these projects, we
are exposed to the possibility of cost overruns, which may be significant,
and/or delays in commencement of commercial production.
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 against these risks and the related financial
consequences.
In particular, our operations in Yemen expose us to potential material adverse
financial consequences. In 2004, Yemen accounted for $415 million or 52% of our
net income and this is expected to decline somewhat in 2005 as production
declines on Masila are partially offset by production from completion of
development activities on Block 51.
62
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 citizens 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 15 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.
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, 2004, $468 million ($770 million, undiscounted) has been
provided in the Consolidated Financial Statements for future asset
retirement costs, relating to our oil and gas, Syncrude and chemicals
facilities.
o During 2004, we increased our asset retirement obligations by $146 million
(2003 - $6 million) to reflect new obligations incurred or acquired.
o Actual site remediation expenditures for the year were $31 million (2003 -
$20 million). We anticipate actual site remediation expenditures in 2005 to
approximate $47 million primarily in Australia and Nigeria.
o We perform periodic internal and external assessments of our operations and
adjust our estimates and retirement obligations accordingly.
o During 2002, we conducted an external audit of our management systems for
safety, environment and social responsibility issues. Overall, the review
was positive and the few minor recommendations for improvement were
implemented.
o During 2003 and 2004, we conducted an external operational audit and
confirmed that our management systems for safety, environment and social
responsibility issues were being followed.
CLIMATE CHANGE
The Kyoto Protocol comes into force on February 16, 2005 following Russia's
delivery of its ratification instrument on November 18, 2004. Canada had
previously ratified the Kyoto Protocol in December 2002. Canada committed in
Kyoto in 1997 to an emission reduction of 6% below 1990 levels during the First
Commitment period (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 associated with
ratification and implementation of the Kyoto Protocol by providing the oil and
gas sector with limits on cost (a cap of $15/tonne) and volume (a cap of 55
megatonnes for large industrial emitters) as well as its position on long-term,
high capital-cost projects. In addition, emission reductions for oil and gas
producers are expected to be capped at levels that are 15% lower than business
as usual levels. 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 remains 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 Green House Gas
(GHG)-related legislation should not adversely affect the development of new
energy projects such as the oil sands.
For years, we have been assessing the impact of climate change developments on
our various business interests. 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. As well, we continue
to work closely with the Canadian and Alberta governments to assess the impact
of domestic regulatory options and provide information on our business to assist
governments in their policy deliberations. We maintain a wide range of business
contacts to ensure that a full slate of options is available to us in order to
meet the obligations that may be imposed by future legislation.
63
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. We have voluntarily reduced direct GHG emissions by
almost two 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.
We have entered into discussions with the management of several GHG investment
pools and we continue to evaluate the opportunities associated with biological
and geological sequestration of (CO2) and the capture of methane from landfills.
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 policy and requirements with respect to GHG when conducting these
reviews.
We are committed to the principles of full disclosure and we 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. Any indirect risks and
liabilities attributable to GHG are too remote and unquantifiable at this time.
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.
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 prepare our estimates. However, 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.
Management is responsible for estimating the quantities of proved oil and
natural gas reserves and for 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. An Executive Reserves Committee,
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 this 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 are resolved when the
differences are greater than 10%.
64
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-estimated 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.
Reserves 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 2004, $125 million of our
total $175 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 $33 million after tax.
o Calculating our unit-of-production depletion rates. Both proved and proved
developed reserve (1) estimates are used to determine rates that are
applied to each unit-of-production in calculating our depletion expense.
Proved reserves are used where a property is acquired and proved developed
reserves are used where a property is drilled and developed. In 2004, oil
and gas depletion of $541 million was recorded in depletion, depreciation,
amortization and impairment expense. If our reserves estimates changed by
10%, our depletion, depreciation, amortization and impairment expense would
have changed by approximately $38 million, after tax, assuming no other
changes to our reserves profiles.
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.
Since we do not have any loan covenants directly linked to reserves, 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 the
Liquidity section of the MD&A.
OIL AND GAS ACCOUNTING - EVALUATION OF EXPLORATION DRILLING
We use the successful efforts method to account for our oil and gas exploration
and production activities. Under this method, exploration costs are capitalized
pending an evaluation as to whether sufficient quantities of reserves have been
found to justify commercial production. Accounting rules require that this
evaluation be made within at least one year of well completion. If our
evaluation determines that the well did not encounter sufficient quantities of
reserves to justify commercial production, the well costs are expensed as a dry
hole and are reported in exploration expense. Exploratory wells that are judged
to have discovered potentially sufficient quantities of oil and gas in areas
where major capital expenditures are required before the commencement of
production and where commercial viability requires the drilling of additional
exploratory wells, remain capitalized as long as the drilling of additional
exploratory wells is under way or firmly planned for the near future. For
offshore deep-water exploratory discoveries, it is not unusual to have
exploratory wells capitalized on our balance sheet for a number of years while
we perform additional appraisal drilling and seismic work on the potential oil
and gas field. We continually monitor the results of the additional appraisal
work and expense capitalized well costs as dry holes if we determine that the
potential field does not warrant further exploratory efforts in the near term.
We currently have an interest in an exploration block, offshore Nigeria where
capitalized exploratory costs have been on our balance sheet for longer than one
year. Major capital expenditures are required before production can begin and
additional drilling efforts are underway to fully appraise the block. We are
preparing a field development plan for the block with our partners for
submission to the Nigerian government for approval. Once we obtain this approval
and the project has been sanctioned, we will book proved reserves. Capitalized
costs relating to this exploration block as at December 31, 2004 were $77
million (2003 - $68 million). In the event that we are unable to book proved
reserves for this project, amounts capitalized will be written off.
For more information with respect to amounts and geographic locations of costs
incurred on exploration activity and amounts on our balance sheet relating to
unproved properties, please refer to our Capitalized Costs and Costs Incurred
tables set out in our supplemental Oil and Gas Producing Activities disclosures.
(1) "Proved" oil and gas reserves are the estimated quantities of natural gas,
crude oil, condensate and natural gas liquids that geological and engineering
data demonstrate with reasonable certainty can be recoverable in future years
from known reservoirs under existing economic and operating conditions.
Reservoirs are considered "proved" if economic producibility 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 operation methods.
65
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 at the end of 2004 and
found no impairments were required based on our assumptions.
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$17/bbl to US$56/bbl and US$2/mmbtu to US$19/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 and development 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 forecast WTI crude oil prices were to fall to mid-US$20 levels 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.
Any impairment charges would lower our net income.
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.
BUSINESS COMBINATION - PURCHASE PRICE ALLOCATION
During the fourth quarter of 2004, we acquired EnCana (UK) Limited, a company
operating and exploring oil and gas properties located in the North Sea. We
accounted for this acquisition using the purchase method of accounting. Under
this method, we are required to record on our consolidated balance sheet the
estimated fair values of the acquired company's assets and liabilities at the
acquisition date. Any excess of the purchase price over the fair values of the
tangible and intangible net assets acquired is recorded as goodwill.
We have made various assumptions in determining the fair values of the acquired
company's assets and liabilities. The most significant assumptions and judgments
made relate to the estimation of the fair value of the oil and gas properties.
To determine the fair value of these properties, we estimated (a) oil and gas
reserves in accordance with our reserve standards, and (b) future prices of oil
and gas.
Our reserve estimates were based on the work performed by our engineers and
outside consultants. The judgments associated with these estimated reserves are
described earlier in our critical accounting estimates discussion entitled "Oil
and Gas Accounting - Reserves Determination". Our estimates of future prices
were based on prices derived from a consensus of future price forecasts amongst
industry analysts and our own assessments. The judgments associated with these
estimates are described earlier in our critical accounting estimates discussion
entitled "Oil and Gas Accounting - Impairment".
We applied our estimated future prices to the estimated reserves quantities
acquired, and we estimated future operating and development costs, to arrive at
estimated future net revenues for the properties acquired. For proved
properties, we discounted the future net revenues using after-tax discount
rates. The same principles were applied in arriving at the fair value of
unproved properties acquired. These unproved properties generally represent the
value of the probable and possible reserves. Because of their very nature,
probable and possible reserve estimates are more imprecise than those of proved
reserves. To compensate for the inherent risk of estimating and valuing unproved
reserves, an appropriate risk-weighting factor was applied to the discounted
future net revenues of the probable and possible reserves in each particular
instance.
If the fair value allocated to oil and gas properties acquired had been
decreased by $50 million, future income tax liabilities would have decreased by
$20 million and goodwill would have increased by $30 million.
ASSET RETIREMENT OBLIGATIONS
We are required to remove or remedy the effect of our activities on the
environment at our present and former operating sites by dismantling and
removing production facilities and remediating any damage caused. Estimating our
future asset retirement obligations requires us to make estimates and judgments
with respect to activities that will occur many years into the future. In
addition, the ultimate financial impact of environmental laws and regulations is
not always clearly known and cannot be reasonably estimated as standards evolve
in the countries in which we operate.
66
We record asset retirement obligations in our consolidated financial statements
by discounting the present value of the estimated retirement obligations
associated with our oil and gas wells and facilities and chemical plants. In
arriving at amounts recorded, numerous assumptions and judgments are made with
respect to ultimate settlement amounts, inflation factors, credit adjusted
discount rates, timing of settlement and expected changes in legal, regulatory,
environmental and political environments. The asset retirement obligations we
have recorded result in an increase to the carrying cost of our property, plant
and equipment. The obligations are accreted with the passage of time. A change
in any one of our assumptions could impact our asset retirement obligations, our
property, plant and equipment and our net income.
It is difficult to determine the impact of a change in any one of our
assumptions. As a result, we are unable to provide a reasonable sensitivity
analysis of the impact a change in our assumptions would have on our financial
results. We are confident, however, that our assumptions are reasonable.
NEW ACCOUNTING PRONOUNCEMENTS
CANADIAN PRONOUNCEMENTS
In an effort to harmonize Canadian GAAP with US GAAP, the Canadian Accounting
Standards Board has issued sections:
o 1530, COMPREHENSIVE INCOME;
o 3855, FINANCIAL INSTRUMENTS -- RECOGNITION AND MEASUREMENT; and
o 3865, HEDGES.
Under these new standards, all financial assets should be measured at fair value
with the exception of loans, receivables and investments that are intended to be
held to maturity and certain equity investments, which should be measured at
cost. Similarly, all financial liabilities should be measured at fair value when
they are held for trading or they are derivatives.
Gains and losses on financial instruments measured at fair value will be
recognized in the income statement in the periods they arise with the exception
of gains and losses arising from:
o financial assets held for sale, for which unrealized gains and losses are
deferred in other comprehensive income until sold or impaired; and
o certain financial instruments that qualify for hedge accounting.
Sections 3855 and 3865 make use of "other comprehensive income". Other
comprehensive income comprises revenues, expenses, gains and losses that are
recognized in comprehensive income, but are excluded from net income. Unrealized
gains and losses on qualifying hedging instruments, translation of
self-sustaining foreign operations, and unrealized gains or losses on financial
instruments held for sale will be included in other comprehensive income and
reclassified to net income when realized. Comprehensive income and its
components will be a required disclosure under the new standard.
These new standards are effective for fiscal years beginning on or after October
1, 2006 and early adoption is permitted. Adoption of these standards as at
December 31, 2004 would have the following impact on our Consolidated Financial
Statements:
In November 2004, the Financial Accounting Standards Board (FASB) issued
Statement 151, INVENTORY COSTS. This statement amends ARB 43 to clarify that:
o abnormal amounts of idle facility expense, freight, handling costs and
wasted material (spoilage) should be recognized as current-period charges;
and
o requires the allocation of fixed production overhead to inventory based on
the normal capacity of the production facilities.
The provisions of this statement are effective for inventory costs incurred
during fiscal years beginning after June 15, 2005. We do not expect the adoption
of this statement will have any material impact on our results of operations or
financial position.
In December 2004, the FASB issued Statement 123(R), SHARE-BASED PAYMENTS. This
statement revises Statement 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, and
supersedes APB Opinion 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES.
Statement 123(R) requires all stock-based awards issued to employees to be
measured at fair value and to be expensed in the income statement. This
statement is effective for reporting periods beginning after June 15, 2005.
We are currently expensing stock-based awards issued to employees using the fair
value method for equity based awards and the intrinsic method for liability
based awards. Adoption of this standard will change our expense under US GAAP
for tandem options and stock appreciation rights as these awards will be
measured using the fair value method rather than the intrinsic method. We are
currently evaluating the provisions of Statement 123(R) and have not yet
determined the full impact this statement will have on our results of operations
or financial position under US GAAP.
67
In December 2004, the FASB issued Statement 152, ACCOUNTING FOR REAL ESTATE.
This statement amends Statement 66, ACCOUNTING FOR SALES OF REAL ESTATE, to
reference the financial accounting and reporting guidance for real estate
time-sharing transactions that is provided in AICPA Statement of Position 04-2,
ACCOUNTING FOR REAL ESTATE TIME-SHARING TRANSACTIONS. This statement also amends
FASB Statement 67, ACCOUNTING FOR COSTS AND INITIAL RENTAL OPERATIONS OF REAL
ESTATE PROJECTS, to state that the guidance for incidental operations and costs
incurred to sell real estate projects does not apply to real estate time-sharing
transactions. This statement is effective for financial statements with fiscal
years beginning after June 15, 2005 and will not impact our results of
operations or financial position.
In December 2004, the FASB issued Statement 153, EXCHANGES OF NONMONETARY
ASSETS, an amendment of APB Opinion 29, ACCOUNTING FOR NONMONETARY TRANSACTIONS.
This amendment eliminates the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance. Under Statement 153,
if a nonmonetary exchange of similar productive assets meets a
commercial-substance test and fair value is determinable, the transaction must
be accounted for at fair value resulting in the recognition of any gain or loss.
This statement is effective for nonmonetary transactions in fiscal periods that
begin after June 15, 2005. We do not expect the adoption of this statement will
have any material impact on our results of operations or financial position.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 recognize these risks and manage our operations to
minimize our exposures to the extent practical.
NON-TRADING
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.
In 2004, WTI averaged US$41.40/bbl reaching a high of US$56.42/bbl and a low of
US$32.41/bbl. NYMEX natural gas prices averaged US$6.19/mcf in 2004, reaching a
high of US$8.12/mcf and a low of US$4.34/mcf.
Our sensitivities to commodity prices and the expected impact on our 2005 cash
flow from operating activities and net income are as follows:
These sensitivities to changes in benchmark prices for crude oil and natural gas
are based on our estimated 2005 production levels for crude oil and natural gas
and assume a Canadian/US dollar exchange rate of 80(cent). Our estimated crude
oil and natural gas production range for 2005 is between 230,000 and 250,000
boe/d, of which natural gas represents approximately 20%.
The majority of our oil and gas 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 2004, we purchased WTI put options to manage the commodity price risk
exposure on a portion of our oil production in 2005 and 2006. These options
establish an annual average WTI floor price of US$43/bbl in 2005 and US$38/bbl
in 2006, as follows:
Notional Average Price
Volumes Term (WTI)
--------------------------------------------------------------------------------
(US$/bbl)
Crude Oil WTI Put Options 60,000 bbls/d 2005 43
60,000 bbls/d 2006 38
---------------------------------------------
In 2003, we entered into WTI and NYMEX gas forward contracts for a 12 month
period. These forward contracts fixed our oil and gas prices at contract prices
for the hedged volumes, less applicable price differentials, as follows:
Hedged Average
Volumes Term Price
--------------------------------------------------------------------------------
(US$)
Fixed WTI Price 5,000 bbls/d April 2003 - March 2004 28.50/bbl
Fixed NYMEX Price 12,000 mmbtu/d April 2003 - March 2004 5.35/mmbtu
-------------------------------------------------------
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Since actual prices during the contract period were higher than the fixed prices
we received, our return was lower than what it would have been without these
contracts in place. These contracts expired in March 2004.
FOREIGN CURRENCY RISK
A substantial portion of our operations are denominated in or referenced to US
dollars including:
o sales of crude oil, natural gas and certain chemicals products;
o capital spending and expenses for our oil and gas and chemicals operations;
and
o short-term and long-term borrowings.
The Canadian/US dollar exchange rate averaged 77(cent) in 2004 with a high of
85(cent) and a low of 72(cent).
Our sensitivities to the US dollar and the expected impact of a one cent change
on our 2005 cash flow from operating activities, net income, capital
expenditures and long-term debt are as follows:
Cash Net Capital Long-Term
(Cdn$ millions) Flow Income Expenditures Debt
-------------------------------------------------------------------------------------------
$0.01 change in US to Canadian dollar 25 13 18 50
----------------------------------------
Our sensitivities to changes in the Canadian/US dollar exchange rate are
calculated based on projected revenues, expenses, capital expenditures and
US-dollar denominated long-term debt for 2005. These estimates are based on a
WTI price for crude oil of US$40.00/bbl, a NYMEX natural gas price of
US$6.50/mcf and a Canadian/US dollar exchange rate of 80 (cent).
We manage our exposure to fluctuations between the US and Canadian dollar by
matching our expected net cash flows and borrowings in the same currency. Net
revenue from our foreign operations and our US-dollar borrowings are generally
used to fund US-dollar capital expenditures and debt repayments. Since the
timing of cash inflows and outflows is not necessarily interrelated,
particularly for capital expenditures, we maintain revolving Canadian and
US-dollar borrowing facilities that can be used or repaid depending on expected
net cash flows. We designate our US-dollar borrowings as a hedge against our
US-dollar net investment in foreign operations.
Our Buzzard project in the North Sea creates foreign currency exposure as a
portion of the capital costs are denominated in British pounds (GBP) and Euros.
In order to reduce our exposure to fluctuations in these currencies relative to
the US dollar, we purchased foreign currency call options in early-2005. These
options set a ceiling on most of our British pound and Euro spending exposure
from February 2005 through to the end of 2006.
These call options effectively set a maximum GBP-US$ exchange rate of 1.95 on a
total of GBP 84 million for the period March 2005 through June 2005, and a
maximum rate of 2.00 on a total of GBP 185 million for the period July 2005
through December 2006. With respect to our Euro exposure, the call options
effectively set a maximum Euro-US$ exchange rate of 1.40 on a total of Euros 59
million for the period February through September 2005. Managing our exchange
rate exposure through the use of call options caps our exposure if the US dollar
weakens relative to the British pound and the Euro but allows us to benefit
fully from any strengthening of the US dollar relative to these currencies.
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, 2004, 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 $50 million.
INTEREST RISK
We are exposed to fluctuations in short-term interest rates from our
floating-rate debt and, to a lesser extent, our derivative instruments and
long-term debt, as their market value is sensitive to interest rate
fluctuations. To minimize our exposure to interest rate fluctuations, we
occasionally use derivative instruments.
Short-term interest rates for US dollar borrowings averaged 3.1% in 2004,
reaching a high of 3.2% and low of 3.0%.
Our sensitivity to interest rates and the expected impact of a 1% change in
interest rates on our 2005 cash flow from operating activities and net income is
as follows:
(Cdn$ millions) Cash Flow Net Income
--------------------------------------------------------------------------------
Interest Rates - 1% change in rates 12 8
------------------------
Our sensitivity to changes in interest rates is based on 2005 estimated average
floating rate debt of $1.2 billion and a Canadian/US dollar exchange rate of
80 (cent).
Our 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, 2004 fixed-rate
borrowings comprised 56% (2003 - 100%) of our long-term debt at an effective
average rate of 6.6% (2003 - 8.2%). During the year we periodically drew on our
unsecured syndicated term credit facilities and at December 31, 2004, floating
rate debt comprised 44% (2003 - nil) of our long-term debt at an effective
average rate of 3.2% (2003 - 2.0%).
We had no interest rate swaps outstanding in 2004 or 2003.
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TRADING
COMMODITY PRICE RISK
Our marketing operation is involved in the marketing and trading of crude oil,
natural gas and power, 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. These net open positions allow us to generate income, but also expose
us to risk of loss due to fluctuating market prices (market risk). 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 exceeded and the potential loss could be greater than our
estimate. There were no changes in the methodology we used to estimate VaR in
2004.
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 year-end, annual high, annual low and annual average VaR amounts are as
follows:
(Cdn$ millions) 2004 2003 2002
--------------------------------------------------------------------------------
Value at Risk
Year-End 21 21 19
High 42 31 28
Low 17 14 12
Average 29 20 17
------------------------------
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 our energy trading activities regularly.
CREDIT RISK
Credit risk affects both our trading and non-trading activities and is the risk
of loss if counterparties do not fulfill their contractual obligations. Most of
our receivables are with counterparties in the oil and gas and energy trading
industry and are subject to normal industry credit risk. We take the following
measures to reduce this risk:
o we assess the financial strength of our counterparties 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 rating agency credit ratings and internal
assessments based on company and industry analysis;
o we review counterparty credit limits regularly; and
o we use standard agreements that allow for the netting of 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, 2004:
o over 90% of our receivables were investment grade;
o only two counterparties individually made up more than 5% of our credit
exposure. All were investment grade.
70
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this report, including those appearing in ITEMS 1 AND 2 -
BUSINESS AND PROPERTIES and ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS, are forward-looking
statements(1). Forward-looking statements are generally identifiable by terms
such as ANTICIPATE, BELIEVE, INTEND, PLAN, EXPECT, ESTIMATE, BUDGET, OUTLOOK or
other similar words, and include statements relating to future production
associated with our Long Lake, North Sea and West Africa projects.
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 in Item 7 and QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK in Item 7A.
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 asset dispositions;
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.
(1) Within the meaning of the United States PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995, Section 21E of the United States SECURITIES EXCHANGE ACT OF 1934,
as amended, and Section 27A of the United States SECURITIES ACT OF 1933, as
amended.
71
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, 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 require disclosure of finding and development (F&D) costs
per boe of proved reserves additions whereas NI 51-101 requires that
various F&D costs per boe be disclosed. NI 51-101 requires that F&D costs
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;
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;
o the SEC does not consider the upgrading component of our integrated oil
sands project at Long Lake as an oil and gas activity, and therefore
permits recognition of bitumen reserves only. NI 51-101 specifically
includes such activity as an oil and gas activity and recognizes synthetic
oil as a product type, and therefore permits recognition of synthetic
reserves. Given low year-end bitumen prices, we have not recognized any
proved bitumen reserves under SEC requirements whereas under NI 51-101 we
would have recognized 205 million barrels of proved synthetic reserves
(before royalties); and
o the SEC considers our Syncrude operation as a mining activity rather than
an oil and gas activity, and therefore does not permit related reserves to
be included with oil and gas reserves. NI 51-101 specifically includes such
activity as an oil and gas activity and recognizes synthetic oil as a
product type, and therefore permits them to be included with oil and gas
reserves. We have provided a separate table showing our share of the
Syncrude proved reserves as well as the additional disclosures relating to
mining activities required by SEC requirements.
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.
72
FINANCIAL STATEMENTS
[GRAPHIC OMITTED]
[GRAPHIC IMAGE: GULF OF MEXICO, US]
73
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION
TABLE OF CONTENTS
REPORT OF MANAGEMENT..........................................................75
REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS........................76
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statement of Income.........................................77
Consolidated Balance Sheet ..............................................78
Consolidated Statement of Cash Flows ....................................79
Consolidated Statement of Shareholders' Equity ..........................80
Notes to Consolidated Financial Statements ..............................81
SUPPLEMENTARY FINANCIAL INFORMATION (UNAUDITED)
Quarterly Financial Data in Accordance with Canadian and US GAAP........113
Oil and Gas Producing Activities and Syncrude Operations ...............114
74
REPORT OF MANAGEMENT
February 7, 2005
To the Shareholders of Nexen Inc.:
We are responsible for the preparation and fair presentation of the consolidated
financial statements, as well as the financial reporting process that gives rise
to such consolidated financial statements. This responsibility requires us to
make significant accounting judgments and estimates. For example, we are
required to choose accounting principles and methods that are appropriate to the
company's circumstances and we are required to make estimates and assumptions
that affect amounts reported. 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 also have responsibility for the preparation and fair presentation of other
financial information in this report and to ensure the consistency of this
information with the financial statements.
We are responsible for the development and implementation of internal controls
over the financial reporting process. These controls are designed to provide
reasonable assurance that relevant and reliable financial information is
produced. 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 our internal controls over
financial reporting provide reasonable assurance that our assets are safeguarded
against loss from unauthorized use or disposition, that receipts and
expenditures of the company are made only in accordance with authorization of
management and directors of the company, and that our records are reliable for
preparing our consolidated financial statements and other financial information
in accordance with applicable generally accepted accounting principles and in
accordance with applicable securities rules and regulations. All internal
control systems, no matter how well designed, have inherent limitations.
Therefore, even those systems determined to be effective can provide only
reasonable assurance with respect to financial statement preparation and
presentation.
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 required regulatory disclosures.
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 and include
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 is responsible for reviewing and approving the
consolidated financial statements and for overseeing management's performance of
its financial reporting responsibilities. 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 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 the independent auditors, to review
accounting policies, financial reporting and internal control issues and to
ensure each party is properly discharging its responsibilities. The Audit
Committee is responsible for the appointment and compensation of the independent
auditors and also considers their independence, reviews their fees and (subject
to applicable securities laws), pre-approves their retention for any permitted
non-audit services and their fee for such services. The internal auditors and
independent registered Chartered Accountants have full and unlimited access to
the Audit Committee, with or without the presence of management.
(signed) "Charles W. Fischer" (signed) "Marvin F. Romanow"
President and Chief Executive Officer Executive Vice President
and Chief Financial Officer
75
REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS
To the Board of Directors and Shareholders of Nexen Inc.:
We have audited the consolidated balance sheet of Nexen Inc. as at December 31,
2004 and 2003 and the consolidated statements of income, cash flows and
shareholders' equity for each of the years in the three year period ended
December 31, 2004. 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 Canadian generally accepted auditing
standards and the standards of the Public Company Accounting Oversight Board
(United States). These 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. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 2004
and 2003 and the results of its operations and its cash flows for each of the
years in the three year period ended December 31, 2004 in accordance with
Canadian generally accepted accounting principles.
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of the Company's
internal control over financial reporting as at December 31, 2004, based on the
criteria established in INTERNAL CONTROL - INTEGRATED FRAMEWORK issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report
dated February 7, 2005 expressed an unqualified opinion on management's
assessment of the effectiveness of the Company's internal control over financial
reporting and an unqualified opinion on the effectiveness of the Company's
internal control over financial reporting.
COMMENTS BY AUDITORS ON CANADA-UNITED STATES OF AMERICA REPORTING DIFFERENCE
The standards of the Public Company Accounting Oversight Board (United States)
require the addition of an explanatory paragraph (following the opinion
paragraph) when there are changes in accounting principles that have a material
effect on the comparability of the Company's financial statements, such as the
changes described in Note 1(r) to the consolidated financial statements. Our
report to the board of directors and shareholders on the consolidated financial
statements of Nexen Inc., dated February 7, 2005, is expressed in accordance
with Canadian reporting standards which do not require a reference to such
changes in accounting principles in the auditors' report when the change is
properly accounted for and adequately disclosed in the financial statements.
NEXEN INC.
CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2004
Cdn$ millions, except per share amounts
2004 2003 2002
------------------------------------------------------------------------------------------------------------
Restated for Restated for
Changes in Changes in
Accounting Accounting
Principles Principles
Note 1(r) Note 1(r)
REVENUES
Net Sales 3,176 2,844 2,341
Marketing and Other (Note 14) 729 610 496
----------------------------------------
3,905 3,454 2,837
----------------------------------------
EXPENSES
Operating 762 721 701
Depreciation, Depletion, Amortization and Impairment (Note 5) 744 995 632
Transportation and Other 564 489 475
General and Administrative 299 190 151
Exploration 246 199 178
Interest (Note 7) 143 169 181
----------------------------------------
2,758 2,763 2,318
----------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 1,147 691 519
----------------------------------------
PROVISION FOR INCOME TAXES (Note 15)
Current 248 214 207
Future 119 (73) (44)
----------------------------------------
367 141 163
----------------------------------------
NET INCOME FROM CONTINUING OPERATIONS 780 550 356
Net Income from Discontinued Operations (Note 11) 13 28 53
----------------------------------------
NET INCOME 793 578 409
========================================
EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
Basic (Note 10) 6.07 4.45 2.91
========================================
Diluted (Note 10) 5.99 4.41 2.87
========================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 10) 6.17 4.67 3.34
========================================
Diluted (Note 10) 6.09 4.63 3.30
========================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
77
NEXEN INC.
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2004 AND 2003
Cdn$ millions, except share amounts
2004 2003
-----------------------------------------------------------------------------------------------
Restated for
Changes in
Accounting
Principles
Note 1(r)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 74 1,087
Accounts Receivable (Note 3) 2,136 1,423
Inventories and Supplies (Note 4) 351 270
Other 42 79
--------------------------
Total Current Assets 2,603 2,859
--------------------------
PROPERTY, PLANT AND EQUIPMENT (Note 5) 8,643 4,550
GOODWILL 375 36
FUTURE INCOME TAX ASSETS (Note 15) 333 108
DEFERRED CHARGES AND OTHER ASSETS (Note 17) 429 164
--------------------------
12,383 7,717
==========================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings (Note 7) 100 --
Current Portion of Long-Term Debt (Note 7) -- 572
Accounts Payable and Accrued Liabilities 2,416 1,404
Accrued Interest Payable 34 44
Dividends Payable 13 12
--------------------------
Total Current Liabilities 2,563 2,032
--------------------------
LONG-TERM DEBT (Note 7) 4,259 2,517
FUTURE INCOME TAX LIABILITIES (Note 15) 2,131 720
ASSET RETIREMENT OBLIGATIONS (Note 8) 421 305
DEFERRED CREDITS AND OTHER LIABILITIES 142 68
SHAREHOLDERS' EQUITY (Note 9)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2004 - 129,199,583 shares
2003 - 125,606,107 shares 637 513
Contributed Surplus -- 1
Retained Earnings 2,335 1,594
Cumulative Foreign Currency Translation Adjustment (105) (33)
--------------------------
Total Shareholders' Equity 2,867 2,075
--------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Notes 12 and 15)
12,383 7,717
==========================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Approved on behalf of the Board:
(Signed) "Charles W. Fischer" (Signed) "David A. Hentschel"
Director Director
78
NEXEN INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 2004
Cdn$ millions
2004 2003 2002
-------------------------------------------------------------------------------------------------------------------------------
Restated for Restated for
Changes in Changes in
Accounting Accounting
Principles Principles
Note 1(r) Note 1(r)
OPERATING ACTIVITIES
Net Income from Continuing Operations 780 550 356
Net Income from Discontinued Operations 13 28 53
Charges and Credits to Income not Involving Cash (Note 16) 903 1,018 724
Exploration Expense 246 199 178
Changes in Non-Cash Working Capital (Note 16) (122) (320) (46)
Other (Note 16) (213) (70) (15)
------------------------------------------------
1,607 1,405 1,250
FINANCING ACTIVITIES
Proceeds from Long-Term Notes and Debentures (Note 7) 1,779 651 790
Repayment of Long-Term Notes and Debentures (Note 7) (300) -- -
Proceeds from (Repayment of) Term Credit Facilities, Net 83 93 (419)
Proceeds from (Repayment of) Short-Term Borrowings, Net 101 (18) (33)
Proceeds from Subordinated Debentures (Note 7) -- 613 --
Redemption of Preferred Securities (Note 7) (289) (340) --
Dividends on Common Shares (52) (40) (37)
Issue of Common Shares 124 73 51
Other (20) (26) (23)
------------------------------------------------
1,426 1,006 329
INVESTING ACTIVITIES
Business Acquisition, Net of Cash Acquired (Note 2) (2,583) -- --
Capital Expenditures
Exploration and Development (1,582) (1,276) (1,477)
Proved Property Acquisitions (4) (164) (4)
Chemicals, Corporate and Other (95) (54) (144)
Proceeds on Disposition of Assets 34 293 49
Changes in Non-Cash Working Capital (Note 16) 244 (18) 7
Other (27) -- --
------------------------------------------------
(4,013) (1,219) (1,569)
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
CASH EQUIVALENTS (33) (164) (12)
------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (1,013) 1,028 (2)
CASH AND CASH EQUIVALENTS - BEGINNING OF YEAR 1,087 59 61
------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF YEAR 74 1,087 59
================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
79
NEXEN INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 2004
Cdn$ millions
2004 2003 2002
-------------------------------------------------------------------------------------------------------------------------------
Restated for Restated for
Changes in Changes in
Accounting Accounting
Principles Principles
Note 1(r) Note 1(r)
COMMON SHARES (Note 9)
Balance at Beginning of Year 513 440 389
Exercise of Stock Options 93 50 27
Issue of Common Shares 31 23 24
------------------------------------------------
Balance at End of Year 637 513 440
------------------------------------------------
CONTRIBUTED SURPLUS
Balance at Beginning of Year 1 -- --
Stock Based Compensation Expense (Note 9) 2 1 --
Modification of Stock Option Plan to Tandem Option Plan (Note 9) (3) -- --
------------------------------------------------
Balance at End of Year -- 1 --
------------------------------------------------
RETAINED EARNINGS
Balance at Beginning of Year 1,594 1,056 697
Retroactive Adjustment for Changes in Accounting Principles (Note 1) -- -- (13)
Net Income 793 578 409
Dividends on Common Shares (52) (40) (37)
------------------------------------------------
Balance at End of Year 2,335 1,594 1,056
------------------------------------------------
CUMULATIVE FOREIGN CURRENCY TRANSLATION ADJUSTMENT
Balance at Beginning of Year (33) 94 94
Retroactive Adjustment for Changes in Accounting Principles (Note 1) -- -- (34)
Translation Adjustment, Net of Income Taxes (72) (127) 34
------------------------------------------------
Balance at End of Year (105) (33) 94
------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
80
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 19. 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. Our
management reviews these estimates, including those related to litigation,
environmental and dismantlement liabilities, income taxes and determination of
proved reserves on an ongoing basis. Changes in facts and circumstances may
result in revised estimates and actual results may differ from these estimates.
(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 proportionately consolidate our undivided interests in our oil
and gas exploration, development and production activities conducted under joint
venture arrangements. We also proportionately consolidate our 7.23% undivided
interest in the Syncrude joint venture, which is considered a mining activity
under US regulations. While the joint ventures under which these activities are
carried out do not comprise distinct legal entities, they are operating
entities, the significant operating policies of which are, by contractual
arrangement, jointly controlled by all working interest parties.
(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, marketing 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.
Inventory costs include expenditures and other costs, including depreciation,
depletion and amortization, directly or indirectly incurred in bringing the
inventory to its existing condition.
(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, 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 pending evaluation as to whether sufficient quantities of
reserves have been found to justify commercial production. If commercial
quantities of reserves are not found, exploration drilling costs are expensed.
All exploratory wells are evaluated for commercial viability within twelve
months of drilling completion. Exploration wells that discover potentially
commercial quantities of reserves in areas requiring major capital expenditures
before the commencement of production and where commercial viability requires
the drilling of additional exploratory wells, remain capitalized as long as the
drilling of additional exploratory wells is under way or firmly planned. 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.
Property, plant and equipment for our Syncrude operation is recorded at cost and
includes only recoverable costs that directly result in an identifiable future
benefit. Unrecoverable costs, 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 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.
81
(e) DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
Under successful efforts accounting, we deplete oil and gas capitalized 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 remaining proved reserves. Depletion is
considered a cost of inventory when the oil and gas is produced. When this
inventory is sold, the depletion is charged to DD&A expense.
Our Syncrude PP&E is depleted using the unit-of-production method. Capitalized
costs are depleted over proved and probable reserves within developed areas of
interest.
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. Unproved property costs and
major projects that are under construction or development are not depreciated,
depleted or amortized.
We evaluate the carrying value of our PP&E whenever events or conditions occur
that indicate that the carrying value of properties on our balance sheet may not
be recoverable from future cash flows. These events or conditions occur
periodically. If carrying value exceeds the sum of undiscounted future cash
flows, the property's value is impaired. The property is then 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, amortization and impairment. Our cash flow estimates require
assumptions about future commodity prices, operating costs and other factors.
Actual results can differ from those estimates.
In assessing the carrying values of our unproved properties, we take into
account our future plans for those properties, the remaining terms of the leases
and any other factors that may be indicators of potential impairment.
(f) CARRIED INTEREST
We conduct certain international operations jointly with foreign governments in
accordance with production sharing agreements pursuant to which proved reserves
are recognized using the economic interest method. 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) ASSET RETIREMENT OBLIGATIONS
We provide for future asset retirement obligations on our resource properties,
facilities, production platforms, pipelines and chemicals facilities based on
estimates established by current legislation and industry practices. The asset
retirement obligation is initially measured at fair value and capitalized to
property, plant and equipment as an asset retirement cost. The asset retirement
obligation accretes until the time the retirement obligation is expected to
settle while the asset retirement cost is amortized over the useful life of the
underlying property, plant and equipment. The amortization of the asset
retirement cost and the accretion of the asset retirement obligation are
included in depreciation, depletion, amortization and impairment. Actual
retirement costs are recorded against the obligation when incurred. Any
difference between the recorded asset retirement obligation and the actual
retirement costs incurred is recorded as a gain or loss in the period of
settlement.
(h) GOODWILL
Goodwill is recorded at cost and is not amortized. We test goodwill for
impairment annually based on estimated future cash flows of the reporting unit
to which the goodwill is attributable. In addition, we test goodwill for
impairment whenever an event or circumstance occurs that may reduce the fair
value of a reporting unit below its carrying amount. Our goodwill is
attributable to our Marketing and United Kingdom reporting units.
(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, the United States and the United
Kingdom, our customers typically take title when the crude oil and natural gas
reaches the end of the pipeline. For our other 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).
82
CHEMICALS
Revenue from our chemicals operations is only recognized when our products are
delivered to our customers. Delivery only takes place when we have a sales
contract in place specifying delivery volumes and sales prices. We assess
customer credit worthiness before entering into sales contracts to minimize
collection risk.
MARKETING
Substantially all of the physical purchase and sales 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 unless the requirements for hedge accounting are met (see
Note 1(m)). 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. We assess customer
credit worthiness before entering into contracts and provide for netting terms
to minimize collection risk. Amounts are recorded on a net basis where we have
the legal right of offset. Our marketing operation has received cash payments in
exchange for assuming certain transportation obligations from third parties.
These cash payments have been recorded as deferred liabilities and are
recognized in net income as the transportation is used.
(j) INCOME TAXES
We follow the liability method of accounting for income taxes (see Note 15).
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) 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.
(l) CAPITALIZED INTEREST
We capitalize interest on major development projects until such time as the
project is substantially complete using the weighted-average interest rate on
all of our borrowings. Capitalized interest cannot exceed the actual interest
expense.
(m) 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
6). We record these instruments at fair value at the balance sheet date and
record any change in fair value as a net gain or loss in marketing and other
during the period of change unless the requirements for hedge accounting are
met. 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
at the inception of the hedge. We recognize gains and losses on the derivative
instruments designated as hedges 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.
83
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 fair 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 deferred credits
and other liabilities.
(n) 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.
(o) STOCK-BASED COMPENSATION
In 2003, we adopted the fair-value method of accounting for stock options
granted to employees and directors. We recorded stock-based compensation expense
in the Consolidated Statement of Income as general and administrative expenses
for all options granted on or after January 1, 2003, with a corresponding
increase to contributed surplus. Compensation expense for options granted was
based on estimated fair values at the time of grant and we recognized the
expense over the vesting period of the option.
In May 2004, we modified our stock option plan to a tandem option plan by
including a cash feature. The tandem options give the holders a right to either
purchase common shares at the exercise price or to receive cash payments equal
to the excess of the market value of the common shares over the exercise price.
As a result of the modification, we record obligations for the tandem options
using the intrinsic-value method of accounting and recognize compensation
expense. Obligations are accrued on a graded vesting basis and represent the
difference between the market value of our common shares and the exercise price
of the options. The obligations are revalued each reporting period based on the
change in the market value of our common shares and the number of graded vested
options outstanding. We reduce the liability when the options are surrendered
for cash. When the options are exercised for stock, the recorded liability
amount is transferred to share capital.
Stock options awarded to our US employees on or after December 1, 2004 do not
include a cash feature and are not accounted for as tandem options. Instead, we
account for these options using the fair-value method. Compensation expense is
based on estimated fair values at the time of grant and is recognized over the
vesting period of the options. The expense is included as general and
administrative expense with a corresponding increase to contributed surplus.
We provide stock appreciation rights to employees as described in Note 9.
Obligations are accrued as compensation expense over the graded vesting period
of the stock appreciation rights.
(p) CASH AND CASH EQUIVALENTS
Cash and cash equivalents include short-term, highly liquid investments that
mature within three months of their purchase. They are recorded at cost, which
approximates market value.
(q) 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.
(r) CHANGES IN ACCOUNTING PRINCIPLES
ASSET RETIREMENT OBLIGATIONS (ARO)
On January 1, 2004, we retroactively adopted the Canadian Institute of Chartered
Accountants (CICA) standard S.3110, ASSET RETIREMENT OBLIGATIONS. This new
standard 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. We previously provided
for dismantlement and site restoration costs on our oil and gas wells and
facilities, and chemicals plants based on estimates established by current
legislation and industry practices. We recorded a provision for these costs in
DD&A based on proved reserves or estimated remaining asset lives. The change was
adopted retroactively and all prior periods presented have been restated.
84
FINANCIAL INSTRUMENTS
In the fourth quarter of 2004, we retroactively adopted the changes to CICA
standard S.3860, FINANCIAL INSTRUMENTS. These changes require that fixed-amount
contractual obligations that can be settled by issuing a variable number of
equity instruments be classified as a liability. Our US-dollar denominated
preferred and subordinated securities have these characteristics and accordingly
have been reclassified as long-term debt. Dividends and interest on these
securities have been included in interest expense and issue costs previously
charged to retained earnings have been amortized over the life of the
securities. Unamortized issue costs have been expensed on the redemption of the
preferred securities in 2003 and 2004. Foreign exchange gains or losses from
translation of the US-dollar amounts have been included as cumulative foreign
currency translation adjustments. The change was adopted retroactively and all
prior periods presented have been restated.
GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
In 2004, we adopted CICA standard S.1100, GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES which eliminated general practice in Canada as a component of GAAP.
Our accounting policy for 2004 is to include geological and geophysical costs as
operating cash outflows in our Consolidated Statement of Cash Flows. For
previous years, we included geological and geophysical costs as investing cash
outflows consistent with industry practice in Canada. In our Consolidated
Statement of Cash Flows for 2004, we included $73 million of geological and
geophysical costs as other operating cash outflows. For 2003 and 2002,
geological and geophysical costs of $62 million and $80 million, respectively,
are included in investing activities as exploration and development capital
expenditures. This change in accounting policy was adopted prospectively.
IMPACT OF CHANGES IN ACCOUNTING PRINCIPLES
The impact of the changes on our 2004 Consolidated Statement of Income resulted
in additional interest expense of $3 million for dividends on preferred
securities, additional transportation and other expense of $11 million for the
unamortized issue costs on the redemption of preferred securities, and a
corresponding reduction in the provision for income taxes of $6 million. The
impact of these changes in accounting principles on our Consolidated Statement
of Income and Earnings per Common Share for the years ended December 31, 2003
and 2002 and on our Consolidated Balance Sheet at December 31, 2003, are shown
below.
CONSOLIDATED STATEMENT OF INCOME FOR THE YEARS ENDED DECEMBER 31, 2003 AND 2002
2003 2002
-------------------------------------------------------------------------------------------------
Depletion, Depreciation, Amortization and Impairment Expense as Reported (1) 995 632
Less: Dismantlement and Site Restoration (33) (35)
Plus: Asset Retirement Cost Amortization 14 15
Plus: Asset Retirement Obligation Accretion 19 20
-----------------
Depletion, Depreciation, Amortization and Impairment Expense as Restated 995 632
-----------------
Transportation and Other Expense as Reported 461 475
Plus: Unamortized Issue Costs on Redemption of Preferred Securities 28 --
-----------------
Transportation and Other Expense as Restated 489 475
-----------------
Interest Expense as Reported 105 109
Plus: Dividends on Preferred Securities 64 72
-----------------
Interest Expense as Restated 169 181
-----------------
Provision for Future Income Taxes as Reported (1) (42) (15)
Plus: Tax Effect of Changes in Accounting Principles (31) (29)
-----------------
Provision for Future Income Taxes as Restated (73) (44)
-----------------
Note:
(1) Adjusted for discontinued operations.
85
NET INCOME AND EARNINGS PER COMMON SHARE FOR THE YEARS ENDED DECEMBER 31, 2003 AND 2002
2003 2002
----------------------------------------------------------------------------------------------------------------
Net Income Attributable to Common Shareholders
As Reported 599 409
Less: Unamortized Issue Costs on Preferred Securities Redemption, Net of Income Taxes (21) --
--------------------
As Restated 578 409
=====================
Earnings per Common Share ($/share)
Basic as Reported 4.84 3.34
=====================
Restated 4.67 3.34
=====================
Diluted as Reported 4.79 3.30
=====================
Restated 4.63 3.30
=====================
CONSOLIDATED BALANCE SHEET AS AT DECEMBER 31, 2003
FINANCIAL
ARO INSTRUMENTS
AS REPORTED CHANGE CHANGE AS RESTATED
----------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment 4,469 81 -- 4,550
Deferred Charges and Other Assets 153 -- 11 164
Current Portion of Long-Term Debt 291 -- 281 572
Long-Term Debt 2,485 -- 32 2,517
Future Income Tax Liabilities 724 (17) 13 720
Asset Retirement Obligations -- 305 -- 305
Dismantlement and Site Restoration 179 (179) -- --
Preferred and Subordinated Securities 364 -- (364) --
Retained Earnings 1,659 (28) (37) 1,594
Cumulative Foreign Currency Translation Adjustment (119) -- 86 (33)
-------------------------------------------------------
(s) RECLASSIFICATION
Certain information provided for prior years has been reclassified to conform to
the presentation adopted in 2004.
2. BUSINESS ACQUISITION
On December 1, 2004, we acquired 100% of the issued and outstanding share
capital of EnCana (UK) Limited (EnCana UK) from EnCana Corporation (EnCana) for
cash consideration of US$2.1 billion, subject to certain adjustments. EnCana UK
held all of EnCana's offshore oil and gas assets in the North Sea.
We acquired EnCana UK to establish a strategic presence in the North Sea by
acquiring operatorship of the Buzzard field development and operatorship of the
producing Scott and Telford fields. The acquisition also gives us access to
interests in several satellite discoveries and over 700,000 net undeveloped
exploration acres. In addition, we acquired the management and technical teams
that found and are developing the Buzzard discovery. Goodwill paid is
attributable to the established North Sea presence acquired and the knowledge
and business relationships acquired through the management team and employees of
EnCana UK.
86
The acquisition has been accounted for using the purchase method and the results
of EnCana UK have been consolidated with the results of Nexen from December 1,
2004. The following table shows the allocation of the purchase price based on
the estimated fair value of the assets and liabilities acquired:
--------------------------------------------------------------------------
Purchase Price, Net of Cash Acquired:
Cash Paid 2,561
Transaction Costs 22
-------
2,583
=======
Purchase Price Allocated as follows:
Accounts Receivable 310
Inventories and Supplies 11
Other Current Assets 2
Property, Plant and Equipment 3,395
Future Income Tax Assets 239
Goodwill (1) 334
Deferred Charges and Other Assets 12
Accounts Payable and Accrued Liabilities (289)
Asset Retirement Obligations (134)
Future Income Tax Liabilities (1,284)
Deferred Credits and Other Liabilities (13)
-------
Total Purchase Price Allocated 2,583
=======
Note:
(1) The amount of goodwill deductible for tax purposes is nil.
The unaudited pro forma results for the years ended December 31, 2004 and 2003
are shown below as if the acquisition had occurred on January 1, 2003. Pro forma
results are not necessarily indicative of actual results or future performance.
2004 2003
--------------------------------------------------------------------------------
Revenues 4,258 3,642
Net Income 841 595
Earnings Per Common Share - Basic ($/share) 6.54 4.81
Earnings Per Common Share - Diluted ($/share) 6.46 4.75
------------------
3. ACCOUNTS RECEIVABLE
2004 2003
--------------------------------------------------------------------------------
Trade
Marketing 1,452 1,078
Oil and Gas 593 263
Chemicals and Other 57 47
------------------
2,102 1,388
Non-Trade 49 50
------------------
2,151 1,438
Allowance for Doubtful Receivables (15) (15)
------------------
Total Accounts Receivable 2,136 1,423
==================
4. INVENTORIES AND SUPPLIES
2004 2003
--------------------------------------------------------------------------------
Finished Products
Marketing 199 138
Oil and Gas 6 16
Chemicals and Other 13 12
-----------------
218 166
Work in Process 4 6
Field Supplies 129 98
-----------------
Total Inventories and Supplies 351 270
=================
87
5. PROPERTY, PLANT AND EQUIPMENT
2004 2003
------------------------------------------------------------------------------------------------------------------
Accumulated Net Book Accumulated Net Book
Cost DD&A Value Cost DD&A Value
------------------------------------- --------------------------------------------
Oil and Gas
Yemen 678 506 172 656 489 167
Yemen - Carried Interest 1,360 1,044 316 1,242 1,008 234
Canada 3,463 1,615 1,848 2,951 1,460 1,491
United States 2,249 1,037 1,212 2,153 887 1,266
United Kingdom 3,499 16 3,483 -- -- --
Other Countries 535 408 127 534 410 124
Marketing 157 64 93 158 57 101
------------------------------------- --------------------------------------------
11,941 4,690 7,251 7,694 4,311 3,383
Syncrude 1,030 155 875 821 144 677
Chemicals 815 409 406 774 381 393
Corporate and Other 201 90 111 168 71 97
------------------------------------- --------------------------------------------
Total PP&E 13,987 5,344 8,643 9,457 4,907 4,550
===================================== ============================================
The above table includes capitalized costs of $3,945 million (2003 - $630
million) relating to unproved properties and projects under construction or
development. These costs are not being depreciated, depleted or amortized. We
currently have an interest in an exploration block, offshore Nigeria, where
capitalized exploratory costs have been on our balance sheet for longer than one
year. Major capital expenditures are required before production can begin and
additional drilling efforts are underway to fully appraise the block.
Exploratory drilling costs were first capitalized in 1998 and we have
subsequently drilled a further seven successful wells on the block. We are
preparing a field development plan for the block with our partners for
submission to the Nigerian government for approval. Once we obtain this approval
and the project has been sanctioned, we will book proved reserves. Capitalized
costs relating to this exploration block as at December 31, 2004 were $77
million (2003 - $68 million).
Our 2003 depreciation, depletion, amortization and impairment expense in the
Consolidated Statement of Income includes an impairment charge of $269 million
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.
We incurred $35 million (2003 - $20 million) related to research and development
activities. Costs of $26 million (2003 - $14 million) were recorded in other
expense on the Consolidated Statement of Income. The remaining costs have been
deferred and are included in PP&E.
2004 2003
--------------------------------------------------------------------------------
Development Costs Deferred, Beginning of Year 6 --
Deferred in the Year 9 6
Amortized in the Year -- --
-----------------
Development Costs Deferred, End of Year 15 6
=================
88
6. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
(a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE AND FINANCIAL
INSTRUMENTS
The carrying value, fair value, and unrecognized gains or losses on our
outstanding derivatives and long-term financial assets and liabilities at
December 31 are:
(Cdn$ millions) 2004 2003
---------------------------------------------------------------------------------------------------------------------
Carrying Fair Unrecognized Carrying Fair Unrecognized
Value Value Gain/(Loss) Value Value Gain/(Loss)
------------------------------------ -------------------------------------
Commodity Price Risk
Non-Trading Activities
Future Sale of Oil and Gas
Production -- -- -- -- (3) (3)
Crude Oil Put Options 200 200 -- -- -- --
Trading Activities
Crude Oil and Natural Gas 83 83 -- 101 101 --
Future Sale of Gas Inventory -- 6 6 -- (11) (11)
Foreign Currency Risk
Non-Trading Activities 7 7 -- -- (1) (1)
Trading Activities 10 10 -- 5 5 --
------------------------------------ -------------------------------------
Total Derivatives 300 306 6 106 91 (15)
==================================== =====================================
Financial Assets and Liabilities
Long-Term Debt (4,259) (4,503) (244) (3,089) (3,316) (227)
==================================== =====================================
The estimated fair value of all derivative instruments is based on quoted market
prices and, if not available, on estimates from third-party brokers or dealers.
The carrying value of cash and cash equivalents, amounts receivable and
short-term obligations approximates their fair value because the instruments are
near maturity.
(b) COMMODITY PRICE RISK MANAGEMENT
NON-TRADING ACTIVITIES
We generally sell our crude oil and natural gas under short-term market based
contracts.
FUTURE SALE OF OIL AND GAS PRODUCTION
In 2003, we entered into WTI and NYMEX gas forward contracts for a 12-month
period. These forward contracts fixed our oil and gas prices at the contract
prices for the hedged volumes, less applicable price differentials. Since actual
prices during the contract period were higher than the fixed prices we received,
our return was lower than it would have been without these contracts in place.
These contracts expired in March 2004.
CRUDE OIL PUT OPTIONS
We purchased WTI crude oil put options to manage the commodity price risk
exposure of a portion of our oil production in 2005 and 2006. These options
establish an annual average WTI floor price of US$43/bbl in 2005 and US$38 in
2006 at a cost of $144 million. The WTI crude oil put options are stated at fair
value and included in deferred charges and other assets as they settle beyond 12
months of the balance sheet date. Any change in fair value is included in
marketing and other on the Consolidated Statement of Income.
We enter into physical purchase and sales contracts as well as financial
commodity contracts to enhance our price realizations and lock-in our margins.
The physical and financial commodity contracts (derivative contracts) are stated
at market value. The $83 million fair value of the contracts has been recognized
in net income.
FUTURE SALE OF GAS INVENTORY
We have certain NYMEX futures contracts and swaps in place, which effectively
lock-in our margins on the future sale of our natural gas inventory in storage.
We have designated, in writing, some of these derivative contracts as cash flow
hedges of the future sale of our storage inventory. As a result, gains and
losses on these designated futures contracts and swaps are recognized in net
income when the inventory in storage is sold. The principal terms of these
outstanding contracts and the unrecognized gains and losses at December 31, 2004
are:
HEDGED AVERAGE UNRECOGNIZED
VOLUMES MONTH PRICE GAIN
--------------------------------------------------------------------------------------------
(mmcf) (US$/mcf) (Cdn$ millions)
NYMEX Natural Gas Futures 3,740 January 2005 6.825 2
5,660 February 2005 6.53 2
NYMEX Natural Gas Fixed Price Swaps 1,000 January 2005 7.147 1
500 February 2005 6.987 1
-------
6
=======
We designate our US-dollar debt as a hedge against our net investment in
self-sustaining foreign 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. In December 2004, we drew US$1.5 billion against term
credit facilities established for our North Sea acquisition. This amount has
been designated as a hedge of our investment in our self-sustaining foreign
operations.
The foreign exchange gains or losses related to the designated debt are included
in the cumulative foreign currency translation adjustment in shareholders'
equity. Undesignated foreign exchange gains or losses on the November 2003 debt
issues were included in marketing and other prior to the designation of this
debt as a hedging instrument in February 2004. Our net investment in
self-sustaining foreign operations and our designated US-dollar debt at December
31 are as follows:
(US$ millions) 2004 2003
--------------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign Operations 3,973 1,574
US-Dollar Debt 3,315 1,143
-------------------
We also have exposure to currencies other than the US dollar. A portion of our
capital spending on our Long Lake project is denominated in Euros and Japanese
Yen. A portion of our United Kingdom operating expenses and capital spending is
denominated in British Pounds and Euros. 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, 2004, we held a
foreign currency derivative instrument that obligates us and the counterparty to
exchange principal and interest amounts. In November 2006, we will pay US$37
million and receive Cdn $50 million (see Note 7). We have recognized a gain of
$7 million for the fair value of this derivative instrument.
TRADING ACTIVITIES
Our sales and purchases of crude oil and natural gas are generally transacted in
or referenced to the US dollar, as are most of the financial commodity contracts
used by our marketing group. We enter into forward contracts to sell US dollars.
When combined with certain commodity sales contracts, either physical or
financial, these forward contracts allow us to lock-in our margins on the future
sale of crude oil and natural gas. The fair value of our US dollar forward
contracts at December 31, 2004 was $10 million (2003 - $5 million). This fair
value has been recognized in net income and settles within one year.
90
(d) TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES
Amounts related to derivative instruments held by our marketing operation are
equal to fair value as we use mark-to-market accounting, and are as follows at
December 31:
(Cdn $millions) 2004 2003
--------------------------------------------------------------------------------
Accounts Receivable 177 102
Deferred Charges and Other Assets (1) 91 63
-------------------
Total Derivative Contract Assets 268 165
===================
Accounts Payable and Accrued Liabilities 129 34
Deferred Credits and Other Liabilities (1) 46 25
-------------------
Total Derivative Contract Liabilities 175 59
===================
Total Derivative Contract Net Assets 93 106
===================
Note:
(1) These derivative instruments settle beyond 12 months and are considered
non-current.
(e) 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, 2004, fixed-rate borrowings comprised
56% (2003 - 100%) of our long-term debt at an effective average rate of 6.6%
(2003 - 8.2%). During the year we periodically drew on our floating rate
unsecured syndicated term credit facilities. We had no interest rate swaps
outstanding in 2004 or 2003.
(f) CREDIT RISK MANAGEMENT
A substantial portion of our accounts receivable are with counterparties 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 counterparties. We assess the financial
strength of our counterparties, 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, is
routinely reported to our Risk Management Committee. We also use standard
agreements that allow for the netting of exposures associated with a single
counterparty. We believe this minimizes our overall credit risk.
7. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
2004 2003
--------------------------------------------------------------------------------
Acquisition Credit Facilities (US$1.5 billion drawn) (a) 1,806 --
Term Credit Facilities (US$72 million drawn) (b) 87 --
Notes, due 2004 (c) -- 291
Debentures, due 2006 (d) 93 98
Medium Term Notes, due 2007 (e) 150 150
Medium Term Notes, due 2008 (f) 125 125
Notes, due 2013 (US$500 million) (g) 602 646
Notes, due 2028 (US$200 million) (h) 241 258
Notes, due 2032 (US$500 million) (i) 602 646
Subordinated Debentures, due 2043 (US$460 million) (j) 553 594
Preferred Securities, due 2048 (US$217 million) (k) -- 281
----------------
4,259 3,089
Less: Current Portion of Long-Term Debt (c) (k) -- (572)
----------------
4,259 2,517
================
(a) ACQUISITION CREDIT FACILITIES
Nexen has committed, unsecured, non-revolving credit facilities totalling US$2
billion. The credit facilities include a bridge facility in the amount of US$1.5
billion, which was advanced on December 1, 2004 and used to fund a portion of
the purchase price for the acquisition of EnCana (UK) Limited and a development
facility in the amount of US$500 million, which may be drawn upon to finance a
portion of our share of the costs for the development and operation of the
acquired assets.
91
The credit facilities provide that the bridge facility shall not exceed US$750
million by November 2005 with the balance to be repaid by May 2007. The credit
facilities also provide that the development facility be repaid by November
2007, unless this date is extended to May 2008. Optional repayments may be made
by Nexen at any time with notice. Borrowings are available as US-dollar base
rate loans, LIBOR-based loans, Canadian bankers' acceptances and Canadian prime
rate loans. Interest is payable monthly at a floating rate. During 2004, the
weighted average interest rate on the acquisition credit facilities was 3.2%.
Amounts due November 2005 with respect to the bridge facility have not been
included in current liabilities as we are able to refinance this amount with our
term credit facilities, if need be.
(b) TERM CREDIT FACILITIES
Nexen has committed, unsecured, revolving term credit facilities totalling
$1,656 million, $410 million of which is available until 2008 and $1,246 million
until 2009. At December 31, 2004, US$72 million was drawn on these facilities.
The lenders have the option to extend the terms annually. 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 2004, the weighted average interest rate was 3.2% (2003 - 2.0%).
(c) NOTES, DUE 2004
During February 2004, we repaid US$225 million of notes.
(d) 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%.
(e) 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%.
(f) 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%.
(g) 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%.
(h) 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%.
(i) 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%.
92
(j) SUBORDINATED DEBENTURES, DUE 2043
During November 2003, we issued US$460 million of unsecured subordinated
debentures. Interest is payable quarterly in cash at a rate of 7.35% and the
principal is to be repaid in November 2043. 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.
(k) PREFERRED SECURITIES, DUE 2048
During March 1998, we issued US$217 million of preferred securities. The
securities were redeemed at par on February 9, 2004. Interest was payable
quarterly at a rate of 9.375%.
Some of our debt instruments contain covenants with respect to certain financial
ratios and our ability to grant security. At December 31, 2004, we were in
compliance with all covenants.
(n) SHORT-TERM BORROWINGS
Nexen has unsecured operating loan facilities of approximately $349 million, of
which $100 million was drawn (US$83 million) at December 31, 2004. Interest is
payable at floating rates. During 2004, the weighted average interest rate on
our short-term borrowings was 2.9% (2003 - 2.4%).
Capitalized interest relates to and is included as part of the cost of oil and
gas and Syncrude properties. The capitalization rates are based on our
weighted-average cost of borrowings.
8. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with
our property, plant and equipment are as follows:
2004 2003
--------------------------------------------------------------------------------
Balance at Beginning of Year 323 390
Obligations Assumed with Development Activities 12 6
Obligations Assumed with Business Acquisition 134 --
Obligations Discharged with Disposed Properties (4) (27)
Expenditures Made on Asset Retirements (31) (20)
Accretion 17 22
Revisions to Estimates 24 (19)
Effect of Foreign Exchange (7) (29)
-------------------
Balance at End of Year (1) 468 323
===================
Note:
(1) Obligations due within 12 months of $47 million (2003 - $18 million) have
been included in accounts payable and accrued liabilities.
93
Our total estimated undiscounted asset retirement obligations amount to $770
million ($514 million - December 31, 2003). We have discounted the total
estimated asset retirement obligations using a weighted-average, credit-adjusted
risk-free rate of 5.7%. Approximately $121 million included in our asset
retirement obligations will be settled over the next five years. The remaining
obligations settle beyond five years and will be funded by future cash flows
from our operations.
We own interests in assets for which the fair value of the asset retirement
obligations cannot be reasonably determined because the assets currently have an
indeterminate life and we cannot determine when remediation activities would
take place. These assets include our interest in Syncrude's upgrader and sulphur
pile.
The estimated future recoverable reserves at Syncrude are significant and given
the long life of this asset, we are unable to determine when asset retirement
activities would take place. Furthermore, the Syncrude plant can continue to run
indefinitely with ongoing maintenance activities.
The retirement obligations for these assets will be recorded in the first year
in which the lives of the assets are determinable.
9. SHAREHOLDERS' EQUITY
(a) AUTHORIZED CAPITAL
Authorized share capital consists of an unlimited number of common shares of no
par value, and an unlimited number of Class A preferred shares of no par value,
issuable in series.
(b) ISSUED COMMON SHARES AND DIVIDENDS
(thousands of shares) 2004 2003 2002
--------------------------------------------------------------------------------
Beginning of Year 125,606 122,966 121,202
Issue of Common Shares for Cash:
Exercise of Stock Options 2,951 1,964 1,090
Dividend Reinvestment Plan 448 476 500
Employee Flow-through Shares 195 200 174
-------------------------------
End of Year 129,200 125,606 122,966
===============================
Dividends per Common Share ($/share) 0.40 0.325 0.30
===============================
Cash Consideration (Cdn$ millions)
Exercise of Stock Options 93 50 27
Dividend Reinvestment Plan 21 15 17
Employee Flow-through Shares 10 8 7
-------------------------------
124 73 51
===============================
At December 31, 2004, there were 689,937 common shares (2003 - 1,307,305; 2002 -
1,783,968) reserved for issuance under the Dividend Reinvestment Plan.
(c) STOCK OPTIONS
In May 2004, our shareholders approved the modification of our stock option plan
to a tandem option plan by including a cash feature. The tandem options give the
holders a right to either purchase common shares at the exercise price or to
receive cash payments equal to the excess of the market value of the common
shares over the exercise price.
Similar to our stock appreciation rights, we use the intrinsic-value method to
recognize compensation expense associated with our tandem options. Obligations
are accrued on a graded vesting basis and represent the difference between the
market value of our common shares and the exercise price of the options. The
obligations are revalued each reporting period based on the change in the market
value of our common shares and the number of graded vested options outstanding.
Upon modification of the stock option plan, we were required to recognize an
obligation for our tandem options. This obligation represented the difference
between the market value of our common shares and the weighted-average exercise
price of the options. As a result, we recognized an obligation of $85 million
for the graded vested portion of the 6.3 million outstanding options on June 30,
2004. In the second quarter, a one-time, non-cash charge of $82 million was
included in general and administrative expense, net of $3 million previously
expensed in respect of our original stock options.
94
Following the introduction of the AMERICAN JOB CREATION ACT OF 2004 in the US,
stock options awarded to our US employees on or after December 1, 2004 do not
include a tandem option cash feature. We use the fair-value method to recognize
compensation expense associated with these options. The expense is recognized
over the vesting period of the options with a corresponding increase to
contributed surplus. This resulted in compensation expense in 2004 of $0.1
million which was included in general and administrative expense.
We have granted options to purchase common shares to directors, officers and
employees. Each option permits the holder to purchase one Nexen common share at
the stated exercise price. Options granted prior to February 2001 vest over 4
years and are exercisable on a cumulative basis over 10 years. Options granted
after February 2001 vest over 3 years and are exercisable on a cumulative basis
over 5 years. At the time of grant, the exercise price equals the market price.
The following options have been granted:
2004 2003 2002
----------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Options Price Options Price Options Price
------------------------------------------------------------------------------------------------------------------------------
(thousands) ($/option) (thousands) ($/option) (thousands) ($/option)
BALANCE AT BEGINNING OF YEAR 9,203 34 9,476 30 8,831 30
Granted 2,112 51 1,877 44 1,788 31
Exercised for stock (2,951) 30 (1,964) 28 (1,090) 25
Surrendered for cash (144) 34 -- -- -- --
Forfeited (82) 33 (186) 32 (53) 30
----------------------------------------------------------------------------
BALANCE AT END OF YEAR 8,138 39 9,203 34 9,476 30
============================================================================
OPTIONS EXERCISABLE AT END OF YEAR 4,227 34 5,067 30 5,113 29
----------------------------------------------------------------------------
COMMON SHARES RESERVED FOR ISSUANCE
UNDER THE STOCK OPTION PLAN 9,586 9,788 9,760
----------------------------------------------------------------------------
The range of exercise prices of options outstanding and exercisable at December
31, 2004 is as follows:
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)
$15.00 to $19.99 132 18 4 132 18
$20.00 to $24.99 182 24 2 182 24
$25.00 to $29.99 768 27 4 641 27
$30.00 to $34.99 1,772 33 3 1,326 33
$35.00 to $39.99 1,330 36 6 1,324 36
$40.00 to $44.99 1,850 43 4 622 43
$45.00 to $49.99 25 48 4 -- --
$50.00 to $54.99 2,079 51 5 -- --
-------------------------------------- --------------------------
Total options 8,138 4,227
============= ============
In previous periods, we estimated the fair value of stock options issued using
the Generalized Black-Scholes option pricing model under the following
assumptions:
2003 2002
------------------------------------------------------------------------------------------------------------------------------
Weighted-Average Fair Value ($/option) 10.10 9.08
Risk-Free Interest Rate (%) 3.6 3.6
Estimated Hold Period Prior to Exercise (years) 3 3
Volatility in the Price of Nexen's Common Shares (%) 30 35
Dividends per Common Share ($/share) 0.40 0.30
--------------------------
95
The following shows pro forma net income and earnings per common share had we
applied the fair-value method to account for all stock options outstanding that
were granted up to December 31, 2002. Stock options granted after that date have
been expensed as general and administrative costs.
2003 2002
------------------------------------------------------------------------------------------------------------------------------
Fair Value of Stock Options Granted 25 22
Less: Fair Value of Stock Options Expensed (1) --
-------------------------
24 22
Net Income Attributable to Common Shareholders
As Reported 578 409
-------------------------
Pro Forma 554 387
=========================
Earnings Per Common Share ($/share)
Basic as Reported 4.67 3.34
=========================
Pro Forma 4.48 3.16
=========================
Diluted as Reported 4.63 3.30
=========================
Pro Forma 4.44 3.13
=========================
(d) STOCK APPRECIATION RIGHTS
Under our stock appreciation rights (StARs) 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. At the time of grant, the exercise price equals the market price.
The following stock appreciation rights have been granted:
2004 2003 2002
------------------------- ------------------------ -------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
StARs Price StARs Price StARs Price
------------------------------------------------------------------------------------------------------------------------------
(thousands) ($/right) (thousands) ($/right) (thousands) ($/right)
BALANCE AT BEGINNING OF YEAR 2,404 37 1,812 33 915 31
Granted 1,304 51 1,017 43 908 34
Exercised for cash (433) 33 (363) 32 (3) 31
Forfeited (57) 37 (62) 32 (8) 31
---------------------------------------------------------------------------
BALANCE AT END OF YEAR 3,218 43 2,404 37 1,812 33
===========================================================================
RIGHTS EXERCISABLE AT END OF YEAR 1,011 36 495 33 306 31
---------------------------------------------------------------------------
The range of exercise prices of stock appreciation rights outstanding and
exercisable at December 31, 2004 is as follows:
Outstanding StARs Exercisable StARs
------------------------------------------------------------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Number of Exercise Years to Number of Exercise
StARs Price Expiry StARs
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