200 8 ann ual rep ort
the premium value defined growth independent
value creation n return on capital n low-cost producer n return on assets
canadian natural 2008 a n n u a l r ep ort
general information
performance highlights
4
6
letter to shareholders
10 our team advantage
12 world-class assets
14 operations defined
26 marketing
29
health & safety, environment & community
34 year-end reserves
40 management’s discussion and analysis
71 management’s report
72
management’s assessment of internal
control over financial reporting
independent auditors’ report
72
74 consolidated financial statements
78
notes to the consolidated financial
statements
101 supplementary oil & gas information
106 ten-year review
108 corporate information
company definition
cautionary statements
throughout the annual report, canadian natural resources
limited is referred to as “us”, “we”, “our”, “canadian natural”,
or the “company”.
currency
All amounts are reported in Canadian currency unless otherwise stated.
abbreviations
AECO
AIF
API
bbl
bbl/d
bcf
bcf/d
boe
boe/d
Bitumen
Alberta natural gas reference location
Annual Information Form
Specific gravity measured in degrees on the
American Petroleum Institute scale
barrels
barrels per day
billion cubic feet
billion cubic feet per day
barrels of oil equivalent
barrels of oil equivalent per day
Extra heavy crude oil, generally more dense
than 14º API
Canadian dollars
Compound Annual Growth Rate
Capital expense
Coal Bed Methane
Carbon Dioxide
Carbon Dioxide Equivalents
Cyclic Steam Stimulation
Enhanced Oil Recovery
Floating Production, Storage and Offtake Vessel
Greenhouse Gas
C$
CAGR
CAPEX
CBM
CO2
CO2e
CSS
EOR
FPSO
GHG
Horizon Project Horizon Oil Sands Project
LNG
mbbl
mbbl/d
mboe
mboe/d
mcf
mcf/d
mmbbl
mmboe
mmbtu
mmcf/d
NGLs
NYMEX
NYSE
OOIP
SAGD
SCO
SEC
tcf
TSX
UK
US
USGC
US$
WCS
WCSB
WTI
Liquid natural gas
thousand barrels
thousand barrels per day
thousand barrels of oil equivalent
thousand barrels of oil equivalent per day
thousand cubic feet
thousand cubic feet per day
million barrels
million barrels of oil equivalent
million British thermal units
million cubic feet per day
Natural gas liquids
New York Mercantile Exchange
New York Stock Exchange
Original Oil In Place
Steam Assisted Gravity Drainage
Synthetic light crude oil
US Securities and Exchange Commission
trillion cubic feet
Toronto Stock Exchange
United Kingdom
United States
United States Gulf Coast
United States dollars
Western Canadian Select crude oil blend
Western Canadian Sedimentary Basin
West Texas Intermediate
Certain information regarding the Company contained herein may
constitute forward-looking statements under applicable securities
laws. Such statements are subject to known or unknown risks and
uncertainties that may cause actual results to differ materially from
those anticipated or implied in the forward-looking statements.
Please refer to page 40 for the complete special note regarding
forward-looking statements.
All production and sales statistics represent Canadian Natural’s
working interest amounts before deduction of royalties unless
stated otherwise. Where volumes are reported in barrels of oil
equivalent (“boe”), natural gas is converted to oil at six thousand
cubic feet per barrel. This conversion may be misleading, particularly
when used in isolation, since the 6 mcf:1 bbl ratio is based on an
energy equivalency at the burner tip and does not represent the
value equivalency at the well head. Methodologies for determining
annual reserves are described on pages 34 to 39. This report also
includes references to financial measures commonly used in the
oil and gas industry that are not defined by Generally Accepted
Accounting Principles (“GAAP”). The Company uses these measures
to evaluate its performance, however they should not be considered
an alternative to or more meaningful than net earnings.
Canadian Natural may disclose contingent resources as additional
information. These are internal estimates that utilize the definition
within section 5 of the Canadian Oil & Gas Evaluation Handbook
as prescribed under NI 51-101. Contingent resources are defined
as those quantities of petroleum estimated, as of a given date,
to be potentially recoverable from known accumulations using
established technology or technology under development, but
which are not currently considered to be commercially recoverable
due to one or more contingencies. Additionally engineering and
geotechnical appraisal through drilling, testing and/or production
is required before the contingent resources can be classified as
reserves. There is no certainty that any portion of the resources will
be commercially viable to produce.
metric conversion chart
to
cubic metres
cubic metres
metres
kilometres
hectares
tons
to convert
barrels
thousand cubic feet
feet
miles
acres
tonnes
multiply by
0.159
28.174
0.305
1.609
0.405
1.102
value creation
our business approach
CAN ADIAN NATURAL 2 008 AN NUAL R EPORT
CANAD IAN NATURAL 2 0 08 AN NUAL R EPORT
Canadian Natural’s dedicated leadership
and disciplined corporate strategy provide
a strong foundation for the Company’s
future and for shareholder value.
Our objective and strategy have remained consistent over the last
twenty years and are as relevant today as they were in the past.
The breadth of our asset base provides the Company with the
ability to effectively allocate capital to maximize returns.
The Company’s value creation over the last twenty years
was achieved by following some basic principles as
articulated below. Maintaining discipline is diffi cult, but
Canadian Natural has proven that it is possible.
Drive to be the low cost producer – this is an important element to the strategy. We strive to
be the lowest cost producer in every product and basin in which we operate. Over the long run we
believe that only the lowest cost producers will continue to generate economic returns throughout
the cycle – the rest will be forced to divest their assets to the stronger competitors. We are a very
strong competitor.
Focus on exploitation – we view this as a low-risk approach to value creation as emphasis is
placed on maximizing the value of already discovered resource versus trying to fi nd the next major
pool. We use proven new technologies, our own discoveries, and new industry fi ndings to effectively
“lead the followers”. This ever-increasing industry knowledge is maximized across our large developed
and undeveloped land holdings, creating even more upside potential.
Augment exploitation with strategic acquisitions – the combination of our lower cost
profi le and our extensive exploitation-based focused on the basins we operate, make us a natural
consolidator of properties throughout our core regions. Often counter-cyclical, our major acquisitions
have made us a stronger and more diverse company. Most of these major acquisitions were comprised
of a strong footing in our core regions but also provided entry into a new strategic basin.
Maintain fl exibility and control allocation of capital – we strive to operate and own
100% of our assets. This allows us to start up or shut down drilling programs on very short notice –
facilitating an ever-vigilant weekly allocation of capital by the Management Committee. Simultaneously,
when practical we avoid committing ourselves into long term drilling or supply contracts.
Strive for balance – we believe that balance between natural gas, heavy crude oil and light crude
oil provide some diversifi cation from commodity price risk while also facilitating more options with
which to allocate capital to the highest return projects. Balance between short, medium and long
term projects also provides more visibility to future growth initiatives.
Maintain fi nancial strength – maintaining a strong balance sheet and access to capital markets
is integral to delivering our plan. We target strong investment grade debt ratings and manage our
liquidity as a core asset – particularly important in these current times. We augment these plans with
a disciplined hedge program which strives to provide cash fl ow certainty in the short term, such that
the capital plans made by the Company are prudently fi nanceable.
CANADIAN NATURAL
1
2
CANADIAN NATURAL
20 years of history
Production (boe/d)
WTI (US$/bbl)
CNQ Share price (C$-TSX)
Crude oil
price rises
80%
Crude oil
price drops
55%
Crude oil
price rises
155%
Crude oil
price drops
35%
Crude oil
price rises
600%
Horizon Project Construction
Crude oil
price drops
70%
(boe/d)
700,000
600,000
500,000
400,000
300,000
200,000
100,000
($)
160
140
120
100
80
60
40
20
Dec. 88
Dec. 90
Dec. 92
Dec. 94
Dec. 96
Dec. 98
Dec. 00
Dec. 02
Dec. 04
Dec. 06
Dec. 08
1989
1991
1993
1996
2000
2002
2005
Shallow gas basin of Alberta
was the modern iteration of the
Company’s birthplace and is still a
major contributor to our success.
Even in today’s world, and despite
the challenges of Alberta’s new
royalty framework, conventional
and shallow natural gas drilling
can generate signifi cant returns
as we leverage our strong land
position with new technology.
Northeast British Columbia
natural gas basin was entered,
providing early knowledge and a
leading position into this prolifi c
basin. Canadian Natural became a
major natural gas producer in
British Columbia through
acquisition and drilling. Advances
in technologies and new resource
plays such as Montney Shale gas
means that this area will continue
to be a major growth driver for
the foreseeable future.
Heavy crude oil operations
were new to Canadian Natural
following the acquisition of
primary heavy crude oil lands in
1993. We took our time and
developed an expertise in these
operations. This allowed us to
intelligently acquire and expand
our holdings. Today, we are a
recognized leader leveraging
technology to further grow and
recover crude oil. Fields such as
Pelican Lake will continue to add
signifi cant value to shareholders
for years to come.
Thermal heavy crude oil
properties were purchased by
Canadian Natural. As one of the
initial entrants in the fi eld we
were better able to understand
and economically bid on asset
packages including the landmark
acquisition in 1999 where the
majority of our thermal and
Horizon Project mining properties
were acquired.
Today we are a leader in thermal
crude oil developments and
have a clearly defi ned plan
for future growth.
International offshore properties
were fi rst acquired as part of a
larger transaction. The acquired
package included numerous,
fractional interests around the
world. We carefully rationalized
the assets in accordance with our
strategy and expertise. The North
Sea represents a mature basin
where we look to acquire assets
and economically extend fi eld lives
– the same approach used in
Western Canada. Offshore West
Africa provides the opportunity
for exploration and exploitation
growth while leveraging our
offshore expertise.
Deep gas basin of Northwest
Alberta was initially acquired as
part of a larger acquisition and
further augmented by other
acquisitions. We leveraged our
knowledge and expertise between
British Columbia and Northwest
Alberta to make both areas
stronger. Although challenged by
Alberta’s new royalty framework
(which makes many other prospects
in this area uneconomic), we are
excited about the area’s potential.
This area is home to numerous
resource plays and shale gas
opportunities and is a part of our
future growth story.
Oil sands mining construction of
the Horizon Project began in 2005
with the fi rst phase completed in
early 2009. We plan to expand
production of this world-class
asset base with a target synthetic
crude oil rate of 500,000 bbl/d.
our assets
Natural gas
A low-risk growth story
Effective leadership
A story of discipline and experience
With higher returns continuing to be found in crude oil projects,
natural gas production for Canadian Natural has declined over the
past couple of years. It still remains our largest single product
offering, representing 44% of our total oil equivalent production.
We balance the development of this low-risk conventional assets
with the development of our key growth projects such as the Deep
Basin, and the Montney and Muskwa shales.
The development of our assets is based on effi cient capital allocation.
Therefore, natural gas drilling activity will increase when relative
returns and netbacks are equivalent to or better than crude oil.
Thermal heavy crude oil
A visible growth story
Within 13 years of operating experience, Canadian Natural has
one of the longest track records of operating thermal properties in
Canada. We have an extensive asset base and a disciplined
approach to the development of new pools that seeks to minimize
geological risk and maximize use of new technologies.
Our extensive asset base will facilitate the eventual development
of 285,000 bbl/d of new heavy crude oil over the next several
years. We target to develop these assets in an economically
prudent and environmentally sustainable way.
Heavy crude oil and Pelican Lake
An exploitation story
As one of the largest heavy crude oil producers in Canada we have
a portfolio of conventional assets that provide reliable and
sustainable production with good returns on capital.
At Pelican Lake, our polymer fl ood will add millions of barrels of
new reserves at very low development and lifting costs, creating
signifi cant value for Canadian Natural’s shareholders.
The Management Committee exemplifi es the maxim that a team can make better decisions
than the individual. Capital is diligently allocated based upon returns, time frame, fi nancial
capability, marketing and expiries or set-up potential, and other relevant considerations.
LEADERSHIP
PEOPLE
OIL
SANDS
MINING
Marketing
A story of being proactive
We proactively develop the market. Our fi rst heavy crude oil blending
initiative was a major success that allowed more refi neries within our
existing markets to take our crude oil. Another signifi cant success was
expanding heavy crude oil conversion capacity in our geographic
markets. We are also expanding our geographic reach via supporting
new pipelines, such as the Pegasus and Keystone XL.
Horizon project
A legacy asset for decades to come
The fi rst phase of Canadian Natural’s Horizon Project is capable of
producing from existing proved and probable reserves for decades.
This translates to meaningful generation of cash fl ow for decades. This
“annuity” will fund ongoing growth throughout the Company.
We are evaluating expansions which will lead to approximately
500,000 bbl/d of light, sweet synthetic crude oil production. In all, we
believe that up to 8 billion barrels of reserves and contingent resources
are recoverable via open pit mining techniques.
HEAVY
OIL
International
A story of light crude oil growth
THERMAL
OIL
INTERNATIONAL
MARKETING
NATURAL
GAS
With operations in the United Kingdom portion of the North Sea and in
Offshore West Africa, we enjoy a stable and committed source of light
crude oil production. We continue to develop our international assets
with a cautious and cost conscious approach, optimizing facilities and
managing our infrastructure. We are utilizing our United Kingdom
expertise in our Offshore West Africa development opportunities.
our metrics
CANAD IAN NATURAL 2 00 8 AN NUAL REPORT
performance highlights
The success of our corporate business strategies
are measured by four metrics that demonstrate
consistent performance.
Daily production per 10,000 shares
(boe/d)
Gross reserves per share (1)
(boe)
Crude oil
Natural gas
Mining SCO
Crude oil
Natural gas
12
10
8
6
4
2
0
FINANCIAL ($ millions, except per share data)
Revenue, before royalties
Net earnings
Per common share – basic and diluted
Adjusted net earnings from operations (1)
Per common share – basic and diluted
Cash flow from operations (2)
Per common share – basic and diluted
Capital expenditures, net of dispositions
Long-term debt (3)
Shareholders’ equity
OPERATING
Daily production, before royalties
Crude oil and NGLs (mbbl/d)
North America
North Sea
Offshore West Africa
Natural gas (mmcf/d)
North America
North Sea
Offshore West Africa
Barrels of oil equivalent (mboe/d)
2008
2007
2006
$
$
$
$
$
$
$
$
$
$
16,173
4,985
9.22
3,492
6.46
6,969
12.89
7,451
13,016
18,374
$
$
$
$
$
$
$
$
$
$
244
45
27
316
1,472
10
13
1,495
565
$
$
$
$
$
$
$
$
$
$
12,543
2,608
4.84
2,406
4.46
6,198
11.49
6,425
10,940
13,321
247
56
28
331
1,643
13
12
1,668
609
11,643
2,524
4.70
1,664
3.10
4,932
9.18
12,025
11,043
10,690
235
60
37
332
1,468
15
9
1,492
581
98
99
00
01
02
03
04
05
06
07
08
98
99
00
01
02
03
04
05
06
07
08
Cash flow from operations per share (2)
Conventional pretax
net asset value per share (3)
(1) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation of this measure is discussed
in the Management’s Discussion and Analysis (“MD&A”).
(2) Cash fl ow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company’s ability to fund capital reinvestment and repay
debt. The derivation of this measure is discussed in the MD&A.
(3) Includes the current portion of long-term debt.
$80
$70
$60
$50
$40
$30
$20
$10
$0
98
99
00
01
02
03
04
05
06
07
08
98
99
00
01
02
03
04
05
06
07
08
(1) Based on constant price and costs.
(2) Cash fl ow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company’s ability to fund capital reinvestment and
repay debt. The derivation of this measure is discussed in the MD&A.
(3) Escalated pricing. Based upon 10% discounted, forecast price pre-tax proved and probable net present values as reported in the Company’s AIF for conventional
reserves, with $250/acre added for core undeveloped land in 2005, 2006, 2007 and 2008, $75/acre for all years prior, less long-term debt and adjustments for
working capital. Excludes Horizon Project SCO mining reserves. Refer to the “Year-End Reserves” section of the Annual Report.
Cash flow from operations
(C$ millions)
Total production, before royalties
(mboe/d)
08
07
06
05
04
6,969
6,198
4,932
5,021
3,769
08
07
06
05
04
565
609
581
553
514
CA NA DIAN N ATURAL
3
4
CANADIAN NATURAL
12
10
8
6
4
2
0
$15
$12
$9
$6
$3
$0
ca na dia n natu ral 2008 a nn u a l r epo rt
Drilling activity (1)
North America
North Sea
Offshore West Africa
Core undeveloped landholdings (thousands of net acres)
North America
North Sea
Offshore West Africa
Company gross proved reserves (2) (before royalties)
Conventional crude oil and NGLs (mmbbl)
North America
North Sea
Offshore West Africa
Conventional natural gas (bcf)
North America
North Sea
Offshore West Africa
Barrels of oil equivalent (mmboe)
Company net proved reserves (2) (after royalties)
Conventional crude oil and NGLs (mmbbl)
North America
North Sea
Offshore West Africa
Conventional natural gas (bcf)
North America
North Sea
Offshore West Africa
Barrels of oil equivalent (mmboe)
Net oil sands proved mineable reserves (2) (after royalties)
Synthetic crude oil (3) (mmbbl)
2008
984
3
3
990
11,603
258
192
12,053
1,057
256
157
1,470
4,077
67
107
4,251
2,178
948
256
142
1,346
3,523
67
94
3,684
1,960
1,946
2007
1,060
4
4
1,068
12,160
287
192
12,639
1,084
311
148
1,543
4,275
81
79
4,435
2,282
920
310
128
1,358
3,521
81
64
3,666
1,969
1,761
2006
1,351
8
4
1,363
12,785
299
192
13,276
1,043
299
145
1,487
4,507
37
69
4,613
2,256
887
299
130
1,316
3,705
37
56
3,798
1,949
1,596
(1) Excludes net stratigraphic test and service wells.
(2) Based on constant prices and costs.
(3) SCO reserves are based upon upgrading of the bitumen volumes using technologies implemented at the Horizon Project.
Company gross conventional proved reserves
(before royalties (2), mmboe)
Closing TSX share price
(C$/share, adjusted for 2004 and 2005 share splits)
08
07
06
05
04
2,178
2,282
2,256
08
07
06
05
04
1,804
1,674
48.75
72.58
62.15
57.63
25.63
CA NA DIAN NATURAL
5
“Our team continually targets cost effective alternatives to develop
our portfolio of projects and to deliver our defi ned growth plan,
thereby creating value for shareholders.”
allan p. markin
CHAIRMAN
OF THE BOARD
canadian natural 2 008 a n n u a l r e p ort
letter to shareholders
Canadian Natural’s goal is to run our business and run it well, executing on our projects and
creating value for our shareholders. That is what we have focused on for the past 20 years, and it
is what we continue to focus on.
Our world-class asset base is strong and balanced. We have crude oil and natural gas conventional
operations in domestic and international basins, along with North America’s most recent oil sands
mining operation. We have the depth of knowledge and experience, with the right people in the
right place at the right time. Our defi ned growth plan allows us to create value for our shareholders,
even in uncertain economic times.
business environment
2008 was a year characterized by commodity price volatility and uncertainty within the capital markets. During the fi rst half of 2008,
crude oil prices reached record levels. By the second half of the year, crude oil pricing faced a massive correction as demand
declined worldwide due to the global recession. The year saw a historically narrower heavy crude oil differential, which led to
record high netbacks in heavy crude oil – an area where we hold a substantial position in.
Natural gas prices remained relatively weak much of the year, refl ecting increased production from the US, along with very high
storage levels in both the US and Canada. These volumes were offset slightly by a decline in Canadian natural gas production.
Drilling and service cost pressure did not respond in kind with the weaker relative natural gas pricing and we continued to
experience price infl ation in the natural gas drilling services sector essentially facing a low price, high cost environment. We also
experienced infl ationary pressures in the crude oil drilling services sector but these were partially offset – at least for awhile – by
strong crude oil pricing.
strategy – our approach to the business
Each phase of the business cycle presents its own unique challenges and rewards. The Company strives to capture opportunity
from each one and has been able to grow into a stronger, more robust company as a result. Canadian Natural has a history of value
creation as seen through our commitment to growing the four metrics to which we steward – production per share, conventional
reserves per share, cash fl ow per share and conventional pre-tax net asset value per share.
Our approach to our business does not change based on commodity prices or business cycle. It is proven and effective, and serves as
a testament to the strength and depth of the Company. Our fundamental approach to business is to maximize value through effi cient
capital allocation. This is key to our success. Further, we remain balanced in all facets of our business. We balance our product mix
with projects in both natural gas and crude oil while balancing project time horizons with near, mid and long-term projects. We
achieve production growth through our defi ned growth strategy, incorporating exploitation and exploration, along with strategic
acquisitions. We dominate our core areas through area knowledge, infrastructure and land base, ultimately assisting in cost control.
For the vast majority of our assets we own and operate nearly 100% and as such have control over capital allocation.
This year more than ever, our strategy was put to the test and in a challenging and uncertain business environment, it has served
us well. This tells us we are taking the right approach.
6
CANAD IA N NATU RAL
“The economic environment for our Company has changed;
however, our fl exible approach to capital allocation allows us to
take advantage of opportunities that arise, regardless of the
business cycle.”
n. murray edwards
VICE-CHAIRMAN
OF THE BOARD
ca na dia n natu ral 2008 a nn u a l r epo rt
north america crude oil
Throughout the year we saw great success in North America crude oil, particularly in our heavy crude oil assets. We remain a
leading producer of crude oil and NGLs with extensive positions in primary heavy and thermal crude oil production in western
Canada and are an industry leader in maximizing netbacks in these areas. We are a low cost producer and are in an enviable
position to continue to grow production through our thermal heavy crude oil development plan. We take a measured and
methodical approach in the development of these assets and in doing so, we are able to remain cost focused and disciplined in our
execution. The economics of this play type remain one of the most attractive in the Company even at lower commodity prices.
As part of our heavy crude oil development plan, the Primrose East expansion was completed in 2008, ahead of schedule and on
budget. This 100% owned project added an incremental 40,000 bbl/d of thermal crude oil production capacity to the Company.
The robust economics for heavy crude oil carries over into our Pelican Lake assets. The conversion from water fl ood to polymer fl ood
continued throughout the year as we see enhanced crude oil recovery as the optimal solution for the majority of the reservoir.
Our heavy crude oil production in Western Canada is balanced with light crude oil. We have that expertise and focus on optimizing
our light crude oil fi eld operations and water fl ood techniques. We look to other enhanced oil recovery processes for light crude
oil, including CO2 fl ooding, polymer fl ooding and alkaline surfactant fl ooding. All of these technologies look promising and, we
will continue to work to develop these commercial operations.
north america natural gas
Canadian Natural holds the largest undeveloped land base in Western Canada with exposure to conventional, unconventional,
resource and exploration play types. We are Canada’s second largest producer of natural gas with a vast and strategic infrastructure
that we leverage to achieve cost control.
Our natural gas strategy is based on allocating capital between low-risk conventional assets and development of new natural gas
resources. Conventional exploitation provides low-risk, solid returns and reliable cash fl ow, and continues to be an important part
of our balanced portfolio. However, a large portion of our future resource additions will be sourced from key unconventional
projects in our Deep Basin area, along with the Montney and Muskwa shale plays. We are well positioned for short, mid and long-
term value growth.
The economics of natural gas continued to be challenging throughout the year, and as near term returns for heavy crude oil
projects remain more attractive than natural gas, we will continue to decrease our natural gas drilling program going forward. We
will increase production in natural gas when we see economic returns. Our strategy for 2009 is to set ourselves up for the future,
countering land expiries and competitive drainage issues with strategic drilling and a focus on reducing costs within the Western
Canadian Sedimentary Basin. We have the fl exibility to allocate capital and the assets to either slow down or accelerate development,
depending on commodity pricing and cost structure.
CA NA DIAN NATURAL
7
“Our fi nancial discipline, commitment to a strong balance sheet,
and high capacity to internally generate cash fl ows provide us the
means to grow our company in the long term.”
John g. langille
VICE-CHAIRMAN
OF THE BOARD
canadian natural 2 008 a n n u a l r e p ort
international
Our international assets provide a reliable, low-risk source for continued light crude oil production. We continue to capitalize on
our core competency of mature basin exploitation in the North Sea and Offshore West Africa provides development opportunities
with signifi cant exploration upside. We capitalize on our relationships that we have developed with stakeholders over the past few
years and leverage our technical and operational expertise from the North Sea to our basins in Offshore Côte d’Ivoire and
Offshore Gabon.
In the North Sea, we operate 90% of our assets with an average working interest of over 80%. We have expertise in managing
aging infrastructure and mature basin exploitation necessary to maximize long-term value creation. We leverage our technical
teams in Offshore West Africa where we operate 100% of our assets and have a number of projects under development. In
Offshore Côte d’Ivoire at Baobab, we have returned to the fi eld for a one year drilling window to boost production following well
failures in 2006. We now have three wells re-drilled with a fourth well underway. At Espoir, we are currently upgrading our FPSO
and will continue with an infi ll drilling program. In Offshore Gabon at Olowi, we are targeting to deliver fi rst crude oil in early 2009
and will continue to drill the remaining wells to reach targeted production.
horizon proJect – oil sands mining
The Horizon Project is a world-class asset providing cash fl ow for years to come. Phase 1 of the Horizon Project includes bitumen
mining and an integrated upgrader. Construction on Phase 1 was completed in early 2009 with fi rst production of synthetic crude
oil achieved on February 28, 2009 – a historic milestone for Canadian Natural. We faced numerous challenges and infl ationary
pressures during the planning, construction and commissioning stages of this project. The total construction costs for Phase 1 were
approximately $9.7 billion, or $88,182 per fl owing barrel of capacity which comes in well below the industry average for current and
future projects with similar facilities. First synthetic crude oil was achieved approximately fi ve months beyond the initial target we set
upon project sanctioning in 2005. Although the cost and schedule experienced some over run, the fi rst phase of the Horizon Project
was built in an extremely volatile and infl ationary business environment and in that respect, it is a job well done.
As fi rst crude oil has been achieved, our focus now is on delivering full production capacity for Phase 1 and leveraging our expertise
and infrastructure to future expansions. These expansions have been broken out into four tranches or smaller projects that will
ultimately lead to enhanced project and cost control. Tranche 1 of the expansion was completed during 2007. Future tranches of
the expansion are currently being re-profi led, taking project control to the next level. We will not build future expansions in a high
cost environment for a moderate price world.
8
CANAD IA N NATU RAL
“The cornerstone of Canadian Natural’s successful strategy is
ensuring we are a low-cost producer. This cost advantage, coupled
with our diverse portfolio of assets and talented workforce,
facilitates strong economic returns for shareholders.”
steve w. laut
PRESIDENT &
CHIEF OPERATING OFFICER
ca na dia n natu ral 2008 a nn u a l r epo rt
financial strength
As with the rest of our operations, our financial objectives remain the same regardless of business environment – to maintain a
strong balance sheet, maintain strong credit ratings, finance operations with a flexible capital structure, and create value. We
remain committed to financial discipline and a flexible capital allocation process, developing only those projects with the highest
returns. This process leads to a large inventory of high quality opportunities.
Commodity price volatility is a part of the resource industry and as such we protect our cash flow from operations with a risk
management program that includes proactively managed commodity price hedging. As a result, we remain flexible regardless of
the business cycle and do not compromise our business strategies. Our approach allows us to manage the conditions inherent to
the exploration and production business – volatility of commodity prices, demands of the capital markets, ability to capitalize on
our asset base and acquisition opportunities.
We are able to generate free cash flow from every one of our business segments and manage our cash flow in a number of ways. A
certain amount is required to maintain property and production growth. We focus on managing debt levels to our targets and returns
to our shareholders. And lastly, we continue to develop our significant and diverse asset base providing for long-term growth.
We increased our dividend in 2008, the ninth consecutive year. This recognizes the stability of our cash flow and ensures a cash return to
our shareholders.
the canadian natural advantage
We control the allocation of our capital and remain disciplined. Our management philosophy is strong and balanced, just as the
rest of our business. Going forward, we will capture opportunities and create value through this challenging part of the business
cycle. We have done it in the past and we will do it again.
We are in a position that allows us to be flexible due to our extensive land base and inventory of prospects in both crude oil and
natural gas. Our strategy allows us to prepare for the future. As we have said time and again, all assets end up in the hands of the
low-cost producer and in tough economic times, the low-cost producer has the advantage. It is no coincidence that Canadian
Natural is a low-cost producer. We have that advantage.
allan p. markin
CHAIRMAN
OF THE BOARD
n. murray edwards
VICE-CHAIRMAN
OF THE BOARD
John g. langille
VICE-CHAIRMAN
OF THE BOARD
steve w. laut
PRESIDENT &
CHIEF OPERATING OFFICER
CA NA DIAN NATURAL
9
canadian natural 2 008 a n n u a l r e p ort
our team advantage
Lonnie Abadier, Walday Abeda, Darren Acheson, Belinda Adams, Janine Adams, Mike Adams, Debra Addinall, Adetokunbo Adebayo, Yemisi Adebayo, Richald Adzabe Ella, James Agate, Gerardo Aguirre, Miguel Aguirre, Sarshar Ahmad, Nadia Ahmed, Pervez Ahmed,
Salman Ahmed, Sarah Aho, Dong Ai, Garrisen Ailsby, Travis Ailsby, Kristy Aitken, Sina Akinsanya, Mounir Al Halabi, Joseph Albano, Suhaib AlDhabbi, Bruce Alexander, Gregory Alexander, Joseph Alexander, Vincent Alexander, Daniel Alfred, Elena Algazina,
Mohieddin Alghazali, Arshad Ali, Catriona Allan, David Allan, John Allan, Geoff Allen, Jill Allen, John Allen, Trent Allen, Simon Allerton, Simon Allerton, Devin Allibone, Karen Almadi, Jocelyn Alonso, Khaled Alsouqi, Arturo Alvarez, Diane Amalaman, Gregory Amalia,
Joann Aman, Traore Amara, Jonah Amedu, Sharareh Ameripour, Donald Ames, Sylvia Anaka, Jan Andersen, Troy Andersen, Allan Anderson, Georgina Anderson, Jeremy Anderson, Kelvin Anderson, Kristin Anderson, Leonard Anderson, Linsey Anderson, Perri
Anderson, Richard Anderson, Sarah Anderson, Steve Anderson, Peter Andrekson, Janet Andrew, Bob Andrews, Todd Andrews, Evan Angel, Carlo Angeles, Carolyn Angus, Shehzad Anjum, Jarid Annis, Stuart Annis, Greg Anstey, Helen Antle, Kathy Antonishyn, Shelley
Antonuk, Brandon April, Richard April, Luc Arbour, John Argan, Humberto Arias, Juan Arizaleta, James Arkley, Anthony Armstrong, Darryl Armstrong, Randall Armstrong, Rob Armstrong, Colin Arnold, Keith Arnold, Monique Arsenault, Paul Arsenault, Bala
Arunachalam, Arthur Ashley, Randy Aslin, Jim Asmus, Steven Aspden, Jacqueline Asso, Victoire Assohou-Ooattara, Francklin Assoko-Mve, Andrew Astalos, Maguy Atheba, John Atkinson, Edwin Au, Gordon Au, Jason Auch, Bernard Auger, Richard Augustyn, Carlos
Aular, Reinaldo Aular, Ryan Austin, Maria F Avila, Farooq Azam, Krishnaswamy Babu, Kevin Babuik, Adrian Baciulica, Michael Baddeley, Mary Ann Baes, Babak Baghban, Alex Bagnall, Brian Bahlieda, Dave Baier, Janice Baik, Michael Baik, Dwayne Bailer, Rod
Bailer, Brandon Bailey, Christopher Bailey, Judy Bailey, Kimberley Bailey, Robert Bain, Leon Bakaas, Shane Baker, Sharon Baker, Thomas Balakas, Reginald Baldock, Charity Baldwin, Christopher Baldwin, Mark Baldwin, Robert Baldwin, Vaughn Baldwin, Irineo
Balicanta, Joel Balkam, Darin Balkwill, Michael Ball, Gary Ballas, Ronnie Ballas, Sheldon Ballas, Brenda Balog, Corrie Balogh, Ladji Bamba, Mamadou Bamba, Mike Bamber, Neville Banak, Saiyed Banamia, Darwin Banash, Junet Banawa, Mark Bancroft, Bob
Banks, Linda Banks, Bennett Bannis, Teresa Banny, Inge Bantli, Garry Bardoel, Larry Bardoel, Pamala Bare, Dale Barge, Muhammad Bari, Ross Barker, Sharon Barker, Dennis Barnes, Michael Barnes, Tiziana Barnes, Beata Barnett, Javier Baroja, Deborah Barr, Sean
Barr, Blair Bartlett, Cynthia Bartlett, Eddie Bartlett, Marty Bartman, Lloyd Basines, Magued Bastawross, Michael Batac, Cheryl Bateman, Lisa Bateman, Selena Bath, Mark Batovanja, Brenda Battyanie, Jackie Bauer, Lydell Bauer, Ronnie Bauer, Raymond Bazan,
Martin Beach, Colin Beaman, Harold Beamish, Chad Beaton, Aura Beattie, Erica Beauchamp, Richard Beaudoin, Guy Beaulieu, Laurier Beaunoyer, Brent Beck, Chris Becker, Holly Becker, Bryce Beckner, Gurpreet Bedi, Gregory Bednarchuk, Sheldan Beebe, Keith
Begg, Adrian Begley, Loren Behrens, Anhar Belah, Nawar Belah, Guy Belanger, Kelly Belanger, Lesley Belcourt, Kala Belding, Dustin Beliveau, Calvin Bell, David Bell, Faye Bell, Jon Bell, Stephen Bell, Reg Bellanger, Janet Bembridge, Michael Bembridge, Ahmed
Bendahmane, Khalida Bendahmane, Brad Bendick, Jennifer Benko, Lene Benner, Chris Bennett, Darren Bennett, Erick Bennett, Murray Bennett, Brad Bensmiller, Shelly Bensmiller, Chad Benson, Pamela Benson, James Bentley, Linda Beresh, Debbie Berg, Jaimie
Berg, William Berg, Jeffrey Bergeson, Becky Bergley, David Berlinguette, Henry Berlinguette, Daniel Bernardo, Lynn Bernhardt, Joanne Berrade, Andre-Lyne Berthiaume, Murray Bertsch, Jeffrey Best, Jonathon Best, Rodney Best, Stewart Bettinson, Ashley Bexson,
Rupal Bhatt, Pareshkumar Bhavsar, Marc Bickham, Jennifer Bidlake Schroeder, Corey Bieber, Daniel Bieber, Douglas Bielech, Derek Biener, Inge A Biener, Judy Billard-Payne, Shelley Billinghurst, Roger Binkley, Roger Bintz, Warren Birch, Jane Birkett-Hodson, Robert
Bischoff, Shane Bischoff, Christopher Bish, Kathy Bishop, Travis Bishop, Craig Bisschop, Darwin Bittner, Darcy Bjorge, Kevin Bjornstad, Adam Black, Chad Black, Chris Black, Craig Black, David Black, Leah Black, Paul Blackburn, Kenneth Blackhall, Kerri Blackmore,
Daniel Blain, Michael Blair, Deana Blais, David Blake, Evan Blake, Barton Blakney, Alvaro Blanco, William Blanco, Wesley Bland, Chris Blatchly, Shawn Blaydes, Zoe Bleackley, Parrish Blizard, Judith Blomdal, Ellen Bloomfield, Rolland Blouin, Samantha Blouin,
Gregory Blundon, Kyla Bly, Carlos Boadas Salazar, Henry Bocalan, Allan Boddy, Brad Bodnar, Dennis Boehmer, Kent Boerrichter, Kyle Boerrichter, Dean Boettcher, Darcy Boettger, Warren Bogelund, Marty Boggust, Brent Boguslaw, Tyler Bohach, Gordon Bohrson,
Christopher Bohush, Lauren Boida, Claude Boily, Evan Boire, Michael Bolianatz, Greg Bolin, Ariadna Bonilla, Tom Bonwick, Patricia Booklall, Martin Booth, Charlene Boraas, Barry Borbely, Adriana Borbon, Robert Borg, Mark Born, Michael Born, Jon Borstel, Blair
Bosch, Dave Bosch, Dave Bosek, Greg Boshaw, Enrica Bosoni, Keith Bottriell, Maurice Bouchard, Suzanne Boudignon, Tony Boudreau, Lance Boulet, Tyler Bouma, Rick Bourassa, Sheldon Bourassa, Delwood Bourke, Daryl Bourque, Daniel Boutin, Brian Bovay,
Devrey Bowen, Jonathan Bowen, Jim Bowers, Robert Bowers, Slade Bowers, Bruce Bowles, Clinton Bowles, Nadine Bowles, Ernest Bown, Gordon Bowzaylo, Dale Boychuk, Doug Boyd, Patrick Boyd, Charline Boyer, Lorraine Boyle, Richard Boyle, Neil Bozak, John
Brabec, Dave Bracey, Bryan Bradley, Kenneth Bradley, Peggy Bradner, Jan Bradshaw, Marianne Brady, Mary Jane Brady, Linda Bragg, Jo-Ann Brake, Nicholas Brake, Brian Brant, David Brant, Myron Brataschuk, Colin Brausen, Luis Bravo, Neil Bray, Tess Bray, Tara
Brechin, Gordon Brecht, Sharon Breitkreuz, Joseph Breland, Paul Breland, Barry Brenton, Lori Brenton, Ryan Brenton, Roxane Bretzlaff, Olaf Breukel, Lisa Brewer, Barry Brick, Butch Briggs, Denis Brisebois, Donald Britton, Lisa Brock, Shawn Brockhoff, Brian Broda,
Kelly Broda, Dwayne Brodziak, John Brogly, Bill Bromling, Murray Brooker, Andrew Brooks, Debbie Brooks, Jeremy Brooks, Tanya Brooks, Kenneth Brosowsky, Eugene Brown, Jason Brown, Jennifer Brown, Jeremy Brown, Leroy Brown, Mary Brown, Steve Brown,
Tracy Brown, Tyler Brown, Yvonne Brown, Leo Browne, Robert Brownless, Christopher Bruce, Shelly Bruce, Fred Brugger, John Brule, Russell Brundige, Leo Brunelle, Jason Bryant, Michelle Bryson, Sean Bryson, Gordon Buckshaw, Linda Buczkowski, Malcolm Budd,
Robert Budzen, Raymon Bueckert, Darren Buffett, Wayne Bugiak, Ian Bulloch, Joe Bullock, Don Bumstead, Douglas Bumstead, Alan Bunyan, Clarence Bur, Carla Burbridge, Trevor Burchenski, Ian Burchette, Jeffrey Burdett, David Burdziuk, Brent Bureau, Keith
Bureau, Grant Burgess, Alastair Burke, David Burke, Lyle Burke, Tim Burke, Angela Burnett, Ken Burnham, Barry Burt, Corey Burt, Shawn Burt, Gerald Burtch, Corinne Burton, Robert Busato, Lisa Bush, Colleen Bussey, David Bussey, Rosemary Bussi, Heather
Butchart, Terry Butchart, Robert Butler, James Butt, Bob Butterworth, Ronald Butts, Leanne Butz, David Byrnes, Mike Byrtus, Irina Byvald, Arcelie Cabrega, Moraima Caceres, Mark Cadman, James Cadrain, Ling Cai, Simon Cains, Brian Calder, Laura Calder, Leslie
Calder, Byron Caldwell, Patrick Caldwell, Tom Callaghan, Natalia Callejas, Patrick Callin, Richard E Calliou, Ryan Cameron, Shirley Cameron, Lisa Campacci, Catherine Campbell, Clayton Campbell, Dean Campbell, Doug Campbell, Earl Campbell, Kyle Campbell,
Michael Campbell, Nancy Campbell, Niall Campbell, Andre Campeau, Wayne Campeau, Gregory Cane, Carlos Canizalez, Brad Canning, Kelly Cap, Richard Cap, James M Capjack, John Capstick, Barry Carabin, Kathleen Carbury, Fred Cardinal, Jason Cardinal, Lee
Cardinal, Myles Cardinal, Sharon Cardinal, Wayne Cardinal, Mark Carew, Jim Carey, Justin Carey, Joey Carifelle, Rodger Carifelle, Ian Carleton, Wes Carlson, Dean Carnes, Albert Caron, Rochelle Caron, Diego Carrera, Janie Carrier, Wayne Carrigan, Kim Carrol,
Greg Carroll, Ian Carroll, Shayne Carroll, Melissa Carson, Eduardo Cartaya, Eric Carter, Michael Carter, Jessica Cartwright, Gary Case, Mary-Jo Case, Trevor Cassidy, Lance Casson, Mike Catley, Steve Caven, Richard Cawaling, Ciara Celis, Marco Celis, Ali Centeno,
Samuel Cervantes, Andrew Chaisson, Sachi Chakravarty, Mark Chalmers, Samantha Chalmers, Erin Chamberlain, Kevin Champagne, Lise Champagne, Alan Chan, Anly Chan, Ranee Chan, Sarah Chan, Wayne Chandler, Alan Chaney, Koh Chang, Claude Chaon,
Deon Chappell, Harry Chappell, Darryl Charabin, Christopher Charbonneau, Colleen Chartrand, Roger Chartrand, Susan Y Chase, Leon Chateauneuf, Sumit Chatterjee, Siddique Chaudhry, Rajesh Chauhan, Gary Chaulk, Mark Chayko, Carl Cheeseman, Bo Chen,
James Chen, Lulu Chen, Daniel Chenier, Mike Chernichen, Tyler Cherry, James Cheung, Kawaljeet Chhabra, Joel Chiasson, Gloria Chick, Al Chin, Melaine Chin, Sharon Chin, Trish Chipiuk, Thomas Chisholm, William Chiverton, Randall Chodzicki, Raymond Chong,
Brent Chopping, Brett Chorney, Curtis Chornohos, Shayela Chowdhury, Alphonse Chretien, Ruth Christensen, Heidi Christensen Brown, Marianne Christianson, David Christie, Rob Christopher, Andy Chu, John Chuiko, Loy Chunpongtong, Heather Church, Ronni
Church, Roderick Churchill, Kadidiatou Cisse-Banny, Elaine Cissell, Magda Ciulavu, Michael Clapham, William Clapperton, Amanda Clark, Amanda Clark, Andrea M Clark, Brent Clark, Janice Clark, Ken Clarke, Martha Clarke, Sanja Clarke, Shandon Clarke, Walter
Clarkson, Greg Clegg, Joseph Clevenger, Karla Cluett, George Clutton, Brooke Coburn, Dale Coburn, John Coers, John Coggan, Leanne Colborne, Aubrey Colbourne, Robin Coles, Celibeth del Carmen Colina, Lorne Collard, Marc Collie, Grant Collier, Garth Collings,
Curtis S Collins, Richard Collins, Robert Collins, Rod Collins, Anne Collison, Gordon Collison, Royston Collison, Adam Collyer, Rebecca Conacher, John Condie, Mark Connellan, Spencer Constant, David Conybeare, Chris Cook, Anna Cooke, Lori Cookson, Brian
Coolen, Rob Coolen, Sean Coolen, Gary Coombe, Kent Cooper, Laura Cooper, David Coppard, Robert Coppard, Mark Corell, Elaine Coreman, Clair Cormier, Rocky Cormier, Rosette Cormier, Veronica Cormier, Alessandro Corradi, Rosario Corral, David Corson, Jim
Corson, Lorenzo Cortes, Pierpaolo Corticelli, Harry Costello, Christian Cote, Sanga Coulibaly, Dougie Coull, Eric Coulombe, Kim Coulter, Jack Courchene, Robert Courchesne, Gerald Courtney, Kathryn Courtney, Dave A Cousins, David H Cousins, Richard Coward,
Keith Cowger, Cath Cowie, Gemma Cox, Randy Cox, Wade R Cox, Edward Cozicor, Nigel Crabb, Harry Crabtree, Cody Craig, Layne Craig, Bruce Crain, Stephen Crake, Patrick Cramb, Allen Crawford, Marina Crawford, Michael Crawford, Paul Crawford, Beverley
Creed, Leanne Cressman, Roger Crichton, Kevin Croft, Shane Croft, Stefan Croft-Bednarski, Christopher Cross, Lana Cross, Lloyd Cross, Teresa Cross, Randall Crossman, Camille Croteau, Barbara Crowley, Linda Cruttenden, David Cruz, Anthony Csabay, Edgardo
Cuello, Lynn Cullen, Corinna Culler, Darrel Cunningham, Davis Cunningham, Tara Cunningham-Canfield, Arley Currie, David Currie, Elizabeth Currie, Brent Curtis, Troy Curzon, Dale S Cusack, Kenneth Cusack, Pat Cusack, Real Cusson, Midge Cuthill, John Cutler,
Chris Cyr, Suzanne Da Costa, Kevin d’Abadie, Victor Daboin, Andrew Dabrowski, Marivic Dacillo, Ganiyat Dada, Fakhri Dadashov, Gary Dahl, Hamid Dahmani, Eliane Dakaud, Brittany Dalby, Patrick Dale, Layne Dalgetty-Rouse, Sean Dalgleish, Scott Dalrymple,
Gary Daly, Walter M Danchak, Mike Danis, Gene Danyluk, Peter Danyluk, Daniel Daraban, Corbin Dargatz, Eric Dargis, Mark Darling, Lynne Darlington, Merl Darragh, Martin Darveau, Altaf Dasurkar, Bruce Davidson, Graham Davidson, Jeffrey Davidson, Mike
Davidson, Scott Davidson, Todd Davidson, Brian Davies, Charlee Davies, Lynne Davies, Frank Davis, Graham Davis, Greg Davis, Randall Davis, Robert Davis, Sarah Davis, Jeffrey Davison, Peter Davison, Leonard Dawe, David Day, Julia Day, Natasha Daya, David
Daye, Douglas De Avila, Ryan De Bruyne, Meinrado de Chavez, Eric de Kock, Ryan De Leeuw, Benito De Lorenzo, Robbert de Ruiter, Albert De Sousa, Brian de Winter, David Dean, Harry Dean, Martha Dean, Trevor Debler, Ron Erick DeCastro, Derek Dechaine,
James Dechaine, Raymond Dechaine, Roland Dechesne, Dave Defoort, Sheldon DeFord, Mervin J Degenstien, Barbara Deglow, Gerald Del Frari, Karin Delday, Rachelle Delgado, Mitchell Dell, Franco Dell’Ovo, Brent Delorme, Michael Delorme, Michael RJ DeLorme,
Suzanne Demaer, Charlene DeMone, Fred Denney, Judy Denney, Geoffrey Dennis, Susan Dennis, Kimberley Dennis-Wood, Shirley Denny, Christopher Denslow, Susan d’Entremont, Colin Derby, Jayme Derix, Shane Derlukewich, Greg Derouin, Semir Dervovic,
Eugenie Dery, Ajit Desai, Nareshchandra Desai, Miles Deschambeau, Darren Deschene, Raymond Desjarlais, Laurie A Devey, John DeVries, Fraser Dewar, Todd Dewhurst, Debbie Dewis, Dana Dey, Karen Deyaegher, Maldip Dhaliwal, Pirmohammed Dhalwala,
Jabeen Dharamsi, Vikas Dhawan, Keith Diakiw, Karim Diallo, Sumara Diaz, Karen Dickason, Bob Dicken, Garry Dickie, Anthony Dicks, Blair Dickson, Cameron Dickson, Francis Dickson, Alexander Didenko, Sue Didyk, Brenda Diebel, David Diebel, Irene Dikau,
Benjamin Dikit, Anne Dillon, James Dillon, Michael Dingley, Patricia Dingley, Ronald Dinkel, Hubert Dinn, Issiaka Diomande, Chris Dionne, Gayle Dionne, Michael Dirk, Al Dixon, Robin Dixon, Rod Dixon, Trent Dixon, Derrick Dobrowski, Leanne Dobson, Linnae
Dobson, Edward Dochuk, Russell Dodd, Alistair Dodds, John Dodman, Erin Doepker, Kelly Doepker, Kim Doepker, Ritchie Doering, Patrick Dolan, James Doleman, Logan Dolen, Kathy Doll, Amy Dolomount, Kyle Donald, Scott Donaldson, Claire Dong, Tim
Donkersloot, Veronica Dooling, Tim Dootka, Allen M Dorey, Tredou Dorgeles, Mark Dorocicz, Real Doucet, David Doucette, Martin Douglas, Scott Douglas, Dahl Dow, Angela Dowd, Jeff Dowd, Marlene Dowdell, Phil Downes, Nicoletta Downey, Alecia Downton,
Lisa Doyle, Colin Drake, Darcy Draper, Kevin Draper, Todd Draper, Wayne Draper, Kenton Dreger, Brian Drew, Timothy Dreyer, Colleen Drury, John Drury, Calvin Duane, Rafael Duarte, Sean Dubelt, Rosalind Ducey, Rick Ducharme, Jon Dudley, Alan Duffy, Simon
Dugdale, Douglas Duguid, Albert Duhaime, David Duke, Doug Duke, Cheryl Dumais, Laurent Dumoulin, Stella Dumoulin, Barry Duncan, Sean Duncan, Jason Duniece, Graham Dunlop, Gavin Dunn, Robert Dunn, Keith Dunnett, Judy Dunsmuir, Kurt Dupuis, Lyle
Dupuis, Michael Durnie, Harvey Dutchak, Robert Duval, Charles Dyer, Terry Dyer, Eugene A Dyjur, Linzi Dykes, Krzysztof Dzwonek, Julina Eagleson, Gary Earl, Kevin Earle, Julie Easthope, Suzanne Eaton, Greg Ecker, James Edens, Malcolm Edirisinghe, John Edmunds,
Josephine Edoukou, Gordon Edward, Dave Edwards, Michael Edwards, Sabrina Edwards, Sue Edwards, Cindy Egden, Phoebe Egden, Christopher Ehresman, Brian Eitzen, Devin Ekdahl, Samuel Eleko, David Eley, Carole Eliuk, Anthony M Ell, Diane Elliott, Michael
Elliott, Robert Elliott, Trent Elliott, Shaun Ellis, Edwin Ellsworth, Heather Emery, Rommel Engler, Joanne English, Terry Erickson, Kresten Eriksen, Michael Ernst, Polina Ersh, Jane Eruchalu, Sarah Esson, Oscar Estrada, Andrew Etele, Samantha Etherington, Lee Evans,
Randy Evans, Leila Eveleigh, Susan Eveleigh, Clayton Eves, Doug Eves, Laura Ewen, Kris Eyolfson, Leonard Fabes, Lawrence Facchina, Denis Fagnan, Heather Fahey, Richard Fairbairn, Andy Fankhauser, Festus Fariyibi, Chelsea Farrell-Dreger, Greg Farrer, Randy
Farrer, Travis Farrer, Barry Fast, Arthur Faucher, Chris Faucher, Everette Fauth, Karman Fayant, Tyson Feairs, Andrew Fearne, Ella Fedossova, Ira C Feland, Jeremie Feland, Warren Feland, Jason Feltham, Wallace Feltham, Kurt Fenrich, Logan Fentie, Randy Fenton,
Ken Ference, Lawrence Ference, Brad Ferguson, Donald Ferguson, Helen Ferguson, Mark Ferguson, Neil Ferguson, Roy Ferguson, Scott Ferguson, Mario Feria-Estrada, Ana Camila Fernandez, Eduardo Fernandez, Sergio Fernandez-Trujillo, Ninfa Ferrer, Ron Fewer,
Darren Fichter, Jane Fielding, Walter Fielding, Chris Filgate, Michael Filipchuk, Neil A Findlay, Bob Finlayson, James Finlayson, Chad Finnebraaten, Timothy Finnigan, Tanya Fir, Marlain Firmston, John Fisera, Calvin Fisher, David Fittkau, Sandra Fitzpatrick, Colleen
Flamont, Doug Fleming, Sean Fleming, Rodney Flett, Trevor Flood, Reynaldo Flores, Mark Flynn, Edmond Foisy, Justin Foisy, Brent Foley, Gregory Fontaine, Leo Fontaine, Robert Fontaine, Roger Fontaine, Lynn Foo, Harris Foote, Randy Foran, Adele Forcade, Ryan
Ford, David Foret, David Forfar, Curtis Formanek, Randy Formanek, Devon N Fornwald, Leslie Forrester, Rhonda Forrester, Alastair Forsyth, William Forsyth, Richard Forth, Chantal Fortin, Danny Fortin, Donald Foster, Dwayne Fotty, Kevin Foulds, Scott Fouracres,
James Fowler, Donna Frame, Fiona Frame, Roger France, Oscar Franchi, Ron Frank, Richard Franken, Allan Frankiw, Dru Franklin, Shelley Franssen, Leonard Fraser, Michael Fraser, Ken Frazer, Ted Frederickson, David French, Ernest French, Peter French, Roger Frere,
Jared Frese, Kurt A Freyman, Brad Friesen, David Friesen, Kenneth Friesen, Monte Friesen, Kevin Frith, David Fritz, Andrei Frizorguer, Frank Frosini, Colin Frost, Scott Froude, Xiao Wei Fu, Karen Fujimoto, Doug Fukushima, Samantha Fuller, Jim Fung, Sarina Fung-Yau,
Danny Furlotte, Ted Furuya, Josephine Gaddi, Leonard Gadowski, Sharon Gaehring, Marcel Gagnon, Serge Gagnon, Serge R Gagnon, Jaylyne Galey, Ron Gall, Ryan Gallant, Fabio Gallardo, Michael Gallon, A William Galloway, Yoko Galvin, Andreas Gamp, Vovel
Gapaz, Carlos Garcia, Daina Gardiner, Doug Gardner, Lynette Gardner, Jon Gareau, Tim Gareau, Glen Garton, Linda Garvey, Stan Garwon, Carlos Garzon, Mark Gaspich, Harold Gates, Janet Gatrell, Vanessa Gaudreau, Andrew Gaunt, Matt Gauthier, Maurice
Gauthier, Michelle Gauthier, Neil Gauthier, Klaus Gautschi, Steve Gavronsky, Rebecca Gayler, Paul Gazzard, James Geddes, Michael Geddes, Kevin Gee, Cory Geier, David Geleta, Lesley Ann Gemmell, Glenn Genge, Neil Genge, Patricia Gentles, Devin George,
William George, James Georget, Kimberley Gereluk, Jim Gergely, Matthew Gering, Grant Gerla, Michel Germain, Raymond Germain, Robert Germain, Colin Germaniuk, Karlene Gervais, Marc Gervais, Paul Gervais, Sheldon Getson, Nicole Getz, Stanley Getz, Ken
Getzinger, Mohammad Reza Ghods-Esfahani, Essam Ghoubrial, Oliver Giammarioli, Douglas Gibson, Susan Giebel, Shaun Giefer, Todd Giesbrecht, Dwayne Giggs, Tamara Giles, Kevin Gill, Ralph Gill, Perry Gillam, John Gillatt, John Gillespie, Ron Gillespie, Timothy
Gillespie, Erin Gillis, Vicki Gillis, Martin B Gillund, Justin Gilmour, Scott Gilmour, Douglas Ginn, Kevin Ginter, Conrad Girard, Donald Girard, Marc Girard, Stewart Girbav, Ben Gisby, Eugenio Giuliani, Marvin Gladue, Russell Gleed, Andy Glemba, Steven Glockner,
Tatiana Glowczeski, Jason Glubish, Laurie Godwin, Duane Goetz, Peter Goetz, Lida Goldchteine, David Golden, Jorge Gomez, Julio Gomez, Cody Gomuwka, Elaine Gong, Kun Gong, Brian Gonsalves, Jose G Gonzalez, Yvonne Gonzalez, Adam Goodwin, James
Goodwin, Wayne Goodwin, Vijayakumar Gopalakrishnan, Ian Gordon, James Gordon, Winston Goretsky, Michael Gorman, Rhonda Gosse, Trent Gosse, Yvon Gosselin, Kristen Goudie, Allan Gould, Antonella Goulet, Pierre Goulet, Henri Gousseau, John Graca,
Carl Graham, David Graham, James Graham, Roger Graham, Stephanie Graham, Trevor Graham, Ed Grams, Austin Grant, Harry Grant, Bonnie Gray, Jenny Gray, Ronald Gray, Sheila Gray, Christopher Grayston, John Greaves, Edie Green, Linda Green, Shilo Green,
Wayne Green, Cory Greenawalt, Dallas Greenawalt, Shannon Greene, Theresa Greene, Dale Greep, Richard Grieve, Edmond Griffiths, Robert Groenen, Daryl Grundner, Denis Grzela, Trevor Guay, Hiromi Guest, Louis Guevremont, Don Guglielmin, Aristides Guillen,
Aliya Gulamhusein, Karim Gulamhusein, Robert Gullion, Carolyn Gunderson, Colin Gunn, Lauren Gunnell, Alan Gunst, Ashok Gupta, Mike Gurin, Edward Gushnowski, Terry Gusnowski, Graham Gustafson, Brian Guthrie, Maria Gutierrez, Bartley Haahr, Rodney
Haberlack, Amber Hachey, Cameron Hachey, Violet Haddad, Leisa Haddleton, Resad Hadzismajlovic, Chad Hagstrom, Keith Hague, Allan Hains, Ahmad Haj Hamdan, Sam Hajar, Shemin Haji, Zohreh Hajibeygi, Paul Hakim, Dan Halaburda, Montie Hale, Dean
Halewich, Rick Halkow, Barry Hall, Charles Hall, Donald Hall, Michael Hall, Shane J Hall, Todd Halladay, Chris Hallborg, Patricia Halldorson, James Hallett, Robert D Hallett, Paul Hamel, Larry Hamende, Edson Hamilton, Tim Hamilton, Kevin Hamm, Michael Hammel,
Larry Hammell, Rick Hammond, Sora Han, Brad Hancock, Judy Handy, Ray Hank, Karl Hann, Colby Hansen, James Hansen, Todd Hansen, Judy Hanson, Leland Hanson, Aman Haq, Brent Harbin, Leon Harder, Ashley Hardes, Malcolm Hardie, Caleb Harding, Carson
Harding, Kent Hardisty, Edavazhiyath Harikumar, Ken Harke, Julia Harker, Brent Harle, Heather Harms, Erik Haroldson, Coby Harris, Jody L Harris, Murray Harris, Roderick Harris, Roger Harris, Ron Harris, Stephen Harris, Clayton Harrison, Dylan Harrison, Selena
Harrison, Randy Harsany, David Hart, Bud Hartley, Caroline Hartley, Stuart Hartman, James Harty, Lorne Harty, Mike Harty, Amie Harvey, Greg Harvey, Jerry Harvey, Julie Harvey, Cheryl Hasenclever, Ahmed Hassan, Colin Hastings, James Haston, Peter Hatt, Bryan
Hattebuhr, Christine Hattebuhr, Wayne Hatton, Colin Hattrick, Dave Haub, Willow Hauber, Ross Hauger, Wayne Hausch, Paul Hausmanis, Jason Haviland, Lindsay Hawco, Betty Hayden, Cameron Hayden, Craig Hayes, Mark Hayes, Kris Hayko, David Haywood,
Sean Head, Jay Heagy, Andy Heale, Brad Hearn, Larry Heath, Praveen Hebbale, David Hebert, Gerald Hebert, Gerald Hebert, Terry Heck, Christopher Heffner, Robin Hein, Mandeep Heir, Mahmud Hejni, Curtis Heltman, Barton Henderson, Ken Henderson, Steven
Hennessey, Anita Hennig, Reid Henry, Daniel Herauf, Jeremy Herbison, Kim K Herbst, Brad Herman, James Herman, Justin Herman, Judith Hermann, Edgar Hernandez, German Hernandez, Luis Herrera, Coreen Herring, Jeremy Herritt, Michele Herron, Ryan Heska,
Keith Heslop, Tyson Hessler, Kim Hicks, Rodney Higa, Andrew Higgins, Rachelle Higgins, Mark Hildebrand, Charlene Hill, Gordon Hill, Ernie Hilland, Jesse Hillebrand, Jeff Hillier, Todd Hillier, Christie Hillis, Arnold Himschoot, Ken Hingley, Katarzyna Hinks, Jim Hlewka,
Margaret Ho, Donald Hoar, Karyn Hobbs, Dora Hodder, Barry Hodgan, Barbara Hofer, Joanne Hogg, Kyle Hokkanen, Doug Holman, Richard Holman, Chris Holmes, Christine Holmes, David Holt, Brett Holthe, Clayton Holthe, Donald Hood, Shannon Hood, Hans
Hoogendam, Graham Hook, Trevor Hornberger, Keith Hornseth, Kimberley Horvath, Richard Horvath, Jon Horyn, Lance Hoskyn, Iqbal Hossain, Tony Libo Hou, Jeff Houck, Sherri Houle, Justine House, John Howard, Trapper Howard, Kristy Howe, Sanjib Howlader,
Darren Howlett, Wade Hoyles, Angela Hoza, Tracy Hrycay, Natasha Hrynyk, Rena Hu, Li Huan, Jianxin Huang, Nicky Huang, Joseph Hubelit, Kyle Huculak, Paul Hudson, Sandy Huebner, David Huff, Jeremy Hughes, Mark Hughes, Michael Hughson, Eun Ju Huh,
Donna Huitikka, Riley Hull, Wendy Hum, Terry Humbke, Jenna Humphrey, Manpreet Hundal, Ian Hundeby, Leanne Hunter, Robert A Hunter, Tom Hunter, Chad Huseby, Shahzad Hussain, Glenn Hussey, John Hussynec, Dennis Hutchinson, Ray Hutscal, Bruce J Hutt,
Ewart Hutton, Donald G Huxley, An Huynh, Bonnie Hynes, David Hynes, Scott Hyrcha, Sarah Hyslop, Gerard Iannattone, Pina Iannattone, Vladimir Iglesias, Matthew Ilchuk, Anna-Marie Iles, Kene Ilochonwu, Kenneth Imlach, Dominic Ing, Michael Ingles, Alexander
Inglis, Max Inglis, Brad Inman, Matt Inscho, Eglee Irausquin, Muhammad Irfan, Scotty Iron, Jamieson Irons, Jeff Irons, Ted Irwin, Darren Isele, Floyd Isley, Karen Ivan, Arlette Ivany, Wallace Jack, Judy Jackson, Kurtis Jackson, Nicholas Jackson, Niki Jackson, Robin
Jackson, Ronald Jackson, Russel Jackson, Victoria Jackson, Arne Jacobson, Ken Jacobson, Albert Jacula, Curtis Jacula, Marci Jacula, Todd Jacula, Vivek Jain, Michael Jaindl, Boris Jakulj, Stephen Jamam, Chris James, Jeff James, Bob Jamieson, Nigel Jamieson,
Sally-Anne Jamieson, Maria Jancewicz, Ian Janeo, Marc Janke, Dale Jans, Peter Janson, Simon Janssen, Leonard Janzen, Ian Jappy, Nancy Jarman, Calvin Jarratt, Brett Jarvis, Jim Jarvis, Derek Jeannotte, Jamie Jeannotte, Wendal M Jellison, Tyler Jenkins, Jason
Jenner, Lindsay Jenner, Michael Jennings, Brent Jensen, Karl Jensen, Kevin Jensen, Parry Jensen, Mark Jespersen, Mary-Ann Jesso, Daryn Jestin, Deshun Jiang, Simon Jiang, Ramon Jimeno, Mahmud Joarder, Terry Jocksch, Juan Joffre, Brent Johns, Darrell Johns,
David Johnson, Dustin Johnson, Jeffrey Johnson, Jennifer Johnson, Larry Johnson, Magnus Johnson, Marlene Johnson, Neville Johnson, Richard Johnson, Scott Johnson, Stacy Johnson, Theresa Johnson, Holly Johnston, Joe Johnston, Neil Johnston, Norman
Johnston, Janet Johnstone, Dan Johnston-Watson, Ed Jones, Gareth Jones, Mark Jones, Pamela Jones, Tammy Jones, Wayne Jones, Paul Joo, Damian Jordan, Tushar Joshi, Umeshkumar Joshi, Stuart Josselyn, Jaime Juan, Timothy Juett, Albert Junco, James Jung,
Sandy Jung, Chris Jungen, Ronald Jungkind, Marjorie Junio, Asif Kachra, Alexander Kaczorek, Mary Kadri, Carol Kadutski, Chad Kaglea, Raymond Kahanyshyn, Paul Kainth, Krista Kaiser, Myra Kalakailo, Kevin Kalinsky, Sheron Kalirai, Derek Kalynchuk, Elizabeth
Kaminski, Janet Kanarek, Larry Kane, Shari Kane, Dwayne Kaprowski, Tom Karpa, Doug Kary, Jerome Kasha, Natalia Kashirina, Lynn Kasper, Sylvain Kassi, Amy Kastelic, Beverley Katay, Myles Kathan, Uma Kathiresan, Deanne Katnick, Hassan Katrip, Travis Kavalec,
Richard Kavanagh, Olga Kay, Dobrin Kazandzhiev, Mary Kealey, Philip Keele, John Keith, Joe Kelenc, Michelle Kellerman, Ernest Kellough, Marilyn Kelloway, David Kelly, Jeff Kelly, Tim Kelly, Simon Kelsey, Greg Kemp, Stephen Kempton, Wayne Kennedy, Scott Kent,
Val Kenyon, Dan Kenzle, James Keough, Juliana Kerr, Rob Kerr, Ryan Kerr, Shaudia Keslick, Blair Kessler, Lori Ketchuk, Greg Ketter, Brian Kevol, Ajmal Khan, Aman Khan, Amjad Khan, Shafique Khan, Shehnaz Khan, Shaalini Khanna, Serge Kiasosua, Roy Kidmose,
Kimberly Kielt, Leonard Kiez, Todd Kilback, Michael Kilcollins, Olga Kilo, Heather Kim, Curtis Kimler, Billie-Jo King, Dale King, Douglas King, Justin King, Ray King, Richard King, Tony King, Wade King, Tasha Kingsbury, Peter Kinnear, Roland Kinney, Cam Kinniburgh,
Marvin Kinsman, Thomas Kirsop, Sebastian Kirstine, Tony Kirtley, Brandon Kiss, Marlene Kissoon, Bob Kitsch, Curtis Kiyawasew, Jody Kiziak, Terry Klassen, Cody Klatt, Brent Klautt, George Klemak, Julie Knibbs, Allen Knight, Darcey Knoblich, Olga Knopov, William
Knouse, Tamara Knox, Dwayne Kobes, Russ Kobi, Barney Kobzey, Bill Koch, Emmanuel Koffi, Sylvain Koffi, Blair Koizumi, Lutz Kolberg, Eva Komers, Cameron Komm, Hadizata Konate-Rassi, Tad Kondo, Martin Kondor, Brent Kondratowicz, Ibrahim Kone, Lacina
Kone, Natasha Kooistra, Nathan Koops, Bonnie Kootenay, Sergey Korchagin, Brent Korolischuk, Rick Koshman, Jennifer Koslowski, Brent Kosowan, Vladimir Kostic, Diane Kostiuk, Kevin Kostrub, Ann Kostyshyn, Brice Kotchi, Stacey Kotelniski, David Kotze, Marcelin
Koua, Philippe Kouadio, Angele Kouakou, Didier Kouame, Randall Kovalenko, Richard Kowalski, Kevin Kowbel, Adam Kownatka, Dennis Kozak, Eugene Kozakevich, Teresa Kozina, Brad Kozuback, Russell Kraeleman, Cameron Kramer, Andrew Krancz, Lyndon
Krankowsky, Trevor Kratz, Bryan Krause, Gary Krause, Trevor Krause, Jessica Krawetz, Justin Krebs, Todd M Kreics, Dee Jay Krein, Jeffrey Kreiser, Murray Kreiser, Kari Kremer, Daniel Krentz, Blayne Kress, Ken Krewulak, Connie Kriaski, Anand Krishnamoorthy, Heather
Krislock, Linda Kroeker, Ryan Kroeker, Peter Krol, Vanja Krtolica, George Kucy, Warren Kuefler, Randall Kuka, Chad Kully, Bharat Kumar, Sudip Kumar, Vikas Kumar, Jeff Kuntz, Tanya Kuntz, Barry Kunza, Gregory Kurek, Mahendi-Ali Kureshi, Kelly Kursteiner, Frank
Kurucz, Brian Kutash, Steve Kuzmak, Corinne Kwan, Keith Kwan, Russ Kwan, Kelly Kwiatkowski, Roger Kwiatkowski, Angele Kwon, John Kwon, Karen Kyffin, Bob Kyllo, Philippa LaBossiere, Robert Laboucane, Stacey LaBoucane, Stanley LaBrash, Gernot Lackner,
Liberty Lacuna, Jocelan Ladner, Phillip Laflair, Levi Lafrance, Ronald LaFrance, Leon Lafreniere, Ashok Babu Laguduva, Dilip Laha, Cassandra Lai, Philip Lai, Theresa Lai, Ronald Laing, David Lainof, Munira Lalji, Elaine Lam, Raymon Lam, Sam Lam, Kurtis Lamb,
Terri Lamb, Dee Lambert, Dino Lambert, Richard Lameman, Sharon Lamontagne, David Landers, Celeste Landry, Marcel Landry, John Lane, Stephen Lane, Raul Lanfranchi, Renato Lanfranchi, Marc Langford, John Langille, Carolyn Langpap, Tammy Lanktree, Sandra
Lanz, Pamela Lapp, Melvin Lapratt, Gianni Larice, Corey Larocque, Leon LaRose, Justin Larsen, Dave Larsh, Rob Larson, Bengt Larsson, Ronald Lasek, Reno Laseur, Jane LaSha, John Lasocki, William Latchuk, Krista Latunski, Peter Latus, Ira Lau, Michael Laudel,
David Laurenson, Karen Laurin, Steve Laut, Roy Lavallee, Patricia Lavery, Michal Lavi, Bernard Lavoie, Iris Law, Joanne Law, Pearle Law, Darron D Lawrence, Ewen J Lawrence, Fred Lawrence, Lindsey Lawrence, Shareen Lawrence, Gordon Lawson, Martin Lawson,
10
CANAD IA N NATU RAL
To develop people to work together
to create value for the Company’s shareholders
by doing it right with fun and integrity.
David Laycock, James Layes, Paul Layland, Sharon Layton, Greg Lazaruk, Mark Lazette, Mae Yu Le, Brian Leach, Doug Leach, Trevor Leach, Albin Leaf, Reginald LeBlanc, Rodney Leblanc, Susan Leckie, Amanda Lee, Colleen Lee, Howard Lee, Jeffrey Lee, John Lee,
Linn Lee, Madison Lee, Rayanne Lee, Roxcie Lee, Swee Lee, Tim Lee, June Leechuy, David Leeper, Gillian Lefebure, Colin Lefebvre, Kevin Legault, Rodger Legault, Heather Leggett, Malcolm LeGrow, Kris Lehocky, Daniel Lehouillier, Benjamin Lehr, Thomas Lemon,
Robert Lendrum, Jarrod Lengyel, Candace Lenz, Gustavo Leon, Heidi Leonard, Arlene Leonardo, Gary Leong, Hin Leong, Stephen Lepp, Paul Lepper, Yelena Lerner, Gerry L Leslie, Richard Leslie, Shane Lester, Lonnie Letawsky, Marcus Lethaby, Phil Letkeman, Don
Leung, Eric Leung, Katie Leung, Preeminence Leung, Maurice Levac, Tracy Levasseur, Jean Levesque, Raymond Levesque, Shelly Lewchuk, Ryan Lewis, Jason L’Hirondelle, Larry L’Hirondelle, Troy L’Hirondelle, Jun Li, June Li, Xiaowan Li, Craig Liba, Shu-Hsuan Lien,
John Lieverse, Danny Lim, Hout Lim, Bonnie Lind, Jessica Lind, Penny Linden, Ewen Lindsay, Shari Lindsay, Deirdre Little, Laura Little, Robert Little, Susan Little, Tracy Little, Tony Littlefair, Dennis Liu, Ligong Liu, Cam Lizee, Dale Lloyd, Yvonne Lo, Conrad Loch, Fred
Locke, Rod Loewen, Joy Lofendale, Per Lofgren, Charlene Logan, Shauna Logan, Rodney Logozar, Kristen Lomond, Craig Long, Wade Longmore, Dallas Longshore, Kai Loo, Daniel Loose, Roger Lopez, Willy Lopez, Nelson Lord, Catlin Lorenson, Darin Lorenson,
Matthew Lorincz, Bob Lorinczy, Jose Lotito, Nancy Lotocki, Michelle Lou, Andrew Lough, Allan Loughran, Wayne Loutit, Christopher Love, Mellodie Love, Lloyd Lovelace, Dan Lowe, Darryl Lowe, Devin Lowe, Devin Lowe, Brad Lowell, Joe Lowen, Leah Loyola,
Eduardo Lozano, Jian Lu, Dave Lucas, Derrick Lucas, Gerd Lucas, Serena Lucci, Mark Luery, Oscar Lugo, Charlene Luk, Wes Lundell, Erin Lunn, Clarence Lunzmann, Jeff Luscombe, Jason Lush, Rees Lusk, Kristin Lussier, Jim Lutyck, Kathy Lutz, Ken Lynam, Jason
Lyonnais, Jim Lyons, Andy Ma, Haibin Ma, Hong Ma, Nicky Maawia, Patricia MacCrimmon, Lindsey Macdearmid, David MacDonald, Jonathan MacDonald, Julie MacDonald, Mark MacDonald, Patti Lynn MacDonald, Ray MacDonald, Raymond G MacDonald, Yun
Yun Macedo, Shawn Mack, Brent MacKay, Grant MacKay, Steve MacKay, Tim MacKellar, Richard Mackelvie, Graeme P MacKenzie, Ken MacKenzie, Shawn MacKenzie, Todd Mackenzie, Adam MacKinnon, Brandon MacKinnon, James William MacKinnon, Joseph
M MacKinnon, Graham Mackintosh, Richard MacKnight, Kyle MacLean, Mark MacLean, Tyler MacLean, Jamie MacLennan, Callum MacLeod, Jamie MacLeod, Bradley MacNeill, Angela MacNiven, Crystal MacPherson, Angus MacPhie, Heidi MacRae, Ronald
MacSween, Morgan Maddison, Andrea Maddocks, Hazel Madore, Robert Madore, Ashley Madrusan, Gary D Madsen, Markus Maennchen, Oda-Liz Maestre, Cathy Mageau, Mike Magnusson, Sheryl Maguire, Bill Mah, Jennifer Mah, Tony Mah, Kevin Maheux,
Tara Mailandt, Martin Mailhot, Elizabeth Maillet, Amy Mailman, Ali Majid, Michelle Major, Anita Mak, Tyler Maksymchuk, Eduardo Malabad, John P Malachowski, Lanre Maliki, Tea Malkova, Sean Mallay, Gilbert Malo, Linda Maloney, Dave Mamprin, Mike
Manchen, Dennis Mandley, Leonard Mandrusiak, Darcy Mandziak, Darcy Mann, Darrell Mann, Don Mann, Girvani Manoharan, Jan Manoharan, Rachelle Mantei, Luis Manzano Weffer, Roy Marceniuk, Keith Marche, Michael Marchi, Catherine Marchuk, Rodney
Marcichiw, Ronald Marcichiw, Lissete Marcucci, Balamurugan Mariappan, Helen Marietta, Shane Marion, David Mark, Brian Marsh, Rosemarie Marsh, Aaron Marshall, Lynn Marshall, Stephen Marshall, Boyd Martin, Cesar Martin, David Martin, Kevin Martin,
Leonie Martin, Lindsay Martin, Regis Martinez, Allan Masliuk, Chad Mason, Kevin Mason, Mandy Massiah, Al Massicotte, Ada Matchem, John Mathieson, Richard Mathieson, Scott Matieshin, James Mattheis, David Matthews, Demetri Mavridis, Tim Maxwell,
Karen May, Richard May, Scott Mayer, Kevin Mayner, Donald McAmmond, Brian McBean, Andrew McBoyle, Robin McBrien, Nicole McCabe, Shayla McCann, James McClellan, Brent McConachie, Bruce McCormack, John McCoshen, Michelle McCotter, Clete
McCoy, Scott McCracken, Peter McDade, Ken McDavid, Cheryl McDonald, Cynthia McDonald, Kevin McDonald, Mark McDonald, Stewart McDonald, Rod McDougall, Mary McElroy, K Tracy McFadyen, John McFadzean, Mark McFarlane, Bruce McFaul, Allan
McGann, Frances McGlynn, Terence McGovern, Robert McGowan, Alan McGrath, Bruce E McGrath, Matt McGrath, Paije McGrath, Steve McGregor, John McGuckin, Gordon McHattie, Alan McIntosh, Eric McIntosh, Sandra McIntosh, Bernice McKay, Jeff McKay,
Kelvin McKay, Kim I McKay, Robert McKay, Tim McKay, Dennis McKee, Ken McKelvey, Brenda McKendry, Neil McKendry, Robert McKendry, Phil McKenna, Kate McKenzie, Keith McKenzie, Mike McKenzie, Kevin McKie, Douglas McLachlan, Bonnie-Lynn McLaren,
Keith McLaughlin, Reginald McLaughlin, Colin McLean, John McLean, Marla McLean, Nick McLean, William McLean, Joan McLellan, Charles McLeman, Mandi McLenehan, Charles McLeod, Ian McLeod, Eamonn McMahon, Liana McMahon, Blake McManus,
Sandra McMichael, Rod McNair, David McNamara, Jennifer McNeelands, Ron McNeil, Robert McNinch, Erma McNulty, Reid McPhail, Jamie McPherson, Richard McRae, Jacqueline McTamney, Maggie McTurk, Marc Meadwell, Manfred Meakes, Isabel Medina,
Nestor Medina, Tatrina Medvescek, Karyn Meehan-Coles, Jai Mehta, Corrine Mei, Jessica Meister, Juan Mejia, Daniel Melanson, Majid Melatdoost, Belinda Meller, Glen Mellom, Darrell Mellott, Marvin Melnyk, Paul Mendes, Nelson Meneses, Crystal Mercer,
Jennifer Mercer, Mark Mercer, Paula Mercier, Ambereen Merk, Timothy Merk, Greg Merkel, Danny Merkley, Anthony Merle, Nathaniel Merritt, Udell Meservy, Marina Mesquita, Ryan Metz, Steve Meunier, Michael Meynberg, Emma Meynin, Igor Meynin, Saravanan
Meyyappan, Cindy Michalko, Gail Michaud, Barry Michelson, Kevin Michener, Murray Michie, Jennifer Michiels, Barry Middleton, Dale Midgley, Marc Miiller, Jane Mikalsky, Andrei Mikhailov, Jacqueline Miko, Jeffrey Miller, Laurel Miller, Roger Miller, Sherrie Miller,
Wendy Miller, William Miller, David Milligan, H John Mills, Ronald Mills, Colin Milne, June Milne, Nicholas Milne, Terence Milne, Shikha Minhas, Jonathan Minick, Michelle Minick, Wyman Minni, Susan Minns, Denis Mino, Barry Mintenko, Mason Mintenko, Kerry
Minter, Alan Minty, Willian Mirabal, Mahmood Mirza, Anice Mitangou, Allan Mitchell, Sandy Mitchell, Yvonne Mitchell, Anar Mitha, Leon Miura, Tom Moen, John Moffat, Roman Mognin, Bassam Mohammed, Kim Mohler, Derek Moir, Lydia Mok, Mimi Mok, Jeff
Molde, Dwayne Molle, Jelena Molnar, Mike Monias, Rosa Monna, Pamela Montague, Frances Montefresco, Rick Monteith, Vicente Montenegro, Nicholas Montevecchi, John Montgomery, Mary May Bernadette Montinola, Heather Moody, Ken Moon, Dave Moore,
Norma Moore, Claudia Moran, Jason Moravec, Orlando Morean, German Moreno, Hernan Moreno, Christopher Morgan, Jonathan Morgan, Karen Morgan, Shaun Morgan, Michael Moriarty, Sherril Moring, Shaun Moroziuk, Karen- Anne Morrice, Janette Morris,
Kyle Morris, Nicole Morris, Scott Morris, Tyler W Morris, Denny Morrison, Donald Morrison, Jeanette Morrison, Jennifer Morrison, Louise A Morrison, Randle Morrison, Merle Morrisseau, Wesley N Morrow, Shannon Moseng, Tim Moskol, Paul Mossey, Glen Mott,
Bruce Mottle, Michael Mousseau , Cheryl Mouta , Gary Mowat , Glen Moyer , Wayne B Mudryk , Godswill Mugambiwa , Lee Mugford , Colin Muir , Siddhartho Mukherjee , Peter Mulcahy , Lee-Ann Mules , Lucy Mulgrew , Wanda Mulkay , Leon Mulrooney ,
Noella Mulvena , Ryan Munro , Jeffrey Murdock, Alicia Murphy, Cora Murphy, Kenneth Murphy, Patrick Murphy, Carrie Murray, Cliff Murray, Terence Murtagh, Aaron Musil, William K Muss, Blyth Mutch, Kevin D J Mutch, Dan Myers, David Myshak, Melonie
Myszczyszyn, Richard Nachtegaele, Jeannine Nagy, Bill Nalder, Elly Nance, Rick Napier, Sajid Naqvi, Kuralenthi Narayanan, Bill Nash, Henriette Ndjoteme-Nendjot, Marian Neagu, Randy Necember, John E Neff, Donald Neigum, Lois Neil, Allen Neilson, John
Nejedlik, Andrew Nelson, Donna Nelson, Douglas Nelson, Gilbert Nelson, Vincent Nelson, Brad Nessman, Steven Neu, Monty Neudorf, Caleb Neufeld, Henry Neufeld, Shelley Neufeld, Darrell Nevil, Daryl Newbigging, John Newman, Lisa Newman, Stephanie
Newnham, Luke Newport, Kevin Newton, Rae Newton, Alice Ng, Hannah Ng, Tchimou N’Gbesso, Eileen Ngo, Hien Ngo, Mpinga Ngoy, Cindy Nguyen, Melissa Nguyen, Tai Nguyen, Muhammad Niaz, Matteo Niccoli, Fawn L Nichol, Jonathan Nicholl, Gary Nichols,
James Nichols, Doris Nickel, Matthew Nicol, Josie Nicolajsen, Ian Nieboer, Wayne Nielsen, Orlando Nieto, Mona Nighswander, Wesley Nikiforuk, Chris Nixon, Roger Nolan, Greg Nolin, Bill Norberg, Alexander Norburn, Lawrence Nordstrom, Robert Norman, Troy
Normand, David Noseworthy, Allen Noskey, Kerry Novinger, Anne Nowakowski, Daniel Nugent, Kelvin Nurkowski, Genia Nyenhuis, Tim Nyitrai, Donald Oaks, Cam Oberg, Blair O’Brien, Ken O’Brien, Pamela O’Brien, Tim O’Brien, Jeffery Obrigewitsch, Pedro Ocana,
Tim O’Connor, Kathleen Odendahl, Richard Odlin, Rick O’Donnell, Terry Oele, Julie Oganwu, Robert Ogilvie, Kevin O’Hearn, Ryan Okada, Charles O’Keefe, Steve O’Keefe, Michael Olaniyan, Paul Olaniyan, Blake Olaski, Delvin Olesen, Dianne Oliveira, Filomena
Olivito, Jason G Ollikka, Ghasem Oloumi, Amber Olsen, Kevin Olsen, Richard Olsen, Dean T Olson, Shauna Olson, Stephen Olson, Steven Olson, Warren Olson, Bunmi Oluwole, Kevin Ondic, Dave O’Neil, David O’Neill, Tim O’Neill, Emmanuel Onumonu, Margaret
Oporska, Robert Orbeck, Steven O’Reardon, Anna Oreshkova, Doug Orlecki, Alison Orr, Colette Orr, Neil Orr, Lucy Ortiz, Justin Osadczuk, Wayne Otteson, Tyler Ouart, Patrick Oudin, Mike Ouellet, Denis Ouellette, Jolanta Ouellette, Keith Ouellette, Jean-Francois
Ousset, Mark Overwater, Janet Owen, Mark Owen, Leonard Owens, Gervais Owono, Dennis Ozaruk, Fabio Pacheco, Ron Pacholuk, Jared Paddock, Dante Padilla, Robyn Padwicki, Elgin Paglinawan, Marcus Pagnucco, Robert Painchaud, Randall Paine, Elizabeth
Palmer, Lee Palmer, Rick Palmer, Glenn Paluck, Miodrag Pancic, Amol Pande, Garry Pangracs, William Papineau, Alishia Paradis, Pat Paradis, Travis Paradis, Antony Paradoski, Blair Parent, Bernard Parenteau, Clement Parenteau, Joanna Parenteau, Sachin Parikh,
Blaine Parker, Darby Parker, John Parker, Nicole Parker, Shawna Parker, Barry Parkin, Randy Parkyn, John Parr, Diane Parry, Cheryl Parsons, Krista Parsons, Jordy Partington, Lawrence Paslawski, Joey Pasos, Ashish Patel, Bhaveshkumar Patel, Hasmukhlal Patel,
Mahendra Patel, Nikunjkumar Patel, Nisha Patel, Paresh Patel, Pragnesh Patel, Sanjaykumar Patel, Narendrasingh Pateliya, Andy Paterson, Judy Paterson, Richard Patey, Brandon Patrick, Brian Patterson, Donna Patton, Geoffrey Paul, Eric Paulin, Wilma Pauls-Atas,
Brent Paulson, Brian Paulssen, Daniel Pavelick, Lance Pawlik, Richard Pawlyn, David Payne, Dean Payne, Paul Payne, Ron Pearce, Gerald Pearson, Pam Pearson, Chantal Peddle, Danika Peddle, Philip Pedersen, Brian Pederson, Lance Pederson, Luvelyn Pedro,
Hendrickson Pedroza, Dianne Peel, Cam Peifer, Sandra Pelkey, Sean Pell, Daniel Pelletier, Deborah Pemberton, Peter Peng, Robin Penner, Kevin Pennington, John Penzo, Subodh Peramanu, John Perepelecta, Nihal Perera, Luis Perez, Luis Alfonso Perez, Mark Perkins,
Julito Peroramas, Craig Perrin, Nancy Perron, Don Perry, Gladys Perry, Trevor Perry, Vicki Perry, Tarla Persaud, Darrell Person, Bernie Persson, Deborah Peters, Shelley Peters, Carson Petersen, Casey Petersen, Bill Peterson, Melissa Peterson, Miranda Peterson, Tracy
Peterson, Ron Petit, William S Petlyk, Dino Petrakos, Rick Petrick, Rodney Petrie, Shauna Petrock, Nicolas Petrola, Lucyna Pettigrew, John Pettit, Lien Pham, Sherry Phan, Peter Phillips, Rod Phillips, Russell Piche, Alain Pickersgill, Doug Pierce, Frank Pike, Barbara
Pilgrim, Ron Pilisko, Jodi Pilsner, Kathy Pinco, Dale Pinder, Jose Pinerua, Nelson Pires, Josef Pisa, Kyle Pisio, Edward Pittman, Adrian Plaiasu, Julio Plata, Ted Plouffe, Erwin Po, Imhotep Pocaterra, Justine Podolchuk, Ricot Poitevien, Donna Poitras, Wade W Poitras,
David Pole, Christopher Pollard, John R Pollock, Morgan Pollock, Eleanor Polson, Seward Pon, Haripradha Ponnurangan, Robert Pool, Colleen Popko, Jason Popko, Tsvetan Popov, Diane Porter, Fred Post, Patti Postlewaite, Ryan Postnikoff, Jeffrey Poth, Stephanie
Pothier, Jason Potter, Terry Potter, Randy Pottle, Craig Pottruff, Ryan Potts, Jesse Poulin, Dave Powell, Susan Powell, Laurie Power, Lisa Power, Melissa Power, Tiffany Power, Mitesh Prajapati, Dhrub Prasad, Jeffrey Pratt, Timothy Pratt, Mike Preece, Robert
Prefontaine, Alanna Price, Robert Price, Travis Prins, Melodi Pritchard, Doug Proll, Mangoueu Prosper, Sarah Proudlock, Richard Proulx, Kayla Prowse, Steve Pshyk, Yesid Edgar Puerto, Domenic Puglia, Justyna Puhl, Nam Pui, Lance Pulak, Derek Pullem, Sachin
Pupneja, Shantelle Purcell, Suniel Puri, Trent Pylypow, Kent Qin, Lu Qing, Munawar Quadri, Tony Quan, John Quick, Duane Quigley, Ron Quiring, Samir Qureshi, Mandi Rabeau, Nathan Rabinovitch, Warren Raczynski, Nelda Radford, Gen Ragelyte, Subodh Chandra
Raghavan, Morteza Rahmanian, Priya Rai, Michael Rainey, Yina Raisbeck, Vidas Ramachala, Cristina Ramirez, Maritess Ramirez, Ruth Ramonas, Lorraine Ramsay, Robert Ramsay, Kerri Ramsbottom, Len Rancourt, James Rankin, Dorotea Ranola, Gregory Ransom,
Jeremy Ransom, Tariq Rasheed, Chris Rasko, Shauna Rasmussen, Wade Ratcliffe, Soukseum Rathamone, Stojan Ratkovic, Murray Rattray, Andrew Rau, Carrie Rawlake, Derek Ray, Jason Rayner, Robert Rayner, Blair Read, Wayne Reashore, Ted Reay, Deston Reber,
Bernie Redlich, Jon Reed, Keith Reed, Loreena Reed, Scott Reed, Tim Reed, Michael Rees, Duncan Rehm, Carmon Reich, Alan Reid, Cameron Reid, Christopher Reid, Kerry Reid, Lilian Reid, Mark A Reid, Marty Reid, Tyler Reid, Sarah Reid-Bicknell, John Reiniger,
Glenn A Reiter, Harvey Reithaug, Wendy Reitmeier, David Rejman, Audrey Rempel, Long Ren, Shirley Renaud, George Renfrew, Alexander Scott Rennie, Dustin Ressler, Jose Restrepo, Orville Reyes, Gregory Reynolds, James Reynolds, Pat Reynolds, Naseem
Rhemtulla, Bruce Rice, Donna Rice, Jennifer Rice, Lisa Rich, Tammy Richard, Carolyn Richards, Charles Richards, Gerald Richards, Rob Richardson, Susan Richardson, Wesley Richardson, William Richardson, Lori Richmond, William Richmond, Jeff Riddell, Robert
Riddell, Bonnie Ries, Darren Riley, Dominic Riley, Carl Ringdahl, Mike Rioux, Serge Rioux, Darren Risling, Lawrence Ritchat, Laura Ritchie, Michelle Rivard, Ana Rivera, Carlos Rivera, Ismael Rivera, Sammie Rivet, Syedinamali Rizvi, Andrew Roach, Ken Roach,
Tracey Roasting, Jo-Anne Robak, Terrence Robbins, Brian Robertson, Dale Robertson, Malcolm Robertson, Michael Robertson, Morag Robertson, Nancy Robertson, Stephen Robertson, Aaron Robinson, Amber Robinson, David Robinson, Gene Robinson, Julian
Robinson, Scott Robson, Aaron Roche, Lennon Roche, Jesse Rockarts, Neal Roculan, Sheila Rodberg, Roger Rodermond, Ray Rodh, Olga Rodriguez, Paul Roett, Dean Rogal, Audrey Rogers, Martin Rogers, Murray Rogers, Neil Rogerson, Lisbeth Rojas, Mercibeth
Rojas-Bouchard, Henry Rojo, Paul Rokosh, Louis L Romanchuk, Dwayne Romanovich, Donny Romanyshyn, William Rombough, Eduardo Romeo, Joy Romero, Claude Rondeau, Darren Rondeau, Eric Rondeau, Jeffrey Rose, Andrew Ross, David Ross, Dennis Ross,
Jason Ross, Robert Ross, Ron Ross, Graham Rosso, Worley Rosson, Barry Rosychuk, Cheryl Rosychuk, Rick Rosychuk, Roy Roth, Samuel Roth, Tom Roth, Katarina Rothe, Judy Rotzoll, David Rouleau, Gordon Rourke, Richie Rovere, Natasha Rowden, Scott Rowein,
Michael Rowland, Beverly Roy, Zenita Ruda, Vivian Ruddy, Colleen Rudolph, Marie-Louise Ruetz, Adam Ruff, Colleen Ruggles, Nigel Rusk, Ryan Rusnell, Denise Russell, Matthew Russett, Jeff Rutherford, John Rutherford, Brian Rutledge, Doug L Rutley, Justin
Rutley, Mark Rutter, Hal Rutz, Andrea Ryan, Dan Ryan, Rick Rybchinsky, Craig Ryder, Jeff Ryll, Romulo Sabas, Mikael Sabo, Muhammad(Saqib) Saeed, Ludmila Safonova, Jochi Sahabandu, Ashok Saini, Poonam Saini, Joseph Sair, Darlene G Sakires, Rodrigo Sala,
Dwight Salahub, Sherrie Salahub, Alba Salazar, Carla Salazar, Diana Salazar, Shahid Saleem, Wesley Salkey, Whitney Salkey, Peter Salomon, Gord Salt, Geoffrey Samuel, David Sanderson, Michael Sanderson, Sandy Sandhar, Tom Sanelli, Eddy Sangroniz, Juan Pablo
Santini, Theo Santos, Megan Santucci, Andrea SanVicente-Kraus, Sameer Saran, David Sargent, John C Sargent, Anita Sartori, Martin Sas, Greg Sauer, Lisa Saumier, Ashleigh Saunders, Chantelle Sauve, Jesse Savard, Luc Savoie, Michelle Savoie, Colin Savostianik,
Todd Sawchuk, William Sawyers, Chris Sayer, Richard Sayer, Amber Sayers, Kimberley Scagliarini, Ryan Scammell, Brian Scarth, Robert Schaap, Trevor Schable, Bruce Schade, Judy Schafer, Brenda Schamehorn, Paul Schaub, Alan Schaufele, Lorne Schaufert, Perry
Scheffelmaier, Mike Schellenberg, Lance Schelske, Lou Scheper, Larry Schielke, Dianne Schiewe, Brad Schiller, Mike Schiller, Andrew Schindel, Ronald Schlachter, Marcus Schlegel, Helen Schlenker, Casey Schmaltz, Tracy Schmaltz, Jeannette Schmidt, Joseph Schmitz,
Melissa Schmitz, Christopher Schneider, Darryl Schneider, David Schneider, Debbie Schneider, Joseph Schneider, Ngoc Schneider, Paul Schneider, Shaun Schneider, Blaine Schnell, Aaron Schnick, Jack Schnieder, Ronald Schnieder, C Brian Schnurer, Stephen Schofield,
Norm Schonhoffer, Sheldon Schroeder, Michael Schubert, Tricia Schuh, Nathan Schuler, Stephen Schultheiss, Jaclyn Schultz, Randy Schultz, Kevin Schumacher, Derek Schutte, Lorraine Schwetz, Leslie Scory, Curtis Scott, Drew Scott, James Scott, John Scott, Murray
Scott, Ronalda Scott, Rodney Scoville, Ashley Scriba, Marc Scrimshaw, Ian Scully, Neil Scully, Gordon Seabrook, Christa Seaman, Geordie Seaton, Don Sedor, Morley Seguin, Stephen Seguin, Linda Sehn, Clayton Seifridt, Paul Seipp, Fraser Selfridge, Mike Sell,
Kenneth Selman, Leslie Semeniuk, Megan Semjanovs, Roland Senecal, Trevor Senger, Debbie Sereda, Derek Serfas, David Sergeant, Edward Serniak, Ligia Serrano, Cindy Severite, Gianni Sgambaro, Mohsen Shafizadeh, Bhavin Shah, Maulesh Shah, Samir Shah,
Sanjay Shah, Philip Shankowski, Gilbert Shantz, Raj Sharma, Brigitte Shaw, Ian Shaw, Lisette Shaw, Christopher Shears, David Sheaves, Wayne Sheaves, Ben Shenton, Glenn Sheppard, Leah Sheppard, Nathan Sheppard, Robert Sheppard, Tim Sheppard, Judi
Shermerhorn, Dean Shewchuk, Colin Shields, Nick Shier, Annette Shillam, Liz Shivas, Bill Shmoury, Bryden Shmyr, Leonard Shostak, Michael Shukalov, Robert Shumay, Lisa Shute, Evelyn Sibley, Indrajit Siddhanta, Melanie Siddon, Pritam Sidhu, Travis Siemens,
Wayne Sikorski, Beh Silue, Armindo Silva, Elvin Silva, Ismael Silva, Cam Simard, Kevin Simard, Vladan Simin, Gregory Simm, Francesca Simms, Doug Simoneau, Barbara Simpson, Brad Simpson, Cameron Simpson, Gordon Simpson, Jilleen Simpson, Nicola Simpson,
Pat Simpson, Elisha Sinclair, Garry Sinclair, Robert Sinclair, Jerret Singer, Inder Singh, Sarbjeet Singh, Darcy Singleton, David Sirtonski, Richard Sisson, James Sjonnesen, Matt Skanderup, Kelly Skarra, Geoffrey Skinner, Michael Skipper, Max Skliarov, Grace Skoczek,
Mary Skogland, Warren Skomorowski, Shirley Skulmoski, Martin Skulski, Nicolas Skulski, Michael Skyrpan, Michael Slavin, Edward Sleet, Delwin M Slemp, Darrell Sleno, John Slipchuk, Kevin Slotwinski, Jason Sloychuk, Doreen Smale, Lyle Small, Samantha Small,
Bill Smith, Blair Smith, Carl Smith, Catriona Smith, David L M Smith, Jason Smith, Maurice Smith, Michael Smith, Michael Smith, Nancy Smith, Robert Smith, Robert Smith, Rory Smith, Ryan Smith, Sandi Smith, Sandra Smith, Scott Smith, Tim K Smith, Tina Smith,
Todd Smith, Trevor Smith, V Todd Smith, Allen Smyl, Richard Smyl, Brad Smylie, Garry Snider, Kurt Snow, William Snow, Douglas Snyder, Jessica Solar, Jennifer Soley, Angelina Solis, Kathleen Soltys, Immanuelraj Soosaiprakasam, Hans Sorensen, Curtis Sorochan,
Daryl Soroko, Golam Sorwar, Dallas Spagrud, Paul Spavor, Edmund Spearman, Jason Spears, Robert Spears, Ashley Spence, Kevin W Spencer, Brent Spendiff, Darcy Spenst, David Spetz, Tony Spitz, David Spooner, John Springer, Mike Sprinkle, Ellis Spurrell, Paul
Spurvey, Arthur Squire, Lawson Squire, Murugan Srinivasan, Eric St Pierre, Robert St Amant, Gayle St Croix, Robert St Martin, Mario St Pierre, Barry St Jean, Carrie Stacey, Ian Stacey-Salmon, Glen Stadnichuk, Randy Stadnyk, Stacey Stadnyk, Tyson Stafford, Kendall
Stagg, Mark Stainthorpe, Karen Stairs, Ernesto Stamile, Randy Stamp, Nick Stanford, Laura Stang, Kellie Stante, Cindy Stanway, Kristen Stark, Lezlie Stark, Christie Starnes, Scott Stauffer, Scott Stauth, Nicole Stebbings, Craig Steel, Don Steele, Richard Steele,
Pamela Steenson, Leanne Steeves, Gary Stefan, Silviu Stefan, Wayne Steffen, Carolyn Steinson, Allan Stella, Robert Stelten, Peter Stephen, Taryn Stephenson, Jane Stevens, Lyle Stevens, James Stevenson, Robert Stevenson, Robert B Stevenson, Carol Stewart,
Cody Stewart, Douglas Stewart, Karen Stewart, Lorie Stewart, Rory Stewart, Wendy Stewart, Rick Stieben, Kevin Stilwell, Stewart Stirling, Melissa Stockes, Mark Stockton, Shaun Stokes, Didier Stout, Suzanne Strachan, Wade Strand, Robert Strang, Linda
Strangway, Tanner Strangway, George Stratford, Brenda Stratichuk, Michael Street, William Stretch, Darcy Stringer, Michael Stroh, Robert Struski, Dwayne Strynadka, Linda Stuart, Peter Stuart, Allan Stubel, SueAnn Stuckey, Christopher Study, Mike Sturkenboom,
David Sturrock, Ravi Subramaniam, Stephen Suche, Chris Suhan, Mark Sullivan, Shelley Sullivan, Victoria Sullivan, Shiraz Sumar, Effie Summers, Daniel Sutherland, Rick Sutton, Scott Sverdahl, Rade Svorcan, Amer Swadi, Steven Swain, Christine Swan, Stephen
Sweetapple, Nathan Swennumson, Halina Swierz, Paul Swire, Edward Switzer, Ryan Switzer, Stacey Sydia, Don Sylvestre, Catherine Szmata, Derek Sztym, Szymon Szymczakowski, Jeffrey Ta, Vicky Ta, David Taggart, Morgan Taheri, Patrick Taiani, Dave Talbot,
Miguel Tamayo, Krystalle Tanner, Michael Tanouye, Cedric Tapley, Crisalida Tarache, Bill Tarkowski, Ron Taron, Joanne Taubert, Nader Tavassoli, Ray Taviner, Brian Taylor, Carla Taylor, Cat Taylor, Colin Taylor, Dana Taylor, Dawn Taylor, James Taylor, James R Taylor,
Jennie Taylor, Ken Taylor, Ken W Taylor, Leroy Taylor, Michelle Taylor, Paul Taylor, Todd Taylor, Joseph Taza, Yves Tchicaya, Chin Seng Teh, Jenny Tejada, Mariana Teleptean, Berhanu Temesgen, Tammy Temple, Robert Templeton, Derek Tempro, V Leighton Tenn, Kurt
Tenney, Marilyn R Tenold, Gus Teske, Brock Tetz, Terence Tham, Richard Theberge, Mark Theriault, Marc Theroux, Bob Thibodeau, Richard Thibodeau, Chad Thiessen, Jill Thiessen, Rinet Thissen, Karen Thistleton, Laurie Thomas, Matthew Thomas, Steven Thomas,
Angela Thompson, Arthur Scott Thompson, Chris Thompson, Gerald Thompson, Herb Thompson, Ian Thompson, Lindsay Thompson, Mark Thompson, Wayne Thompson, Peter Thomsen, Adele Thomson, Julie Thomson, Rory Thomson, Earl Thornton, Keith Thornton,
Sharon Thuillier, Jason Thurlow, Margaret Thurmeier, Leonard Thyr, Brian Tiffin, Michelle Tilford-Shaw, Daniel Tillapaugh, Joseph Tiller, Terry Tillotson, Colin Tiltman, David Timms, Simon Timothy, Neil Tindall, Bruce E Tipton, Dharmendra Tiwary, Ravindra Tiwary, Eric
To, Carol Tobin, Kevin Tobler, Ron Tochor, Joana Todica, Alfred Tokpa, Christopher Tomlinson, Dale R Tomlinson, David Tonner, Blair Torgerson, Lesley Torrance, Domenic Torriero, Michael Tosio, Derek Toullelan, David Tovey, Sabrina D Trafiak, Brittany Trask, Warren
Trelinski, Josie Tremblay, Maurice Tremblay, Catherine Trenouth, Brian E Trimble, Amy Trinh, Duc Trinh, Len Trotzuk, Ruaidhri Truter, Lisa Tsimaras, David Tuite, Sunny Tulan, Brent Tulloch, Neil Tulloch, Bruce Tumbach, George Tunnicliffe, Art Tupper, Terry Turgeon,
Trent Turgeon, Dick Turnbull, Dave Turner, Gene Turner, Ruth Turner, Stanley Turner, Darren Turpin, Veronika Turska, Mark Tustian, Irene Tutto, Dave Tweddell, Gordon Twin, Oleg Tyan, Angela Tyler, Wayne Tymchuk, Shaun Tymchyshyn, Don Tyner, Peter Tyrer, Eric
Ulrich, Gregory A Ulrich, Joselito Umali, Janis Underdahl, Nathan Underwood, Karl Unger, Earl Ungeran, David Unruh, Unnati Upadhyaya, Jackeline Urdaneta, Anand Vaidyanath, Allan Valentine, Gary L Valiquette, Darren Vallee, Louis Vallee, Michael Vallee, Anna
Valmadrid, Bryant Van Iderstine, Henk-Jan van Klinken, Vicki Van Orman, Salomon Van Rensburg, Christina Vander Pyl, Kevin Vandergaag, Vyvette Vanderputt, Collin Vare, Michael Varga, Selena Varga, Maria Vasquez de Placid, Daniel Vasseur, Nicolette Vaughan,
Blaine Veitch, Gerrit Veldman, Brandon Velichka, Steve Venus, Jorge Vera, Sheila Verigin, Natalia Verkhogliad, Dan Verleyen, Nancy Tay Vetrici, Cesar Viana, Bonnie Vickery, Wilf Vielguth, Angu Vifansi, Christine Viljoen, Ronald Vinkle, Dean Vipond, Bill Virus, George
Virus, Mark Virus, Santosh Vishwakarma, Tony Vitkunas, James W Vollman, Mel Vollman, Luke Vondermuhll, Blake Von-Grat, Chrystal Voortman, Gary Wack, Richard Wack, Kyle Waddy, Gene Wafler, Valerie Wagar, Todd Waggoner, Trevor Wagil, Joy Wagner, Juon
Wah, Lee Wahl, Donald Wakaruk, Lance Wakefield, Michael Lane Wakefield, Kevin Wakulchyk, Jeff Walden, Dave Waldner, Darcy Waldo, David Walker, David Walker, Dean Wall, Erin Wallace, Greg Wallace, Kevin Wallace, Vince Wallwork, Patrick Walsh, Lorie Walter,
Amanda Walters, Kevin Walters, Michelle Walton, John A Wandler, Jinghao Wang, Ping Wang, Selina Wang, Wenyan Wang, Xiang Wang, Xing Zhu Wang, Blaise Wangler, Kevin Warcimaga, Danny Ward, Kathy Ward, Keith Ward, Kirk Ward, Terry Ware, Wayne M J
Warholik, Chris Wark, Wanda Warman, Jason Warren, Rob Warren, Michael Warrick, Faye Warrington, Warren Waskowic, Paul T Wassell, James Waterfield, Frank Watkin, Julie Watkins, Kaye Watson, Ken Watson, Twila Watson, Debra Watt, Gordon Watt, Graham
Watt, Alan Webb, Byron Webb, Keith Webster, Gail Wee, Kim Wee, Eric Weening, Jeff Weibrecht, Derren Weimer, Lionel Weinrauch, Randy Weir, Brock Weisgerber, Bonnie Wells, Kelly Wells, Lisa Welsh, Guy Welwood, Mark S Wenner, Jeromy Wenzlawe, Dwayne
Werle, Craig Werstiuk, Matthew Werstiuk, Ted Wesley, Darrin West, Jacqueline West, Michael Westad, Kris Westland, Nina Whalen, Troi Whalen, John Wham, Loyd Wheating, Ceri Wheaton, Joshua Wheaton, Andrew Wheeler, Charmaigne Whelan, Chris Whelan,
Rosemarie Whelan-Maloney, Judd Whidden, David White, David White, Francis W White, Howard White, Jeffrey White, Ken White, Ralph White, Robert White, Terence White, David Whitehouse, Audrey Whitlock, Michael Whittingham, Heather Whynot, David Wiebe,
Malcolm Wiebe, Debbie Wiens, Cameron Wietzel, Cheryl Wiggett, Zandra Wigglesworth, Steven Wight, Don Wijesingha, Bob Wilbern, Mason Wilcox, Brandon Wild, Darrell Wilde, John Wilding, Daryl Wiles, Troy Wilk, Clifton Wilkes, Melanie Wilkie, Derek Wilkinson,
Pauline Will, Peter Will, Elmer Willard, Stanley Willette, Bill Williams, Brent Williams, Dustin Williams, Grant Williams, Greg Williams, Julian Williams, Sherri Williams, Wes Williams, Curtis Williamson, Kelvin Williamson, Monty Williamson, Brennon Willick, Jeff
Willick, Robin Willis, Christian Willson, Curtis Wilson, Don Wilson, Ian Wilson, James Wilson, Jeff Wilson, Jody Wilson, Marty Wilson, Patrick Wilson, Tricia Wilson, Tyler Wilson, Woodrow Wilson, Joan Wilton, Daryl Winnicky, Jodie Winquist, Ken Winsborrow, Craig
Winsor, Greg Winters, Garrett Wirachowsky, Morrison Wiseman, Paul Wiseman, Dale Wittman, Cameron Wlad, Kelly Woidak, Colin Woloshyn, C K Bill Wong, Jennifer Wong, Keith Wong, Linda Wong, Lisa Wong, Maggie Wong, Pauline Wong, Julie Woo, Leonard
Wood, Lynn Wood, Philip Wood, Roxanne Wood, Timothy Wood, Mark Woodfin, Marilyn Woodske, Wayne Woodward, Robin Woolner, Sidney Wosnack, Raymond Wourms, Mark Woynarowich, Chris Wright, Dorothy Wright, Richard Wright, Stephen Wright, Bin
Wu, Diana Wu, Jeff Wurzer, Christine Wutzke, Kelly Wutzke, Brent Wychopen, George Wyndham, Brent Wyness, Valerie Wyonzek, Brenda Wyton, Qiang Xu, Ken Yakimowich, Canghu Yang, Lin Yang, Zhen Lin Yang, Mike Yanota, Andrew Yaremko, Rick Yarmuch,
James Yaroslawsky, Salman Yasin, Noah Yates, Basile Yeboue, Betty Yee, Davin Yee, Claire Yeoman, Justin Yeon, Jeffrey Yip, Kitty Yip, Mark Yobb, Ibrahim Yohanna, Amber Yoingco, Nina Yomi, Darrell York, Rachelle Yorke, Daryl Youck, Andrew Young, Chalene Young,
Dale Young, Kevin Young, Lynn Young, Michael Young, Robert Young, Sylvia Young, William Young, Ray Yowney, Eugene Yu, Clement Yuen, Dustin Yuill, Jeff Yuill, William Yuill, Brian Yurchyshyn, Robin Zabek, Tyler Zachoda, Cam Zackowski, David Zahara, Kent
Zahara, Lisa Zaharichuk, Attila Zahorszky, Gabri Zambrano, Doug Zarowny, Kendall Zarowny, Chris Zeebregts, Lynn Zeidler, Tony Zeiser, Aleksandra Zelic, Diane Zeliznik, Devon Zell, Warren Zeller, Darcy Zelman, Denis Zentner, Kathy Zerr, Michelle Zerr, Jessica
Zhang, Yingte Zhang, Adam Zhao, Susan Zheng, Wanli Zhu, Brenda Ziegler, Dwayne Zilinski, Megan Zilkey, Esther Zondervan, Aaron Zubot, Adriana Zuniga, Diana Zurabyan.
CA NA DIAN NATURAL
11
canadian natural 2 008 a n n u a l r e p ort
world-class assets
Canadian Natural’s strong, low-risk asset base includes
natural gas and crude oil properties, highlighted by world-
class oil sands in-situ and mining developments.
creating value: defined strategy
Canadian Natural’s strategy is based on allocating capital to maximize
returns. This is achieved through effective execution by being proactive
and recognizing and capturing opportunities. The Company dominates its
core areas and maintains high levels of ownership and operatorship for all
of its properties. This allows for cost control, flexibility and efficient
decision making. We are the drivers of our own destiny.
Balance is a key part of our approach to business. The Company maintains
balance in its product mix, producing both natural gas and crude oil.
We balance our project time horizons between near, mid and long-term
projects. Finally, we balance organic growth with growth through
acquisition.
We focus on long-term value creation through our defined plan for
profitable growth. We have extensive knowledge and experience in
mature basin exploitation, utilizing our expertise in all of the basins in
which we operate, whether it be the Western Canadian Sedimentary
Basin (“WCSB”), the North Sea or Offshore West Africa.
North America
Canadian Natural’s North American operations serve as
the foundation for the Company, with a balanced portfolio
of assets, providing low-risk, sustainable and economic
production.
n Canadian Natural has the largest undeveloped land base in the WCSB
and a large infrastructure position.
n We have exposure to major natural gas resource plays in the WCSB and
balance the development of new natural gas resources with the
development of low-risk conventional assets.
n We are one of the largest producers of conventional crude oil and NGLs
in Western Canada, and have 285,000 bbl/d of incremental crude oil
projects to develop from our thermal heavy crude oil asset base.
n The Horizon Project includes a surface oil sands mining and bitumen
extraction plant, complimented by on-site bitumen upgrading and
associated infrastructure. The Horizon Project produces high quality
synthetic crude oil.
12
CANAD IA N NATU RAL
north america
2008 net, after royalties
Production
(mboe/d)
Proved reserves (1)
(mmboe)
Crude oil and NGLs
Natural gas
Boe
% of total
208
204
412
85
948
587
1,535
78
international
2008 net, after royalties
Production
(mboe/d)
Proved reserves (1)
(mmboe)
Crude oil and NGLs
Natural gas
Boe
% of total
68
4
72
15
398
27
425
22
horizon proJect mining
2008 net, after royalties
Proved reserves (1)
(mmbbl)
Synthetic crude oil (2)
1,946
(1) Based on constant prices and costs.
(2) SCO reserves are based upon upgrading of the bitumen volumes
using technologies implemented at the Horizon Project.
BC
AB
SK
MB
North
America
ca na dia n natu ral 2008 a nn u a l r epo rt
allan m. Knight
SENIOR VICE-PRESIDENT,
INTERNATIONAL & CORPORATE DEVELOPMENT
Production by region,
net of royalties
85%
NORTH AMERICA
NORTH SEA
10%
OFFSHORE WEST AFRICA 5%
North Sea
Offshore West Africa
Canadian Natural’s core competency in the UK
portion of the North Sea is managing existing
infrastructure and extending field life in a
mature basin.
Canadian Natural’s competitive advantage in
Offshore West Africa lies in the relationships the
Company has built with the stakeholders of Côte
d’Ivoire and Gabon.
n A source of high value, light crude oil with long-term
n Generates significant free cash flow providing light crude
developments.
oil growth.
n Capitalize on core competency of mature basin exploitation.
n Provides some of the highest returning projects in the
Company.
Africa
Atlantic Ocean
North Sea
UK
CA NA DIAN NATURAL
13
canadian natural 2 008 a n n u a l r e p ort
operations defined
production
As commodity and market prices fluctuate, Canadian Natural’s approach to business remains consistent. The strength of our strategy
was demonstrated throughout 2008, as a volatile and uncertain business environment put the industry to the test. We continue to
maintain balance within our portfolio of assets, project time horizons and production growth. We take a cautious approach in
developing our assets and maintain large project inventories in both natural gas and crude oil. As a result, we have the ability to high
grade projects, to develop and produce those assets that yield the highest returns. Canadian Natural allocates capital to maximize
returns amongst the commodities we produce (i.e. natural gas, light crude oil, Pelican Lake crude oil, primary heavy crude oil,
thermal crude oil, and synthetic crude oil (“SCO“) from oil sands mining). Time and resources are allocated towards those projects
that give the greatest economic return. Canadian Natural has a proven track record based on low-risk, exploitation based production.
Most importantly, we control our costs through area knowledge and domination of our core areas.
During 2008, production before royalties was 565 mboe/d, a slight decline from 2007 levels of 609 mboe/d. The decline in
production resulted from Canadian Natural’s strategic decision to reduce spending on natural gas drilling. Natural gas production,
before royalties, for the year averaged 1,495 mmcf/d, down 10% from 2007. Crude oil volumes for 2008 were down averaging
315,667 bbl/d for the year, a decrease of 5%. The decrease in crude oil was a result of natural declines in primary crude oil drilling,
strategically reduced activity in the North Sea, and the nature of the steaming cycle in thermal crude oil operations.
strategic land base
Canadian Natural has the largest conventional undeveloped land base in the WCSB, with undeveloped net acreage of 11.5 million
acres. The strength and depth of Canadian Natural’s land base is a result of continued land purchases and utilizes strategic
acquisitions. Our land base affords significant opportunities to control operating costs, along with finding and on-stream costs. The
majority of the Company’s land base is positioned to utilize existing owned and operated infrastructure and also strategically
positions Canadian Natural to maximize the benefit of new play types developed by ourselves and industry.
The infrastructure associated with our land base also provides a competitive advantage in terms of lowering marginal operating
and development costs for newly drilled or acquired properties. This dominance can create acquisition opportunities as we control
access to strategic infrastructure and maintain a low-cost regime.
(before royalties)
Natural gas
North America light/medium crude oil and NGLs
Pelican Lake crude oil
Primary heavy crude oil
Thermal heavy crude oil
North Sea light/medium crude oil
Offshore West Africa light/medium crude oil
Total
2008
2007
Production
mboe/d
249
53
37
89
65
45
27
565
Mix
%
44
9
6
16
12
8
5
100
Production
mboe/d
278
57
34
92
64
56
28
609
Mix
%
45
9
6
15
11
9
5
100
Daily natural gas production, before royalties
(mmcf/d)
Daily crude oil and NGLs production, before royalties
(mbbl/d)
08
07
06
05
04
14
CANAD IA N NATU RAL
1,495
1,492
1,668
1,439
1,388
08
07
06
05
04
316
331
332
313
283
ca na dia n natu ral 2008 a nn u a l r epo rt
2008
2007
Gross
Net
Net %
Gross
Net
Net %
8,524
14,033
22,557
6,640
11,603
18,243
108
314
422
7
247
254
74
258
332
4
192
196
8,639
14,594
23,233
6,718
12,053
18,771
78
83
81
69
82
79
57
78
77
78
83
81
8,255
14,782
23,037
6,424
12,160
18,584
122
356
478
7
247
254
88
287
375
4
192
196
8,384
15,385
23,769
6,516
12,639
19,155
78
82
81
72
81
78
57
78
77
78
82
81
mary-Jo e. case
VICE-PRESIDENT,
LAND
core landholdings
(thousands of acres)
North America
Developed
Undeveloped
North Sea
Developed
Undeveloped
Offshore West Africa
Developed
Undeveloped
Total
Developed
Undeveloped
geo-science strategy
The integration of seismic interpretation, geology, and innovative engineering drives our successful annual drilling program and our
ongoing addition of new high quality locations to our conventional and unconventional inventory. We believe that a multi-
disciplined focus on geology, geophysics and reservoir engineering reduces exploration risk while enhancing capital efficiency,
ultimately leading to improved full cycle economics. In total, we invested $55 million during 2008 to acquire new seismic and to
purchase and reprocess existing seismic data. In total, 1,113 kilometers of conventional 2D seismic data and 200 square kilometers
of 3D seismic data were acquired. Additionally, 4,970 kilometers of conventional 2D seismic data and 1,027 square kilometers
of 3D seismic data were purchased. We continue to acquire this data under stringent environmental controls and in a cost
effective manner.
activity by core region
North America conventional
Northeast British Columbia
Northwest Alberta
Northern Plains
Southern Plains
Southeast Saskatchewan
Thermal in-situ oil sands
Horizon Oil Sands Project
North Sea
Offshore West Africa
Net Undeveloped Land
(thousands of net acres)
Drilling Activity
(net wells)
2008
2007
2008
2007
2,227
1,352
6,452
832
130
495
2,401
1,489
6,626
925
121
483
27
82
643
112
58
99
61
126
636
169
28
192
11,488
12,045
1,021
1,212
115
258
192
115
287
192
92
4
4
98
7
5
12,053
12,639
1,121
1,322
CA NA DIAN NATURAL
15
douglas a. proll
CHIEF FINANCIAL OFFICER &
SENIOR VICE-PRESIDENT,
FINANCE
randall s. davis
VICE-PRESIDENT,
FINANCE & ACCOUNTING
drilling activity and strategy
During 2008, Canadian Natural successfully drilled 682 net crude oil wells and 269 net natural gas wells. It was an uncertain and
volatile year for commodities with the price of crude oil steadily escalating, reaching record highs by mid year, followed by dramatic
weakening concurrent with the global economic downturn and uncertainty surrounding worldwide demand for crude oil. For the
year, natural gas prices remained weaker relative to crude oil prices. As such, capital continued to be allocated towards higher
return crude oil projects, in particular, heavy crude oil. The crude oil focus of Canadian Natural’s drilling activity for 2008 was a
reflection of historically narrow heavy crude oil differentials. For the bulk of the year, returns in heavy crude oil exceeded returns
elsewhere in the Company. Counter to the strong heavy crude oil differential, the weaker natural gas price throughout much of
the year led to declines in natural gas production and a decrease in overall natural gas wells drilled.
In 2008, we saw stabilization and in some cases a reduction of industry and service costs within the WCSB. Small decreases in cost
were seen in natural gas drilling in certain geographic areas. The stabilization was in response to industry-wide pressure placed on
the services through several scaled-back drilling programs, weaker commodity prices and uncertainty surrounding Alberta’s new
royalty framework. Looking specifically to natural gas, efficiencies were gained and our natural gas drilling program, although
scaled back, returned results that exceeded expectations – a result of better crews, better equipment and a deep, high quality
prospect inventory. Costs in crude oil related services stabilized but continue to be high.
Going forward, 2009 will be a year where Canadian Natural will benefit from its capital allocation flexibility. Natural gas drilling will
focus on the development of strategic projects and land expiries. The level of crude oil drilling will be reduced but closer to 2008
levels as strong returns are achievable, largely driven by strong heavy crude oil differentials. We will be prudent in our approach to
developing our assets. Flexibility is the key and we are able to ramp up or scale back our programs quickly and efficiently.
wells drilled
Year ended December 31
Crude oil – North America
Light crude oil
Pelican Lake crude oil
Primary heavy crude oil
Thermal heavy crude oil
North Sea light crude oil
Offshore West Africa light crude oil
Natural gas – North America
Northeast British Columbia
Northwest Alberta
Northern Plains
Southern Plains
Dry
Subtotal
Stratigraphic test / service wells
Total
2008
2007
Gross
Net
Success
Net
Success
115
110
422
74
3
4
728
28
79
145
159
411
44
1,183
133
1,316
98
110
396
74
2
2
682
24
66
100
79
269
39
990
131
1,121
93%
100%
95%
100%
76%
100%
96%
88%
95%
96%
100%
96%
96%
63
126
340
55
4
4
592
42
98
96
147
383
93
1,068
254
1,322
94%
99%
94%
100%
100%
100%
96%
74%
88%
72%
99%
85%
91%
Total North America landholdings
(thousands of net acres)
Total wells drilled
(net wells)
08
07
06
05
04
Developed
Undeveloped
16
CANAD IA N NATU RAL
08
07
06
05
04
1,121
1,322
1,738
1,882
1,449
north america natural gas
ca na dia n natu ral 2008 a nn u a l r epo rt
Canadian Natural is the second largest producer of natural gas in Western Canada with average
daily production of 1,472 mmcf/d for 2008. Natural gas remains our single largest product offering,
representing 44% of our total oil equivalent production. Our natural gas assets are strong, leveraged
by a vast land base, well developed infrastructure and a deep, diversified inventory of drilling
prospects. By utilizing our expertise, infrastructure and low cost operations, we have the competitive
advantage to achieve low-risk growth.
2008 proved to be another challenging year for natural gas with relatively flat pricing
while industry costs continued to rise. With higher returns found in crude oil, capital
was allocated away from natural gas towards the crude oil projects. This resulted in
a decline in production volumes of 10% from entry to exit for the year. In light of a
reduced natural gas drilling program, we were able to focus on only the most
economic natural gas wells and as such, executed a high-graded drilling program.
This allows us to control our costs while exceeding performance targets for the year.
Although the year was not easy for natural gas, we made steady, significant progress
in the development of our key growth projects, namely the Deep Basin and shale
plays. We have exposure to several major resource plays in the WCSB and are
delivering our future resource potential in a cost effective manner.
The approach to developing our natural gas assets will continue to be based on
efficient capital allocation in 2009. We will balance the need for capital between
low-risk conventional assets which provide a source of low-risk and reliable cash
flow, with the development of new natural gas resources. As netbacks increase in
natural gas, so too will our drilling activity. The priorities for the year are to advance
our resource projects, to grow our location inventory and to effectively execute on
our drilling program. Our program includes drilling strategic wells to offset expiries
on lands located in our growth areas.
Our natural gas production is concentrated in five North American core regions: Northwest Alberta, Northeast British Columbia,
the Foothills, the Northern Plains and the Southern Plains. These areas are anchored by our large strategic infrastructure ensuring
cost-effective development of all our key projects. This infrastructure is throughout our land base of over 11 million net acres of
undeveloped land.
northwest alberta
Canadian Natural has transformed the potential of the deep multi-zone plays of Northwest Alberta into a widespread, repeatable
production project. Again, we enjoy a large undeveloped land base of 1.4 million net acres in conjunction with 26 operated
facilities and an extensive pipeline network that provides significant competitive advantage. We have leveraged our existing land
and infrastructure to expand the initial Cardium play into our current multi-zone play. In Wild River, we have achieved sustainable
cost control by reducing the number of drilling days per well and now routinely commingle up to 12 geological zones, decreasing
the average cost of completion per zone by as much as 50% through limited entry fracs. Most notably, we have increased the
reserves per well while reducing the cost to drill new wells.
North America successful natural gas wells drilled
(net wells)
North America natural gas production, before royalties
(mmcf/d)
08
07
06
05
04
269
383
641
689
890
08
07
06
05
04
1,472
1,643
1,468
1,416
1,330
CA NA DIAN NATURAL
17
canadian natural 2 008 a n n u a l r e p ort
Jeff w. wilson
SENIOR VICE-PRESIDENT,
ExPLORATION
In the Deep Basin our Lower Doig/Montney resource project is similar in many ways to the Wild River area. Again, we are using our
land and infrastructure to reduce the cost of entry into this emerging resource play. Our initial position in the Montney was greatly
enhanced by the timely acquisition of Anadarko Canada in late 2006. We capitalized on our existing land position at that time, giving
us early exposure to the play. This allowed us to acquire strategic sections of prime Montney land at a fraction of today’s cost.
northeast british columbia
Canadian Natural
largest holder of
is the second
undeveloped land in British Columbia. Along with lowering
and controlling our costs, this land position combined with
our extensive infrastructure allows for low cost entry into
the overheated market for natural gas resources, most
notably in the Montney shales.
The progress we have made in the Deep Basin Lower Doig/
Montney play continues into our Northeast British Columbia
Montney project at Septimus, which is currently in the pilot
phase. We have gathered geo-data and production test
data and have wells planned for 2009 setting up our
commercial development phase, targeted for 2010. Going
forward, we will maximize our cost effective position by
integrating the data with the right technology, and acquire
new land and assets that fit our existing infrastructure.
The Helmet area of Northeast British Columbia has a play that contains significant thicknesses of natural gas pay in the Muskwa
shale. Based on existing data, our strategic land position and our Jean-Marie infrastructure, we have allocated long-term capital to
the experimental stage of this project. We will further evaluate the Muskwa potential by drilling more wells on our existing land
and production testing through existing facilities to determine if a viable development exists.
foothills
The Foothills area has a large inventory of development and exploration ready to drill prospects. We also have the land, infrastructure
and expertise to exploit the large undiscovered remaining resources. We will continue to build our drilling location inventory that
has resulted in 14% average annual growth since 2004.
northern / southern plains
In the Plains natural gas area, shallow gas and Horseshoe Canyon coal bed methane (“CBM”) provide large, downspaced drilling
programs that result in low-risk, long life reserves. In addition, ongoing focused exploitation continues to find excellent multizone,
conventional prospects for development drilling and secondary zone recompletions. Overall, natural gas production from CBM and
shallow gas has not been as severely impacted by Alberta’s new royalty structure and will provide opportunities for timely drilling
programs as prices improve.
Canadian Natural continues to access and develop new natural gas opportunities, focus on growing our location inventory and
optimizing all our natural gas production assets throughout 2009.
18
CANAD IA N NATU RAL
north america crude oil and NGLs
ca na dia n natu ral 2008 a nn u a l r epo rt
Canadian Natural is one of the largest conventional producers of crude oil and NGLs in western
Canada, with approximately 244,000 barrels per day production of crude oil and NGLs in 2008. Our
crude oil assets illustrate Canadian Natural’s balanced portfolio approach to business, producing
light, Pelican heavy, primary heavy and thermal heavy crude oil. Canadian Natural’s crude oil is
produced from very distinct assets, using different recovery technologies that are tailored to fit each
unique reservoir.
In 2008, we saw significant progress in the development of our North American crude oil assets. The completion of the Primrose
East expansion project was a highlight, adding an incremental 40,000 barrels per day of capacity to our thermal operations. We
also saw the continuation of the Pelican Lake enhanced crude oil recovery program. Primary heavy crude oil production, which
serves as the backbone for all our crude oil assets, continued to deliver low-risk, reliable production.
Going forward we will achieve production growth from crude oil through our defined growth strategy incorporating low-risk
development projects. We target secondary and tertiary recovery of light crude oil, primary, secondary and tertiary recovery of heavy
crude oil and thermal recovery of bitumen. Our crude oil development strategy is based on low-risk exploitation anchored by our
expertise in improved recovery techniques. This allows us to maximize crude oil recovery and value from both mature and new crude
oil pools.
light crude oil and ngls
We produce light crude oil and NGLs in all of our western Canadian core regions.
The majority of these pools are mature but recovery factors are still modest. The
majority of Canadian Natural’s light crude oil pools are produced under waterflood
which provide relatively high ultimate recovery factors with low production
decline rates. All of these projects are low risk but do require rigorous geological
and engineering analysis in order to be successful.
Although the basin is mature, new pool development remains part of our light
crude oil strategy. Our extensive undeveloped land base continues to deliver new
pool discoveries through detailed geophysical and geological analysis.
Our light crude oil pools have recovered approximately 30% of the original oil in
place (“OOIP”), leaving a significant resource target. The availability and
development of new technology leads to improving recovery factors, adding
significant leverage to Canadian Natural. We are currently testing various EOR
processes that include water flooding, CO2 flooding, polymer flooding and
alkaline surfactant polymer flooding. All of these technologies show promise.
In 2008, Canadian Natural’s light crude oil drilling and development programs
continued to pursue several initiatives within Western Canada. We efficiently
executed on low-risk, infill and step-out drilling in crude oil pools located in the
core regions of Northern and Southern Plains, Northwest Alberta, Northeast
British Columbia and Southeast Saskatchewan. Our strong technical teams
continued with waterflood optimization programs through detailed reservoir
characterization and analysis. EOR made progress with continued testing and
evaluation with the promise of commercial projects in the near future.
Canadian Natural drilled 105 wells in our light crude oil program during 2008.
For 2009, we are planning to drill 20 wells in our light crude oil program across
western Canada.
CA NA DIAN NATURAL
19
canadian natural 2 008 a n n u a l r e p ort
tim s. mcKay
SENIOR VICE-PRESIDENT,
OPERATIONS
pelican laKe crude oil
Pelican Lake is a premium asset within Canadian Natural’s portfolio, producing approximately 37,000 barrels per day in 2008. We
have had great success with EOR in this pool, first with waterfloods and now with polymer floods.
Pelican Lake is a large, shallow crude oil pool in our Northern Plains core region estimated to contain 4.5 billion barrels of OOIP on
Canadian Natural land. Although initially developed for primary production, we started converting portions of the field to water
flood in 2004, resulting in a significant production increase which reversed the previous three years of production decline. Building
on that success, we began testing polymer flooding in 2005. This EOR technique has proven to be much more effective than
waterflooding and as such, we are in the midst of converting more of the field to polymer flood.
Polymer is a chemical compound that we mix with water to create an injection that has a viscosity similar to olive oil. The application
of the polymer flood increases oil recovery since the thicker polymer solution reduces fingering or break-through in the reservoir.
Polymer flooding has the potential to increase ultimate recovery to 20% of the OOIP at a relatively low cost; approximately an
incremental $0.40 to $0.60 per barrel in operating cost plus an incremental $6 to $8 per barrel of reserves in capital cost.
During 2008, Canadian Natural drilled 110 wells as part of our Pelican Lake program.
Since converting from primary production to the polymer flood requires us to
re-pressurize the reservoir with the polymer solution, the full response from the
polymer flood is not expected until 2010. Production is expected to peak in 2011 and
plateau for several years at over 50,000 barrels per day.
As in any waterflood, optimizing water handling is key to the process – polymer flooding
is no different. We recycle more than 90% of our produced water, and we have initiated
brackish water usage to mix with the polymer. We have been operating in the area for
more than 10 years and our staff has done a tremendous job adapting to new technology
while minimizing our operating and capital costs.
For 2009, we continue to work on enhancements to the process to optimize our field
operations. We are testing the polymer flood in regions with poor crude oil quality
and continue to optimize the quantity and type of polymer we use. Improvements to
our facilities design have been made and we are now building larger mixing units and
are enhancing our polymer distribution system.
primary heavy crude oil
Canadian Natural’s primary heavy crude oil operations are centered on the Alberta – Saskatchewan border, near the city of
Lloydminster. In 2008 we produced approximately 90,000 barrels per day of heavy crude oil from our extensive and dominant land
base. This dominance allows us to conduct large scale drilling and development programs while minimizing our capital cost
requirements. Costs are further managed through owning and operating centralized treating and sand handling facilities,
maximizing their utilization and using our size to achieve economies of scale. Our infrastructure includes five crude oil processing
facilities and four salt caverns for solids disposal. Ownership of the ECHO sales pipeline allows us to be the only producer capable
of delivering undiluted heavy crude oil into our blending facilities at Hardisty, Alberta. Our infrastructure and size gives us a
significant competitive advantage in this area and our large inventory of drilling prospects leads to greater flexibility enabling us to
react very quickly to changes in commodity prices or changes in capital allocation.
Primary production typically produces between 5% and 15% of the OOIP, leaving a vast unrecovered resource that we feel will
ultimately be exploited. Improving recovery by drilling infill wells in some pools, testing waterfloods in others, and using horizontal
North America successful crude oil wells drilled
(net wells)
North America crude oil and NGLs production,
before royalties (mbbl/d)
08
07
06
05
04
20
CANAD IA N NATU RAL
678
584
591
612
08
07
06
05
04
317
244
247
235
222
206
ca na dia n natu ral 2008 a nn u a l r epo rt
wells in specific applications, are a few of the ways we are working towards improving recovery factors. We are also evaluating
several other technologies, such as polymer flooding and solvent injection.
During 2008 we drilled 415 low-risk heavy crude oil wells and recompleted approximately 490 wells to secondary zones. For 2009,
317 heavy crude oil locations are forecast to be drilled and a further 380 wells are targeted to be recompleted.
thermal (in-situ) heavy crude oil
Canadian Natural believes it holds some of the best oil sands assets in Canada,
providing tremendous value and growth potential. Our thermal assets are located
in two of the major oil sands deposits in Western Canada – the Athabasca and the
Cold Lake deposits. Within the Athabasca deposits, the McMurray reservoir is our
primary target and steam assisted gravity drainage (“SAGD”) is the recovery
process of choice. SAGD uses two well bores, one for continuous steaming and
the other for continuous production. Within the Athabasca region, the majority
of our assets are in the planning stages. These include Kirby, Grouse, Birch
Mountain, Ipiatik, Gregoire and Leismer. In the Cold Lake deposits, we have our
Primrose and Primrose East operations where we currently produce from the
Clearwater reservoir using the cyclic steam stimulation (“CSS”) process. CSS uses
a single well bore to inject and produce steam. This technology has been historically
applied to reservoirs that have barriers to vertical flow. The production peaks and
troughs at Primrose are a reflection of the cyclic steam process – the peaks are
associated with production cycles from newer, less mature wells and the troughs
are associated with production cycles from the more mature areas in the field. In
2008, production from our thermal operations averaged 65,000 bbl/d.
Canadian Natural’s multi-year thermal development program continued in 2008
with the completion of construction and commencement of production at the
Primrose East expansion. This 40,000 bbl/d project achieved first production in
Q4/08, on budget and ahead of schedule. The major components to the project
included expansion of our central treating facility at Wolf Lake, taking capacity to
120,000 bbl/d, and also a new satellite steam generation facility at the Primrose
East site. We also drilled 80 horizontal wells from four pads for the first stage.
The development, design and construction of Primrose East has proven to be a
success.
Throughout 2008 and into 2009, we will drill additional well pads at Primrose
North which will result in production increases. We will also continue development
of the existing operations at Primrose South and North with the drilling of
70 wells.
The next thermal project that Canadian Natural has under development is Kirby.
It is the first project that we are undertaking in the Athabasca – McMurray
reservoir and will be using SAGD technology. Regulatory applications were filed
in 2007.
Beyond 2009 we see the potential to add significant incremental thermal in-situ
production from our oil sands leases. By executing our defined plan to develop
these leases and assuming adequate returns are achievable, we target to achieve
15% growth on our thermal production alone. Our thermal operations represent
a tremendous value growth opportunity and are an integral part of Canadian
Natural’s defined plan.
CA NA DIAN NATURAL
21
canadian natural 2 008 a n n u a l r e p ort
international
International operations remain a strategic part of our business, providing a stable and committed
source of light crude oil production. We concentrate our efforts in two core areas, the UK portion of
the North Sea and in Offshore West Africa. We are able to apply our expertise in mature, low-risk,
exploitation basins to our North Sea operations, leveraging our experience to add value through our
Offshore West Africa assets. As part of our fundamental strategy, we maintain high working interest
in all of our International assets.
In the North Sea, attention is focused on managing existing infrastructure
in a mature basin which leads to field life extension. With a solid inventory
of drilling prospects, the North Sea provides additional recovery potential
in a low-risk environment. In Offshore West Africa, the Company has
some of its highest returning projects. Offshore West Africa assets
continue to generate significant free cash flow as they provide
considerable light crude oil growth.
united Kingdom section of the north sea
In the UK portion of the North Sea, our focus is on managing our
infrastructure, platform maintenance and mature basin exploitation.
This approach ultimately prolongs the life and economic value of our
assets. The North Sea is a low-risk source of high-value, light crude oil.
We maintain a large inventory of drilling locations to maximize our
development projects and infill drilling. We operate 90% of our fields in
the North Sea with an average working interest of over 80%, giving us
control of our assets.
During 2008, we saw high production uptimes with top quartile
performance for our assets. We delivered key production enhancements
and field life extension projects while drilling four net wells, three work-
overs, and increasing water injection at our Columba E North Sea
development. The majority of our production is achieved by optimizing
water injection and processing as many barrels of crude oil as possible.
We also executed five planned turnarounds as part of our advanced
asset integrity management program aimed to enhance the long-term
viability of our infrastructure.
For 2009, we are consistent with our defined strategies. Very few wells will be drilled during the year as projects have been
deferred, though we maintain a very strong inventory of drilling prospects for resumption of activity when appropriate. Capital cost
and operating cost reduction are paramount for 2009. Focus will remain on cost reduction projects and upgrades to facilities to
add long-term value, with three major turnarounds planned. As a result of deferred drilling and turnarounds, production will be
down slightly for the year.
Long term, our objective for the North Sea is to stabilize production and plan for modest growth with long-term developments of
Lyell, Columba and Thelma. Mature field declines will be offset with development projects and infill drilling. We also expect there
may be significant acquisition opportunities within the basin where we could capitalize on our mature basin expertise.
22
CANAD IA N NATU RAL
ca na dia n natu ral 2008 a nn u a l r epo rt
terry J. Jocksch
VICE-PRESIDENT, INTERNATIONAL
& MANAGING DIRECTOR
CNR INTERNATIONAL
offshore west africa
We maintain a high working interest for all of our Offshore West Africa
assets and have 100% operatorship of our assets. This is an area that
once again delivers high-value, light crude oil, providing development
opportunities with significant exploration upside. We capitalize on
strong government relationships and leverage the technical/operational
expertise from the North Sea.
At Baobab in Offshore Côte d’Ivoire, the second phase of our program
is on track. We are increasing production following well failures that
occurred in 2006, with three wells already re-drilled and a fourth well
underway. Baobab remains a challenging field and we are proceeding
cautiously. We have implemented a robust gravel pack technology in
the replacement wells and through a measured approach, we anticipate
a larger third phase program in the near future. At Espoir, also in
Offshore Côte d’Ivoire, we have been upgrading our FPSO, leading to
greater production from the field. This upgrade is targeted to be
complete in 2009.
At Olowi in Offshore Gabon, development drilling has begun and first
crude oil is targeted for early 2009. Additional wells will be drilled
throughout the year with a production plateau of 20,000 bbl/d targeted
to be reached and maintained in 2010.
Long-term plans for Offshore West Africa include a cautious and cost
conscious approach towards the development of Baobab. At Espoir, we
will continue with infill programs, optimizing our facilities. At Olowi,
we will sustain production with continued platform drilling.
International successful crude oil wells drilled
(net wells)
International total production
(mboe/d)
08
07
06
05
04
4
8
12
11
15
08
07
06
05
04
76
89
86
101
95
CA NA DIAN NATURAL
23
canadian natural 2 008 a n n u a l r e p ort
horizon oil sands project
After roughly four years of planning, followed by four years of construction, the Horizon Project
successfully and sustainably produced its first barrels of high quality, low-sulphur, 34° API, sweet
synthetic crude oil in 2009. First production of SCO was a major milestone for Canadian Natural and
we are very pleased with the success of the project. Acting as our own primary contractor on the
Horizon Project, we have built a core competency in executing large scale projects from the ground
up and have learned a great deal from the construction and start up of Phase 1.
The Horizon Project includes a surface oil sands mining and bitumen extraction plant, complimented by on-site bitumen upgrading
with associated infrastructure to produce high quality SCO. Canadian Natural holds extensive leases that are estimated to contain
approximately 16 billion barrels of oil in place and six to eight billion barrels of mineable reserves and contingent resources. The
Horizon Project is located on these leases just north of Fort McMurray, Alberta in the Athabasca region. Due to the massive
resource base, the mine and plant facilities are expected to produce for decades without production declines normally associated
with conventional crude oil production.
The total construction costs for Phase 1 were approximately $9.7 billion, or $88,182 per flowing barrel of capacity. The final cost
was 43% above our original estimate of $6.8 billion first set in 2004. However, the total cost of the Horizon Project comes in well
below the industry average for current and future projects with similar facilities. First synthetic crude oil was achieved approximately
five months beyond the initial target we set upon project sanctioning in 2005. Although both the cost and schedule were over
initial targets, the project was built in an extremely volatile and inflationary business environment and in that respect, we consider
it a success.
Operations have gone well since we started producing at the Horizon Project, with no major causes for concern. In a start up year
without the benefit of targeted full production capacity, the operating cost for 2009 is forecast to be $35 to $40 per barrel of SCO.
At full production, we target the operating cost for the life of the mine, at 250,000 bbl/d to be between $25 and $35 per barrel
of SCO, a low-cost producer within the oil sands industry.
Full production capacity for Phase 1 is targeted to deliver 110,000 bbl/d of fully upgraded, light, sweet, SCO. We are targeting to reach
full production capacity by late 2009. The early stages of production were approximately 55,000 bbl/d. Full ramp up to 110,000 bbl/d
is targeted to be reached in 2009 as we continue to fine tune the plant to design rates with a focus on safety and reliability.
Looking to the future of the Horizon Project, Phase 1 is just the first step in value creation from this significant asset. A considerable
amount of capital for infrastructure was included in Phase 1 in anticipation of future phases. These include but are not limited to,
support infrastructure such as the aerodrome, buildings, shops, warehouses, camps and roads, site preparation, the piperack,
coker foundations, gas and power distributions, the majority of underground piping and so on. There is also the added benefit that
a large portion of this work was completed early on in the construction process, a much less inflationary business environment.
Canadian Natural is in the position to leverage the benefits from our existing operation into future expansions.
24
CANAD IA N NATU RAL
ca na dia n natu ral 2008 a nn u a l r epo rt
réal J. h. doucet
SENIOR VICE-PRESIDENT,
OIL SANDS
The expansions to the Horizon Project have been broken into four tranches. Going forward, Canadian Natural wants to avoid the
“mega-project” approach to development and feel that breaking the overall expansion into smaller, more manageable pieces will
lead to enhanced project and cost control. Tranche 1 of the expansion was completed during 2007. This tranche included
engineering and design specifications for greater production capacity, the setting of additional coker foundations, other supporting
infrastructure, and the procurement of long lead equipment such as coke drums, reactors and mobile equipment. Future tranches
of the expansion are currently being re-profiled, taking project control to the next level. We will see incremental production gains
throughout the completion of future tranches, with targeted full facility capacity between 232,000 and 250,000 bbl/d. Further
phases of expansion (Phases 4 and 5) will bring the ultimate capacity to 500,000 bbl/d.
targeted activities within future expansions (phase 2/3)
Tranche 1 (completed)
planned basis for future expansions by:
n Creating engineering design specification (232,000 bbl/d to 250,000 bbl/d SCO);
n Completing front end engineering and design;
n
n Ordering and transporting to site long lead equipment (coke drums, reactors, mobile equipment).
Building coker foundations and some supporting infrastructure; and
Tranche 2
facilitates potential production gains by 5% to 15% by:
n
n
n
n
Increasing uptime and reliability (Ore Preparation Plant (“OPP”) – train 3 and Hydrotransport);
Ensuring environmental commitments are met (Gas Recovery Unit, Sulphur Plant – train 3);
Increasing reliability (“Flood the Upgrader” and mine equipment); and
Planning the debottlenecking process.
Tranche 3
increases production by 10,000 to 20,000 bbl/d sco by:
n
Reducing energy and operating costs (new tailings technology);
n
Expanding mining capability (mining equipment and shops);
n
Increasing plant capacity (coker expansion); and
n Adding environmental efficiencies (CO2 recovery).
Tranche 4
expands to full capacity of 232,000 to 250,000 bbl/d sco through:
n OPP (trains 4 and 5);
n
n
n Vacuum Recovery Unit and Diluent Recovery Unit;
n Hydrotreating (2 units);
n Hydrogen Plant;
n
n Cogeneration and Heat Integration; and
n
Extraction (retrofit trains 1 and 2);
Froth Treatment Plant (train 2);
Sulphur Plant (train 4);
Tankage.
The timing of construction for future expansions is critical for cost
control and we position the Company to take advantage of the
recent downturn in market activity. However, we are not driven to
increase production at the expense of economic returns. The
barrels are in the ground and will still be there when we are ready
to proceed with our expansions; when the economics are right.
Future phases will go ahead, it is just a matter of when and how.
The Horizon Project asset is substantial and anticipated to provide
significant free cash flow well into the future. The development of
this world-class asset is predicated upon generating the greatest
value for our shareholders.
CA NA DIAN NATURAL
25
canadian natural 2 008 a n n u a l r e p ort
marketing
The 2008 business environment was defined by commodity price volatility throughout the course of
the year. 2008 will be recognized for the financial uncertainty caused by high prices midway through
the year followed by the financial crisis and the beginning of a significant recession. In spite of this
changing business environment, Canadian Natural’s business approach remains focused and
disciplined and this applies without exception to our marketing strategies and activities.
natural gas
Canadian Natural’s long-term natural gas marketing objective is to maximize the realized
price for our overall portfolio. Canadian Natural’s realized wellhead price in 2008 was
$8.39/mcf, 22% higher than in 2007. The AECO and NYMEx index both rose respectively
by 23% and 29%. The average Canadian dollar strengthened slightly relative to the US
dollar by 1% in 2008. Mild weather throughout 2008 and lower industrial demand late in
the year caused natural gas prices to decline and resulted in full storage capacity by the
third week of November. In the US, prolific increase from shale gas production and a 6%
increase in wells completed, increased supply by 8.6% to 57.6 bcf/d. Domestically, overall
Canadian natural gas production dropped by approximately 3% to 16.2 bcf/d over the
year as completions were down 2% from the previous year.
The annual volume of Liquid Natural Gas (“LNG”) imported into the US was lower than the
previous year at 0.94 bcf/d as price differentials were biased in favor of the European and
Asian markets. The current forward strips for worldwide natural gas markets suggest a
continued low volume of LNG imports for 2009. The commissioning of several new
liquefaction facilities announced for the next two years may change the pricing dynamics in
favor of those markets with the capacity to receive and store these incremental volumes.
crude oil
Crude oil prices were extremely volatile in 2008 with the NYMEx West Texas Intermediate (“WTI”) averaging US$99.65/bbl,
exceeding the previous year by 38%. The pricing reached its peak on July 11 at US$147.27/bbl prior to beginning its downward
spiral. This decline was caused by the loss of demand due to the worldwide financial crisis and bottomed at a low of US$32.40/bbl
on December 19. The international benchmark Dated Brent was 34% higher than in 2007 at US$96.99/bbl.
Canadian Natural’s realized wellhead price in 2008 was $82.41/bbl, 49% higher than 2007. The price differential for Canadian
heavy crude oil, as measured by the Western Canadian Select crude oil blend (“WCS”) price at Hardisty, Alberta improved by 12%
over 2007 to a narrow differential of 20% of the NYMEx WTI for the yearly average in 2008. WCS heavy crude oil differentials
narrowed to an attractive 13% of WTI in July and August in response to strong worldwide demand for diesel fuels and low gasoline
cracking spreads. The continued declines in the volumes from Mexico and Venezuela also contributed to stronger demand for
Canadian heavy crude oil barrels and resulted in excellent realized prices for this important component of our portfolio.
Our goal is to maximize the value of our crude oil portfolio in whatever market condition we are faced with. Canadian Natural’s
strategy consists of three main components: the blending of various crude oil streams and diluents to better serve the needs of our
refining customers, the supportive participation in the expansion of pipeline export capacity and finally, the support and potential
participation in projects adding incremental conversion capacity for bitumen and SCO.
WTI crude oil reference pricing
(US$/bbl)
NYMEX natural gas reference pricing
(US$/mmbtu)
08
07
06
05
04
72.40
66.25
56.61
41.43
99.65
08
07
06
05
04
6.92
7.26
8.95
8.56
6.09
26
CANAD IA N NATU RAL
ca na dia n natu ral 2008 a nn u a l r epo rt
réal m. cusson
SENIOR VICE-PRESIDENT,
MARKETING
The WCS crude oil stream is a blend of several conventional crude oils, bitumen and
diluents from either conventional or synthetic sources. WCS is used as the benchmark for
Canadian heavy crude oil marketed out of the WCSB. Canadian Natural contributes, on
average, approximately 150,000 bbl/d to the WCS blend, which is 55% of the total stream.
The blending of WCS allows the Company to reduce its blending, logistics and storage
thereby increasing the heavy crude oil netback for a significant portion of our heavy crude
oil production.
The second component of our crude oil marketing strategy includes the expansion of
pipeline systems to open up new markets for heavy crude oil and SCO. Canadian Natural
has supported industry export initiatives such as the Spearhead Pipeline to Cushing,
Oklahoma, Southern Access to the upper PADD II market and Kinder Morgan’s west
coast expansion.
Canadian Natural is also a key supporter of the Keystone crude oil pipeline system that will
provide access to the US Gulf Coast (“USGC”) markets by 2012. The first phase of this
project is currently under construction and is targeted to be in service in the first quarter
of 2010 and reach Cushing, Oklahoma one year later. The second phase, Keystone xL, will
provide an average of 910,000 bbl/d but requires regulatory approvals. The target
completion period is the first quarter of 2012 with potential additions of laterals to USGC
terminals by 2013. Canadian Natural has committed 120,000 bbl/d for an initial term of
20 years for firm service on Keystone xL to the USGC.
The third component of our long-term marketing strategy is supported by our commitment
to supply 100,000 bbl/d for an initial term of 20 years to a large USGC refiner. This anchors
an expansion project adding more coking capacity to this refiner’s already complex
configuration. The uncommitted Canadian Natural volumes available in the USGC are
targeted for the general refining spot and term markets of 45,000 bbl/d. All of our sales
in the USGC area will receive the prevailing market price.
These agreements represent a step forward in the implementation of our defined marketing
plan to improve the margins we realize on our heavy crude oil production and to reduce
the volatility historically experienced in the heavy crude oil markets. This strategic
marketing component is part of the Company’s long-term plan to develop its heavy oil
production capacity.
$10
$8
$6
$4
$2
$0
$(2)
$(4)
08
07
06
05
04
2008 Mayan - WCS realized price spread
(US$/bbl)
2008 WTI crude oil reference pricing
(US$/bbl)
$140
$120
$100
$80
$60
$40
$20
$0
Jan.
Feb. Mar.
Apr. May
Jun.
Jul.
Aug.
Sep.
Oct.
Nov.
Dec.
Jan.
Feb. Mar.
Apr. May
Jun.
Jul.
Aug.
Sep.
Oct.
Nov.
Dec.
WCS price differential to WTI
(%)
20
Canada/US average exchange rate
(US$ in equivalent C$)
32
33
32
37
08
07
06
05
04
1.07
1.07
1.13
1.21
1.30
CA NA DIAN NATURAL
27
canadian natural 2 008 a n n u a l r e p ort
price risK management
Canadian Natural utilizes hedging techniques to provide some assurance on price
realizations and to protect cash flow generation capability in order to fund ongoing
development programs. Generally, the downside pricing risks associated with various
commodities are determined and, if deemed appropriate, financial derivatives are
used to limit risk. Currency exposures are also monitored and may be hedged along
with the commodities. Starting in January 2009, our hedge policy will allow for the
hedging of up to 60% of the near 12 months budgeted production and up to 40%
of the following 13 to 24 months estimated production. For further information on
the particulars of this hedge program please refer to the Management’s Discussion
and Analysis and the Consolidated Financial Statements.
midstream
Our midstream assets consist of the 100% owned and operated ECHO Pipeline, a
15% interest in the Cold Lake Pipeline system, a 62% interest in the Company-
operated Pelican Lake Pipeline, and a 50% interest in the 84 megawatt co-generation
unit located at the Primrose facility. The midstream assets allow us to control and
optimize transportation costs for about 85% of our heavy crude oil production. It also
generates additional revenue from third party volumes, along with the sale of surplus
electricity. ECHO Pipeline operated at 92% utilization in 2008 and is the only pipeline
delivering undiluted raw bitumen to Hardisty terminals. Crude volumes delivered from
ECHO pipeline play an important role in our heavy crude oil blending and marketing
strategy for WCS and other diluted bitumen blends.
In 2008, the Company committed firm capacity of 42,000 bbl/d for an initial term of
10 years to anchor a new pipeline from our Nipisi terminal to Edmonton. This project,
to be built by the Pembina Pipeline Income Fund (“Pembina”), still needs to obtain full
regulatory approvals and is targeted for completion in July 2011. This new pipeline
project includes a diluent supply pipeline to Nipisi for the blending of our increasing
production volumes from our Pelican Lake area.
The new pipeline, owned and operated by Pembina, built to ship SCO from our Horizon
Project to refineries in Edmonton has been fully operational since November 1, 2008.
We are currently reviewing a detailed forecast for Cold Lake production from the
Primrose area to determine the timing and size of incremental pipeline capacity
required to support our expansion plans for 2010 and beyond.
Company average crude oil and NGLs selling price
(C$/bbl)
Company average natural gas selling price
(C$/mcf)
08
07
06
05
04
28
CANAD IA N NATU RAL
55.45
53.65
46.86
37.99
82.41
08
07
06
05
04
8.39
8.57
6.85
6.72
6.50
ca na dia n natu ral 2008 a nn u a l r epo rt
health and safety,
environment and community
For Canadian Natural, “doing it right with fun and integrity” is a commitment we make towards
responsible operations and environmental stewardship. Our management systems encourage
continuous corporate improvement in the areas of health and safety, infrastructure integrity,
environmental management and community support for our employees, contractors
and stakeholders. We recognize that improvement in these areas is fundamental to our
long-term growth.
health and safety
Canadian Natural conducts operations in a way that protects the health and
safety of employees, contractors, the public and the environment. We continue
to enhance safety awareness by maintaining a focus on safety programs and
processes. In 2008 our health and safety performance benchmarks surpassed
internal targets and continue to improve. Over the past six years, the total
recordable injury frequency has decreased across all our operations.
Canadian Natural has a very aggressive audit program with over 500 audit
inspections conducted in 2008. All internal audits are performed using a Company-
developed safety and compliance audit protocol. Our ongoing initiatives ensure
that Canadian Natural maintains an Energy Resources Conservation Board
satisfactory inspection rate that is significantly better than the industry average.
In 2008, the Horizon Project underwent the last stage of construction and
transitioned into commissioning and start-up of operations. Despite the busy
year, the Horizon Project achieved 24 million hours Lost Time Injury Free. The Horizon Project Health and Safety Group worked
closely with all the groups involved and implemented safety prequalification programs for all contractors to ensure smooth
transitions and safe commissioning and start-up.
We are also working hard to continue to improve worksite safety behaviours by delivering targeted safety leadership training. In
2008 we implemented an “Operations Readiness” Program which included Oil Sands Safety Association (“OSSA”) approved Safe
Work Permit training. We also successfully embedded new electronic Integrated Safe System of Work (“ISSoW”) on all our North
Sea installations.
infrastructure integrity
Canadian Natural is committed to managing the integrity of its pipelines and facilities. We’ve established Asset Integrity Programs
at our operations which develop and implement the pressure equipment guidelines to meet corporate standards and regulatory
requirements. The Integrity Group tracks and coordinates inspections for over 36,000 pieces of pressure equipment. All critical
findings from proactive inspections are resolved via repair or replacement. The Integrity Group also tracks the resolution of findings
from proactive inspections that are not an immediate risk but may pose a problem down the road.
We work diligently to maintain the structural integrity of all our operations, especially our more mature installations and pipelines.
We take a proactive approach to Risk Based Inspection (“RBI”). RBI is used to ensure that inspections are carried out at an appropriate
frequency. It also helps us ensure that inspections address potential failure modes for the system. This approach allows us to optimize
inspection intervals and in many cases we’re able to extend intervals based upon this analysis. In every project, we strive to ensure
that all assets operate safely and effectively for the life of field of all the assets within Canadian Natural’s portfolio.
CO2e reductions from gas conservation
Primrose and Wolf Lake thermal operations (megatonnes)
08
07
06
05
04
0.46
0.41
0.41
0.32
0.21
In the past five years, our
investment in solution gas
conservation has
prevented 8.2 million
tonnes of CO2e emissions.
CA NA DIAN NATURAL
29
canadian natural 2 008 a n n u a l r e p ort
lyle g. stevens
SENIOR VICE-PRESIDENT,
ExPLOITATION
environment
Environmental stewardship is an essential element of all Canadian Natural’s operations.
Management and operating personnel are committed to ensuring that planning,
training and due diligence are key elements in our environmental management
programs. Environmental strategies target corporate standards, operations compliance,
liability reduction, air emission management, reduction of fresh water use and
minimizing our landscape footprint.
Canadian Natural’s Environmental Management System (“EMS”) focuses on ensuring
our field operations meet all corporate standards and regulatory requirements and
minimizes their environmental impact. In 2008, we continued the development,
enhancement and implementation of the EMS in our conventional operations and the
Horizon Project. In our North Sea operations, two more installations achieved ISO
14001 certification; all Canadian Natural’s North Sea operations are now certified. In
2008, emergency preparedness and response plans were reviewed and enhanced in
our West Africa operations.
Canadian Natural Environment staff continued implementing our rigorous audit
program, which includes a formal review of environmental compliance and risk
management activities for a site. In addition, many third-party audits were conducted at
Canadian Natural facilities and key well sites throughout the year. Action items resulting
from these audits are tracked to ensure appropriate corrective and preventive actions
are taken in a timely manner.
For North American conventional operations, our liability reduction programs focus on abandonment, reclamation and
decommissioning activities. In 2008, we abandoned 116 wells and 373 pipelines, and received 329 reclamation certificates.
At our Horizon Project, reclamation work has already begun, prior to full operation of the facility. In 2008, we reclaimed 80
hectares of land.
Our industry faces regulatory and stakeholder concerns associated with air emissions from operations, specifically greenhouse
gases (“GHGs”) and air pollutants. Canadian Natural is committed to developing innovative and effective solutions to manage
GHG emissions and air quality issues. Implementation of flaring and venting reductions and fuel and solution gas conservation
programs continue.
30
CANAD IA N NATU RAL
ca na dia n natu ral 2008 a nn u a l r epo rt
Year-over-year flaring volumes decreased by 17% due to improved operational practice and due to lower natural gas production
volumes. In 2008, Canadian Natural spent $6.3 million and completed 101 solution gas conservation projects which reduced over
0.84 million tonnes of CO2e. The focus of the majority of these projects was to increase the efficiency of our operations and
conserve natural gas.
In Alberta, Canadian Natural’s solution gas conservation rate was 85%. This has improved significantly from a rate of 63% in 2000.
The Horizon Project will incorporate numerous advancements in technology to reduce GHG emissions including continued research,
development and implementation of a process to sequester CO2 into tailings. At the completion of Phases 2/3 of the Horizon
Project, we believe this process will sequester approximately 219,000 tonnes of CO2 annually. Our “Taking Action on Greenhouse
Gas Emissions” document outlines our strategy to address GHG emissions from our operations in the short and long term and is
available on our web site.
Carbon Capture and Storage (“CCS”) has emerged as the centerpiece of Alberta’s GHG reduction efforts in the medium to long
term. Canadian Natural is currently operating a CO2 Enhanced Oil Recovery (“EOR”) project in Southern Alberta. We will be
working with the Alberta government in 2009 on opportunities and incentives to further develop CCS within our operations.
In our international operations, we continue to pursue emission reduction opportunities including improvements to flare systems
and natural gas turbines.
Throughout our operations, we consistently strive to reduce our fresh water use. Our ongoing work to meet this goal includes
recycling a high percentage of produced water, increasing the use of brackish/saline water and using produced water in our drilling
and abandonment operations. Increased brackish/saline water use at our Primrose and Wolf Lake operations continues to enable
increased bitumen production without an equivalent increase in fresh water use. In 2008, the relative proportion of fresh water to
brackish water use continued to decrease at the Primrose and Wolf Lake operations. Two additional brackish wells were installed
in 2008 increasing brackish production and treatment capacity. This increased supply is helping to meet the needs of the Primrose
East Expansion Project.
In 2008, construction of the Wapan Sakahikan lake was completed at the Horizon Project site and was filled with water. This lake
provides new fish habitat as compensation for habitat lost due to project development. Water quality monitoring at the lake is
ongoing to determine the timing for stocking the lake with fish and will continue to ensure appropriate water quality to sustain
fish populations.
Water management at the Horizon Project continues to be a priority for Canadian Natural. Our water withdrawal from the
Athabasca River began in 2007, and we continue to withdraw amounts far below our approval limits. In 2008, we continued to
work with other oil sands operators in the Athabasca Region to ensure that water use is coordinated and does not exceed
regulatory limits.
CA NA DIAN NATURAL
31
canadian natural 2 008 a n n u a l r e p ort
communities and staKeholders
Canadian Natural is committed to operating in a socially responsible way
and maintaining a long-term presence in the communities where we
operate. Our business activities contribute to the quality of life and economic
health in communities where we do business. In 2008, Canadian Natural
continued its wide range of community investment programs.
Our community investment projects benefit people living in communities
across Western Canada, the UK and West Africa by providing financial and
volunteer support for the projects that meet their vision for the future.
Overall, Canadian Natural’s community sponsorship and funding support in
2008 totaled more than $4 million.
We strongly believe that education and training are fundamental to
developing people. Throughout our operations, Canadian Natural supports
a number of initiatives in building labour capacity in communities to meet
the long-term human resource needs in the crude oil and natural gas
industry. In 2008 we supported programs such as the Petroleum Employment
Training Program, the Northeast British Columbia’s Stay-in-School Program
and Inside Education.
Through the Canadian Natural Building Futures scholarship program we are
proud to support students who are pursuing education and training related to
crude oil and natural gas. In 2008 we awarded approximately $100,000 in
scholarships to 76 students living in all regions of Alberta, British Columbia and
Saskatchewan, including many Aboriginal students living near our operations.
In 2008, we continued to develop and sustain strong working relationships with our stakeholders. We aim to understand their
interests so we can consider and incorporate their input in our operations. Where possible, we strive to integrate economic,
environmental and social considerations in the decision-making process across all of our business activities.
Canadian Natural works closely with the more than 55 Aboriginal communities near our operations in Western Canada to
strengthen mutual understanding and co-operation and enhance the opportunities for economic participation in our crude oil and
natural gas developments.
32
CANAD IA N NATU RAL
2008 review
ca na dia n natu ral 2008 a nn u a l r epo rt
34
year-end reserves
40 management’s discussion and analysis
71 management’s report
72
72
74
78
101
106
108
management’s assessment of internal control over financial reporting
independent auditors’ report
consolidated financial statements
notes to the consolidated financial statements
supplementary oil & gas information
ten-year review
corporate information
CA NA DIAN NATURAL
33
canadian natural 2 008 a n n u a l r e p ort
year-end reserves
independent evaluation
Determination of reserves
For the year ended December 31, 2008, Canadian Natural retained a qualified independent reserves evaluator, Sproule Associates
Limited (“Sproule”), to evaluate 100% of the Company’s conventional proved, and proved and probable crude oil and natural gas
reserves and prepare Evaluation Reports on the Company’s total reserves. Canadian Natural has been granted an exemption from
certain of the provisions of National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), which
prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. This
exemption allows the Company to substitute United States Securities and Exchange Commission (“SEC”) requirements for certain
disclosures required under NI 51-101. There are three principal differences between the two standards. The first is the requirement
under NI 51-101 to disclose both proved and proved and probable reserves, as well as the related net present value of future net
revenues using forecast prices and costs. The second is in the definition of proved reserves; however, as discussed in the Canadian
Oil and Gas Evaluation Handbook (“COGEH”), the standards that NI 51-101 employs, the difference in estimated proved reserves
based on constant pricing and costs between the two standards is not material. The third is the requirement to disclose a gross
reserve reconciliation (before the consideration of royalties). Canadian Natural discloses its reserve reconciliation net of royalties in
adherence to SEC requirements.
The Company has disclosed proved reserves using constant prices and costs as mandated by the SEC and has also provided proved
and probable reserves under the same parameters as voluntary additional information.
The SEC requires that oil sands mining reserves be disclosed separately from conventional oil and gas disclosure. Canadian Natural
retained a qualified independent reserves evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), to evaluate Phase 1 to Phase 3 of the
Company’s Horizon Project under SEC Industry Guide 7 requirements.
The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures
with Sproule and GLJ as to the Company’s reserves.
Conventional crude oil, NGLs and natural gas include all of the Company’s light and medium, heavy, and thermal crude oil, natural
gas, coal bed methane and natural gas liquid activities. They do not include the Company’s oil sands mining assets.
Corporate Conventional net reserves
Crude oil, natural gas and NGLs proved reserves decreased by 0.5% replacing 95% of production. This was accomplished at all-in
finding and on-stream cost of $20.68 per barrel of oil equivalent for proved reserves and $14.66 per barrel of oil equivalent for
proved and probable reserves.
In the Evaluation Reports, 53% of crude oil and NGLs proved reserves were assigned to the proved undeveloped category, compared
to 46% in 2007.
In the Evaluation Reports, 23% of natural gas proved reserves were assigned to the proved undeveloped category reflecting the
generally shorter lead times required for natural gas developments in Canada.
In the Evaluation Reports, total proved and probable reserves increased by 2%.
north ameriCa Conventional net reserves
Crude oil and NGLs proved reserves increased by 3% replacing 137% of production. Natural gas proved reserves increased by
0.1% replacing 100% of 2008 production.
international Conventional net reserves
North Sea proved reserves decreased by 56 million barrels to 267 million barrels of oil equivalent, which represents 14% of the total
proved Company reserves. The decrease was primarily due to changes in year over year pricing.
In Offshore West Africa proved reserves increased to 158 million barrels in 2008 from 139 million barrels in 2007.
horizon oil sanDs mining net reserves
The net proved synthetic crude oil reserves increased to 1.95 billion barrels. The net proved and probable synthetic crude oil
reserves were 2.94 billion barrels.
34
CANAD IA N NATU RAL
reSerVeS oF conVentional crude oil and natural GaS, net oF roY altieS (1)
Crude oil and ngls (mmbbl)
North America
North Sea
Offshore West Africa
natural gas (bcf)
North America
North Sea
Offshore West Africa
total reserves (mmboe)
reserve replacement ratio(4) (%)
Cost to develop(5) ($/boe)
10% discount
15% discount
present value of conventional reserves(6) ($ millions)
10% discount
15% discount
Crude oil and NGLs (mmbbl)
North America
North Sea
Offshore West Africa
Natural gas (bcf)
North America
North Sea
Offshore West Africa
Total reserves (mmboe)
Reserve replacement ratio(4) (%)
Cost to develop(5) ($/boe)
10% discount
15% discount
Present value of conventional reserves(6) ($ millions)
10% discount
15% discount
December 31, 2008
proved
proved
Developed(2) Undeveloped(2)
proved
total(2)
proved and
probable(3)
428
97
107
632
2,690
45
89
2,824
1,103
520
159
35
714
833
22
5
860
857
948
256
142
1,346
3,523
67
94
3,684
1,960
95%
0.80 $
0.70 $
6.94 $
6.04 $
3.48 $
3.03 $
1,599
399
191
2,189
4,619
94
131
4,844
2,996
134%
3.03
2.60
12,987 $
11,253 $
2,200 $
1,164 $
15,187 $
12,417 $
19,264
15,179
December 31, 2007
Proved
Proved
Developed(2) Undeveloped(2)
Proved
Total(2)
Proved and
Probable(3)
426
240
70
736
2,731
58
53
2,842
1,210
494
70
58
622
790
23
11
824
759
920
310
128
1,358
3,521
81
64
3,666
1,969
110%
1.25 $
1.09 $
6.73 $
6.43 $
3.36 $
3.15 $
1,545
405
186
2,136
4,602
113
88
4,803
2,937
87%
3.20
2.99
25,767 $
21,924 $
8,810 $
6,082 $
34,577 $
28,006 $
44,286
34,604
$
$
$
$
$
$
$
$
oil SandS MininG reSer VeS (1)
The following table sets out Canadian Natural’s reserves of synthetic crude oil from the Horizon Project Oil Sands leases.
net reserves, after royalties (mmbbl)
Synthetic crude oil(7)
December 31, 2008
December 31, 2007
proved
total
proved and
probable
Proved
Total
Proved and
Probable
1,946
2,944
1,761
2,680
CA NA DIAN NATURAL
35
total
1,316
30
16
3
1
(3)
(107)
102
1,358
51
17
10
–
–
(101)
(45)
56
130
–
–
–
–
–
(10)
8
128
–
4
–
–
–
(8)
8
10
142
1,346
195
–
–
–
–
–
(10)
1
186
–
–
–
–
–
(8)
8
5
2,119
41
58
4
8
(3)
(107)
16
2,136
76
13
23
6
–
(101)
22
14
191
2,189
conVentional crude oil and nGls reSer VeS reconciliation, net oF roY altieS(1)(8)
north
america
north
offshore
sea West africa
887
30
10
3
1
–
(77)
66
920
51
7
10
–
–
(76)
28
8
948
1,502
41
52
4
2
–
(77)
21
1,545
76
9
23
6
–
(76)
59
(43)
1,599
299
–
6
–
–
(3)
(20)
28
310
–
6
–
–
–
(17)
(81)
38
256
422
–
6
–
6
(3)
(20)
(6)
405
–
4
–
–
–
(17)
(45)
52
399
proved reserves (mmbbl)
Reserves, December 31, 2006
Extensions and discoveries
Infill drilling
Improved recovery
Property purchases
Property disposals
Production
Revisions of prior estimates
Reserves, December 31, 2007
Extensions and discoveries
Infill drilling
Improved recovery
Property purchases
Property disposals
Production
Economic revisions due to prices
Revisions of prior estimates
reserves, December 31, 2008
proved and probable reserves (mmbbl)
Reserves, December 31, 2006
Extensions and discoveries
Infill drilling
Improved recovery
Property purchases
Property disposals
Production
Revisions of prior estimates
Reserves, December 31, 2007
Extensions and discoveries
Infill drilling
Improved recovery
Property purchases
Property disposals
Production
Economic revisions due to prices
Revisions of prior estimates
reserves, December 31, 2008
36
CANAD IA N NATU RAL
conVentional natural GaS reSer VeS reconciliation, net oF roY altieS(1)(8)
north
america
north
offshore
sea West africa
proved reserves (bcf)
Reserves, December 31, 2006
Extensions and discoveries
Infill drilling
Improved recovery
Property purchases
Property disposals
Production
Revisions of prior estimates
Reserves, December 31, 2007
Extensions and discoveries
Infill drilling
Improved recovery
Property purchases
Property disposals
Production
Economic revisions due to prices
Revisions of prior estimates
reserves, December 31, 2008
proved and probable reserves (bcf)
Reserves, December 31, 2006
Extensions and discoveries
Infill drilling
Improved recovery
Property purchases
Property disposals
Production
Revisions of prior estimates
Reserves, December 31, 2007
Extensions and discoveries
Infill drilling
Improved recovery
Property purchases
Property disposals
Production
Economic revisions due to prices
Revisions of prior estimates
reserves, December 31, 2008
3,705
134
124
8
12
–
(503)
41
3,521
140
46
6
77
(1)
(449)
(19)
202
3,523
4,857
177
163
8
17
(1)
(503)
(116)
4,602
182
58
8
93
(6)
(449)
(27)
158
4,619
37
–
3
–
–
–
(5)
46
81
–
(1)
–
–
–
(4)
(56)
47
67
93
–
3
–
1
–
(5)
21
113
–
(3)
–
–
–
(4)
(63)
51
94
total
3,798
134
127
8
12
–
(512)
99
3,666
140
51
6
77
(1)
(457)
(69)
271
3,684
5,049
177
166
8
18
(1)
(512)
(102)
4,803
182
55
8
93
(6)
(457)
(82)
248
56
–
–
–
–
–
(4)
12
64
–
6
–
–
–
(4)
6
22
94
99
–
–
–
–
–
(4)
(7)
88
–
–
–
–
–
(4)
8
39
131
4,844
CA NA DIAN NATURAL
37
conVentional FindinG and on-StreaM coStS
net reserve replacement expenditures ($ millions)
net reserve additions (mmboe) (9)
Proved
Proved and probable
finding and on-stream costs ($/boe) (10)
Proved
Proved and probable
reSerVeS claSSiFication BY product , net oF roYaltieS(1)
2008
2007
2006
three Year
total
$
3,475 $
3,027 $
8,727 $
15,229
168
237
212
168
540
865
$
$
20.68 $
14.66 $
14.28 $
18.02 $
16.16 $
10.09 $
920
1,270
16.55
11.99
December 31, 2008
proved
proved
Developed(2) Undeveloped(2)
proved
total(2)
proved and
probable(3)
light crude oil and ngls
North America
North Sea
Offshore West Africa
Total
heavy crude oil and ngls
North America – Primary Heavy
North America – Pelican Lake
North America – Thermal
Total
total crude oil and ngls
North America
North Sea
Offshore West Africa
Total
natural gas
North America
North Sea
Offshore West Africa
Total
total Boe
5%
5%
5%
15%
4%
4%
9%
17%
22%
5%
5%
32%
23%
1%
1%
25%
57%
1%
8%
2%
11%
1%
3%
21%
25%
26%
8%
2%
36%
7%
–
–
7%
6%
13%
7%
26%
5%
7%
30%
42%
48%
13%
7%
68%
30%
1%
1%
32%
5%
13%
6%
24%
4%
7%
37%
48%
53%
13%
6%
72%
26%
1%
1%
28%
43%
100%
100%
38
CANAD IA N NATU RAL
(1) Reserve estimates and present value calculations are based upon year end constant reference price assumptions as detailed below as well as constant year-end costs.
Crude oil and NGLs
2008
2007
2006
Natural gas
2008
2007
2006
Company
Average
Price
(C$/bbl)
WTI @
Cushing
Oklahoma
(US$/bbl)
Hardisty
Heavy
12º API
(C$/bbl)
34.51 $
62.87 $
51.11 $
44.60 $
96.00 $
61.05 $
26.11 $
41.70 $
41.94 $
North
Sea
Brent
(US$/bbl)
41.76
96.02
58.93
Company
Average
Price
(C$/mcf)
Henry Hub
Louisiana
(US$/mmbtu)
Alberta
AECO C
(C$/mmbtu)
British Columbia
Huntingdon
Sumas
(C$/mmbtu)
6.51 $
6.48 $
6.07 $
5.63 $
6.80 $
5.52 $
6.34 $
6.52 $
6.13 $
7.48
6.96
6.52
$
$
$
$
$
$
A foreign exchange rate of US$0.82/C$1.00 was used in the 2008 evaluation; US$1.01/C$1.00 was used in the 2007 evaluation; US$0.86/C$1.00 was used in the
2006 evaluation.
(2) Proved reserve estimates and values were evaluated in accordance with the SEC requirements. The stated reserves have a reasonable certainty of being economically
recoverable using year-end prices and costs held constant throughout the productive life of the properties.
(3) Proved and probable reserve estimates and values were evaluated in accordance with the standards of the COGEH and as mandated by NI 51-101. The stated
reserves have a 50% probability of equaling or exceeding the indicated quantities and were evaluated using year-end costs and prices held constant throughout
the productive life of the properties.
(4) Reserve replacement ratios were calculated using annual net reserve additions comprised of all change categories divided by the net production for that year.
(5) Cost to develop represents total discounted future capital for each reserves category excluding abandonment capital divided by the reserves associated with that category.
(6) Present value of reserves are based upon discounted cash flows associated with prices and operating expenses held constant into the future, before income taxes.
Future development costs and associated material well abandonment costs have been applied against future net revenues.
(7) Synthetic crude oil reserves are based on upgrading of the bitumen using technologies implemented at the Horizon Project.
(8) In 2007, revisions of prior estimates includes economic revisions due to prices.
(9) Reserves additions are comprised of all categories of reserves changes, exclusive of production.
(10) Reserves finding and on-stream costs are determined by dividing total capital cash expenditures for each year by net reserves additions for that year. It excludes costs
associated with head office, abandonments, midstream and the Horizon Project.
CA NA DIAN NATURAL
39
canadian natural 2 008 a n n u a l r e p ort
management’s discussion and analysis
speCial note regarDing
forWarD-looKing statements
Certain statements in this document or documents incorporated
herein by reference constitute forward-looking statements
or information (collectively referred to herein as “forward-
looking statements”) within the meaning of applicable
securities legislation. Forward-looking statements can be
identified by the words “believe”, “anticipate”, “expect”,
“plan”, “estimate”, “target”, “continue”, “could”, “intend”,
“may”, “potential”, “predict”, “should”, “will”, “objective”,
“project”, “forecast”, “goal”, “guidance”, “outlook”,
“effort”, “seeks”, “schedule” or expressions of a similar
nature suggesting future outcome or statements regarding
an outlook. Disclosure related to expected future commodity
pricing, production volumes, royalties, operating costs, capital
expenditures, and other guidance provided throughout this
Management’s Discussion and Analysis (“MD&A”) including
the information in the “Outlook” section and the sensitivity
analysis constitute forward-looking statements. Disclosure of
plans relating to existing and future developments, including
but not limited to the Horizon Project, Primrose East, Pelican
Lake, Gabon Offshore West Africa, and the Kirby Oil Sands
Project also constitute forward-looking statements. This
forward-looking information is based on annual budgets and
multi-year forecasts, and is reviewed and revised throughout
the year if necessary in the context of targeted financial ratios,
project returns, product pricing expectations and balance
in project risk and time horizons. These statements are not
guarantees of future performance and are subject to certain
risks and the reader should not place undue reliance on these
forward-looking statements as there can be no assurances
that the plans, initiatives or expectations upon which they are
based will occur.
In addition, statements relating to “reserves” are deemed to
be forward-looking statements as they involve the implied
assessment based on certain estimates and assumptions
that the reserves described can be profitably produced in
the future. There are numerous uncertainties inherent in
estimating quantities of proved crude oil and natural gas
reserves and in projecting future rates of production and the
timing of development expenditures. The total amount or
timing of actual future production may vary significantly from
reserve and production estimates.
The forward-looking statements are based on current
expectations, estimates and projections about Canadian
Natural Resources Limited (the “Company”) and the industry
in which the Company operates, which speak only as of
the date such statements were made or as of the date of
the report or document in which they are contained, and
are subject to known and unknown risks, uncertainties and
other factors that could cause the actual results, performance
or achievements of the Company to be materially different
40
CANAD IA N NATU RAL
from any future results, performance or achievements
expressed or implied by such forward-looking statements.
Such factors include, among others: general economic and
business conditions which will, among other things, impact
demand for and market prices of the Company’s products;
volatility of and assumptions regarding crude oil and natural
gas prices; fluctuations in currency and interest rates;
assumptions on which the Company’s current guidance is
based; economic conditions in the countries and regions in
which the Company conducts business; political uncertainty,
including actions of or against terrorists, insurgent groups
or other conflict including conflict between states; industry
capacity; ability of the Company to implement its business
strategy, including exploration and development activities;
impact of competition; the Company’s defense of lawsuits;
availability and cost of seismic, drilling and other equipment;
ability of the Company and its subsidiaries to complete capital
programs; the Company’s and its subsidiaries’ ability to
secure adequate transportation for its products; unexpected
difficulties in mining, extracting or upgrading the Company’s
bitumen products; potential delays or changes in plans with
respect to exploration or development projects or capital
expenditures; ability of the Company to attract the necessary
labour required to build its thermal and oil sands mining
projects; operating hazards and other difficulties inherent in
the exploration for and production and sale of crude oil and
natural gas; availability and cost of financing; the Company’s
and its subsidiaries’ success of exploration and development
activities and their ability to replace and expand crude oil and
natural gas reserves; timing and success of integrating the
business and operations of acquired companies; production
levels; imprecision of reserve estimates and estimates of
recoverable quantities of crude oil, bitumen, natural gas
and liquids not currently classified as proved; actions by
governmental authorities; government regulations and the
expenditures required to comply with them (especially safety
and environmental laws and regulations and the impact of
climate change initiatives on capital and operating costs);
asset retirement obligations; the adequacy of the Company’s
provision for taxes; and other circumstances affecting revenues
and expenses. The Company’s operations have been, and in
the future may be, affected by political developments and
by federal, provincial and local laws and regulations such as
restrictions on production, changes in taxes, royalties and other
amounts payable to governments or governmental agencies,
price or gathering rate controls and environmental protection
regulations. Should one or more of these risks or uncertainties
materialize, or should any of the Company’s assumptions
prove incorrect, actual results may vary in material respects
from those projected in the forward-looking statements. The
impact of any one factor on a particular forward-looking
statement is not determinable with certainty as such factors
are dependent upon other factors, and the Company’s course
of action would depend upon its assessment of the future
considering all information then available. For additional
information refer to the “Risks and Uncertainties” section of
this MD&A.
Readers are cautioned that the foregoing list of factors is not
exhaustive. Unpredictable or unknown factors not discussed in
this report could also have material adverse effects on forward-
looking statements. Although the Company believes that the
expectations conveyed by the forward-looking statements are
reasonable based on information available to it on the date
such forward-looking statements are made, no assurances
can be given as to future results, levels of activity and
achievements. All subsequent forward-looking statements,
whether written or oral, attributable to the Company or
persons acting on its behalf are expressly qualified in their
entirety by these cautionary statements. Except as required by
law, the Company assumes no obligation to update forward-
looking statements should circumstances or Management’s
estimates or opinions change.
speCial note regarDing
non-gaap finanCial measUres
Management’s Discussion and Analysis includes references to
financial measures commonly used in the crude oil and natural
gas industry, such as adjusted net earnings from operations,
cash flow from operations and net asset value. These financial
measures are not defined by generally accepted accounting
principles in Canada (“GAAP”) and therefore are referred to
as non-GAAP measures. The non-GAAP measures used by
the Company may not be comparable to similar measures
presented by other companies. The Company uses these
non-GAAP measures to evaluate its performance. The
non-GAAP measures should not be considered an alternative
to or more meaningful than net earnings, as determined in
accordance with Canadian GAAP, as an indication of the
Company’s performance. The non-GAAP measures adjusted
net earnings from operations and cash flow from operations
are reconciled to net earnings, as determined in accordance
with Canadian GAAP, in the “Financial Highlights” section of
this MD&A. The Company also presents certain non-GAAP
financial ratios and their derivation in the “Liquidity and
Capital Resources” section of this MD&A.
management’s DisCUssion anD analYsis
Management’s Discussion and Analysis of the financial
condition and results of operations of the Company should be
read in conjunction with the Company’s audited consolidated
financial statements and related notes for the year ended
December 31, 2008. The consolidated financial statements
have been prepared in accordance with generally accepted
accounting principles in Canada (“Canadian GAAP”). A
reconciliation of Canadian GAAP to generally accepted
accounting principles in the United States (“US GAAP”) is
included in note 18 to the consolidated financial statements.
All dollar amounts are referenced in Canadian dollars,
except where otherwise noted. The calculation of barrels
of oil equivalent (“boe”) is based on a conversion ratio of
six thousand cubic feet (“mcf”) of natural gas to one barrel
(“bbl”) of crude oil to estimate relative energy content. This
conversion may be misleading, particularly when used in
isolation, since the 6 mcf:1 bbl ratio is based on an energy
equivalency at the burner tip and does not represent the
value equivalency at the wellhead. Production volumes are
the Company’s interest before royalties, and realized prices
are net of transportation and blending costs and exclude the
effect of risk management activities. The following discussion
and analysis refers primarily to the Company’s 2008 financial
results compared to 2007 and 2006, unless otherwise
indicated. In addition, this MD&A details the Company’s
capital program and outlook for 2009.
Additional information relating to the Company, including
its quarterly MD&A for the year and three months ended
December 31, 2008 and its Annual Information Form for the
year ended December 31, 2008, is available on SEDAR at
www.sedar.com.
This MD&A is dated March 4, 2009.
aBBreviations
aCC
aeCo
api
aro
bbl
bbl/d
bcf
boe
boe/d
Brent
C$
CiCa
Co2
Co2e
Canadian gaap
fpso
Anadarko Canada Corporation
Alberta natural gas reference location
Specific gravity measured in degrees on the
American Petroleum Institute scale
Asset retirement obligations
barrels
barrels per day
billion cubic feet
barrels of oil equivalent
barrels of oil equivalent per day
Dated Brent
Canadian dollars
Canadian Institute of Chartered Accountants
Carbon dioxide
Carbon dioxide equivalents
Generally accepted accounting principles
in Canada
Floating Production, Storage and
Offtake Vessel
Greenhouse Gas
gigajoules
gigajoules per day
ghg
gJ
gJ/d
heavy Differential Heavy crude oil differential from WTI
horizon project
liBor
mcf
mmbbl
mmbtu
mmcf/d
ngls
nYmeX
nYse
prt
sCo
seC
Horizon Oil Sands Project
London Interbank Offered Rate
thousand cubic feet
million barrels
million British thermal units
million cubic feet per day
Natural gas liquids
New York Mercantile Exchange
New York Stock Exchange
Petroleum Revenue Tax
Synthetic light crude oil
United States Securities and
Exchange Commission
Toronto Stock Exchange
United Kingdom
United States
Generally accepted accounting principles
in the United States
United States dollars
Western Canadian Select
tsX
UK
Us
Us gaap
Us$
WCs
Wti
West Texas Intermediate
CA NA DIAN NATURAL
41
oBJeCtive anD strategY
The Company’s objectives are to increase crude oil and natural gas production, reserves, cash flow and net asset value (1) on a per
common share basis through the development of its existing crude oil and natural gas properties and through the discovery and/
or acquisition of new reserves. The Company strives to meet these objectives by having a defined growth and value enhancement
plan for each of its products and segments. The Company takes a balanced approach to growth and investments and focuses on
creating long-term shareholder value. The Company allocates its capital by maintaining:
n
Balance among its products, namely natural gas, light/medium crude oil, Pelican Lake crude oil (2), primary heavy crude oil and
thermal heavy crude oil;
n Balance among near-, mid- and long-term projects;
n Balance among acquisitions, exploitation and exploration; and
n Balance between sources and terms of debt financing and maintenance of a strong balance sheet.
(1) Discounted value of conventional crude oil and natural gas reserves plus value of undeveloped land, less net debt.
(2) Pelican Lake crude oil is 14–17º API oil, which receives medium quality crude netbacks due to lower production costs and lower royalty rates.
The Company’s three-phase crude oil marketing strategy includes:
n Blending various crude oil streams with diluents to create more attractive feedstock;
n Supporting and participating in pipeline expansions and/or new additions; and
n Supporting and participating in projects that will increase the downstream conversion capacity for heavy crude oil.
Operational discipline and cost control are fundamental to the Company. By consistently controlling costs throughout all cycles of
the industry, the Company believes it will achieve continued growth. Cost control is attained by developing area knowledge, by
dominating core areas and by maintaining high working interests and operator status in its properties.
The Company is committed to maintaining a strong balance sheet and flexible capital structure. The Company believes it has built
the necessary financial capacity to complete all of its growth projects, including the Horizon Project and its conventional crude
oil and natural gas opportunities. Additionally, the Company’s risk management hedge program reduces the risk of volatility in
commodity prices and supports the Company’s cash flow for its capital expenditures programs.
Strategic accretive acquisitions, like the acquisition of ACC in 2006, are a key component of the Company’s strategy. The Company
has used a combination of internally generated cash flows and debt financing to selectively acquire properties generating future
cash flows in its core regions.
Highlights for the year ended December 31, 2008 include the following:
n Achieved record levels of net earnings, adjusted net earnings from operations, and cash flow from operations;
n Achieved annual crude oil and natural gas production guidance;
n Completed the construction of and achieved first production from the Primrose East Expansion;
n Completed drilling and brought three wells back on production at the Baobab Field, Côte d’Ivoire;
n Development continued on the Olowi Field in offshore Gabon with first oil targeted for Spring 2009;
n Substantially completed construction of Phase 1 of the Horizon Project; and
n
Increased dividends per common share.
net earnings anD Cash floW from operations
Financial Highlights
($ millions, except per common share amounts)
Revenue, before royalties
Net earnings
Per common share – basic and diluted
Adjusted net earnings from operations (1)
Per common share – basic and diluted
Cash flow from operations (2)
Per common share – basic and diluted
Dividends declared per common share
Total assets
Total long-term liabilities
Capital expenditures, net of dispositions
2008
2007
$
$
$
$
$
$
$
$
$
$
$
16,173 $
4,985 $
9.22 $
3,492 $
6.46 $
6,969 $
12.89 $
0.40 $
42,650 $
20,856 $
7,451 $
12,543 $
2,608 $
4.84 $
2,406 $
4.46 $
6,198 $
11.49 $
0.34 $
36,114 $
19,230 $
6,425 $
2006
11,643
2,524
4.70
1,664
3.10
4,932
9.18
0.30
33,160
19,399
12,025
(2)
(1) Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company
evaluates its performance based on adjusted net earnings from operations. The reconciliation “Adjusted Net Earnings from Operations” presented below lists the
after-tax effects of certain items of a non-operational nature that are included in the Company’s financial results. Adjusted net earnings from operations may not
be comparable to similar measures presented by other companies.
Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company
evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company’s
ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Cash Flow from Operations”
presented below lists the effects of certain non-cash items that are included in the Company’s financial results. Cash flow from operations may not be comparable to
similar measures presented by other companies.
42
CANAD IA N NATU RAL
adjusted net earnings from operations
($ millions)
Net earnings as reported
Stock-based compensation (recovery) expense, net of tax (a)
Unrealized risk management (gain) loss, net of tax (b)
Unrealized foreign exchange loss (gain), net of tax (c)
Effect of statutory tax rate and other legislative changes
on future income tax liabilities (d)
Adjusted net earnings from operations
2008
2007
$
4,985 $
(38)
(2,112)
698
2,608 $
134
977
(449)
(41)
(864)
$
3,492 $
2,406 $
2006
2,524
95
(674)
114
(395)
1,664
(a)
The Company’s employee stock option plan provides for a cash payment option. Accordingly, the intrinsic value of outstanding vested options is recorded as a
liability on the Company’s balance sheet and periodic changes in the intrinsic value are recognized in net earnings or are capitalized as part of the Horizon Project
during the construction period.
(c)
(d)
(b) Derivative financial instruments are recorded at fair value on the balance sheet, with changes in fair value of non-designated hedges recognized in net earnings. The
amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily
crude oil and natural gas.
Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, offset
by the impact of cross currency swap hedges, and are recognized in net earnings.
All substantively enacted or enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the
Company’s consolidated balance sheet in determining future income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in
net earnings during the period the legislation is substantively enacted or enacted. Income tax rate changes during 2008 resulted in a reduction of future income tax
liabilities of approximately $19 million in North America and $22 million in Côte d’Ivoire, Offshore West Africa. Income tax rate and other legislative changes during
2007 resulted in a reduction of future income tax liabilities of approximately $864 million in North America. Income tax rate changes during 2006 resulted in an
increase of future income tax liabilities of approximately $110 million in the North Sea, a reduction of approximately $438 million in North America, and a reduction of
approximately $67 million in Côte d’Ivoire, Offshore West Africa.
cash Flow from operations
($ millions)
Net earnings
Non-cash items:
Depletion, depreciation and amortization
Asset retirement obligation accretion
Stock-based compensation (recovery) expense
Unrealized risk management (gain) loss
Unrealized foreign exchange loss (gain)
Deferred petroleum revenue tax (recovery) expense
Future income tax expense (recovery)
2008
2007
$
4,985 $
2,608 $
2,683
71
(52)
(3,090)
832
(67)
1,607
2,863
70
193
1,400
(524)
44
(456)
Cash flow from operations
$
6,969 $
6,198 $
2006
2,524
2,391
68
139
(1,013)
134
37
652
4,932
For 2008, the Company reported net earnings of $4,985 million compared to net earnings of $2,608 million for 2007 (2006 –
$2,524 million). Net earnings for the year ended December 31, 2008 included net unrealized after-tax income of $1,493 million
related to the effects of risk management activities, changes in foreign exchange rates, stock-based compensation, and the impact
of statutory tax rate and other legislative changes on future income tax liabilities (2007 – $202 million; 2006 – $860 million).
Excluding these items, adjusted net earnings from operations for the year ended December 31, 2008 increased to $3,492 million
from $2,406 million for 2007 (2006 – $1,664 million) primarily due to the impact of higher realized pricing, lower depletion,
depreciation and amortization expense, and lower interest and administration expense. These factors were partially offset by
higher realized risk management losses, higher royalty and production expense, lower sales volumes, and the impact of the
stronger Canadian dollar relative to the US dollar during the first half of 2008.
The impacts of unrealized risk management activities, stock-based compensation and changes in foreign exchange rates are
expected to continue to contribute to significant volatility in consolidated net earnings and are discussed in detail in the relevant
sections of this MD&A.
Cash flow from operations for the year ended December 31, 2008 increased to $6,969 million ($12.89 per common share) from
$6,198 million ($11.49 per common share) for 2007 (2006 – $4,932 million; $9.18 per common share). The increase was primarily
due to the impact of higher realized pricing and lower interest and administration expense, partially offset by higher realized risk
management losses, higher royalty and production expense, higher current income tax expense, lower sales volumes, and the
impact of the stronger Canadian dollar relative to the US dollar during the first half of 2008.
For 2008, the Company’s average sales price per bbl of crude oil and NGLs increased to $82.41 per bbl from $55.45 per bbl in
2007 (2006 – $53.65 per bbl). The Company’s average natural gas price increased to $8.39 per mcf from $6.85 per mcf for 2007
(2006 – $6.72 per mcf).
Total production of crude oil and NGLs before royalties decreased to 315,667 bbl/d from 331,232 bbl/d for 2007 (2006 –
331,998 bbl/d). The decrease in crude oil and NGLs production was primarily due to lower production in the North Sea and
Offshore West Africa due to the timing of field turnarounds, the sale of the Company’s working interest in the B-Block Fields late
in 2007, and the impact of the shut in of a portion of the Baobab Field production, and in North America due to the cyclic nature
of the Company’s thermal production.
CA NA DIAN NATURAL
43
Total natural gas production before royalties decreased to 1,495 mmcf/d from 1,668 mmcf/d for 2007 (2006 – 1,492 mmcf/d).
The decrease in natural gas production primarily reflected natural production declines due to the Company’s strategic reduction in
natural gas drilling activity in North America.
Total crude oil and NGLs and natural gas production volumes before royalties decreased to 564,845 boe/d from 609,206 boe/d for
2007 (2006 – 580,724 boe/d). Total production for 2008 was within the Company’s previously issued guidance.
operating highlights
Crude oil and ngls ($/bbl) (1)
Sales price (2)
Royalties
Production expense
Netback
natural gas ($/mcf) (1)
Sales price (2)
Royalties
Production expense
Netback
Barrels of oil equivalent ($/boe) (1)
Sales price (2)
Royalties
Production expense
Netback
2008
2007
2006
$
$
$
$
$
$
82.41 $
10.48
16.26
55.67 $
8.39 $
1.46
1.02
5.91 $
68.62 $
9.78
11.79
47.05 $
55.45 $
5.94
13.34
36.17 $
6.85 $
1.11
0.91
4.83 $
49.05 $
6.26
9.75
33.04 $
53.65
4.48
12.29
36.88
6.72
1.29
0.82
4.61
47.92
5.89
9.14
32.89
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management activities.
sUmmarY of QUarterlY resUlts
The following is a summary of the Company’s quarterly results for the eight most recently completed quarters:
($ millions, except per common share amounts)
2008
Revenue, before royalties
Net earnings (loss)
Net earnings (loss) per common share
– basic and diluted
2007
Revenue, before royalties
Net earnings
Net earnings per common share
– basic and diluted
total
Dec 31
sep 30
Jun 30
mar 31
16,173 $
4,985 $
2,511 $
1,770 $
4,583 $
2,835 $
5,112 $
(347) $
3,967
727
9.22 $
3.27 $
5.25 $
(0.65) $
1.35
Total
Dec 31
Sep 30
Jun 30
Mar 31
12,543 $
2,608 $
3,200 $
798 $
3,073 $
700 $
3,152 $
841 $
3,118
269
4.84 $
1.48 $
1.30 $
1.56 $
0.50
$
$
$
$
$
$
Net earnings (loss) over the eight most recently completed quarters generally reflected fluctuations in realized crude oil and
natural gas prices, fluctuations in sales volumes, the impact of mark-to-market accounting of derivative financial instruments and
stock-based compensation, fluctuations in depletion, depreciation and amortization charges and foreign exchange rates, and
adjustments to future income tax liabilities due to statutory tax rate and other legislative changes. More specifically, volatility in
quarterly net earnings was primarily due to:
n crude oil pricing
Crude oil prices reflected fluctuating demand, geopolitical uncertainties and fluctuations in the Heavy Differential in North America.
n natural gas pricing
Natural gas prices primarily reflected seasonal fluctuations in both the demand for natural gas and inventory storage levels,
fluctuations in liquefied natural gas imports into the US, and increased shale gas production in the US.
n crude oil and nGls sales volumes
Crude oil and NGLs sales volumes primarily reflected increased production from the Company’s Primrose thermal projects, the
results from the Pelican Lake water and polymer flood projects, and development of the Espoir Field. Crude oil and NGLs sales
volumes also reflected fluctuations in production from the North Sea and Offshore West Africa due to timing of liftings and
maintenance activities and the impact of the shut in of a portion of the Baobab Field production.
44
CANAD IA N NATU RAL
n natural gas sales volumes
Natural gas sales volumes primarily reflected production declines due to the Company’s strategic decision to reduce natural gas
drilling activity in North America due to the allocation of capital to higher return crude oil projects, as well as natural decline rates.
n Foreign exchange rates
Fluctuations in the Canadian dollar relative to the US dollar impacted the realized price the Company received for its crude
oil and natural gas sales, as sales prices are based predominately on US dollar denominated benchmarks. Similarly, unrealized
foreign exchange gains and losses were recorded with respect to US dollar denominated debt and the re-measurement of North
Sea future income tax liabilities denominated in UK pounds sterling to US dollars, partially offset by the impact of cross currency
swap hedges.
n risk management
Net earnings (loss) have fluctuated due to the recognition of realized and unrealized gains and losses from the mark-to-market
and subsequent settlement of the Company’s risk management activities.
n changes in income tax expense
Fluctuations in income tax expense (recovery) include statutory tax rate and other legislative changes substantively enacted or
enacted in the various periods.
n Stock-based compensation
Net earnings (loss) have fluctuated due to the mark-to-market movements of the Company’s stock-based compensation liability.
Stock-based compensation expense (recovery) reflected fluctuations in the Company’s share price over the eight most recently
completed quarters.
n production expense
Production expense has fluctuated company wide primarily due to the impact of the demand for services, industry-wide
inflationary cost pressures experienced in prior quarters in all segments, fluctuations in product mix, and the impact of seasonal
costs that are dependent on weather.
n depletion, depreciation and amortization
Depletion, depreciation and amortization expense has fluctuated due to changes in sales volumes, finding and development
costs associated with crude oil and natural gas exploration, and estimated future costs to develop the Company’s proved
undeveloped reserves.
BUsiness environment
(Yearly average)
WTI benchmark price (US$/bbl)
Dated Brent benchmark price (US$/bbl)
WCS blend differential from WTI (US$/bbl) (1)
WCS blend differential from WTI (%) (1)
Condensate benchmark price (US$/bbl)
NYMEX benchmark price (US$/mmbtu)
AECO benchmark price (C$/GJ)
US / Canadian dollar average exchange rate
US / Canadian dollar year end exchange rate
2008
2007
$
$
$
$
$
$
$
$
99.65 $
96.99 $
20.03 $
20%
100.10 $
8.95 $
7.71 $
0.9381 $
0.8166 $
72.40 $
72.59 $
23.25 $
32%
72.88 $
6.92 $
6.26 $
0.9304 $
1.0120 $
2006
66.25
65.18
21.53
32%
66.24
7.26
6.62
0.8818
0.8581
(1)
Beginning in 2008, the Company has quantified the Heavy Differential using the WCS blend as the heavy crude oil marker. Prior period amounts have been
reclassified.
commodity prices
Substantially all of the Company’s production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based
on WTI and Brent indices. Canadian natural gas pricing is primarily based on Alberta AECO reference pricing, which is derived
from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at Henry Hub. The
Company’s realized price is also highly sensitive to fluctuations in foreign exchange rates. The average value of the Canadian dollar
in relation to the US dollar fluctuated significantly throughout 2008, with a high of approximately $1.03 in February 2008 and a
low of approximately $0.77 in December 2008.
The overall increase in WTI pricing in 2008 reflected strong demand for crude oil and tight supply during the first half of 2008,
followed by a significant decrease in demand as a result of worldwide financial and economic events during the fourth quarter of
the year. WTI pricing was also impacted by ongoing geopolitical uncertainty resulting in increased market volatility. For 2008, WTI
averaged US$99.65 per bbl, an increase of 38% compared to US$72.40 per bbl for 2007 (2006 – US$66.25 per bbl). WTI reached
a high of US$147.27 per bbl on July 11, 2008 and a low of US$32.40 per bbl on December 19, 2008.
Brent averaged US$96.99 per bbl for 2008, an increase of 34% compared to US$72.59 per bbl for 2007 (2006 – US$65.18 per bbl).
Crude oil sales contracts for the North Sea and Offshore West Africa are typically based on Brent pricing, which was also impacted
by worldwide financial and economic events late in the year.
CA NA DIAN NATURAL
45
The Company’s realized crude oil prices benefited from strong commodity pricing during most of the year and a favorable Heavy
Differential. The Heavy Differential averaged 20% of WTI for 2008, compared to 32% for 2007 (2006 – 32%). As the worldwide
demand for diesel remained strong and the refinery cracking margins were relatively weak, the Heavy Differential continued to
remain strong, despite the falling benchmark pricing late in 2008.
The Company anticipates continued volatility in the crude oil pricing benchmarks due to the unpredictable nature of supply and
demand factors, geopolitical events and the global economic slowdown resulting from worldwide financial and economic events.
The Heavy Differential is expected to continue to reflect seasonal demand fluctuations and refinery cracking margins.
NYMEX natural gas prices averaged US$8.95 per mmbtu for 2008, an increase of 29% from US$6.92 per mmbtu for 2007 (2006
– US$7.26 per mmbtu). The Alberta based AECO natural gas pricing for 2008 increased 23% to average $7.71 per GJ from $6.26
per GJ in 2007 (2006 – $6.62 per GJ). During the first half of 2008, the demand and pricing for natural gas were tracking with oil
pricing and general economic activity. During the second half of the year, natural gas pricing decreased due to a significant increase
in production from shale gas reservoirs in the US and a significant decline in industrial demand caused by the onset of worldwide
financial and economic events.
operating, royalty and capital costs
Strong commodity prices over the last several years have resulted in increased demand for oilfield services worldwide. This has led
to inflationary operating and capital cost pressures throughout the crude oil and natural gas industry, particularly related to drilling
activities and oil sands developments.
The crude oil and natural gas industry is also experiencing cost pressures related to environmental regulations, both in North
America and internationally. In Canada, the Federal Government has indicated its intent to develop regulations that would be
in effect in 2010 to address industrial GHG emissions; however future Federal regulatory requirements remain uncertain. The
Federal Government has also outlined national and sectoral reduction targets for several categories of air pollutants. In Alberta,
GHG regulations came into effect July 1, 2007, affecting facilities emitting more than 100 kilotonnes of CO2e annually. Two of
the Company’s facilities, the Primrose/Wolf Lake in-situ heavy crude oil facilities and the Hays sour natural gas plant, fall under the
regulations. Commencing July 1, 2008, the British Columbia carbon tax is being assessed at $10/tonne of CO2e on fuel consumed
in the province, increasing to $30/tonne by July 1, 2012. In the UK, GHG regulations have been in effect since 2005. During Phase 1
(2005 – 2007) of the UK National Allocation Plan, the Company operated below its CO2 allocation. For Phase 2 (2008 – 2012)
the Company’s CO2 allocation has been decreased below the Company’s estimated current operations emissions. The Company
continues to focus on implementing reduction programs based on efficiency audits to reduce CO2 emissions at its major facilities
and on trading mechanisms to ensure compliance with requirements now in effect.
Continued cost pressures and the final outcome of changes to environmental regulations may adversely impact the Company’s
future net earnings, cash flow and capital projects. For additional details, refer to the “Greenhouse Gas and Other Air Emissions”
section of this MD&A.
The Alberta Government implemented its New Royalty Framework (“NRF”) effective January 1, 2009. The NRF includes a number
of changes to royalty rates for natural gas, conventional crude oil, and oil sands production. Under the NRF, royalties payable vary
according to commodity prices and the productivity of wells. Leading up to the January 2009 implementation of the NRF, the
Alberta Government made several adjustments to the originally proposed formula to address unintended consequences. These
adjustments affect royalties payable for certain natural gas and crude oil production wells. For additional details, refer to the
“Royalties” section of this MD&A.
46
CANAD IA N NATU RAL
analYsis of Changes in revenUe, Before roYalties anD risK management aCtivities
Changes due to
Changes due to
($ millions)
2006
Volumes
Prices
Other
2007 volumes
prices
other
2008
north america
Crude oil and NGLs
Natural Gas
north sea
Crude oil and NGLs
Natural gas
offshore West africa
Crude oil and NGLs
Natural gas
subtotal
Crude oil and NGLs
Natural gas
$ 5,262 $
3,804
298 $
452
9,066
750
287 $
46
333
– $
–
5,847 $
4,302
(49) $ 3,013 $
(531)
914
10,149
(580)
3,927
1,600
16
1,616
931
19
950
7,793
3,839
(107)
(2)
(109)
(216)
5
(211)
(25)
455
430
–
82
8
90
36
1
37
405
55
460
–
–
–
–
–
–
–
–
–
–
–
–
2
8
1,575
22
1,597
751
25
776
8,173
4,349
12,522
74
(53)
(334)
(5)
(339)
(136)
5
(131)
(519)
(531)
(1,050)
–
–
512
(1)
511
280
19
299
3,805
932
4,737
–
– $ 8,811
4,685
–
–
13,496
–
–
–
–
–
–
–
–
–
3
1,753
16
1,769
895
49
944
11,459
4,750
16,209
77
11,632
72
midstream
intersegment eliminations
and other (1)
(61)
–
–
(60)
(113)
total
$ 11,643 $
430 $
460 $
10 $ 12,543 $ (1,050) $ 4,737 $
(57) $ 16,173
(1) Eliminates primarily internal transportation, electricity charges, and natural gas sales.
Revenue increased 29% to $16,173 million for 2008 from $12,543 million for 2007 (2006 – $11,643 million). The increase was
primarily due to increased realized crude oil and NGLs and natural gas prices company-wide.
For 2008, 17% of the Company’s crude oil and natural gas revenue was generated outside of North America (2007 – 19%; 2006
– 22%). North Sea accounted for 11% of crude oil and natural gas revenue for 2008 (2007 – 13%; 2006 – 14%), and Offshore
West Africa accounted for 6% of crude oil and natural gas revenue for 2008 (2007 – 6%; 2006 – 8%).
analYsis of proDUCt priCes
Crude oil and ngls ($/bbl) (1) (2)
North America
North Sea
Offshore West Africa
Company average
natural gas ($/mcf) (1) (2)
North America
North Sea
Offshore West Africa
Company average
Company average ($/boe) (1) (2)
percentage of gross revenue (2) (excluding midstream revenue)
Crude oil and NGLs
Natural gas
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management activities.
2008
2007
2006
$
$
$
$
$
$
$
$
$
77.42 $
100.31 $
97.96 $
82.41 $
8.41 $
4.09 $
10.03 $
8.39 $
68.62 $
49.16 $
74.99 $
71.68 $
55.45 $
6.87 $
4.26 $
5.68 $
6.85 $
46.52
72.62
67.99
53.65
6.77
2.66
5.37
6.72
49.05 $
47.92
68%
32%
62%
38%
64%
36%
Realized crude oil and NGLs prices increased 49% to average $82.41 per bbl for 2008 from $55.45 per bbl for 2007 (2006 –
$53.65 per bbl). The increase in 2008 was primarily a result of higher WTI and Brent benchmark crude oil prices during most of
the year and a narrower Heavy Differential, partially offset by the impact of the stronger Canadian dollar relative to the US dollar
during the first half of 2008.
The Company’s realized natural gas price increased 22% to average $8.39 per mcf for 2008 from $6.85 per mcf for 2007 (2006
– $6.72 per mcf). The increase in 2008 was primarily a result of increased benchmark prices due to increased industrial demand
and lower liquefied natural gas imports into the US in the first half of 2008, partially offset by a significant reduction in industrial
demand late in the year as a result of worldwide financial and economic events, and the impact of higher storage levels due to
increased shale gas production in the US.
CA NA DIAN NATURAL
47
north america
North America realized crude oil prices increased 57% to average $77.42 per bbl for 2008 from $49.16 per bbl for 2007 (2006
– $46.52 per bbl). The increase in 2008 was due to increased WTI benchmark pricing and a narrower Heavy Differential, partially
offset by the impact of the strong Canadian dollar during the first half of 2008.
In North America, the Company continues to focus on its crude oil marketing strategy, including the development of a blending
strategy that expands markets within current pipeline infrastructure, supporting pipeline projects that will provide capacity to
transport crude oil to new markets, and working with refiners to add incremental heavy crude oil conversion capacity. During 2008,
the Company contributed approximately 150,000 bbl/d of heavy crude oil blends to the WCS stream. The Company has entered
into a 20 year transportation agreement to commit to ship 120,000 bbl/d of heavy sour crude oil on the proposed 500,000 bbl/d
Keystone Pipeline US Gulf Coast expansion from Hardisty, Alberta to the US Gulf Coast. Contemporaneously, the Company also
entered into a 20 year crude oil purchase and sales agreement to sell 100,000 bbl/d of heavy sour crude oil to a major US refiner.
Deliveries under the agreements are expected to commence in 2012 upon completion of the pipeline expansion and are subject to
Keystone’s receipt of regulatory approval of the pipeline expansion.
North America realized natural gas prices increased 22% to average $8.41 per mcf for 2008 from $6.87 per mcf for 2007 (2006 –
$6.77 per mcf), primarily related to fluctuations in benchmark prices due to the impact of weather and storage levels.
Comparisons of the prices received for the Company’s North America production by product type were as follows:
Wellhead price (1) (2)
Light/medium crude oil and NGLs (C$/bbl)
Pelican Lake crude oil (C$/bbl)
Primary heavy crude oil (C$/bbl)
Thermal heavy crude oil (C$/bbl)
Natural gas (C$/mcf)
2008
2007
2006
$
$
$
$
$
89.04 $
76.91 $
74.91 $
71.89 $
8.41 $
66.24 $
46.29 $
43.77 $
43.49 $
6.87 $
63.09
45.02
41.35
40.98
6.77
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management activities.
north Sea
North Sea realized crude oil prices increased 34% to average $100.31 per bbl for 2008 from $74.99 per bbl for 2007 (2006 –
$72.62 per bbl). Realized crude oil prices per bbl in any particular period are dependant on the terms of the various sales contracts,
the frequency and timing of liftings of each field, and prevailing crude oil prices at the time of lifting. Realized crude oil prices
in the North Sea during 2008 benefited from the increased Brent benchmark pricing, partially offset by the impact of the strong
Canadian dollar during the first half of 2008.
offshore West africa
Offshore West Africa realized crude oil prices increased 37% to average $97.96 per bbl for 2008 from $71.68 per bbl for 2007
(2006 – $67.99 per bbl). Realized crude oil prices per bbl in any particular period are dependant on the terms of the various sales
contracts, the frequency and timing of liftings of each field, and prevailing crude oil prices at the time of lifting. Realized crude oil
prices in Offshore West Africa during 2008 benefited from the increased Brent benchmark pricing, partially offset by the impact of
the strong Canadian dollar during the first half of 2008.
analYsis of DailY proDUCtion, Before roYalties
Crude oil and ngls (bbl/d)
North America
North Sea
Offshore West Africa
natural gas (mmcf/d)
North America
North Sea
Offshore West Africa
2008
2007
2006
243,826
45,274
26,567
315,667
1,472
10
13
1,495
246,779
55,933
28,520
331,232
1,643
13
12
1,668
235,253
60,056
36,689
331,998
1,468
15
9
1,492
total barrels of oil equivalent (boe/d)
564,845
609,206
580,724
product mix
Light/medium crude oil and NGLs
Pelican Lake crude oil
Primary heavy crude oil
Thermal heavy crude oil
Natural gas
48
CANAD IA N NATU RAL
22%
6%
16%
12%
44%
23%
6%
15%
11%
45%
26%
5%
16%
11%
42%
daily production, net of royalties
Crude oil and ngls (bbl/d)
North America
North Sea
Offshore West Africa
natural gas (mmcf/d)
North America
North Sea
Offshore West Africa
2008
2007
2006
207,933
45,182
22,641
275,756
1,225
10
11
1,246
210,769
55,825
26,012
292,606
1,378
13
11
1,402
205,382
59,940
35,212
300,534
1,185
15
9
1,209
total barrels of oil equivalent (boe/d)
483,541
526,193
502,024
Daily production and per barrel statistics are presented throughout this MD&A on a “before royalty” or “gross” basis. Production
on an “after royalty” or “net” basis is also presented.
The Company’s business approach is to maintain large project inventories and production diversification among each of the
commodities it produces; namely natural gas, light/medium crude oil and NGLs, Pelican Lake crude oil, primary heavy crude oil and
thermal heavy crude oil.
Total production averaged 564,845 boe/d for 2008, a 7% decrease from 609,206 boe/d for 2007 (2006 – 580,724 boe/d).
Total production of crude oil and NGLs before royalties decreased 5% to 315,667 bbl/d for 2008 from 331,232 bbl/d for 2007
(2006 – 331,998 bbl/d). The decrease in crude oil and NGLs production from 2007 primarily reflected lower production in the
North Sea and Offshore West Africa due to the timing of field turnarounds and the sale of the Company’s working interest in the
B-Block Fields late in 2007, and in North America due to the cyclic nature of the Company’s thermal production. Crude oil and
NGLs production for 2008 was within the Company’s previously issued guidance of 313,000 to 318,000 bbl/d.
Natural gas production continued to represent the Company’s largest product offering, accounting for 44% of the Company’s total
production in 2008. Total natural gas production before royalties decreased 10% to 1,495 mmcf/d for 2008 from 1,668 mmcf/d
for 2007 (2006 – 1,492 mmcf/d). The decrease in natural gas production from 2007 primarily reflected natural production declines
due to the Company’s strategic decision to reduce natural gas drilling activity to focus on higher return crude oil projects. Natural
gas production for 2008 was within the Company’s previously issued guidance of 1,492 to 1,506 mmcf/d.
For 2009, revised annual production is forecasted to average between 331,000 and 399,000 bbl/d of crude oil and NGLs and
between 1,272 and 1,328 mmcf/d of natural gas.
north america
North America crude oil and NGLs production for 2008 decreased 1% to average 243,826 bbl/d from 246,779 bbl/d for 2007 (2006 –
235,253 bbl/d). The decrease in production from 2007 was primarily due to the cyclic nature of the Company’s thermal production.
North America natural gas production for 2008 decreased 10% to average 1,472 mmcf/d from 1,643 mmcf/d for 2007 (2006 –
1,468 mmcf/d). The decrease in natural gas production from 2007 reflected production declines due to the Company’s strategic
decision to reduce natural gas drilling activity to focus on higher return crude oil projects.
north Sea
North Sea crude oil production for 2008 was 45,274 bbl/d, a decrease of 19% from 55,933 bbl/d for 2007 (2006 – 60,056 bbl/d)
due to increased planned maintenance, the sale of the Company’s working interest in the B-Block Fields late in 2007, expected
production declines and delays in development projects.
offshore West africa
Offshore West Africa crude oil production for 2008 decreased 7% to 26,567 bbl/d from 28,520 bbl/d for 2007 (2006 – 36,689 bbl/d).
Production decreased in 2008 due to expected production declines, partially offset by a full year of production at the recently
completed West Espoir development and restoration of certain of the shut-in production at the Baobab Field during the fourth
quarter of 2008.
CA NA DIAN NATURAL
49
CrUDe oil inventorY volUmes
The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place. The
related crude oil volumes by segment, which have not been recognized in revenue, were as follows:
(bbl)
North America, related to pipeline fill
North Sea, related to timing of liftings
Offshore West Africa, related to timing of liftings
2008
2007
2006
761,351
558,904
609,444
1,097,526
1,032,723
8,578
1,097,526
910,796
113,774
1,929,699
2,138,827
2,122,096
During 2008, the North America pipeline fill was reduced, increasing cash flow from operations by approximately $18 million.
In addition, during 2008, net production of approximately 127,000 barrels of crude oil produced in the Company’s international
operations was deferred and included in inventory at December 31, 2008. Notwithstanding the overall increase in inventory, cash
flow from operations increased by approximately $5 million, as the increase in cash flow from additional sales volumes in the North
Sea more than offset the decrease in cash flow from lower sales volumes in Offshore West Africa due to the timing of liftings.
roYalties
Crude oil and ngls ($/bbl) (1)
North America
North Sea
Offshore West Africa
Company average
natural gas ($/mcf) (1)
North America
Offshore West Africa
Company average
Company average ($/boe) (1)
percentage of revenue (2)
Crude oil and NGLs
Natural gas
Boe
2008
2007
2006
$
$
$
$
$
$
$
$
11.99 $
0.21 $
14.81 $
10.48 $
1.47 $
1.52 $
1.46 $
9.78 $
13%
17%
14%
7.19 $
0.14 $
6.40 $
5.94 $
1.12 $
0.51 $
1.11 $
6.26 $
11%
16%
13%
5.86
0.13
2.81
4.48
1.31
0.22
1.29
5.89
8%
19%
12%
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management activities.
north america
Government royalties on a significant portion of North America crude oil and NGLs production fall under the oil sands royalty
regime and are calculated on a project by project basis as a percentage of gross revenue less operating, capital and abandonment
costs (“net profit”). For 2008 and prior years, royalties were calculated as 1% of gross revenues until the Company’s capital
investments in the applicable project were fully recovered, at which time the royalty increased to 25% of net profit. Effective
January 1, 2009, changes to the Alberta royalty regime under the NRF include the implementation of a sliding scale for oil sands
royalties ranging from 1% to 9% on a gross revenue basis pre-payout and 25% to 40% on a net revenue basis post-payout
depending on benchmark crude oil pricing.
In addition, effective January 1, 2009, new royalty formulas under the NRF for conventional crude oil and natural gas are to operate
on sliding scales ranging up to 50%, determined by commodity prices and well productivity.
Crude oil and NGLs royalties for 2008 continued to reflect strong realized crude oil prices and averaged approximately 15% of
gross revenues for 2008 and 2007 (2006 – 13%). North America crude oil and NGLs royalties per bbl are anticipated to average
10% to 15% of gross revenue for 2009.
Natural gas royalties per mcf generally fluctuate with natural gas prices and well productivity. Natural gas royalties averaged approximately
18% of gross revenues for 2008 compared to 16% for 2007 (2006 – 19%), primarily due to increased benchmark natural gas prices.
North America natural gas royalties per mcf are anticipated to average 14% to 18% of gross revenue for 2009.
north Sea
North Sea government royalties on crude oil were eliminated effective January 1, 2003. The remaining royalty is a gross overriding
royalty on the Ninian Field.
offshore West africa
Offshore West Africa production in both Côte d’Ivoire and Gabon is governed by the terms of the various Production Sharing
Contracts (“PSCs”). Under the PSCs, revenues are divided into cost recovery oil and profit oil. Cost recovery oil allows the Company
to recover its capital and production costs and the costs carried by the Company on behalf of the Government State Oil Companies.
Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been
50
CANAD IA N NATU RAL
allocated to the Governments. The Governments’ share of profit oil attributable to the Company’s equity interest is allocated
between royalty expense and current income tax expense in accordance with the PSCs. The Company’s capital investments in the
Espoir Fields in Côte d’Ivoire were fully recovered in early 2007, increasing royalty rates and current income taxes in accordance
with the terms of the PSCs.
Royalty rates as a percentage of revenue averaged approximately 15% for 2008 compared to 9% for 2007 (2006 – 4%). The
increase in royalty rates from 2007 was due to the impact of the Company’s full recovery of its capital investment in the Espoir Fields
in 2007 and the resulting increase in profit oil on which the Government’s entitlement is based. The increase was compounded by
the impact of the reduction in the Côte d’Ivoire corporate income tax rate enacted early in 2008, which had the effect of increasing
the allocation of the Government’s share of profit oil to royalties. Offshore West Africa royalty rates are anticipated to average 6%
to 10% of gross revenue for 2009, reflecting a lower price environment and the Espoir Field contributing a lower proportion of the
total Offshore West Africa production.
proDUCtion eXpense
Crude oil and ngls ($/bbl) (1)
North America
North Sea
Offshore West Africa
Company average
natural gas ($/mcf) (1)
North America
North Sea
Offshore West Africa
Company average
Company average ($/boe) (1)
2008
2007
2006
$
$
$
$
$
$
$
$
$
14.96 $
26.29 $
10.29 $
16.26 $
1.00 $
2.51 $
1.61 $
1.02 $
11.79 $
12.26 $
20.78 $
8.32 $
13.34 $
0.90 $
2.17 $
1.48 $
0.91 $
9.75 $
11.73
17.57
7.45
12.29
0.81
1.40
1.19
0.82
9.14
(1) Amounts expressed on a per unit basis are based on sales volumes.
north america
North America crude oil and NGLs production expense for 2008 increased 22% to $14.96 per bbl from $12.26 per bbl for 2007
(2006 – $11.73 per bbl). The increase in production expense per bbl from 2007 was primarily a result of the higher cost of natural
gas for fuel for the Company’s thermal operations and increased property tax and power costs. The increase was also a result of
the impact of lower production volumes on the fixed cost portion of production costs.
North America natural gas production expense for 2008 increased 11% to $1.00 per mcf from $0.90 per mcf for 2007 (2006 –
$0.81 per mcf). The increase in production expense per mcf from 2007 was primarily a result of the Company’s strategic reduction
in natural gas drilling activity, decreasing natural gas production throughout 2008 and increasing production expense per mcf on
the fixed cost portion of production costs.
Production expense per boe for 2009 is anticipated to increase as a result of an overall reduction in budgeted volumes for 2009,
while fixed costs, such as property taxes and lease rentals, are forecasted to continue to escalate.
north Sea
North Sea crude oil production expense increased on a per barrel basis from 2007 primarily due to lower production volumes on a
relatively fixed operating cost base as well as due to higher planned maintenance costs.
offshore West africa
Offshore West Africa crude oil production expense increased on a per barrel basis from 2007 primarily due to lower production
volumes on a relatively fixed operating cost base.
miDstream
($ millions)
Revenue
Production expense
Midstream cash flow
Depreciation
Segment earnings before taxes
2008
2007
2006
$
$
77 $
25
52
8
74 $
22
52
8
44 $
44 $
72
23
49
8
41
The Company’s midstream assets consist of three crude oil pipeline systems and a 50% working interest in an 84-megawatt
cogeneration plant at Primrose. Approximately 80% of the Company’s heavy crude oil production is transported to international
mainline liquid pipelines via the 100% owned and operated ECHO Pipeline, the 62% owned and operated Pelican Lake Pipeline
and the 15% owned Cold Lake Pipeline. The midstream pipeline assets allow the Company to control the transport of its own
production volumes as well as earn third party revenue. This transportation control enhances the Company’s ability to manage the
full range of costs associated with the development and marketing of its heavier crude oil.
CA NA DIAN NATURAL
51
Depletion, DepreCiation anD amortization (1)
($ millions, except per boe amounts) (2)
North America (3)
North Sea
Offshore West Africa
Expense
$/boe
(1) DD&A excludes depreciation on midstream assets.
(2) Amounts expressed on a per unit basis are based on sales volumes.
(3) Amounts include the impact of intersegment eliminations.
2008
2007
$
$
$
2,226 $
317
132
2,675 $
12.97 $
2,350 $
340
165
2,855 $
12.84 $
2006
1,897
297
189
2,383
11.27
Depletion, Depreciation and Amortization (“DD&A”) expense for 2008 decreased 6% to $2,675 million from $2,855 million for
2007 (2006 – $2,383 million), primarily due to the impact of lower sales volumes.
asset retirement oBligation aCCretion
($ millions, except per boe amounts) (1)
North America
North Sea
Offshore West Africa
Expense
$/boe
2008
2007
$
$
$
42 $
27
2
71 $
0.34 $
38 $
30
2
70 $
0.32 $
2006
35
31
2
68
0.32
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due
to the passage of time. Accretion expense in 2008 was comparable to 2007.
aDministration eXpense
($ millions, except per boe amounts) (1)
Expense
$/boe
(1) Amounts expressed on a per unit basis are based on sales volumes.
2008
2007
$
$
180 $
0.87 $
208 $
0.93 $
2006
180
0.85
Administration expense for 2008 decreased from 2007 primarily due to decreased staffing costs, including costs related to the
Company’s share bonus program, as well as due to decreased office lease costs.
stoCK-BaseD Compensation
($ millions)
(Recovery) expense
2008
2007
$
(52) $
193 $
2006
139
The Company’s Stock Option Plan (the “Option Plan”) provides current employees (the “option holders”) with the right to elect
to receive common shares or a direct cash payment in exchange for options surrendered. The design of the Option Plan balances
the need for a long-term compensation program to retain employees with the benefits of reducing the impact of dilution on
current Shareholders and the reporting of the obligations associated with stock options. Transparency of the cost of the Option
Plan is increased as changes in the intrinsic value of outstanding stock options are recognized each period. The cash payment
feature provides option holders with substantially the same benefits and allows them to realize the value of their options through
a simplified administration process.
The Company recorded a $52 million ($38 million after-tax) stock-based compensation recovery during 2008 due to a 33% decrease
in the Company’s share price for the year ended December 31, 2008 (December 31, 2008 – C$48.75; December 31, 2007 –
C$72.58; December 31, 2006 – C$62.15; December 31, 2005 – C$57.63), offset by the impact of normal course graded vesting of
options granted in prior periods and the impact of vested options exercised or surrendered during the year. As required by Canadian
GAAP, the Company records a liability for potential cash payments to settle its outstanding employee stock options each reporting
period based on the difference between the exercise price of the stock options and the market price of the Company’s common
shares, pursuant to a graded vesting schedule. The liability is revalued at each reporting date to reflect changes in the market price
of the Company’s common shares and the options exercised or surrendered in the year, with the net change recognized in net
earnings, or capitalized during the construction period in the case of the Horizon Project. For the year ended December 31, 2008,
the Company recorded a $23 million recovery on previously capitalized stock-based compensation on the Horizon Project (2007 –
$58 million capitalized; 2006 – $79 million capitalized).
The stock-based compensation liability reflected the Company’s potential cash liability should all the vested options be surrendered
for a cash payout at the market price on December 31, 2008. In periods when substantial stock price changes occur, the Company’s
earnings are subject to significant volatility. The Company utilizes its stock-based compensation plan to attract and retain employees
in a competitive environment. All employees participate in this plan.
52
CANAD IA N NATU RAL
For the year ended December 31, 2008, the Company paid $207 million for stock options surrendered for cash settlement (2007
– $375 million; 2006 – $264 million).
interest eXpense
($ millions, except per boe amounts and interest rates) (1)
Expense, gross
Less: capitalized interest, Horizon Project
Expense, net
$/boe
Average effective interest rate
2008
2007
$
$
$
609 $
481
128 $
0.62 $
5.1%
632 $
356
276 $
1.24 $
5.5%
2006
336
196
140
0.66
5.7%
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest expense and the Company’s average effective interest rate decreased from 2007 primarily due to a decrease in short
term borrowing rates during the last half of 2008 and the impact of the stronger Canadian dollar during the first half of 2008.
On commencement of operations of Phase 1 of the Horizon Project, interest capitalization will cease on this Phase and interest
expense will increase accordingly.
risK management aCtivities
The Company utilizes various derivative financial instruments to manage its commodity price, currency and interest rate exposures.
The Company’s risk management program is not used for speculative purposes.
($ millions)
Crude oil and NGLs financial instruments
Natural gas financial instruments
Foreign currency contracts
realized loss
Crude oil and NGLs financial instruments
Natural gas financial instruments
Foreign currency contracts
Unrealized (gain) loss
net (gain) loss
2008
2007
$
$
$
$
$
2,020 $
(21)
(139)
1,860 $
(3,104) $
16
(2)
(3,090) $
(1,230) $
505 $
(343)
–
162 $
1,244 $
156
–
1,400 $
1,562 $
2006
1,395
(70)
–
1,325
(736)
(260)
(17)
(1,013)
312
The net realized loss (gain) from crude oil and natural gas financial instruments would have decreased (increased) the Company’s
average realized prices as follows:
Crude oil and NGLs ($/bbl) (1)
Natural gas ($/mcf) (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2008
17.45 $
(0.04) $
$
$
2007
4.18 $
(0.56) $
2006
11.57
(0.13)
Complete details related to outstanding derivative financial instruments at December 31, 2008 are disclosed in note 13 to the
Company’s consolidated financial statements.
The commodity derivative financial instruments currently outstanding have not been designated as hedges for accounting purposes
(the “non-designated hedges”). The fair value of these non-designated hedges is based on prevailing forward commodity prices
in effect at the end of each reporting period and is reflected in risk management activities in consolidated net earnings. The cash
settlement amount of the commodity derivative financial instruments may vary materially depending upon the underlying crude oil
and natural gas prices at the time of final settlement, as compared to their mark-to-market value at December 31, 2008.
Due to changes in crude oil and natural gas forward pricing and the reversal of prior period unrealized gains and losses, the
Company recorded a net unrealized gain of $3,090 million ($2,112 million after-tax) on its risk management activities for the year
ended December 31, 2008 (2007 – $1,400 million unrealized loss, $977 million after-tax; 2006 – $1,013 million unrealized gain,
$674 million after-tax).
foreign eXChange
($ millions)
Net realized (gain) loss
Net unrealized loss (gain) (1)
net loss (gain)
(1) Amounts are reported net of the effect of cross currency swap hedges.
2008
2007
2006
$
$
(114) $
832
718 $
53 $
(524)
(471) $
(12)
134
122
CA NA DIAN NATURAL
53
The Company’s North Sea operations are classified as self-sustaining for the purposes of foreign currency translation. The North
Sea operations are initially measured in US dollars and then translated to Canadian dollars using the current rate method, whereby
assets and liabilities are translated into Canadian dollars using the exchange rate in effect at the balance sheet date, while revenue
and expenses are translated into Canadian dollars using the monthly average exchange rate. Foreign currency gains or losses
arising on the translation of non-US dollar monetary assets and liabilities are included in net earnings while subsequent gains or
losses arising on translation to Canadian dollars are deferred and included in accumulated other comprehensive income.
During 2008, the Company determined that its operations in Offshore West Africa were now operationally and financially
independent and the current rate method of translation was prospectively adopted for translation of the financial statements
of the Offshore West African subsidiaries as at December 31, 2008. Prior to this determination, the Company’s Offshore West
Africa foreign operations were classified as integrated for the purposes of foreign currency translation, and accordingly, Offshore
West Africa foreign operations and foreign currency transactions and balances held in North America were directly translated into
Canadian dollars using the temporal method. All related foreign exchange gains or losses were included in net earnings.
As a result of foreign currency translation, the Company’s operating results are affected by the fluctuations in the exchange rates
between the Canadian dollar, US dollar, and UK pound sterling. A majority of the Company’s revenue is based on reference to US
dollar benchmark prices. An increase in the value of the Canadian dollar in relation to the US dollar results in decreased revenue
from the sale of the Company’s production. Conversely a decrease in the value of the Canadian dollar in relation to the US dollar
results in increased revenue from the sale of the Company’s production. Production expenses and future income tax liabilities in
the North Sea are subject to foreign currency fluctuations due to changes in the exchange rate of the UK pound sterling to the US
dollar. The value of the Company’s US dollar denominated debt is also impacted by the value of the Canadian dollar in relation to
the US dollar.
The net unrealized foreign exchange loss in 2008 was primarily related to the weakening of the Canadian dollar in relation to
the US dollar with respect to the US dollar denominated debt, partially offset by the impact of the re-measurement of North Sea
future income tax liabilities denominated in UK pounds sterling to US dollars. Included in the net unrealized loss for the year ended
December 31, 2008 was an unrealized gain of $449 million related to the impact of cross currency swap hedges. The net realized
foreign exchange gain for 2008 was primarily due to the result of foreign exchange rate fluctuations on settlement of working
capital items denominated in US dollars or UK pounds sterling and the repayment of US dollar denominated debt. The Canadian
dollar ended the year at US$0.8166 compared to US$1.0120 at December 31, 2007 (December 31, 2006 – US$0.8581).
taXes
($ millions, except income tax rates)
Current
Deferred
taxes other than income tax
North America
North Sea
Offshore West Africa
Current income tax
future income tax
Income tax rate and other legislative changes (1) (2) (3)
effective income tax rate before income tax rate
and other legislative changes
2008
2007
2006
$
$
$
$
245 $
(67)
178 $
33 $
340
128
501
1,607
2,108
41
2,149 $
121 $
44
165 $
96 $
210
74
380
(456)
(76)
864
788 $
219
37
256
143
30
49
222
652
874
395
1,269
30.3%
31.1%
37.3%
(1) Includes the effects of one time recoveries of $19 million due to British Columbia corporate income tax rate reductions and $22 million due to Côte d’Ivoire
corporate income tax rate reductions substantively enacted or enacted during 2008.
(2) Includes the effect of one time recoveries of $864 million due to Canadian Federal income tax rate reductions and other legislative changes substantively enacted
or enacted during 2007.
(3) Includes the effect of the following:
n
n
n
a one time expense of $110 million related to the increased supplementary charge on oil and gas profits in the UK North Sea enacted in 2006.
a one time recovery of $438 million due to Canadian Federal, Alberta and Saskatchewan corporate income tax rate reductions enacted in 2006.
a one time recovery of $67 million due to Côte d’Ivoire, Offshore West Africa corporate income tax rate reductions enacted in 2006.
Taxes other than income tax primarily includes current and deferred PRT, which is charged on certain fields in the North Sea at the rate
of 50% of net operating income, after allowing for certain deductions including related capital and abandonment expenditures.
Taxable income from the conventional crude oil and natural gas business in Canada is primarily generated through partnerships,
with the related income taxes payable in subsequent periods. North America current income taxes have been provided on the basis
of this corporate structure. In addition, North America and North Sea current income taxes will vary depending on available income
tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year.
For 2009, based on budgeted prices and the current availability of tax pools, the Company expects to incur current income tax
expense in Canada of $20 million to $50 million and in the North Sea of $350 million to $450 million.
54
CANAD IA N NATU RAL
net Capital eXpenDitUres (1)
($ millions)
expenditures on property, plant and equipment
Net property acquisitions (dispositions) (2)
Land acquisition and retention
Seismic evaluations
Well drilling, completion and equipping
Production and related facilities
total net reserve replacement expenditures
Horizon Project:
Phase 1 construction costs
Phase 1 operating and capital inventory
Phase 1 commissioning costs
Phases 2/3 costs
Capitalized interest, stock-based compensation and other
Total Horizon Project (3)
Midstream
Abandonments (4)
Head office
total net capital expenditures
By segment
North America
North Sea
Offshore West Africa
Other
Horizon Project
Midstream
Abandonments (4)
Head office
total
2008
2007
2006
336 $
86
107
1,664
1,282
3,475
2,732
87
277
336
480
3,912
9
38
17
(39) $
95
124
1,642
1,205
3,027
2,740
–
–
124
437
3,301
6
71
20
4,733
210
130
2,340
1,314
8,727
2,768
–
–
79
338
3,185
12
75
26
7,451 $
6,425 $
12,025
2,344 $
319
811
1
3,912
9
38
17
7,451 $
2,428 $
439
159
1
3,301
6
71
20
6,425 $
7,936
646
134
11
3,185
12
75
26
12,025
$
$
$
$
(1) Net capital expenditures exclude adjustments related to differences between carrying value and tax value, and other fair value adjustments.
(2) Includes Business Combinations.
(3) Net expenditures for the Horizon Project also include the impact of intersegment eliminations.
(4) Abandonments represent expenditures to settle ARO and have been reflected as capital expenditures in this table.
The Company’s operating strategy is focused on building a diversified asset base that is balanced among various products. In
order to facilitate efficient operations, the Company concentrates its activities in core regions where it can dominate the land base
and infrastructure. The Company focuses on maintaining its land inventories to enable the continuous exploitation of play types
and geological trends, greatly reducing overall exploration risk. By dominating infrastructure, the Company is able to maximize
utilization of its production facilities, thereby increasing control over production costs.
Net capital expenditures for 2008 were $7,451 million compared to $6,425 million for 2007 (2006 – $12,025 million). Excluding
the ACC acquisition, net capital expenditures were $7,270 million for 2006. Capital expenditures in 2008 primarily reflected the
continued progress on the Company’s larger, future growth projects, most notably the Horizon Project, Primrose East, and Gabon,
offset by the effects of an overall strategic reduction in the North America natural gas drilling program.
During 2008, the Company drilled a total of 1,121 net wells consisting of 269 natural gas wells, 682 crude oil wells, 131 stratigraphic
test and service wells, and 39 wells that were dry. This compared to 1,322 net wells drilled for 2007 (2006 – 1,738 net wells).
The Company achieved an overall success rate of 96% for 2008, excluding the stratigraphic test and service wells (2007 – 91%;
2006 – 91%).
north america
North America, excluding the Horizon Project, accounted for approximately 32% of the total capital expenditures for the year
ended December 31, 2008 compared to approximately 39% for 2007 (2006 – 67%).
During 2008, the Company targeted 280 net natural gas wells, including 27 wells in Northeast British Columbia, 104 wells in the
Northern Plains region, 70 wells in Northwest Alberta, and 79 wells in the Southern Plains region. The Company also targeted
704 net crude oil wells during the year. The majority of these wells were concentrated in the Company’s crude oil Northern Plains
region where 415 primary heavy crude oil wells, 110 Pelican Lake crude oil wells, 74 thermal crude oil wells and 7 light crude oil
wells were drilled. Another 98 wells targeting light crude oil were drilled outside the Northern Plains region.
Due to significant differences in relative commodity prices between crude oil and natural gas throughout most of 2008, the
Company continued to access its large crude oil drilling inventory to maximize value in both the short and long term. Due to the
CA NA DIAN NATURAL
55
Company’s focus on drilling crude oil wells in 2007 and 2008 and as a result of royalty changes under the Alberta NRF, natural gas
drilling activities have been reduced to manage overall capital spending. Deferred natural gas well locations have been retained in
the Company’s prospect inventory.
As part of the phased expansion of its In-Situ Oil Sands Assets, the Company is continuing to develop its Primrose thermal projects.
During 2008, the Company drilled 74 thermal oil wells, 2 water source wells, and 19 stratigraphic test wells and observation wells.
Overall Primrose thermal production for 2008 was approximately 65,000 bbl/d (2007 – 64,000 bbl/d; 2006 – 64,000 bbl/d).
The Primrose East Expansion, a new facility located 15 kilometers from the existing Primrose South steam plant and 25 kilometers
from the Wolf Lake central processing facility, was completed and first steaming commenced in September 2008, with first
production achieved in the fourth quarter of 2008. Subsequent to December 31, 2008, operational issues on one of the pads has
caused steaming to cease on all well pads in the Primrose East project area and the Company is working on rectifying the issues.
The next planned phase of the Company’s In-Situ Oil Sands Assets expansion is the Kirby project located 120 kilometers north of
the existing Primrose facilities. During 2007, the Company filed a combined application and Environmental Impact Assessment for
this project with Alberta Environment and the Alberta Energy and Utilities Board. Final corporate sanction and project scope will
be impacted by environmental regulations and their associated costs. Subject to regulatory approval, crude oil pricing, and capital
costs, the Company may proceed with the detailed engineering and design work.
Development of new pads and secondary recovery conversion projects at Pelican Lake continued as expected throughout 2008.
Drilling consisted of 110 horizontal crude oil wells, with plans to drill 58 additional horizontal crude oil wells in 2009. The response
from the water and polymer flood projects continues to be positive. Pelican Lake production averaged approximately 37,000 bbl/d
in 2008 (2007 – 34,000 bbl/d; 2006 – 30,000 bbl/d).
For 2009, the Company’s overall drilling activity in North America is expected to comprise approximately 142 natural gas wells and
465 crude oil wells, excluding stratigraphic and service wells.
Horizon project
The Company continued the construction, commissioning and staged start up of the Horizon Project, with first production of
synthetic crude oil from Phase 1 achieved February 28, 2009, representing a major milestone. Currently, the Company is filling all
product tanks in preparation for blending and pipeline shipment.
All major components have been completed and are fully operational, with the exception of the Distillate Hydrotreating Plant
(Plant 42). The Naphtha and Gas Oil Hydrotreaters (Plants 41 and 43 respectively) are fully operational and currently capable of
producing approximately 55,000 bbl/d. Upon completion of Plant 42, the focus will be on reaching full production capacity of
110,000 bbl/d. Plant 42 has now been turned over to operations for commissioning and is targeted to be operational by the end
of April 2009, subject to any unforeseen start up issues.
During the initial stages of the ramp-up of production, the production volumes will fluctuate on a weekly basis until the end of the second
quarter of 2009 when the Company expects to see a steady ramp up to full production by the end of 2009. The Company will work
towards full capacity throughout 2009 as the plant continues to be fine tuned to design rates with a focus on safety and reliability.
Phase 1 of the Horizon Project was designed, engineered, and constructed in an extremely volatile and inflationary business
environment with final construction costs totaling approximately $9.7 billion. Subsequent planned expansion through Phases 2/3,
further broken down into a series of four Tranches, are being reprofiled with the goal of attaining better cost management.
north Sea
In 2008, the Company continued with its planned program of infill drilling, recompletions, workovers and waterflood optimizations.
During 2008, 4.1 net wells were drilled, including 0.9 net water injectors, with an additional 1.2 net wells drilling at year end.
Specifically, two production wells were completed at Murchison and one production well was completed at Ninian, with an
additional production well in progress at Ninian at year end. The Company also delivered one water injection well at Ninian and
further increased volumes injected into the Ninian reservoir.
The Company continued with its planned investment in its long-term facilities and infrastructure strategy and successfully carried
out maintenance turnarounds at all five installations during the year. Within the Murchison turnaround the Company successfully
implemented a new control system, which has resulted in improved platform uptime.
offshore West africa
During 2008, 4.1 net wells were drilled with 0.9 net wells drilling at year end.
Development drilling on West Espoir was completed in early 2008, on budget and on time. At the Baobab Field, the Company
delivered three new wells from the drilling program, with a fourth well due to be completed in the second quarter of 2009.
At the 90% owned and operated Olowi Field in offshore Gabon, the Conductor Supported Platform was installed, construction
was completed on the FPSO, which arrived on location in February 2009, and construction continued on the wellhead towers and
subsea facilities. First crude oil is targeted for late in the first quarter or early in the second quarter of 2009.
56
CANAD IA N NATU RAL
liQUiDitY anD Capital resoUrCes
($ millions, except ratios)
Working capital (deficit) (1)
Long-term debt (2) (3)
shareholders’ equity
Share capital
Retained earnings
Accumulated other comprehensive income (loss)
Total
Debt to book capitalization (3) (4)
Debt to market capitalization (3) (5)
After tax return on average common shareholders’ equity (6)
After tax return on average capital employed (3) (7)
$
$
$
2008
2007
392 $
13,016 $
(1,382) $
10,940 $
2,768 $
2,674 $
15,344
262
10,575
72
2006
(832)
11,043
2,562
8,141
(13)
$
18,374 $
13,321 $
10,690
41%
33%
33%
19%
45%
22%
22%
12%
51%
25%
27%
17%
(1) Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
(2) Includes the current portion of long-term debt (2008 – $420 million; 2007 and 2006 – $nil).
(3) Long-term debt at December 31, 2008 and 2007 is stated at its carrying value, net of fair value adjustments, original issue discounts and transaction costs. Amounts
for 2006 were not adjusted for these items.
(4) Calculated as current and long-term debt; divided by the book value of common shareholders’ equity plus current and long-term debt.
(5) Calculated as current and long-term debt; divided by the market value of common shareholders’ equity plus current and long-term debt.
(6) Calculated as net earnings for the year; as a percentage of average common shareholders’ equity for the year.
(7)
Calculated as net earnings plus after-tax interest expense for the year; as a percentage of average capital employed. Average capital employed is the average
shareholders’ equity and current and long-term debt for the year, including $10,678 million in average capital employed related to the Horizon Project (2007 –
$7,001 million; 2006 – $3,760 million).
At December 31, 2008, the Company’s capital resources consisted primarily of cash flow from operations, available bank credit facilities
and access to debt capital markets. Cash flow from operations is dependent on factors discussed in the “Risks and Uncertainties”
section of this MD&A. The Company’s ability to renew existing bank credit facilities and raise new debt is also dependent upon these
factors, as well as maintaining an investment grade debt rating and the condition of capital and credit markets.
The ongoing worldwide financial and economic events have resulted in a significant tightening of the availability and cost of new
sources of liquidity including bank credit facilities and funds derived from debt capital markets. In light of these credit challenges,
the Company has undertaken a thorough review of its liquidity sources as well as its exposure to counterparties and has concluded
that its capital resources are sufficient to meet ongoing short-, medium- and long-term commitments. Specifically, the Company
continues to believe that its internally generated cash flow from operations supported by the implementation of its hedge policy,
the flexibility of its capital expenditure programs supported by its multi-year financial plans, its existing bank credit facilities and
its ability to raise new debt on commercially acceptable terms, will provide sufficient liquidity to sustain its operations in the short,
medium and long term and support its growth strategy. Further, the Company believes that its counterparties currently have the
financial capacity to settle outstanding obligations in the normal course of business.
On an ongoing basis, the Company continues to focus on the following areas:
n Monitoring cash flow from operations, which is the primary source of funds;
n
n
n
n
n
Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant
packages;
Monitoring credit markets, governments, world banks and the Company’s bank syndicates to identify associated risks and
exposures;
Maintaining an active commodity risk management program that manages exposure to crude oil and natural gas price volatility.
The Company believes this is an effective tool to manage short- and medium-term changes in spot commodity prices. The
Company also monitors its commodity risk management counterparties to ensure they are in position to settle obligations
within the contractually agreed terms of settlement;
Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when
appropriate, ensuring parental guarantees or letters of credit are in place to minimize the impact in the event of default; and
Monitoring the Company’s 2009 capital and operating plans to provide the required flexibility to deal with commodity price
volatility, commitments in respect of capital and operating expenditures, and commitments to retire its non-revolving bank
credit facility maturing in October 2009. The Company actively manages the allocation of maintenance and growth capital
to ensure it is expended in a prudent and appropriate manner. The Company continued the construction, commissioning and
staged start up of the Horizon Project, with first production of synthetic crude oil from Phase 1 achieved February 28, 2009.
At December 31, 2008, the Company had $2,082 million of available credit under its bank credit facilities, which together with
cash flow from operating activities to be generated in 2009 supported by its commodity risk management program and the ability
to actively manage the capital expenditure programs, is forecasted to be sufficient to repay the $2,350 million non-revolving bank
credit facility maturing October 2009. Further, the Company’s current debt ratings are BBB (high) with a negative trend by DBRS
Limited, Baa2 with a stable outlook by Moody’s Investors Service and BBB with a stable outlook by Standard & Poor’s.
CA NA DIAN NATURAL
57
Further details related to the Company’s long-term debt at December 31, 2008 are discussed below and in note 5 to the Company’s
audited annual consolidated financial statements.
At December 31, 2008, the Company’s working capital was $392 million, excluding the current portion of long-term debt and
including both the current portion of the net mark-to-market asset for risk management derivative financial instruments of
$1,851 million and the current portion of the stock-based compensation liability of $159 million, together with related future
income tax liabilities of $585 million. The cash settlement amount of the risk management derivative financial instruments may
vary materially depending upon the underlying crude oil and natural gas prices at the time of final settlement, as compared to their
mark-to-market value at December 31, 2008. The settlement of the stock-based compensation liability is dependant upon both
the surrender of vested stock options for cash settlement by employees and the value of the Company’s share price at the time
of surrender.
Long-term debt was $13,016 million at December 31, 2008, resulting in a debt to book capitalization level of 41% as at December 31,
2008 (December 31, 2007 – 45%; December 31, 2006 – 51%). This ratio is near the midpoint of the 35% to 45% range targeted
by management, including the impact of capital spending on the Horizon Project. The Company remains committed to maintaining
a strong balance sheet and flexible capital structure. The Company has hedged a portion of its crude oil and natural gas production
for 2009 and 2010 at prices that protect investment returns to ensure ongoing balance sheet strength and the completion of its
capital expenditure programs. In the future, the Company may also consider the divestiture of certain non-strategic and non-core
properties to gain additional balance sheet flexibility.
The Company’s commodity hedging program reduces the risk of volatility in commodity prices and supports the Company’s cash
flow for its capital expenditures programs. This program currently allows for the hedging of up to 60% of the near 12 months
budgeted production and up to 40% of the following 13 to 24 months estimated production. For the purpose of this program,
the purchase of crude oil put options is in addition to the above parameters. As at December 31, 2008, in accordance with the
policy, approximately 6% of budgeted crude oil volumes were hedged using collars for 2009 and approximately 33% of budgeted
natural gas volumes were hedged for the first quarter of 2009. In addition, 92,000 bbl/d of crude oil volumes are protected by put
options for 2009 at a strike price of US$100.00 per bbl.
The Company had the following net commodity derivative financial instruments outstanding as at December 31, 2008:
remaining term
volume
Weighted average price
index
Crude oil
Crude oil price collars
Crude oil puts
natural gas
Natural gas price collars (1)
Jan 2009 – Dec 2009
Apr 2009 – Jun 2009
Jan 2009 – Dec 2009
25,000 bbl/d
4,000 bbl/d
92,000 bbl/d
US$70.00 – US$111.56
US$70.00 – US$90.00
US$100.00
WTI
WTI
WTI
Jan 2009 – Mar 2009
500,000 GJ/d
C$6.00 – C$8.63
AECO
(1) Subsequent to December 31, 2008, the Company entered into 220,000 GJ/d of C$6.00 – C$8.00 natural gas AECO collars for the period January to December 2010.
The Company’s outstanding commodity derivative financial instruments are expected to be settled monthly based on the applicable
index pricing for the respective contract month.
In addition to the financial derivatives noted above, subsequent to December 31, 2008, the Company entered into natural gas physical
sales contracts for 400,000 GJ/d at an average fixed price of C$5.29 per GJ at AECO for the period April to December 2009.
long-term DeBt
The Company’s long-term debt of $13,016 million at December 31, 2008 was comprised of drawings under its bank credit facilities
and debt issuances under medium and long-term unsecured notes.
Bank credit Facilities
As at December 31, 2008, the Company had in place unsecured bank credit facilities of $6,232 million, comprised of:
n a $125 million demand credit facility;
n a non-revolving syndicated credit facility of $2,350 million maturing October 2009, as discussed below;
n a revolving syndicated credit facility of $2,230 million maturing June 2012;
n a revolving syndicated credit facility of $1,500 million maturing June 2012; and
n a £15 million demand credit facility related to the Company’s North Sea operations.
During 2007, one of the revolving syndicated credit facilities was increased from $1,825 million to $2,230 million and a $500 million
demand credit facility was terminated. The revolving syndicated credit facilities were also extended and now mature June 2012. Both
facilities are extendible annually for one year periods at the mutual agreement of the Company and the lenders. If the facilities are not
extended, the full amount of the outstanding principal would be repayable on the maturity date. Borrowings under these facilities can
be made by way of Canadian dollar and US dollar bankers’ acceptances, and LIBOR, US base rate and Canadian prime loans.
58
CANAD IA N NATU RAL
In conjunction with the closing of the acquisition of ACC in November 2006, the Company executed a $3,850 million, non-revolving
syndicated credit facility maturing October 2009. In March 2007, $1,500 million was repaid, reducing the facility to $2,350 million.
During 2009, the Company plans to fully retire this facility from its existing borrowing capacity under its other long-term bank
credit facilities, which were $2,050 million at December 31, 2008, supported by cash flow from operating activities, including
the commodity risk management activities. In accordance with these plans, and repayments of $420 million made subsequent to
December 31, 2008 on this facility, $420 million has been classified as current.
In addition to the outstanding debt, letters of credit and financial guarantees aggregating $372 million, including $300 million
related to the Horizon Project, were outstanding at December 31, 2008.
Medium-term notes
The Company has $2,600 million remaining on its outstanding $3,000 million base shelf prospectus filed in September 2007 that
allows for the issue of medium-term notes in Canada until October 2009. If issued, these securities will bear interest as determined
at the date of issuance.
In December 2007, the Company issued $400 million of unsecured notes maturing December 2010, bearing interest at 5.50%.
Proceeds from the securities issued were used to repay bankers’ acceptances under the Company’s bank credit facilities.
During 2007, $125 million of the 7.40% unsecured debentures due March 1, 2007 were repaid.
Senior unsecured notes
The adjustable rate senior unsecured notes bear interest at 6.54%, with the final annual principal repayment of US$31 million due
in May 2009. During 2008 and 2007, US$31 million of the senior unsecured notes were repaid each year.
uS dollar debt Securities
In January 2008, the Company issued US$1,200 million of unsecured notes under a US base shelf prospectus, comprised of
US$400 million of 5.15% unsecured notes due February 2013, US$400 million of 5.90% unsecured notes due February 2018, and
US$400 million of 6.75% unsecured notes due February 2039. Proceeds from the securities issued were used to repay bankers’
acceptances under the Company’s bank credit facilities. After issuing these securities, the Company has US$1,800 million remaining
on its outstanding US$3,000 million base shelf prospectus filed in September 2007 that allows for the issue of US dollar debt securities
in the United States until October 2009. If issued, these securities will bear interest as determined at the date of issuance.
During 2008, US$8 million of US dollar debt securities were repaid.
In March 2007, the Company issued US$2,200 million of unsecured notes, comprised of US$1,100 million of unsecured notes
maturing May 2017 and US$1,100 million of unsecured notes maturing March 2038, bearing interest at 5.70% and 6.25%,
respectively. Concurrently, the Company entered into cross currency swaps to fix the Canadian dollar interest and principal repayment
amounts on the entire US$1,100 million of unsecured notes due May 2017 at 5.10% and C$1,287 million. The Company also
entered into a cross currency swap to fix the Canadian dollar interest and principal repayment amounts on US$550 million of
unsecured notes due March 2038 at 5.76% and C$644 million. Proceeds from the securities issued were used to repay bankers’
acceptances under the Company’s bank credit facilities.
During 2008, the Company terminated the interest rate swaps that had been designated as a fair value hedge of US$350 million
of 5.45% unsecured notes due October 2012. Accordingly, the Company ceased revaluing the related debt from the date of
termination of the interest rate swaps for subsequent changes in fair value. The fair value adjustment of $20 million at the date of
termination is being amortized to interest expense over the remaining term of the debt.
During 2007, The Company de-designated the portion of the US dollar denominated debt previously hedged against its net
investment in US dollar based self-sustaining foreign operations. Accordingly, all foreign exchange (gains) losses arising each period
on US dollar denominated long-term debt are now recognized in the consolidated statements of earnings.
share Capital
As at December 31, 2008, there were 540,991,000 common shares outstanding and 30,962,000 stock options outstanding. As at
March 3, 2009, the Company had 541,149,000 common shares outstanding and 30,285,000 stock options outstanding.
The Company did not renew the Normal Course Issuer Bid during 2008. During 2007 and 2008, the Company did not purchase
any common shares for cancellation (2006 – 485,000 common shares were purchased at an average price of $57.33 per common
share for a total cost of $28 million).
In March 2009, the Company’s Board of Directors approved an increase in the annual dividend paid by the Company to $0.42
per common share for 2009. The increase represents a 5% increase from the prior year. The dividend policy undergoes a periodic
review by the Board of Directors and is subject to change. In February 2008, an increase in the annual dividend paid by the
Company was approved to $0.40 per common share for 2008. The increase represented an 18% increase from 2007.
CA NA DIAN NATURAL
59
Commitments anD off BalanCe sheet arrangements
In the normal course of business, the Company has entered into various commitments that will have an impact on the Company’s future
operations. These commitments primarily relate to firm commitments for gathering, processing and transmission services; operating
leases relating to offshore FPSOs, drilling rigs and office space; expenditures relating to ARO; as well as long-term debt and interest
payments. As at December 31, 2008, no entities were consolidated under CICA Handbook Accounting Guideline 15, “Consolidation
of Variable Interest Entities”. The following table summarizes the Company’s commitments as at December 31, 2008:
($ millions)
2009
2010
2011
2012
2013
Thereafter
Product transportation
and pipeline
Offshore equipment
operating lease
Offshore drilling
Asset retirement obligations (1)
Long-term debt (2)
Interest expense (3)
Office lease
Other
$
219 $
184 $
159 $
133 $
124 $
1,175
$
$
$
$
$
$
$
175 $
251 $
6 $
2,385 $
610 $
25 $
321 $
145 $
62 $
7 $
400 $
565 $
29 $
180 $
144 $
– $
6 $
490 $
543 $
23 $
17 $
116 $
– $
6 $
429 $
490 $
2 $
12 $
117 $
– $
6 $
890 $
428 $
2 $
8 $
398
–
4,443
6,707
5,992
1
19
(1)
(2)
(3)
Amounts represent management’s estimate of the future undiscounted payments to settle ARO related to resource properties, facilities, and production platforms,
based on current legislation and industry operating practices. Amounts disclosed for the period 2009 – 2013 represent the minimum required expenditures to meet
these obligations. Actual expenditures in any particular year may exceed these minimum amounts.
The long-term debt represents principal repayments only and does not reflect fair value adjustments, original issue discounts or transaction costs. No debt repayments
are reflected for $1,725 million of revolving bank credit facilities due to the extendable nature of the facilities.
Interest expense amounts represent the scheduled fixed rate and variable rate cash payments related to long-term debt. Interest on variable rate long-term debt was
estimated based upon prevailing interest rates as of December 31, 2008.
legal proCeeDings
The Company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. In addition,
the Company is subject to certain contractor construction claims related to the Horizon Project. The Company believes that any
liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position.
reserves
For the year ended December 31, 2008, the Company retained a qualified independent reserves evaluator, Sproule Associates
Limited (“Sproule”), to evaluate 100% of the Company’s conventional proved, as well as proved and probable crude oil, NGLs
and natural gas reserves(1) and prepare Evaluation Reports on these reserves. The Company has been granted an exemption from
certain of the provisions of National Instrument 51-101 – “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”), which
prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. This
exemption allows the Company to substitute SEC requirements for certain disclosures required under NI 51-101. There are three
principal differences between the two standards. The first is the requirement under NI 51-101 to disclose both proved and proved and
probable reserves, as well as the related net present value of future net revenues using forecast prices and costs. The second is in the
definition of proved reserves; however, as discussed in the Canadian Oil and Gas Evaluation Handbook (“COGEH”), the standards that
NI 51-101 employs, the difference in estimated proved reserves based on constant pricing and costs between the two standards
is not material. The third is the requirement to disclose a gross reserve reconciliation (before the consideration of royalties).
The Company discloses its conventional crude oil, NGLs and natural gas reserve reconciliations net of royalties in adherence to
SEC requirements.
The Company annually discloses proved conventional reserves and the standardized measure of discounted future net cash flows
using year end constant prices and costs as mandated by the SEC in the supplementary oil and gas information section of the
Company’s Annual Report and in its annual Form 40-F filing with the SEC. The Company has elected to provide the net present
value(2) of these same conventional proved reserves as well as its conventional proved and probable reserves and the net present
value of these reserves under the same parameters as additional voluntary information. The Company has also elected to provide
both proved and proved and probable conventional reserves and the net present value of these reserves using forecast prices and
costs as additional voluntary information, which is disclosed in the Company’s Annual Information Form.
(1) Conventional crude oil, NGLs and natural gas reserves include all of the Company’s light/medium, primary heavy, and thermal crude oil, natural gas, coal bed
(2)
methane and NGLs reserves. They do not include the Company’s oil sands mining reserves.
Net present values of conventional reserves are based upon discounted cash flows prior to the consideration of income taxes and existing asset abandonment liabilities.
Future development costs and associated material well abandonment liabilities have been applied.
60
CANAD IA N NATU RAL
The following tables summarize the Company’s proved conventional crude oil and natural gas reserves, net of royalties, as at
December 31, 2008 and 2007:
Crude oil and ngls (mmbbl)
Net conventional proved reserves
Reserves, December 31, 2007
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Economic revisions due to prices
Revisions of prior estimates
reserves, December 31, 2008
north
america
north
offshore
sea West africa
920
51
17
–
–
(76)
28
8
948
310
–
6
–
–
(17)
(81)
38
256
128
–
4
–
–
(8)
8
10
142
total
1,358
51
27
–
–
(101)
(45)
56
1,346
The Company’s net proved conventional crude oil reserves at December 31, 2008 totaled 1,346 mmbbl. Approximately 88% of
production was replaced by reserve additions during 2008. Extensions and discoveries resulting from exploration and development
activities amounted to 51 mmbbl, while net positive revisions amounted to 11 mmbbl.
natural gas (bcf)
Net conventional proved reserves
Reserves, December 31, 2007
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Economic revisions due to prices
Revisions of prior estimates
reserves, December 31, 2008
north
america
north
offshore
sea West africa
3,521
140
52
77
(1)
(449)
(19)
202
3,523
81
–
(1)
–
–
(4)
(56)
47
67
64
–
6
–
–
(4)
6
22
94
total
3,666
140
57
77
(1)
(457)
(69)
271
3,684
The Company’s net proved conventional natural gas reserves at December 31, 2008 totaled 3,684 bcf. Approximately 104% of
production was replaced by reserve additions during 2008. Extensions and discoveries resulting from exploration and development
activities amounted to 140 bcf, while net positive revisions amounted to 202 bcf.
For the year ended December 31, 2008, the Company retained a qualified independent reserves evaluator, GLJ Petroleum
Consultants Ltd. (“GLJ”), to evaluate Phase 1 to Phase 3 of the Company’s Horizon Project and prepare an Evaluation Report on
the Company’s proved, as well as proved and probable oil sands mining reserves. These reserves were evaluated adhering to the
requirements of SEC Industry Guide 7 using year end constant pricing and have been disclosed separately from the Company’s
conventional proved and proved and probable crude oil, NGLs and natural gas reserves.
synthetic crude oil reserves (1)
Net reserves, after royalties (mmbbl)
Proved
Proved and probable
2008
1,946
2,944
2007
1,761
2,680
(1) SCO reserves are based on the upgrading of bitumen using technologies implemented at the Horizon Project.
The net proved SCO reserves increased by 185 mmbbl, while net proved and probable SCO reserves increased by 264 mmbbl. The
increases are primarily due to a low constant dollar crude oil price, deferring project payout and thereby reducing royalties paid.
The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures
with each of Sproule and GLJ to review the qualifications of and procedures used by each evaluator in determining the estimate of
the Company’s quantities and net present value of remaining conventional crude oil, NGLs and natural gas reserves as well as the
Company’s quantity of oil sands mining reserves.
CA NA DIAN NATURAL
61
risKs anD UnCertainties
The Company is exposed to various operational risks inherent in exploring, developing, producing and marketing crude oil and natural
gas and the mining and upgrading of bitumen into SCO. These inherent risks include, but are not limited to, the following items:
n
Economic risk of finding, producing and replacing reserves at a reasonable cost, including the risk of reserve revisions due
to economic and technical factors. Reserve revisions can have a positive or negative impact on asset valuations, ARO and
depletion rates;
Prevailing prices of crude oil and natural gas;
Regulatory risk related to approval for exploration and development activities, which can add to costs or cause delays in
projects;
Labour risk associated with securing the manpower necessary to complete capital projects in a timely and cost effective
manner;
Operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas;
Success of exploration and development activities;
Timing and success of integrating the business and operations of acquired companies;
Credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts;
Interest rate risk associated with the Company’s ability to secure financing on commercially acceptable terms;
Foreign exchange risk due to fluctuating exchange rates on the Company’s US dollar denominated debt and as the majority of
sales are based in US dollars;
Environmental impact risk associated with exploration and development activities, including GHG;
Risk of catastrophic loss due to fire, explosion or acts of nature;
Geopolitical risks associated with changing governmental policies, social instability and other political, economic or diplomatic
developments in the Company’s operations; and
Other circumstances affecting revenue and expenses.
n
n
n
n
n
n
n
n
n
n
n
n
n
The Company uses a variety of means to help mitigate and/or minimize these risks. The Company maintains a comprehensive
property loss and business interruption insurance program to reduce risk to an acceptable level. Operational control is enhanced
by focusing efforts on large core areas with high working interests and by assuming operatorship of key facilities. Product mix is
diversified, consisting of the production of natural gas and the production of crude oil of various grades. The Company believes
this diversification reduces price risk when compared with over-leverage to one commodity. Accounts receivable from the sale of
crude oil and natural gas are mainly with customers in the crude oil and natural gas industry and are subject to normal industry
credit risks. The Company manages these risks by reviewing its exposure to individual companies on a regular basis and where
appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default.
Substantially all of the Company’s accounts receivables are due within normal trade terms. Derivative financial instruments are
utilized to help ensure targets are met and to manage commodity prices, foreign currency rates and interest rate exposure. The
Company is exposed to possible losses in the event of nonperformance by counterparties to derivative financial instruments;
however, the Company manages this credit risk by entering into agreements with substantially all investment grade financial
institutions and other entities. The arrangements and policies concerning the Company’s financial instruments are under constant
review and may change depending upon the prevailing market conditions.
The Company’s capital structure mix is also monitored on a continual basis to ensure that it optimizes flexibility, minimizes cost
and offers the greatest opportunity for growth. This includes the determination of a reasonable level of debt and any interest rate
exposure risk that may exist.
For additional detail regarding the Company’s risks and uncertainties, refer to the Company’s Annual Information Form.
environment
The crude oil and natural gas industry is experiencing incremental increases in costs related to environmental regulation, particularly
in North America and the North Sea. Existing and expected legislation and regulations will require the Company to address and
mitigate the effect of its activities on the environment. Increasingly stringent laws and regulations may have an adverse effect on
the Company’s future net earnings and cash flow from operations.
The Company’s associated risk management strategies focus on working with legislators and regulators to ensure that any new or
revised policies, legislation or regulations properly reflect a balanced approach to sustainable development. Specific measures in response
to existing or new legislation include a focus on the Company’s energy efficiency, air emissions management, released water quality,
reduced fresh water use and the minimization of the impact on the landscape. The Company’s strategy employs an Environmental
Management Plan (the “Plan”). Details of the Plan and the results are presented to, and reviewed by, the Board of Directors quarterly.
The Company’s Plan and operating guidelines focus on minimizing the impact of operations while meeting regulatory requirements,
regional management frameworks, industry operating standards and guidelines, and internal corporate standards. The Company,
as part of this Plan, has implemented a proactive program that includes:
n
n
An internal environmental compliance audit and inspection program of the Company’s operating facilities;
A suspended well inspection program to support future development or eventual abandonment;
62
CANAD IA N NATU RAL
n
n
n
n
n
n
n
n
n
n
Appropriate reclamation and decommissioning standards for wells and facilities ready for abandonment;
An effective surface reclamation program;
A due diligence program related to groundwater monitoring;
An active program related to preventing and reclaiming spill sites;
A solution gas reduction and conservation program;
A program to replace the majority of fresh water for steaming with brackish water;
Environmental planning for all projects to assess impacts and to implement avoidance and mitigation programs;
Reporting for environmental liabilities;
A program to optimize efficiencies at the Company’s operating facilities; and
Continued evaluation of new technologies to reduce environmental impacts.
The Company has also established stringent operating standards in four areas:
n
n
n
n
Implementing cost effective ways of reducing GHG emissions per unit of production;
Exercising care with respect to all waste produced through effective waste management plans;
Using water-based, environmentally friendly drilling muds whenever possible; and
Minimizing produced water volumes onshore and offshore through cost-effective measures.
For 2008, the Company’s capital expenditures included $38 million for abandonment expenditures (2007 – $71 million;
2006 – $75 million).
The Company’s estimated undiscounted ARO at December 31, 2008 was as follows:
Estimated ARO, undiscounted ($ millions)
North America, including Horizon Project
North Sea
Offshore West Africa
North Sea PRT recovery
$
2008
3,165 $
1,216
93
4,474
(529)
$
3,945 $
2007
3,038
1,286
102
4,426
(555)
3,871
The estimate of ARO is based on estimates of future costs to abandon and restore wells, production facilities and offshore
production platforms. Factors that affect costs include number of wells drilled, well depth and the specific environmental legislation.
The estimated costs are based on engineering estimates using current costs in accordance with present legislation and industry
operating practice. The Company’s strategy in the North Sea consists of developing commercial hubs around its core operated
properties with the goal of increasing production, lowering costs and extending the economic lives of its production facilities,
thereby delaying the eventual abandonment dates. The future abandonment costs incurred in the North Sea are estimated to result
in a PRT recovery of $529 million (2007 – $555 million; 2006 – $625 million), as abandonment costs are an allowable deduction
in determining PRT and may be carried back to reclaim PRT previously paid. The expected PRT recovery reduces the Company’s net
undiscounted abandonment liability to $3,945 million (2007 – $3,871 million).
greenhoUse gas anD other air emissions
The Company, through the Canadian Association of Petroleum Producers (“CAPP”), is working with legislators and regulators as
they develop and implement new GHG emission laws and regulations. Internally, the Company is pursuing an integrated emissions
reduction strategy to ensure that it is able to comply with existing and future emissions reduction requirements. The Company
continues to develop strategies that will enable it to deal with the risks and opportunities associated with new GHG and air
emissions policies. In addition, the Company is working with relevant parties to ensure that new policies encourage innovation,
energy efficiency, targeted research and development while not impacting competitiveness.
In Canada, the Federal Government has indicated its intent to develop regulations that would be in effect in 2010 to address
industrial GHG emissions. The Federal Government has also outlined national and sectoral reduction targets for several categories
of air pollutants. In Alberta, GHG regulations came into effect July 1, 2007, affecting facilities emitting more than 100 kilotonnes of
CO2e annually. Two of the Company’s facilities, the Primrose/Wolf Lake in-situ heavy crude oil facilities and the Hays sour natural gas
plant, fall under the regulations. Commencing July 1, 2008, the British Columbia carbon tax is being assessed at $10/tonne of CO2e
on fuel consumed in the province, increasing to $30/tonne by July 1, 2012. In the UK, GHG regulations have been in effect since
2005. During Phase 1 (2005 – 2007) of the UK National Allocation Plan, the Company operated below its CO2 allocation. For Phase 2
(2008 – 2012) the Company’s CO2 allocation has been decreased below the Company’s estimated current operations emissions. The
Company continues to focus on implementing reduction programs based on efficiency audits to reduce CO2 emissions at its major
facilities and on trading mechanisms to ensure compliance with requirements now in effect.
There are a number of unresolved issues in relation to Canadian Federal and Provincial GHG regulatory requirements. Key among
them is an appropriate facility emission threshold, availability and duration of compliance mechanisms, and resolution of federal/
provincial harmonization agreements. The Company continues to pursue GHG emission reduction initiatives including solution
CA NA DIAN NATURAL
63
gas conservation, CO2 capture and sequestration in oil sands tailings, CO2 capture and storage in association with enhanced oil
recovery, and participation in an industry initiative to promote an integrated CO2 capture and storage network.
The additional requirements of enacted or proposed GHG legislation on the Company’s operations will increase capital expenditures
and operating expenses, especially those related to the Horizon Project and the Company’s other existing and planned large oil
sands projects. This may have an adverse effect on the Company’s net earnings and cash flow from operations.
Air pollutant standards and guidelines are being developed federally and provincially and the Company is participating in these
discussions. Ambient air quality and sector based reductions in air emissions are being reviewed. Through Company and industry
participation with stakeholders, guidelines have been developed that adopt a structured process to emission reductions that is
commensurate with technological development and operational requirements.
CritiCal aCCoUnting estimates
The preparation of financial statements requires the Company to make judgements, assumptions and estimates in the application of
Canadian GAAP that have a significant impact on the financial results of the Company. Actual results may differ from those estimates,
and those differences may be material. Critical accounting estimates are reviewed by the Company’s Audit Committee annually. The
Company believes the following are the most critical accounting estimates in preparing its consolidated financial statements.
property, plant and equipment / depletion, depreciation and amortization
The Company follows the full cost method of accounting for its conventional crude oil and natural gas properties and equipment.
Accordingly, all costs relating to the exploration for and development of conventional crude oil and natural gas reserves, whether
successful or not, are capitalized and accumulated in country-by-country cost centres. Proceeds on disposal of properties are
ordinarily deducted from such costs without recognition of a gain or loss except where such dispositions result in a change in the
depletion rate of the specific cost centre of 20% or more. Under Canadian GAAP, substantially all of the capitalized costs and
estimated future capital costs related to each cost centre from which there is production are depleted on the unit-of-production
method based on the estimated proved reserves of that country using estimated future prices and costs, rather than single-day,
year-end prices and costs (“constant dollar pricing”) as required by the SEC for US GAAP purposes.
Under Canadian GAAP, the carrying amount of crude oil and natural gas properties in each cost centre may not exceed their
recoverable amount (“the ceiling test”). The recoverable amount is calculated as the undiscounted cash flow using proved reserves
and estimated future prices and costs. If the carrying amount of a cost centre exceeds its recoverable amount, an impairment loss
equal to the amount by which the carrying amount of the properties exceeds their estimated fair value is charged against net
earnings. Fair value is calculated as the cash flow from those properties using proved and probable reserves and estimated future
prices and costs, discounted at a risk-free interest rate. No ceiling test impairments were recognized under Canadian GAAP at
December 31, 2008, as future net revenues exceeded capitalized costs. Under US GAAP, the ceiling test differs from Canadian
GAAP in that future net revenues from proved reserves are based on constant dollar pricing and are discounted at 10%. Capitalized
costs and future net revenues are determined on a net of tax basis. These differences in applying the ceiling test in the current year
resulted in the recognition of an after-tax ceiling test impairment of $6,164 million for US GAAP purposes.
The US GAAP ceiling test is based on constant dollar pricing and is highly sensitive to differences in benchmark pricing and the
Heavy Differential in effect at year end as opposed to pricing throughout the year. As the Company’s crude oil production is
weighted towards heavier grades of crude oil, which have historically traded at lower prices at year end due to normal seasonality,
constant dollar pricing in effect at year end is generally not representative of average pricing realized throughout the year. Had the
US GAAP ceiling test at December 31, 2008 been prepared using average realized pricing throughout 2008, rather than constant
dollar pricing, and assuming no other changes in reserves, operating costs, or future development costs, the Company would not
have recognized a ceiling test impairment loss in the current year for US GAAP purposes.
The alternate acceptable method of accounting for crude oil and natural gas properties and equipment is the successful efforts
method. A major difference in applying the successful efforts method is that exploratory dry holes and geological and geophysical
exploration costs would be charged against net earnings in the year incurred rather than being capitalized to property, plant and
equipment. In addition, under this method, cost centres are defined based on reserve pools rather than by country. The use of the
full cost method usually results in higher capitalized costs and increased DD&A rates compared to the successful efforts method.
crude oil and natural Gas reserves
The estimation of reserves involves the exercise of judgement. Forecasts are based on engineering data, estimated future prices,
expected future rates of production and the timing and amount of future capital expenditures, all of which are subject to many
uncertainties and interpretations. The Company expects that over time its reserve estimates will be revised either upward or
downward based on updated information such as the results of future drilling, testing and production levels. Reserve estimates
can have a significant impact on net earnings, as they are a key component in the calculation of depletion, depreciation and
amortization and for determining potential asset impairment. For example, a revision to the proved reserve estimates would result
in a higher or lower DD&A charge to net earnings. Downward revisions to reserve estimates may also result in an impairment of
crude oil and natural gas property, plant and equipment carrying amounts under the ceiling test.
64
CANAD IA N NATU RAL
asset retirement obligations
Under CICA Handbook Section 3110, “Asset Retirement Obligations”, the Company is required to recognize a liability for the
future retirement obligations associated with its property, plant and equipment. An ARO is recognized to the extent of a legal
obligation associated with the retirement of a tangible long-lived asset the Company is required to settle as a result of an existing or
enacted law, statute, ordinance or written or oral contract, or by legal construction of a contract under the doctrine of promissory
estoppel. The ARO is based on estimated costs, taking into account the anticipated method and extent of restoration consistent
with legal requirements, technological advances and the possible use of the site. Since these estimates are specific to the sites
involved, there are many individual assumptions underlying the Company’s total ARO amount. These individual assumptions can
be subject to change.
The estimated fair values of ARO related to long-term assets are recognized as a liability in the period in which they are incurred.
Retirement costs equal to the estimated fair value of the ARO are capitalized as part of the cost of associated capital assets and
are amortized to expense through depletion over the life of the asset. The fair value of the ARO is estimated by discounting the
expected future cash flows to settle the ARO at the Company’s average credit-adjusted risk-free interest rate, which is currently
6.7%. In subsequent periods, the ARO is adjusted for the passage of time and for any changes in the amount or timing of the
underlying future cash flows. The estimates described impact earnings by way of depletion on the retirement cost and accretion on
the asset retirement liability. In addition, differences between actual and estimated costs to settle the ARO, timing of cash flows to
settle the obligation and future inflation rates may result in gains or losses on the final settlement of the ARO.
An ARO is not recognized for assets with an indeterminate useful life (e.g. pipeline assets and the Horizon Project upgrader and
related infrastructure) because an amount cannot be reasonably determined. An ARO for these assets will be recorded in the first
period in which the lives of these assets are determinable.
income taxes
The Company follows the liability method of accounting for income taxes. Under this method, future income tax assets and
liabilities are recognized based on the estimated tax effects of temporary differences between the carrying value of assets and
liabilities in the consolidated financial statements and their respective tax bases, using income tax rates substantively enacted or
enacted as of the consolidated balance sheet date. Accounting for income taxes is a complex process that requires management
to interpret frequently changing laws and regulations (e.g. changing income tax rates) and make certain judgements with respect
to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets.
These interpretations and judgements impact the current and future income tax provisions, future income tax assets and liabilities,
and net earnings.
risk Management activities
The Company utilizes various derivative financial instruments to manage its commodity price, foreign currency and interest rate
exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes.
The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows and discount rates. In determining these assumptions, the Company has
relied primarily on external readily observable market inputs including quoted commodity prices and volatility, interest rate yield
curves, and foreign exchange rates. The resulting fair value estimates may not necessarily be indicative of the amounts that may
be realized or settled in a current market transaction and these differences may be material.
purchase price allocations
The purchase prices of business combinations and asset acquisitions are allocated to the underlying acquired assets and liabilities
based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make
assumptions and estimates regarding future events. The allocation process is inherently subjective and impacts the amounts
assigned to individually identifiable assets and liabilities. As a result, the purchase price allocation impacts the Company’s reported
assets and liabilities and future net earnings due to the impact on future DD&A expense and impairment tests.
The Company has made various assumptions in determining the fair values of the acquired assets and liabilities. The most significant
assumptions and judgements relate to the estimation of the fair value of the crude oil and natural gas properties. To determine the
fair value of these properties, the Company estimates (a) crude oil and natural gas reserves, and (b) future prices of crude oil and
natural gas. Reserve estimates are based on the work performed by the Company’s internal engineers and outside consultants.
The judgements associated with these estimated reserves are described above in “Crude Oil and Natural Gas Reserves”. Estimates
of future prices are based on prices derived from price forecasts among industry analysts and internal assessments. The Company
applies estimated future prices to the estimated reserves quantities acquired, and estimates future operating and development
costs, to arrive at estimated future net revenues for the properties acquired.
CA NA DIAN NATURAL
65
Control environment
The Company’s management, including the President and Chief Operating Officer and the Chief Financial Officer and Senior
Vice-President, Finance, evaluated the effectiveness of disclosure controls and procedures as at December 31, 2008, and concluded
that disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its
annual filings and other reports filed with securities regulatory authorities in Canada and the United States is recorded, processed,
summarized and reported within the time periods specified and such information is accumulated and communicated to the
Company’s management to allow timely decisions regarding required disclosures.
The Company’s management, including the President and Chief Operating Officer and the Chief Financial Officer and Senior
Vice-President, Finance also performed an assessment of internal control over financial reporting as at December 31, 2008, and
concluded that internal control over financial reporting is effective. Further, there were no changes in the Company’s internal
control over financial reporting during 2008 that have materially affected, or are reasonably likely to materially affect, internal
controls over financial reporting.
While the Company’s management, including the President and Chief Operating Officer and the Chief Financial Officer and
Senior Vice-President, Finance believes that the Company’s disclosure controls and procedures and internal controls over financial
reporting provide a reasonable level of assurance they are effective, they recognize that all control systems have inherent limitations.
Because of its inherent limitations, the Company’s control systems may not prevent or detect misstatements. Also, projections of
any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes
in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
neW aCCoUnting stanDarDs
Effective January 1, 2008, the Company adopted the following accounting and disclosure standards issued by the CICA:
capital disclosures
n
Section 1535 – “Capital Disclosures” requires entities to disclose their objectives, policies and processes for managing capital, as
well as quantitative data about capital. The standard also requires the disclosure of any externally imposed capital requirements
and compliance with those requirements. The standard does not define capital. This standard affects disclosure only and did
not impact the Company’s accounting for capital.
inventories
n
Section 3031 – “Inventories” replaces Section 3030 – “Inventories” and establishes new standards for the measurement of cost
of inventories and expands disclosure requirements for inventories. Adoption of this standard did not have a material impact
on the Company’s financial statements.
Financial instruments
n
Section 3862 – “Financial Instruments – Disclosure” and Section 3863 “Financial Instruments – Presentation” replace Section
3861 – “Financial Instruments – Disclosure and Presentation”. Section 3862 enhances disclosure requirements concerning risks
and requires quantitative and qualitative disclosures about exposures to risks arising from financial instruments. Section 3863
carries forward the presentation requirements from Section 3861 unchanged. These standards affect disclosures only and did
not impact the Company’s accounting for financial instruments.
Effective January 1, 2009, the Company will adopt the following new accounting standard issued by the CICA:
Goodwill and intangible assets
n
Section 3064 – “Goodwill and Intangible Assets” replaces Section 3062 – “Goodwill and Other Intangible Assets” and Section
3450 – “Research and Development Costs.” In addition, EIC-27 – “Revenue and Expenditures during the Pre-Operating Period”
has been withdrawn. The new standard addresses when an internally generated intangible asset meets the definition of an
asset. Adoption of the new standard may impact the Company’s future capitalization of certain costs during the development
and start-up of large development projects.
international finanCial reporting stanDarDs
In February 2008, the CICA’s Accounting Standards Board confirmed that Canadian publicly accountable enterprises will be required
to adopt International Financial Reporting Standards (“IFRS”) as promulgated by the International Accounting Standards Board
(“IASB”) in place of Canadian GAAP effective January 1, 2011.
The Company commenced its IFRS conversion project in 2008 and has established a formal project governance structure. The
structure includes a Steering Committee, which consists of senior levels of management from finance and accounting, operations
and information technology (“IT”). The Steering Committee provides regular updates to the Company’s Senior Management and
the Audit Committee of the Board of Directors.
66
CANAD IA N NATU RAL
The Company’s IFRS conversion project consists of the following phases:
n
n
n
n
n
Phase 1 Diagnostic – identification of potential accounting and reporting differences between Canadian GAAP and IFRS.
Phase 2 Planning – development of project governance, processes, resources, budget and timeline.
Phase 3 Policy Delivery and Documentation – establishment of accounting policies under IFRS.
Phase 4 Policy Implementation – establishment of processes for accounting and reporting, IT change requirements, and education.
Phase 5 Sustainment – ongoing compliance with IFRS after implementation.
The Company has completed the Diagnostic phase. Significant differences were identified in accounting for Property, Plant &
Equipment (“PP&E”), including exploration costs, depletion and depreciation, impairment testing, capitalized interest and asset
retirement obligations. Other significant differences were noted in accounting for stock-based compensation, risk management
activities, and income taxes. The Company is currently performing the necessary research to develop and document IFRS policies to
address the major differences noted. At this time, the impact on the Company’s future financial position and results of operations
is not reasonably determinable. In addition, IFRS is expected to change prior to adoption in 2011, and the impact of these potential
changes is not known. Included in the potential IFRS changes is an exposure draft issued in September 2008 by the IASB that proposes
transition rules for oil and gas companies following full cost accounting. The proposed transition rule would allow full cost companies
to allocate their existing full cost PP&E balances using reserve values or volumes to IFRS compliant units of account as at the date of
conversion without requiring retroactive adjustment. The Company intends to adopt the transition rule if it is approved.
oUtlooK
The Company continues to implement its strategy of maintaining a large portfolio of varied projects, which the Company believes
will enable it, over an extended period of time, to provide consistent growth in production and create shareholder value. Annual
budgets are developed, scrutinized throughout the year and revised if necessary in the context of targeted financial ratios, project
returns, product pricing expectations, and balance in project risk and time horizons. The Company maintains a high ownership
level and operatorship level in all of its properties and can therefore control the nature, timing and extent of capital expenditures
in each of its project areas. The Company expects production levels in 2009 to average between 331,000 bbl/d and 399,000 bbl/d
of crude oil and NGLs and between 1,272 mmcf/d and 1,328 mmcf/d of natural gas.
The forecasted capital expenditures in 2009 are currently expected to be as follows:
($ millions)
Conventional crude oil and natural gas
North America natural gas
North America crude oil and NGLs
North Sea
Offshore West Africa
Property acquisitions, dispositions and midstream
horizon project
Phase 1 – Construction
Phase 1 – Operating and capital inventory
Phase 1 – Commissioning costs
Phase 2/3 – Tranche 2
Sustaining capital
Capitalized interest and other costs
Total
north america natural Gas
2009 forecast
$
$
$
$
$
589
1,138
141
553
109
2,530
180
43
183
121
94
41
662
3,192
The 2009 North America natural gas drilling program is highlighted by the continued high-grading of the Company’s natural gas
asset base as follows:
(Number of wells)
Coal bed methane and shallow natural gas
Conventional natural gas
Cardium natural gas
Deep natural gas
Total
2009 forecast
30
66
9
37
142
The Company has reduced 2009 natural gas drilling in Alberta due to the anticipated future impact of royalty changes effective
January 1, 2009.
CA NA DIAN NATURAL
67
north america crude oil and nGls
The 2009 North America crude oil drilling program is highlighted by continued development of the Primrose thermal projects,
Pelican Lake, and a strong conventional primary heavy program, as follows:
(Number of wells)
Conventional primary heavy crude oil
Thermal heavy crude oil
Light crude oil
Pelican Lake crude oil
Total
Horizon project
2009 forecast
317
70
20
58
465
During the initial stages of the ramp-up of production, the production volumes will fluctuate on a weekly basis until the end of the second
quarter of 2009 when the Company expects to see a steady ramp up to full production capacity of 110,000 bbl/d by the end of 2009.
The Company will work towards full capacity throughout 2009 as the plant continues to be fine tuned to design rates with a focus on
safety and reliability.
north Sea
The 2009 capital forecast for the North Sea includes drilling 0.9 net platform wells with focus on building drilling and workover
inventory for 2010.
offshore West africa
The 2009 capital forecast for Offshore West Africa anticipates spending $80 million to complete Phase 2 of the development of the
Baobab Field in Côte d’Ivoire. The Company is targeting the fourth well to be completed in the second quarter of 2009.
sensitivitY analYsis
The following table is indicative of the annualized sensitivities of cash flow from operations and net earnings from changes in
certain key variables. The analysis is based on business conditions and sales volumes during the fourth quarter of 2008, excluding
mark-to-market gains (losses) on risk management activities and capitalized interest, and is not necessarily indicative of future
results. Each separate line item in the sensitivity analysis shows the effect of a change in that variable only with all other variables
being held constant.
Cash flow from
operations
($ millions)
Cash flow from
operations
(per common
share, basic)
net
earnings
($ millions)
net
earnings
(per common
share, basic)
price changes
Crude oil – WTI US$1.00/bbl (1)
Excluding financial derivatives
Including financial derivatives
Natural gas – AECO C$0.10/mcf (1)
Excluding financial derivatives
Including financial derivatives
volume changes
Crude oil – 10,000 bbl/d
Natural gas – 10 mmcf/d
foreign currency rate change
$0.01 change in US$ (1)
Including financial derivatives
interest rate change – 1%
$
$
$
$
$
$
$
$
112 $
66 $
38 $
38 $
87 $
18 $
0.21 $
0.12 $
0.07 $
0.07 $
0.16 $
0.03 $
84 $
48 $
28 $
28 $
38 $
7 $
89 – 92 $
32 $
0.17 $
0.06 $
8 – 9 $
32 $
0.16
0.09
0.05
0.05
0.07
0.01
0.02
0.06
(1) For details of financial instruments in place, refer to note 13 to the Company’s audited annual consolidated financial statements as at December 31, 2008.
68
CANAD IA N NATU RAL
DailY proDUCtion BY segment, Before roYalties
Crude oil and ngls (bbl/d)
North America
North Sea
Offshore West Africa
Total
natural gas (mmcf/d)
North America
North Sea
Offshore West Africa
Total
Barrels of oil equivalent (boe/d)
North America
North Sea
Offshore West Africa
Q1
Q2
Q3
Q4
2008
2007
2006
248,960
49,568
28,689
245,616
45,830
27,631
239,973
42,760
24,237
240,831
42,991
25,748
243,826
45,274
26,567
246,779
55,933
28,520
235,253
60,056
36,689
327,217
319,077
306,970
309,570
315,667
331,232
331,998
1,513
11
14
1,538
1,501
10
15
1,526
1,467
9
14
1,490
1,405
10
12
1,427
1,472
10
13
1,495
1,643
13
12
1,668
1,468
15
9
1,492
501,061
51,404
31,023
495,836
47,545
30,056
484,542
44,309
26,505
475,089
44,623
27,687
489,081
46,956
28,808
520,564
58,099
30,543
479,891
62,558
38,275
Total
583,488
573,437
555,356
547,399
564,845
609,206
580,724
per Unit resUlts (1)
Crude oil and ngls ($/bbl)
Sales price (2)
Royalties
Production expense
Netback
natural gas ($/mcf)
Sales price (2)
Royalties
Production expense
Netback
Barrels of oil equivalent ($/boe)
Sales price (2)
Royalties
Production expense
Q1
Q2
Q3
Q4
2008
2007
2006
$
78.99 $ 103.73 $ 102.30 $ 45.81 $ 82.41 $
8.70
14.81
14.82
16.39
14.17
17.61
4.49
16.33
10.48
16.26
55.45 $ 53.65
4.48
12.29
5.94
13.34
$ 55.48 $ 72.52 $ 70.52 $ 24.99 $ 55.67 $
36.17 $ 36.88
$
7.77 $
1.35
1.03
9.89 $
1.86
0.94
8.82 $
1.55
1.05
7.03 $
1.08
1.06
8.39 $
1.46
1.02
6.85 $
1.11
0.91
$
5.39 $
7.09 $
6.22 $
4.89 $
5.91 $
4.83 $
6.72
1.29
0.82
4.61
$
65.09 $ 84.88 $ 80.60 $ 43.84 $ 68.62 $
8.43
11.02
13.26
11.60
12.06
12.52
5.37
12.05
9.78
11.79
49.05 $ 47.92
5.89
9.14
6.26
9.75
Netback
$ 45.64 $ 60.02 $ 56.02 $ 26.42 $ 47.05 $
33.04 $ 32.89
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management activities.
netBaCK analYsis
($/boe) (1)
Sales price (2)
Royalties
Production expense (3)
netback
Midstream contribution (3)
Administration
Interest, net
Realized risk management loss
Realized foreign exchange loss (gain)
Taxes other than income tax – current
Current income tax – North America
Current income tax – North Sea
Current income tax – Offshore West Africa
Cash flow
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management activities.
(3) Excluding inter-segment eliminations.
$
2008
2007
68.62 $
9.78
11.79
47.05
(0.25)
0.87
0.62
8.99
(0.55)
1.18
0.15
1.64
0.62
49.05 $
6.26
9.75
33.04
(0.23)
0.93
1.24
0.73
0.24
0.54
0.43
0.95
0.33
$
33.78 $
27.88 $
2006
47.92
5.89
9.14
32.89
(0.23)
0.85
0.66
6.27
(0.06)
1.04
0.68
0.14
0.23
23.31
CA NA DIAN NATURAL
69
traDing anD share statistiCs
Q1
Q2
Q3
Q4
2008
2007
tsX – C$
Trading Volume (thousands)
Share Price ($/share)
High
Low
Close
Market capitalization as at
December 31 ($ millions)
Shares outstanding (thousands)
nYse – Us$
Trading Volume (thousands)
Share Price ($/share)
High
Low
Close
Market capitalization as at
December 31($ millions)
Shares outstanding (thousands)
$
$
$
$
$
$
134,421
145,018
186,906
213,393
679,738
429,034
76.80 $
58.88 $
70.27 $
111.30 $
68.08 $
100.84 $
104.83 $
64.40 $
73.00 $
72.89 $
34.19 $
48.75 $
111.30 $
34.19 $
48.75 $
80.02
52.45
72.58
$
26,373 $
540,991
39,174
539,729
157,781
190,756
292,659
326,032
967,228
486,266
78.43 $
57.07 $
68.26 $
109.32 $
66.21 $
100.25 $
103.40 $
61.82 $
68.46 $
68.87 $
26.43 $
39.98 $
109.32 $
26.43 $
39.98 $
87.17
44.56
73.14
$
21,629 $
540,991
39,476
539,729
70
CANAD IA N NATU RAL
management’s report
ca na dia n natu ral 2008 a nn u a l r epo rt
The accompanying consolidated financial statements and all other information contained elsewhere in this Annual Report are the
responsibility of management. The consolidated financial statements have been prepared by management in accordance with the
accounting policies described in the accompanying notes. Where necessary, management has made informed judgements and
estimates in accounting for transactions that were not complete at the balance sheet date. In the opinion of management, the
financial statements have been prepared in accordance with Canadian generally accepted accounting principles appropriate in the
circumstances. The financial information presented elsewhere in the Annual Report has been reviewed to ensure consistency with
that in the consolidated financial statements.
Management maintains appropriate systems of internal control. Policies and procedures are designed to give reasonable assurance
that transactions are appropriately authorized and recorded, assets are safeguarded from loss or unauthorized use and financial
records are properly maintained to provide reliable information for preparation of financial statements.
PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has been engaged, as approved by a vote of the
shareholders at the Company’s most recent Annual General Meeting, to audit and provide their independent audit opinions on
the following:
n
n
the Company’s consolidated financial statements as at December 31, 2008; and
the effectiveness of the Company’s internal control over financial reporting as at December 31, 2008.
Their report is presented with the consolidated financial statements.
The Board of Directors (the “Board”) is responsible for ensuring that management fulfills its responsibilities for financial reporting
and internal controls. The Board exercises this responsibility through the Audit Committee of the Board, which is comprised of
non-management directors. The Audit Committee meets with management and the independent auditors to satisfy itself that
management responsibilities are properly discharged and to review the consolidated financial statements before they are presented
to the Board for approval. The consolidated financial statements have been approved by the Board on the recommendation of the
Audit Committee.
Steve W. laut
PRESIDENT & CHIEF OPERATING OFFICER
douglas a. proll, CA
CHIEF FINANCIAL OFFICER &
SENIOR VICE-PRESIDENT, FINANCE
randall S. davis, CA
VICE-PRESIDENT, FINANCE &
ACCOUNTING
MARCH 4, 2009
CALGARY, ALBERTA, CANADA
CA NA DIAN NATURAL
71
canadian natural 2 008 a n n u a l r e p ort
management’s assessment of internal control
over financial reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as
defined in Rules 13a–15(f) and 15d–15(f) under the United States Securities Exchange Act of 1934, as amended.
Management, together with the Company’s President and Chief Operating Officer and the Company’s Chief Financial Officer
and Senior Vice-President, Finance, performed an assessment of the Company’s internal control over financial reporting based on
the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (“COSO”).
Based on the assessment, management, together with the Company’s President and Chief Operating Officer and the Company’s
Chief Financial Officer and Senior Vice-President, Finance, has concluded that the Company’s internal control over financial reporting
is effective as at December 31, 2008. Management recognizes that all internal control systems have inherent limitations. Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of
any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes
in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has provided an opinion on the Company’s internal
control over financial reporting as at December 31, 2008, as stated in their Auditors’ Report.
Steve W. laut
PRESIDENT & CHIEF OPERATING OFFICER
MARCH 4, 2009
CALGARY, ALBERTA, CANADA
douglas a. proll, CA
CHIEF FINANCIAL OFFICER &
SENIOR VICE-PRESIDENT, FINANCE
independent auditors’ report
to the shareholders of Canadian natural resources limited
We have completed integrated audits of Canadian Natural Resources Limited’s 2008, 2007, and 2006 consolidated financial
statements and of its internal control over financial reporting as at December 31, 2008. Our opinions, based on our audits, are
presented below.
ConsoliDateD finanCial statements
We have audited the accompanying consolidated balance sheets of Canadian Natural Resources Limited (the “Company”) as
at December 31, 2008 and December 31, 2007, and the related consolidated statements of earnings, shareholders’ equity,
comprehensive income and cash flows for each of the years in the three year period ended December 31, 2008. These consolidated
financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits of the Company’s consolidated financial statements in accordance with Canadian generally accepted
auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements. A financial statement audit also includes assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
72
CANAD IA N NATU RAL
ca na dia n natu ral 2008 a nn u a l r epo rt
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of
the Company as at December 31, 2008 and December 31, 2007 and the results of its operations and its cash flows for each of the
years in the three year period ended December 31, 2008 in accordance with Canadian generally accepted accounting principles.
internal Control over finanCial reporting
We have also audited Canadian Natural Resource Limited’s internal control over financial reporting as at December 31, 2008,
based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the
accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express an opinion
on the Company’s internal control over financial reporting based on our audit.
We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of
internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing
the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as at
December 31, 2008 based on criteria established in Internal Control — Integrated Framework issued by the COSO.
Chartered accountants
CALGARY, ALBERTA, CANADA
MARCH 4, 2009
Comments BY aUDitor for U.s. reaDers on CanaDa-U.s. reporting DifferenCes
In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion
paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Company’s
consolidated financial statements, such as the changes indicated in the Consolidated Statements of Shareholders’ Equity and
Comprehensive Income. Our report to the shareholders dated March 4, 2009 is expressed in accordance with Canadian reporting
standards which do not require a reference to such a change in accounting principles in the Auditors’ Report when the change is
properly accounted for and adequately disclosed in the consolidated financial statements.
Chartered accountants
CALGARY, ALBERTA, CANADA
MARCH 4, 2009
CA NA DIAN NATURAL
73
canadian natural 2 008 a n n u a l r e p ort
consolidated balance sheets
As at December 31
(millions of Canadian dollars)
assets
Current assets
Cash and cash equivalents
Accounts receivable and other
Future income tax (note 8)
Current portion of other long-term assets (note 3)
property, plant and equipment (note 4)
other long-term assets (note 3)
liaBilities
Current liabilities
Accounts payable
Accrued liabilities
Future income tax (note 8)
Current portion of long-term debt (note 5)
Current portion of other long-term liabilities (note 6)
long-term debt (note 5)
other long-term liabilities (note 6)
future income tax (note 8)
shareholDers’ eQUitY
share capital (note 9)
retained earnings
accumulated other comprehensive income (note 10)
Commitments and contingencies (note 14).
Approved by the Board of Directors:
2008
2007
$
27 $
1,514
–
1,851
3,392
38,966
292
$
42,650 $
$
383 $
1,802
585
420
230
3,420
12,596
1,124
7,136
24,276
2,768
15,344
262
18,374
$
42,650 $
21
1,662
480
18
2,181
33,902
31
36,114
379
1,567
–
–
1,617
3,563
10,940
1,561
6,729
22,793
2,674
10,575
72
13,321
36,114
Catherine m. Best
CHAIR OF THE AUDIT COMMITTEE
AND DIRECTOR
n. murray edwards
VICE-CHAIRMAN OF THE BOARD OF DIRECTORS
AND DIRECTOR
74
CANAD IA N NATU RAL
consolidated statements of earnings
ca na dia n natu ral 2008 a nn u a l r epo rt
For the years ended December 31
(millions of Canadian dollars, except per common share amounts)
revenue
Less: royalties
revenue, net of royalties
expenses
Production
Transportation and blending
Depletion, depreciation and amortization
Asset retirement obligation accretion (note 6)
Administration
Stock-based compensation (recovery) expense (note 6)
Interest, net
Risk management activities (note 13)
Foreign exchange loss (gain)
earnings before taxes
Taxes other than income tax (note 8)
Current income tax expense (note 8)
Future income tax expense (recovery) (note 8)
net earnings
net earnings per common share (note 12)
Basic and diluted
2008
2007
$
16,173 $
(2,017)
12,543 $
(1,391)
14,156
11,152
2006
11,643
(1,245)
10,398
2,451
1,936
2,683
71
180
(52)
128
(1,230)
718
6,885
7,271
178
501
1,607
2,184
1,570
2,863
70
208
193
276
1,562
(471)
8,455
2,697
165
380
(456)
4,985 $
2,608 $
1,949
1,443
2,391
68
180
139
140
312
122
6,744
3,654
256
222
652
2,524
9.22 $
4.84 $
4.70
$
$
CA NA DIAN NATURAL
75
canadian natural 2 008 a n n u a l r e p ort
consolidated statements of
shareholders’ equity
For the years ended December 31
(millions of Canadian dollars)
2008
2007
2006
share capital
Balance – beginning of year
Issued upon exercise of stock options
Previously recognized liability on stock options exercised for common shares
Purchase of common shares under Normal Course Issuer Bid
$
Balance – end of year
retained earnings
Balance – beginning of year, as originally reported
Transition adjustment on adoption of financial instruments standards
Balance – beginning of year, as restated
Net earnings
Dividends on common shares (note 9)
Purchase of common shares under Normal Course Issuer Bid
2,674 $
18
76
–
2,768
10,575
–
10,575
4,985
(216)
–
2,562 $
21
91
–
2,674
8,141
10
8,151
2,608
(184)
–
Balance – end of year
15,344
10,575
accumulated other comprehensive income (loss)
Balance – beginning of year
Transition adjustment on adoption of financial instruments standards
Balance – beginning of year, after effect of transition adjustment
Other comprehensive income (loss), net of taxes
Balance – end of year
shareholders’ equity
72
–
72
190
262
(13)
159
146
(74)
72
$
18,374 $
13,321 $
10,690
2,442
21
101
(2)
2,562
5,804
–
5,804
2,524
(161)
(26)
8,141
(9)
–
(9)
(4)
(13)
consolidated statements of
comprehensive income
For the years ended December 31
(millions of Canadian dollars)
net earnings
net change in derivative financial instruments
designated as cash flow hedges
Unrealized income during the year,
net of taxes of $1 million (2007 – $6 million, 2006 – $nil)
Reclassification to net earnings,
net of taxes of $6 million (2007 – $45 million, 2006 – $nil)
foreign currency translation adjustment
Translation of net investment
other comprehensive income (loss), net of taxes
2008
2007
$
4,985 $
2,608 $
2006
2,524
30
(12)
18
172
190
38
(96)
(58)
(16)
(74)
–
–
–
(4)
(4)
Comprehensive income
$
5,175 $
2,534 $
2,520
76
CANAD IA N NATU RAL
consolidated statements of cash flows
ca na dia n natu ral 2008 a nn u a l r epo rt
For the years ended December 31
(millions of Canadian dollars)
operating activities
Net earnings
Non-cash items
Depletion, depreciation and amortization
Asset retirement obligation accretion
Stock-based compensation (recovery) expense
Unrealized risk management (gain) loss
Unrealized foreign exchange loss (gain)
Deferred petroleum revenue tax (recovery) expense
Future income tax expense (recovery)
Other
Abandonment expenditures
Net change in non-cash working capital (note 15)
financing activities
(Repayment) issue of bank credit facilities, net
Issue of medium-term notes
Repayment of senior unsecured notes
Issue of US dollar debt securities
Issue of common shares on exercise of stock options
Dividends on common shares
Purchase of common shares
Net change in non-cash working capital (note 15)
investing activities
Expenditures on property, plant and equipment
Net proceeds on sale of property, plant and equipment
Net expenditures on property, plant and equipment
Acquisition of Anadarko Canada Corporation (note 16)
Net change in non-cash working capital (note 15)
2008
2007
2006
$
4,985 $
2,608 $
2,524
2,683
71
(52)
(3,090)
832
(67)
1,607
25
(38)
(189)
6,767
(623)
–
(31)
1,215
18
(208)
–
46
417
(7,433)
20
(7,413)
–
235
2,863
70
193
1,400
(524)
44
(456)
38
(71)
(346)
5,819
(1,925)
273
(33)
2,553
21
(178)
–
8
719
(6,464)
110
(6,354)
–
(186)
2,391
68
139
(1,013)
134
37
652
(2)
(75)
(679)
4,176
6,499
400
–
788
21
(153)
(28)
37
7,564
(7,266)
71
(7,195)
(4,641)
101
increase (decrease) in cash and cash equivalents
Cash and cash equivalents – beginning of year
6
21
Cash and cash equivalents – end of year
$
27 $
(2)
23
21 $
5
18
23
Supplemental disclosure of cash flow information (note 15)
(7,178)
(6,540)
(11,735)
CA NA DIAN NATURAL
77
canadian natural 2 008 a n n u a l r e p ort
notes to the consolidated financial statements
(tabular amounts in millions of Canadian dollars, unless otherwise stated)
1. aCCoUnting poliCies
Canadian Natural Resources Limited (the “Company”) is a senior independent crude oil and natural gas exploration, development
and production company head-quartered in Calgary, Alberta, Canada. The Company’s conventional crude oil and natural gas
operations are focused in North America, largely in Western Canada; the United Kingdom (“UK”) portion of the North Sea; and
Côte d’Ivoire and Gabon in Offshore West Africa.
Within Western Canada, the Company is developing its Horizon Oil Sands Project (the “Horizon Project”) in a series of staged
development phases (“Phases”). The Horizon Project is designed to produce synthetic crude oil through bitumen mining and
upgrading operations.
Also within Western Canada, the Company maintains certain midstream activities that include pipeline operations and an electricity
co-generation system.
The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally
accepted in Canada (“Canadian GAAP”). A summary of differences between accounting principles in Canada and those generally
accepted in the United States (“US GAAP”) is contained in note 18.
Significant accounting policies are summarized as follows:
(a) principleS oF conSolidation
The consolidated financial statements include the accounts of the Company and all of its subsidiary companies and partnerships.
A significant portion of the Company’s activities are conducted jointly with others and the consolidated financial statements reflect
only the Company’s proportionate interest in such activities.
(B) MeaSureMent uncertaintY
Management has made estimates and assumptions regarding certain assets, liabilities, revenues and expenses in the preparation
of the consolidated financial statements. Such estimates primarily relate to unsettled transactions and events as of the date of the
consolidated financial statements. Accordingly, actual results may differ from estimated amounts.
Purchase price allocations; depletion, depreciation and amortization, and amounts used in impairment calculations are based on
estimates of crude oil and natural gas reserves. The estimation of reserves involves the exercise of judgement. Forecasts are based
on engineering data, estimated future prices, expected future rates of production and the timing of future capital expenditures,
all of which are subject to many uncertainties and interpretations. The Company expects that, over time, its reserve estimates will
be revised upward or downward based on updated information such as the results of future drilling, testing and production levels,
and may be affected by changes in commodity prices. As a result, the impact of differences between actual and estimated oil and
gas reserves amounts on the consolidated financial statements of future periods may be material.
The calculation of asset retirement obligations includes estimates of the future costs to settle the asset retirement obligation, the
timing of the cash flows to settle the obligation, and the future inflation rates. The impact of differences between actual and
estimated costs, timing and inflation on the consolidated financial statements of future periods may be material.
The calculation of income taxes requires judgement in applying tax laws and regulations, estimating the timing of temporary
difference reversals, and estimating the realizability of future tax assets. These estimates impact current and future income tax
assets and liabilities, and current and future income tax expense (recovery).
The measurement of petroleum revenue tax expense in the United Kingdom and the related provision in the consolidated financial
statements are subject to uncertainty associated with future recoverability of crude oil and natural gas reserves, commodity prices
and the timing of future events, which may result in material changes to deferred amounts.
The estimation of fair value for derivative financial instruments requires the use of assumptions. In determining these assumptions,
the Company has relied primarily on external, readily observable market inputs including quoted commodity prices and volatility,
interest rate yield curves, and foreign exchange rates. The resulting fair value estimates may not necessarily be indicative of the
amounts that could be realized or settled in a current market transaction and these differences may be material.
(c) caSH and caSH eQuiV alentS
Cash comprises cash on hand and demand deposits. Other investments (term deposits and certificates of deposit) with an original
term to maturity at purchase of three months or less are reported as cash equivalents on the balance sheet.
78
CANAD IA N NATU RAL
(d) propertY, plant and eQuipMent
conventional crude oil and natural Gas
The Company follows the full cost method of accounting for its conventional crude oil and natural gas properties and equipment
as prescribed by Accounting Guideline 16 (“AcG 16”) issued by the Canadian Institute of Chartered Accountants (“CICA”).
Accordingly, all costs relating to the exploration for and development of conventional crude oil and natural gas reserves are
capitalized and accumulated in country-by-country cost centres. Directly attributable administrative overhead incurred during
the development of certain large capital projects is capitalized until the projects are available for their intended use. Proceeds on
disposal of properties are ordinarily deducted from such costs without recognition of a gain or loss except where such dispositions
result in a change in the depletion rate of the specific cost centre of 20% or more.
oil Sands Mining operations and upgrading operations
The Company’s Horizon Project is comprised of both mining operations and upgrading operations and accordingly, capitalized
costs related to the Horizon Project are accounted for separately from the Company’s Canadian conventional crude oil and natural
gas costs. Capitalized mining activity costs include property acquisition, construction and development costs. Construction and
development costs are capitalized separately to each Phase of the Horizon Project. Construction and development for a particular
Phase of the Horizon Project is considered complete once the Phase is available for its intended use. Costs related to major
maintenance turnaround activities will be capitalized and amortized on a straight-line basis over the period to the next scheduled
major maintenance turnaround.
Midstream and other
The Company capitalizes all costs that expand the capacity or extend the useful life of the assets.
(e) oVerBurden reMoV al coStS
Overburden removal costs incurred during development of the Horizon Project mine are capitalized to property, plant and
equipment. Overburden removal costs incurred during production of the Horizon Project mine will be included in the cost of
inventory produced, unless the overburden removal activity has resulted in a betterment of the mineral property, in which case the
costs will be capitalized to property, plant and equipment. Capitalized overburden removal costs will be amortized over the life of
the mining reserves that directly benefit from the overburden removal activity.
(F) capitaliZed intereSt
The Company capitalizes construction period interest based on the Horizon Project costs incurred and the Company’s cost of borrowing.
Interest capitalization on a particular Phase of the Horizon Project ceases once this Phase is available for its intended use.
(G) leaSeS
Contractual arrangements that meet the definition of a lease are accounted for as capital leases or operating leases as appropriate.
Leases that transfer substantially all of the benefits and risks of ownership to the Company are accounted for as capital leases and
are recorded as property, plant and equipment with an offsetting liability. All other leases are accounted for as operating leases
whereby lease costs are expensed as incurred.
(H) depletion, depreciation and aMortiZation
conventional crude oil and natural Gas
Substantially all costs related to each country-by-country cost centre are depleted on the unit-of-production method based on the
estimated proved reserves of that country. Volumes of net production and net reserves before royalties are converted to equivalent
units on the basis of estimated relative energy content. In determining its depletion base, the Company includes estimated future
costs to be incurred in developing proved reserves and excludes the cost of unproved properties and major development projects.
Costs for major development projects, as identified by management, are not subject to depletion until the projects are available
for their intended uses. Unproved properties and major development projects are assessed periodically to determine whether
impairment has occurred. When proved reserves are assigned or the value of an unproved property or major development project
is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.
Processing and production facilities are depreciated on a straight-line basis over their estimated lives.
The Company reviews the carrying amount of its conventional crude oil and natural gas properties (“the properties”) relative
to their recoverable amount (“the ceiling test”) for each cost centre at each annual balance sheet date, or more frequently if
circumstances or events indicate impairment may have occurred. The recoverable amount is calculated as the undiscounted cash
flow from the properties using proved reserves and expected future prices and costs. If the carrying amount of the properties
exceeds their recoverable amount, an impairment loss is recognized in depletion expense equal to the amount by which the
carrying amount of the properties exceeds their fair value. Fair value is calculated as the cash flow from those properties using
proved and probable reserves and expected future prices and costs, discounted at a risk-free interest rate.
oil Sands Mining operations and upgrading operations
Upon commencement of operations for the Horizon Project, mine-related costs and costs of the upgrader and related infrastructure
located on the Horizon Project site will be amortized on the unit-of-production method based on the estimated proved reserves of
the Horizon Project or productive capacity, respectively. Moveable mine-related equipment is depreciated on a straight-line basis
over its estimated useful life.
CA NA DIAN NATURAL
79
The Company reviews the carrying amount of the Horizon Project relative to its recoverable amount if circumstances or events
indicate impairment may have occurred. The recoverable amount is calculated as the undiscounted cash flow from the Horizon
Project assets using proved and probable reserves and expected future prices and costs. If the carrying amount exceeds the
recoverable amount, an impairment loss is recognized in depletion equal to the amount by which the carrying amount of the assets
exceeds fair value. Fair value is calculated as the discounted cash flow from the Horizon Project using proved and probable reserves
and expected future prices and costs.
Midstream and other
Midstream assets are depreciated on a straight-line basis over their estimated lives. The Company reviews the recoverability of
the carrying amount of the midstream assets when events or circumstances indicate that the carrying amount might not be
recoverable. If the carrying amount of the midstream assets exceeds their recoverable amount, an impairment loss equal to the
amount by which the carrying amount of the midstream assets exceeds their fair value is recognized in depreciation.
Other capital assets are amortized on a declining balance basis.
(i) aSSet retireMent oBliGationS
The Company provides for future asset retirement obligations on its resource properties, facilities, production platforms, gathering
systems, and oil sands mining operations and tailings ponds based on current legislation and industry operating practices. The fair
values of asset retirement obligations related to property, plant and equipment are recognized as a liability in the period in which
they are incurred. Retirement costs equal to the fair value of the asset retirement obligations are capitalized as part of the cost of
the associated property, plant and equipment and are amortized to expense through depletion and depreciation over the lives of
the respective assets. The fair value of an asset retirement obligation is estimated by discounting the expected future cash flows to
settle the asset retirement obligation at the Company’s average credit-adjusted risk-free interest rate. In subsequent periods, the
asset retirement obligation is adjusted for the passage of time and for changes in the amount or timing of the underlying future
cash flows. Actual expenditures are charged against the accumulated asset retirement obligation as incurred.
The Company’s Horizon Project upgrader and related infrastructure and its midstream pipelines have an indeterminate life and
therefore the fair values of the related asset retirement obligations cannot be reasonably determined. The asset retirement
obligations for these assets will be recorded in the year in which the lives of the assets are determinable.
(J) ForeiGn currencY tranSlation
Foreign operations that are self-sustaining are translated using the current rate method. Under this method, assets and liabilities are
translated to Canadian dollars from their functional currency using the exchange rate in effect at the consolidated balance sheet
date. Revenues and expenses are translated to Canadian dollars at the monthly average exchange rates. Gains or losses on translation
are included in accumulated other comprehensive income (loss) in shareholders’ equity in the consolidated balance sheets.
Foreign operations that are integrated are translated using the temporal method. For foreign currency balances and integrated
subsidiaries, monetary assets and liabilities are translated to Canadian dollars at the exchange rate in effect at the consolidated
balance sheet date. Non-monetary assets and liabilities are translated at the exchange rate in effect when the assets were acquired
or obligations incurred. Revenues and expenses are translated to Canadian dollars at the monthly average exchange rates. Provisions
for depletion, depreciation and amortization are translated at the same rate as the related assets. Gains or losses on translation of
integrated foreign operations and foreign currency balances are included in the consolidated statements of earnings.
(K) reVenue recoGnition and coStS oF GoodS Sold
Revenue from the production of crude oil and natural gas is recognized when title passes to the customer, delivery has taken place
and collection is reasonably assured. The Company assesses customer creditworthiness, both before entering into contracts and
throughout the revenue recognition process.
Revenue as reported represents the Company’s share and is presented before royalty payments to governments and other mineral
interest owners. Revenue, net of royalties represents the Company’s share after royalty payments to governments and other
mineral interest owners.
Related costs of goods sold are comprised of production; transportation and blending; and depletion, depreciation and amortization
expenses. These amounts have been separately presented in the consolidated statements of earnings.
(l) tranSportation and BlendinG
Transportation and blending costs incurred to transport crude oil and natural gas to customers are recorded as a separate cost in
the consolidated statements of earnings.
(M) production SHarinG contractS
Production generated from Offshore West Africa is currently shared under the terms of various Production Sharing Contracts
(“PSCs”). Revenues are divided into cost recovery oil and profit oil. Cost recovery oil allows the Company to recover its capital
and production costs and the costs carried by the Company on behalf of the respective Government State Oil Companies (the
“Governments”). Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a
portion has been allocated to the Governments. The Governments’ share of profit oil attributable to the Company’s equity interest
is allocated to royalty expense and current income tax expense in accordance with the terms of the PSCs.
80
CANAD IA N NATU RAL
(n) petroleuM reVenue taX
The Company accounts for the UK petroleum revenue tax (“PRT”) by the life-of-the-field method. The total future liability or
recovery of PRT is estimated using proved and probable reserves and anticipated future sales prices and costs. The estimated future
PRT is then apportioned to accounting periods on the basis of total estimated future operating income. Changes in the estimated
total future PRT are accounted for prospectively.
(o) incoMe taX
The Company follows the liability method of accounting for income taxes. Under this method, future income tax assets and
liabilities are recognized based on the estimated tax effects of temporary differences in the carrying value of assets and liabilities
in the consolidated financial statements and their respective tax bases, using income tax rates substantively enacted or enacted as
of the consolidated balance sheet date. The effect of a change in income tax rates on the future income tax assets and liabilities is
recognized in net earnings in the period of the change.
Taxable income arising from the conventional crude oil and natural gas business in Canada is primarily generated through
partnerships, with the related income taxes payable in subsequent periods. Accordingly, North America current and future income
taxes have been provided on the basis of this corporate structure.
(p) StocK-BaSed coMpenSation planS
The Company accounts for stock-based compensation using the intrinsic value method as the Company’s Stock Option Plan (the
“Option Plan”) provides current employees with the right to elect to receive common shares or a direct cash payment in exchange
for options surrendered. A liability for potential cash settlements under the Option Plan is accrued over the vesting period of the
stock options based on the difference between the exercise price of the stock options and the market price of the Company’s
common shares, after consideration of an estimated forfeiture rate. This liability is revalued at each reporting date to reflect
changes in the market price of the Company’s common shares and actual forfeitures, with the net change recognized in net
earnings, or capitalized during the construction period in the case of the Horizon Project. When stock options are surrendered for
cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares under the
Option Plan, consideration paid by employees and any previously recognized liability associated with the stock options are recorded
as share capital.
The Company has an employee stock savings plan and a stock bonus plan. Contributions to the employee stock savings plan
are recorded as compensation expense at the time of the contribution. Contributions to the stock bonus plan are recognized as
compensation expense over the related vesting period.
(Q) Financial inStruMentS
The Company classifies its financial instruments into one of the following categories: held-for-trading financial assets and financial
liabilities; held-to-maturity investments, loans and receivables; available-for-sale financial assets; and other financial liabilities. All
financial instruments are required to be measured at fair value on initial recognition. Measurement in subsequent periods is
dependent on the classification of the respective financial instrument.
Held-for-trading financial instruments are subsequently measured at fair value with changes in fair value recognized in net
earnings. Available-for-sale financial assets are subsequently measured at fair value with changes in fair value recognized in other
comprehensive income, net of tax. All other categories of financial instruments are measured at amortized cost using the effective
interest method.
Cash and cash equivalents are classified as held-for-trading and are measured at fair value. Accounts receivable are classified as
loans and receivables. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as
other financial liabilities. Although the Company does not intend to trade its derivative financial instruments, risk management
assets and liabilities are classified as held-for-trading for accounting purposes unless formally designated as hedges.
Transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability and original issue
discounts on long-term debt have been included in the carrying value of the related financial asset or liability and are amortized to
consolidated net earnings over the life of the financial instrument using the effective interest method.
(r) riSK ManaGeMent actiVitieS
The Company uses derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures.
These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes.
Effective January 1, 2007, all derivative financial instruments are recognized on the consolidated balance sheet at estimated fair
value at each balance sheet date. The estimated fair value of derivative financial instruments is determined based on appropriate
internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of
assumptions concerning the amount and timing of future cash flows and discount rates.
The Company documents all derivative financial instruments that are formally designated as hedging transactions at the inception
of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the hedging
relationship is evaluated, both at inception of the hedge and on an ongoing basis.
CA NA DIAN NATURAL
81
The Company periodically enters into commodity price contracts to manage anticipated sales of crude oil and natural gas production
in order to protect cash flow for capital expenditure programs. The effective portion of changes in the fair value of derivative
commodity price contracts formally designated as cash flow hedges is initially recognized in other comprehensive income and
is reclassified to risk management activities in consolidated net earnings in the same period or periods in which the crude oil or
natural gas is sold. The ineffective portion of changes in the fair value of these designated contracts is immediately recognized in
risk management activities in consolidated net earnings. All changes in the fair value of non-designated crude oil and natural gas
commodity price contracts are recognized in risk management activities in consolidated net earnings.
The Company enters into interest rate swap contracts to manage its fixed to floating interest rate mix on certain of its long-term
debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal
amounts on which the payments are based. Changes in the fair value of interest rate swap contracts designated as fair value
hedges and corresponding changes in the fair value of the hedged long-term debt are included in interest expense in consolidated
net earnings. Changes in the fair value of non-designated interest rate swap contracts are included in risk management activities
in consolidated net earnings.
Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt.
The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal
amounts on which the payments are based. Changes in the fair value of the foreign exchange component of cross currency swap
contracts designated as cash flow hedges are included in foreign exchange in consolidated net earnings. The effective portion
of changes in the fair value of the interest rate component of cross currency swap contracts designated as cash flow hedges is
initially included in other comprehensive income and is reclassified to interest expense when realized, with the ineffective portion
recognized in risk management activities in consolidated net earnings. Changes in the fair value of non-designated cross currency
swap contracts are included in risk management activities in consolidated net earnings.
Realized gains or losses on the termination of financial instruments that have been designated as cash flow hedges are deferred
under accumulated other comprehensive income on the consolidated balance sheets and amortized into consolidated net earnings
in the period in which the underlying hedged item is recognized. In the event a designated hedged item is sold, extinguished
or matures prior to the termination of the related derivative instrument, any unrealized derivative gain or loss is recognized
immediately in consolidated net earnings. Realized gains or losses on the termination of financial instruments that have not been
designated as hedges are recognized in consolidated net earnings immediately.
Upon termination of an interest rate swap designated as a fair value hedge, the interest rate swap is de-recognized on the balance
sheet and the related long-term debt hedged is no longer revalued for changes in fair value. The fair value adjustment on the
long-term debt at the date of termination of the interest rate swap is amortized to interest expense over the remaining term of
the debt.
Foreign currency forward contracts are periodically used to manage foreign currency cash management requirements. The foreign
currency forward contracts involve the purchase or sale of an agreed upon amount of US dollars at a specified future date at
forward exchange rates. Changes in the fair value of the foreign currency forward contracts are included in risk management
activities in consolidated net earnings.
Embedded derivatives are derivatives that are included in a non-derivative host contract. Embedded derivatives are recorded at
fair value separately from the host contract when their economic characteristics and risks are not clearly and closely related to the
host contract.
(S) coMpreHenSiVe incoMe
Comprehensive income is comprised of the Company’s net earnings and other comprehensive income. Other comprehensive
income includes the effective portion of changes in the fair value of derivative financial instruments designated as cash flow hedges
and foreign currency translation gains and losses on the net investment in self-sustaining foreign operations. Other comprehensive
income is shown net of related income taxes.
(t) per coMMon SHare aMountS
The Company uses the treasury stock method to determine the dilutive effect of stock options and other dilutive instruments. This
method assumes that proceeds received from the exercise of in-the-money stock options not accounted for as a liability are used
to purchase common shares at the average market price during the year. The Company’s Option Plan described in note 9 results in
a liability and expense for all outstanding stock options. As such, the potential common shares associated with the stock options
are not included in the calculation of diluted earnings per share. The dilutive effect of other convertible securities is calculated
by applying the “if-converted” method, which assumes that the securities are converted at the beginning of the period and that
income items are adjusted to net earnings.
82
CANAD IA N NATU RAL
(u) recentlY iSSued accountinG StandardS under canadian Gaap
Effective January 1, 2009, the Company will adopt the following new accounting standard issued by the CICA:
Goodwill and intangible assets
n
Section 3064 – “Goodwill and Intangible Assets” replaces Section 3062 – “Goodwill and Other Intangible Assets” and Section
3450 – “Research and Development Costs”. In addition, EIC-27 – “Revenue and Expenditures during the Pre-Operating Period”
has been withdrawn. The new standard addresses when an internally generated intangible asset meets the definition of an
asset. The adoption of this standard will not have a material impact on the Company’s financial statements.
(V) international Financial reportinG StandardS
In February 2008, the CICA’s Accounting Standards Board confirmed that Canadian publicly accountable entities will be required
to adopt International Financial Reporting Standards (“IFRS”) as promulgated by the International Accounting Standards Board in
place of Canadian GAAP effective January 1, 2011. The Company is currently assessing which accounting policies will be affected
by the change to IFRS and the potential impact of these changes on its financial position and results of operations.
(W) coMparatiVe FiGureS
Certain prior year figures have been reclassified to conform to the presentation adopted in 2008.
2. Changes in aCCoUnting poliCies
Effective January 1, 2008, the Company adopted the following new accounting and disclosure standards issued by the CICA:
n
n
n
Section 1535 – “Capital Disclosures” requires entities to disclose their objectives, policies and processes for managing capital, as
well as quantitative data about capital. The standard also requires the disclosure of any externally imposed capital requirements
and compliance with those requirements. The standard does not define capital. This standard affected disclosure only and did
not impact the Company’s accounting for capital (note 11).
Section 3031 – “Inventories” replaces Section 3030 – “Inventories” and establishes new standards for the measurement of cost
of inventories and expands disclosure requirements for inventories. Adoption of this standard did not have a material impact
on the Company’s financial statements.
Section 3862 – “Financial Instruments – Disclosure” and Section 3863 – “Financial Instruments – Presentation” replace Section
3861 – “Financial Instruments – Disclosure and Presentation”. Section 3862 enhances disclosure requirements concerning risks
and requires quantitative and qualitative disclosures about exposures to risks arising from financial instruments. Section 3863
carries forward the presentation requirements from Section 3861 unchanged. These standards affected disclosures only and
did not impact the Company’s accounting for financial instruments (note 13).
3. other long-term assets
Risk management (note 13)
Other
Less: current portion
4. propertY, plant anD eQUipment
2008
2007
$
2,119 $
24
2,143
1,851
$
292 $
–
49
49
18
31
2008
accumulated
depletion and
Cost depreciation
2007
Accumulated
depletion and
depreciation
net
Cost
$
Conventional crude oil and natural gas
North America
North Sea
Offshore West Africa
Other
Horizon Project
Midstream
Head office
36,532 $
14,381 $
22,151 $
34,195 $
12,162 $
4,167
2,671
40
12,573
278
190
2,119
777
14
–
72
122
2,048
1,894
26
12,573
206
68
3,174
1,833
39
8,651
269
170
1,446
645
14
–
64
98
$
56,451 $
17,485 $
38,966 $
48,331 $
14,429 $
Net
22,033
1,728
1,188
25
8,651
205
72
33,902
During the year ended December 31, 2008, the Company capitalized directly attributable administrative costs of $55 million
(2007 – $47 million, 2006 – $41 million) in the North Sea and Offshore West Africa, related to exploration and development and
$404 million (2007 – $312 million, 2006 – $255 million) in North America, related to the Horizon Project construction.
During the year ended December 31, 2008, the Company capitalized $481 million (2007 – $356 million, 2006 – $196 million) in
construction period interest costs related to the Horizon Project.
CA NA DIAN NATURAL
83
Included in property, plant and equipment are unproved land and major development projects that are not currently subject to
depletion or depreciation:
Conventional crude oil and natural gas
North America
North Sea
Offshore West Africa
Other
Horizon Project
$
2008
2007
2,271 $
12
595
26
12,573
2,259
10
138
25
8,651
$
15,477 $
11,083
The Company has used the following estimated benchmark future prices (“escalated pricing”) in its full cost ceiling tests for
conventional crude oil and natural gas activities prepared in accordance with Canadian GAAP, as at December 31, 2008:
Crude oil and ngls
North America
WTI at Cushing (US$/bbl)
$
Hardisty Heavy 12˚ API (C$/bbl) $
Edmonton Par (C$/bbl)
$
North Sea and Offshore West Africa
$
North Sea Brent (US$/bbl)
natural gas
North America
Henry Hub Louisiana (US$/mmbtu) $
$
AECO (C$/mmbtu)
Huntingdon/Sumas (C$/mmbtu) $
2009
2010
2011
2012
2013
53.73 $
47.05 $
65.35 $
63.41 $
54.58 $
72.78 $
69.53 $
59.96 $
79.95 $
79.59 $
67.53 $
86.57 $
92.01
74.08
94.97
51.73 $
61.37 $
67.45 $
77.47 $
89.84
6.30 $
6.82 $
6.82 $
7.32 $
7.56 $
7.56 $
7.56 $
7.84 $
7.84 $
8.49 $
8.38 $
8.38 $
9.74
9.20
9.20
Average
annual
increase
thereafter
2.0%
2.0%
2.0%
2.0%
2.0%
2.2%
2.2%
84
CANAD IA N NATU RAL
5. long-term DeBt
Canadian dollar denominated debt
Bank credit facilities
Bankers’ acceptances
Medium-term notes
5.50% unsecured debentures due December 17, 2010
4.50% unsecured debentures due January 23, 2013
4.95% unsecured debentures due June 1, 2015
Us dollar denominated debt
Senior unsecured notes
Adjustable rate due May 27, 2009 (2008 – US$31 million, 2007 – US$62 million)
US dollar debt securities
7.80% due July 2, 2008 (2008 – US$nil, 2007 – US$8 million)
6.70% due July 15, 2011 (2008 – US$400 million, 2007 – US$400 million)
5.45% due October 1, 2012 (2008 – US$350 million, 2007 – US$350 million)
5.15% due February 1, 2013 (2008 – US$400 million, 2007 – US$nil)
4.90% due December 1, 2014 (2008 – US$350 million, 2007 – US$350 million)
6.00% due August 15, 2016 (2008 – US$250 million, 2007 – US$250 million)
5.70% due May 15, 2017 (2008 – US$1,100 million, 2007 – US$1,100 million)
5.90% due February 1, 2018 (2008 – US$400 million, 2007 – US$nil)
7.20% due January 15, 2032 (2008 – US$400 million, 2007 – US$400 million)
6.45% due June 30, 2033 (2008 – US$350 million, 2007 – US$350 million)
5.85% due February 1, 2035 (2008 – US$350 million, 2007 – US$350 million)
6.50% due February 15, 2037 (2008 – US$450 million, 2007 – US$450 million)
6.25% due March 15, 2038 (2008 – US$1,100 million, 2006 – US$1,100 million)
6.75% due February 1, 2039 (2008 – US$400 million, 2007 – US$nil)
Less – original issue discount on senior unsecured notes and US dollar debt securities (1)
Fair value impact of interest rate swaps on US dollar debt securities (2)
Long-term debt before transaction costs
Less: transaction costs (1) (3)
Less: current portion
2008
2007
$
4,073 $
4,696
400
400
400
5,273
400
400
400
5,896
38
61
–
490
429
490
429
306
1,346
490
490
429
429
551
1,346
490
(23)
7,730
68
7,798
13,071
(55)
13,016
420
$
12,596 $
8
395
346
–
346
247
1,087
–
395
346
346
445
1,087
–
(23)
5,086
9
5,095
10,991
(51)
10,940
–
10,940
(1) The Company has included unamortized original issue discounts and directly attributable transaction costs in the carrying value of the outstanding debt.
(2) The carrying value of US$350 million of 5.45% notes due October 2012 and US$350 million of 4.90% notes due December 2014 have been adjusted by
(3)
$68 million (2007 – $9 million) to reflect the fair value impact of hedge accounting.
Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other
professional fees.
Bank credit Facilities
As at December 31, 2008, the Company had in place unsecured bank credit facilities of $6,232 million, comprised of:
n
n
n
n
n
a $125 million demand credit facility;
a non-revolving syndicated credit facility of $2,350 million maturing October 2009;
a revolving syndicated credit facility of $2,230 million maturing June 2012;
a revolving syndicated credit facility of $1,500 million maturing June 2012; and
a £15 million demand credit facility related to the Company’s North Sea operations.
During 2007, one of the revolving syndicated credit facilities was increased from $1,825 million to $2,230 million and a
$500 million demand credit facility was terminated. The revolving syndicated credit facilities were also extended and now mature
June 2012. Both facilities are extendible annually for one year periods at the mutual agreement of the Company and the lenders.
If the facilities are not extended, the full amount of the outstanding principal will be repayable on the maturity date. Borrowings
under these facilities can be made by way of Canadian dollar and US dollar bankers’ acceptances, and LIBOR, US base rate and
Canadian prime loans.
In conjunction with the closing of the acquisition of Anadarko Canada Corporation (“ACC”) in November 2006 (note 16),
the Company executed a $3,850 million, non-revolving syndicated credit facility maturing in October 2009. In March 2007,
$1,500 million was repaid, reducing the facility to $2,350 million. During 2009, the Company plans to fully retire this facility from
its existing borrowing capacity under its other long-term bank credit facilities, which were $2,050 million at December 31, 2008,
CA NA DIAN NATURAL
85
supported by cash flow from operating activities, including the commodity risk management activities. In accordance with these
plans, and repayments of $420 million made subsequent to December 31, 2008 on this facility, $420 million has been classified
as current.
The weighted average interest rate of the bank credit facilities outstanding at December 31, 2008, was 2.2% (2007 – 5.2%).
In addition to the outstanding debt, letters of credit and financial guarantees aggregating $372 million, including $300 million
related to the Horizon Project, were outstanding at December 31, 2008.
Medium-term notes
The Company has $2,600 million remaining on its outstanding $3,000 million base shelf prospectus filed in September 2007 that
allows for the issue of medium-term notes in Canada until October 2009. If issued, these securities will bear interest as determined
at the date of issuance.
In December 2007, the Company issued $400 million of unsecured notes maturing December 2010, bearing interest at 5.50%.
Proceeds from the securities issued were used to repay bankers’ acceptances under the Company’s bank credit facilities.
During 2007, $125 million of the 7.40% unsecured debentures due March 1, 2007 were repaid.
Senior unsecured notes
The adjustable rate senior unsecured notes bear interest at 6.54%, with the final annual principal repayment of US$31 million due
in May 2009. During 2008, US$31 million of the senior unsecured notes were repaid.
uS dollar debt Securities
In January 2008, the Company issued US$1,200 million of unsecured notes under a US base shelf prospectus, comprised of
US$400 million of 5.15% unsecured notes due February 2013, US$400 million of 5.90% unsecured notes due February 2018, and
US$400 million of 6.75% unsecured notes due February 2039. Proceeds from the securities issued were used to repay bankers’
acceptances under the Company’s bank credit facilities. After issuing these securities, the Company has US$1,800 million remaining
on its outstanding US$3,000 million base shelf prospectus filed in September 2007 that allows for the issue of US dollar debt securities
in the United States until October 2009. If issued, these securities will bear interest as determined at the date of issuance.
During 2008, US$8 million of US dollar debt securities were repaid.
In March 2007, the Company issued US$2,200 million of unsecured notes, comprised of US$1,100 million of unsecured notes
maturing May 2017, and US$1,100 million of unsecured notes maturing March 2038, bearing interest at 5.70% and 6.25%,
respectively. Concurrently, the Company entered into cross currency swaps to fix the Canadian dollar interest and principal
repayment amounts on the entire US$1,100 million of unsecured notes due May 2017 at 5.10% and C$1,287 million (note 13).
The Company also entered into a cross currency swap to fix the Canadian dollar interest and principal repayment amounts on
US$550 million of unsecured notes due March 2038 at 5.76% and C$644 million (note 13). Proceeds from the securities issued
were used to repay bankers’ acceptances under the Company’s bank credit facilities.
During 2008, the Company terminated the interest rate swaps that had been designated as a fair value hedge of US$350 million
of 5.45% unsecured notes due October 2012. Accordingly, the Company ceased revaluing the related debt from the date of
termination of the interest rate swaps for subsequent changes in fair value. The fair value adjustment of $20 million at the date of
termination is being amortized to interest expense over the remaining term of the debt.
During 2007, the Company de-designated the portion of the US dollar denominated debt previously hedged against its net
investment in US dollar based self-sustaining foreign operations. Accordingly, all foreign exchange (gains) losses arising each period
on US dollar denominated long-term debt are now recognized in the consolidated statements of earnings.
required debt repayments
Required debt repayments are as follows:
Year
2009
2010
2011
2012
2013
Thereafter
Repayment
2,385
400
490
429
890
6,707
$
$
$
$
$
$
No debt repayments are reflected in the above table for $1,725 million of revolving bank credit facilities due to the extendable
nature of the facilities. Should the bank credit facilities not be extended by mutual agreement of the Company and the lenders,
the entire amounts due under these facilities would be due in 2012.
86
CANAD IA N NATU RAL
6. other long-term liaBilities
Asset retirement obligations
Stock-based compensation
Risk management (note 13)
Other
Less: current portion
asset retirement obligations
$
2008
1,064 $
171
–
119
1,354
230
$
1,124 $
2007
1,074
529
1,474
101
3,178
1,617
1,561
At December 31, 2008, the Company’s total estimated undiscounted costs to settle its asset retirement obligations were approximately
$4,474 million (2007 – $4,426 million). Payments to settle these asset retirement obligations will occur on an ongoing basis over
a period of approximately 60 years and have been discounted using a weighted average credit-adjusted risk-free interest rate of
6.7% (2007 – 6.6%; 2006 – 6.7%). A reconciliation of the discounted asset retirement obligations is as follows:
Balance – beginning of year
Liabilities incurred
Liabilities acquired (note 16)
Liabilities disposed
Liabilities settled
Asset retirement obligation accretion
Revision of estimates
Foreign exchange
Balance – end of year
Stock-based compensation
2008
2007
$
$
1,074 $
18
3
–
(38)
71
(156)
92
1,064 $
1,166 $
21
–
(65)
(71)
70
35
(82)
1,074 $
2006
1,112
26
56
–
(75)
68
(21)
–
1,166
The Company recognizes a liability for potential cash settlements under its Option Plan. The current portion represents the maximum
amount of the liability payable within the next twelve month period if all vested options are surrendered for cash settlement.
Balance – beginning of year
Stock-based compensation
Cash payment for options surrendered
Transferred to common shares
Capitalized to Horizon Project
Balance – end of year
Less: current portion
7. emploYee fUtUre Benefits
2008
2007
2006
$
529 $
(52)
(207)
(76)
(23)
171
159
744 $
193
(375)
(91)
58
529
390
$
12 $
139 $
891
139
(264)
(101)
79
744
611
133
In connection with the acquisition of ACC, the Company assumed obligations to provide defined contribution pension benefits to
certain ACC employees continuing their employment with the Company, and defined benefit pension and other post-retirement
benefits to former ACC employees, under registered and unregistered pension plans.
The estimated future cost of providing defined benefit pension and other post-retirement benefits to former ACC employees is
actuarially determined using management’s best estimates of demographic and financial assumptions. The discount rate of 7.0%
(2007 – 5.5%) used to determine accrued benefit obligations is based on a year-end market rate of interest for high-quality debt
instruments with cash flows that match the timing and amount of expected benefit payments. Company contributions to the
defined contribution plan are expensed as incurred.
The benefit obligation under the registered pension plan at December 31, 2008 was $27 million (2007 – $32 million). As required
by government regulations, the Company has set aside funds with an independent trustee to meet these benefit obligations. As at
December 31, 2008, these plan assets had a fair value of $34 million (2007 – $47 million). The unregistered pension plan and other
post-retirement benefits are unfunded and have a benefit obligation of $9 million at December 31, 2008 (2007 – $10 million).
CA NA DIAN NATURAL
87
8. taXes
taxes other than income tax
Current PRT expense
Deferred PRT (recovery) expense
Provincial capital taxes and surcharges
income tax
The provision for income tax is as follows:
Current income tax – North America
Current income tax – North Sea
Current income tax – Offshore West Africa
Current income tax expense
Future income tax expense (recovery)
Income tax expense (recovery)
2008
2007
2006
$
$
210 $
(67)
35
178 $
97 $
44
24
165 $
196
37
23
256
2008
2007
2006
$
33 $
96 $
340
128
501
1,607
$
2,108 $
210
74
380
(456)
(76) $
143
30
49
222
652
874
The provision for income tax is different from the amount computed by applying the combined statutory Canadian federal and
provincial income tax rates to earnings before taxes. The reasons for the difference are as follows:
Canadian statutory income tax rate
Income tax provision at statutory rate
Effect on income taxes of:
Non-deductible portion of Canadian crown payments
Canadian resource allowance
Deductible UK petroleum revenue tax
Foreign and domestic tax rate differentials
North America income tax rate and other legislative changes
UK income tax rate changes
Côte d’Ivoire income tax rate changes
Non-taxable portion of foreign exchange loss (gain)
Stock options exercised in shares
Other
2008
29.8%
2007
32.5%
$
2,166 $
877 $
–
–
(72)
(5)
(19)
–
(22)
127
6
(73)
–
–
(71)
(25)
(864)
–
–
(96)
63
40
Income tax expense (recovery)
$
2,108 $
(76) $
The following table summarizes the temporary differences that give rise to the net future income tax asset and liability:
2006
34.9%
1,275
131
(129)
(82)
6
(438)
110
(67)
5
35
28
874
Future income tax liabilities
Property, plant and equipment
Timing of partnership items
Unrealized foreign exchange gain on long-term debt
Unrealized risk management activities
Other
Future income tax assets
Asset retirement obligations
Loss carryforwards for income tax
Stock-based compensation
Unrealized risk management activities
Other
Deferred petroleum revenue tax
Net future income tax liability
Less: current portion of future income tax liability (asset)
Future income tax liability
2008
2007
$
$
6,303 $
1,276
13
651
–
(372)
(62)
(38)
–
(7)
(43)
7,721
585
7,136 $
5,695
1,288
199
–
55
(380)
(104)
(125)
(399)
–
20
6,249
(480)
6,729
During 2008, substantively enacted or enacted income tax rate changes resulted in a reduction of future income tax liabilities of
approximately $19 million in British Columbia and approximately $22 million in Côte d’Ivoire.
During 2007, substantively enacted or enacted income tax rate and other legislative changes resulted in a reduction of future
income tax liabilities of approximately $864 million in North America.
88
CANAD IA N NATU RAL
During 2006, enacted income tax rate changes resulted in a reduction of future income tax liabilities of approximately $438 million
in North America, an increase of future income tax liabilities of approximately $110 million in the UK North Sea and a reduction of
future income tax liabilities of approximately $67 million in Côte d’Ivoire.
During 2003, the Canadian Federal Government enacted legislation to phase in changes to the taxation of resource income by
2007. The legislation reduced the corporate income tax rate on resource income to 21%, the deduction for resource allowance
was phased out and a deduction for actual crown royalties paid was phased in. Subsequently, as a result of enacted income tax rate
changes in 2007, the Canadian Federal corporate income tax rate is being reduced from 21% in 2007 to 15% in 2012.
9. share Capital
authorized
200,000 Class 1 preferred shares with a stated value of $10.00 each.
Unlimited number of common shares without par value.
issued
Common shares
Balance – beginning of year
Issued upon exercise of stock options
Previously recognized liability on
2008
2007
number of
shares
(thousands)
amount
Number of
shares
(thousands)
539,729 $
1,262
2,674
18
537,903 $
1,826
stock options exercised for common shares
–
76
–
Balance – end of year
normal course issuer Bid
540,991 $
2,768
539,729 $
Amount
2,562
21
91
2,674
The Company did not renew the Normal Course Issuer Bid during 2008. During 2007 and 2008, the Company did not purchase
any common shares for cancellation (2006 – 485,000 common shares were purchased at an average price of $57.33 per common
share for a total cost of $28 million).
dividend policy
The Company has paid regular quarterly dividends in January, April, July and October of each year since 2001. The dividend policy
undergoes a periodic review by the Board of Directors and is subject to change.
In March 2009, the Board of Directors set the Company’s regular quarterly dividend at $0.105 per common share (2008 – $0.10
per common share, 2007 – $0.085 per common share).
Stock options
The Company’s Option Plan provides for granting of stock options to employees. Stock options granted under the Option Plan have
terms ranging from five to six years to expiry and vest over a five-year period. The exercise price of each stock option granted is
determined at the closing market price of the common shares on the Toronto Stock Exchange on the day prior to the grant. Each
stock option granted provides the holder the choice to purchase one common share of the Company at the stated exercise price or
receive a cash payment equal to the difference between the stated exercise price and the market price of the Company’s common
shares on the date of surrender of the option.
The following table summarizes information relating to stock options outstanding at December 31, 2008 and 2007:
Outstanding – beginning of year
Granted
Surrendered for cash settlement
Exercised for common shares
Forfeited
Outstanding – end of year
Exercisable – end of year
2008
2007
Weighted
stock
options
average
(thousands) exercise price
Stock
options
(thousands)
Weighted
average
exercise price
30,659 $
7,705 $
(3,702) $
(1,262) $
(2,438) $
30,962 $
8,809 $
47.23
53.38
25.60
14.61
56.56
51.94
44.58
34,431 $
7,502 $
(7,249) $
(1,826) $
(2,199) $
30,659 $
7,640 $
33.77
70.03
16.10
11.71
46.46
47.23
30.00
CA NA DIAN NATURAL
89
The range of exercise prices of stock options outstanding and exercisable at December 31, 2008 was as follows:
range of exercise prices
$11.83 – $19.99
$20.00 – $29.99
$30.00 – $39.99
$40.00 – $49.99
$50.00 – $59.99
$60.00 – $69.99
$70.00 – $79.99
$80.00 – $89.99
$90.00 – $92.50
stock options outstanding
stock options exercisable
stock options
outstanding
(thousands)
Weighted
average
remaining
term (years)
Weighted
average
exercise
price
stock
options
exercisable
(thousands)
Weighted
average
exercise
price
2,909
3,023
865
6,845
5,001
4,884
6,526
–
909
30,962
0.51 $
1.30 $
1.66 $
5.01 $
2.75 $
3.15 $
4.20 $
– $
5.53 $
3.32 $
16.44
25.57
33.27
46.37
58.06
61.54
70.76
–
92.50
51.94
1,918 $
1,454 $
397 $
203 $
1,860 $
1,762 $
1,215 $
– $
– $
8,809 $
16.13
25.42
33.30
46.29
57.93
61.60
70.67
–
–
44.58
10. aCCUmUlateD other Comprehensive inCome
The components of accumulated other comprehensive income, net of taxes, were as follows:
Derivative financial instruments designated as cash flow hedges
Foreign currency translation adjustment
2008
2007
$
$
119 $
143
262 $
101
(29)
72
During the next twelve months, $19 million is expected to be reclassified to net earnings from accumulated other comprehensive
income.
During 2008, the Company determined that its operations in Offshore West Africa were now operationally and financially
independent and the current rate method of translation was adopted for translation of the financial statements of the Offshore
West African subsidiaries. This change has been applied prospectively. The impact of this change was to increase assets by
$32 million, decrease liabilities by $4 million and increase accumulated other comprehensive income by $36 million.
11. Capital DisClosUres
As required by Canadian GAAP, effective January 1, 2008, the Company must provide certain disclosures regarding its objectives,
policies and processes for managing capital, as well as provide certain quantitative data about capital. As the Company does not
have any externally imposed regulatory capital requirements, for the purposes of this disclosure, the Company has defined its
capital to mean its long-term debt and consolidated shareholders’ equity, as determined each reporting date.
The Company’s objectives when managing its capital structure are to maintain financial flexibility and balance to enable the
Company to access capital markets to sustain its on-going operations and to support its growth strategies. The Company primarily
monitors capital on the basis of an internally derived non-GAAP financial measure referred to as its “debt to book capitalization
ratio”, which is the arithmetic ratio of current and long-term debt divided by the sum of the carrying value of shareholders’ equity
plus current and long-term debt. The Company aims over time to maintain its debt to book capitalization ratio in the range of 35%
to 45%. However, the Company may exceed the high end of such target range if it is investing in capital projects, undertaking
acquisitions, or in periods of lower commodity prices. The Company may be below the low end of the target range when cash flow
from operating activities is greater than current investment activities. The ratio is currently near the midpoint of the target range at
41% including the impact of capital spending on the Horizon Project.
Readers are cautioned that as the debt to book capitalization ratio has no defined meaning under GAAP, this financial measure
may not be comparable to similar measures provided by other reporting entities. Further, there can be no assurances that the
Company will continue to use this measure to monitor capital or will not alter the method of calculation of this measure at some
point in the future.
Long-term debt (1)
Total shareholders’ equity
Debt to book capitalization
(1)
Includes the current portion of long-term debt.
90
CANAD IA N NATU RAL
$
$
2008
13,016 $
18,374 $
41%
2007
10,940
13,321
45%
12. net earnings per Common share
(thousands of shares)
Weighted average common shares outstanding – basic and diluted
Net earnings – basic and diluted
Net earnings per common share – basic and diluted
2008
2007
540,647
539,336
$
$
4,985 $
9.22 $
2,608 $
4.84 $
2006
537,339
2,524
4.70
13. finanCial instrUments
The carrying values of the Company’s financial instruments by category are as follows:
asset (liability)
Cash and cash equivalents
Accounts receivable
Risk management
Accounts payable
Accrued liabilities
Other long-term liabilities
Long-term debt (1)
(1)
Includes the current portion of long-term debt.
Asset (liability)
Cash and cash equivalents
Accounts receivable
Accounts payable
Accrued liabilities
Risk management
Other long-term liabilities
Long-term debt
2008
held for
trading at
fair value
other
financial
liabilities at
amortized
cost
27 $
–
2,119
–
–
–
–
–
–
–
(383)
(1,802)
(105)
(13,016)
loans and
receivables at
amortized
cost
$
– $
1,059
–
–
–
–
–
$
1,059 $
2,146 $
(15,306)
Loans and
receivables at
amortized
cost
$
– $
1,143
–
–
–
–
–
2007
Held for
trading at
fair value
21 $
–
–
–
(1,474)
–
–
$
1,143 $
(1,453) $
Other
financial
liabilities at
amortized
cost
–
–
(379)
(1,567)
–
(86)
(10,940)
(12,972)
The carrying value of the Company’s financial instruments approximates their fair value, except for fixed rate long-term debt as
noted below:
Fixed rate long-term debt (1)
$
8,943 $
7,649 $
6,244 $
6,259
(1)
The carrying value of US$350 million of 5.45% notes due October 2012, and US$350 million of 4.90% notes due December 2014, have been adjusted by $68 million
(2007 – $9 million) to reflect the fair value impact of hedge accounting.
2008
2007
Carrying value
fair value
Carrying value
Fair value
CA NA DIAN NATURAL
91
risk Management
The changes in estimated fair values of derivative financial instruments included in the risk management asset (liability) were
recognized in the financial statements as follows:
asset (liability)
Balance – beginning of year
Retained earnings effect of adoption of financial instruments standards
Net cost of outstanding put options
Net change in fair value of outstanding derivative financial instruments attributable to:
Risk management activities
Interest expense
Foreign exchange
Other comprehensive income
Settlement of interest rate swaps
Add: put premium financing obligations (1)
Balance – end of year
Less: current portion
2008
2007
Risk
risk
management
management
mark-to-market mark-to-market
$
(1,474) $
–
297
3,090
60
449
18
(20)
2,420
(301)
2,119
1,851
$
268 $
128
14
58
(1,400)
9
(350)
125
–
(1,416)
(58)
(1,474)
(1,227)
(247)
(1)
The Company has negotiated payment of put option premiums with various counterparties at the time of actual settlement of the respective options. These obligations
have been reflected in the net risk management asset (liability).
Net (gains) losses from risk management activities for the years ended December 31 were as follows:
Net realized risk management loss
Net unrealized risk management (gain) loss
Financial risk Factors
a) Market risk
2008
2007
$
$
1,860 $
(3,090)
(1,230) $
162 $
1,400
1,562 $
2006
1,325
(1,013)
312
Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market
prices. The Company’s market risk is comprised of commodity price risk, interest rate risk, and foreign currency exchange risk.
commodity price risk management
The Company uses commodity derivative financial instruments to manage its exposure to commodity price risk associated with
the sale of its future crude oil and natural gas production. At December 31, 2008, the Company had the following net derivative
financial instruments outstanding to manage its commodity price exposures:
remaining term
volume
Weighted average price
index
Crude oil
Crude oil price collars
Crude oil puts
Jan 2009 – Dec 2009
Apr 2009 – Jun 2009
Jan 2009 – Dec 2009
25,000 bbl/d
4,000 bbl/d
92,000 bbl/d
US$70.00 – US$111.56
US$70.00 – US$90.00
US$100.00
WTI
WTI
WTI
The net cost of outstanding put options of US$242 million will be settled in 2009.
remaining term
volume
Weighted average price
index
natural gas
Natural gas price collars (1)
Jan 2009 – Mar 2009
500,000 GJ/d
C$6.00 – C$8.63
AECO
(1) Subsequent to December 31, 2008, the Company entered into 220,000 GJ/d of C$6.00 – C$8.00 natural gas AECO collars for the period January to December 2010.
The Company’s outstanding commodity derivative financial instruments are expected to be settled monthly based on the applicable
index pricing for the respective contract month.
There were no commodity derivative financial instruments designated as hedges at December 31, 2008.
In addition to the derivative financial instruments noted above, subsequent to December 31, 2008, the Company entered into
natural gas physical sales contracts for 400,000 GJ/d at an average fixed price of C$5.29 per GJ at AECO for the period April to
December 2009.
92
CANAD IA N NATU RAL
interest rate risk management
The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its floating
rate long-term debt. The Company enters into interest rate swap contracts to manage its fixed to floating interest rate mix on
long-term debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At December 31, 2008, the Company had the following interest rate swap
contracts outstanding:
remaining term
amount ($ millions)
fixed rate
floating rate
interest rate
Swaps – fixed to floating
(1) London Interbank Offered Rate.
Jan 2009 – Dec 2014
US$350
4.90%
LIBOR (1) + 0.38%
All interest rate related derivative financial instruments designated as hedges at December 31, 2008 were classified as fair value
hedges.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long-
term debt and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted
in other currencies in its subsidiaries and in the carrying value of its self-sustaining foreign subsidiaries. The Company periodically
enters into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on US dollar
denominated long-term debt and working capital. The cross currency swap contracts require the periodic exchange of payments
with the exchange at maturity of notional principal amounts on which the payments are based. At December 31, 2008, the
Company had the following cross currency swap contracts outstanding:
Cross currency
Swaps
remaining term
($ millions)
(US$/C$)
(US$)
(C$)
amount exchange rate
interest rate
interest rate
Jan 2009 – Aug 2016
Jan 2009 – May 2017
Jan 2009 – Mar 2038
US$250
US$1,100
US$550
1.116
1.170
1.170
6.00%
5.70%
6.25%
5.40%
5.10%
5.76%
All cross currency swap derivative financial instruments designated as hedges at December 31, 2008 were classified as cash flow
hedges.
In addition to the cross currency swap contracts noted above, the Company periodically utilizes foreign currency forward contracts
to manage certain foreign currency cash management requirements. At December 31, 2008, the Company had US$408 million of
these contracts outstanding, with terms of approximately 30 days or less.
Financial instrument sensitivities
As required by Canadian GAAP, effective January 1, 2008, the Company must provide certain quantitative sensitivities related to
its financial instruments, which are prepared on a different basis than those sensitivities currently disclosed in the Company’s other
continuous disclosure documents. The following table summarizes the annualized sensitivities of the Company’s net earnings and
other comprehensive income to changes in the fair value of financial instruments outstanding as at December 31, 2008, resulting
from changes in the specified variable, with all other variables held constant. These sensitivities are limited to the impact of changes in
a specified variable applied to financial instruments only and do not represent the impact of a change in the variable on the operating
results of the Company taken as a whole. Further, these sensitivities are theoretical, as changes in one variable may contribute to
changes in another variable, which may magnify or counteract the sensitivities. In addition, changes in fair value generally can not be
extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear.
Commodity price risk
Increase WTI US$1.00/bbl
Decrease WTI US$1.00/bbl
Increase AECO C$0.10/mcf
Decrease AECO C$0.10/mcf
interest rate risk
Increase interest rate 1%
Decrease interest rate 1%
foreign currency exchange rate risk
Increase exchange rate by US$0.01
Decrease exchange rate by US$0.01
impact on other
impact on comprehensive
income
net earnings
$
$
$
$
$
$
$
$
(32) $
32 $
(1) $
1 $
(32) $
32 $
(35) $
35 $
–
–
–
–
(27)
33
–
–
CA NA DIAN NATURAL
93
b) credit risk
Credit risk is the risk that a party to a financial instrument will cause a financial loss to the Company by failing to discharge an
obligation.
counterparty credit risk management
The Company’s accounts receivable are mainly with customers in the crude oil and natural gas industry and are subject to normal
industry credit risks. The Company manages these risks by reviewing its exposure to individual companies on a regular basis and
where appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default.
At December 31, 2008, substantially all of the Company’s accounts receivables were due within normal trade terms.
The Company is also exposed to possible losses in the event of nonperformance by counterparties to derivative financial
instruments; however, the Company manages this credit risk by entering into agreements with counterparties that are substantially
all investment grade financial institutions and other entities. At December 31, 2008, the Company had net risk management assets
of $2,119 million (December 31, 2007 – $20 million) with specific counterparties related to derivative financial instruments. The
Company believes that its counterparties currently have the financial capacity to settle outstanding obligations in the normal course
of business.
c)
liquidity risk
Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities.
Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating activities, available credit facilities, and access to debt capital markets, to
meet obligations as they become due. Due to fluctuations in the timing of the receipt and/or disbursement of operating cash flows,
the Company believes it has adequate bank credit facilities to provide liquidity.
The maturity dates for financial liabilities are as follows:
Accounts payable
Accrued liabilities
Other long-term liabilities
Long-term debt (1)
Less than
1 year
1 to less than
2 years
2 to less than
5 years
Thereafter
$
$
$
$
383 $
1,802 $
86 $
2,385 $
– $
– $
18 $
400 $
– $
– $
1 $
1,809 $
–
–
–
6,707
(1)
The long-term debt represents principal repayments only and does not reflect fair value adjustments, original issue discounts or transaction costs. No debt repayments
are reflected for $1,725 million of revolving bank credit facilities due to the extendable nature of the facilities.
14. Commitments anD ContingenCies
The Company has committed to certain payments as follows:
Product transportation
and pipeline
Offshore equipment
operating leases
Offshore drilling
Asset retirement obligations (1)
Office leases
Other
$
$
$
$
$
$
2009
2010
2011
2012
2013
Thereafter
219 $
184 $
159 $
133 $
124 $
1,175
175 $
251 $
6 $
25 $
321 $
145 $
62 $
7 $
29 $
180 $
144 $
– $
6 $
23 $
17 $
116 $
– $
6 $
2 $
12 $
117 $
– $
6 $
2 $
8 $
398
–
4,443
1
19
(1) Amounts represent management’s estimate of the future undiscounted payments to settle asset retirement obligations related to resource properties, facilities, and
production platforms, based on current legislation and industry operating practices. Amounts disclosed for the period 2009 – 2013 represent the minimum required
expenditures to meet these obligations. Actual expenditures in any particular year may exceed these minimum amounts.
The Company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. In addition,
the Company is subject to certain contractor construction claims related to the Horizon Project. The Company believes that any
liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position.
94
CANAD IA N NATU RAL
15. sUpplemental DisClosUre of Cash floW information
Changes in non-cash working capital were as follows:
Decrease (Increase) in non-cash working capital
Accounts receivable and other
Accounts payable
Accrued liabilities
Net change in non-cash working capital
Relating to:
Operating activities
Financing activities
Investing activities
Other cash flow information:
Interest paid
Taxes paid
16. BUsiness ComBinations
anadarko canada corporation
2008
2007
2006
$
$
$
$
$
$
111 $
(4)
(15)
92 $
(189) $
46
235
92 $
334 $
(456)
(402)
(524) $
(346) $
8
(186)
(524) $
2008
2007
574 $
558 $
556 $
418 $
(116)
157
(582)
(541)
(679)
37
101
(541)
2006
262
703
In November 2006, the Company completed the acquisition of all of the issued and outstanding common shares of ACC, a
subsidiary of Anadarko Petroleum Corporation, for net cash consideration of $4,641 million including working capital and other
adjustments. Substantially all of ACC’s land and production base are located in Western Canada.
The acquisition was accounted for using the purchase method. Operating results from ACC have been consolidated with the
results of the Company effective from November 2, 2006, the date of acquisition, and are reported in the North America segment.
The allocation of the net purchase price to assets acquired and liabilities assumed based on their fair values was as follows:
Net purchase price:
Net cash consideration (1)
Net purchase price allocated as follows:
Non-cash working capital deficit assumed and other
Property, plant and equipment
Long-term debt
Asset retirement obligation
Future income tax
November 2, 2006
$
4,641
$
$
(105)
6,249
(9)
(56)
(1,438)
4,641
(1) Net cash consideration was reduced by $88 million to reflect the settlement of US dollar forward contracts designated as hedges of the ACC purchase price.
CA NA DIAN NATURAL
95
17. SEGMENTED INFORMATION
The Company’s conventional crude oil and natural gas activities are conducted in three geographic segments: North America, North
Sea and Offshore West Africa. These activities include the exploration, development, production and marketing of conventional
crude oil, natural gas liquids and natural gas.
The Company’s Horizon Project is a separate segment from conventional crude oil and natural gas activities as the bitumen will
be recovered through mining operations. There are currently no revenues for this project and all directly related expenditures have
been capitalized.
Midstream activities include the Company’s pipeline operations and an electricity co-generation system. Activities that are not
included in the above segments are reported in the segmented information as other. Inter-segment eliminations include internal
transportation, electricity charges and natural gas sales.
Conventional Crude Oil and Natural Gas
Inter-segment
North America
North Sea
Offshore West Africa
Midstream
elimination and other
2008
2007
2006
2008
2007
2006
2008
2007
2006
2008
2007
2006
2008
2007
2006
2008
2006
Total
2007
Segmented revenue $ 13,496 $ 10,149 $
Less: royalties
(1,876)
(1,318)
9,066 $ 1,769 $
(1,203)
(4)
1,597 $
(3)
1,616 $
(3)
944 $
(143)
776 $
(70)
Revenue, net of royalties 11,620
8,831
7,863
1,765
1,594
1,613
801
706
Segmented expenses
1,881
Production
Transportation and blending 1,975
Depletion, depreciation
and amortization
Asset retirement
obligation accretion
Realized risk
management activities
2,236
1,861
42
1,642
1,595
1,436
1,465
457
10
2,350
1,897
317
38
35
27
129
1,022
(1)
432
16
340
30
33
390
15
297
31
303
102
1
132
2
–
94
1
165
2
–
950
(39)
911
106
1
189
2
–
$
77 $
74 $
72 $
(113) $
(53) $
(61) $ 16,173 $ 12,543 $ 11,643
–
77
25
–
8
–
–
–
74
22
–
8
–
–
–
72
23
–
8
–
–
6
(107)
(14)
(50)
(10)
–
–
–
(53)
(6)
(42)
–
–
–
–
(2,017)
(1,391)
(1,245)
(61)
14,156
11,152
10,398
(6)
(38)
2,451
1,936
2,184
1,570
1,949
1,443
–
–
–
2,683
2,863
2,391
71
70
68
1,860
162
1,325
Total segmented
expenses
7,995
5,754
5,855
810
851
1,036
237
262
298
33
30
31
(74)
(48)
(44)
9,001
6,849
7,176
Segmented earnings before
the following
$ 3,625 $
3,077 $
2,008 $
955 $
743 $
577 $
564 $
444 $
613
$
44 $
44 $
41 $
(33) $
(5) $
(17)
5,155
4,303
3,222
Non-segmented expenses
Administration
Stock-based compensation (recovery) expense
Interest, net
Unrealized risk management activities
Foreign exchange loss (gain)
Total non-segmented expenses
Earnings before taxes
Taxes other than income tax
Current income tax expense
Future income tax expense (recovery)
Net earnings
Capital Expenditures
2008
Net
expenditures
Non cash and
fair value
changes(1)
Capitalized
costs
Net
expenditures
2007
Non cash and
fair value
changes(1)
Capitalized
costs
Conventional crude oil and natural gas
North America
North Sea
Offshore West Africa
Other
$
Horizon Project (2)
Midstream
Head office
2,344 $
319
811
1
3,475
3,912
9
17
(7) $
(127)
6
–
(128)
10
–
–
2,337 $
192
817
1
3,347
3,922
9
17
2,428 $
439
159
1
3,027
3,301
6
20
52 $
(77)
(11)
–
(36)
–
–
–
$
7,413 $
(118) $
7,295 $
6,354 $
(36) $
2,480
362
148
1
2,991
3,301
6
20
6,318
(1) Asset retirement obligations, future income tax adjustments related to differences between carrying value and tax value, and other fair value adjustments.
(2) Net expenditures for the Horizon Project also include capitalized interest, stock-based compensation, and the impact of intersegment eliminations.
CANAD IA N NATU RAL
96
180
(52)
128
208
193
276
(3,090)
1,400
(1,013)
718
(471)
(2,116)
1,606
7,271
2,697
3,654
178
501
1,607
165
380
(456)
180
139
140
122
(432)
256
222
652
$
4,985 $
2,608 $
2,524
Conventional Crude Oil and Natural Gas
Inter-segment
North America
North Sea
Offshore West Africa
Midstream
elimination and other
2008
2007
2006
2008
2007
2006
2008
2007
2006
2008
2007
2006
2008
2007
2006
2008
Total
2007
2006
Segmented revenue $ 13,496 $ 10,149 $
9,066 $ 1,769 $
1,597 $
1,616 $
944 $
776 $
Less: royalties
(1,876)
(1,318)
(1,203)
(4)
(3)
(3)
(143)
Revenue, net of royalties 11,620
8,831
7,863
1,765
1,594
1,613
801
Segmented expenses
Production
1,881
Transportation and blending 1,975
1,642
1,595
1,436
1,465
457
10
and amortization
2,236
2,350
1,897
317
obligation accretion
42
38
35
27
Depletion, depreciation
Asset retirement
Realized risk
management activities
1,861
129
1,022
(1)
432
16
340
30
33
390
15
297
31
303
102
1
132
2
–
(70)
706
94
1
165
2
–
950
(39)
911
106
1
189
2
–
$
77 $
–
77
25
–
8
–
–
74 $
72 $
–
74
22
–
8
–
–
–
72
23
–
8
–
–
(113) $
6
(53) $
–
(61) $ 16,173 $ 12,543 $ 11,643
(1,245)
(2,017)
(1,391)
–
(107)
(53)
(61)
14,156
11,152
10,398
(14)
(50)
(10)
–
–
(6)
(42)
(6)
(38)
2,451
1,936
2,184
1,570
1,949
1,443
–
–
–
–
–
–
2,683
2,863
2,391
71
70
68
1,860
162
1,325
Total segmented
expenses
Segmented earnings before
Non-segmented expenses
Administration
Stock-based compensation (recovery) expense
Interest, net
Unrealized risk management activities
Foreign exchange loss (gain)
Total non-segmented expenses
Earnings before taxes
Taxes other than income tax
Current income tax expense
Future income tax expense (recovery)
Net earnings
7,995
5,754
5,855
810
851
1,036
237
262
298
33
30
31
(74)
(48)
(44)
9,001
6,849
7,176
the following
$ 3,625 $
3,077 $
2,008 $
955 $
743 $
577 $
564 $
444 $
613
$
44 $
44 $
41 $
(33) $
(5) $
(17)
5,155
4,303
3,222
Segmented Assets
Conventional crude oil and natural gas
North America
North Sea
Offshore West Africa
Other
Horizon Project
Midstream
Head office
180
(52)
128
(3,090)
718
208
193
276
1,400
(471)
(2,116)
1,606
7,271
178
501
1,607
2,697
165
380
(456)
180
139
140
(1,013)
122
(432)
3,654
256
222
652
$
4,985 $
2,608 $
2,524
2008
2007
$
$
24,875 $
2,638
2,013
64
12,677
315
68
42,650 $
23,617
1,957
1,354
41
8,740
333
72
36,114
CA NA DIAN NATURAL
97
18. DifferenCes BetWeen CanaDian anD UniteD states
generallY aCCepteD aCCoUnting prinCiples
The Company’s consolidated financial statements have been prepared in accordance with Canadian GAAP. These principles
conform in all material respects with US GAAP except for those noted below. Certain differences arising from US GAAP disclosure
requirements are not addressed.
The application of US GAAP would have the following effects on consolidated net earnings (loss) as reported:
(millions of Canadian dollars, except per common share amounts)
Notes
2008
2007
Net earnings – Canadian GAAP
Adjustments
Depletion, net of taxes of $2,503 million
(2007 – $1 million, 2006 – $1 million)
Stock-based compensation, net of taxes of $32 million
(2007 – $3 million, 2006 – $18 million)
Future income taxes
Derivative financial instruments and hedging activities,
net of taxes of $nil (2007 – $nil, 2006 – $15 million)
Net earnings (loss) before cumulative effect
of change in accounting policy – US GAAP
Cumulative effect of change in accounting policy,
net of taxes of $nil (2007 – $nil, 2006 – $3 million)
Net earnings (loss) – US GAAP
Net earnings (loss) before cumulative effect of
change in accounting policy – US GAAP per common share
Basic
Diluted
Net earnings (loss) – US GAAP per common share
Basic
Diluted
$
4,985 $
2,608 $
(A,D)
(6,169)
(B)
(G)
(76)
234
(C,D)
–
(10)
(22)
(234)
–
(1,026)
2,342
2,603
(B)
–
–
(8)
$
(1,026) $
2,342 $
2,595
$
(F) $
$
(F) $
(1.90) $
(1.90) $
(1.90) $
(1.90) $
4.34 $
4.32 $
4.34 $
4.32 $
2006
2,524
2
(40)
–
117
4.84
4.77
4.83
4.75
2006
2,520
71
805
3,396
Comprehensive income (loss) under US GAAP would be as follows:
(millions of Canadian dollars)
Notes
2008
2007
Comprehensive income – Canadian GAAP
US GAAP earnings adjustments
Derivative financial instruments and hedging activities,
net of taxes of $nil (2007 – $nil million; 2006 – $394 million)
Comprehensive income (loss) – US GAAP
$
5,175 $
(6,011)
(C)
$
–
(836) $
2,534 $
(266)
–
2,268 $
The application of US GAAP would have the following effects on the consolidated balance sheets as reported:
2008
Notes
Canadian
gaap
increase
(Decrease)
$
3,392 $
– $
(A,B,D,E)
(H)
38,966
292
(8,551)
55
Us
gaap
3,392
30,415
347
$
42,650
$
(8,496) $
34,154
(B) $
(H)
(B)
(A,B,D,E,G)
3,420 $
150 $
12,596
1,124
7,136
2,768
15,344
262
55
15
(2,474)
–
(6,242)
–
3,570
12,651
1,139
4,662
2,768
9,102
262
$
42,650
$
(8,496) $
34,154
(millions of Canadian dollars)
Current assets
Property, plant and equipment
Other long-term assets
Current liabilities
Long-term debt
Other long-term liabilities
Future income tax
Share capital
Retained earnings
Accumulated other comprehensive income
98
CANAD IA N NATU RAL
(millions of Canadian dollars)
Current assets
Property, plant and equipment
Other long-term assets
Current liabilities
Long-term debt
Other long-term liabilities
Future income tax
Share capital
Retained earnings
Accumulated other comprehensive income
notes:
2007
Notes
Canadian
GAAP
Increase
(Decrease)
$
2,181 $
– $
(A,B,D,E)
(H)
33,902
31
91
51
$
36,114 $
142 $
(B) $
(H)
(B)
(A,B,D,E,G)
3,563 $
10,940
1,561
6,729
2,674
10,575
72
$
36,114 $
66 $
51
20
236
–
(231)
–
142 $
US
GAAP
2,181
33,993
82
36,256
3,629
10,991
1,581
6,965
2,674
10,344
72
36,256
(A) Under Canadian full cost accounting rules, costs capitalized in each country cost centre are limited to an amount equal to the
undiscounted, future net revenues from proved reserves using estimated future prices and costs, plus the carrying amount of
unproved properties and major development projects (the “ceiling test”) as described in note 1(H). Under the full cost method
of accounting as set forth by the US Securities and Exchange Commission, the ceiling test differs from Canadian GAAP in that
future net revenues from proved reserves are based on prices and costs as at the balance sheet date (“constant dollar pricing”)
and are discounted at 10%. Capitalized costs and future net revenues are determined on a net of tax basis. These differences
in applying the ceiling test to current and prior years resulted in the recognition of ceiling test impairments under US GAAP,
which reduced property, plant and equipment by $8,697 million in 2008 (2007 – $36 million, 2006 – $40 million).
For the year ended December 31, 2008, US GAAP net earnings would have decreased by $6,164 million, net of income taxes
of $2,501 million to reflect the impact of a current year ceiling test impairment. In addition, the impact of prior ceiling test
impairments would have increased US GAAP net earnings by $3 million (2007 – decreased by $4 million, 2006 – increased by
$3 million), net of income taxes of $1 million (2007 – $8 million, 2006 – $2 million) to reflect the impact of lower depletion
charges. The 2007 income tax effect includes the effect of enacted Canadian income tax rate changes on this item.
(B) The Company accounts for its stock-based compensation liability under Canadian GAAP using the intrinsic value method, as
described in note 1(P). Under US GAAP, effective January 1, 2006, the Company would have adopted Financial Accounting
Standards Board Statement (“FAS”) 123(R), which requires companies to account for all stock-based compensation liabilities
using the fair value method, where fair value is measured using an option pricing model. The Company uses the Black Scholes
option pricing model to determine the fair value of its stock-based compensation liability for US GAAP purposes. The previous
US GAAP standard, FAS 123, required companies to account for cash settled stock-based compensation liabilities using the
intrinsic value method. For the year ended December 31, 2008, US GAAP net earnings would have decreased by $76 million
(2007 – $22 million, 2006 – $48 million), net of income taxes of $32 million (2007 – $3 million, 2006 – $21 million including
the cumulative effect of the change in accounting policy of $8 million, net of income taxes of $3 million). The 2007 income tax
effect includes the effect of enacted Canadian income tax rate changes on this item.
(C) Effective January 1, 2007, the Company adopted new accounting standards for financial instruments. The Company’s accounting
policies for financial instruments under Canadian GAAP are described in notes 1(Q) and 1(R). After adopting the new standards,
Canadian GAAP is substantially harmonized with US GAAP as prescribed by FAS 133, “Accounting for Derivative Financial
Instruments and Hedging Activities,” as amended by FAS 138 and FAS 149.
Prior to adoption of the new accounting policies, the net earnings associated with realized and unrealized hedge ineffectiveness
on derivative contracts designated as cash flow hedges during the year ended December 31, 2006 would have been $29
million, net of income taxes of $15 million. Comprehensive income would have increased by $805 million as a result of
recording all derivative financial instruments at fair value in accordance with US GAAP.
(D) During 2006, under Canadian GAAP, the Company hedged the foreign currency component of the US dollar purchase price
of ACC using derivative financial instruments formally designated as cash flow hedges. Under US GAAP, the foreign currency
component of a business combination is not eligible for cash flow hedging, and therefore, for the year ended December 31,
2006, the $88 million after-tax gain on the derivative financial instruments would have been included in net earnings. For the
year ended December 31, 2008, US GAAP net earnings would have been decreased by $8 million (2007 – $6 million, 2006 –
$1 million), net of income taxes of $3 million (2007 – $7 million, 2006 – $1 million), to reflect the impact of higher depletion
charges. The 2007 income tax effect includes the effect of enacted Canadian income tax rate changes on this item.
CA NA DIAN NATURAL
99
(E) Under Canadian GAAP, the Company began capitalizing interest on the Horizon Project when the Board of Directors approval
was received in 2005. For US GAAP, capitalization of interest on projects constructed over time is mandatory and interest would
have been capitalized to the costs of construction beginning in 2004. As a result of applying US GAAP, an additional $27 million
would have been capitalized to property, plant and equipment in 2004.
(F) Under Canadian GAAP, the Company is not required to include potential common shares related to stock options in the
calculation of diluted earnings per share as the Company has recorded the potential settlement of the stock options as a
liability. Under US GAAP FAS 128 “Earnings per Share”, the Company would have included potential common shares related
to stock options in the calculation of diluted earnings per share. For the year ended December 31, 2008, no additional shares
would have been included in the calculation of diluted earnings per share for US GAAP as the impact would have been anti-
dilutive (2007 – 3,376,000 additional shares, 2006 – 8,762,000 additional shares).
(G) Under Canadian GAAP, the effects of income tax changes are recognized when the changes are considered substantively
enacted. Under US GAAP, the income tax changes would not be recognized until the changes are enacted into law. For the year
ended December 31, 2007, the differences between substantively enacted and enacted tax legislation resulted in a difference
in timing of the recognition of a $234 million future income tax recovery.
(H) Effective January 1, 2007, under Canadian GAAP, debt issue costs on long-term debt must be included in the carrying value
of the related debt. Under US GAAP, these items must be recorded as a deferred charge. Application of US GAAP would have
resulted in the balance sheet reclassification of $55 million of debt issue costs from long-term debt to deferred charges in 2008
(2007 – $51 million). There was no difference from Canadian GAAP prior to 2007.
(I) In September 2006, the FASB issued FAS 157 “Fair Value Measurements” effective for fiscal years beginning after November
15, 2007. The implementation date was subsequently delayed until years beginning on or after November 15, 2008 except
for non financial assets and non financial liabilities that are recognized or disclosed at fair value in the financial statements on
a recurring basis (at least annually). FAS 157 standardizes the meaning of “Fair Value” in all FASB statements that refer to fair
value and expands disclosures about fair value measurements. The adoption of this standard did not result in a Canadian and
US GAAP reconciling item.
(J) In February 2007, the FASB issued FAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” effective for
fiscal years beginning after November 15, 2007. FAS 159 allows entities to carry most financial instruments at fair value, even
if existing standards would not require this. The adoption of this standard did not result in a US GAAP reconciling item.
(K) In December 2007, the FASB issued FAS 141(R) “Business Combinations”, which replaces FAS 141 effective for fiscal years
beginning after December 15, 2008. FAS 141(R) retains the purchase method of accounting and requires assets acquired and
liabilities assumed in a business combination to be measured at fair value at the date of acquisition. The standard also requires
acquisition-related costs and restructuring costs to be recognized separately from the business combination. This standard is
to be applied prospectively to all business combinations subsequent to the effective date and does not require restatement of
previously completed business combinations.
(L) US GAAP – Recently issued accounting standards
During 2008, the US Securities and Exchange Commission adopted revisions to its oil and gas reporting disclosures contained in
Regulation S-K and Regulation S-X. These revisions change the price basis for calculating oil and gas reserves from a single-day,
year-end price to a monthly average price based on “first day of the month” price. These revisions will impact the reserves used
in the Company’s accounting for depletion and its calculation of the ceiling test under US GAAP. These revisions are effective
for filings made on or after January 1, 2010, and will be applied prospectively with no retroactive restatement.
100 CANAD IA N NATU RAL
supplementary oil & gas information (unaudited)
ca na dia n natu ral 2008 a nn u a l r epo rt
This supplementary crude oil and natural gas information is provided in accordance with the United States Financial Accounting
Standards Board Statement 69 (“FAS 69”), “Disclosures about Oil and Gas Producing Activities”, and where applicable is reconciled
to the financial information prepared in accordance with generally accepted accounting principles in the United States (“US
GAAP”).
net proveD CrUDe oil anD natUral gas reserves
The Company retains qualified independent reserves evaluators to evaluate the Company’s proved crude oil and natural gas reserves.
n
n
For the year ended December 31, 2008, the reports by Sproule Associates Limited (“Sproule”) covered 100% of the Company’s
conventional reserves.
For the years ended December 31, 2007, 2006, and 2005 the reports by Sproule and Ryder Scott Company covered 100% of
the Company’s conventional reserves.
Proved crude oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids (“NGLs”) that
geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed reserves are reserves that can be expected to be recovered
from existing wells with existing equipment and operating methods.
Estimates of crude oil and natural gas reserves are subject to uncertainty and will change as additional information regarding
producing fields and technology becomes available and as future economic and operating conditions change.
The following table summarizes the Company’s proved and proved developed conventional crude oil and natural gas reserves, net
of royalties, as at December 31, 2008, 2007, 2006, and 2005:
Crude oil and ngls (mmbbl)
Net proved reserves
Reserves, December 31, 2005
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Revisions of prior estimates (1)
Reserves, December 31, 2006
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Revisions of prior estimates (1)
Reserves, December 31, 2007
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Economic revisions due to prices
Revisions of prior estimates
reserves, December 31, 2008
Net proved developed reserves
December 31, 2005
December 31, 2006
December 31, 2007
December 31, 2008
north
america
north
offshore
sea West africa
694
53
190
26
–
(75)
(1)
887
30
13
1
–
(77)
66
920
51
17
–
–
(76)
28
8
948
402
420
426
428
290
3
26
–
–
(22)
2
299
–
6
–
(3)
(20)
28
310
–
6
–
–
(17)
(81)
38
256
214
214
240
97
134
–
–
–
–
(13)
9
130
–
–
–
–
(10)
8
128
–
4
–
–
(8)
8
10
142
80
63
70
107
total
1,118
56
216
26
–
(110)
10
1,316
30
19
1
(3)
(107)
102
1,358
51
27
–
–
(101)
(45)
56
1,346
696
697
736
632
(1) Revisions of prior estimates for the years ended December 31, 2007 and 2006 include the impact of economic revisions due to prices.
CA NA DIAN NATURAL
101
natural gas (bcf)
Net proved reserves
Reserves, December 31, 2005
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Revisions of prior estimates (1)
Reserves, December 31, 2006
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Revisions of prior estimates (1)
Reserves, December 31, 2007
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Economic revisions due to prices
Revisions of prior estimates
reserves, December 31, 2008
Net proved developed reserves
December 31, 2005
December 31, 2006
December 31, 2007
December 31, 2008
north
america
north
offshore
sea West africa
2,741
250
74
1,111
(1)
(433)
(37)
3,705
134
132
12
–
(503)
41
3,521
140
52
77
(1)
(449)
(19)
202
3,523
2,300
2,934
2,731
2,690
29
–
–
–
–
(5)
13
37
–
3
–
–
(5)
46
81
–
(1)
–
–
(4)
(56)
47
67
16
17
58
45
72
–
–
–
–
(3)
(13)
56
–
–
–
–
(4)
12
64
–
6
–
–
(4)
6
22
94
10
12
53
89
total
2,842
250
74
1,111
(1)
(441)
(37)
3,798
134
135
12
–
(512)
99
3,666
140
57
77
(1)
(457)
(69)
271
3,684
2,326
2,963
2,842
2,824
(1) Revisions of prior estimates for the years ended December 31, 2007 and 2006 include the impact of economic revisions due to prices.
CapitalizeD Costs relateD to CrUDe oil anD natUral gas aCtivities
2008
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
north
america
north
offshore
sea West africa
$
34,386 $
2,271
36,657
(21,857)
4,155 $
12
4,167
(3,366)
2,076 $
595
2,671
(777)
other
14 $
26
40
(14)
total
40,631
2,904
43,535
(26,014)
Net capitalized costs
$
14,800 $
801 $
1,894 $
26 $
17,521
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
North
America
North
Sea
Offshore
West Africa
2007
$
32,061 $
2,259
34,320
(12,213)
3,164 $
10
3,174
(1,446)
1,695 $
138
1,833
(645)
Other
14 $
25
39
(14)
Total
36,934
2,432
39,366
(14,318)
Net capitalized costs
$
22,107 $
1,728 $
1,188 $
25 $
25,048
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
North
America
North
Sea
Offshore
West Africa
2006
$
29,596 $
2,244
31,840
(9,878)
3,346 $
24
3,370
(1,341)
1,601 $
84
1,685
(481)
Other
14 $
24
38
(14)
Total
34,557
2,376
36,933
(11,714)
Net capitalized costs
$
21,962 $
2,029 $
1,204 $
24 $
25,219
102 CANAD IA N NATU RAL
Costs inCUrreD in CrUDe oil anD natUral gas aCtivities
(millions of Canadian dollars)
Property acquisitions
Proved
Unproved
Exploration
Development
Costs incurred
(millions of Canadian dollars)
Property acquisitions
Proved
Unproved
Exploration
Development
Costs incurred
(millions of Canadian dollars)
Property acquisitions
Proved
Unproved
Exploration
Development
Costs incurred
north
america
north
offshore
sea West africa
other
total
2008
$
299 $
84
144
1,810
$
2,337 $
(7) $
1
3
195
192 $
44 $
1
–
772
817 $
2007
– $
–
1
–
1 $
336
86
148
2,777
3,347
North
America
North
Sea
Offshore
West Africa
Other
Total
$
$
$
$
55 $
13
239
2,173
2,480 $
(38) $
1
19
380
362 $
– $
–
–
148
148 $
2006
– $
–
1
–
1 $
17
14
259
2,701
2,991
North
America
North
Sea
Offshore
West Africa
Other
Total
5,627 $
910
238
2,807
9,582 $
– $
–
4
628
632 $
1 $
–
1
133
135 $
– $
–
11
–
11 $
5,628
910
254
3,568
10,360
resUlts of operations from CrUDe oil anD natUral gas proDUCing aCtivities
The Company’s results of operations from crude oil and natural gas producing activities for the years ended December 31, 2008,
2007, and 2006 are summarized in the following tables:
(millions of Canadian dollars)
2008
north
america
north
offshore
sea West africa
Crude oil and natural gas revenue, net of royalties and blending costs
Production
Transportation
Depletion, depreciation and amortization (1)
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
$
8,126 $
(1,881)
(327)
(9,661)
(42)
–
1,128
1,731 $
(457)
(10)
(1,564)
(27)
(143)
235
801 $
(102)
(1)
(132)
(2)
–
(141)
total
10,658
(2,440)
(338)
(11,357)
(71)
(143)
1,222
Results of operations
$
(2,657) $
(235) $
423 $
(2,469)
(1)
Includes the impact of a ceiling test impairment at December 31, 2008 of $8,665 million, pre-tax.
(millions of Canadian dollars)
2007
North
America
North
Sea
Offshore
West Africa
Crude oil and natural gas revenue, net of royalties and blending costs $
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
$
7,441 $
(1,642)
(335)
(2,359)
(38)
–
(997)
2,070 $
1,522 $
(432)
(16)
(340)
(30)
(141)
(282)
281 $
709 $
(94)
(1)
(165)
(2)
–
(121)
326 $
Total
9,672
(2,168)
(352)
(2,864)
(70)
(141)
(1,400)
2,677
CA NA DIAN NATURAL
103
(millions of Canadian dollars)
2006
North
America
North
Sea
Offshore
West Africa
Crude oil and natural gas revenue, net of royalties and blending costs $
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
$
5,707 $
(1,436)
(326)
(1,894)
(35)
–
(706)
1,310 $
1,310 $
(390)
(15)
(297)
(31)
(234)
(172)
171 $
911 $
(106)
(1)
(189)
(2)
–
(172)
441 $
Total
7,928
(1,932)
(342)
(2,380)
(68)
(234)
(1,050)
1,922
stanDarDizeD measUre of DisCoUnteD fUtUre net Cash floWs from proveD CrUDe oil anD
natUral gas reserves anD Changes therein
The following standardized measure of discounted future net cash flows from proved crude oil and natural gas reserves has been
computed using year-end sales prices and costs and year-end statutory income tax rates. A discount factor of 10% has been
applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the
standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not
be considered to represent the fair value of the crude oil and natural gas properties. Actual net cash flows will differ from the
presented estimated future net cash flows due to several factors including:
n
n
n
n
n
n
n
Future production will include production not only from proved properties, but may also include production from probable and
possible reserves;
Future production of crude oil and natural gas from proved properties will differ from reserves estimated;
Future production rates will vary from those estimated;
Future rather than year-end sales prices and costs will apply;
Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will change;
Future estimated income taxes do not take into account the effects of future exploration expenditures; and
Future development and asset retirement obligations will differ from those estimated.
Future net revenues, development, production and restoration costs have been based upon the estimates referred to above. The
following tables summarize the Company’s future net cash flows relating to proved crude oil and natural gas reserves based on the
standardized measure as prescribed in FAS 69:
(millions of Canadian dollars)
Future cash inflows
Future production costs
Future development and asset retirement obligations
Future income taxes
Future net cash flows
10% annual discount for timing of future cash flows
2008
north
america
north
offshore
sea West africa
$
51,913 $
(23,747)
(9,238)
(3,097)
15,831
(6,872)
13,681 $
(6,845)
(4,674)
(2,011)
151
(76)
6,789 $
(3,000)
(364)
(1,061)
2,364
(1,011)
total
72,383
(33,592)
(14,276)
(6,169)
18,346
(7,959)
Standardized measure of future net cash flows
$
8,959 $
75 $
1,353 $
10,387
(millions of Canadian dollars)
Future cash inflows
Future production costs
Future development and asset retirement obligations
Future income taxes
Future net cash flows
10% annual discount for timing of future cash flows
$
North
America
71,069 $
(23,729)
(7,938)
(9,508)
29,894
(13,952)
2007
North
Sea
Offshore
West Africa
30,269 $
(9,316)
(4,021)
(11,376)
5,556
(2,176)
9,921 $
(2,419)
(621)
(1,978)
4,903
(2,505)
Total
111,259
(35,464)
(12,580)
(22,862)
40,353
(18,633)
Standardized measure of future net cash flows
$
15,942 $
3,380 $
2,398 $
21,720
104 CANAD IA N NATU RAL
(millions of Canadian dollars)
Future cash inflows
Future production costs
Future development and asset retirement obligations
Future income taxes
Future net cash flows
10% annual discount for timing of future cash flows
$
North
America
63,368 $
(21,634)
(7,029)
(9,118)
25,587
(11,214)
2006
North
Sea
Offshore
West Africa
20,815 $
(8,077)
(4,348)
(5,623)
2,767
(956)
7,779 $
(2,517)
(824)
(1,372)
3,066
(1,258)
Total
91,962
(32,228)
(12,201)
(16,113)
31,420
(13,428)
Standardized measure of future net cash flows
$
14,373 $
1,811 $
1,808 $
17,992
The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the following
table:
(millions of Canadian dollars)
2008
2007
Sales of crude oil and natural gas produced, net of production costs
Net changes in sales prices and production costs
Extensions, discoveries and improved recovery
Changes in estimated future development costs
Purchases of proved reserves in place
Sales of proved reserves in place
Revisions of previous reserve estimates
Accretion of discount
Changes in production timing and other
Net change in income taxes
Net change
Balance – beginning of year
Balance – end of year
$
(9,679) $
(14,680)
820
(715)
113
(1)
112
3,468
767
8,462
(7,150) $
7,412
1,429
(169)
39
(103)
2,380
2,760
508
(3,378)
(11,333)
21,720
3,728
17,992
$
10,387 $
21,720 $
2006
(5,635)
(2,420)
4,769
(1,885)
2,406
(2)
81
3,112
(2,156)
1,270
(460)
18,452
17,992
CA NA DIAN NATURAL
105
canadian natural 2 008 a n n u a l r e p ort
ten-year review
Years ended December 31
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
finanCial information (1)
(C$ millions, except per share amounts)
Net earnings
Per share - basic $
Cash flow from operations (2)
4,985
9.22 $
2,608
2,524
1,050
1,405
1,403
4.84 $
4.70 $
1.96 $
2.62 $
2.62 $
539
1.06 $
639
1.32 $
758
1.62 $
213
0.51
Per share - basic $ 12.89 $
6,969
6,198
11.49 $
4,932
5,021
3,769
3,160
2,254
1,920
1,884
9.18 $
9.36 $
7.03 $
5.88 $
4.41 $
3.96 $
4.04 $
724
1.74
Capital expenditures, net of dispositions (including business combinations)
4,932
12,025
7,451
6,425
4,633
2,506
4,069
1,885
2,823
1,901
Balance sheet information
Working capital (deficiency) surplus
(28)
Property, plant and equipment, net
38,966
42,650
Total assets
Long-term debt
12,596
Shareholders’ equity 18,374
share information (1)
Common shares outstanding (thousands)
(1,382)
(832)
(1,774)
(652)
(505)
(14)
(6)
(77)
36
33,902
36,114
10,940
13,321
30,767
33,160
11,043
10,690
19,694
21,852
3,321
8,237
17,064
18,372
3,538
7,324
13,714
14,643
2,748
6,006
12,934
13,793
4,200
4,754
8,766
9,290
2,788
3,928
7,439
8,051
2,573
3,297
4,679
4,976
2,157
1,962
539,729
Weighted average shares outstanding (thousands)
539,336
540,991
540,647
537,903
536,348
536,361
534,926
535,104
484,804
489,116
445,816
537,339
536,650
536,223
536,940
511,532
485,200
466,804
415,624
Dividends declared per common share
$
0.40 $
0.34 $
0.30 $
0.24 $
0.20 $
0.15 $
0.13 $
0.10 $
– $
–
trading statistics (1)
TSX – C$
Trading volume (thousands)
679,738
429,034
508,935
637,992
606,024
590,702
619,316
534,976
567,412
430,460
Share Price ($/share)
High
Low
Close
NYSE – US$
Trading volume (thousands)
$ 111.30 $
$ 34.19 $
$ 48.75 $
80.02 $
52.45 $
72.58 $
73.91 $
45.49 $
62.15 $
62.00 $
24.28 $
57.63 $
27.58 $
15.96 $
25.63 $
16.81 $
11.30 $
16.34 $
13.64 $
9.40 $
11.70 $
13.09 $
8.98 $
9.58 $
14.05 $
7.45 $
10.38 $
9.65
4.95
8.81
967,228
486,266
401,909
251,554
125,468
46,916
31,864
20,764
3,172
Share Price ($/share)
High
Low
Close
$ 109.32 $
$ 26.43 $
$ 39.98 $
87.17 $
44.56 $
73.14 $
64.38 $
40.29 $
53.23 $
54.05 $
19.74 $
49.62 $
22.37 $
11.94 $
21.39 $
12.85 $
7.32 $
12.61 $
8.72 $
5.89 $
7.42 $
8.63 $
5.70 $
6.10 $
9.46 $
6.19 $
6.88 $
–
–
–
–
ratios
Debt to book capitalization (3)
29%
34%
33%
47%
42%
44%
52%
51%
41%
Return on average common shareholders’ equity, after tax (3)
27%
33%
14%
Daily production before royalties per ten thousand common shares (boe/d)
10.3
10.4
22%
45%
11.3
10.8
Conventional proved and probable reserves per common share (boe) (4)
6.1
6.3
6.4
4.8
Net asset value per common share (1) (5)
21%
26%
13%
18%
29%
13%
9.6
4.3
8.5
4.0
8.2
3.3
7.4
3.1
6.6
2.9
5.0
2.4
$ 79.78 $
68.93 $
56.41 $
60.44 $
33.13 $
23.35 $
19.57 $
16.88 $
20.54 $ 12.33
(1) Restated to reflect two-for-one share splits in May 2004 and May 2005.
(2) Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company
evaluates its performance based on cash flow from operations. Cash flow from operations may not be comparable to similar measures used by other companies.
(3) Refer to the “Liquidity and Capital Resources” section of the MD&A for the definitions of these items.
(4) Based upon constant dollar Company gross reserves (before royalties), using year-end common shares outstanding.
(5)
Based upon 10% discounted, forecast price pre-tax proved and probable net present values as reported in the Company’s AIF for conventional reserves, with $250/acre
added for core undeveloped land in 2005, 2006, 2007 and 2008, $75/acre for all years prior, less long-term debt and adjustments for working capital. Refer to the
“Year-End Reserves” section of the Annual Report.
106 CANAD IA N NATU RAL
ca na dia n natu ral 2008 a nn u a l r epo rt
Years ended December 31
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
operating information
Conventional crude oil and ngls (mmbbl, constant prices and costs)
Company gross proved reserves (before royalties)
North America
North Sea
Offshore West Africa
Company gross proved and probable reserves (before royalties)
North America
North Sea
Offshore West Africa
1,057
256
157
1,470
1,760
399
212
2,371
4,077
67
107
4,251
5,339
94
151
5,584
1,084
311
148
1,543
1,806
406
218
2,430
4,275
81
79
4,435
5,582
113
109
5,804
1,043
299
145
1,487
1,753
421
223
2,397
4,507
37
69
4,613
5,898
93
121
6,112
785
290
148
1,223
1,154
417
230
1,801
3,378
29
83
3,490
4,372
69
127
4,568
695
303
125
1,123
992
415
214
1,621
3,202
27
81
3,310
4,100
57
102
4,259
672
222
106
1,000
977
317
187
1,481
3,006
62
86
3,154
3,611
101
111
3,823
665
203
94
962
742
277
162
1,181
3,048
71
90
3,209
3,450
89
120
3,659
644
83
61
788
740
106
111
957
2,566
94
69
2,729
2,915
118
96
3,129
643
102
36
781
731
134
46
911
2,360
91
65
2,516
2,762
114
84
2,960
554
–
–
554
640
–
–
640
2,183
–
–
2,183
2,547
–
–
2,547
Conventional natural gas (bcf, constant prices and costs)
Company gross proved reserves (before royalties)
North America
North Sea
Offshore West Africa
Company gross proved and probable reserves (before royalties)
North America
North Sea
Offshore West Africa
total proved reserves (before royalties) (mmboe)
2,178
2,282
2,256
1,804
1,674
1,526
1,497
1,243
1,200
918
total proved and probable reserves (before royalties) (mmboe)
3,302
3,397
3,416
2,562
2,330
2,118
1,791
1,479
1,404
1,065
Daily production (before royalties)
Crude oil and NGLs (mbbl/d)
North America
North Sea
Offshore West Africa
244
45
27
316
Natural gas (mmcf/d)
North America
North Sea
Offshore West Africa
1,472
10
13
1,495
247
56
28
331
1,643
13
12
1,668
total production (before royalties) (mboe/d)
235
60
37
332
1,468
15
9
1,492
222
68
23
313
1,416
19
4
1,439
206
65
12
283
1,330
50
8
1,388
175
57
10
242
1,245
46
8
1,299
169
39
7
215
1,204
27
1
1,232
167
36
3
206
906
12
–
918
155
17
2
174
793
1
–
794
87
–
–
87
721
–
–
721
565
609
581
553
514
459
421
359
306
207
product pricing
Average crude oil and NGLs price ($/bbl)
Average natural gas price ($/mcf)
82.41
55.45
53.65
46.86
37.99
32.66
31.22
23.45
31.89
22.26
8.39
6.85
6.72
8.57
6.50
6.21
3.77
5.45
4.92
2.52
CA NA DIAN NATURAL
107
canadian natural 2 008 a n n u a l r e p ort
corporate information
BoarD of DireCtors
*Catherine m. Best (1 – Chair) (2)
Interim Chief Financial Officer,
Alberta Health Services
Calgary, Alberta
n. murray edwards (4)
President, Edco Financial Holdings Ltd.
Calgary, Alberta
*honourable gary a. filmon, P.C., O.M. (1) (3)
Consultant, The Exchange Group
Winnipeg, Manitoba
*ambassador gordon D. giffin (1) (3 – Chair)
Senior Partner, McKenna Long & Aldridge LLP
Atlanta, Georgia
John g. langille
Vice-Chairman,
Canadian Natural Resources Limited
Calgary, Alberta
steve W. laut
President & Chief Operating Officer,
Canadian Natural Resources Limited
Calgary, Alberta
Keith a. J. macphail (4) (5)
Chairman, President & Chief Executive Officer,
Bonavista Energy Trust
Calgary, Alberta
allan p. markin, O.C. (5)
Chairman of the Board,
Canadian Natural Resources Limited
Calgary, Alberta
*norman f. mcintyre (2) (4) (5)
Independent Businessman
Calgary, Alberta
*honourable frank J. mcKenna, P.C., O.C., O.N.B., Q.C. (2) (3)
Deputy Chair, TD Bank Financial Group
Cap Pelé, New Brunswick
*James s. palmer, C.M., A.O.E., Q.C. (2 – Chair) (4) (5)
Chairman and Partner,
Burnet, Duckworth & Palmer LLP
Calgary, Alberta
*eldon r. smith, M.D. (2) (5 – Chair)
Professor Emeritus and Former Dean,
Faculty of Medicine, University of Calgary
Calgary, Alberta
*David a. tuer (1) (3) (4 – Chair)
Vice-Chairman and Chief Executive Officer,
Marble Point Energy Ltd.
Calgary, Alberta
108 CANAD IA N NATU RAL
management Committee
allan p. markin
Chairman of the Board
n. murray edwards
Vice-Chairman of the Board
John g. langille
Vice-Chairman of the Board
steve W. laut
President & Chief Operating Officer
Douglas a. proll
Chief Financial Officer & Senior Vice-President, Finance
réal m. Cusson
Senior Vice-President, Marketing
réal J.h. Doucet
Senior Vice-President, Oil Sands
allen m. Knight
Senior Vice-President, International
& Corporate Development
tim s. mcKay
Senior Vice-President, Operations
lyle g. stevens
Senior Vice-President, Exploitation
Jeff W. Wilson
Senior Vice-President, Exploration
mary-Jo e. Case
Vice-President, Land
randall s. Davis
Vice-President, Finance & Accounting
terry J. Jocksch
Vice-President, International and Managing Director
CNR International (U.K.) Limited
(1) Audit Committee member
(2) Compensation Committee member
(3) Nominating and Corporate Governance Committee member
(4) Reserves Committee member
(5) Health, Safety and Environment Committee member
* Determined to be independent by the Nominating and Corporate Governance
Committee and the Board of Directors and pursuant to the independent
standards established under National Instrument 58-101 and the New York
Stock Exchange Corporate Governance Listing Standards.
ca na dia n natu ral 2008 a n n u a l rep ort
Corporate governanCe
Canadian Natural’s corporate governance practices and
disclosure of those practices are in compliance with National
Policy 58-201 Corporate Governance Guidelines and National
Instrument 58-101 Disclosure of Corporate Governance
Practices. Canadian Natural, as a “foreign private issuer” in the
United States, may rely on home jurisdiction listing standards
for compliance with most of the New York Stock Exchange
(“NYSE”) Corporate Governance Listing Standards but must
disclose any significant differences between its corporate
governance practices and those required for U.S. companies
listed on the NYSE.
Canadian Natural follows Toronto Stock Exchange (“TSX”) rules
with respect to shareholder approval of equity compensation
plans and material revisions to such plans. TSX rules provide
that only the creation of or material amendments to equity
compensation plans which provide for new issuance of
securities are subject to shareholder approval. However, the
NYSE requires shareholder approval of all equity compensation
plans whether they provide for the delivery of newly issued
securities, or rely on securities acquired in the open market by
the issuing company for the purposes of redistribution to plan
beneficiaries, and material revisions to such plans. Canadian
Natural has a share bonus plan pursuant to which common
shares are purchased through the TSX. This is not a new issue
of securities under the share bonus plan and under TSX rules
the plan is not subject to shareholder approval.
Canadian Natural has included as exhibits to its Annual Report
on Form 40-F for the 2008 fiscal year filed with the United
States Securities and Exchange Commission certificates of the
Chief Executive Officer and Chief Financial Officer certifying as
to disclosure controls and procedures and internal control over
financial reporting.
Corporate offiCes
Head office
canadian natural resources limited
2500, 855 – 2 Street S.W.
Calgary, AB T2P 4J8
telephone: 403.517.6700
Facsimile: 403.517.7350
Website: www.cnrl.com
investor relations
telephone: 403.514.7777
Facsimile: 403.514.7888
email:
ir@cnrl.com
international office
cnr international (u.K.) limited
St. Magnus House, Guild Street
Aberdeen AB11 6NJ Scotland
registrar anD transfer agent
computershare trust company of canada
Calgary, Alberta
Toronto, Ontario
computershare investor Services llc
New York, New York
aUDitors
pricewaterhousecoopers llp
Calgary, Alberta
Common share DiviDenD
The Company paid its first dividend on its common shares on
April 1, 2001. Since then, dividends have been paid on the first
day of every January, April, July and October. The following
table shows the aggregate amount of the cash dividends
declared per common share in each of its last three years ended
December 31.
2008
2007
2006
Cash dividends declared
per common share
$ 0.40 $ 0.34 $ 0.30
notiCe of annUal meeting
Canadian Natural’s Annual General Meeting of the
Shareholders will be held on Thursday, May 7, 2009 at
3:00 p.m. Mountain Daylight Time in the Ballroom of the
Metropolitan Centre, Calgary, Alberta.
stoCK listing
cnQ
The Toronto Stock Exchange
The New York Stock Exchange
inDepenDent QUalifieD reserves evalUators
GlJ petroleum consultants ltd.
Calgary, Alberta
Sproule associates limited
Calgary, Alberta
Printed in Canada by McAra Printing.
Principal photography by Gary Campbell Photography and
Canadian Natural team members.
Canadian natural resources limited
2500, 855 – 2 Street S.W.
Calgary, AB
T2P 4J8
telephone: 403.517.6700
facsimile: 403.517.7350
email: ir@cnrl.com
WWW.cnrl.coM