Canadian Natural Resources Annual Report 2005

FY2005 Annual Report · Canadian Natural Resources
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The Premium Value,
Deﬁ ned Growth, Independent.

2005 Annual Report

General information

COMPANY DEFINITION
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.

Alberta natural gas reference location
Annual Information Form
barrel
barrels per day
billion cubic feet
billion cubic feet per day
barrels of oil equivalent
barrels of oil equivalent per day
Canadian dollars
Coal Bed Methane
Canadian Natural Upgrader
Cyclic Steam Stimulation
Enhanced Oil Recovery
Exploration and Production
Floating Production, Storage and Offtake Vessel
Greenhouse Gas

ABBREVIATIONS
AECO 
AIF
bbl
bbl/d
bcf
bcf/d
boe 
boe/d 
C$ 
CBM 
CNUG 
CSS 
EOR 
E&P 
FPSO 
GHG 
Horizon Project  Horizon Oil Sands Project
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 
US$ 
WCS 
WCSB 
WTI 

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
Securities and Exchange Commission
trillion cubic feet
Toronto Stock Exchange
United Kingdom
United States
United States dollars
Western Canadian Select crude oil blend
Western Canadian Sedimentary Basin
West Texas Intermediate

CAUTIONARY STATEMENTS
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  45  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 40 to 44.
This  report  also  includes  references  to  ﬁ nancial  measures 
commonly used in the oil and gas industry that are not deﬁ ned 
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.

COMMON SHARE DIVIDEND
The  Company  paid  its  ﬁ rst  dividend  on  its  common  shares  on 
April 1st, 2001. Since then, dividends have been paid on the ﬁ rst 
day of every January, April, July and October.
The following table, restated for the two-for-one subdivisions of 
the common shares that occurred in May 2004 and May 2005, 
shows the aggregate amount of the cash dividends declared per 
common share in each of its last three years ended December 31.

Cash dividends declared
  per common share 

  2005 

  2004 

  2003

$  0.24  $  0.20  $  0.15

NOTICE OF ANNUAL MEETING
Canadian  Natural’s  Annual  General  Meeting  of  Shareholders 
will be held on Thursday, May 4, 2006 at 3:00 p.m. Mountain 
Daylight  Time  in  the  Ballroom  of  the  Metropolitan  Centre, 
Calgary, Alberta.

METRIC CONVERSION CHART
To convert 
barrels
thousand cubic feet 
feet
miles
acres
tonnes

To 
cubic metres 
cubic metres 
metres
kilometres
hectares
tons

Multiply by
0.159
28.174
0.305
1.609
0.405
1.102

 
 
 
 
 
 
The People

Our people are motivated and competent. Our 
technical  skills  are  compounding,  allowing  us 
to maintain our core competencies and pursue 
larger and more complex projects.

The Plan

Our  exploitation based strategy allocates capital 
in a balanced manner, providing near-, mid- and 
long-term growth initiatives. This plan provides 
signiﬁ cant transparency to investors.

The Assets

Our  strong  asset  base  is  comprised  of  a 
deep  portfolio  of  conventional  oil  and  gas 
opportunities in North America, the North Sea 
and Offshore West Africa. This is bolstered by 
a vast oil sands resource base in Alberta capable 
of supporting over 675,000 barrels per day of 
light sweet SCO production for years to come.

Capitalizing on opportunities.

Relying on our People and applying their expanding technical skills to our vast 
Asset portfolio has allowed us to extend our Plan for oil sands development. 
This includes targeting further expansions at the Horizon Project as well as 
the  development  of  our  in-situ  lands  together  with  the  construction  of  the 
Canadian Natural Upgrader which will be capable of upgrading this product 
to light, sweet Synthetic Crude Oil.

TABLE OF CONTENTS

Financial Highlights
Letter to Shareholders

4
7 
12  The People

14  The Plan: Review of Operations
18  The Plan: Marketing
22  The Plan: Financial Plan

Conventional Operations
Year in Review

COST CONTROL remains strong, reﬂ ecting the beneﬁ ts of leveraging a large infrastructure to create economies
of scale. This ability also lends itself to capital efﬁ ciencies.

NET CONVENTIONAL PROVED RESERVES additions were 145% of net production at a ﬁ nding and onstream 
cost  of  $13.41/boe  (3-year  average  $12.55/boe).  Using  net  proved  and  probable  reserves  we  replaced  195%  of 
net production at a ﬁ nding and onstream cost of $9.97/boe (3-year average $8.05/boe). In addition, we booked
2.2 billion barrels of gross proved (3.4 billion barrels of gross proved and probable) mineable bitumen reserves at 
our Horizon Project.

CANADIAN NATURAL GAS PRODUCTION
was up 6%. This was primarily driven through the 
largest natural gas drilling program in the Company’s 
history with 975 wells and strategic acquisitions.

CANADIAN CRUDE OIL PRODUCTION was up 
7%. Growth was primarily organic with a record 
642 net wells targeting crude oil. Using our lower-
risk exploitation approach we achieved a 95% 
success rate on this program.

TOTAL PRODUCTION increased by 8% to 
average 553 mboe/d.

NORTH SEA CRUDE OIL VOLUMES were 
up 6% due to the combination of an active 
exploitation program and the full year impact 
of a property acquisition made in 2004.

OFFSHORE WEST AFRICA VOLUMES
essentially doubled through the additional 
drilling of wells at our East Espoir Field and 
the commissioning of the deepwater Baobab 
Field, both located in Côte d’Ivoire. The 
Baobab Field represented the Company’s ﬁ rst 
deepwater development and was completed 
in a cycle time of only 4.5 years from initial 
discovery to ﬁ rst production.

OUR PROJECT INVENTORY WAS STRENGTHENED DURING 2005 AS FOLLOWS:

•   Total landholdings, the input to sustainable conventional 
growth, increased during the year. As the second largest 
landholder in the WCSB, it provides us with leverage in 
most play types found in the basin.

•   The success of our heavy crude oil marketing plan 

provided the conﬁ dence to announce the planned, stepwise, 
development of 300 mbbl/d of new in-situ production over 
the next several years.

•   Secondary and enhanced recovery schemes are working 

at Pelican Lake in Alberta, increasing the potential of this 
large proliﬁ c ﬁ eld.

•   Additional phases of development were announced for the 
Horizon Project targeting up to 500 mbbl/d of production 
from our oil sands mining leases.

•   We are reviewing a second bitumen upgrader, in addition to 
the one integrated with the Horizon Project was announced 
in tandem with our in-situ developments. Implementation 
of cost control schemes such as gasiﬁ cation technologies in 
our oil sands developments is planned.

•   We captured a new exploitation development of a proved 

light crude oil ﬁ eld located offshore Gabon.

Our disciplined approach continues to deliver
strong production volumes at a low cost.

The Horizon Oil Sands Project

THE HORIZON OIL SANDS PROJECT (“Horizon Project”) represents a world class crude oil 
development with the following characteristics:

•   Low  geological  risk  as  it  is  delineated  by  several 
hundred  stratigraphic  wells.  We  know  the  resource 
base and its characteristics.

•   No  production  declines  normally  associated  with 
conventional  crude  oil  and  natural  gas  operations. 
Production is sustainable; literally, for decades to come.

•   Bitumen  is  upgraded  on-site  to  a  light  sweet  synthetic 
crude oil that is sold at a premium to WTI during 2005.

•   Only reliable, proven technologies have been utilized.

Due to minimal capital reinvestment requirements, this translates into consistent high free 
cash ﬂ ow generation capability for decades to come.

OUR DISCIPLINED APPROACH to this development 
is being leveraged to its utmost. Prior to sanctioning, 
we spent 4 years and over $400 million to understand 
what we wanted to build and how we wanted to build 
it. This investment was well worth the effort. It helped 
us to achieve cost certainty in the form of targeting 
68% of construction costs under ﬁ xed price bids, a ﬁ rst 
in the oil sands industry. 

DURING 2005 we made signiﬁ cant headway on construction 
activities, accomplishing about 19% of Phase 1 construction by year 
end. It is still early, but we remain on-time and on-schedule. Many 
of the foundations were completed and all winter-critical path items 
remained on track. We target to be approximately 55% completed 
by the end of 2006.

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OUR CREATIVE LABOUR strategy was a further outcome from 
this preplanning. The addition of an on-site 737–capable airstrip 
has enabled workers from all across Canada to participate in our 
managed open site. This expanded access to labour is a critical 
success factor as the construction effort continues. Our ﬁ rst class 
camp facilities augment this plan.

WE ARE REVIEWING the option of combining Phases 
2 and 3 into one phase bringing total production to 
approximately 232 mbbl/d by approximately 2011. 
Doing so may enable us to keep more trained workers 
remaining on site in a competitive market. Financially we 
are capable of accomplishing it. We will fully investigate 
the merits of this and will decide by early 2007.

WE ANNOUNCED ADDITIONAL FUTURE PHASES 4 AND 5 late in 2005 which will seek to optimize the development of this vast 
asset base. These phases, augmented by bitumen feedstock from in-situ operations, will result in total production capacity of about
500 mbbl/d of light sweet synthetic crude oil from the leases by 2017.

Horizon will add signiﬁ cant shareholder value
for decades to come.

Canadian Natural Upgrader
and In-situ Developments

CANADIAN NATURAL OWNS A TREMENDOUS ASSET BASE in the heavy crude oil and oil sands regions 
of Canada. The challenge has been to develop these assets in a methodical and disciplined manner due to the 
limitations imposed by reﬁ ner conversion capacity.

OUR HEAVY CRUDE OIL MARKETING STRATEGY seeks to overcome this challenge. We 
have been aggressive in the execution of this strategy over the last two years. We are now the 
largest blender of heavy crude oil in Canada at about 140 mbbl/d during 2005, creating  products 
that are usable by more reﬁ ners within our traditional geographic market. We support various 
pipeline initiatives to expand the geographic reach of our marketing efforts, and in 2005 we 
committed 25 mbbl/d to the Coriscana Pipeline delivering our heavy crude oil directly into the 
US Gulf Coast where signiﬁ cant conversion capacity exists. The ﬁ nal leg of the strategy is to 
encourage the creation of more conversion capacity in our markets.

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THE ECONOMICS OF THE 
UPGRADER ARE ROBUST; in a 
US$35/bbl WTI price world we would 
expect to increase per barrel net backs 
by approximately US$9.50 over selling 
bitumen alone. Additionally, since we 
will be selling a light crude oil capable 
of feeding most reﬁ neries we reduce 
the impacts of existing heavy crude oil 
conversion capacity limits.

THE PROPOSED CANADIAN 
NATURAL UPGRADER represents
the logical extension of this third 
effort and leverages the upgrading 
and project management technical 
expertise from our Horizon Project. 
We will complete a Scoping Study to 
determine the optimal technology, 
location, size and product output of 
this heavy oil upgrader in 2006. If 
approved, we will utilize the same 
disciplined approach that is making 
the Horizon Project so successful 
– front end engineering and design.

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OUR PRIMROSE, KIRBY, GREGOIRE AND BIRCH MOUNTAIN in-situ opportunities headline 
a vast oil sands opportunity for our shareholders. We will develop these and other properties 
to provide feedstock for our upgraders. We target to bring on about 300 mbbl/d of new in-situ 
production in manageable, stepwise increments of 30 mbbl/d over the next several years.

Lightening the mix reduces marketing risks
and increases netbacks.

The Deﬁned Plan for 
Proﬁtable Future Growth

OUR PROJECT INVENTORY HAS NEVER BEEN STRONGER and this affords us the ability to add 
signiﬁcant transparency to our deﬁned growth plan. We articulate the optimal 5-year organic development 
strategy for every product and every basin in which we operate. Our knowledge of our basins, historic track 
records and lower-risk exploitation focus facilitate a realistic determination of base production declines, 
and results of the planned drill program. Major new project development expenditures and a conservative 
price deck of ﬂat US$35/bbl WTI are then applied to obtain a ﬁnancial view of the Company.

EVEN WITH CONSERVATIVE PRICING we remain well 
within our targeted ﬁnancial ratios. Opportunistic acquisitions 
have always been a key element of our strategy, and we have 
diligently altered our organic plans to accommodate them. That 
is the strength of owning and operating your project portfolio 
– you have the ﬂexibility to alter plans on short notice. While 
current pricing of assets remain outside of our parameters, we 
maintain ﬁnancial ﬂexibility in our plan to accommodate such 
acquisitions should they become available.

OUR SKILL SET CONTINUES TO EVOLVE 
enabling us to take on larger and more complex projects. 
We have developed deep water development proﬁciency, 
upgrading expertise and mega project management skills. 
Our team has evolved to maximize the value of our 
asset base. 

OUR FINANCIAL STRENGTH will allow us to continue 
to add to this expertise and to our project portfolio.

BY 2013, WE EXPECT OUR PRODUCTION LEVELS TO SIGNIFICANTLY INCREASE. Further 
given the nature of the additions we are making, our production mix will provide higher realizations 
and stronger cash ﬂows. This will make Canadian Natural a larger more sustainable company 
throughout the resource price cycle.

Building an even stronger,
more sustainable Canadian Natural.

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We do not compromise on our values and do not chase commodity prices. 
Recent high commodity prices have shifted our short-term emphasis solely 
into organic growth as acquisitions are expensive. Every well we drill must 
still  pass  hurdle  rates  similar  to  prior  years.  Our  major  developments  are 
still subject to extensive front end design prior to construction. Maintaining 
discipline is a core competency.

24 

 The Plan: Environment,
Health & Safety and Community 

26  The Assets: Review of Assets

40 The Assets: Year-End Reserves
45  Management’s Discussion & Analysis
 Auditors’ Report / Consolidated 
74 
Financial Statements

 Supplementary Oil & Gas Information

97 
102  Ten-Year Review
104  Corporate Information

Financial Highlights

FINANCIAL ($ millions, except per share data)
Revenue, before royalties 
Net earnings 
  Per common share  – basic (1)

– diluted (1)

Adjusted net earnings from operations (2)
  Per common share  – basic (1)

– diluted (1)

Cash flow from operations (2)
  Per common share  – basic (1)

– diluted (1)

Capital expenditures, net of dispositions 
Long-term debt 
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 

Barrel of oil equivalent (mboe/d)

Average prices before royalties (3)
Crude oil and NGLs ($/bbl)
  North America 
  North Sea 
  Offshore West Africa 
  Company average 
Natural gas ($/mcf) 
  North America 
  North Sea 
  Offshore West Africa 
  Company average 

2005

2004

$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 

10,107 
1,050 
1.96 
1.95 
2,034 
3.79 
3.78 
5,021 
9.36 
9.33 
4,932 
3,321 
8,237 

222 
68 
23 
313 

1,416 
19 
4 
1,439 
553 

39.62 
66.57 
59.91 
46.86 

8.65 
3.17 
5.91 
8.57 

$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 

7,547 
1,405 
2.62 
2.60 
1,405 
2.62 
2.60 
3,769 
7.03 
6.98 
4,633 
3,538 
7,324 

206 
65 
12 
283 

1,330 
50 
8 
1,388 
514 

33.16 
51.37 
49.05 
37.99 

6.61 
3.73 
5.25 
6.50 

$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 

2003

6,155
1,403
2.62
2.53
987
1.84
1.80
3,160
5.88
5.76
2,506
2,748
6,006

175
57
10
242

1,245
46
8
1,299
459

29.40
42.00
36.47
32.66

6.34
3.03
4.37
6.21

(1) Restated to reflect two-for-one share splits in May 2004 and May 2005.
(2)  Adjusted net earnings from operations and cash flow from operations are non-GAAP terms that represent net earnings adjusted for certain items of a non-operational and non-cash nature. 

The Company evaluates its performance based on these measures. Adjusted net earnings from operations and cash flow from operations may not be comparable to similar measures 
presented by other companies.

(3) Including transportation costs and excluding risk management activities.

4

Financial Highlights

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2005 represented a record year in 
terms of production, reserves and 
cash ﬂ ow. We remain poised for 
continued delivery.

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(cid:173)(cid:10)(cid:102)(cid:202)(cid:147)(cid:136)(cid:143)(cid:143)(cid:136)(cid:156)(cid:152)(cid:195)(cid:174)

(cid:228)(cid:120)

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(cid:211)(cid:93)(cid:211)(cid:120)(cid:123)

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(cid:206)(cid:93)(cid:199)(cid:200)(cid:153)

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2005

1,617 
13 
4 
1,634 

10,947 
352 
426 

785 
290 
148 
1,223 

3,378 
29 
83 
3,490 
1,804 

694 
290 
134 
1,118 

2,741 
29 
72 
2,842 
1,592 

1,848 
1,626 

2004

1,099 
11 
3 
1,113 

11,523 
565 
886 

695 
303 
125 
1,123 

3,202 
27 
81 
3,310 
1,674 

648 
303 
115 
1,066 

2,591 
27 
72 
2,690 
1,514 

– 
– 

2003

1,338
13
2
1,353

9,811
573
943

672
222
106
1,000

3,006
62
86
3,154
1,526

588
222
85
895

2,426
62
64
2,552
1,320

–
–

Financial Highlights

5

Drilling activity (net wells, excluding stratigraphic test/service wells)

  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 (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)

Net proved reserves (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 (after royalties)
  Bitumen (mmbbl) 
  Synthetic Crude Oil* (mmbbl)

*  SCO reserves are based upon upgrading of the bitumen reserves.

The reserves shown for bitumen and SCO are not additive.

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
THE PEOPLE
Our multi disciplinary teams leverage the 
skills of all members to deliver the Plan.

THE PLAN
We develop strategies for every facet of our 
operations to optimize our resources and 
control costs.

THE ASSETS
Our asset portfolio is deep, facilitating 
nimble reactions to changing business 
environments and opportunistic acquisitions.

6

Letter to Shareholders

ALLAN P. MARKIN
Chairman

N. MURRAY EDWARDS
Vice-Chairman

JOHN G. LANGILLE
Vice-Chairman

STEVE W. LAUT
President &
Chief Operating Ofﬁ cer

Letter to Shareholders

For Canadian Natural, 2005 was another exceptionally successful 
year. On the conventional side of the business, each of our four 
per-share business metrics have increased as shown below, adding 
to the substantial gains during the last 5 years. 

1–Year 

5–Year

Growth per share in:
8% 
  Net production  
8% 
  Net proved and probable reserves 
33% 
  Cash ﬂ ow 
  NAV of conventional reserves and land (1)  82% 

57%
66%
132%
194%

Over  and  above  the  conventional  side  of  the  business,  we 
sanctioned  Phase  1  of  the  Horizon  Oil  Sands  Project  (“Horizon 
Project”) in early 2005, obtained lump sum bids on a substantial 
portion  of  Phase  1  construction  costs  and  completed  19%  of 
the construction effort. The Horizon Project will add signiﬁ cant 
value 
for  shareholders,  with  commissioning  of  Phase  1
targeted at 110,000 barrels per day capacity of light sweet synthetic 
crude  oil  in  the  second  half  of  2008  (and  ultimately  targeted  at 
232,000 barrels per day as Phase 2 and 3 are commissioned) with 
no declines expected for decades to come. A year-end independent 
evaluation resulted in the booking of 3.4 billion barrels of gross 
proved and probable bitumen reserves for the Horizon Project.

We also added signiﬁ cant transparency to the longer term growth 
prospects  of  the  Company  by  articulating  our  extensive  in-situ 
oil sands plans and proposed heavy crude oil upgrader project as 
well as Phases 4 and 5 for the Horizon Project.

These proposed enhancements:

STRATEGIES AND THE BUSINESS 
ENVIRONMENT
During 2005, commodity prices remained strong, enabling us to 
reduce long-term debt by approximately $400 million while both 
spending $1.3 billion on construction of the Horizon Project and 
delivering on our base conventional business. This left our debt 
to book capitalization at only 29%, or 5 percentage points better 
than where we entered the year. 

However,  this  robust  price  environment  has  also  resulted  in 
a  high  demand  for  services  and  many  cost  control  challenges. 
During 2005, the industry set records for active drill rigs, meters 
drilled and the numbers of wells drilled in western Canada. This 
combined  with  the  general  business  and  construction  boom 
in  western  Canada  places  a  high  demand  on  the  labour  force 
and  creates  signiﬁ cant  cost  inﬂ ation  for  services.  Many  oilﬁ eld 
services and drilling day rate costs have increased by up to 30% 
over the past year. High activity levels have also resulted in a near 
doubling in per-hectare land acquisition costs. 

As such, maintaining discipline remains a priority. By adhering to 
our strategies, we have been able to mitigate much of these cost 
increases, maintaining our cost competitiveness. For example, our 
production expense and our ﬁ nding and onstream costs increased 
at  below  industry  average  rates,  despite  record  drilling  by  the 
Company and an increase in total land ownership. This reﬂ ects 
the execution of a well thought out multi-year development and 
drilling plan  and our  domination of  core region infrastructure, 
which facilitates low-cost reserve additions and synergistic cost 
savings across ﬁ elds. 

  •   Provide a natural migration of professional engineering and 

project management skills as well as construction workers;

Canadian  Natural’s  strategy  allows  us  to  allocate  capital  to 
maximize returns and remains predicated on:

  •   Unlock our vast heavy crude oil resource value potential;

  •   Capture  a  major  portion  of  the  value  chain  in  the  heavy 

crude oil business; and,

  •   Maintaining  a  large  project  portfolio  in  every  basin  we 
operate  to  enable  us  to  continually  high-grade  current 
developments;

  •   Maintaining  balance  in  our  product  mix,  project  time 

  •   Control  operating  costs  through  targeted  application  of 

horizons and ﬁ nancing strategies;

gasiﬁ cation technologies.

(1) Discounted value of conventional reserves and undeveloped land less net debt.

Letter to Shareholders

7

 
 
During 2005, our growth was primarily 
achieved though the drillbit as property 
acquisition costs remained high. This 
program resulted in crude oil production 
increases of 11% and natural gas 
volumes increases of 6% in Canada.

  •   Continually balancing between acquisitions and exploration, 

while remaining focused on low-cost exploitation;

  •   Identifying  and  completing  acquisitions  if  they  are  cost 

effective and provide strategic upside; and,

•   Controlling costs through area knowledge and domination 

of core focus regions.

2005 CONVENTIONAL OPERATIONS
IN REVIEW
During  2005,  our  growth  was  primarily  achieved  through  the 
drillbit as property acquisition costs remained high. Our drilling 
program  resulted  in  crude  oil  production  increases  of  about 
11%  over  2004  levels  and  natural  gas  volume  increases  of 
6%  in  Canada.  Expenditures  on  conventional  operations 
represented about 68% of the cash ﬂ ow generated by them.

INTERNATIONAL
Our International operations represented a signiﬁ cant portion of 
that growth. Average light crude oil production in the North Sea 
increased by about 4 thousand barrels per day or 6% from the 
previous year, the result of both an active in-ﬁ ll drilling program 
and the full year impact of an acquisition made in mid-2004. We 
have sufﬁ cient exploitation projects in inventory to maintain and 
marginally  grow  volumes  for  the  next  several  years  on  a  very 
economic basis. 

Our Offshore West African crude oil production volumes from 
Côte  d’Ivoire  effectively  doubled  from  11.6  thousand  barrels 
per  day  in  2004  to  average  22.9  thousand  barrels  per  day  in 
2005.  This  reﬂ ected  an  active  in-ﬁ ll  drilling  program  to  access 
previously untapped portions of the East Espoir development as 
well as the commencement of production from our ﬁ rst deepwater 
development  at  Baobab.  First  production  from  Baobab  was 
completed  in  just  4.5  years  from  ﬁ rst  discovery  –  an  excellent 
cycle time for deepwater developments. This achievement in our 
ﬁ rst deepwater development speaks to the technical expertise that 
we have developed and the diligence we demand in delivery.

We expect continued growth in Offshore West Africa as our West 
Espoir  satellite  development  is  completed  in  the  second  half  of 

2006  and  as  we  forecast  to  commence  production  in  late  2008 
from our recently acquired Olowi Field located Offshore Gabon. 
The Olowi Field was acquired during the fourth quarter of 2005 
and  we  ﬁ led  our  development  plan  with  the  Government  of 
Gabon by the end of the year. In early 2006 we received required 
approvals  and  have  already  commenced  the  engineering  tender 
process. The new opportunity created with the Olowi acquisition 
allows us to utilize our Offshore West Africa experience to quickly 
bring Olowi onstream.

NORTH AMERICAN NATURAL GAS 
We  remain  a  signiﬁ cant  producer  of  natural  gas  in  Canada, 
representing approximately 8.5% of western Canadian output. 
Further, our land base represents the second largest portfolio in 
the industry, meaning that we have exposure to virtually every 
play  type  found  in  the  basin.  As  our  largest  single  product 
offering at about 43% of our production mix in 2005, production 
increased by about 6% over 2004 levels driven largely by record 
natural gas drilling activity and the full year inclusion of property 
acquisitions made in 2004.

Most of the 2005 production growth was centered in Northwest 
Alberta where we continue to build on our strong base of assets 
acquired  in  2002.  This  core  region,  along  with  our  Northeast 
British Columbia core region, has the ability to drive corporate 
natural gas production growth of 3% to 5% for at least the next 
5 years. Our Northern Plains core region will provide relatively 
ﬂ at  to  slightly  declining  production  while  the  Southern  Plains 
region has potential to grow volumes both through its shallow 
and coal bed methane natural gas programs.

Our  5-year  deﬁ ned  plan  incorporates  a  disciplined  low-cost 
exploitation  methodology  for  each  of  our  natural  gas  assets 
assuming prices well below today’s market pricing.

NORTH AMERICAN CRUDE OIL AND NGLS
Success  in  our  Canadian  crude  oil  operations  continued  with 
production  increasing  by  over  7%  from  2004  levels.  At  our 
Pelican  Lake  Field  we  reversed  years  of  production  declines 
through  a  successful  waterﬂ ood  rollout  in  portions  of  the 
ﬁ eld.  The  development  of  Pelican  Lake  has  occurred  in  a  very 
disciplined manner. We experimented with different approaches 

8

Letter to Shareholders

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to  the  waterﬂ ood,  initially  obtaining  a  tripling  of  production 
with water cuts of 70%-80%. Our current approach, however, is 
providing per well crude oil production increases of 10-15 times 
with water cuts of only 10%. This application of waterﬂ ood may 
ultimately  double  expected  recovery  factors  from  the  reservoir. 
This same diligence will be used in our current testing of polymer 
ﬂ oods,  which  have  the  potential  to  again  signiﬁ cantly  increase 
recovery  factors  from  the  Field.  Based  on  our  success,  we  now 
expect  to  ramp  production  levels  at  this  Field  and  signiﬁ cantly 
extend Field life.

Our conventional heavy crude oil production grew throughout 
the year following the most active drilling program in our history. 
Similar to our natural gas approach we also have an extensive 5 
year development plan for these assets allowing us to maintain 
and grow volumes in a very disciplined manner. We continually 
leverage our large infrastructure and land base to control costs.

Our  thermal  in-situ  oil  sands  developments  also  continue 
to  outperform  our  expectations.  The  Primrose  development 
continued with the addition of 109 net new wells, which yielded 
production  increases  of  approximately  22%  over  2004  levels. 
Overall, the new Primrose well pads continue to produce at rates 
approximately  17%  better  than  expected.  The  Primrose  North 
expansion also continued on time and on budget with ﬁ rst crude 
oil production coming on stream in early 2006. This expansion 
will  add  about  30,000  barrels  per  day  to  exit  rate  production 
capacity in 2006.

Our  heavy  crude  oil  assets  in  Alberta  represent  a  substantial 
opportunity. We have extensive landholdings with both primary 
and  in-situ  oil  sands  areas  that  continue  to  deliver  signiﬁ cant 
returns.  However,  in  order  to  capitalize  on  these  assets  in 
a  disciplined  manner  the  Company  has  developed  a  strong 
marketing plan. We ﬁ rst articulated our heavy crude oil marketing 
strategy in 2003 and we have since been successfully executing 
against that plan. 

At about 140,000 barrels per day, Canadian Natural is now the 
largest  blender  of  crude  oils  in  western  Canada.  This  blending 

strategy  represents  the  ﬁ rst  element  of  the  marketing  strategy 
and allows us to sell product to an expanded group of reﬁ ners 
within our traditional geographic markets. The blending strategy 
has  evolved  to  allow  for  multiple  blends  that  can  be  changed 
as markets for various forms of diluents and ﬁ nal product price 
differentials change.

The  second  element  of  this  strategy  was  to  support  various 
pipeline initiatives to expand geographic markets. During 2005 
we committed to a 25,000 barrels per day shipping agreement on 
the reversal of the Corsicana line, which will enable us to deliver 
heavy crude oil directly into the US Gulf Coast. This market is 
important as much of the heavy crude oil conversion capacity in 
the United States is located in the region and heavy crude is sold 
for a premium to what is received in our traditional US Midwest 
markets.  We  continue  to  pursue  similar  opportunities  to  other 
markets in a disciplined manner.

Finally,  with  respect  to  the  pursuit  of  increased  heavy  crude 
oil  conversion  capacity,  we  proposed  in  late  2005  that  we  will 
leverage our technical expertise, project management skills and 
ﬁ nancial  capability,  which,  coupled  with  our  strong  asset  base 
would enable us to build our own upgrader in Alberta. To that 
end we are currently engaged in a scoping study that will deﬁ ne 
the location, nature and technologies to be utilized in this project. 
This proposed upgrader is targeted to be onstream in 2012, and 
will facilitate an additional 300,000 barrels per day of incremental 
bitumen  production  in  a  stepwise  and  disciplined  manner  over 
the  next  decade  selling  a  portion  of  it  as  light  crude  oil  rather 
than lower priced heavy crude oil. Capturing substantially more 
of the heavy crude oil value chain through upgrading not only 
increases  realizations,  it  also  reduces  marketing  and  cash  ﬂ ow 
risks  as  it  expands  markets  for  the  bitumen  and  eliminates  the 
impact of quality differentials.

HORIZON OIL SANDS PROJECT
This  bitumen  mining  and  upgrader  project  made  signiﬁ cant 
progress  during  the  year  following  the  sanctioning  for  Phase  1 
by our Board of Directors in February 2005. This approval was 
predicated on a disciplined process in which signiﬁ cant front end 

Letter to Shareholders

9

We believe that Canadian Natural has 
the People, the Plan and the Assets 
to continue to deliver shareholder 
value for years to come. We remain 
committed to “develop people to 
work together to create value for the 
Company’s shareholders by doing it 
right with fun and integrity”.

engineering efforts afforded us the ability to obtain the majority 
of  the  Phase  1  construction  costs  under  lump  sum  bids.  This 
high  degree  of  cost  certainty  was  augmented  by  an  expanded 
hedging  program,  which  ensured  that  adequate  free  cash  ﬂ ow 
to complete the four year construction effort would be available. 
While there was an opportunity cost associated with the hedging 
program,  it  was  the  combination  of  these  two  elements  that 
enabled the Company to retain a 100% working interest in the 
Horizon  Project  without  having  to  compromise  on  any  of  our 
conventional developments.

Four years and $400 million worth of front end engineering have 
provided Canadian Natural with a strong understanding of what 
we  are  building  and,  just  as  importantly,  how  we  are  going  to 
build it. We have forged relationships with a variety of contractors 
from  around  the  world  and  together  have  provided  a  strong 
deﬁ nition  of  the  construction  execution  plan.  Further  this  high 
project deﬁ nition reduces the risks associated with late engineering 
or “scope” changes which have historically resulted in signiﬁ cant 
cost  revisions  for  oil  sands  builders.  Finally,  we  have  developed 
a  unique  and  creative  labour  strategy  that  has  enabled  workers 
of all labour afﬁ liations from across Canada to participate in the 
construction effort. This strategy is facilitated through our ﬂ y in/
ﬂ y out capability from our on-site air strip. Today, workers from 
several  provinces  in  Canada  regularly  ﬂ y  to  our  site  and  home 
again on various shifts which accommodate their lifestyles.

Starting from a cleared site of dirt at the beginning of the year, 
we exit 2005 with approximately 19% of the construction effort 
completed. Deep underground facilities are installed, many of the 
footings are in place and much of the large prefabricated units are 
complete with several already being delivered to site. Although it 
is still early, we remain on schedule and on budget.

Our lump sum contractors are motivated to seek creative ways to 
build their portions more effectively. One opportunity identiﬁ ed 
by  them  was  the  exploitation  of  an  expected  lull  in  industry 
construction  activity  in  2006  which  should  make  additional 
workers  available  to  industry.  As  such,  they  requested  and  we 
approved the acceleration of $400 million of 2007 spending into 

10 Letter to Shareholders

2006, as long as they did not deviate from the base requirement 
of having 80% of engineering completed prior to construction. 
As a result, we expect to exit 2006 in excess of approximately 
55% of the construction effort completed. In all, we remain on 
budget and on schedule for ﬁ rst oil in 2008.

Further, in concert with our in-situ oil sands development plan, 
we announced the parameters of Phase 4 and Phase 5 expansions 
of the Horizon Project which will leverage the remainder of our 
mineable leases. We now target to produce in excess of 500,000 
barrels per day of light sweet synthetic crude oil from the Horizon 
leases  by  approximately  2017,  with  no  production  declines 
for  decades  to  come.  This  is  truly  a  world  class  development 
opportunity  and  we  intend  to  follow  the  same  disciplined 
approach that is currently being utilized on Phase 1.

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DEFINED PLAN
The  Canadian  Natural  team  is  proud  to  be  able  to  provide  a 
transparent strategy and growth proﬁ le to its shareholders. We 
still target to grow each of our four metrics by an average of 10% 
per annum and believe that we have the assets to deliver on it. 

Financially,  we  stress  tested  our  plan  at  US$35  WTI  per  barrel 
crude oil prices and would still remain below our targeted ﬁ nancial 
strength ratios. As such, we do not have to compromise on our 
basic  strategies  and  retain  additional  ﬁ nancing  capacity  should 
compelling  acquisition  opportunities  present  themselves.  Of 
course, as has occurred in the past, our disciplined allocation of 
capital may result in a shift between organic projects and acquired 
production as is prudent, should such an opportunity arise.

In  addition  to  the  production  growth  aspect  of  the  plan,  the 
migration of the production mix from one dominated by natural 
gas  and  heavy  crude  oil  to  one  dominated  by  light  crude  oil 
and  natural  gas  means  that  the  economic  sustainability  of  the 
organization is enhanced throughout the business cycle. Reducing 
overall  exposure  to  heavy  crude  oil  differentials  and  avoiding 
reliance on third parties to develop the markets for our products 
was a key consideration in our plans. We have taken control of 
the  plan  in  a  ﬁ nancially  and  operationally  disciplined  manner 
and will create a company and deﬁ ned plan that:

  •   Leverages the low-cost and lower-risk exploitation nature of 

the Alberta oil sands with light crude oil netbacks;

  •   Utilizes  an  exceptionally  large  land  base/infrastructure  to 
deliver increased natural gas volumes in an economic manner;

  •   Leverages  the  exploitation  expertise  developed  in  western 
Canada into the United Kingdom North Sea basin to create 
new value for shareholders; and,

  •   Fully exploits the offshore expertise developed in the North 
Sea, and combined with the strong relationships developed 
in Offshore West Africa enables us to identify appropriate 
new  exploration  and  exploitation  opportunities  in  one  of 
the most proliﬁ c light crude oil basins in the world.

Management  would  like  to  thank  our  team  for  continuing  to 
deliver the Plan. We would also like to extend our welcome to 
new  Directors  standing  for  election  this  year,  the  Honourable 
Gary A. Filmon, P.C., O.M., and Mr. Norman F. McIntyre.

We believe that Canadian Natural has the People, the Plan and 
the Assets to continue to deliver shareholder value for years to 
come. As a team, we remain committed to “developing people to 
work together to create shareholder value by doing it right with 
fun and integrity”.

ALLAN P. MARKIN
Chairman

N. MURRAY EDWARDS
Vice-Chairman

JOHN G. LANGILLE
Vice-Chairman

STEVE W. LAUT
President &
Chief Operating Ofﬁ cer

Letter to Shareholders

11

The People

Excellent people are critical to the success of any organization. 
The  Company  strives  to  achieve  a  balance  of  technical  skills, 
leadership,  and  a  strong  organizational  culture.  Even  with  the 
rapid expansion of our team, we have retained this balance.
Our technical skills have grown as we have expanded into new 
basins and products. For example, it was the upgrading expertise 

and  mega-project  management  skills  that  we  have  developed 
through  the  Horizon  Project  that  afford  us  the  potential  to 
undertake new initiatives such as the Canadian Natural Upgrader 
for our in-situ oilsands developments.
These are the people that make our team. Together we deliver the 
“Plan”, converting our strong assets into shareholder value.

Lonnie Abadier, Walday Abeda, Hazel Aberdein-Quirie, Mona Abravesh, Marbella Abuin, Janine Adams, Michael Adams, Steve 
Adams, Steven Adams, James Agate, Jennifer Ahern, Sarshar Ahmad, Garrisen Ailsby, John Aina, John Aina, Fiona Jean Aitken, 
Sina  Akinsanya,  Joseph  Albano,  Chris  P  Alderson,  Andrew  Alexander,  Bruce  Alexander,  Gregory  Alexander,  Elena  Algazina, 
Mohieddin Alghazali, John Allan, Selena Allan, Jill Allen, John Allen, Simon Allerton, William Allerton, Devin Allibone, Karen Almadi, 
Eva D Almeida, Gordon Almond, Robert Almond, Jocelyn Alonso, Nelson Alook, Cindy Alpaugh, Ulises Amador, Joann Aman, Clark 
Ambler, Donald Ames, Sylvia Anaka, Eric Andersen, Grayson Andersen, Jan Andersen, Troy Andersen, Bruce Anderson, Georgina 
Anderson,  Greg  Anderson,  Jeremy  Anderson,  Kelvin  Anderson,  Larry  Anderson,  Leonard  Anderson,  Murray  Anderson,  Paula 
Anderson, Perri Anderson, Richard Anderson, Peter Andrekson, Janet Andrew, Bob Andrews, Todd Andrews, Sherley Angers, Carolyn 
Angus, Brian Antoni, Rogerio B Antonio, Kathy Antonishyn, Shelley Antonuk, Jim Archibald, John Argan, James Arkley, Anthony 
Armstrong,  Darryl  Armstrong,  Randall  Armstrong,  Rob  Armstrong,  Paul  Arsenault,  Niels  Arveschoug,  Jim  Asmus,  Jacqueline 
N’Goran Asso, Sialla Victoire Assohou, Francklin Assoko-Mve, Maguy Aude Atheba, John Atkinson, Nicole Atkinson, Gordon Au, 
Maurice Aubin, Jason Auch, Bernard Auger, Richard Augustyn, Colin Avison, Eustace Azim, Adrian Baciulica, August Baier, Dave 
Baier, Janice Baik, Michael Baik, Dwayne Bailer, Rod Bailer, Leon Bakaas, Chris Baker, Sharon Baker, Patricia Bakker, Reginald 
Baldock,  Christopher  Baldwin,  Mark  Baldwin,  Vaughn  Baldwin,  Joel  Balkam,  Colin  Ball,  Gary  Ballas,  Ronnie  Ballas,  Sheldon 
Ballas,  Mamadou  Bamba,  Neville  Banak,  Darwin  Banash,  Rechelle  Baniqued,  Bob  Banks,  Teresa  Banny,  Inge  Bantli,  Garry 
Bardoel, Larry Bardoel, Pamala Bare, Sharon Barker, Stephen Barker, Michael Barnes, Javier Baroja, Kenneth Barrett, Phrona Lisa 
Barrett, Darcy Barry, Carol Barss, Marty Bartman, Sonia Basati, Julius Bascon, Calvin Bast, Cheryl Bateman, Lisa Bateman, 
Selena Bath, Brenda Battyanie, Jackie Bauer, Kevin Bauman, Juan Bavaresco, Veronica Bayley, Colin Beaman, Chad Beaton, Aura 
Beattie,  Laurier  Beaunoyer,  David  Bechtel,  Chris  Becker,  Elke  Becker,  Gurpreet  Bedi,  Ewan  Beenham,  Adrian  Begley,  Loren 
Behrens, Guy Belanger, Lesley Belcourt, Betty Belenky, Calvin Bell, David Bell, Faye Bell, Jon Bell, Larry Bell, William Bell, Reg 
Bellanger,  Lorne  Bellows,  Remie  Belmonte,  Ahmed  Bendahmane,  Khalida  Bendahmane,  Brad  Bendick,  David  Bendrey,  David 
Bennington,  Shelly  Bensmiller,  James  Bentley,  Linda  Beresh,  Debbie  Berg,  Lorn  Berg,  William  Berg,  Jeffrey  Bergeson,  David 
Berlinguette,  Henry  Berlinguette,  Joanne  Berrade,  Murray  Bertsch,  Jonathon  Best,  Stewart  Bettinson,  Bob  Bezpalko,  Marc 
Bickham, Jennifer Bidlake Schroeder, Douglas Bielech, Inge A Biener, Bruce Bignell, Rhett Binding, Roger Bintz, Warren Birch, Tim 
Bird, Hope Bishop, Travis Bishop, Paula Bissell, Peter Bissell, Darwin Bittner, Kevin Bjornstad, Adam Black, Chad Black, David 
Black, Jennifer Black, Kenneth Blackhall, Kerri Blackmore, Michael Blair, Deana Blais, David Blake, Christopher Blatchly, Parrish 
Blizard, Ellen Bloomﬁeld, Robin Bly, Allan Boddy, Brad Bodnar, Dennis Boehmer, Michael Boer, Kent Boerrichter, Darcy Boettger, 
Marty Boggust, Gordon Bohrson, Paul Boileau, Claude Boily, Peter Boisvert, Michael Bolianatz, Greg Bolin, Greg Bolton, Patricia 
Booklall, Jayne Booth, Karen Booth, Jack Bootsman, Charlene Boraas, Barry Borbely, Adriana Borbon, Albert Bordeleau, Michael 
Born, Jon Borstel, Prasanta Borthakur, Dave Bosch, Dave Bosek, Greg Boshaw, Keith Bottriell, Suzanne Boudignon, Kari Bouillet, 
Sheldon Bourassa, Daryl Bourque, Jason Bowers, Jim Bowers, Slade Bowers, Dale Boychuk, Doug Boyd, Patrick Boyd, Randy Boyd, 
Charline Boyer, Neil Bozak, John Brabec, Dave Bracey, Bryan Bradley, Peggy Bradner, Jan Bradshaw, Marianne Brady, Mary Jane 
Brady, Linda Bragg, Ralph Brand, Myron Brataschuk, Brad Braun, Colin Brausen, Vincent Breaker, Tara Brechin, Tara Brechin, 
Sharon  Breitkreuz,  Leonie  Breitling,  Joseph  Breland,  Paul  Breland,  Roxane  Bretzlaff,  Denis  Brisebois,  Robert  Brisson,  Shawn 
Brockhoff, Kelly Broda, Brian Brodbin, Ashley Broderick, Dwayne Brodziak, Katherine Brogden, John Brogly, Bill Bromling, Murray 
Brooker, Dennis Brooks, Carla Brown, Darren Brown, Jeremy Brown, Steve Brown, Robert Brownless, Elizabeth Brownrigg, John 
Brule, Gordon Bryant, Stewart Buchan, William Buchan, Anna Bucior, Linda Bucke, Natasha Buckland, Gordon Buckshaw, Linda 
Buczkowski, Malcolm Budd, Raymon Bueckert, Ryan Bulger, Ian Bulloch, Clarence Bur, Trevor Burchenski, Ian Burchette, Jeffrey 
Burdett, Brent Bureau, Heather Bureau, Keith Bureau, Grant Burgess, Alastair Burke, Crystal Burke, Gayle Burnett, Wendy Bursey, 
Gerald Burtch, Corinne Burton, Lisa Bush, Rosemary Bussi, Terry Butchart, Jim Butler, Bob Butterworth, Ronald Butts, Leanne 
Butz, Tricia Butz, Mike Byrtus, Irina Byvald, Joe Cabay, Mark Cadman, James Cadrain, Simon Cains, Laura Calder, Leslie Calder, 
Patrick  Caldwell,  Thomas  Callaghan,  Richard  E  Calliou,  Lynn  Callsen,  Dean  Cameron,  Mike  Cameron,  Rory  Cameron,  Shirley 
Cameron,  Tavis  Cameron,  Catherine  Campbell,  Clayton  Campbell,  Dean  Campbell,  Doug  Campbell,  Earl  Campbell,  Nancy 
Campbell,  Robert  J  Campbell,  Shawn  Campbell,  Valerie  Campbell,  Andre  Campeau,  Gregory  Cane,  James  M  Capjack,  John 
Capstick, Kathleen Carbury, Fred Cardinal, Harley Cardinal, Lee Cardinal, Sharon Cardinal, Wayne Cardinal, Jim Carey, Mary-Ann 
Carey, Ian Carleton, Wes Carlson, Daryl Carlton, Leslie Carlyle-Ebert, Albert Caron, Murrey W Carpendale, Kim Carrol, Eduardo 
Cartaya, Marilyn Carter, Gary Case, Mary-Jo Case, Trevor Cassidy, Mike Catley, Steve Caven, Tom Cegielny, Marco Celis, Samuel 
Cervantes, Sachi Chakravarty, Mark Chalmers, Erin Chamberlain, Joe Chamberlain, Cynthia Chambers, Katrina Chambers, Lise 
Champagne, Alan Chan, Anly Chan, Jack Chan, Jik Chan, Sarah Chan, Tim Chan, Christina Chang, Calvin Chapman, Melody 
Chapman,  Todd  Chapman,  Deon  Chappell,  Harry  Chappell,  Darryl  Charabin,  Cynthia  Chartrand,  Susan  Y  Chase,  Leon 
Chateauneuf, Siddique Chaudhry, Dawn Chau-Lam, Gary Chaulk, Jackson Chaves, Rinet Maria Chaves-Thissen, Jacinto Cheng, 
Mike Chernichen, Brian (Chuck) Cherry, Albert Cheung, James Cheung, Sherry Chiang, Gloria Chick, Patricia Childs, Melaine Chin, 
Sharon  Chin,  Jamie  Chisholm,  William  Chiverton,  Randall  Chodzicki,  Jessica  Choi,  Raymond  Chong,  Wayne  Chorney,  Lynn 
Chotowetz,  Sherry  Chow,  Daryl  Chrapko,  Alphonse  Chretien,  Ruth  Christensen,  Marianne  Christianson,  Steven  Christie,  Rob 
Christopher,  Andy  Chu,  Ken  Chudleigh,  Sharon  Chung,  Heather  Church,  Ronni  Church,  Kadidiatou  Cisse,  Magda-Christina 
Ciulavu, Michael Clapham, Bryan Clapperton, William Clapperton, Amanda Clark, Andrea M Clark, Evan Clark, Janice Clark, Evan 
Clarke, Martha Clarke, Olivia Clarke, Sanja Clarke, Shandon Clarke, William J Clarke, Walter Clarkson, Greg Clegg, George Clutton, 
Brooke  Coburn,  Dale  Coburn,  Judith  Cochran,  Sabrina  Colangelo,  Martin  Cole,  Robin  Coles,  Elva  Coley,  Curtis  S  Collins,  Rod 
Collins, Royston Collison, Ronald Compton, David Conybeare, Brad Cook, Brian Cook, Christopher Cook, Anna Cooke, Bill Cooke, 
Gary Coombe, Kent Cooper, Tammy Cooper, Jean Corbiere, Elaine Coreman, Rosetta Cormier, James Corner, Rosario Corral, Luis 
Correal, Jim Corson, Lorenzo Cortes, Neil Cortmann, Harry Costello, Neil Costeloe, Douglas Coull, Kim Coulter, Jack Courchene, 
Kathryn Courtney, Julie Cousineau, Dave A Cousins, James Coutts, Gordon Coveney, Richard Coward, Keith Cowger, Catherine 
Cowie, Jonathan Cox, Randy Cox, Wade R Cox, Nigel Crabb, Harry Crabtree, Layne Craig, Ryan Craig, Bruce Crain, Allen Crawford, 
Bryan  Crawford,  Marina  Crawford,  Paul  Crawford,  Beverley  Creed,  Leanne  Cressman,  Donald  Cretney,  Roger  Crichton,  David 
Cridland,  Stefan  Croft-Bednarski,  Christopher  Cross,  Lloyd  Cross,  Camille  Croteau,  Philip  Cruickshank,  Linda  Cruttenden, 
Anthony  Csabay,  Will  Csanyi,  Jeff  Cullen,  Corinna  Culler,  Francesca  Cultrera,  Darrel  Cunningham,  Davis  Cunningham,  Arley 
Currie, David Currie, Brent Curtis, Paul Curtis, DaleS Cusack, Kenneth Cusack, Pat Cusack, Réal Cusson, Midge Cuthill, Don 
Cutting, Ken Cyr, Andre C DaCosta, Helder J DaSilva, Ivone Elma Malaquias DaSilva, Victor Daboin, Greg Dacyk, Fakhri Dadashov, 
Gary Dahl, Hamid Dahmani, Eliane Dakaud, Trevo D Dales, Joey Daley, Layne Dalgetty-Rouse, Walter M Danchak, Gene Danyluk, 
Peter Danyluk, Alan Dar, Eric Dargis, Lynne Darlington, Wigo Dascalescu, Graham Davidson, Marie Davidson, Philip Davidson, Tim 
Davidson, Todd Davidson, Frank Davis, Graham Davis, Randall Davis, Robert Davis, Sarah Davis, Jeffrey Davison, Peter Davison, 
Leonard Dawe, Robert Day, Eric de Kock, Douglas De Avila, Ryan De Bruyne, Phil De Gagne, Ryan De Leeuw, Lance De Meillon, 
David Dean, Harry Dean, Derek Dechaine, Raymond Dechaine, Roland Dechesne, Sheldon DeFord, Mervin J Degenstien, Barbara 
Deglow, Daniel L Deiana, Bonnie Deis, Natalie Delfs, Gabriel Deliu, Franco Dell’Ovo, Benita De Lorenzo, Brent Delorme, Michael 
Delorme,  Fiona  Dempster,  Susan  Dennis,  Shirley  Denny,  Edward  Deren,  Tom  Dereniwski,  Semir  Dervovic,  Eugenie  Dery,  Travis 
Desilets, Michael Des Roches, Laurie A Devey, Wendy De Visser, Robert Dewis, Karen Deyaegher, Vikas Dhawan, Aldo Di Flumeri, 
Karim Mounian Diallo, Harry Diamantopoulos, Sumara Diaz, Daniel Diaz-De-Leon, Catherine Dicken, Robert Dicken, Garry Dickie, 
Cameron Dickson, Irene Dikau, Anne Dillon, Michael Dingley, Ashley Dinkel, Ronald Dinkel, Hubert Dinn, Issiaka Diomande, Gayle 
Dionne, Al Dixon, Kathleen Dixon, Trent Dixon, Denise Dixson, John Dmetruik, Angela Dobb, Leanne Dobson, Linnae Dobson, Edward 
Dochuk,  Alistair  Dodds,  John  Dodman,  Erin  Doepker,  Kelly  Doepker,  Ritchie  Doering,  Patrick  Dolan,  Amy  Dolomount,  Conrad 
Dombowsky, Kelly Dombrosky, Brenda Dombrova, Manuel P Domingos, Dan Domke, Kyle Donald, Scott Donaldson, Tim Donkersloot, 
Tim Dootka, James Doran, Allen M Dorey, CecilI Dorey, Mathieu Dorval, Olga Dost, Réal Doucet, Edward Douglas, Dahl Dow, Angela 
Dowd, Phil Downes, Wayne Draper, Don Drindak, Colleen Drury, John Drury, Steven Drysdall, Calvin Duane, Laurie Dube, JoAnne 
Dubeau, Renee Dubeau, Jeramie Ducharme, Albert Duczek, Jon Dudley, Rhonda Dudley, Simon Dugdale, Douglas Duguid, Albert 
Duhaime, Cheryl Dumais, Barry Duncan, Lois Duncan, Sean Duncan, Dale Duniece, Graham Dunlop, Jill Dunlop, Robert Dunn, 
Andrew Dunne, Judy Dunsmuir, Lyle Dupuis, Dariela Duran, Harvey Dutchak, Diane Duthie, Eugene A Dyjur, Krzysztof Dzwonek, Gary 

12

The People

Earl, Kevin Earle, Julie Easthope, Suzanne Eaton, Sean Ebert, Jim Eby, Greg Ecker, James Edens, Robert Edgar, Josephine Angie 
Edoukou, Gordon Edward, Dave Edwards, Susan Edwards, Fred Eefting, Cindy Egden, Nicole Eitzen, Devin Ekdahl, Wassim El 
Chayati,  Douglas  Elder,  Carole  Eliuk,  Anthony  M  Ell,  Mohamed  El-Naas,  Jerry  Enders,  Rommel  Engler,  Joanne  English,  Chris 
Erickson, Terry Erickson, Kresten Eriksen, KenI Erker, Polina Ersh, Rick Estrada, Dave Evans, Lee Evans, Tim Evans, Leila Eveleigh, 
Maureen Evers-Dakers, Clayton Eves, Adrian R Ewasiuk, Laura Ewen, Douglas Eynon, Leonard Fabes, Lawrence Facchina, Denis 
Fagnan, Heather Fahey, Catherine Falconer, Andy Fankhauser, Travis Farrer, Ravinder Farwaha, Stefa Fassina, Arthur Faucher, 
John Fay, Karman Fayant, Tanya Fayant, Brian Fehr, Darwin Feil, Ira C Feland, Maria H Felix, Andre Yves Felix Tchicaya, Kurt 
Fenrich, Randy Fenton, Ken Ference, Brad Ferguson, Helen Ferguson, Mark Ferguson, Roy Ferguson, Scott Ferguson, Mario Feria-
Estrada, Joaquim Fernandes, Cory Fernets, Darren Fichter, Tiziana Ficocelli, Alan Fiddes, Jane Fielding, Michael Filipchuk, Natalie 
Filippini, NeilA Findlay, Kelly Finigan, Bob Finlayson, Chad Finnebraaten, Tanya Fir, John Fisera, Calvin Fisher, David Fittkau, Bill 
Fitzgerald, Sandra Fitzpatrick, Paul Flanders, Ken Fleck, Sean Fleming, Rodney Flett, Trevor Flood, Edmond Foisy, Justin Foisy, 
Ryan Folkerts, Gregory Fontaine, Robert Fontaine, Roger Fontaine, Lynn Foo, Harris Foote, Adele Forcade, Curtis Formanek, Randy 
Formanek,  Devon  N  Fornwald,  Leslie  Forrester,  Alastair  Forsyth,  Alstair  Forsyth,  Brenda  Forsyth,  Chantal  Fortin,  Gilles  Fortin, 
Thomas Fortin, Donald Foster, Dwayne Fotty, Kevin Foulds, Lise Fournier, Neil Fowler, Peter Fowler, Donald Fox, Donna Frame, Joao 
A Francisco, Ron Frank, Shelley Franssen, Leonard Fraser, William Fraser, Barry Frazer, Ken Frazer, Ted Frederickson, Michael 
Freeman,  Stacey  Freidin,  Tammy  J  Fremont,  Roger  Frere,  Kurt  A  Freyman,  Brad  Friesen,  Kenneth  Friesen,  Tracy  Frith,  Andrei 
Frizorguer,  Frank  Frosini,  Scott  Froude,  Karen  Fujimoto,  Jim  Fung,  Sarina  Fung,  Ted  Furuya,  Don  Gabruck,  Josephine  Gaddi, 
Leonard Gadowski, Sharon Gaehring, Kelly Gagne, Larry Galea, Ron Gall, Michael Gallon, A William Galloway, Carmen Galue, Yoko 
Galvin, Bob Gandhi, Carlos Garcia, Doug Gardner, Jon Gareau, Glen Garton, Stan Garwon, John Gates, Joseph Gaugler, Maurice 
Gauthier,  Neil  Gauthier,  Steve  Gavronsky,  Paul  Gazzard,  Alain  Gbo,  Michael  Geldert,  David  Geleta,  Lesley-Ann  Gemmell,  Neil 
Genge, Patricia Gentles, William George, James Georget, Matthew Gering, Grant Gerla, Michel Germain, Raymond Germain, Robert 
Germain, Albert Gervais, Marc Gervais, Paul Gervais, Bob Gerwing, Sheldon Getson, Beryl Gettings, Clark Getz, Glen Getz, Ken 
Getzinger, Zoheir Ghaddar, Douglas Gibson, Charles Giddings, Jean Giesbrecht, Todd Giesbrecht, Dwayne Giggs, Laura Giggs, 
Elias Gildeh, Tamara Giles, Gladwin Gill, Perry Gillam, Jeremy Gillespie, John Gillespie, Sharen Gillett, Janna Gillick, Sandra Gillis, 
Justin Gilmour, Scott Gilmour, Douglas Ginn, Anna Giove, Stewart Girbav, Ben Gisby, Eugenio Giuliani, Marvin Gladue, Russell 
Gleed, John Glennon, Duane Goetz, Peter Goetz, David Golden, Cody Gomuwka, Brian Gonsalves, Yvonne Gonzalez, Ian Gordon, 
James Gordon, Wendy Gordon, Winston Goretsky, Yvon Gosselin, Allan Gould, Todd Gould, Antonella Goulet, Sandra Goundrey, Carl 
Graham, Pamela Graham, Stephanie Graham, Harry Grant, Allissa Gray, David Gray, Ronald Gray, Sheila Gray, John Greaves, Linda 
Green, Theresa Greene, Ernie Greenwood, Lisa Gregg, Derek Greidanus, Clint Greschner, Edmond Grifﬁths, Leo Groenewoud, Robert 
Grover, Wayne R Gruhlke, Daryl Grundner, Neil Guay, Trevor Guay, Cesar Guercio, Don Guglielmin, Gilbert Guigon, Robert Gullion, 
Shane Gullion, Swarna Gunaratne, Carolyn Gunderson, Alan Gunst, Ashok Gupta, Rustam Guseynov, Edward Gushnowski, Terry 
Gusnowski,  Elaine  Gussman,  Graham  Gustafson,  Harold  Gutek,  Fabio  Gutierrez,  Bartley  Haahr,  Violet  Haddad,  Resad 
Hadzismajlovic, Keri Hagemann, Egbert Hagens, Chad Hagstrom, Keith Hague, Sam Hajar, Shemin Haji, Zohreh Hajibeygi, Dan 
Halaburda, Montie Hale, Dean Halewich, Eric Haley, Rick Halkow, Barry Hall, Charles Hall, Donald Hall, Kathy Hall, Shane J Hall, 
Todd  Halladay,  Patricia  Halldorson,  James  Hallett,  Robert  D  Hallett,  Charlene  Halter,  Larry  Hamende,  Jeremy  Hamilton,  Tim 
Hamilton, Kevin Hamm, Michael Hammel, Larry Hammell, Rick Hammond, Chrystal Hamori, Elaine Hampton, Brad Hancock, Anne 
Hand, Carol Handley, Shane Handsaeme, Tracy Hanline, Karl Hann, James Hansen, Ole Hansen, Todd Hansen, Judy Hanson, Leland 
Hanson, Brent Harbin, Leon Harder, Kent Hardisty, Ken Harke, Brent Harle, Leslie Harley, Angela Harlos, Erik Haroldson, Bill Harris, 
Chad Harris, Jody L Harris, Murray Harris, Roger Harris, Ron Harris, Clayton Harrison, Dylan Harrison, Randy Harsany, James Harty, 
Mike Harty, Janet Harvey, Jerry Harvey, Julie Harvey, Robert Harvey, Cory Harvie, Cheryl Hasenclever, Colin Hastings, Iain Haston, 
James Haston, Ewen Hatchwell, Bryan Hattebuhr, Christine Hattebuhr, Dale Hattebuhr, Helen Hattie, Barret Hatton, Wayne Hatton, 
Dave Haub, Dave Haub, Willow Hauber, Wayne Hausch, Lew Hayes, R Joey Hayward, David Haywood, Sean Head, Jay Heagy, Larry 
Heath, Brian Hebert, Gerald Hebert, Terry Heck, Ken Hedstrom, Della Hefford, Sherrie Heil, Robin Hein, Raymond Heisz, Mahmud 
Hejni, Greg Helman, Barton Henderson, Steven Hennessey, John Hennessy, Leona Hennig, David Henry, Jackueline Herauf, Kim K 
Herbst, Sheri Herman, Judith Hermann, William Hernandez Paredes, Darryl E Herner, Luis Herrera, Coreen Herring, Keith Heslop, 
Andrew Higgins, Rachelle Higgins, Tyla Higgs, Charlene Hill, Gordon Hill, Marie Ellen Hill, Steve Hill, Jesse Hillebrand, Laureen 
Hillebrand, Jeff Hillier, Christie Hillis, Arnold Himschoot, James Hinde, Jim Hlewka, Margaret Ho, Donald Hoar, Barry Hodgan, Gary 
Hodge,  Barbara  Hofer,  Miles  Hogaboam,  Joanne  Hogg,  Kevin  Hogg,  Krista  Hogg,  Kevin  Hoium,  Donald  Holley,  Doug  Holman, 
Richard Holman, Donald Holmen, Cliff Holmerson, Chris Holmes, Ian Holmes, David Holt, Kim Holtby-York, Clayton Holthe, Dennis 
O Holthe, Shannon Hood, Hans Hoogendam, Blaine Hook, Graham Hook, Keith Hornseth, Camelia Horvath, Lance Hoskyn, Helena 
Houghton, Sherri Houle, John Howard, Trapper Howard, Kristy Howe, Kim Hranac, Jianxin Huang, Joanne Huang, Michael Hudgins, 
Paul Hudson, Sandy Huebner, David Huff, Jeremy Hughes, Mark Hughes, Eun Ju Huh, Wayne Hui, Bryan Huk, Riley Hull, Terry 
Humbke,  Manpreet  Hundal,  Jennifer  Hunt,  Kevin  Hunter,  Robert  A  Hunter,  Tom  Hunter,  Vivian  Hunter,  James  Hurdal,  Bradley 
Hurtubise,  Glenn  Hussey,  Daniel  Hutchinson,  Dennis  Hutchinson,  Myrna  Hutchinson,  Ray  Hutscal,  Bruce  J  Hutt,  Greg  Huva, 
Stephen Hygard, Bonnie Hynes, David Hynes, Scott Hyrcha, Sarah Hyslop, Matthew Ilchuk, Detlev Imorde, Dominic Ing, Jennifer 
Inglis, Brad Inman, Rebecca Innes, Jamieson Irons, Jeff Irons, Dora Irsa, Darren Isele, Khalid Ishaq, Floyd Isley, Karen Ivan, Jeff 
Iwanaka,  Nicholas  Jack,  Wallace  Jack,  Allen  Jackson,  Daniel  Jackson,  Judy  Jackson,  Kevin  Jackson,  Russel  Jackson,  Victoria 
Jackson, Ken Jacobs, Ken Jacobson, Albert Jacula, Curtis Jacula, Irene Jacula, Todd Jacula, Hamid Jafari, Charu Jain, Vivek Jain, 
Michael  Jaindl,  Boris  Jakulj,  Annie  Jalotjot,  Chris  James,  Bob  Jamieson,  Nigel  Jamieson,  Maria  Jancewicz,  Marc  Janke,  Steve 
Jansky, Peter Janson, Leonard Janzen, Crystal Jardine, Nancy Jarman, Calvin Jarratt, Dave Jarrell, Joanie Jarvis, Mark Jean, Wendal 
M Jellison, Megan Jenkins, Jason Jenner, Lindsay Jenner, Brent Jensen, Kevin Jensen, Parry Jensen, Qi Jiang, Agostinho Joao, Terry 
Jocksch, Amy Johnson, David Johnson, Evan Johnson, Jeffrey Johnson, Marlene Johnson, Mitzi Johnson, Neville Johnson, Stacy 
Johnson, Susan Johnson, Joe Johnston, Neil Johnston, Dan Johnston-Watson, Victoria Jolliffe, Brent Jones, Delbert Jones, Gareth 
Jones, Lori Jones, Mark Jones, Pamela Jones, Paul Joo, Damian Jordan, Joy Joseph, Jaime Juan, James Jung, Chris Jungen, Judd 
Jurado, James Jurome, Melanie Juurlink, Paul Kabatek, Asif Kachra, Carol Kadutski, Jonathan Kadutski, Raymond Kahanyshyn, 
Myra Kalakailo, Dustin Kalinsky, Sheron Kalirai, Derek Kalynchuk, Elizabeth Kaminski, Ari Kandasamy, Shari Kane, Nashila Kanji, 
Sam  Kapoor,  Dwayne  Kaprowski,  Tom  Karpa,  Angela  Karst,  Doug  Kary,  Lynn  Kasper,  Shelina  Kassam,  Myles  Kathan,  Deanne 
Katnick, Christopher Kean, David Keck, Philip Keele, Christopher Keim, John Keith, Rayelene Kellock, Christine Kelly, Ken Kelly, Tim 
Kelly, Simon Kelsey, Gregory Kemp, Denise Kennedy, Wayne Kennedy, Val Kenyon, Blair Kessler, Lori Ketchuk, Amjad Khan, Tatiana 
Kharitonova, Kimberly Kielt, Leonard Kiez, Todd Kilback, Iain Kilpatrick, Selma Kilpatrick, Curtis Kimler, Douglas King, Kurt King, 
Richard W King, Richard King, Tasha Kingsbury, Peter Kinnear, Cam Kinniburgh, Marvin Kinsman, Sandra Kintzl, Anthony Kirtley, 
Cryssy Kish, Brent Kissel, Marlene Kissel, Robyn Kissel, Shane Kissel, Marlene Kissoon, Mario Kiteculo, Bob Kitsch, Myles Kitt, Ken 
Kiyonaga, Cody Klatt, Dalton D Klippert, Douglas Klug, Jeff Knibbs, Allen Knight, Anita Knipe, Patricia Knipe, Olga Knopov, Ernie 
Knowles, AJohn Knutson, Russ Kobi, Corey Koble, Barney Kobzey, Kouakou Laussin Emma Kofﬁ, Blair Koizumi, Lutz Kolberg, Eva 
Komers, Cameron Komm, Brent Kondratowicz, Ibrahim Kone, Brent Korolischuk, Jennifer Koslowski, Diane Kostiuk, Ann Kostyshyn, 
Stacey Kotelniski, Marcelin Yao Koua, Hermann Didier Kofﬁ Kouame, Richard Kowalski, Kevin Kowbel, James S Kowula, Dennis 
Kozak,  Teresa  Kozina,  Dale  Kozma,  Cameron  Kramer,  Andrew  Krancz,  Lyndon  Krankowsky,  Trevor  Kratz,  Bryan  Krause,  Trevor 
Krause, Todd M Kreics, Jeffrey Kreiser, Patti Krekoski, Connie Kriaski, Michael Krips, Udaya Kumar Krishnan, Peter Krol, Vanja 
Krtolica, Gabriel Krywolt, Chris Kubisch, George Kucy, Warren Kueﬂer, Amit Kumar, Vikas Kumar, Len Kurowski, Frank Kurucz, Steve 
Kuzmak, Daisy H Kwan, Keith Kwan, Kelly Kwiatkowski, Angele Kwon, Karen Kyfﬁn, Bob Kyllo, Robert Laboucane, Jocelan Ladner, 
Philip Lafond, Anny Lafontaine, Levi Lafrance, Ronald LaFrance, Cassandra Lai, Philip Lai, Amy Laidlaw, Ronald Laing, Edward G 
Lalande, Mahmud Lalani, Elaine Lam, Kurtis Lamb, Susan Lamb, Terri Lamb, Dino Lambert, Richard Lameman, David Landers, 
Marc Landry, Michel Landry, Francis Aaron Lane, Robert Lang, Marc Langford, John Langille, Carolyn Langpap, Michelle Lapointe, 
Pamela Lapp, Melvin Lapratt, Corey Larocque, Leon LaRose, Ozlem Larsen, Dave Larsh, Rob Larson, Robert Larson, Ronald Lasek, 
Reno Laseur, John Lasocki, Daniel Lastiwka, William Latchuk, Joan Latter, Krista Latunski, Laura Latyn, Michael Laudel, Robert 
Lauder, Karen Laurin, Steve Laut, Bernard Lavoie, Iris Law, Joanne Law, Lucas K Law, Darron D Lawrence, Ewen J Lawrence, Fred 

(cid:32)(cid:213)(cid:147)(cid:76)(cid:105)(cid:192)(cid:202)(cid:156)(cid:118)(cid:202)(cid:10)(cid:62)(cid:152)(cid:62)(cid:96)(cid:136)(cid:62)(cid:152)(cid:202)(cid:32)(cid:62)(cid:204)(cid:213)(cid:192)(cid:62)(cid:143)(cid:202)(cid:105)(cid:147)(cid:171)(cid:143)(cid:156)(cid:222)(cid:105)(cid:105)(cid:195)

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Lawrence, Lindsey Lawrence, Shareen Lawrence, Brian W Lawson, Martin Lawson, David Laycock, Chelsea Layden, Sharon Layton, 
Greg Lazaruk, Brian Leach, Doug Leach, Trevor Leach, Albin Leaf, Amanda Leam, Margo Lebel, Rodney Leblanc, Sarah LeBlanc, 
Carmen Lee, Colleen Lee, Howard Lee, Jane Lee, John Lee, Swee Lee, Tim Lee, David Leeper, Caroline Lefebvre, Kevin Legault, 
Heather Leggett, Kris Lehocky, Christine Leibel, Alfredo Leon, Gustavo Leon, Heather Leonard, Joseph Leonard, Gary Leong, Hin 
Leong,  Stephen  Lepp,  David  Lesko,  Gerry  L  Leslie,  Marcus  Lethaby,  Phil  Letkeman,  Don  Leung,  Esther  Leung,  Katie  Leung, 
Preeminence  Leung,  Maurice  Levac,  Tracy  Levasseur,  Jean  Levesque,  Shelly  Lewchuk,  Susan  Lewis,  Katherine  Leys,  Larry 
L’Hirondelle, Jun Li, Craig Liba, Geof Liddon, Richard Lim, Suzanne Lin, Bonnie Lind, Jessica Lind, Katherine Linder, Ewen Lindsay, 
Shari Lindsay, Trina Lineger, Janice Linehan, Annette Linggon, Yvonne Linnartz, Yuri Lipkov, Tracy Little, Tony Littlefair, Dennis Liu, 
James Livingston, Michael Livingstone, Cam Lizee, Dale Lloyd, Debby Lo, Sharon Lo, Conrad Loch, Fredrick Lock, Richard Lock, 
Fred  Locke,  Kendall  Locke,  Darren  Loder,  Joy  Lofendale,  Per  Lofgren,  Shauna  Logan,  Randal  Logelin,  Rodney  Logozar,  Jorge 
Lombardi, Craig Long, Wade Longmore, Dallas Longshore, Herb Longworth, Kai Loo, Nelson Lord, Catlin Lorenson, Darin Lorenson, 
Matthew Lorincz, Bob Lorinczy, Michelle Lou, Andrew Lough, Allan Loughran, Larry Love, Mellodie Love, Dan Lowe, Darryl Lowe, 
Devin Lowe, Brad Lowell, Leah Loyola, Gerd Lucas, Serena Lucci, Crystal Lucier, Dana Lund, Wes Lundell, Paige Luong, Jason Lush, 
Rees Lusk, Wendy Lutzen-Askew, Brent Lydiatt, Kathy M Lydiatt, Ken Lynam, Jim Lyons, Nicky Maawia, Patricia MacCrimmon, 
Lindsey Macdearmid, Garry MacDonald, Jason MacDonald, Mark MacDonald, Ray MacDonald, Raymond G MacDonald, Stephen 
MacDougall, Carl Machin, Shawn Mack, Kenneth Mackenzie, Ken MacKenzie, Ryan MacKenzie, Shawn MacKenzie, James William 
MacKinnon, Jesse A MacKinnon, Joseph M MacKinnon, Graham Mackintosh, Richard MacKnight, Mark MacLean, Susan MacLean, 
Douglas MacLeod, Jamie MacLeod, E Anne MacNeil, Bradley MacNeill, Angela MacNiven, Angela MacNiven, Marilyn Macoy, Heidi 
Macrae, Ronald MacSween, Bruce Maddex, Morgan Maddison, Hazel Madore, Gary D Madsen, Markus Maennchen, Cathy Mageau, 
Mike Magnusson, Bill Mah, Glen Mah, Jennifer Mah, Darren Mahony, Martin Mailhot, Al Majdzadeh, Michelle Major, Anita Mak, 
Darren Mak, John P Malachowski, Ronald Malboeuf, Lanre Maliki, Linda Maloney, Mike Manchen, Leonard Mandrusiak, Darcy 
Mandziak,  Avy  Mann,  Darcy  Mann,  Don  Mann,  Ronald  Mann,  Rachelle  Mantei,  Roy  Marceniuk,  Catherine  Marchuk,  Ronald 
Marcichiw, Nicholas Margiotta, Shane Marion, David Mark, Luis Marquez, Aaron Marshall, Lynn Marshall, Mary Marshall, Stephen 
Marshall, Karen Martin, Lindsay Martin, Dave Marttila, Mike Masse, Mandy Massiah, Al Massicotte, Richard Mathieson, Davinder 
Mathur, Scott Matieshin, Tracy Matthews, Tim Maxwell, Richard May, Edward Mayer, Lyle Mayer, Scott Mayer, Scott R G McAllister, 
Leslie  McAuly-Brand,  David  R  McBride,  Pat  L  McCarron,  Bruce  McChesney,  Lana  McClenaghan,  Crystal  McCormack,  Robert 
McCormick, John McCoshen, Clete McCoy, Erin McCoy, Ken McDavid, Cynthia McDonald, Kevin McDonald, Mark McDonald, Steve 
McDonald, Stewart McDonald, Rod McDougall, Laurie McEwen, K Tracy McFadyen, Debra McFarlane, Bruce McFaul, Allan McGann, 
Frances McGlynn, Terence McGovern, Grant McGowan, Robert McGowan, Ryan McGowan, Brandy McGrath, Bruce E McGrath, Paije 
McGrath, Steve McGregor, Stephen McGregor, Tom McHale, Gordon McHattie, Eric McIntosh, Sandra McIntosh, Stephanie McIntyre, 
Daniel McKain, Kelvin McKay, Kim I McKay, Lindsey McKay, Rod McKay, Roxana McKay, Tim McKay, Keith McKenzie, Mike McKenzie, 
Douglas McLachlan, Bonnie-Lynn McLaren, David McLaughlin, John McLean, Marla McLean, Michelle McLean, Joan McLellan, 
Kaye McLellan, Ian McLeod, Eamonn McMahon, Blake McManus, Sandra McMichael, Bryan McNamara, David McNamara, Kendal 
McNeil, Lynn McNeil, Stephanie McNeil, Bill McNeill, Stephanie McNeill, Jaime McNichol, Reid McPhail, Elaine M McPherson, Rick 
T  McQueen,  Tracy  McRae,  Maggie  McTurk,  Frank  McVey,  Karyn  Meehan-Coles,  Corrine  Mei,  Barry  Meier,  Daniel  Meier,  Gloria 
Melenberg, Belinda Meller, Dick Mellor, Darrell Mellott, Jean Melnychuk, Marvin Melnyk, Paul Mendes, Lynette Mercer, Lynn Mercer, 
Mark  Mercer,  Timothy  Merk,  Greg  Merkel,  Danny  Merkley,  Nathaniel  Merritt,  Udell  Meservy,  Steve  Meunier,  Rick  Meyers,  Cindy 
Michalko, Barry Michelson, Murray Michie, Ian Middler, Dale Midgley, Jacek Mielczarek, Marc Miiller, Jane Mikalsky, Jacqueline 
Miko, Carolina Milla, Jeffrey Miller, Laurel Miller, Wendy Miller, William Miller, Bruce Mills, Claire Mills, H John Mills, Jeff Mills, Rob 
Mills, Ronald Mills, Colin Milne, June Milne, Stephen Milne, Michelle Minick, Wyman Minni, Denis Mino, Kerry Minter, Carolyn 
Minton, Alan Minty, Maria-Celeste Miranda, Umar Mirza, Daleep Misri, Allan Mitchell, Brent Mitchell, Yvonne Mitchell, Neven 
Mitchell-Banks, Anar Mitha, Leon Miura, Glen J Mock, Tom Moen, Derek Moir, Rosa Moises, Lydia Mok, Mimi Mok, Jeff Molde, 
Dwayne Molle, Jelena Molnar, Huguette Monette, Mike Monias, Roy Monro, Rick Monteith, Bill Montgomery, Alfred MoonJr, David 
Moore, Judy Moore, Kevin Moore, Melinda Morante, Jason Moravec, Christopher Morgan, David Morgan, Jonathan Morgan, Karen 
Morgan, Marcia Morgan, Michael Moriarty, Shaun Moroziuk, Karen Morrice, Paul Morris, Scott Morris, Terry Morris, Tyler W Morris, 
Jennifer Morrison, Louise A Morrison, Joseph Morrow, Wesley N Morrow, Shannon Moseng, Paul Mossey, Glen Mott, Bruce Mottle, 
Cheryl Mouta, Wayne B Mudryk, Sieg Mueller, Colin Muir, Lee-Ann Mules, Lucy Mulgrew, Noella Mulvena, Martin Munday, Blair 
Munro, Ryan Munro, Cora Murphy, Clifford Murray, Dale Murray, Dean Murray, Deirdre Murray, Patricia Murray, Shara Murray, 
William K Muss, Kevin D J Mutch, Lorna Myers, Eva Myles, David Myshak, Melonie Myszczyszyn, Richard Nachtegaele, Aleksandra 
Naczk-Cameron, Ashley Nagy, Jeannine Nagy, Zoltan Nagy-Kovacs, John Naismith, Bill Nalder, Elly Nance, Rick Napier, Bill Nash, 
Darren  Naugler,  Bill  Navratil,  Henriette  Ndjoteme-Nendjot,  Marian  Neagu,  Randy  Necember,  John  E  Neff,  Fikerte  Neguisse, 
Eduardo Neira, Aaron Nelson, Douglas Nelson, Gilbert Nelson, Peter Nelson, Vincent Nelson, Cheryl Nepinak, Brad Nessman, Monty 
Neudorf, Caleb Neufeld, Brian W Neumeier, Dustin Newman, Jason Newman, John Newman, Nicholas Newman, Kevin Newton, 
Alice Ng, Hannah Ng, Tchimou P N’Gbesso, Eileen Ngo, Melissa Nguyen, Tai Nguyen, Thu-Van Nguyen, Muhammad Niaz, Aaron 
Nicdao, Fawn L Nichol, James Nicholson, William Nicholson, Doris Nickel, Simon Nicol, William Nicol, Josie Nicolajsen, Brian Nicoll, 
Wayne Nielsen, Rod M Nisi, Steven Niu, Bill Noble, Scott Noble, David R Noel, Geoff Noel, Greg Nolin, Robert Norman, Troy Normand, 
Kerry Novinger, Daniel Nugent, Eden Nunes-Vaz, Edward Nunes-Vaz, Kelvin Nurkowski, Robert Nuytten, Genia Nyenhuis, Wayne 
Nyholt, Tim Nyitrai, Jason Nykolaychuk, Donald Oaks, Cam Oberg, Pamela O’Brien, Jeffery Obrigewitsch, Richard Odlin, Robert 
Ogilvie, Anne Marie O’Gorman, Kevin O’Hearn, Hugo Olaciregui, Alvin Olchowy, Delvin Olesen, Deanna Olichny, Scott Oliphant, 
Dianne Oliveira, Cathy Oliver, Jason G Ollikka, Ghasem Oloumi, Kevin Olsen, Richard Olsen, Dean T Olson, Stephen Olson, Dave 
O’Neil, Kelly Oram, Steven O’Reardon, Flora O’Reilly, Kim O’Reilly, Doug Orlecki, Alison Orr, Colette Orr, Neil Orr, Colin Orton, Perry 
Osgood,  Wayne  Otteson,  Mike  Ouellet,  Denis  Ouellette,  Jolanta  Ouellette,  Jean  Francois  Ousset,  Mark  Overwater,  Mark  Owen, 
Marilyn Owens, Michael Owens, Gervais Owonon, Dennis Ozaruk, Fabio Pacheco, Rodney Pacholek, Ron Pacholuk, Jared Paddock, 
Larry Padley, Marcus Pagnucco, Robert Painchaud, Randall Paine, Elizabeth Palmer, Lee Palmer, Michael Palmer, Rick Palmer, 
Kevin  Palsat,  Glenn  Paluck,  Miodrag  Pancic,  Jamie  Pandachuck,  Neal  E  Pangman,  Garry  Pangracs,  Brian  Pankiw,  Durward 
Pankow, John Papp, Pat Paradis, Theo Paradis, Blair Parent, Bernard Parenteau, Clement Parenteau, Blaine Parker, Darby Parker, 
Herbert Lyle Parker, Steve Parker, Barry Parkin, Shelley Parks, Randy Parkyn, John Parr, John Parry, Jordy Partington, Ken Partsch, 
Lawrence Paslawski, Joey Pasos, Michael Pasveer, Andrew Paterson, Judy Paterson, Brian Patterson, Carolyn Pattinson, Donna 
Patton, Geoffrey Paul, Chris Paulette, Wilma Pauls-Atas, John Paulson, Brian Paulssen, Daniel Pavelick, Robynn Pavia, Lance 
Pawlik, Rick Pay, David Payne, Dean Payne, Keith Payne, Gerald Pearson, Pam Pearson, Robert Pearson, Brenda Peatch, Angela 
Peden, Hans H Pedersen, Philip Pedersen, Shawn Pedersen, Brian Pederson, Lance Pederson, Luvelyn Pedro, Dianne Peel, Sean 
Pell, Roberto Pena, Bruce C Penner, Robin Penner, Kevin Pennington, John Perepelecta, Don Perry, Gladys Perry, Tarla Persaud, 
Bernie Persson, Bernard Peterson, Bill Peterson, Brenda Peterson, Douglas Peterson, William S Petlyk, Dino Petrakos, Rick Petrick, 
Henry Petrie, Rodney Petrie, Lucyna Pettigrew, Marie (Huong) Phan, Bryanne Philibert, Doug Pierce, Frank Pike, Ron Pilisko, Kathy 
Pinco, Dale Pinder, Alonso Pineda, Dan Pingitore, Barry Pitchford, Edward Pittman, Ted Plouffe, Erwin Po, Imhotep Pocaterra, 
Donna Poitras, Wade W Poitras, David Pole, Brandy Poliakiwski, Marlene Pollock, Eleanor Polson, Robert Pool, Chris Poole, James 
Pope, Jason Popko, Carol Porter, Patti Postlewaite, Jeffrey Poth, Terry Potter, Randy Pottle, Ryan Potts, Bruce Powell, Susan Powell, 
Laurie Power, Lisa Power, Melissa Power, Noleen Pratap, Mike Preece, Travis Prins, Catherine Proctor, Lesley Proctor, Doug Proll, 
Sarah Proudlock, Jacques J P Proulx, Richard Proulx, Kayla Prowse, Steve Pshyk, John Puckering, Yesid Edgar Puerto, Justyna Puhl, 
Nam Pui, Leslie Punko, Suniel Puri, Trent Pylypow, Lu Qing, Munawar Quadri, Warren Raczynski, Levente Rado, Gloria E Ragan, 
Michael  Rainey,  Yina  Raisbeck,  Maritess  Ramirez,  Ruth  Ramonas,  Matthew  Ramsay,  Ron  Ramsay,  Kerri  Ramsbottom,  Brian 
Ramsum, Sunita Ranganathan, Dorotea Ranola, Gregory Ransom, Jeremy Ransom, Shauna Rasmussen, Soukseum Rathamone, 
Stojan Ratkovic, Joan L Rattai, Murray Rattray, Robert Rayner, Blair Read, Teddy Reay, Deston Reber, Duane R Reber, Bernie 
Redlich, Donald Reed, Kendra Reed, Loreena Reed, Tim Reed, Michael Rees, Irene N Regner, Duncan Rehm, Carmon Reich, Alan 
Reid, Lilian Reid, Angela Reimer, Rolande Reinboldt, John Reiniger, Phillip Reist, Glenn A Reiter, Wendy Reitmeier, Kelly Rempel, 
Long Ren, George Renfrew, Alexander Rennie, Dustin Ressler, Russell Retzlaff, Mike Rew, Pat Reynolds, Keith Rhodes, Charles 

Richards,  Andrew  T  Richardson,  Rob  Richardson,  Wesley  Richardson,  William  Richardson,  Andrea  Richmond,  Lori  Richmond, 
William Richmond, Jeff Riddell, Robert Riddell, Bonnie Ries, Dominic Riley, Dale E Rinas, Carl Ringdahl, Serge Rioux, Tracey 
Roasting,  Jo-Anne  Robak,  Jimmie  Roberts,  Andrew  Robertson,  Dale  Robertson,  Morag  Robertson,  Nancy  Robertson,  Stephen 
Robertson,  Heather  Robillard,  Aaron  Robinson,  Amber  Robinson,  Arlene  Robinson,  Brian  E  Robinson,  Gene  Robinson,  Julian 
Robinson, Scott Robson, Sheila Rodberg, Nenesa Rodelas, Roger Rodermond, Ray Rodh, Ricardo Rodriguez, Roberto Rodriguez, 
Paul Roett, Dean Rogal, Russell J Rogers, Neil Rogerson, Henry Rojo, Louis L Romanchuk, Dwayne Romanovich, Eduardo Romeo, 
Joy  Romero,  Linda  Romness,  Claude  Rondeau,  Dennis  Ross,  Robert  Ross,  Ron  Ross,  Graham  Rosso,  Worley  Rosson,  Barry 
Rosychuk, Cheryl Rosychuk, Rick Rosychuk, Reagan L Roszell, Tom Roth, Katarina Rothe, Judy Rotzoll, David Rouleau, Gordon 
Rourke, Richie Rovere, Natasha Rowden, Scott Rowein, Andrea Roy, Jeff Roy, Zenita Ruda, Colleen Ruggles, Nigel Rusk, Denise 
Russell,  Jylian  Russell,  Mark  Russell,  Matthew  Russett,  Jeff  Rutherford,  Brian  Rutledge,  Doug  L  Rutley,  Daniel  Ruttan,  Mark 
Rutter, Hal Rutz, David Ruud, Dan Ryan, Rick Rybchinsky, Jeff Ryll, Mikael Sabo, Adam Saby, Gurdip Sahota, Darlene G Sakires, 
Mourad Salameh, Shahid Saleem, Khaled Saleh, Shahid Salem, Pedro Salomao, Peter Salomon, Gord Salt, Blaine Salzl, E Wayne 
Sampson, Geoffrey Samuel, Juan Jose Sanchez, Andrea Sanden, David Sanderson, Sandy Sandhar, Darryl Sandquist, Tom Sanelli, 
Juan Pablo Santini, Rajiv Saran, John C Sargent, Anita Sartori, Greg Sauer, Lisa Saumier, Christine Savary, Brian Saville, Codey 
Saville, Luc Savoie, William Sawyers, Chris Sayer, Richard Sayer, Ryan Scammell, Robert Schaap, Trevor Schable, Bruce Schade, 
Judy Schafer, Paul Schaub, Lorne Schaufert, Perry Scheffelmaier, Barry Schellenberg, Mike Schellenberg, Lance Schelske, Sally 
Schick, Larry Schielke, Darcy Schira, Ronald Schlachter, Mark Schleindl, Helen Schlenker, Tracy Schmaltz, Beat Schmid, Raquel 
Schmidt,  Joseph  Schmitz,  Melissa  Schmitz,  Christopher  Schneider,  Craig  Schneider,  Darryl  Schneider,  Paul  Schneider,  Blaine 
Schnell, Aaron Schnick, Jack Schnieder, Ronald Schnieder, C Brian Schnurer, Rene Schoch, Stephen Schoﬁ eld, Norm Schonhoffer, 
Sheldon Schroeder, Michael Schubert, Tricia Schuh, Stephen Schultheiss, Julie Schultz, Lorraine Schwetz, Tony Sciarrabba, Leslie 
Scory, Curtis Scott, James Scott, John Scott, Judy Scott, Kim Scott, Murray Scott, Ronalda Scott, Rodney Scoville, Gordon Seabrook, 
Geordie Seaton, Adam Seber, John C Seffern, Brian Segouin, Morley Seguin, Stephen Seguin, Clayton Seifridt, Fraser Selfridge, 
Kenneth Selman, Conrad Semeniuk, Kevin Semenoff, Roland Senecal, David Sergeant, Edward Serniak, Cindy Severite, Jeremy 
Seward,  Gianni  Sgambaro,  Mohsen  Shaﬁ zadeh,  Sanjay  Shah,  Philip  Shankowski,  Gilbert  Shantz,  Raj  Sharma,  Marilyn  Shaw, 
Dorothy Shea, Robert Shears, David Sheaves, Wayne Sheaves, Ben Shenton, Glenn Sheppard, Robert Sheppard, Tim Sheppard, Ron 
Sheremeta, Judi Shermerhorn, Jason Sherstabetoff, Annette Shillam, Leonard Shostak, Trent Shwaluk, Melanie Siddon, Patricia 
Sideen, Ken Siemens, Steve Siemens, Travis Siemens, Wayne Sikorski, Lorraine Silas, Beh Silue, Kevin Simard, Bradley Simonar, 
Barbara Simpson, Brad Simpson, Patrick Simpson, Dennis Sinclair, Garry Sinclair, Neil R Sinclair, Robert Sinclair, Sukhwinder 
Singh, Paul Siree, Richard Sisson, Matt Skanderup, Michael Skipper, Grace Skoczek, Shirley Skulmoski, Darrell Sleno, Doreen 
Smale, Lyle Small, David Smart, Bonnie Smith, Carl Smith, Catriona Smith, Glen Smith, Jennifer Smith, Lyle E Smith, Michael 
Smith, Michael Smith, Nancy Smith, Ryan Smith, Sandi Smith, Sandra Smith, Scott Smith, Tim K Smith, Tina Smith, Allen Smyl, 
Richard Smyl, Brad Smylie, Jeffrey Snide, Kurt Snow, William Snow, Douglas Snyder, Kristi Soderman, Lumbo Soma, Ray Soon, 
Curtis Sorochan, Daryl Soroko, Paul Spavor, Jason Spears, Kevin W Spencer, David Spetz, Evelien Spoelstra, David Spooner, Jill 
Spornitz, John Springer, Ellis Spurrell, Lawson Squire, Daniel D Srinivasagam, Eric St. Pierre, Robert St. Amant, Robert St. Martin, 
Mario  St.  Pierre,  Carrie  Stacey,  Ian  Stacey-Salmon,  Stacey  Stadnyk,  Kendall  Stagg,  Rodney  Stahn,  Elisha  Staines,  Mark 
Stainthorpe, Karen Stairs, Randy Stamp, Nick Stanford, Lezlie Stark, Scott Stauffer, Scott Stauth, Achilles Stavropoulos, Craig 
Steel, Mark Steenbergen, Leanne Steeves, Jerry Stefanyshyn, Wayne Steffen, Robert Steinborn, Bradley Steinke, Carolyn Steinson, 
Taryn  Stephenson,  Jonathan  Steranko,  G  Austin  Stevens,  Lyle  Stevens,  Robert  Stevenson,  Carol  Stewart,  Dana  Stewart,  Don 
Stewart, Douglas Stewart, Karen Stewart, Lorie Stewart, Wendy Stewart, Todd G Stiles, Kevin Stilwell, Stewart Stirling, Melissa 
Stockes, Anita Stockford, Katrina Stockman, Mark Stockton, Godfrey Stowe, Suzanne Strachan, Wade Strand, Linda Strangway, 
George  Stratford,  Brenda  Stratichuk,  William  Strecker,  Michael  Street,  William  Stretch,  Robert  Struski,  Linda  Stuart,  Mike 
Sturkenboom, David Sturrock, Stephen Suche, Mark Sullivan, Shiraz Sumar, Daniel Sutherland, Laura Sutherland, Scott Sverdahl, 
Rade Svorcan, Michael Swain, Rick Swanson, Halina Swierz, Don Sylvestre, Angela Szeponski, Darren Taciuk, David Talbot, Miguel 
Tamayo, Kevin Tanas, Valentina Taneva, J Nick Tannahill, Aaron Tannas, Krystalle Tanner, Michael Tanouye, Kari Tansowny, Boyd 
Tarasoff, Dan Tarasoff, Bill Tarkowski, Ron Taron, Darcy Tarrant, Ross Tarrant, Joanne Taubert, Raymond Taviner, Brian Taylor, 
Cathy Taylor, Colin Taylor, Dawn Taylor, George Taylor, Jackie Taylor, James Taylor, James R Taylor, Ken Taylor, Ken W Taylor, Thomas 
Taylor, Tom Taylor, William Taylor, Joseph Taza, Veniece Tedeschini, Chin Seng Teh, Berhanu Temesgen, Jennifer Temple, Robert 
Templeton, Derek Tempro, V Leighton Tenn, Kurt Tenney, Marilyn R Tenold, Travis Terpstra, Stephen Terry, Gus Teske, Jason Tessier, 
Cherie Thannhauser, Howard Thaw, Richard Theberge, Marc Theroux, Karen Thistleton, George Thomas, Laurie Thomas, Angela 
Thompson,  Arthur  cott  Thompson,  Ben  Thompson,  Herb  Thompson,  Mark  Thompson,  Peter  Thomsen,  Adele  Thomson,  Julie 
Thomson, Todd Thomson, Amber Thornton, Bruce Thornton, Keith Thornton, Richard William Thornton, Jason Thurlow, Margaret 
Thurmeier,  Daniel  Tillapaugh,  Terry  Tillotson,  Colin  Tiltman,  Brian  Timmerman,  David  Timms,  Simon  Timothy,  Bruce  E  Tipton, 
Dharmendra  Tiwary,  Carol  Tobin,  Ron  Tochor,  James  Todd,  Mervin  Todoschuk,  Al  Tokarchik,  Christopher  Tomlinson,  Dale  R 
Tomlinson, David Tonner, Domenic Torriero, Chyndelle Toth, David Toth, Paige Tracey, Sabrina D Traﬁ ak, Catherine Trenouth, Brian 
E Trimble, Ray Trombley, Ruaidhri Truter, Sunny Tulan, Brent Tulloch, Bruce Tumbach, Art Tupper, Terry Turgeon, Trent Turgeon, 
David Turk, Richard Turnbull, Donald Turner, Stanley Turner, Irene Tutto, Cary Twardy, David Tweddell, Wayne Tymchuk, Shaun 
Tymchyshyn, Kathleen Tynan, Kenechukwu Ufondu, Kevin Ullyott, Eric Ulrich, Gregory A Ulrich, Catherine Umpherville, Karl Unger, 
Stephen Unruh, Jackeline Urdaneta, Allan Valentine, Darrel Valin, Louis Vallee, Michael Vallee, Bryant VanIderstine, Christina 
VanderPyl, Vyvette Vanderputt, Collin Vare, Daniel Vasseur, Nicolette Vaughan, Sheila Verigin, Carmine Vertone, Nancy Tay Vetrici, 
Dale Vickery, Maria H Victoria Pereira, Wilf Vielguth, Tony Vitkunas, Demetry (Jim) Vlahos, James W Vollman, Leo Vollmin, Luke 
Vondermuhll, Nguyen Vu, Janel Wageman, Todd Waggoner, Trevor Wagil, Joy Wagner, Juon Wah, Donald Wakaruk, Ken Walchuck, 
Jeff Walden, Dave Waldner, David Walker, Martin Walker, Jeff Wall, Erin Wallace, Kevin Wallace, Marie Wallace, Andrew Wallis, 
Vince Wallwork, Lorie Walter, Michelle Walton, Roger Walton, Alfred Wandler, John A Wandler, Wanitta D Wandler, Blaise Wangler, 
Janet Wannop, Kathy Ward, Kirk Ward, Terry Ware, Wayne M J Warholik, Christopher Wark, Wanda Warman, John Warrell, Faye 
Warrington, Godfried Wasser, James Waterﬁ eld, Frank Watkin, Julie Watkins, Kenneth Watson, Trish Wear, Alan Webb, Byron Webb, 
Larry  Webb,  Randall  Weeks,  Maureen  C  Weeres,  Lionel  Weinrauch,  Randy  Weir,  Gregory  Wells,  Guy  Welwood,  Mark  S  Wenner, 
Dwayne Werle, Tracy Wersch, Craig Werstiuk, Matthew Werstiuk, Darrin West, Jacqueline West, Jeremy Wetsch, Terry Wetzstein, 
John Wham, Terence Whang, Loyd Wheating, Joshua Wheaton, Andrew Wheeler, Bob W Wheeler, Francis W White, Gail White, Julie 
White, Ken White, Ralph White, David Whitehouse, John Whitlock, Grant Whittemore, Michael Whittingham, Heather Whynot, Jane 
Whyte, Blaine Wicentovich, David Wiebe, Debbie Wiens, Cameron Wietzel, Cheryl Wiggett, Zandra Wigglesworth, Bob Wilbern, 
Brandon  Wild,  John  Wilding,  Daryl  Wiles,  Troy  Wilk,  Melanie  Wilkie,  Amy  Wilkinson,  Derek  Wilkinson,  Elmer  Willard,  Shannon 
Willcott, Bill Williams, Grant Williams, Greg Williams, Julian Williams, Kelvin Williamson, Monty Williamson, Jeff Willick, Kennneth 
Willis, Robin Willis, Wayne Willis, Susan Wills, Christian Willson, Curtis Wilson, Don Wilson, Ian Wilson, James Wilson, Jeff Wilson, 
Marty Wilson, Patrick Wilson, Tammy Wilson, Tyler Wilson, Woodrow Wilson, Joan Wilton, Bob Wing, Ken Winsborrow, Noel Winter, 
Greg Winters, Garrett Wirachowsky, Jeff Wiseman, Morrison Wiseman, Paul Wiseman, Dale Wittman, Kelly Woidak, Colin Woloshyn, 
C K Bill Wong, Jason Wong, Jennifer Wong, Lisa Wong, Steve Wong, E Bette Wood, Leonard Wood, Philip Wood, Roxanne Wood, Laura 
Wooding, Travis Woods, Marilyn Woodske, Wayne Woodward, Sidney Wosnack, Raymond Wourms, Mark Woynarowich, Chris Wright, 
Daniel Wright, Richard Wright, Bin Wu, Christine Wutzke, Brent Wychopen, Guy Wylie, George Wyndham, Brent Wyness, Barry 
Wynne,  Valerie  Wyonzek,  Cameron  Yamada,  Canghu  Yang,  Grace  Yang,  Lin  Yang,  Andrew  Yaremko,  Rick  Yarmuch,  James 
Yaroslawsky, Jeff Yates, Noah Yates, Betty Yee, Davin Yee, Gordon Yee, Michael Yee, WSelina Yeung, Jeffrey Yip, Kitty Yip, Darrell 
York, Rachelle Yorke, Daryl Youck, Bill Young, Chalene Young, Clayton Young, Kelly Young, Richard Young, Wendell Young, Ray 
Yowney, Clement Yuen, Dustin Yuill, Jeff Yuill, William Yuill, Arina Yuzhakova, Robin Zabek, Robert Zabot, Gabriel Zachoda, Tyler 
Zachoda, Cam Zackowski, John E Zahary, Attila Zahorszky, Mark Zan, Glenn Zeebregts, Patricia Zegers-de-Beyl, Lynn Zeidler, Tony 
Zeiser,  Aleksandra  Zelic,  Diane  Zeliznik,  Grant  Zellweger,  Darcy  Zelman,  Denis  Zentner,  Kathy  Zerr,  Michelle  Zerr,  Xu  (Frank) 
Zhang, Wanli Zhu, Evgeny Zhuromsky, Brenda Ziegler, Dwayne Zilinski, Hernando Zorrilla, Ana Zulueta, Bob Zulueta.

The People

13

The Plan

We have a strong track record of setting a plan 
and diligently delivering against it. That being 
said, we remain ﬂ exible to react to market changes 
or take advantages of opportunities as they arise.

Review of Operations

PRODUCTION STRATEGY AND RESULTS
Canadian  Natural  has  increased  its  hydrocarbon  production 
and reserves each and every year since becoming an independent 
producer  in  1989.  Throughout  that  17  year  period  we  have 
adhered to the same basic business formula - maintain large project 
inventories in every product and basin in which we participate. 
Large  project  inventories  enable  the  Company  to  continually 
high-grade the capital allocation process and balance production 
mix among each of the commodities we produce; namely natural 
gas, light crude oil, Pelican Lake crude oil, primary heavy crude 
oil and thermal heavy crude oil. 

In 2005 we again achieved record levels of production on a barrel 
of oil equivalent basis. Production before royalties on a barrel of 
crude oil equivalent was 553 mboe/d during 2005, up 8% from 
2004 levels and was achieved primarily through a combination 
of  exploration  and  asset  development.  Natural  gas  production 
before royalties increased by 4% and continues to represent our 
largest  product  offering.  Total  crude  oil  and  NGLs  production 
before  royalties  increased  by  11%,  with  the  primary  drivers 
being the commencement of production from the Baobab Field 
located offshore Côte d’Ivoire and improvements in production 
from  North  Sea  light  crude  oil,  Pelican  Lake  crude  oil  and  the 
Primrose in-situ oil sands development.

(before royalties) 

Natural gas  
North America light crude oil and NGLs  
Pelican Lake crude oil   
Primary heavy crude oil  
Thermal heavy crude oil  
North Sea light crude oil  
Offshore West Africa light crude oil  
Total  

2005

2004

Production 
mboe/d  

 Mix  
%  

Production  
mboe/d  

240 
52 
23  
93  
53  
69  
23  
553  

43  
10 
4  
17  
10  
12  
4  
100  

231 
 47 
20 
95 
44 
65 
12 
514  

Mix
%

45
9
4
19
8
13
2
100

(cid:12)(cid:62)(cid:136)(cid:143)(cid:222)(cid:202)(cid:152)(cid:62)(cid:204)(cid:213)(cid:192)(cid:62)(cid:143)(cid:202)(cid:125)(cid:62)(cid:195)(cid:202)(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:93)(cid:202)(cid:76)(cid:105)(cid:118)(cid:156)(cid:192)(cid:105)(cid:202)(cid:192)(cid:156)(cid:222)(cid:62)(cid:143)(cid:204)(cid:136)(cid:105)(cid:195)
(cid:173)(cid:147)(cid:147)(cid:86)(cid:118)(cid:201)(cid:96)(cid:174)

(cid:12)(cid:62)(cid:136)(cid:143)(cid:222)(cid:202)(cid:86)(cid:192)(cid:213)(cid:96)(cid:105)(cid:202)(cid:156)(cid:136)(cid:143)(cid:202)(cid:62)(cid:152)(cid:96)(cid:202)(cid:32)(cid:20)(cid:29)(cid:195)(cid:202)(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:93)(cid:202)(cid:76)(cid:105)(cid:118)(cid:156)(cid:192)(cid:105)(cid:202)(cid:192)(cid:156)(cid:222)(cid:62)(cid:143)(cid:204)(cid:136)(cid:105)(cid:195)
(cid:173)(cid:147)(cid:76)(cid:76)(cid:143)(cid:201)(cid:96)(cid:174)

(cid:228)(cid:120)

(cid:228)(cid:123)

(cid:228)(cid:206)

(cid:228)(cid:211)

(cid:228)(cid:163)

(cid:163)(cid:93)(cid:123)(cid:206)(cid:153)

(cid:163)(cid:93)(cid:206)(cid:110)(cid:110)

(cid:163)(cid:93)(cid:211)(cid:153)(cid:153)

(cid:163)(cid:93)(cid:211)(cid:206)(cid:211)

(cid:153)(cid:163)(cid:110)

(cid:228)(cid:120)

(cid:228)(cid:123)

(cid:228)(cid:206)

(cid:228)(cid:211)

(cid:228)(cid:163)

(cid:206)(cid:163)(cid:206)

(cid:211)(cid:110)(cid:206)

(cid:211)(cid:123)(cid:211)

(cid:211)(cid:163)(cid:120)

(cid:211)(cid:228)(cid:200)

14

The Plan: Review of Operations

 
 
 
 
 
 
 
 
 
 
  
 
 
 
  
 
 
 
  
 
 
 
  
 
 
 
  
 
 
 
  
 
 
 
 
 
THE PEOPLE
Our technical skills are strong and our 
people are motivated.

THE PLAN
Our exploitation approach is ﬂ exible to 
accomodate changes in our operating 
environment.

THE ASSETS
We have exposure to many play types, 
through ownership of one of the largest 
landholding positions in the WCSB.

Africa  saw  the  acquisition  of  2,400  kilometers  of  proprietary 
2-D  seismic  data  and  the  purchase  and  reprocessing  of  1,530 
square kilometers of 3-D seismic data.

STRATEGIC LAND BASE
Canadian  Natural  has  the  second  largest  undeveloped  land 
inventory  in  the  WCSB.  At  the  end  of  2005,  our  Canadian 
undeveloped  net  acreage  totaled  10.9  million  net  acres.  Total 
landholdings were 16.6 million net acres at the end of 2005, up 
slightly from 2004. 

land  base  affords 

strong  concentrated 

signiﬁ cant 
This 
opportunities  to  maintain  our  low  ﬁ nding  and  onstream  costs 
and low operating costs. The vast majority of our land base is 
positioned to utilize existing owned and operated infrastructure 
and  it  also  strategically  positions  us  to  maximize  the  beneﬁ t 
of  new  play  types  developed  by  ourselves  and  other  producers 
adjacent to our core operating areas.

We  can  also  lever  newly  discovered  opportunities  into  upside 
potential for our existing lands or into acquisition of competitor 
lands.  As  an  example,  in  late  2003,  we  leveraged  our  vast 
Northeast  British  Columbia  land  base  to  correlated  well  data 
to  develop  a  new  regional  shallow  natural  gas  play.  In  2005, 
production from this shallow play reached 35 mmcf/d.

TIM S. McKAY
Senior Vice-President, 
North American
Operations

MARY-JO E. CASE
Vice-President, Land

GEO-SCIENCE STRATEGY
We  believe  that  a  disciplined  focus  on  geology  and  geophysics 
reduces exploration risk and ultimately results in better full cycle 
economics.  We  drill  hundreds  of  wells  each  year  and  add  new 
high quality locations to our inventory by integrating geological 
plays  with  seismic  data  analysis.  The  achievements  of  our 
experienced  team  of  geologists  and  geophysicists  is  reﬂ ected  in 
our quality results.

Canadian Natural continues to be active in adding quality locations 
to its inventory by integrating geological plays with seismic data 
analysis.  In  Canada,  we  invested  $96  million  during  2005  to 
acquire new seismic and to purchase and reprocess existing seismic 
data. In total, over 4,389 kilometers of conventional 2-D seismic 
data  and  over  430  square  kilometers  of  3-D  seismic  data  were 
acquired.  Additionally,  over  12,577  kilometers  of  conventional 
2-D seismic data and 986 square kilometers of 3-D seismic data 
were purchased. We continue to acquire this data under stringent 
environmental controls and in a cost effective manner. 

In the North Sea, we purchased 2,800 square kilometers of 2-D 
seismic  and  reprocessed  a  further  64  square  kilometers  of  3-D 
seismic data. This data allows us to continue aggressive in-ﬁ eld 
and  near-ﬁ eld  development  and  exploration.  Offshore  West 

(cid:45)(cid:105)(cid:136)(cid:195)(cid:147)(cid:136)(cid:86)(cid:202)(cid:105)(cid:221)(cid:171)(cid:105)(cid:152)(cid:96)(cid:136)(cid:204)(cid:213)(cid:192)(cid:105)(cid:195)(cid:202)(cid:136)(cid:152)(cid:202)(cid:10)(cid:62)(cid:152)(cid:62)(cid:96)(cid:62)
(cid:173)(cid:102)(cid:202)(cid:147)(cid:136)(cid:143)(cid:143)(cid:136)(cid:156)(cid:152)(cid:195)(cid:174)

(cid:47)(cid:156)(cid:204)(cid:62)(cid:143)(cid:202)(cid:32)(cid:156)(cid:192)(cid:204)(cid:133)(cid:202)(cid:1)(cid:147)(cid:105)(cid:192)(cid:136)(cid:86)(cid:62)(cid:152)(cid:202)(cid:143)(cid:62)(cid:152)(cid:96)(cid:133)(cid:156)(cid:143)(cid:96)(cid:136)(cid:152)(cid:125)(cid:195)
(cid:173)(cid:204)(cid:133)(cid:156)(cid:213)(cid:195)(cid:62)(cid:152)(cid:96)(cid:195)(cid:202)(cid:156)(cid:118)(cid:202)(cid:152)(cid:105)(cid:204)(cid:202)(cid:62)(cid:86)(cid:192)(cid:105)(cid:195)(cid:174)

(cid:12)(cid:105)(cid:219)(cid:105)(cid:143)(cid:156)(cid:171)(cid:105)(cid:96)

(cid:49)(cid:152)(cid:96)(cid:105)(cid:219)(cid:105)(cid:143)(cid:156)(cid:171)(cid:105)(cid:96)

(cid:153)(cid:200)

(cid:200)(cid:163)

(cid:228)(cid:120)

(cid:228)(cid:123)

(cid:228)(cid:206)

(cid:228)(cid:211)

(cid:228)(cid:163)

(cid:123)(cid:228)

(cid:123)(cid:110)

(cid:123)(cid:200)

(cid:228)(cid:120)

(cid:228)(cid:123)

(cid:228)(cid:206)

(cid:228)(cid:211)

(cid:228)(cid:163)

(cid:120)(cid:93)(cid:200)(cid:153)(cid:153)

(cid:123)(cid:93)(cid:110)(cid:110)(cid:153)

(cid:123)(cid:93)(cid:228)(cid:206)(cid:200)

(cid:206)(cid:93)(cid:110)(cid:206)(cid:211)

(cid:206)(cid:93)(cid:120)(cid:199)(cid:110)

(cid:200)(cid:93)(cid:211)(cid:199)(cid:211)

(cid:163)(cid:228)(cid:93)(cid:153)(cid:123)(cid:199)

(cid:163)(cid:163)(cid:93)(cid:120)(cid:211)(cid:206)

(cid:153)(cid:93)(cid:110)(cid:163)(cid:163)

(cid:163)(cid:228)(cid:93)(cid:211)(cid:163)(cid:206)

The Plan: Review of Operations

15

The  infrastructure  associated  with  this  vast,  concentrated  land 
base  also  provides  a  competitive  advantage  in  terms  of  lower 
marginal  operating  and  development  costs  for  newly  drilled 
or  acquired  properties.  This  dominance  can  create  property 
acquisition opportunities, as we maintain a low-cost regime and 
access to infrastructure. 

Internationally, our North Sea net undeveloped acreage remained 
strong  while  Offshore  West  Africa  net  undeveloped  lands 
decreased following the sale of leases held in Angola as partially 
offset by the acquisition of lands in Gabon.

CORE LANDHOLDINGS

The  Company’s  overall  average  landholding  working  interest 
of  82%  reﬂ ects  the  Company’s  philosophy  to  maintain  high 
ownership  levels  and  control  operations.  Assets  are  better 
developed and exploited according to the Company’s own plans 
and timelines.  This ﬂ exibility allows the Company to  maintain 
discipline in its capital expenditures. For example, in 2004 as a 
result of capital allocated to strategic property acquisitions, the 
Company inventoried many of its planned 2004 drilling locations 
for future years.

(thousands of acres)  

North America
  Developed  
  Undeveloped  

North Sea
  Developed  
  Undeveloped  
Offshore West Africa
  Developed 
  Undeveloped  
Total  
  Developed 
  Undeveloped  

Gross  

7,184 
13,163 
20,347 

138 
457 

7 
521 

7,329 
14,141 
21,470 

2005

Net  

5,699 
10,947 
16,646 

93 
352 

4 
426 

5,796 
11,725 
17,521 

%  

79 
83  
82 

67 
77  

58 
82  

79 
83 
82 

Gross  

6,577 
14,051 
20,628 

138 
830 

8 
1,672  

6,723  
16,553  
23,276  

2004

Net  

4,889 
11,523 
16,412 

93 
565 

5 
886 

4,987 
12,974 
17,961 

%

74
82
80

67
68

59
53

74
78
77

extensive  prospect  inventory,  it  would  have  been  a  challenge 
to  complete  the  majority  of  the  program  in  an  economic  and 
disciplined manner. The merits of this discipline and planning are 
reﬂ ected in our ﬁ nding and onstream cost control.

DRILLING ACTIVITY AND STRATEGY
During  2005,  we  completed  the  largest  drilling  program  in  the 
Company’s  history,  a  total  of  1,882  wells  or  30%  more  than  in 
2004. Our drilling success rate of 93% improved slightly over the 
prior year and reﬂ ects the low-risk exploitation approach that we 
take to the business. 

In 2005 our drilling plans were the most comprehensive we have 
ever  prepared  in  Canada,  including  an  organized  migration  of 
rigs to optimize utilization and better balance drilling activities 
throughout  the  year.  We  leveraged  that  plan  and  our  extensive 
drilling  inventory  to  its  fullest  extent  due  to  weather.  Warmer 
than  normal  winter  weather  in  2005  led  to  an  earlier  spring 
breakup for winter access areas and a much wetter than normal 
summer was followed by a late freeze up for the 2005/6 winter 
drilling season. This meant that our execution had to be ﬂ exible 
and  had  we  not  developed  such  a  comprehensive  plan  with  an 

(cid:47)(cid:156)(cid:204)(cid:62)(cid:143)(cid:202)(cid:152)(cid:105)(cid:204)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:202)(cid:96)(cid:192)(cid:136)(cid:143)(cid:143)(cid:105)(cid:96)

(cid:12)(cid:192)(cid:136)(cid:143)(cid:143)(cid:136)(cid:152)(cid:125)(cid:202)(cid:195)(cid:213)(cid:86)(cid:86)(cid:105)(cid:195)(cid:195)(cid:202)(cid:192)(cid:62)(cid:204)(cid:105)(cid:93)
(cid:105)(cid:221)(cid:86)(cid:143)(cid:213)(cid:96)(cid:136)(cid:152)(cid:125)(cid:202)(cid:195)(cid:204)(cid:192)(cid:62)(cid:204)(cid:136)(cid:125)(cid:192)(cid:62)(cid:171)(cid:133)(cid:136)(cid:86)(cid:202)(cid:204)(cid:105)(cid:195)(cid:204)(cid:201)(cid:195)(cid:105)(cid:192)(cid:219)(cid:136)(cid:86)(cid:105)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)
(cid:173)(cid:175)(cid:174)

(cid:228)(cid:120)

(cid:228)(cid:123)

(cid:228)(cid:206)

(cid:228)(cid:211)

(cid:228)(cid:163)

(cid:163)(cid:93)(cid:123)(cid:123)(cid:153)

(cid:163)(cid:93)(cid:110)(cid:110)(cid:211)

(cid:163)(cid:93)(cid:199)(cid:153)(cid:206)

(cid:153)(cid:228)(cid:228)

(cid:163)(cid:93)(cid:228)(cid:153)(cid:211)

(cid:228)(cid:120)

(cid:228)(cid:123)

(cid:228)(cid:206)

(cid:228)(cid:211)

(cid:228)(cid:163)

16

The Plan: Review of Operations

(cid:153)(cid:206)

(cid:153)(cid:163)

(cid:153)(cid:163)

(cid:153)(cid:123)

(cid:153)(cid:200)

 
 
 
 
 
 
 
 
 
  
  
 
 
 
 
 
 
 
 
 
 
 
 
  
  
 
 
 
 
  
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
For 2006 we plan to take our comprehensive drilling plans one step 
further and design the drilling program to optimize the capabilities 
of the drill rig contracted for the area. That is, while some rigs 
may be capable of a wide range of applications, there is generally 
a  range  of  depths  in  which  the  rig  is  at  its  optimum  efﬁ ciency. 
We will target wells that have depths or other requirements that 

ﬁ t  within  these  optimum  efﬁ ciencies.  This  will  help  ensure  that 
every dollar spent is generating maximum value. Those wells in 
inventory that do not ﬁ t into the criteria for the drill rig in 2006 
will be re-inventoried for drilling in a future year when the most 
efﬁ cient rig type is available in that area.

Year Ended December 31 

Crude oil
  North America
  Light oil  
  Pelican Lake 
  Primary heavy oil 
  Thermal heavy oil 

  North Sea 
  Offshore West Africa 

Natural gas – North America
  Northeast British Columbia 
  Northwest Alberta 
  Northern Plains 
  Southern Plains 

Dry   
Subtotal
Stratigraphic test / service wells 
Total  

2005

2004

Gross 

Net  

Success

Net 

Success

107 
83 
369 
107 
13 
6 
685 

230 
184 
240 
417 
1,071 
136 
1,892 
251 
2,143 

81 
83 
341 
107 
12 
3 
627 

201 
152 
199 
338 
890 
117 
1,634 
248 
1,882 

92% 
99% 
94% 
98% 
87% 
85% 
95% 

88% 
92% 
84% 
99% 
91% 

93% 

97%
100%
96%
100%
82%
77%
97%

89%
92%
80%
95%
89%

91%

45 
34 
180 
58 
9 
2 
328 

167 
138 
163 
221 
689 
96
1,113 
336
1,449

North  American  crude  oil  drilling  increased  substantially  from 
2004  levels  when  capital  was  reallocated  following  four  major 
property acquisitions. The largest increase in drilling occurred on 
primary heavy crude oil projects where activity was ramped by 
over 90%. This was reﬂ ected in associated production volumes 
which increased from approximately 92 mbbl/d in the ﬁ rst quarter 
to over 96 mbbl/d in the fourth quarter. Drilling at Pelican Lake 
increased  by  50  net  wells  or  147%  due  to  increased  activity 
associated  with  enhanced  oil  recovery  schemes  and  additional 
primary  production  potential  that  continues  to  expand  our 
developable  land  base.  Associated  production  at  Pelican  Lake 
increased from approximately 18 mbbl/d in the ﬁ rst quarter to 
over  28  mbbl/d  in  the  fourth  quarter.  Thermal  drilling  activity 
increased 90% reﬂ ecting the development of the North Primrose 
Field which commenced production in early 2006.

ACTIVITY BY CORE REGION 

Natural  gas  drilling  activity  also  increased  in  each  of  our  core 
regions  and  by  26%  overall  when  compared  with  2004  levels. 
Drilling  in  Northeast  British  Columbia  increased  with  26% 
more wells being drilled across a variety of depths and geological 
structures.  In  Northwest  Alberta,  76  net  Cardium  wells  were 
drilled  versus  69  in  2004.  In  the  Plains  increased  activity  was 
associated with coal bed methane gas with 100 net wells drilled 
and shallow gas with 209 net wells drilled.

During the year, 126 net stratigraphic wells were drilled on our 
oil sands mining leases and 95 were drilled on our conventional 
leases  to  delineate  resource  potential.  A  total  of  27  net  service 
wells  were  drilled  including  25  wells  in  North  America  and 
2 wells internationally.

Northeast British Columbia 
Northwest Alberta 
Northern Plains 
Southern Plains 
Southeast Saskatchewan 
Horizon Oil Sands Project 
United Kingdom North Sea 
Offshore West Africa    

Net Undeveloped Land 
(thousands of net acres)
2004

2005

2,027 
1,507 
6,594 
621 
82 
116 
352 
426 
11,725 

2,040 
1,660 
6,922 
661 
123 
116 
565 
886 
12,974 

Drilling Activity
(net wells)

2005

241 
183 
907 
354 
52 
126 
14 
5 
1,882 

2004

192
156
613
240
13
218
14
3
1,449

The Plan: Review of Operations

17

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
THE PEOPLE
Our people understand our customers and 
have creatively found ways to expand the 
markets we sell to.

THE PLAN
We seek to maximize market potential for every 
product we sell. In particular, we leverage our 
3-Phase heavy crude oil marketing plan to access 
our vast resource base.

THE ASSETS
Our midstream infrastructure provides us with 
ﬂ exibility. The ECHO pipeline delivers undiluted 
raw bitumen used in our Synbit and WCS crude 
oil blends.

Marketing

NATURAL GAS
Canadian Natural’s gas marketing objective is to maximize the 
realized  price  for  its  overall  portfolio.  Our  strategy  requires  us 
to  develop  solid  business  relationships  based  on  demonstrated 
performance  and  integrity  and  to  work  together  with  our 
customers to meet their needs. The Company markets primarily 
to  large  credit  worthy  utilities,  industrial  and  commercial 
customers across North America. The current portfolio includes 
20%  of  direct  sales  to  various  American  customers,  69%  sold 
directly  into  our  domestic  markets  with  the  remaining  11% 
going to the Alberta based gas supply and market aggregators. 
Canadian  Natural’s  portfolio  is  essentially  driven  by  current 
market  prices  with  over  98%  of  all  sales  ﬂ uctuating  with  the 
pricing index prevailing at the points of physical delivery of the 
gas. The marketing team monitors regulatory applications by the 
pipeline  companies  and  participates  as  necessary  to  ensure  an 
optimal outcome is achieved for all concerned parties. 

Canadian Natural’s realized wellhead price improved by 32% in 
2005  to  $8.57/mcf  primarily  in  response  to  a  very  tight  North 
American  supply  environment  exacerbated  by  the  devastating 
hurricanes  Katrina  and  Rita  impacting  the  US  Gulf  Coast  in 
early Fall of 2005. The average annual prices for 2005 were up 
41% on the NYMEX and 25% at the AECO hub with the basis 
differential at AECO widening by 63% in Canadian dollars over 
the 2004 average. As of early March 2006, the cumulative losses 
of gas production from the affected areas are estimated at 678 bcf 
with some 1.4 bcf/d of production still down. This extraordinary 
supply  disruption  resulted  in  very  high  gas  prices  reaching
US$15/mmbtu in December 2005 and causing several industrial 
plants  to  curtail  or  temporarily  shutdown  their  operations. 
However, this winter will also be characterized by the warmest 

18

The Plan: Marketing

month  of  January  on  record  creating  a  very  volatile  pricing 
environment  with  the  current  NYMEX  price  at  the  US$7/
mmbtu level. The gas storage positions are expected to close the 
withdrawal season at the end of March 2006 at levels not seen 
since 1991.

The  drilling  activity  continued  to  be  very  high  in  2005  with  a 
record number of completions in Canada at 16,700 and the US 
at  27,000.  However,  the  North  American  overall  supply  was 
essentially ﬂ at year over year with the increase in the electrical 
generation  offset  by  the  losses  from  the  industrial  sector.  We 
expect  the  North  American  supplies  to  be  challenged  over  the 
next several years even with the increased drilling for the tight gas 
in the Rockies and the promising CBM in Alberta. The timeframe 
for the production of gas from the McKenzie Delta and Alaska 
projects  continue  to  be  extended  into  the  next  decade  given 
the  economic  and  regulatory  challenges.  The  large  number  of 
proposals to import liqueﬁ ed natural gas in the North American 
grid has yet to translate into incremental quantities available to 
the end users with the 2005 import volumes remaining ﬂ at at 1.8 
bcf/d. The forecast is for a modest increase of these volumes in 
2006  as  the  competition  for  supplies  intensiﬁ es  with  European 
and Asian markets.

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The marketing team maximizes our wellhead 
price realizations by optimizing the logistics 
and creatively developing new markets for our 
heavy crude oil.

RÉAL M. CUSSON
Senior Vice-President, 
Marketing

Canadian Natural’s natural gas production for 2006 is forecast 
to average between 1,450 – 1,515 mmcf/d and with the current 
2006 pricing strips for NYMEX at US$7.95/mmbtu and AECO 
at  C$7.22/GJ  this  would  yield  an  overall  wellhead  price  of 
C$7.12/mcf  for  our  sales  portfolio,  using  a  US$0.88/C$1.00 
exchange rate.

The  benchmark  price  for  WTI  crude  oil  was  up  37%  in  2005 
US$56.61/bbl and the Brent crude oil was higher than in 2004 
by  42%  to  US$54.45/bbl.  The  price  differential  for  the  Lloyd 
Blend  heavy  crude  oil  widened  by  a  signiﬁ cant  5%  in  2005  to 
an average of 37% of the WTI price and the Canadian currency 
strengthened by 7% over the US dollar. 

CRUDE OIL
Canadian  Natural’s  crude  oil  marketing  strategy  is  designed  to 
unlock the value of our vast heavy oil reserves. The three major 
components  of  our  strategy  consist  of  blending  various  crude 
oil streams and diluents to better serve the needs of our reﬁ ning 
customers, support and participate in the expansion of pipeline 
export capacity and to support and participate in projects adding 
incremental conversion capacity for bitumen and SCO.

Canadian  Natural’s  realized  wellhead  price  improved  by  23% 
in  2005  to  $46.86/bbl  mainly  based  on  the  strong  worldwide 
demand for hydrocarbons and a constrained supply environment 
with  practically  no  spare  capacity  from  the  producers  and  full 
utilization of worldwide reﬁ ning assets.

The demand continues to grow strongly in the Asian markets and 
moderately in the North American and European markets while 
the  supplies  are  essentially  at  capacity.  The  worldwide  reserves 
are  generally  abundant,  however  there  are  several  economic, 
logistical, labour related, and geopolitical challenges to overcome 
to  bring  on  additional  production  on  a  sustainable  basis.  The 
damage  caused  by  the  hurricanes  in  the  US  Gulf  Coast  and  the 
operational  problems  encountered  at  several  reﬁ neries  in  2005 
simply  exacerbated  an  already  tight  balance  for  hydrocarbon 
products. 

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The Plan: Marketing

19

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Canadian  Natural  continued  to  successfully  implement  its 
blending strategy in 2005 by contributing 55% of the total 255 
mbbl/d of WCS stream in the fourth quarter. To further enhance 
our blending ﬂ exibility and economics, we have initiated a full 
evaluation for the importation of condensate or natural gasoline 
from various American facilities. 

The  logistical  challenges  are  being  addressed  by  industry  and 
signiﬁ cant progress was achieved in 2005 with the approval of 
the Enbridge Southern Access Pipeline expansion which will add 
394 mbbl/d to the greater Chicago market area by 2009 and the 
Terasen TMX 1 project to add a total of 75 mbbl/d to the West 
Coast by 2008. The TCPL Keystone project to add 400 mbbl/d 
to the Woodriver market area with further option to extend to 
Cushing has received sufﬁ cient commitments to proceed further. 
Two long haul pipeline projects are being developed to transport 
oil  from  Edmonton  to  the  West  Coast  with  access  to  the  US 
reﬁ neries and the Asian markets. The Enbridge Gateway project 
is for 400 mbbl/d to Kitimat and the Terasen TMX project is for 
625 mbbl/d split between Vancouver and Kitimat/Prince Rupert. 
We believe these two projects are at least ﬁ ve years away given 
the required market developments and regulatory requirements. 
We are conﬁ dent that the industry will proceed with the necessary 
incremental pipeline export capacity on a timely basis to support 
the  expected  incremental  production  out  of  the  WCSB  and 
speciﬁ cally from the oil sands projects.

The Corsicana pipeline is scheduled to ship heavy crude oil from 
Patoka,  IL  to  Nederland,  TX  by  late  March  2006.  Canadian 
Natural has committed 25 mbbl/d for ﬁ ve years on this pipeline 
that  could  eventually  carry  up  to  80  mbbl/d  to  US  Gulf  Coast 
reﬁ neries. The Spearhead pipeline started shipping 80 mbbl/d of 

oil  from  Chicago,  IL  to  Cushing,  OK  on  March  2,  2006  and 
has  the  capacity  to  ship  125  mbbl/d.  Both  pipelines  could  be 
expanded further with market demands for Canadian crude oil. 

Canadian  Natural  continues  to  work  with  North  American 
reﬁ ners  to  encourage  them  to  add  more  conversion  capacity 
to  their  facilities.  The  Company  is  also  proceeding  with  a  full 
evaluation  of  its  second  heavy  crude  oil  upgrading  facilities  in 
addition  to  its  Horizon  Project.  The  full  scope  deﬁ nition  and 
the detailed evaluation of the upgrading technology to be used 
are currently underway at the selected engineering ﬁ rms and we 
expect to complete this phase in early 2007. We intend to follow 
the same rigorous process employed for the Horizon Project. The 
initial concept is to upgrade the bitumen into a sweet SCO and to 
incorporate the synergistic beneﬁ ts of heat integration between 
the upgrading process and the thermal bitumen production with 
the potential use of the gasiﬁ cation technology.

Canadian  Natural’s  portfolio  for  2006  is  forecast  to  average 
between  335  mbbl/d  and  373  mbbl/d  and  with  the  current 
2006  pricing  strips  for  WTI  at  US$64.42/bbl  would  yield  an 
overall wellhead price of C$37.73/bbl, using a US$0.88/C$1.00 
exchange rate.

PRICE RISK MANAGEMENT
Canadian  Natural  utilizes  hedging  techniques  to  provide  some 
assurance on price realizations and to protect cash ﬂ ow generation 
capability  in  order  to  fund  ongoing  development  programs. 
Generally,  the  downside  pricing  risks  associated  with  various 
commodities are determined and, if deemed appropriate, ﬁ nancial 
derivatives  are  used  to  limit  risk.  Currency  exposures  are  also 
monitored and may be hedged in conjunction with commodities.

20

The Plan: Marketing

In conjunction with approval of the Horizon Project, our Board 
of Directors granted management the authority to hedge up to 
75%  of  any  commodity’s  expected  production  volumes  for  a 
forward 12-month period, up to 50% of the second 12-month 
period and up to 25% for the following 24-month period. 

MIDSTREAM
Our midstream assets consist of the 100% owned and operated 
Echo pipeline, the 15% interest in the Cold Lake Pipeline system, 
the 62% interest in the operated Pelican Lake Pipeline and the 
50%  interest  in  the  84  megawatt  co-generation  unit  located  at 
our Primrose facility. The midstream assets allow us to control 
and optimize transportation costs for about 80% of our heavy 
crude oil production and generate additional revenues from third 
party volumes and the sale of surplus electricity.

Echo  is  the  only  pipeline  delivering  undiluted  raw  bitumen  to 
the Hardisty terminals and plays an important role in our heavy 
crude  oil  blending  and  marketing  strategy  for  WCS  and  other 
diluted bitumen blends. 

We will be completing a lateral pipeline from its ECHO pipeline 
to our Morgan battery in the third quarter of 2006 at a cost of 
$6 million to increase the utilization rate from 86% in 2005 to 
90% once completed. 

The  2005  revenues  from  our  Midstream  assets  increased  by 
16.6%  to  $77  million  primarily  from  higher  volumes  on  Echo 
and  Pelican  pipelines,  increased  revenues  from  our  Nipisi 
terminal and higher sales of surplus electricity from our Primrose 
cogeneration facility into the Alberta provincial grid.

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The Plan: Marketing

21

THE PEOPLE
Capital discipline is ingrained throughout all 
operating units. They are accountable for the 
capital they spend and the value they create.

THE PLAN
Maintain good access to capital markets 
while ensuring balance in our borrowing 
sources and the term of their maturities.

THE ASSETS
Backstopping our ﬁ nances are assets capable 
of generating signiﬁ cant free cash ﬂ ow, even 
in a lower priced environment.

Financial Plan

Canadian Natural has always viewed ﬁ nancial strength as integral 
to  ongoing  success.  We  have  carefully  developed  our  ﬁ nancial 
capacity  to  both  proﬁ tably  grow  our  conventional  crude  oil 
and  natural  gas  business  and  to  ﬁ nance  this  growth  as  well  as 
construction of our world class Horizon Oil Sands Project.

OUR FINANCIAL STRENGTHS ARE 
MANY AND INCLUDE:
  •   A  diverse  asset  base  both  geographically  and  by  product, 
most  of  which  is  located  in  G-7  countries  with  stable  and 
secure  economies.  This,  coupled  with  our  exploitation 
approach to the business, reduces operational risk.

  •   Financial 

liquidity, 

including  $3.4  billion  of  bank 
credit  facilities,  $3.3  billion  of  which  were  unutilized  at
December 31, 2005.

In concert with the sanctioning of the Horizon Project and as more 
fully described in the Management’s Discussion and Analysis, our 
risk management program was increased during 2005. In order 
to avoid ﬁ nancial stress should commodity prices fall during the 
period of 2005 through 2008 when we are constructing Phase 1 
of the project, the increased assurance of future cash ﬂ ow levels 
afforded  by  the  risk  management  program,  combined  with  the 
high degree of cost certainty acquired for construction costs, were 
critical to the sanctioning of Phase 1 of the Horizon Project. 

As a strong investment grade borrower, we have many ﬁ nancial 
ratios to which we steward. For example, we target to maintain 
a debt to book capitalization of about 35% to 45%, depending 
upon  where  we  are  in  the  business  cycle.  Assuming  a  post 
2006  US$35/bbl  WTI  price  environment,  we  believe  that  our 
disciplined approach to balance sheet management will facilitate 

  •   A diversiﬁ ed production base with strong internally generated 

cash ﬂ ows, supported by a proactive hedge program.

  •   Flexible  capital  expenditures  program  with  a  balance  of 
solid  production  maintenance  as  well  as  short-,  medium-, 
and long-term initiatives.

  •   A proactive, ﬂ exible approach to project development and 
ﬁ nancing  strategies  predicated  upon  our  5-  and  10-  year 
business plans.

  •   A strong balance sheet with a debt to book capitalization of 

29% as at December 31, 2005. 

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22

The Plan: Financial Plan

DOUGLAS A. PROLL
Chief Financial Ofﬁ cer 
& Senior Vice-President, 
Finance

RANDALL S. DAVIS
Vice-President, 
Financial Accounting 
& Controls

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the  delivery  of  our  conventional  growth  plans  as  well  as  the 
construction  of  the  Horizon  Project  and  the  Canadian  Natural 
Upgrader. Under these plans we would expect to remain within 
our targeted range.

Having  this  excess  ﬁ nancial  capacity  means  that  Canadian 
Natural does not have to compromise on its balanced strategies. 
Maintaining  a  strong  balance  sheet  provides  ﬂ exibility  to  our 
operations and the execution of our deﬁ ned plan.

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(cid:12)(cid:136)(cid:219)(cid:136)(cid:96)(cid:105)(cid:152)(cid:96)(cid:195)(cid:202)(cid:171)(cid:105)(cid:192)(cid:202)(cid:86)(cid:156)(cid:147)(cid:147)(cid:156)(cid:152)(cid:202)(cid:195)(cid:133)(cid:62)(cid:192)(cid:105)
(cid:173)(cid:10)(cid:102)(cid:201)(cid:195)(cid:133)(cid:62)(cid:192)(cid:105)(cid:174)

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The Plan: Financial Plan

23

Health & Safety, Environment
and Community

OUR COMMITMENT TO RESPONSIBLE 
OPERATIONS
“Doing it right” is part of our mission statement and integral to 
the way we approach our business. We continue to conduct our 
operations with diligence to ensure we comply with all regulatory 
standards and guidelines, and with the discipline and proactive 
focus  to  achieve  continuous  improvement  in  our  stewardship 
performance.  Our  people  and  contractors  understand  they  are 
accountable on a daily basis to implement our vision for health 
and safety, environment and community. 

HEALTH AND SAFETY PERFORMANCE: 
INCREASED AWARENESS, EFFECTIVE 
SYSTEMS AND CO-OPERATION
We believe the continual improvements in our health and safety 
performance can be attributed to enhanced safety awareness in our 
operations, continuous improvement of our safety management 
systems, and a high degree of co-operation with our contractors 
in meeting health and safety goals. 

In  our  North  American  conventional  operations,  our  total 
recordable injury frequency continued to decline in 2005 despite 
it being the most active in our history. Approximately 10 million 
more  man  hours  were  worked  in  2005  than  in  2004  with  a 
reduction in the recordable injury frequency of 16%. Lost time 
injury  and  ﬁ rst  aid  injury  frequencies  have  also  continued  to 
decrease during the past three years.

As  part  of  our  proactive  approach,  the  number  of  facility, 
rig,  construction  and  pipeline  safety  and  compliance  audits 
performed  in  our  conventional  operations  increased  by  nearly 
50% over the number conducted in 2004. This aggressive audit 
program continues in 2006. Internationally, we implemented the 
key  elements  of  our  Safety,  Health  and  Environment  (“SHE”) 
Improvement  Program,  a  key  feature  in  our  major  accident 
hazard management strategy.

At the Horizon Project, our Health and Safety team has assembled 
an  extensive  operational  group  to  provide  medical,  safety  and 

security support to the more than 2,000 people now working on-
site. At year-end, all safety frequency statistics for the Horizon 
Project  were  better  or  comparable  to  statistics  benchmarked 
against the Construction Owners Association of Alberta (COAA) 
for  comparable  projects.  By  year-end,  Horizon  Project  had 
surpassed  more  than  3  million  exposure  hours  without  a  Lost 
Time  Accident.  As  Horizon  Project  activities  increase  in  2006, 
there is ongoing development of the Safety Management System, 
site procedures, and safety training programs. 

ENVIRONMENTAL INITIATIVES FOCUS 
ON CURRENT OPERATIONS AS WELL AS 
FUTURE DEVELOPMENTS
Canadian  Natural  continues  to  invest  in  people,  technologies, 
facilities and infrastructure to recover and process crude oil and 
natural  gas  resources  efﬁ ciently  in  an  environmentally  sound 
manner.  Our  environmental  strategies  target  energy  efﬁ ciency, 
air  emissions  management,  water  quality,  reduced  fresh  water 
use, and the minimization of our landscape footprint. Training 
and  due  diligence  for  operators  and  contractors  are  key  to  the 
effectiveness  of  our  environmental  management  programs  and 
the prevention of incidents.

With  a  view  to  operational  start-up  of  the  Horizon  Project  in 
2008, we are already addressing environmental aspects as diverse 
as the development of an audit/inspection package to encompass 
operations, the implementation of our wildlife corridor research 
program, and the construction of a fresh water lake to compensate 
for ﬁ sh bearing streams lost to development. 

In  our  conventional  operations,  our  multi-year  ﬂ aring  and 
venting  reduction  strategy  has  signiﬁ cantly  contributed  to  our 
air emission management programs. In 2005, Canadian Natural 
invested  more  than  $15  million  and  completed  more  than  130 
natural  gas  conservation  projects  with  resulting  recoveries  in 
excess of 13 mmcf/d. In 2006, we plan to complete another 120 
such natural gas conservation projects with a capital investment 
of $17 million.

24

The Plan: Health & Safety, Environment and Community

Though  Canadian  Natural  has  signiﬁ cantly  increased  our 
heavy crude oil production, we have also been able to increase 
the  percentage  of  solution  gas  conserved.  In  2005,  Canadian 
Natural continued to increase both the amount of solution gas 
that is collected and sold or utilized for lease fuel. Our solution 
gas conservation rate has increased from 63% in 2000 to 85%
in 2005.

(cid:1)(cid:143)(cid:76)(cid:105)(cid:192)(cid:204)(cid:62)(cid:202)(cid:195)(cid:156)(cid:143)(cid:213)(cid:204)(cid:136)(cid:156)(cid:152)(cid:202)(cid:125)(cid:62)(cid:195)(cid:202)(cid:86)(cid:156)(cid:152)(cid:195)(cid:105)(cid:192)(cid:219)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:202)(cid:192)(cid:62)(cid:204)(cid:105)
(cid:173)(cid:175)(cid:202)(cid:86)(cid:156)(cid:152)(cid:195)(cid:105)(cid:192)(cid:219)(cid:105)(cid:96)(cid:174)

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(cid:211)(cid:228)(cid:228)(cid:120)

Our  Greenhouse  Gas  (GHG)  emission  reduction  strategy  is 
based on emissions intensity. Our goal is to consistently reduce 
GHG  emissions  per  unit  of  production.  We  systematically  and 
continuously  review  opportunities  for  emissions  reduction  at 
our facilities, and we are developing and implementing strategies 
that include technological solutions and stakeholder input. Since 
2002,  our  emissions  intensity  has  been  reduced  13%  despite 
signiﬁ cant increases in activity and production. 

At our primary heavy crude oil and in-situ oil sands operations our 
goal  is  to  recycle  produced  water  and  supplement  with  brackish 
water, signiﬁ cantly reducing our fresh water use. At our Primrose 
operations we are now recycling about 95% of our produced water 
and have invested about $40 million in new brackish wells, pipelines 
and water treating capacity for our expanding operations. 

At  our  international  operations,  2005  was  the  fourth  year  in 
succession where we achieved a decrease in total operational oil 
in  produced  water.  We  again  exceeded  our  target  of  less  than 
25 parts per million (“ppm”) from our installations, well below 
statutory guidelines of 40 ppm.

BUILDING FUTURES TOGETHER WITH 
COMMUNITIES 
Canadian  Natural  continues  to  build  and  maintain  co-operative 
working  relationships  with  our  stakeholders,  and  to  support 
communities in their quality of life initiatives. We encourage and 
welcome stakeholder input into our plans and ongoing operations. 

We  are  working  collaboratively  with  many  First  Nation  and 
Métis leaders near our operations. We continue to consult with 
First Nation and Métis communities related to reducing impacts 
on traditional lands and incorporating Traditional Environment 
Knowledge  into  our  development  and  reclamation  plans. 
Together, we have been identifying strategies and implementing 
action plans so communities can play a more direct role in the 
development of crude oil and natural gas resources. In 2005 we 
also  increased  ﬁ nancial  and  leadership  support  for  Aboriginal 
education and training programs.

We continue to expand our Building Futures Scholarship Program 
which supports training to help meet the human resource needs 
for  oil  and  natural  gas  ﬁ eld  operations.  Since  2002,  we  have 
awarded more than $400,000 in scholarships to more than 300 
students living in 26 communities near our operations. 

investment  programs  contribute  to  the 
Our  community 
development of people and to the building of strong communities. 
We are proud to work with our communities in Western Canada, 
the  UK  and  West  Africa  to  provide  ﬁ nancial  and  volunteer 
support  for  hundreds  of  projects  that  meet  their  vision  for  the 
future in education, wellness, arts, sports, and social programs. 
In  our  international  operations,  for  example,  we  constructed 
a  water  tank  tower  and  potable  water  network  for  the  Adjue 
village in Côte d’Ivoire to help improve the lives and health of 
community members. In addition to the backing we provide to 
community programs and capital projects, our people throughout 
our  operations  in  Western  Canada  have  selected  a  variety  of 
local  community  agencies  that  we  support.  Our  corporate 
ofﬁ ce  matches  each  dollar  contributed  by  our  employees  and 
contractors to these important community agencies.

The Plan: Health & Safety, Environment and Community

25

The Assets

NORTH AMERICA

2005 net results, after royalties
Proved reserves
Production 
(mmboe)
(mboe/d)
694
192 
457
187 
1,151
379
72
80

Oil and NGLs 
Natural gas 
Boe
% of total 

DEFINED STRATEGY TO EXPLOIT A 
WORLD CLASS ASSET PORTFOLIO
Our  exploitation  based  development  philosophy  has  proven 
through  the  business  cycle  to  minimize  exploration  risks  and 
maintain low operating and capital costs. This disciplined approach 
is  applied  rigorously  throughout  Canadian  Natural’s  worldwide 
operations. It includes:

  •   Maintaining a large inventory of undeveloped land in each 
core region enabling us to continually high-grade prospects 
and to optimally plan future drilling programs. 

  •   Dominating the land base and controlling the infrastructure 
in regions in which we operate. We maintain high working 
interests and operate the vast majority of our assets allowing 
us to steward to our plans and control our costs.

  •   Progressively developing lands as extensions from our existing 
infrastructure, thereby minimizing infrastructure costs.

  •   Evaluating and testing new techniques to maximize resource 

recovery.

  •   Maximizing our facility throughput, allowing us to reduce 
per-unit  production  costs.  Whether 
is  compressor 
utilization  in  Canadian  natural  gas  operations,  water  and 
sand disposal in heavy crude oil operations or FPSO capacity 
utilization internationally, we aggressively seek opportunities 
to leverage capabilities and reduce per-unit costs.

it 

NORTH AMERICAN NATURAL GAS
North American natural gas is Canadian Natural’s single largest 
product, representing 43% of our equivalent production volumes 
and  46%  of  sales  revenues  in  2005.  During  2005,  average 
production  volumes  increased  by  86  mmcf/d  or  6%,  reﬂ ecting 
both  a  strong  drilling  and  asset  development  program  and  the 
full  year  impact  of  2004  property  acquisitions.  Production 
is  concentrated  in  four  of  our  North  American  core  regions: 
Northeast  British  Columbia,  Northwest  Alberta,  the  Northern 
Plains  and  the  Southern  Plains.  We  have  a  deﬁ ned  ﬁ ve  year 
development plan for each of these regions that results in 5% per 
annum production growth. 

NORTH AMERICAN CRUDE OIL AND NGLS
Canadian Natural is one of Canada’s largest producers of crude 
oil  and  NGLs  with  an  extensive  developed  and  undeveloped 
light and heavy crude oil asset base augmented by NGLs which 
are  produced  in  conjunction  with  natural  gas.  During  2005, 
average  production  volumes  increased  by  7%,  reﬂ ecting  our 
successful drilling and development programs. Our heavy crude 
oil production is concentrated in the Northern Plains core region 
with light crude oil being produced in all ﬁ ve of our core regions.

Our exploitation based strategy capitalizes on our dominance in 
our core regions reducing both capital and operating costs. Our 
expertise  in  recovery  techniques  allows  us  to  continually  focus 
on  maximizing  crude  oil  recovery  from  both  mature  and  new 
crude oil pools. 

26

The Assets

LYLE G. STEVENS
Senior Vice-President, 
Exploitation

JEFF W. WILSON
Senior Vice-President, 
Exploration

INTERNATIONAL

2005 net results, after royalties
Proved reserves
Production 
(mmboe)
(mboe/d)
424
91 
17
4
441
95
28
20

Oil and NGLs 
Natural gas 
Boe
% of total 

INTERNATIONAL 
Our international operations provide a vehicle for continued light 
crude oil production growth. A disciplined and focused approach 
is  essential  to  successful  value  creation  in  the  international 
arena,  therefore,  we  limit  our  exposure  to  those  basins  where 
we  see  the  greatest  opportunities  and  we  can  best  lever  our 
business  strategies.  We  capitalize  on  our  core  competency  of 
mature  basin  exploitation  in  the  North  Sea  where  the  business 
parallels that of the WCSB in many ways. Offshore West Africa 
provides development opportunities and signiﬁ cant exploration 
upside, capitalizes on strong government relationships developed 
over  the  past  few  years  and  leverages  the  technical/operational 
expertise in the North Sea. In both basins, we operate in areas 
where we dominate the land base and have the infrastructure to 
support our operations.

OIL SANDS MINING
We hold extensive leases in the Athabasca region north of Fort 
McMurray that are amenable to the open pit mining of bitumen. 
These  resources  will  be  upgraded  on  site  to  a  light  sweet  SCO 
and may be produced for decades to come without production 
declines  normally  associated  with  crude  oil  production.  Our 
Horizon  Oil  Sands  Project  represents  a  phased  development 
accessing up to 6 billion barrels of bitumen resource potential. 
Today we are in construction of the 110,000 bbl/d Phase 1 with 
ﬁ rst oil expected in the second half of 2008. Subsequent phases 
are  planned  with  total  potential  production  from  the  leases  of 
approximately 500,000 bbl/d by 2017.

The Assets

27

OIL SANDS MINING

2005 proved reserves

Gross 
(mmbbl)
2,235 
1,833

Net
(mmbbl)
1,848
1,626

Bitumen 
SCO*

*  SCO reserves are based upon upgrading of the bitumen reserves.

The reserves shown for bitumen and SCO are not additive.

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North American
Natural Gas

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NORTHEAST BRITISH COLUMBIA
THE ASSET AND OUR PLAN
Our  experience  in  Northeast  British  Columbia,  our  large 
undeveloped land base of 2.0 million acres and 6,000 kilometers 
of pipelines affords us a signiﬁ cant competitive advantage in this 
highly  prospective  region.  We  further  break  this  region  down 
into three distinct geological play types:

1.  Most  northerly  is  the  Helmet  area  where  we  employ 
horizontal wells to exploit the low-risk, regionally extensive, 
natural gas charged Jean Marie carbonate formation. 

2.  In the Fort St. John area, natural gas is produced from an 
array  of  carbonate  and  sandstone  reservoirs  ranging  from 
the Notikewin at 2,000 ft to the Slave Point at 15,000 ft. 

3.  Most  southerly  is  the  Foothills  region  where  we  target 
deeper  Mississippian  and  Triassic  age  reservoirs  in  this 
highly deformed structural area.

2005 ACTIVITY
At Helmet, the Company drilled 46 net wells with an 85% success 
rate  adding  incremental  production  of  20  mmcf/d.  In  total, 
228  net  wells  were  drilled  with  a  88%  success  rate,  including
57 net Notikewin natural gas wells. Since this shallow regional 
play was identiﬁ ed in late 2003, the Company has drilled 156 net 
wells on this trend with a success rate of 89%.

We  apportion  a  modest  capital  budget  each  year  to  explore 
for  Slave  Point  reefs,  targeting  reservoirs  with  5  to  30  bcf  of 
recoverable natural gas. In 2005, 2.4 net Slave Point wells were 
drilled  resulting  in  1.4  net  successful  wells.  In  the  Foothills  of 
NE  British  Columbia  and  NW  Alberta  we  are  successfully 
increasing  our  exploration  and  development  activity  as  we 
target  deep  Cretaceous  reservoirs.  Well  costs  are  higher  and 
pipeline  infrastructure  is  less  developed  but  rates  and  reserves 
are  commensurately  much  higher.  During  2005,  10  net  wells 
targeting deep reservoirs were drilled that will add an estimated 
35 mmcf/d of incremental production.

28

The Assets: North American Natural Gas

WHAT TO EXPECT IN 2006 AND BEYOND
The 2006 drilling program is well deﬁ ned with more than 260 
wells planned, including 66 Notikewin wells and 30 horizontal 
wells at Helmet. On the exploration front, four deep natural gas 
wells are planned targeting the Slave Point formation. 

Our project inventory is deep with more than 1,500 well locations 
planned over the next ﬁ ve years. Our large undeveloped land base 
and  our  superior  inventory  of  drilling  prospects  in  the  proliﬁ c 
relatively  undeveloped  basin  of  NE  British  Columbia  creates 
one  of  the  key  drivers  for  our  future  natural  gas  growth.  We 
project resource potential of 1.2 tcf in our 5-year forecast for this
core region. 

NORTHWEST ALBERTA
THE ASSET AND OUR PLAN
This  region  contains  exceptional  exploration  and  exploitation 
opportunities  in  combination  with  our  extensive,  owned  and 
operated infrastructure. We produce liquids rich natural gas from 
multiple,  often  technically  complex  horizons,  with  formation 
depths  ranging  from  2,000  to  15,000  feet.  We  leverage  our 
existing developments to exploit existing pools while continuing 
to develop unconventional and tight gas plays. Landholdings in 
the region exceed 1.5 million undeveloped acres and we own and 
operate  more  than  26  facilities  and  1,800  miles  of  pipelines  to 
support our operations. 

2005 ACTIVITY
In this region we drilled a total of 166 net natural gas wells, a
17  net  well  increase  from  2004.  We  continued  our  low-
risk  Cardium  sand  development,  drilling  76  net  wells  with  a 
remarkable 99% success rate. The focus of our excellent technical 
team  on  this  complex  tight  sand  reservoir  has  resulted  in  a 
previously costly and risky play becoming a low-risk exploitation 
development.  We  are  now  leveraging  the  Cardium  play  in  this 
region to economically access deeper horizons. 

(cid:45)(cid:213)(cid:86)(cid:86)(cid:105)(cid:195)(cid:195)(cid:118)(cid:213)(cid:143)(cid:202)(cid:152)(cid:62)(cid:204)(cid:213)(cid:192)(cid:62)(cid:143)(cid:202)(cid:125)(cid:62)(cid:195)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:202)(cid:96)(cid:192)(cid:136)(cid:143)(cid:143)(cid:105)(cid:96)
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In the northern portion of this core area we continued to expand 
our multi-zone drilling program and also extended the shallow 
Notikewin play ﬁ rst developed in Northeast British Columbia.

WHAT TO EXPECT IN 2006 AND BEYOND
The 2006 drilling program includes almost 150 net wells, with 
large programs for the Cardium, 57 net wells, and the Notikewin, 
13  net  wells.  We  have  identiﬁ ed  more  than  950  locations  to 
be  drilled  over  the  next  ﬁ ve  years  in  this  core  area.  Through 
delineation  drilling,  technical  analysis  and  land  acquisitions 
we  have  secured  a  competitive  advantage  in  the  deep  basin  in 
this  region  and  we  foresee  signiﬁ cant  potential  from  this  play 
type.  Our  expertise  in  the  region  coupled  with  our  extensive 
undeveloped land base creates a strong natural gas growth proﬁ le 
and the second core area that will drive our corporate natural gas 
growth. Here we target new natural gas resource potential of 1.3 
tcf over the next ﬁ ve years.

NORTHERN PLAINS
THE ASSET AND OUR PLAN
Natural gas in the Northern Plains core region is produced from 
shallow, low-risk, multi-zone prospects and more recently from the 
Horseshoe Canyon coal bed methane (“CBM”). This is generally 
considered a mature operating region however through ongoing 
focused exploitation we continue to ﬁ nd excellent prospects for 
both  development  drilling  and  secondary  zone  recompletions. 
Our strategy in this region is to target low-risk exploration and 
development opportunities on our extensive land base, continue 
expansion of our commercial CBM project, examine synergistic 
property acquisitions opportunities, and minimize operating costs 
through high utilization of facilities and operations discipline.

2005 ACTIVITY
During 2005, 238 net wells targeting natural gas were drilled in 
the region with a 84% success rate. CBM development drilling 
continued to grow with the drilling of 42 net wells.

We believe that our asset base is 
capable of delivering continued 
growth over the next 5 years.

WHAT TO EXPECT IN 2006 AND BEYOND
The  2006  drilling  program  includes  353  net  natural  gas  wells 
and recompletion of 299 net wells. Over the next ﬁ ve years we 
have  identiﬁ ed  over  1,700  net  natural  gas  locations,  including 
510 net Horseshoe Canyon CBM locations and more than 800 
recompletion opportunities. 

SOUTHERN PLAINS
THE ASSET AND OUR PLAN
Natural gas in the Southern Plains core region is produced from shallow, 
low-risk wells drilled at high densities, conventional multi-zone and 
additional CBM prospects. We’ve operated in this core region for 10 
years and expect to grow production by an average of 4% per annum 
for the next 5 years. We continue to regionally expand the prospective 
area  for  shallow  gas  resulting  in  new  inﬁ ll  drilling  opportunities
and new shallow plays in undeveloped areas. We have maximized 
our returns on shallow gas and CBM by utilizing our area dominance 
and existing infrastructure to add low-cost volumes. 

2005 ACTIVITY
The 2005 drilling program, at 342 net wells, represented a 47% 
increase over 2004 activity when capital was redeployed towards 
property  acquisitions.  This  2005  program  included  209  net 
shallow  natural  gas  wells,  58  net  CBM  wells  and  75  net  other 
natural gas wells. 

WHAT TO EXPECT IN 2006 AND BEYOND
The  2006  drilling  program  is  comprised  of  more  than  375  net
wells,  almost  250  of  which  are  targeting  low-risk,  shallow 
natural gas. 60 net Horseshoe Canyon CBM wells are planned 
as the Company continues to expand both its expertise and its 
commercial  CBM  operations.  Our  ﬁ ve  year  drilling  inventory 
totals  more  than  1,550  net  natural  gas  wells,  including  over 
1,070  shallow  locations  and  over  170  net  Horseshoe  Canyon 
CBM  wells.  With  the  addition  of  new  shallow  gas  prospects 
and  continued  Horseshoe  Canyon  CBM  development  we  are 
forecasting  modest  production  growth  in  the  Southern  Plains 
over the next ﬁ ve years.

The Assets: North American Natural Gas

29

North American
Crude Oil

LIGHT CRUDE OIL AND NGLS
THE ASSET AND OUR PLAN
We  produce  light  crude  oil  and  NGLs  in  all  of  the  Company’s 
western Canadian core regions. In North America, our light oil 
assets are largely developed; however, we continue to grow light oil 
production through a strategy of new waterﬂ ood implementation, 
existing waterﬂ ood optimization, development drilling, new pool 
discoveries and acquisitions. The vast majority of the Company’s 
light  pools  are  produced  under  waterﬂ ood  resulting  in  high 
recovery factors and low production decline rates.

2005 ACTIVITY
In  2005,  Canadian  Natural’s  light  crude  oil  drilling  and 
development programs pursued four initiatives: 

  •   Low  risk,  inﬁ ll  drilling  in  crude  oil  pools  located  in  the 
Northern  Plains,  Northwest  Alberta  and  the  Southeast 
Saskatchewan core regions;

  •   Waterﬂ ood  optimization  programs  in  all  our  core  regions. 
We  have  a  strong  technical  team  that  is  dedicated  solely 
to  waterﬂ ood  optimization  through  detailed  reservoir 
characterization, analysis of pattern performance, improved 
well  operating  practices  and  improved  ﬂ uid  processing  at 
our facilities;

  •   New  pool  exploration  and  pool  extensions  in  Northwest 
Alberta and Northeast British Columbia where 1,000 bbl/d 
of new production was added. Future development potential 
was also identiﬁ ed; and,

  •   Pilot testing of polymer ﬂ ooding to improve oil recovery in 

a mature waterﬂ ood.

WHAT TO EXPECT IN 2006 AND BEYOND
For 2006, Canadian Natural will continue to focus on waterﬂ ood 
and tertiary recovery opportunities. Our 2005 drilling program 
has  identiﬁ ed  signiﬁ cant  new  development  potential  in  the 
Fireweed  area  of  Northeast  British  Columbia,  the  Worsley 
area  of  Northwest  Alberta  and  the  Pierson  pool  in  Southeast 
Saskatchewan.  More  than  120  net  wells  are  planned  for  our 
2006 light crude oil drilling program making it the largest light 
crude oil program in the Company’s history. 

30

The Assets: North American Crude Oil

Canadian  Natural  will  focus  on  waterﬂ ood  enhancements  to 
add incremental light crude oil reserves. We estimate that just a 
1% improvement in recovery factor could yield an incremental
42 million barrels of reserves. In addition to the enhanced crude 
oil  recovery  initiatives  our  deﬁ ned  plan  includes  over  400  new 
well locations to be drilled over the next ﬁ ve years.

PELICAN LAKE CRUDE OIL
THE ASSET AND OUR PLAN
This massive, shallow crude oil pool in our Northern Plains core 
region  is  estimated  to  contain  up  to  3  billion  barrels  of  OOIP 
and continues to provide excellent opportunities for production 
and  reserves  growth.  We  developed  this  pool  exclusively  with 
horizontal  wells  to  minimize  the  environmental  impact,  reduce 
development  costs  and  provide  greater  well  productivity.  We 
own and operate three centralized treating facilities in the area. 
Although  priced  similarly  to  heavy  crude  oil,  our  Pelican  Lake 
crude oil production yields netbacks typical of medium crude oil 
due to our ability to maintain low operating costs. 

2005 ACTIVITY
At Pelican Lake 2005 proved to be very successful year:

  •   We continued to extend the developable area of the existing 

pool and drilled 52 net primary horizontal wells;

  •   8 net stratigraphic wells were drilled to identify further pool 

extensions and other new pools in the area;

  •   We continued to expand the commercial waterﬂ ood project 
and  have  now  converted  11%  of  our  ﬁ eld  to  waterﬂ ood. 
A  total  of  25  sections  are  under  waterﬂ ood  with  64  net 
production wells and 72 net injection wells; and,

  •   We initiated a ﬁ ve well pilot test to determine the viability 
of polymer ﬂ ooding with the goal of enhancing productivity 
and increasing oil recovery. Initial results are promising and 
lead to a commercial scale installation in 2006.

Application of EOR techniques to the 
3 billion barrels of OOIP, combined with 
new drilling locations will continue 
to ramp Pelican Lake production levels.

(cid:45)(cid:213)(cid:86)(cid:86)(cid:105)(cid:195)(cid:195)(cid:118)(cid:213)(cid:143)(cid:202)(cid:86)(cid:192)(cid:213)(cid:96)(cid:105)(cid:202)(cid:156)(cid:136)(cid:143)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:202)(cid:96)(cid:192)(cid:136)(cid:143)(cid:143)(cid:105)(cid:96)
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The  waterﬂ ood,  primary  production  drilling  and  continued 
optimization has reversed production declines in the ﬁ eld resulting 
in a 10 mbbl/d or 57% production increase from 2004. 

WHAT TO EXPECT IN 2006 AND BEYOND
The  2006  program  will  see  Canadian  Natural  drilling  126  net 
horizontal  wells  for  primary  production  and  14  additional  net 
stratigraphic  wells  to  delineate  pool  extensions.  Expansion  of 
the  Pelican  Lake  waterﬂ ood  remains  a  priority  and  we  plan  to 
complete  the  conversion  of  7  sections  to  waterﬂ ood.  This  will 
entail  drilling  24  net  horizontal  inﬁ ll  production  wells  and 
converting  10  net  producing  wells  into  water  injection  wells. 
Secondary  recovery  processes  are  expected  to  double  primary 
recovery factors on approximately 45 to 55% of the ﬁ eld. 

Beyond waterﬂ ood implementation, we will continue to evaluate 
the use of polymer at our pilot test to enhance waterﬂ ood recovery. 
While it is too early to judge the technical and economic success 
of  this  enhanced  recovery  process, 
polymer ﬂ ood could yield incremental 
recoveries  of  15%  over  primary 
production.  This  could  amount  to 
130 mmbbl of incremental recovery 
at Pelican Lake. 

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(cid:38)(cid:76)(cid:85)(cid:73)(cid:68)(cid:83)

We  currently  expect  that  with  our 
EOR  projects  combined  with  over 
600  net  well  locations  in  our  ﬁ ve 
year  plan  will  continue  to  increase 
production  over  the  next  several 
years.

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 —  CASE STUDY —
PELICAN LAKE

Pelican  Lake  is  a  large,  shallow  oil  pool  in  Canadian 
Natural’s  Northern  Plains  core  region  estimated  to 
contain up to 3 billion barrels of OOIP and is exclusively 
developed  with  horizontal  wells.  Optimization  of  the 
Field continues on several fronts as follows:

  •   We now drill wells with both single and multiple 
leg  “tuning  fork”  wells  efﬁ ciently  draining  more 
of  the  reservoir  from  each  well.  Our  expected 
well  inventory  remains  strong  over  the  next  ﬁ ve 
year period;

  •   Application of waterﬂ ood technology to a portion 
of  the  Field  could  increase  recovery  factors  by  a 
further  7.5%  from  the  base  expected  recovery  of 
about 5%;

  •   Application  of  Polymer  ﬂ ood  (see  ﬁ gure)  could  
increase recovery factors by 15% throughout the 
majority of the Field. Our initial pilot test for this 
ﬂ ood commenced in early 2005 with preliminary 
results expected in 2006.

As  a  result  of  these  initiatives,  Pelican  Lake  production 
increased  57%  during  the  year,  reversing  3  years  of 
production  declines.  Continued  growth  is  expected  in 
production  volumes  for  the  next  ﬁ ve  years,  once  again 
making Pelican Lake a growth story.

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(cid:82)(cid:69)(cid:80)(cid:82)(cid:69)(cid:83)(cid:69)(cid:78)(cid:84)(cid:65)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:79)(cid:70)(cid:0)(cid:48)(cid:69)(cid:76)(cid:73)(cid:67)(cid:65)(cid:78)(cid:0)(cid:44)(cid:65)(cid:75)(cid:69)(cid:12)(cid:0)(cid:87)(cid:72)(cid:73)(cid:67)(cid:72)(cid:0)(cid:73)(cid:83)(cid:0)(cid:65)(cid:0)(cid:70)(cid:76)(cid:79)(cid:79)(cid:68)(cid:0)(cid:79)(cid:70)(cid:0)(cid:80)(cid:65)(cid:82)(cid:65)(cid:76)(cid:76)(cid:69)(cid:76)(cid:0)(cid:72)(cid:79)(cid:82)(cid:73)(cid:90)(cid:79)(cid:78)(cid:84)(cid:65)(cid:76)(cid:0)(cid:87)(cid:69)(cid:76)(cid:76)(cid:83)(cid:14)

The Assets: North American Crude Oil

31

North American
Crude Oil (continued)

PRIMARY HEAVY CRUDE OIL
THE ASSET AND OUR PLAN
Canadian  Natural’s  historic  growth  in  primary  heavy  crude  oil 
production has been achieved through drilling as well as strategic, 
synergistic acquisitions. Heavy crude oil is produced using primary 
production mechanisms from shallow, low-risk, multi-zone wells. 
This leads to low ﬁ nding and development costs, exceptional drilling 
success  rates  and  many  subsequent  recompletion  opportunities. 
The region is also natural gas prone and development drilling can 
lead  to  both  natural  gas  and  heavy  crude  oil  discoveries.  With 
over 1.6 million acres of undeveloped land and 200,000 acres of 
developed land, we dominate production and operations within the 
Bonnyville/Lloydminster primary producing area of our Northern 
Plains core region. This dominance allows us to minimize capital 
by  conducting  large  scale  drilling  and  development  programs. 
We  also  minimize  and  control  our  production  costs  through 
owning  and  operating  central  treating  facilities,  maximizing 
their utilization and using our size to achieve economies of scale. 
Finally, ownership of the ECHO crude oil sales pipeline reduces 
our  transportation  costs  and  allows  us  to  be  the  only  producer 
capable of delivering undiluted heavy crude oil into our blending 
facilities at Hardisty, Alberta. 

2005 ACTIVITY
During 2005 we drilled 360 heavy crude oil net wells, a 180 net 
well increase from 2004. Our ongoing program of recompletions 
continues  to  add  low-cost  volumes  and  in  2005  483  net  wells 
were recompleted to secondary zones.

In  our  efforts  to  improve  crude  oil  recovery  beyond  primary
we initiated a heavy crude oil waterﬂ ood at our Lonerock Field 
and  are  ﬁ eld  testing  an  experimental  solvent  injection  scheme
at Lindbergh.

WHAT TO EXPECT IN 2006
For 2006, 344 locations are forecast to be drilled and a further 
340  net  wells  will  be  recompleted.  Our  deﬁ ned  growth  plan 
forecasts that over 1,675 net well locations will be drilled during 
the  next  ﬁ ve  years,  keeping  production  relatively  ﬂ at.  As  new 
markets  are  created  for  heavy  crude  oil  we  have  the  capability 

32

The Assets: North American Crude Oil

of  ramping  up  this  drilling  effort  and  increasing  production, 
however,  we  will  not  proceed  until  we  are  assured  of  this 
new  demand.  We  will  continue  to  pursue  the  development  of 
applicable technologies to further improve oil recovery and are 
currently conducting research in both the ﬁ eld and the labratory. 
We estimate our developed lands to contain 7 billion to 10 billion 
barrels of OOIP; a modest 1% increase in recovery would equate 
to over 70 million barrels of incremental recoverable crude oil.

THERMAL (IN-SITU) HEAVY CRUDE OIL 
THE ASSET AND OUR PLAN
Canadian Natural has some of the best thermal oil sands assets in 
Canada. In the Cold Lake region we have our commercial Cyclic 
Steam  Stimulation  (CSS)  project  whose  production  makes  us 
the second largest thermal crude oil producer in Canada. In the 
immediate  region  we  also  have  the  undeveloped  Primrose  East 
lease which will provide for future growth using the same proven 
recovery  process.  In  the  Athabasca  region  we  have  more  than 
200,000 undeveloped acres of land suitable for thermal recovery 
processes.  These  assets  coupled  with  the  proposed  Canadian 
Natural upgrader initiative would provide both short and long 
term growth for the Company. Our technical expertise, our asset 
base and years of experience operating and constructing thermal 
projects  has  placed  Canadian  Natural  as  an  industry  leader  in 
thermal in-situ oil recovery. 

2005 ACTIVITY
Our  primary  2005  focus  was  the  construction  and  start-up  of 
the Primrose North expansion project. This project consists of a 
satellite steam generation plant and, 4 new well pads with 96 net 
horizontal wells that are pipeline connected to our central Wolf 
Lake processing plant. The expansion project was completed on 
budget and on schedule allowing for steam injection in Q4 2005 
and production in January 2006.

As  a  result  of  continued  development  and  optimization  at  our 
Primrose South project, our thermal oil production reached record 
levels, over 53 mbbl/d, which was a 22% increase over 2004.

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We are the second largest producer 
of crude oil recovered by thermal 
processes in Canada.

WHAT TO EXPECT IN 2006 AND BEYOND
For 2006, production from the Primrose North expansion project 
will reach its design capacity of 30 mbbl/d by the start of Q4. In 
2006,  we  plan  to  drill  an  additional  75  net  horizontal  wells  at 
Primrose as part of the ongoing project. As part of our long term 
thermal project expansion plans we will also drill more than 220 
net stratigraphic wells to further deﬁ ne our leases at Primrose East, 
Kirby, Birch Mountain and Gregoire Lake. We will also continue 
to delineate further reservoir at Primrose South to maximize both 
resource recovery and the infrastructure utilization.

Mid-term  growth  will  come  from  the  commercial  development 
at  Primrose  East  where  production  is  expected  in  2009.  The 
regulatory application for this project was submitted in January, 
2006. Beyond 2009 we see the potential to add an incremental 
240  mbbl/d  of  thermal  in-situ  production  from  our  Athabasca
oil sands leases at Kirby, Birch Mountain East, and Gregoire Lake. 
This new bitumen production will serve as feedstock for both the 
proposed Canadian Natural upgrader and the Horizon upgrader.

IN-SITU LANDS

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 —  CASE STUDY —
CANADIAN NATURAL UPGRADER

We  are  the  second  largest  producer  of  crude  oil 
recovered  by  thermal  processes  in  Canada  with  2005 
combined average daily production of 53 mbbl/d from 
our three in-situ developments. Beyond this, we a vast 
heavy  crude  oil  resource  base  capable  of  generating 
signiﬁ cant returns for our shareholders.

In  order  to  capitalize  on  this  opportunity  we  are 
proposing to build a heavy crude oil upgrader in Alberta 
which would convert this feedstock into a light sweet 
synthetic crude oil. This would signiﬁ cantly reduce the 
marketing  risk  of  the  production  while  increasing  the 
expected realizations from its sale. It helps facilitate the 
development of these vast resources in a disciplined and 

stepwise manner.

During  2006  we  will  expend  $30  million  on  a 
Scoping Study to determine the preferred location, 
technology,  capital  cost  and  crude  oil  output 
quality. We will also examine the use of gasiﬁ cation 
technologies to further control production expense. 
Resulting recommendations for the Upgrader will 
be tabled in 2007.

Following  a  disciplined  emphasis  on  front  end 
engineering we expect construction to commence 
in 2009 and ﬁ rst production in 2012. Preliminary 
capacity  estimates  are  for  125  mbbl/d  of  SCO, 
expandable to 175 mbbl/d by 2015.

The  proposed  Canadian  Natural  Upgrader,  by 
increasing average realizations and netbacks while 
expanding  markets  for  our  heavy  crude  oil  will 
generate  signiﬁ cant  shareholder  value  for  years
to come.

The Assets: North American Crude Oil

33

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We operate approximately 99% 
of our production with an average 
ownership interest of 80%. Operations 
are currently run from four hubs. By 
maintaining control of these assets we 
have been able to control the capital 
allocation and pace of our exploitation 
plans for the properties.

International

UNITED KINGDOM PORTION OF THE 
NORTH SEA
THE ASSET AND OUR PLAN
Our achievements are a result of the successful utilization of our 
mature basin exploitation expertise. The ﬁ rst stage is based upon 
optimizing  existing  facilities  and  waterﬂ oods.  We  inﬁ ll  drill, 
recomplete,  and  workover  wells  and  optimize  waterﬂ oods  to 
increase production, lower costs and extend ﬁ eld life. The second 
stage incorporates more near pool development and exploration 
in  order  to  maximize  utilization  of  common  facilities  and 
ultimately extend all ﬁ elds’ economic lives. In 2006 and beyond, 
increasing emphasis on this type of work will be made. 

We  believe  that  the  current  environment  within  the  North  Sea  is 
similar to that of the WCSB in the early 1990s. The basin is mature 
and  many  of  the  major  operators  are  reducing  activity  levels  or 
looking at divestiture of properties. Exploitation oriented companies 
like Canadian Natural are proactively pursuing such opportunities.

2005 ACTIVITY
During  2005  we  drilled  13.2  net  wells  and  0.9  service  and 
injection  wells,  effectively  offsetting  production  declines.  At 
the Murchison Hub, production from the satellite pool Playfair 
continued,  however  third  party  natural  gas  export  restrictions 
resulted  in  some  curtailments  of  crude  oil  production.  At  the 
Ninian Hub, work progressed on the Columba Terrace and Lyell 

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Field  developments  with  engineering  of  subsea  raw  seawater 
injection facilities.

In  the  Central  North  Sea,  production  from  at  the  Banff/Kyle 
Hub was consolidated into one FPSO, reducing operating costs 
and extending the economic life of both ﬁ elds. The natural gas 
reinjection plan at Banff resulted in lower natural gas production 
volumes when compared with 2004, but should ultimately increase 
recoverability of crude oil from the reservoir. Refurbishment of 
the Tiffany Platform drilling rig was completed and a third party 
well was drilled and tariff income agreement was completed.

WHAT TO EXPECT IN 2006 AND BEYOND
During  2006, 15  net  wells are expected to be drilled, including 
3 injector wells. At Murchison and Ninian Hubs we will increase 
water  injection  and  processing  throughput.  At  the  Lyell  Field, 
4  new  wells  with  artiﬁ cial  lift  and  an  aggressive  waterﬂ ood are 
part  of  the  longer  term  plan  to  add  approximately  20  mbbl/d
of new plateau production in 2008.

With our current exploitation portfolio we expect to maintain or 
slightly grow current production levels over the next 3-4 years,
but  we  continue  to  look  for  accretive  acquisitions  with 
exploitation upside for growth.

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34

The Assets: International

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ALLEN M. KNIGHT
Senior Vice-President, 
International & 
Corporate Development

OFFSHORE WEST AFRICA
THE ASSET AND OUR PLAN
Canadian  Natural  has  three  exploration  Blocks  comprising 
approximately  274  thousand  net  undeveloped  acres  of  land 
located offshore Côte d’Ivoire. We are currently continuing the 
development of three proved properties East Espoir, West Espoir 
and  Baobab.  East  Espoir  and  Baobab  are  in  production  with 
further  drilling  continuing,  whilst  West  Espoir  will  commence 
development drilling in Q2 2006. 

2005 ACTIVITY
In Côte d’Ivoire in 2005 we drilled an additional two new net in-
ﬁ ll wells at East Espoir, tapping undeveloped portions of the pool 
and increasing production by 5 mbbl/d. Also during the year, ﬁ rst 
oil  at  our  Baobab  medium  crude  oil  development  was  achieved 
on-budget in August 2005 with only 4.5 years elapsed from ﬁ rst 
discovery to ﬁ rst oil – an excellent cycle time for our ﬁ rst deepwater 
development. Our West Espoir development also continued on time 
and on budget with ﬁ rst oil expected in the second half of 2006. 
During the year the well head tower was installed on location and 
the drilling conductors were driven to depth. 

In  October  2005,  Canadian  Natural  completed  the  acquisition 
of the permit to develop the Olowi Field, offshore Gabon. The 
permit  comprises  a  90%  interest  in  the  production  sharing 
agreement  for  the  Block  containing  the  Olowi  Field,  located
20 kilometers offshore and in 30 meters of water. Olowi has been 
delineated by the drilling of 15 wells by the previous owner and 
potentially  contains  as  much  as  500  million  barrels  of  34˚  API 
light crude OOIP. 

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WHAT TO EXPECT IN 2006 AND BEYOND
For 2006, two more producer wells will be drilled at East Espoir 
and 3 wells at Baobab, essentially completing initial development. 
West Espoir is scheduled for ﬁ rst oil during the second half of 2006 
following completion of production infrastructure and drilling of 
the ﬁ rst of 3 producer wells. Essentially, we will have grown our 
production  in  Côte  d’Ivoire  from  no  production  at  the  start  of 
2002 to about 60,000 boe/d through these three developments – 
all at highly attractive economics. Beyond current developments, 
the nearby Acajou Field will eventually be tied back to the East 
Espoir  as  space  becomes  available  in  these  facilities.  Again,  we 
leverage  existing  facilities  to  maximize  recovery  of  economic 
reserves.

The  Olowi  development  plan,  comprising  an  FPSO  and  four 
drilling  towers  was  ﬁ led  with  the  Gabon  Government  in  late 
2005 and was approved for execution in early 2006. Following 
engineering design and request for tenders, the development will 
commence  in  late  2006  with  ﬁ rst  production  targeted  for  late 
2008 and a plateau production rate of 20 mbbl/d. 

We plan to leverage our reputation and experience in the region 
to capture additional exploration and exploitation opportunities 
within this core region.

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The Assets: International

35

THE PEOPLE
We have assembled a world-class 
team of oil sands mining and project 
management experts.

THE PLAN
Our disciplined approach is based 
upon a heavy emphasis on front end 
design and engineering.

THE ASSETS
We estimate our leases to contain up to 
16 billion barrels of bitumen resource 
potential with up to 6 billion of that 
amenable to open pit mining.

Horizon Project

HORIZON
THE ASSET AND OUR PLAN
Canadian  Natural  owns  115,796  acres  in  the  Athabasca  Oil 
Sands  area  of  Northern  Alberta,  about  70  km  north  of  Fort 
McMurray. The Horizon Oil Sands Project includes a surface oil 
sands mining and bitumen extraction plant coupled with on-site 
bitumen  upgrading  and  associated  infrastructure  to  produce  a 
34º API synthetic crude oil.

THE HORIZON ADVANTAGE
The technology at the Horizon Project is based on that currently 
in  use  at  existing  plants,  effectively  mitigating  technology  risk 
in Phase 1. That being said, our plant has been conﬁ gured in a 
manner to maximize beneﬁ ts from the technologies. For example, 
the Horizon Project will have a very high level of heat sharing 
and integration between the facilities, reducing both natural gas 
consumption and greenhouse gas emission levels.

The project is designed as a phased development. First production 
of 110 mbbl/d of SCO from Phase 1 construction is targeted to 
commence in the second half of 2008. Production is targeted to 
increase to 155 mbbl/d following completion of Phase 2 in 2010. 
Finally, production levels of 232 mbbl/d are targeted for 2012, 
following completion of Phase 3 construction. The Company is 
currently  evaluating  the  opportunity  to  combine  Phase  2  and 
3 for a joint operational date of 2011. The project receives the 
beneﬁ ts of typical mine operations where production is limited 
only  by  the  facilities  and  infrastructure  –  while  capturing  the 
generous revenues of oil production with no declines. Sustaining 
capital  will  average  about  $1.22/bbl  once  the  plant  is  up  and 
running – resulting in signiﬁ cant free cash ﬂ ow. 

Construction  capital  costs  for  Phase  1  of  the  Horizon  Project 
are  estimated  at  $6.8  billion,  including  a  contingency  fund  of
$700  million,  with  $1.3  billion  spent  in  2005,  $2.6  billion 
forecast  to  be  incurred  in  2006  and  $2.9  billion  forecast  to  be 
incurred  in  2007  and  2008  combined.  Total  targeted  capital 
costs for all three phases of the development are projected to be
$10.8 billion in a US$45/bbl WTI world.

The  geological  risk  associated with  the project  is  very low. On 
this lease, over 16 stratigraphic net wells per section have been 
drilled to identify overburden levels, and test the ore composition 
and quality. The result is a well designed mine plan that has been 
optimized to support the bitumen extraction and processing.

To  ensure  efﬁ cient  construction,  we  have  implemented  an 
“80% rule”, with about 80% of the engineering effort required 
completion prior to major facility construction. This will allow 
us  to  ensure  materials  are  available  prior  to  construction  and 
minimize  rework.  In  addition  we  believe  that  our  execution 
and  labour  strategy  combined  with  the  ﬂ y-in/ﬂ y-out  ability 
of  workers  and  our  ﬁ rst-class  camp  facilities  will  position  the 
Horizon Project as “the employer of choice” in the region.

At  34º  API  gravity,  low  sulphur  and  fully  sweet,  the  project  is 
designed  to  produce  one  of  the  higher  quality  SCO  products, 
somewhat reducing marketing risks. 

Finally,  this  asset  has  been  designed  to  accommodate  future 
growth. The large footprint allows for easy access to all parts of 
the plant and ensures that future production expansions would 
not impact existing operations.

36 The Assets: Horizon Project

RÉAL J.H. DOUCET
Senior Vice-President, 
Oil Sands

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Site clearing, drainage and deep underground facility installation 
such as electrical, natural gas, water and sewage were completed 
during  the  ﬁ rst  half  of  the  year  and  work  on  access  roads 
continued throughout the year. 

Camps  for construction workers progressed signiﬁ cantly with the 
ﬁ rst camp opening in July 2005 and 72% progress on the second 
camp,  essentially  on  schedule.  Ultimately  three  2,000  worker 
camps will be constructed onsite with a fourth employee camp 
located offsite. To facilitate the Company’s labour strategies, the 
737–capable airstrip was completed in September 2005 and now 
hosts several landings each day.

Also  on  the  plant  site,  coker  and  extraction  separation  cell 
foundations  were  completed.  Erection  of  the 
latter  was 
commenced late in the year with 80% of the required material 
on site. 

Mine overburden removal progressed 10% ahead of plan, with 
a total of 6.7 million banked cubic meters of material removed. 
Earthwork  for  the  raw  water  and  recycle  water  pond  systems 
commence as scheduled.

The Assets: Horizon Project

37

2005 ACTIVITY
Phase 1 of the Horizon Project received sanction from the Board 
of Directors in February 2005 following an extensive front end 
engineering  approach  costing  over  $400  million  over  a  four 
year  period.  The  high  degree  of  up  front  project  engineering 
and  pre-planning  has  reduced  the  risks  on  “cost-plus”  aspects 
of  the  project  and  will  mitigate  the  risk  of  scope  changes  on 
the ﬁ xed price portions (targeted at 68% of Phase 1 costs). The 
pre-engineering and lessons learned from predecessors have also 
enabled  the  Company  to  prepare  a  detailed  development  and 
logistical plan to reduce the scheduling risk.

Signiﬁ cant  progress  was  achieved  during  2005  following  this 
sanctioning,  with  3-D  engineering  design  models  being  well 
advanced  in  most  areas  and  some  plant  areas  achieving  90% 
model review stage. In addition, Hazard and Operability reviews 
were completed with ﬁ ndings being incorporated in plant design. 
No signiﬁ cant changes occurred during the design.

At December 31, 2005, total procurement progress was at C$3.8 
billion in awarded contracts and purchase orders, with a further 
C$600 million in various stages of the tender process.

Use of modularization and prefabrication in existing construction 
yards is considered fundamental to overall success of the project. 
Module  fabrication  and  assembly  maintained  schedule  and 
just  as  importantly,  in  an  environment  of  key  transportation 
restrictions,  module  transportation  remains  on  schedule.  A 
total of 88 oversized loads were transported to site by year-end, 
including piperacks and various reactors.

Construction  also  moved  forward  in  a  signiﬁ cant  way.  During 
the year several critical path items were completed while on-site 
safety  statistics  and  performance  improved  for  eleven  months 
in  a  row  and  remain  well  below  the  Company’s  targets  as 
benchmarked against other projects in the area.

Horizon Project (continued)

WHAT TO EXPECT IN 2006 AND BEYOND
Activities  continue  in  2006  with  detailed  engineering  expected 
to be essentially complete. In addition, we expect to receive and 
complete  the  gas/oil  reactor  and  distillation  tower  and  erect 
critical  path  equipment  such  as  the  coke  drums  and  extraction 
separation cells.

The main piperack will be substantially completed. In February 
2006 the ﬁ rst sections of these piperacks were successfully placed 
with no rework required. At the ﬁ rst mine pit, construction of the 
Ore Preparation Plant will commence. 

The 2006 Phase 1 construction capital budget of $2.6 billion for 
the Horizon Project will facilitate major work as articulated. This 
budget represents an acceleration of spending into 2006, which 
allows Canadian Natural to capitalize on the opportunities created 
by having signiﬁ cant work completed during 2005. This serves 
to  modify  labour  requirements  timing  and  ease  the  execution 
of  the  project.  Capital  for  Phase  1  remains  at  $6.8  billion,
and  advancing  $400  million  from  2007  to  2006  will  result  in 
construction progress at the end of 2006 targeted at 55%.

Expenditures of $128 million to initiate the Engineering Design 
Speciﬁ cation,  order  certain  Phase 2 long-lead items and review 
the merits of combining Phase 2 and Phase 3 expansions into one 
combined Phase targeted to commence production in 2011. While 
not changing overall expected capital costs, this combination will 
provide  enhanced  overall  economics  as  it  allows  full  synergies 
and production to be achieved at an earlier date. The results of 
this review, and the decision whether to combine the phases, are 
expected in early 2007.

THE UPSIDE OPPORTUNITY
We believe that our land assets, site layout, size, and the manner 
in which we have planned this Project will facilitate increases in 
production beyond the 232 mbbl/d of SCO that is currently in 
development. Our internal estimates of resource potential, based 
upon  our  stratigraphic  well  drilling  program  accumulate  to 
approximately 6 billion barrels of mineable bitumen throughout 
our  Horizon  leases.  To  this  end,  we  recently  articulated  an 
expanded development plan.

As noted earlier, we are analyzing the merits of combining Phase 
2  and  Phase  3  expansions  into  one  combined  Phase  targeted 
to  commence  production  in  2011.  While  not  changing  overall 
expected  capital  costs,  this  combination  will  provide  enhanced 
overall  economics  as  it  allows  full  synergies  and  production  to 
be  achieved  at  an  earlier  date.  This  change  will  also  facilitate 
the  Company’s  labour  strategies  in  that  it  provides  a  smoother 
transition from Phase 1, keeps an experienced force on-site and 
optimizes the projected demand for construction labour.

Beyond Phases 1 to 3 of the Horizon Project, we will evaluate the 
Phase 4 addition of 125 mbbl/d of new SCO production targeted 
to commence in 2015 with Phase 5 adding a further 140 mbbl/d 
targeted to commence in 2017. 

In oil sands mining production, the generation of heat is a critical 
element  to  success.  Engineering  design  will  be  completed  to 
consider installation of gasiﬁ cation of the upgrading by-products 
into  Horizon  Project  Phases  1  to  3  in  2013.  This  technology 
would be built into Horizon Project Phase 4 and 5 expansions.

38 The Assets: Horizon Project

In announcing these expansions, we were cognizant of the need to 
maintain discipline while capitalizing on available opportunities. 
Each of these developments:

  •   Leverages our existing team and experience;

  •   Provides a natural migration of professional engineering and 

project management skills;

  •   Provides a natural migration of construction workers;

  •   Is ﬁ nancially supported through anticipated cash ﬂ ow of the 

Company; and, 

  •   Helps control operating costs in oil sands mining operations 
through targeted application of gasiﬁ cation technologies.

The Assets: Horizon Project

39

Year-end reserves

INDEPENDENT EVALUATION
For  the  year  ended  December  31,  2005,  Canadian  Natural  retained  qualiﬁed  independent  reserve  evaluators,  Sproule  Associates 
Limited (“Sproule”) and Ryder Scott Company (“Ryder Scott”) to evaluate 100% of the Company’s conventional proved and probable 
crude oil, natural gas liquids (“NGL”) and natural gas reserves* and prepare Evaluation Reports on these reserves. Sproule evaluated 
the Company’s North America conventional assets and Ryder Scott evaluated its international conventional assets. Canadian Natural 
has  been  granted  an  exemption  from  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 two principal differences between the two standards. The ﬁrst is the 
additional 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 Company has disclosed 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 this Annual Report. The 
Company has elected to provide the net present value (1) of these same conventional proved reserves as well as the conventional proved 
and probable reserves and the net present value of these reserves under the same parameters as additional voluntary information.

For the year ended December 31, 2005, the Company retained a qualiﬁed independent reserves evaluator, GLJ Petroleum Consultants 
(“GLJ”), to evaluate 100% of Phases 1 through 3 of the Company’s Horizon Oil Sands Project and prepare an Evaluation Report on 
the Company’s proved and probable oil sands mining reserves incorporating both the mining and upgrading projects. 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 probable crude oil, NGL and natural gas reserves.

The Reserve Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures 
with each of Sproule, Ryder Scott 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, NGL and natural gas reserves as well 
as the Company’s quantity of oil sands mining reserves.

NET CONVENTIONAL CRUDE OIL, NGL
AND NATURAL GAS RESERVES
During 2005, proved reserve additions of 251 mmboe replaced 145% of production. This growth was achieved at a 2005 ﬁnding 
and onstream cost of $13.41/boe resulting in a 3 year average ﬁnding and onstream cost of $12.55/boe. Proved and probable reserve 
additions of 337 mmboe replaced 195% of production at a 2005 and 3 year average ﬁnding and onstream cost of $9.97/boe and 
$8.05/boe respectively.

NORTH AMERICA
Proved natural gas reserves increased by 6% to 2.7 tcf and replaced 137% of 2005 production. Similarily, proved crude oil and NGL 
reserves increased by 7% to 694 mmbbl and replaced 167% of production. The total proved and probable crude oil and NGL reserves 
increased by 12% to 1,035 mmbbl primarily due to thermal in-situ and Pelican Lake Field developments.

INTERNATIONAL
North Sea proved reserve additions of 13 mmboe were primarily achieved through waterﬂood design optimization, inﬁll drilling and 
recompletions. Offshore West Africa proved crude oil and NGL reserves increased by 17% to 134 mmbbl through developments at 
the Espoir and Baobab ﬁelds in Côte D’Ivoire as well as the acquisition of the Olowi Field in Gabon where 15 mmbbl of proved crude 
oil and NGL reserves were added.

OIL SANDS MINING RESERVES
The Horizon Project’s gross proved and probable synthetic crude oil reserves have increased by 88 mmbbl from February 9, 2005 
estimates to 2,878 mmbbl due to the incorporation of updated pit limits and mine plans from drilling programs. The reserves are 
expected to produce over 37 years with ﬁrst production commencing in 2008.

* 

 Conventional crude oil, NGL and natural gas includes all of the Company’s light and medium, heavy and, thermal crude oil, natural gas, coal bed methane and natural gas liquid activities. It 
does not include the Company’s oil sands mining assets. 

40

The Assets: Year-End Reserves

NET CONVENTIONAL CRUDE OIL, NGL AND 
NATURAL GAS RESERVES (AFTER ROYALTIES) (2) (3)

Crude oil & 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 (%) (6)
Cost to develop ($/boe) (7)
  10% discount 
  15% discount 
Present value of conventional reserves ($ millions) (1)
  10% discount 
  15% discount 

December 31, 2005

Proved 

Proved 
Developed (4) Undeveloped (4)

Proved 
Total (4)

Proved and
Probable (5)

402 
214 
80 
696 

2,300 
16 
10 
2,326 
1,083 

0.79 
0.67 

24,275 
20,939 

292 
76 
54 
422 

441 
13 
62 
516 
509 

5.69 
5.15 

6,342 
4,881 

694 
290 
134 
1,118 

2,741 
29 
72 
2,842 
1,592 
145% 

2.36 
2.11 

1,035
417
206
1,658

3,548
69
110
3,727
2,279
195%

2.55
2.25

30,617 
25,820 

38,682
31,642

NET CONVENTIONAL CRUDE OIL, NGL AND 
NATURAL GAS RESERVES (AFTER ROYALTIES) (2) (3)

Crude oil & 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 (%) (6)
Cost to develop ($/boe) (7)
  10% discount 
  15% discount 
Present value of conventional reserves ($ millions) (1)
  10% discount 
  15% discount 

OIL SANDS MINING RESERVES (2) (8) (9)

Bitumen (mmbbl) 
Synthetic crude oil (mmbbl)  

December 31, 2004

Proved 

Proved 
Developed (4)  Undeveloped (4) 

Proved 
Total (4) 

Proved and
Probable (5)

367 
218 
20 
605 

2,213 
12 
5 
2,230 
976 

0.85 
0.73 

13,739 
11,838 

281 
85 
95 
461 

378 
15 
67 
460 
538 

3.58 
3.27 

4,399 
3,440 

648 
303 
115 
1,066 

2,591 
27 
72 
2,690 
1,514 
220% 

1.77 
1.58 

926
415
196
1,537

3,319
57
90
3,466
2,115
281%

1.78
1.56

18,138 
15,279 

22,937
18,802

December 31, 2005

Gross Reserves 

Net Reserves

Proved 
Total 

2,235 
1,833 

Proved and  
Probable 

3,430 
2,878 

Proved 
Total 

1,848 
1,626 

Proved and
Probable

2,848
2,566

The Assets: Year-End Reserves

41

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
North
America

North
Sea

Offshore
West Africa

588 
17 
24 
1 
36 
– 
(66) 
48 
648 
98 
3 
– 
– 
(3) 
(70) 
18 
694 

857 
20 
29 
2 
49 
– 
(66) 
35 
926 
200 
3 
– 
– 
(4) 
(70) 
(20) 
1,035 

222 
– 
35 
10 
38 
– 
(24) 
22 
303 
– 
3 
– 
– 
– 
(25) 
9 
290 

317 
– 
49 
10 
49 
– 
(24) 
14 
415 
– 
5 
– 
– 
– 
(25) 
22 
417 

85 
– 
– 
– 
– 
– 
(4) 
34 
115 
– 
2 
– 
15 
– 
(8) 
10 
134 

133 
– 
– 
– 
– 
– 
(4) 
67 
196 
– 
6 
– 
17 
– 
(8) 
(5) 
206 

Total

895
17
59
11
74
–
(94)
104
1,066
98
8
–
15
(3)
(103)
37
1,118

1,307
20
78
12
98
–
(94)
116
1,537
200
14
–
17
(4)
(103)
(3)
1,658

NET CONVENTIONAL CRUDE OIL AND NGL
RESERVES RECONCILIATION (AFTER ROYALTIES) (2) (3)

Proved reserves (mmbbl)

Reserves, December 31, 2003
Extensions & discoveries
Infill drilling 
Improved recovery 
Property purchases 
Property disposals 
Production
Revisions of prior estimates
Reserves, December 31, 2004
Extensions & discoveries
Infill drilling 
Improved recovery 
Property purchases 
Property disposals 
Production
Revisions of prior estimates
Reserves, December 31, 2005

Proved and probable reserves (mmbbl)
Reserves, December 31, 2003
Extensions & discoveries
Infill drilling 
Improved recovery 
Property purchases 
Property disposals 
Production
Revisions of prior estimates
Reserves, December 31, 2004
Extensions & discoveries
Infill drilling 
Improved recovery 
Property purchases 
Property disposals 
Production
Revisions of prior estimates
Reserves, December 31, 2005

42

The Assets: Year-End Reserves

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET CONVENTIONAL NATURAL GAS
RESERVES RECONCILIATION (AFTER ROYALTIES) (2) (3)

Proved reserves (bcf)

Reserves, December 31, 2003
Extensions & discoveries
Infill drilling 
Improved recovery 
Property purchases 
Property disposals 
Production
Revisions of prior estimates
Reserves, December 31, 2004
Extensions & discoveries
Infill drilling 
Improved recovery 
Property purchases 
Property disposals 
Production
Revisions of prior estimates
Reserves, December 31, 2005

Proved and probable reserves (bcf)
Reserves, December 31, 2003
Extensions & discoveries
Infill drilling 
Improved recovery 
Property purchases 
Property disposals 
Production
Revisions of prior estimates
Reserves, December 31, 2004
Extensions & discoveries
Infill drilling 
Improved recovery 
Property purchases 
Property disposals 
Production
Revisions of prior estimates
Reserves, December 31, 2005

North
America

North
Sea

Offshore
West Africa

2,426 
334 
74 
6 
182 
(8) 
(383) 
(40) 
2,591 
506 
22 
8 
6 
(23) 
(411) 
42 
2,741 

2,919 
418 
106 
6 
236 
(10) 
(383) 
27 
3,319 
645 
23 
14 
8 
(30) 
(411) 
(20) 
3,548 

62 
– 
– 
– 
10 
– 
(18) 
(27) 
27 
– 
– 
– 
– 
– 
(7) 
9 
29 

102 
– 
– 
– 
18 
– 
(18) 
(45) 
57 
– 
– 
– 
– 
– 
(7) 
19 
69 

64 
– 
– 
– 
– 
– 
(3) 
11 
72 
– 
– 
– 
– 
– 
(1) 
1 
72 

72 
– 
– 
– 
– 
– 
(3) 
21 
90 
– 
1 
– 
– 
– 
(1) 
20 
110 

Total

2,552
334
74
6
192
(8)
(404)
(56)
2,690
506
22
8
6
(23)
(419)
52
2,842

3,093
418
106
6
254
(10)
(404)
3
3,466
645
24
14
8
(30)
(419)
19
3,727

The Assets: Year-End Reserves

43

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET CONVENTIONAL FINDING AND ONSTREAM COSTS (AFTER ROYALTIES) (2) (3)

Reserve replacement expenditures ($ millions)
Reserve additions (mmboe) (10)
  Proved  
  Proved and probable 
Finding and onstream costs per boe (11)
  Proved  
  Proved and probable 

2005

3,361 

251 
337 

13.41 
9.97 

2004

4,259 

354 
453 

12.03 
9.40 

2003

2,283 

185 
441 

12.34 
5.18 

Three Year
 Total

9,903

790
1,231

12.55
8.05

NET CONVENTIONAL RESERVES CLASSIFICATION BY PRODUCT (AFTER ROYALTIES) (2) (3)

December 31, 2005

Proved 

Proved 
Developed (4)  Undeveloped (4) 

Proved 
Total (4) 

Proved and
Probable (5)

Light crude oil and NGLs
   North America 
   North Sea 
   Offshore West Africa 
Total   
Heavy crude oil 
   North America - Primary Heavy 
   North America - Pelican Lake 
   North America - Thermal 
Total   
Total crude oil & NGLs 
   North America 
   North Sea 
   Offshore West Africa 
Total   
Natural gas 
   North America 
   North Sea 
   Offshore West Africa 
Total   
Total boe    

6% 
13% 
5% 
24% 

6% 
3% 
10% 
19% 

25% 
13% 
5% 
43% 

24% 
– 
– 
24% 
67% 

1% 
5% 
3% 
9% 

1% 
2% 
15% 
18% 

19% 
5% 
3% 
27% 

5% 
– 
1% 
6% 
33% 

7% 
18% 
8% 
33% 

7% 
5% 
25% 
37% 

44% 
18% 
8% 
70% 

29% 
– 
1% 
30% 
100% 

6%
18%
9%
33%

6%
5%
29%
40%

46%
18%
9%
73%

26%
–
1%
27%
100%

(1) 

 Net present values of conventional reserves are based upon discounted cash flows prior to the consideration of income taxes and existing asset abandonment liabilities. Only future 
development costs and associated material well abandonment liabilities have been applied with the exception of Offshore West Africa where all abandonment liabilities have been included.

(2)  Net reserves mean the Company’s working interest share of gross reserves after consideration of royalties.
(3)  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 & NGLs  

December 31, 2005 
December 31, 2004 
December 31, 2003 

Natural gas 

December 31, 2005 
December 31, 2004 
December 31, 2003 

Company Average 
Price (C$/bbl) 

WTI @ Cushing 
Oklahoma (US$/bbl) 

Hardisty Heavy 
12º API (C$/bbl) 

North Sea
Brent (US$/bbl)

46.12 
32.14 
32.02 

Company Average 
Price (C$/mcf)

9.45 
6.44 
6.63 

61.04 
44.04 
32.56 

Henry Hub 
Louisiana 
(US$/mmbtu)

10.08 
6.62 
5.80 

32.64 
17.45 
26.16 

58.21
40.47
30.14

Alberta AECO C 
(C$/mmbtu) 

British Columbia
Huntingdon
Sumas (C$/mmbtu)

9.99 
6.78 
6.88 

9.53
6.94
6.94

(4) 

(5) 

 A foreign exchange rate of US$0.86/C$1.00 was used in the 2005 evaluation. A foreign exchange rate of US$0.83/C$1.00 was used in the 2004 evaluation. A foreign exchange rate of 
US$0.77/$C1.00 was used in the 2003 evaluation.
 Proved reserve estimates and values were evaluated in accordance with the Securities and Exchange Commission (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.
 Proved and probable reserve estimates and values were evaluated in accordance with the standards of the Canadian Oil and Gas Evaluation Handbook (“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.

(6)  Reserve replacement ratios were calculated using annual net reserve additions comprised of all change categories divided by the net production for that year.
(7)  Cost to develop represents total future capital for each reserves category excluding abandonment capital divided by the reserves associated with that category.
(8)  Synthetic crude oil reserves are based on upgrading of the bitumen reserves. The reserve values shown for bitumen and synthetic crude oil are not additive.
(9)  Gross reserves mean the total remaining recoverable reserves before consideration of royalties.
(10)  Reserves additions are comprised of all categories of reserves changes, exclusive of production.
(11)   Reserves finding and onstream costs are determined by dividing total capital costs for each year excluding cost associated with head office, abandonments, midstream and the Horizon Project 

by net reserves additions for that year.

44

The Assets: Year-End Reserves

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Management’s Discussion & Analysis

SPECIAL NOTE REGARDING FORWARD-
LOOKING STATEMENTS
Certain statements in this document or documents incorporated 
herein  by  reference  for  Canadian  Natural  Resources  Limited 
(the “Company”) may constitute “forward-looking statements” 
within  the  meaning  of  the  United  States  Private  Securities 
Litigation Reform Act of 1995. These forward-looking statements 
can generally be identiﬁed as such because of the context of the 
statements  including  words  such  as  “believes”,  “anticipates”, 
“expects”, “plans”, “estimates”, or words of a similar nature.

The forward-looking statements are based on current expectations 
and are subject to known and unknown risks, uncertainties and 
other  factors  that  may  cause  the  actual  results,  performance  or 
achievements of the Company, or industry results, to be materially 
different  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; foreign currency 
exchange rates; economic conditions in the countries and regions 
in  which  the  Company  conducts  business;  political  uncertainty, 
including actions of or against terrorists or 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 availability and cost of seismic, drilling and other equipment; 
ability of the Company to complete its capital programs; ability 
of  the  Company  to  transport  its  products  to  market;  potential 
delays  or  changes  in  plans  with  respect  to  exploration  or 
development  projects  or  capital  expenditures;  the  ability  of  the 
Company  to  attract  the  necessary  labour  required  to  build  its 
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;  success  of  exploration 
and  development  activities;  timing  and  success  of  integrating 
the  business  and  operations  of  acquired  companies;  production 
levels; uncertainty of reserve estimates; actions by governmental 
authorities; government regulations and the expenditures required 
to comply with them (especially safety and environmental laws and 
regulations); asset retirement obligations; and other circumstances 
affecting revenues and expenses. The impact of any one factor on 
a particular forward-looking statement is not determinable with 
certainty as such factors are interdependent, and the Company’s 
course of action would depend upon its assessment of the future 
considering all information then available.

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.

Readers are cautioned that the foregoing list of important factors 
is  not  exhaustive.  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  were  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 
the Company’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 cash ﬂow from operations, adjusted net earnings 
from  operations,  and  EBITDA  (net  earnings  before  interest, 
taxes, depreciation, depletion and amortization, asset retirement 
obligation  accretion,  unrealized  foreign  exchange,  stock-based 
compensation expense and unrealized risk management activities). 
These  ﬁnancial  measures  are  not  deﬁned  by  generally  accepted 
accounting  principles  (“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.

MANAGEMENT’S DISCUSSION AND ANALYSIS
Management’s  discussion  and  analysis  (“MD&A”)  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, 2005. The consolidated ﬁnancial statements 
have  been  prepared  in  accordance  with  Canadian  GAAP.  A 
reconciliation  of  Canadian  GAAP  to  United  States  GAAP  is 
included  in  note  15  to  the  consolidated  ﬁnancial  statements. 
All  dollar  amounts  are  referenced  in  Canadian  dollars,  except 
where otherwise noted. Common share data has been restated to 
reﬂect the two-for-one share split in May 2005. 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  well  head.  Production  volumes  are  the 
Company’s interest before royalties, and realized prices exclude 
the  effect  of  risk  management  activities,  except  where  noted 
otherwise. The following discussion and analysis refers primarily 
to the Company’s 2005 ﬁnancial results compared to 2004 and 
2003,  unless  otherwise  indicated.  In  addition,  this  discussion 
details  the  Company’s  capital  program  and  outlook  for  2006. 
This MD&A is dated February 21, 2006.

Management’s Discussion & Analysis

45

ABBREVIATIONS

Alberta natural gas reference location
Annual Information Form
barrel
barrels per day
billion cubic feet
billion cubic feet per day
barrels of oil equivalent
barrels of oil equivalent per day
Canadian dollars
Floating Production, Storage and Offtake Vessel
Greenhouse Gas

AECO
AIF
bbl
bbl/d
bcf
bcf/d
boe
boe/d
C$
FPSO 
GHG 
Horizon Project Horizon Oil Sands Project
mbbl
mbbl/d
mboe
mboe/d
mcf
mcf/d
mmbbl
mmboe
mmbtu
mmcf/d
NGLs
NYMEX
NYSE 
SCO 
SEC 
TSX
UK 
US
US$
WCS
WTI 

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
Synthetic light crude oil
Securities and Exchange Commission
Toronto Stock Exchange
United Kingdom
United States
United States dollars
Western Canadian Select crude oil blend
West Texas Intermediate

OBJECTIVE AND STRATEGY
The  Company’s  objective  is  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 acquisition of new reserves. The Company accomplishes this 
objective by having a deﬁned growth and a 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 wealth. The Company effectively 
allocates its capital by maintaining:

•   Balance among its products, namely natural gas, light crude 
oil, Pelican Lake crude oil  (2), primary heavy crude oil and 
thermal heavy crude oil;

•   Balance among near-, mid- and long-term projects;
•   Balance  among  acquisitions,  exploitation  and  exploration; 

Operational discipline and cost control is central to the Company’s 
strategy. By controlling costs consistently throughout all cycles of 
the industry, the Company believes that it will achieve continued 
growth. Cost control is attained by developing area knowledge, 
by  core  area  domination  and  by  maintaining  a  high  working 
interest in its properties.

The  Company  is  committed  to  maintaining  its  strong  ﬁnancial 
position  throughout  construction  of  the  Horizon  Oil  Sands 
Project  (“Horizon  Project”).  The  Company  believes  that  it  has 
built  the  necessary  ﬁnancial  capacity  to  complete  the  Horizon 
Project while at the same time not compromising delivery from 
its conventional crude oil and natural gas growth opportunities. 
Additionally,  the  Company’s  risk  management  hedge  program 
has been expanded to reduce the risk of volatility in commodity 
price  markets  and  to  support  the  Company’s  cash  ﬂow  for  its 
capital expenditures program throughout the construction period 
of the Horizon Project.

Strategic  accretive  acquisitions  are  a  key  component  of  the 
Company’s  strategy.  The  Company  has  used  a  combination  of 
internally  generated  cash  ﬂows  and  debt  to  selectively  acquire 
properties generating future cash ﬂows in its core regions. These 
targeted acquisitions provide relatively quick repayment of initial 
investments and should provide additional free cash ﬂow during 
the construction years of the Horizon Project while still achieving 
targeted returns.

The year ended December 31, 2005, was another successful year in 
the execution of the Company’s strategy. Highlights are as follows:

•   Maintained strong levels of net earnings;
•   Achieved  record  levels  of  adjusted  net  earnings  from 

operations;

•   Achieved record levels of cash ﬂow;
•   Completed the disposition of a large portion of its overriding 
royalty  interests,  which  were  considered  non-core  to  the 
Company’s  operations,  for  proceeds  of  approximately
$345 million;

•   Completed  the  subdivision  of  its  common  shares  on  the 

basis of two for one;

•   Increased  the  quarterly  dividend  by  20%  to  $0.06  per 

and,

common share;

•   Balance between sources of debt and by maintaining a strong 

balance sheet.

(1) Discounted value of conventional crude oil and natural gas reserves and undeveloped land, 

less net debt.

(2) Pelican Lake crude oil is 14-17º API oil, but receives medium quality crude netbacks due to 

low operating costs and low royalty rates.

The Company’s three-phase crude oil marketing strategy includes: 

•   Blending various crude oil streams with diluents into more 

attractive feedstock;

•   Supporting and participating in pipeline expansion or new 

additions; and

•   Supporting  and  participating  in  projects  that  will  increase 

the conversion capacity of heavy crude oil.

•   Purchased  850,000  common  shares  for  a  total  cost  of
$45 million under the Company’s Normal Course Issuer Bid;
•   Achieved  record  levels  of  natural  gas  and  crude  oil  and 

NGLs production; 

•   Achieved its annual production guidance for crude oil and 

NGLs, and natural gas;

•   Completed  the  development  of  the  57.61%  owned  and 
operated  Baobab  Field  offshore  Côte  d’lvoire  West  Africa, 
which  commenced  production  on  August  9,  2005  at 
approximately 30,000 bbl/d net to the Company;

•   Completed  the  acquisition  of  the  permit  to  develop  the 
Olowi Field, offshore Gabon, West Africa with development 
plans to proceed in 2006;

•   Received  Board  of  Directors’  approval  of  the  Horizon 

Project and completed 19% of Phase 1 construction;

46

Management’s Discussion & Analysis

  •   Signed a key pipeline transportation agreement, which will allow Horizon Project Synthetic Crude Oil (“SCO”) to reach the 

pipeline hub at Edmonton, Alberta;

  •   Completed all major 2005 milestones on the Horizon Project, before winter’ onset;
  •   Commenced  steam  injection  at  Primrose  North.  First  oil  production  began  in  January  2006  and  is  expected  to  increase  to

30,000 bbl/d by the third quarter of 2006;

  •   Drilled a record 1,634 net wells, excluding stratigraphic test/service wells; and
  •   Announced a strategy to review the building of a 100% owned and operated upgrader (“Canadian Natural Upgrader”) for the 

Company’s in-situ oil sands assets in the Cold Lake to Athabasca region.

NET EARNINGS AND CASH FLOW FROM OPERATIONS
Financial highlights ($ millions, except per common share amounts) 

Revenue, before royalties 
Net earnings 
Per common share
  – basic (1) 
  – diluted (1)  
Adjusted net earnings from operations (2)
Per common share
  – basic (1) 
  – diluted (1)  
Cash flow from operations (3)
Per common share
  – basic (1) 
  – diluted (1)  
Dividends declared per common share 
Total assets 
Total long-term liabilities 
Capital expenditures, net of dispositions  

$ 
$ 

$ 
$ 
$ 

$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 
$ 

2005

10,107 
1,050 

1.96 
1.95 
2,034 

3.79 
3.78 
5,021 

9.36 
9.33 
0.236 
21,852 
9,790 
4,932 

2004

7,547 
1,405 

2.62 
2.60  
1,405 

2.62 
2.60 
3,769 

7.03 
6.98  
0.200 
18,372 
9,196 
4,633  

$ 
$ 

$ 
$ 
$ 

$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 
$ 

2003

6,155
1,403

2.62
2.53
987

1.84
1.80
3,160

5.88
5.76
0.150
14,643
7,277
2,506

$ 
$ 

$ 
$ 
$ 

$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 
$ 

(1) Restated to reflect two-for-one share split in May 2005.
(2)  Adjusted net earnings from operations is a non-GAAP term 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 following reconciliation 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.

($ millions)  

Net earnings as reported 
Stock-based compensation, net of tax (a)
Unrealized risk management loss (gain), net of tax (b)
Unrealized foreign exchange gain, net of tax (c)
Effect of statutory tax rate changes on future income tax liabilities (d)
Adjusted net earnings from operations 

$ 

$ 

2005

1,050 
481 
607 
(85) 
(19) 
2,034 

$ 

$ 

2004  

1,405 
168 
(27) 
(75) 
(66) 
1,405 

$ 

$ 

2003

1,403
136
–
(274)
(278)
987

(a)  The Company’s employee stock option plan provides for a cash payment option. Accordingly, the intrinsic value of the outstanding vested options is recorded as a liability on the 

Company’s balance sheet and periodic changes in the intrinsic value, net of taxes, flow through net earnings.

(b)  Effective January 1, 2004, the Company adopted a new accounting standard whereby financial instruments not designated as hedges are recorded at fair value on its balance sheet, with 
changes in fair value, net of taxes, flowing through 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.

(c)  Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates and are immediately recognized in 

net earnings.

(d)  All substantively enacted adjustments in applicable income tax rates are applied to underlying assets and liabilities on the Company’s balance sheet in determining future income tax assets 
and liabilities. The impact of these tax rate changes is recorded in net earnings during the period the legislation is substantively enacted. In 2005, the province of British Columbia enacted 
legislation to reduce its corporate income tax rate by 1.5%. During 2004, the province of Alberta enacted legislation to reduce its corporate income tax rate by 1%. During 2003 the 
province of Alberta enacted legislation to reduce its corporate income tax rate by 0.5%. Also during 2003, the Canadian federal government enacted legislation to change the taxation of 
resource income. The federal legislation reduces the corporate income tax rate on resource income from 28% to 21% over five years beginning January 1, 2003. Over the same period the 
deduction for resource allowance is being phased out and a deduction of actual crown royalties paid is being phased in. The Company’s future income tax liability was reduced by $31 
million with respect to the Alberta corporate income tax rate reduction and by $247 million with respect to the federal resource income tax rate changes.

(3)  Cash flow from operations is a non-GAAP term that represents net earnings adjusted for non-cash items. 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. Cash flow from operations may not be comparable to similar measures presented by other companies.

($ millions)

Net earnings   
Non-cash items:
  Depletion, depreciation and amortization  
  Asset retirement obligation accretion  

Stock-based compensation  

  Unrealized risk management activities  
  Unrealized foreign exchange gain  
  Deferred petroleum revenue tax recovery  

Future income tax  

Cash flow from operations  

$ 

$ 

2005

1,050 

2,013 
69 
723 
925 
(103) 
(9) 
353 
5,021 

$ 

$ 

2004  

1,405 

1,769 
51 
249 
(40) 
(94) 
(45) 
474 
3,769 

$ 

$ 

2003

1,403

1,509
62
200
–
(343)
(9)
338
3,160

Management’s Discussion & Analysis

47

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The Company achieved record levels of cash ﬂ ow from operations and production in 2005 as a result of strong operational performance 
combined with increased commodity prices. The strong operating results are attributable to the Company following its deﬁ ned growth 
strategy and to the strong asset base the Company has developed over time through organic growth and accretive acquisitions. 

For the year ended December 31, 2005, the Company recorded net earnings of $1,050 million compared to net earnings of $1,405 million
for  the  year  ended  December  31,  2004  (2003  –  $1,403  million).  Net  earnings  for  2005  include  unrealized  after-tax  expenses  of
$984 million related to the Company’s risk management activities and stock-based compensation plans, net of foreign exchange gains 
and the effect of statutory tax rate changes ($nil for 2004; 2003 –unrealized after-tax income of $416 million). Excluding the effects of 
these items, adjusted net earnings from operations increased 45% to $2,034 million from $1,405 million in 2004 (2003 – $987 million)
due to continuing strong crude oil and natural gas prices as well as record levels of total sales on a boe basis, offset by realized risk 
management activities and the impact of a strengthening Canadian dollar.

Cash ﬂ ow from operations reached record levels in 2005. Cash ﬂ ow from operations increased 33% to $5,021 million ($9.36 per 
common share), up from $3,769 million ($7.03 per common share) in 2004 (2003 – $3,160 million or $5.88 per common share). The 
increase in cash ﬂ ow from operations was due mainly to strong commodity prices and record levels of total sales volume on a boe 
basis, offset by realized risk management activities and the impact of a strengthening Canadian dollar. In 2005, the Company’s average 
sales price per bbl of crude oil and NGLs increased 23% to $46.86 per bbl from $37.99 per bbl in 2004 (2003 – $32.66 per bbl).
The Company’s average natural gas price increased 32% to $8.57 per mcf from $6.50 per mcf in 2004 (2003 – $6.21 per mcf).

Production volumes before royalties increased 8% to a record 552,960 boe/d, up from 513,835 boe/d in 2004 (2003 – 458,814 boe/d).
The increase in production was due to organic growth from the Company’s extensive North America capital expenditure program and 
the commencement of production from the Baobob Field offshore Côte d’lvoire, as well as the full year impact of accretive acquisitions 
completed  in  2004.  Production  of  crude  oil  and  NGLs  before  royalties  increased  11%  to  313,168  bbl/d,  up  from  282,489  bbl/d
in 2004 (2003 – 242,392 bbl/d). Natural gas production before royalties increased 4% to 1,439 mmcf/d, up from 1,388 mmcf/d in 
2004 (2003 – 1,299 mmcf/d).

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    
Barrel of oil equivalent ($/boe) (1)
Sales price (2) 
Royalties   
Production expense  
Netback    

2005

2004

46.86 
3.97 
11.17 
31.72 

8.57 
1.75 
0.73 
6.09 

48.77 
6.82 
8.21 
33.74 

$ 

$ 

$  

$ 

$ 

$ 

37.99  
3.16 
10.05 
24.78 

6.50 
1.35 
0.67 
4.48 

38.45  
5.37 
7.35 
25.73 

$ 

$ 

$ 

$ 

$ 

$ 

(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Including transportation costs and excluding risk management activities.

SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company’s quarterly results for the most recently completed quarters:
($ millions, except per common share amounts)

2005

Revenue, before royalties 
Net earnings (loss) 
Net earnings (loss) per common share 
  – basic (1) 
  – diluted (1) 

2004

Revenue, before royalties 
Net earnings 
Net earnings per common share 
  – basic (1) 
  – diluted (1) 

(1) Restated to reflect two-for-one share split in May 2005.

48

Management’s Discussion & Analysis

Total 

10,107 
1,050 

1.96 
1.95 

Total 

7,547 
1,405 

2.62 
2.60 

$ 
$ 

$ 
$ 

$ 
$ 

$ 
$ 

Dec 31 

3,032 
1,104 

2.06 
2.06 

Dec 31 

1,969 
577 

1.07 
1.06 

$ 
$ 

$ 
$ 

$ 
$ 

$ 
$ 

Sep 30 

2,918 
151 

0.28 
0.28 

Sep 30 

2,075 
311 

0.58 
0.57 

$ 
$ 

$ 
$ 

$ 
$ 

$ 
$ 

Jun 30 

2,164 
219 

0.41 
0.41 

Jun 30 

1,865 
259 

0.48 
0.48 

$ 
$ 

$ 
$ 

$ 
$ 

$ 
$ 

2003

32.66
2.77
10.28
19.61

6.21
1.32
0.60
4.29

34.84
5.20
7.15
22.49

Mar 31

1,993
(424)

(0.79)
(0.79)

Mar 31

1,638
258

0.49
0.48

$ 

$ 

$ 

$ 

$ 

$ 

$ 
$ 

$ 
$ 

$ 
$ 

$ 
$ 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Quarterly revenues have steadily increased throughout 2004 and 2005. This trend reﬂ ects increasing world benchmark crude oil and 
natural gas prices and increasing sales volumes. 

  •   Prices continued to reﬂ ect world-wide economic growth and persistent geopolitical uncertainty, further exacerbated by hurricane 
activity in the Gulf of Mexico during the third quarters of 2004 and 2005. As a result, the Company’s realized crude oil and 
NGLs price increased from C$34.21 per bbl for the ﬁ rst quarter of 2004 to C$46.38 per bbl for the fourth quarter of 2005. The 
realized natural gas price increased from C$6.31 per mcf to C$11.67 per mcf for the same periods. A strengthening Canadian 
dollar relative to the US dollar offset the impact of increasing commodity prices. The US / Canadian dollar average exchange rate 
increased from 0.76 for the ﬁ rst quarter of 2004 to 0.84 for the fourth quarter of 2005.

  •   Strong sales volumes in 2005 versus 2004 were also fundamental to the steady increase in revenue, driven by North America’s 
extensive capital program, the commencement of production from the Baobab Field offshore Côte d’lvoire in 2005, as well as the 
full year impact of accretive acquisitions completed late in 2004. Daily production increased from 476,944 boe/d day in the ﬁ rst 
quarter of 2004 to 577,505 boe/d for the fourth quarter of 2005.

  •   The Company acquired certain heavy crude oil properties in its Northern Plains core region in the ﬁ rst quarter of 2004.
  •   The Company completed the acquisition of certain resource properties located in Northeast British Columbia and Northwest 

Alberta in the second quarter of 2004. These properties include further ownership in the Ladyfern natural gas ﬁ eld.

  •   The Company acquired certain light crude oil producing properties in the Central North Sea in the third quarter of 2004. The 
acquired properties comprise operated interests in T-Block (Tiffany, Toni and Thelma Fields) and B-Block (Balmoral, Stirling and 
Glamis Fields).

  •   The Company completed the acquisition of certain resource properties located in Alberta, British Columbia and Saskatchewan 

in the fourth quarter of 2004.

In addition to commodity prices, sales volumes and acquisitions, net earnings continued to be impacted by:

  •   The impact of the mark-to-market (“MTM”) treatment of the Company’s commodity price contracts as part of its commodity 
hedging  program.  Steadily  increasing  commodity  prices  have  resulted  in  signiﬁ cant  realized  and  unrealized  risk  management 
losses as the Company strives to lock in prices and secure cash ﬂ ow for its capital expenditure program. 

  •   The  MTM  treatment  on  its  stock-based  compensation  plan.  The  Company’s  strong  stock  performance  has  resulted  in  the 

recognition of signiﬁ cant stock-based compensation expense. 

  •   Increasing production expense. Higher service costs as a result of increased industry-wide activity in reaction to higher commodity 

prices as well as the impact of higher crude oil prices on fuel related expenses have resulted in increased costs. 

  •   Corporate income tax rates. During the ﬁ rst quarter of 2004, the North America future tax liability was reduced by $66 million 
as a result of a reduction in the Alberta corporate income tax rate from 12.5% to 11.5%. During the third quarter of 2005, the 
province of British Columbia enacted legislation to reduce its corporate income tax rate by 1.5% effective July 1, 2005. As a 
result, the North America future income tax liability was reduced by $19 million.

BUSINESS ENVIRONMENT
(Yearly average)

WTI benchmark price (US$/bbl) (1)  
Dated Brent benchmark price (US$/bbl)
Differential to LLB blend (US$/bbl)  
Differential to LLB blend as a % of WTI 
Condensate benchmark price (US$/bbl)  
NYMEX benchmark price (US$/mmbtu)  
AECO benchmark price (C$/GJ)  
US/Canadian dollar average exchange rate (US$)  

$ 
$ 
$ 

$ 
$ 
$ 

2005

56.61 
54.45 
20.83 
37% 
57.25 
8.56 
8.05 
0.8253 

$ 
$ 
$ 

$ 
$ 
$ 

2004

41.43 
38.28 
13.44 
32% 
41.62 
6.09 
6.43 
0.7683 

$ 
$ 
$ 

$ 
$ 
$ 

2003

31.02
28.83
8.55
28%
31.42
5.44
6.35
0.7135

(1) Refers to West Texas Intermediate crude oil barrel prices at Cushing, Oklahoma.

World light crude oil prices reached all-time highs in 2005, supported by:

  •   Strong demand growth, particularly in China, India and the United States;
  •   Ongoing geopolitical uncertainties in Iran, Nigeria, Iraq and Venezuela;
  •   Production losses in the Gulf of Mexico from hurricanes Katrina and Rita. Many platforms and reﬁ neries are not expected to be 

operational until sometime late in 2006; and

  •   Restricted  crude  oil  reﬁ ning  capacity,  which  increased  reﬁ ners’  demand  for  light  crude  oil  to  maximize  yields  of  gasoline

and distillates.

Management’s Discussion & Analysis

49

 
 
 
 
 
West Texas Intermediate (“WTI”) averaged US$56.61 per bbl for the year ended December 31, 2005, an increase of 37% compared 
to US$41.43 per bbl for the year ended December 31, 2004 (2003 – US$31.02 per bbl).

Higher WTI pricing is not fully reﬂ ected in the Company’s crude oil price realizations. The positive impact of higher WTI prices on the 
Company’s crude oil production continues to be mitigated by wider heavy crude oil differentials, which increased 55% to US$20.83 per bbl
for the year ended December 31, 2005 from US$13.44 per bbl for the year ended December 31, 2004 (2003 – $US8.55 per bbl). 

Heavy crude oil differentials in 2005 continued to be higher than the long-term average primarily due to physical limitations for 
demand  at  reﬁ neries.  Following  hurricanes  Katrina  and  Rita,  reﬁ ners  sought  to  process  lighter  barrels  to  increase  their  yields  of 
gasoline and distillates, which resulted in the further deterioration of heavy crude oil differentials. Plant turnarounds and maintenance 
during the year, additional problems at reﬁ neries and upgraders, the higher cost of diluents, and the stronger Canadian dollar also 
mitigated the effect of higher WTI prices on the Company’s heavy crude oil price realizations. A strengthening in the Canadian dollar 
reduces the Canadian dollar sales price the Company receives for its crude oil production as crude oil prices are based on US dollar 
denominated benchmarks.

North American natural gas prices also climbed in 2005 due to concerns around supply as well as the impact of higher crude oil 
prices. NYMEX natural gas prices increased 41% to average US$8.56 per mmbtu for the year ended December 31, 2005, up from 
US$6.09 per mmbtu for the year ended December 31, 2004 (2003 – $5.44 per mmbtu). AECO natural gas pricing moved directionally 
with NYMEX, increasing 25% to average $8.05 per GJ for the year ended December 31, 2005, up from $6.43 per GJ for the year 
ended December 31, 2004 (2003 – $6.35 per GJ). 

REVENUE, BEFORE ROYALTIES
Analysis of changes in revenue, before royalties

($ millions)

2003 

Volumes 

Changes due to 
Prices 

Other 

2004 

Volumes 

Changes due to
Other 

Prices 

$ 1,953 
  3,068 
  5,021 

$  342 
207 
549 

$  283 
126 
409 

$ 

873 
80 
953 

141 
14 
155 

  2,967 
  3,162 
  6,129 
61 

123 
5 
128 

13 
(1) 
12 

478 
211 
689 
– 

227 
9 
236 

54 
1 
55 

564 
136 
700 
– 

– 
– 
– 

– 
– 
– 

– 
– 
– 

– 
– 
– 
7 

$ 2,578 
  3,401 
  5,979 

  1,223 
94 
  1,317 

208 
14 
222 

  4,009 
  3,509 
  7,518 
68 

$  170 
 208 
378 

$  546 
   1,029 
   1,575 

$ 

31 
(59) 
(28) 

182 
(6) 
176 

383 
143 
526 
– 

382 
(12) 
370 

86 
1 
87 

  1,014 
  1,018 
  2,032 
– 

– 
– 
– 

– 
– 
– 

– 
– 
– 

– 
– 
– 
9 

2005

$  3,294
   4,638
   7,932

  1,636
23
  1,659

476
9
485

  5,406
  4,670
  10,076
77

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  

Midstream  
Intersegment
  eliminations and other (1) 
Total 

(35) 
$ 6,155 

– 
$  689 

– 
$  700 

(4) 
3 

(39) 
$ 7,547 

– 
$  526 

– 
$  2,032 

$ 

(7) 
2 

(46)
$ 10,107

$ 

(1) Eliminates primarily internal transportation and electricity charges.

Revenue rose 34% to $10,107 million in 2005, up from $7,547 million in 2004 (2003 – $6,155 million). Price increases accounted 
for 79% of the 2005 increase (2004 – 51%), while volume increases accounted for the remaining 21% (2004 – 49%). 

In 2005, 21% of the Company’s crude oil and natural gas revenue was generated outside of North America, up from 20% in 2004 
(2003 – 18%). North Sea accounted for 16% of crude oil and natural gas revenue in 2005 and 17% in 2004 (2003 – 16%), and 
Offshore West Africa accounted for 5% of crude oil and natural gas revenue in 2005 and 3% in 2004 (2003 – 2%).

50

Management’s Discussion & Analysis

 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ANALYSIS OF PRODUCT PRICES (1)

Crude oil and NGLs ($/bbl) (2)
North America  
North Sea  
Offshore West Africa    
Company average  
Natural gas ($/mcf) (2)
North America  
North Sea  
Offshore West Africa    
Company average  
Company average ($/boe) (2)
Percentage of revenue (excluding midstream revenue)
Crude oil and NGLs  
Natural gas  

(1) Including transportation costs and excluding risk management activities.
(2) Amounts expressed on a per unit basis are based on sales volumes.

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 

2005

2004  

2003

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 

39.62 
66.57 
59.91 
46.86 

8.65 
3.17 
5.91 
8.57 
48.77 

54% 
46% 

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 

33.16 
51.37 
49.05 
37.99 

6.61 
3.73 
5.25 
6.50 
38.45 

54% 
46% 

29.40
42.00
36.47
32.66

6.34
3.03
4.37
 6.21
34.84

50%
50%

Realized crude oil prices increased 23% to average $46.86 per bbl in 2005, up from $37.99 per bbl in 2004 (2003 – $32.66 per bbl).
This increase was primarily due to higher benchmark world crude oil prices, as well as an increased proportion of crude oil and 
NGLs sales coming from Offshore West Africa, offset by higher heavy crude oil differentials and a stronger Canadian dollar. Higher 
benchmark crude oil prices were primarily driven by increased demand in countries such as China, India and the United States as well 
as concerns around supply, which increased pricing volatility.

The  Company’s  realized  natural  gas  price  increased  32%  to  average  $8.57  per  mcf  in  2005,  up  from  $6.50  per  mcf  in  2004
(2003 – $6.21 per mcf), primarily due to supply concerns and a continued strengthening in benchmark North America gas pricing.

NORTH AMERICA
North  America  realized  crude  oil  prices  increased  19%  to  average  $39.62  per  bbl  in  2005,  up  from  $33.16  per  bbl  in  2004 
(2003 – $29.40 per bbl). The increase in the realized crude oil price in 2005 was mainly due to higher benchmark crude oil prices, 
partially offset by wider heavy crude oil differentials and the strengthening Canadian dollar.

North America 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 
geographic  markets,  and  working  with  reﬁ ners  to  add  incremental  heavy  crude  oil  conversion  capacity.  As  part  of  an  industry 
initiative to develop new blends of Western Canadian crude oils, the Company has access to blending capacity of up to 140,000 
bbl/d. The Company is currently contributing approximately 139,000 bbl/d of heavy crude oil blends to the Western Canadian Select 
(“WCS”) stream, a new blend of up to 10 different crude oil streams. WCS resembles a Bow River type crude with distillation cuts 
approximating a natural heavy crude oil with premium quality asphalt characteristics and has an API of 19°-22°. Volumes of the new 
blend are expected to grow, with the potential to become a new benchmark for North American markets in addition to WTI. The 
Company has committed to 25,000 bbl/d of capacity on the Corsicana Pipeline, which will carry crude oil to the Gulf of Mexico and 
is expected to be in operation late in the ﬁ rst quarter of 2006. The Corsicana Pipeline is made up of a series of segments extending 
from Patoka Illinois to Nederland Texas, near the US Gulf Coast.

North  America  realized  natural  gas  prices  increased  31%  to  average  $8.65  per  mcf  for  the  year  ended  December  31,  2005,  up 
from $6.61 per mcf for the year ended December 31, 2004 (2003 – $6.34 per mcf). This increase was due to supply concerns and 
ﬂ uctuations in the North America benchmark natural gas price in response to crude oil pricing. 

A comparison of the price received for the Company’s North America production is as follows:

Wellhead price (1)(2)
Light 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) 

(1) Including transportation costs and excluding risk management activities.
(2) Amounts expressed on a per unit basis are based on sales volumes.

2005

2004

$ 
$ 
$ 
$ 
$ 

58.41 
38.39 
33.53 
32.29 
8.65 

$ 
$ 
$ 
$ 
$ 

45.90 
32.12 
28.99 
29.00 
6.61 

$ 
$ 
$ 
$ 
$ 

2003

37.59
28.05
26.21
25.56
6.34

Management’s Discussion & Analysis

51

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NORTH SEA
North Sea realized crude oil prices increased 30% to average $66.57 per bbl for the year ended December 31, 2005, up from $51.37 per bbl
for the year ended December 31, 2004 (2003 – $42.00 per bbl). The increase in the realized crude oil price compared to 2004 was 
due mainly to higher world benchmark crude oil prices and a narrowing of the average Brent differential, offset by the strengthening 
Canadian dollar.

OFFSHORE WEST AFRICA
Offshore West Africa realized crude oil prices increased 22% to average $59.91 per bbl for the year ended December 31, 2005, an 
increase from $49.05 per bbl for the year ended December 31, 2004 (2003 – $36.47 per bbl). The increase in realized crude oil prices 
from 2004 was primarily due to higher world benchmark crude oil prices offset by the strengthening Canadian dollar. 

CRUDE OIL INVENTORY VOLUMES
The  Company  recognizes  revenue  on  its  crude  oil  production  when  title  transfers  to  the  customer  and  delivery  has  taken  place, 
referred to as “liftings” in this MD&A. For production where revenue has not yet been recognized, the related crude oil inventory 
volumes, by segment, were as follows at December 31, 2005:

(bbl)

North America, related to Corsicana pipeline line fill 
North Sea, related to timing of liftings 
Offshore West Africa, related to timing of liftings, net of government entitlement to profit oil 

At December 31, 2004, variances between production volumes and liftings were not signiﬁ cant.

ANALYSIS OF DAILY PRODUCTION, BEFORE ROYALTIES

2005

484,157
747,141
412,841
  1,644,139

Crude oil and NGLs (bbl/d)
North America  
North Sea  
Offshore West Africa    

Natural gas (mmcf/d)
North America  
North Sea  
Offshore West Africa    

Total barrel of oil equivalent (boe/d)
Product Mix (%)
Light crude oil and NGLs  
Pelican Lake crude oil   
Primary heavy crude oil  
Thermal heavy crude oil  
Natural gas  

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    

Total barrel of oil equivalent (boe/d)

2005

2004

2003

221,669 
68,593 
22,906 
313,168 

1,416 
19 
4 
1,439 
552,960 

26% 
4% 
17% 
10% 
43% 

206,225 
64,706 
11,558 
282,489  

1,330 
50 
8 
1,388  
513,835 

24% 
4% 
19% 
8% 
45% 

174,895
56,869
10,628
242,392

1,245
46
8
1,299
458,814

25%
5%
15%
8%
47%

2005

2004

2003

191,751 
68,487 
22,293 
282,531 

1,125 
18 
4 
1,147 
473,742 

180,011 
64,598 
11,221 
255,830  

1,048 
50 
7 
1,105  
440,022 

152,444
56,928
10,314
219,686

976
46
8
1,030
391,361

Daily production and per barrel statistics are presented throughout this MD&A on a “before royalty” or “gross” basis. Production 
net of royalties is presented for information purposes only.

52

Management’s Discussion & Analysis

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 crude oil and NGLs, Pelican Lake crude oil, primary heavy crude oil and thermal 
heavy crude oil.

Record  levels  of  total  crude  oil  and  natural  gas  production  averaged  552,960  boe/d  for  the  year  ended  December  31,  2005,  an 
increase of 8% or 39,125 boe/d from 513,835 boe/d for the year ended December 31, 2004 (2003 – 458,814 boe/d). The increase in 
production year over year was due to organic growth from the Company’s extensive North America capital expenditure program and 
the commencement of production from the Baobab Field offshore Côte d’Ivoire in 2005, as well as the full year impact of accretive 
acquisitions completed in 2004.

Total record crude oil and NGLs production for the year ended December 31, 2005 increased 11% to 313,168 bbl/d from 282,489 bbl/d
for  the  year  ended  December  31,  2004  (2003  –  242,392  bbl/d).  Crude  oil  and  NGLs  production  for  2005  was  in  line  with  the 
Company’s guidance of 308,000 to 316,000 bbl/d.

Natural  gas  production  continues  to  represent  the  Company’s  largest  product  offering.  Natural  gas  production  for  the  year 
ended  December  31,  2005  increased  4%  or  51  mmcf/d  to  average  1,439  mmcf/d  compared  to  1,388  mmcf/d  for  the  year  ended
December  31,  2004  (2003  –  1,299  mmcf/d).  Growth  in  natural  gas  production  in  Western  Canada  was  negatively  affected  by 
the  early  arrival  of  spring  breakup  and  weather  related  delays  due  to  unusually  wet  conditions  as  well  as  an  overall  increase  in 
industry activity. The market for the necessary oilﬁeld services and material has become increasingly competitive, resulting in drilling, 
completion, tie-in and maintenance delays. Natural gas production for 2005 was in line with the Company’s guidance of 1,436 to
1,448 mmcf/d.

The Company expects annual production levels in 2006 to average 1,468 to 1,551 mmcf/d of natural gas and 335,000 to 373,000 bbl/d
of crude oil and NGLs. First quarter 2006 production is expected to be between 1,426 and 1,475 mmcf/d of natural gas and 306,000 
to 334,000 bbl/d of crude oil and NGLs.

NORTH AMERICA
North America crude oil and NGLs production for the year ended December 31, 2005 increased 7% or 15,444 bbl/d to average 
221,669 bbl/d, up from 206,225 bbl/d for the year ended December 31, 2004 (2003 – 174,895 bbl/d). The increase in crude oil and 
NGLs production was mainly due to the timing of Primrose production cycles and the positive results of the Pelican Lake waterﬂood 
project.

North America natural gas production for the year ended December 31, 2005 increased 6% or 86 mmcf/d to average 1,416 mmcf/d,
up  from  1,330  mmcf/d  in  2004  (2003  –  1,245  mmcf/d).  Natural  gas  production  increased  as  a  result  of  organic  growth  and  the 
full year impact of accretive property acquisitions in 2004, but was negatively impacted by the early arrival of spring breakup and 
weather related delays due to unusually wet conditions during the summer months. In addition to weather related factors, production 
growth was also negatively impacted by the increased demand for oilﬁeld services and materials, which caused delays in the timing 
of production being brought on stream.

NORTH SEA
North Sea crude oil production for the year ended December 31, 2005 was 68,593 bbl/d, an increase of 6% from 64,706 bbl/d for 
2004 (2003 – 56,869 bbl/d). Production levels were in line with expectations, reﬂecting anticipated curtailments at the Lyell Field 
and the Columba B and E Terraces, continued restrictions at Murchison Field due to third party natural gas export facilities and 
production declines at the satellite Playfair Field.

Natural gas production in the North Sea for the year ended December 31, 2005 decreased 62% to average 19 mmcf/d, down from 
50  mmcf/d  for  the  year  ended  December  31,  2004  (2003  –  46  mmcf/d).  The  decrease  in  natural  gas  production  was  due  to  the 
commencement  of  the  natural  gas  reinjection  program  in  the  Banff  Field  in  the  Central  North  Sea  late  in  2004.  The  natural  gas 
reinjection  project  is  expected  to  result  in  an  overall  increase  in  the  reservoir  recovery,  but  resulted  in  reductions  in  natural  gas 
production in 2005.

OFFSHORE WEST AFRICA
Offshore West Africa crude oil production for the year ended December 31, 2005 increased 98% to 22,906 bbl/d from 11,558 bbl/d
for  the  year  ended  December  31,  2004  (2003  –  10,628  bbl/d).  The  production  increase  was  primarily  due  to  commencement  of 
production from the 57.61% owned and operated Baobab Field in August 2005, as well as increased production from additional 
inﬁll wells drilled in East Espoir. 

Management’s Discussion & Analysis

53

ROYALTIES

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)
Percentage of revenue (2)
Crude oil and NGLs  
Natural gas  
Boe   

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 

2005

2004

2003

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 

5.37 
0.10 
1.62 
3.97 

1.78 
– 
0.16 
1.75 
6.82 

8% 
20% 
14% 

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 

4.21 
0.08 
1.43 
3.16 

1.40 
– 
0.15  
1.35  
5.37  

8%  
21% 
14% 

3.79
(0.03)
1.08
2.77

1.38
–
0.13
1.32
5.20

9%
21%
15%

(1) Amounts expressed on a per unit basis are based on sales volumes.

NORTH AMERICA
North America crude oil and NGLs royalties per bbl for the year ended December 31, 2005 increased from 2004 primarily due to 
higher benchmark crude oil prices, offset by wider heavy crude oil differentials and a strengthening Canadian dollar. Royalty rates are 
expected to increase in the future as a result of the Primrose South Field payout expected to occur late in 2006 or early 2007.

Natural gas royalties increased from 2004 due to higher benchmark natural gas prices, offset by a stronger Canadian dollar and 
adjustments to royalty rates related to prior years. 

NORTH SEA
North Sea government royalties on crude oil were eliminated effective January 1, 2003. The remaining North Sea royalty represents 
a gross overriding royalty on the Ninian Field. In 2003, the Company received a refund of royalties previously provided.

OFFSHORE WEST AFRICA
Offshore West Africa production is governed by the terms of Production Sharing Contracts (“PSCs”). Under the PSCs, revenues are 
divided into cost recovery revenue and proﬁ t revenue. Cost recovery revenue allows the Company to recover its capital and operating 
costs and the costs carried by the Company on behalf of the Government State Oil Company. Proﬁ t revenue is allocated to the joint 
venture partners in accordance with their respective equity interests, after a portion has been allocated to the Government. These 
revenues are reported as sales revenue. The Government’s share of proﬁ t revenue attributable to the Company’s equity interest is 
allocated to royalty expense and current income tax expense in accordance with the PSCs. Based on current projections, the Espoir 
Field  and  the  Baobab  Field  are  expected  to  reach  payout  in  2007,  which  will  increase  royalty  rates  and  current  income  taxes  in 
accordance with the PSCs.

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)

(1) Amounts expressed on a per unit basis are based on sales volumes.

2005

2004  

2003

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 

10.49 
14.94 
6.50 
11.17 

0.71 
2.44 
1.05 
0.73 
8.21 

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 

8.94 
14.03 
7.59 
10.05 

0.62 
2.07 
1.33 
0.67 
7.35 

$ 
$ 
$ 
$ 

$ 
$ 
$ 
$ 
$ 

9.14
14.07
8.68
10.28

0.57
1.33
1.39
0.60
7.15

The  Company  continues  to  experience  increasing  production  expense  in  2006,  reﬂ ecting  industry  cost  pressures  in  all  of  its
operating areas.

54

Management’s Discussion & Analysis

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NORTH AMERICA
North  America  crude  oil  and  NGLs  production  expense  per  bbl  for  the  year  ended  December  31,  2005  increased  by  17%  from 
2004. The increase was primarily due to higher industry wide service costs, higher fuel related expenses, and a larger portion of the 
Company’s crude oil volumes being comprised of higher cost thermal crude oil in 2005 versus 2004, offset by the positive impact of 
higher volumes relative to ﬁ xed costs.

North America natural gas production expense per mcf for the year ended December 31, 2005 increased from the comparable periods 
in 2004. The increase from 2004 was due to the service and commodity cost pressures previously noted, offset by the positive impact 
of higher volumes relative to ﬁ xed costs.

NORTH SEA
North Sea crude oil production expense varied on a per barrel basis from 2004 primarily due to the timing of maintenance work, the 
changes in production volumes on a relatively ﬁ xed cost base, the timing of liftings from various ﬁ elds and the impact of production 
being diverted from the Kyle Field to the Banff ﬂ oating production storage and offtake vessel (“FPSO”).

OFFSHORE WEST AFRICA
Offshore West Africa crude oil production expenses are largely ﬁ xed in nature and ﬂ uctuated on a per barrel basis from 2004 due to 
changes in volumes. Production expenses for the year ended December 31, 2005 compared to 2004 were primarily impacted by the 
commencement of production from the Baobab Field in August 2005.

MIDSTREAM
($ millions) 

Revenue    
Production expense  
Midstream cash flow    
Depreciation  
Segment earnings before taxes  

2005

2004

2003

77  
24 
53 
8 
45 

$ 

$ 

68 
20 
48 
7 
41 

$ 

$ 

61
15
46
7
39

$ 

$ 

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.

Earnings and cash ﬂ ow attributable to midstream assets have increased marginally from 2004 primarily due to increased heavy crude 
oil throughput volumes and increased revenue from the Company’s cogeneration plant.

DEPLETION, DEPRECIATION AND AMORTIZATION(1)
($ millions, except per boe amounts) (2)

North America  
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.

2005

1,595 
306 
104 
2,005 
10.02 

$ 

$ 
$ 

2004  

1,444  
265  
53  
1,762  
9.37  

$ 

$ 
$ 

2003

1,209
252
41
1,502
8.96

$ 

$ 
$ 

Depletion, Depreciation and Amortization (“DD&A”) for the year ended December 31, 2005 increased in total and on a boe basis 
from 2004. The increase in DD&A was due to higher ﬁ nding and development costs associated with natural gas exploration in North 
America, the fair value allocation of the acquisition costs associated with acquisitions completed late in 2004, future abandonment 
costs associated with the acquisition of additional properties in the North Sea, higher estimated future costs to develop the Company’s 
proved undeveloped reserves in the North Sea and the commencement of production from the Baobab Field in August 2005.

ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per boe amounts) (1)

North America  
North Sea  
Offshore West Africa    
Expense    
  $/boe    

(1) Amounts expressed on a per unit basis are based on sales volumes.

2005

34 
34 
1 
69 
0.34 

$ 

$ 
$ 

2004  

28  
22  
1  
51 
0.27 

$ 

$ 
$ 

2003

26
36
–
62
0.37

$ 

$ 
$ 

Management’s Discussion & Analysis

55

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accretion expense is the increase in the carrying amount of the asset retirement obligations due to the passage of time. Asset retirement 
obligation accretion expense for North America increased $6 million or 21% from 2004, primarily due to increased activity in the 
conventional drilling program and increased requirements under provincial reclamation legislation. Accretion expense for the North Sea
increased $12 million or 55% from 2004, largely due to the impact of additional retirement obligations related to property acquisitions 
completed late in 2004.

ADMINISTRATION EXPENSE
($ millions, except per boe amounts) (2)

Net expense 
  $/boe    

(1) Restated to conform to current year presentation.
(2) Amounts expressed on a per unit basis are based on sales volumes.

2005 

151 
0.75 

$ 
$ 

2004(1)

125 
0.66 

$ 
$ 

2003

87
0.52

$ 
$ 

Net  administration  expense  for  the  year  ended  December  31,  2005  increased  in  total  and  on  a  boe  basis  from  the  year  ended 
December 31, 2004 primarily due to higher stafﬁ ng levels associated with the Company’s expanding asset base and costs associated 
with the Company’s Share Bonus Plan.

The Share Bonus Plan incorporates employee share ownership in the Company while reducing the granting of stock options and 
the  dilution  of  current  Shareholders.  Under  the  plan,  cash  bonuses  awarded  based  on  Company  and  employee  performance  are 
subsequently used by a trustee to acquire common shares of the Company. The common shares vest to the employee over a three-year
period provided the employee does not leave the employment of the Company. If the employee leaves the employment of the Company, 
the  unvested  common  shares  are  forfeited  under  the  terms  of  the  plan.  For  the  year  ended  December  31,  2005,  the  Company 
recognized $17 million of compensation expense under the Share Bonus Plan (December 31, 2004 – $10 million; 2003 – $nil).

STOCK-BASED COMPENSATION
($ millions) 

Stock-based compensation expense  

2005

2004

$ 

723 

$ 

249 

$ 

2003

200

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 beneﬁ ts 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  since  changes  in  the  intrinsic  value  of  outstanding  stock  options  are  recognized  each  period.  The  cash  payment  feature 
provides option holders with substantially the same beneﬁ ts and allows them to realize the value of their options through a simpliﬁ ed 
administration process.

The Company recorded a $723 million ($481 million after tax) stock-based compensation expense for the year ended December 31, 2005
in connection with the 125% appreciation in the Company’s share price (December 31, 2005 – C$57.63; December 31, 2004 – C$25.63; 
December 31, 2003 – C$16.34; December 31, 2002 – C$11.70). As required by GAAP, the Company’s outstanding stock options are 
valued 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 quarterly to reﬂ ect changes in the market price of the Company’s 
common shares and the options exercised or surrendered in the period, with the net change recognized in net earnings, or capitalized 
during the construction period in the case of the Horizon Project (2005 – $101 million; 2004 – $21 million; 2003 – $10 million).
The stock-based compensation liability reﬂ ects the Company’s potential cash liability should all the vested options be surrendered 
for a cash payout at the market price on December 31, 2005. In periods when substantial stock price changes occur, the Company is 
subject to signiﬁ cant earnings volatility. 

For  the  year  ended  December  31,  2005,  the  Company  paid  $227  million  for  stock  options  surrendered  for  cash  settlement
(December 31, 2004 – $80 million; 2003 – $31 million).

INTEREST EXPENSE
($ millions, except per boe amounts and interest rates) (1)

Interest expense  
  $/boe    
Average effective interest rate  

(1) Amounts expressed on a per unit basis are based on sales volumes.

56

Management’s Discussion & Analysis

$ 
$ 

2005

149 
0.74 
5.6% 

$ 
$ 

2004

189 
1.01 
5.2% 

$ 
$ 

2003

201
1.20
5.8%

 
 
 
 
Net  interest  expense  decreased  on  a  total  and  boe  basis  for  the  year  ended  December  31,  2005  from  2004  primarily  due  to  the 
capitalization  of  construction  period  interest  related  to  the  Horizon  Project  in  2005  of  $72  million  (2004  and  2003  –  $nil).  Pre-
capitalization interest increased from 2004 mainly due to higher interest rates and carrying charges, offset by decreased average debt 
levels and the impact of the strengthening Canadian dollar, which decreased interest expense attributable to the Company’s US dollar 
denominated debt securities. 

RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative ﬁ nancial instruments to manage its commodity price, currency and interest rate exposures. 
These derivative ﬁ nancial instruments are not used for trading or speculative purposes. Changes in fair value of derivative ﬁ nancial 
instruments designated as hedges are not recognized in net earnings until such time as the corresponding gains or losses on the related 
hedged items are also recognized. Changes in fair value of derivative ﬁ nancial instruments not designated as hedges are recognized in 
the consolidated balance sheets each period with the offset reﬂ ected in risk management activities in the statements of earnings. 

The  Company  formally  documents  all  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.

The Company enters into commodity price contracts to manage anticipated sales of crude oil and natural gas production in order to
protect cash ﬂ ow for capital expenditure programs. Gains or losses on these contracts are included in risk management activities. 

The  Company  enters  into  interest  rate  swap  agreements  to  manage  its  ﬁ xed  to  ﬂ oating  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 amount on 
which the payments are based. Gains or losses on interest rate swap contracts designated as hedges are included in interest expense. 
Gains or losses on non-designated interest rate contracts are included in risk management activities. 

Cross currency swap agreements 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. Gains or losses on cross currency swap contracts designated as hedges are included in interest expense.

Gains or losses on the termination of derivative ﬁ nancial instruments that have been designated as hedges are deferred under other 
assets or liabilities on the consolidated balance sheets and amortized into net earnings in the period in which the underlying hedged 
transaction  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 net earnings. Gains or losses on the 
termination of ﬁ nancial instruments that have not been designated as hedges are recognized in net earnings immediately.

($ millions)

Realized loss (gain)
Crude oil and NGLs financial instruments  
Natural gas financial instruments  
Interest rate swaps  

Unrealized loss (gain)
Crude oil and NGLs financial instruments  
Natural gas financial instruments  
Interest rate swaps  

Total  

2005

2004

2003

$ 

$ 

$ 

$ 
$ 

753 
283 
(9) 
1,027 

847 
77 
1 
925 
1,952 

$ 

$ 

$ 

$ 
$ 

501 
5 
(32) 
474 

(47) 
– 
7 
(40)  
434 

$ 

$ 

$ 

$ 
$ 

95
88
(35)
148

–
–
–
–
148

The realized loss from crude oil and NGLs and natural gas ﬁ nancial instruments decreased 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.

2005

6.68 
0.54 

$ 
$ 

2004

4.85 
0.01 

$ 
$ 

2003

1.07
0.19

$ 
$ 

Management’s Discussion & Analysis

57

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The realized gain on non-designated interest rate swaps would have decreased the Company’s reported interest expense as follows:

($ millions, except interest rates) 

Interest expense as reported 
Less: realized risk management gain  

Average effective interest rate  

$ 

$ 

2005

149 
(9) 
140 
5.2% 

$ 

$ 

2004  

189 
(32) 
157 
4.4% 

$ 

$ 

2003

201
(35)
166
4.8%

As effective as commodity hedges are against reference commodity prices, a substantial portion of the derivative ﬁ nancial instruments 
entered  into  by  the  Company  do  not  meet  the  requirements  for  hedge  accounting  under  GAAP  due  to  currency,  product  quality 
and location differentials (the “non-designated hedges”). The Company is required to mark-to-market these non-designated hedges 
based on prevailing forward commodity prices in effect at the end of each reporting period. Accordingly, unrealized risk management 
expense reﬂ ects, at the balance sheet date, the implied price differentials for the non-designated hedges for future years. Due to the 
dramatic increase in crude oil and natural gas forward pricing in 2005, the Company recorded a $925 million ($607 million after tax) 
unrealized loss on its risk management activities for the year ended December 31, 2005 (2004 – a $40 million gain or $27 million 
after tax; 2003 – $nil).

The  cash  settlement  amount  of  the  risk  management  ﬁ nancial  derivative  instruments  may  vary  materially  depending  upon  the 
underlying crude oil and natural gas prices at the time of ﬁ nal settlement of the ﬁ nancial derivative instruments, as compared to their 
mark-to-market value at December 31, 2005. 

In addition to the risk management liability recognized on the balance sheet at December 31, 2005, the net unrecognized liability related 
to the fair value of derivative ﬁ nancial instruments designated as hedges was $990 million (December 31, 2004 – net unrecognized 
asset of $33 million).

Details  relating  to  outstanding  derivative  ﬁ nancial  instruments  at  December  31,  2005  are  disclosed  in  note  10  to  the  Company’s 
audited annual consolidated ﬁ nancial statements as at December 31, 2005.

FOREIGN EXCHANGE
($ millions) 

Realized foreign exchange (gain) loss  
Unrealized foreign exchange gain  
Total  

2005

(29) 
(103) 
(132) 

$ 

$ 

2004

3 
(94) 
(91) 

$ 

$ 

2003

8
(343)
(335)

$ 

$ 

The Company’s results are affected by 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 lower 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 will result in higher revenue from the sale of the Company’s production. Production 
expenses are also subject to ﬂ uctuations due to changes in the exchange rate of the UK pound sterling to the US dollar related to 
North Sea operations. 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. 

In 2005, the majority of the realized foreign exchange gain was the result of the repayment of the Company’s US dollar preferred 
securities.  In  addition,  net  foreign  exchange  gains  were  realized  on  foreign  exchange  rate  ﬂ uctuations  on  working  capital  items 
denominated in US dollars or UK pounds sterling. The unrealized foreign exchange gain is related to the ﬂ uctuation of the Canadian 
dollar in relation to the US dollar with respect to the US dollar debt and working capital denominated in US dollars or UK pounds 
sterling. The Canadian dollar ended the year at US$0.8577 compared to US$0.8308 at December 31, 2004 (2003 – US$0.7738).

In order to mitigate a portion of the volatility associated with ﬂ uctuations in exchange rates, the Company has designated certain 
US dollar denominated debt as a hedge against its net investment in US dollar based self-sustaining foreign operations. Accordingly, 
translation  gains  and  losses  on  this  US  dollar  denominated  debt  are  included  in  the  foreign  currency  translation  adjustment  in 
Shareholders’ equity in the consolidated balance sheets.

58

Management’s Discussion & Analysis

 
 
 
 
 
 
 
 
 
 
 
 
TAXES
($ millions, except income tax rates) 

Taxes other than income tax
Current    
Deferred    
Total  
Current income tax
North America – Current income tax  
North America – Large Corporations Tax  
North Sea  
Offshore West Africa    
Other  
Total  
Future income tax 
Effective income tax rate 

2005

2004

2003

$ 

$ 

$ 

$ 
$ 

203 
(9) 
194 

82 
16 
155 
32 
1 
286 
353 
37.8% 

$ 

$ 

$ 

$ 
$ 

210 
(45) 
165 

89 
11 
2 
13 
1 
116 
474 
29.6% 

$ 

$ 

$ 

$ 
$ 

116
(9)
107

43
16
23
10
–
92
338
23.5%

Taxes other than income tax includes current and deferred petroleum revenue tax (“PRT”) and Canadian provincial capital taxes and 
surcharges. PRT is charged on certain ﬁ elds in the North Sea at the rate of 50% of net operating income, after allowing for certain 
deductions including abandonment expenditures.

Taxable income from the conventional crude oil and natural gas business in Canada is generated by partnerships, with the related 
income taxes payable in a subsequent year. North America current income taxes have been provided on the basis of the corporate 
structure and available income tax deductions and will vary upon the nature and amount of capital expenditures incurred in Canada.

The North Sea current income tax expense for 2005 increased from 2004 due mainly to higher realized product prices, increased sales 
volumes and the deductibility in 2004 of the cost of assets acquired in the UK. In December 2005, the UK government announced 
plans to double the supplementary charge on proﬁ ts from UK North Sea crude oil and natural gas production to 20%. If enacted, 
the increased North Sea supplementary charge would increase the Company’s income tax rate in the North Sea from 40% to 50%. 
The supplementary charge excludes any deduction for ﬁ nancing costs. A charge has not been reﬂ ected in 2005 net earnings as the 
proposed change has not been substantively enacted. If enacted in 2006, the Company anticipates that this rate change will result in 
a charge to future income taxes in the amount of $111 million. 

During 2005, the province of British Columbia enacted legislation to reduce its corporate income tax rate by 1.5% effective July 1, 2005.
As a result, the North America future income tax liability was reduced by $19 million. In 2004, the North America future tax liability 
was reduced by $66 million as a result of a reduction in the Alberta corporate income tax rate from 12.5% to 11.5%. In 2003, the 
Federal Government enacted legislation to reduce the corporate income tax rate on income from resource activities over a ﬁ ve-year 
period starting January 1, 2003, bringing the resource industry in line with the general corporate income tax rate. As part of the 
corporate income tax rate reduction, the legislation also provides for the phased elimination of the existing 25% resource allowance 
and the introduction of a deduction for actual provincial and other crown royalties paid.

The following table shows the effect of non-recurring beneﬁ ts on income taxes:

($ millions, except income tax rates) 

Income tax as reported 
Current income tax  
Future income tax expense  

Provincial corporate tax rate reductions  
Federal corporate tax rate reductions  
Total  
Expected effective income tax rate before non-recurring benefits  

2005

2004  

2003

$ 

$ 

286 
353 
639 
19 
– 
658 
39.0% 

$ 

$ 

116 
474 
590 
66 
– 
656 
32.9% 

$ 

$ 

92
338
430
31
247
708
38.6%

The effective income tax rate for 2005 increased over 2004 due to the effects of the phased elimination of the resource allowance and 
the phased deductibility of crown royalties. It is anticipated that in 2006, based on budgeted prices and the current availability of tax 
pools, the Company is expected to be cash taxable in Canada in the amount of $110 million to $170 million.

Management’s Discussion & Analysis

59

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CAPITAL EXPENDITURES (1)
($ millions) 

Expenditures on property, plant and equipment
Net property acquisitions (2)
Land acquisition and retention  
Seismic evaluations  
Well drilling, completion and equipping  
Pipeline and production facilities  
Total net reserve replacement expenditures 
Horizon Project:
  Phase 1 construction costs 
  Capitalized interest and other 
Total Horizon Project   
Midstream  
Abandonments (3) 
Head office  
Total net capital expenditures 
By segment
North America  
North Sea  
Offshore West Africa    
Other 
Horizon Project  
Midstream  
Abandonments (3) 
Head office  
Total  

2005

2004

(320) 
254 
132 
2,000 
1,295 
3,361 

1,329 
170 
1,499 
4 
46 
22 
4,932 

2,530 
387 
439 
5 
1,499 
4 
46 
22 
4,932 

$ 

$ 

$ 

$ 

1,835 
120 
89 
1,394 
821 
4,259 

– 
291 
291 
16 
32 
35 
4,633 

3,355 
608 
295 
1 
291 
16 
32 
35 
4,633 

$ 

$ 

$ 

$ 

2003

336
154
77
1,194
522
2,283

–
152
152
11
40
20
2,506

1,769
338
176
–
152
11
40
20
2,506

$ 

$ 

$ 

$ 

(1) The net capital expenditures do not include non-cash property, plant and equipment additions or disposals.
(2) Includes Business Combinations. The 2004 comparative figure includes $26 million in non-cash consideration.
(3) Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table.

The Company’s strategy is focused on building a diversiﬁ ed asset base that is balanced among various products. In order to facilitate 
efﬁ cient operations, the Company focuses 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 the year ended December 31, 2005 were $4,932 million compared to $4,633 million for the year ended 
December 31, 2004 (2003 – $2,506 million). During 2005, the Company continued to make signiﬁ cant progress on its larger, future-
growth projects, most notably the Horizon Project, while maintaining its focus on existing assets. The Company drilled a total of 
1,882 net wells in 2005 consisting of 890 natural gas wells, 627 crude oil wells, 248 stratigraphic test and service wells, and 117 wells 
that were dry. This compared to 1,449 net wells drilled in 2004 (2003 – 1,793 net wells). The Company achieved an overall success 
rate of 93%, excluding stratigraphic test and service wells (2004 and 2003 – 91%).

NORTH AMERICA
North America accounted for approximately 83% of the total capital expenditures for the year ended December 31, 2005 compared 
to approximately 80% in 2004 (2003 – 79%).

During 2005, the Company drilled 975 net wells targeting natural gas, including 228 wells in Northeast British Columbia, 238 wells 
in the Northern Plains region, 166 wells in Northwest Alberta, and 343 wells in the Southern Plains region. The Company also drilled 
642 net wells targeting crude oil during 2005. The majority of these wells were concentrated in the Company’s crude oil Northern 
Plains region where 360 heavy crude oil wells, 84 Pelican Lake crude oil wells, 109 thermal crude oil wells, and 7 light crude oil wells 
were drilled. Another 82 light crude oil wells were drilled during the year in the Company’s other regions.

As part of the development of the Company’s heavy crude oil resources, the Company is continuing with its Primrose thermal projects, 
which includes the Primrose North expansion project and drilling additional wells in the Primrose South project to augment existing 
production. The Primrose North expansion was substantially completed in 2005 with total capital expenditures of approximately 
$300 million incurred. Initial steaming commenced in November 2005 and ﬁ rst crude oil production began in January 2006.

60

Management’s Discussion & Analysis

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
In 2004, the Company ﬁled a public disclosure document for regulatory approval of its Primrose East project, a new facility located 
about 15 kilometers from its existing Primrose South steam plant and 25 kilometers from its Wolf Lake central processing facility. The 
development application was submitted to the Alberta Energy and Utilities Board in January 2006, with potential impacts associated 
with the use of bitumen as fuel being evaluated in the Environmental Impact Assessment. The Company expects construction to begin 
in 2007, with initial steaming scheduled for January 2009.

Development at Pelican Lake continued on track in 2005, with 84 wells being drilled and production increasing from approximately 
18,000  bbl/d  to  approximately  28,000  bbl/d  over  the  course  of  the  year.  The  waterﬂood  conversion  project  is  on  schedule  with 
production response exceeding expectations. The Company plans to enhance the waterﬂood process through utilization of Polymer 
Flood technology. A Polymer Flood pilot has been in operation since May 2005 with positive results. The drilling of 150 horizontal 
wells is planned for 2006.

During  2005,  the  Company  sold  a  large  portion  of  its  overriding  royalty  interests  on  various  producing  properties  throughout 
Western Canada and Ontario that were considered non-core to its operations, for proceeds of approximately $345 million, after 
giving effect to anticipated adjustments.

Above  average  temperatures  have  continued  into  2006.  Accordingly,  the  Company  is  leveraging  its  deep  drilling  inventory  and 
optimizing  drilling  plans  to  adjust  for  road  bans  and/or  site  access  issues.  Despite  these  challenges  the  Company  still  expects  to 
complete the majority of its winter drilling program. However, the risk remains for an early spring breakup which could signiﬁcantly 
delay tie-ins of many of these new wells. In 2006, the Company’s overall drilling activity in North America is expected to be comprised 
of approximately 1,139 net natural gas wells and 697 net crude oil wells excluding stratigraphic test/service wells.

HORIZON PROJECT
On February 9, 2005 the Board of Directors of the Company unanimously approved the Company to proceed with Phase 1 of the 
Horizon Project. 

The Horizon Project has continued on schedule and on budget. Speciﬁcally, as at December 31, 2005:

•   Phase 1 Horizon Project construction was 19% complete;
•   The detailed engineering work was on schedule, with 3-D engineering models progressing as planned;
•   The Company awarded $3.8 billion of contracts and purchase orders, with a further $600 million in various stages of the tender 

process; and

•   Approximately 1,700 people were on site and functional.

Major activities for 2006 will include:

•   Substantial completion of detailed engineering;
•   Completion and setting of main piperack modules;
•   Receiving and erecting of critical equipment;
•   Beginning construction of ore preparation plant; and
•   Substantial completion of foundations in each area.

First production of light, sweet Synthetic Crude Oil from Phase 1 construction is targeted to commence in the second half of 2008. 
The Horizon Project is in the early stages of construction.

NORTH SEA
The Company continued in 2005 with its planned program of inﬁll drilling, recompletions, workovers and waterﬂood optimizations. 
During 2005, 14 net wells were drilled, consisting of 12 net crude oil wells, 1 net dry well and 1 net service well, with an additional 
2.9 net wells drilling at quarter-end.

In  anticipation  of  the  2005  program  of  inﬁll  drilling,  workovers,  and  third  party  business  on  the  T  and  B  Blocks,  the  Company 
completed a major refurbishment of the Tiffany platform drilling rig, which is facilitating a two-well program targeting unswept areas 
of the ﬁeld. The ﬁrst of these two wells was drilled and completed late in 2005.

Production from the Kyle Field was diverted to the Banff FPSO during 2005. Under the terms of an early termination agreement, the 
existing Kyle FPSO was released in September 2005. The consolidation of these production facilities is expected to result in lower 
combined operating costs from these ﬁelds and may ultimately extend ﬁeld lives for both ﬁelds. 

Management’s Discussion & Analysis

61

OFFSHORE WEST AFRICA
Offshore West Africa capital expenditures include the development of the 57.61% owned and operated Baobab Field, which commenced 
production on August 9, 2005 at approximately 30,000 bbl/d net to the Company. Upon completion of drilling additional wells in 
2006, production levels are expected to achieve approximately 35,000 bbl/d net to the Company.

In East Espoir, two of the four inﬁ ll wells scheduled for drilling were completed during 2005, with the remainder expected to be 
completed in 2006. The drilling of these wells was a result of additional testing and evaluation that revealed a larger quantity of 
crude oil in place, based upon reservoir studies and production history to date. These new producer wells will effectively exploit this 
additional potential and could increase the recoverable resources and production. The West Espoir drilling tower, which will facilitate 
development drilling of the reservoir, is on site and was installed in late 2005. This project is progressing on time and on budget with 
ﬁ rst crude oil expected in 2006, increasing to approximately 13,000 boe/d once fully developed.

The Company purchased a 100% operator interest in the Olowi PSC offshore Gabon in October 2005 and received approval of its 
development plan for this acquisition subsequent to year end. Development plans include a FPSO handling input from two or three 
shallow-water producing platforms. Development is expected to begin late in 2006, with ﬁ rst oil expected late in 2008 at a rate of 
approximately 20,000 bbl/d.

LIQUIDITY AND CAPITAL RESOURCES
($ millions, except ratios) 

Working capital deficit (1)
Long-term debt  
Shareholders’ equity
Share capital  
Retained earnings  
Foreign currency translation adjustment  
Total  
Debt to cash flow (2)  
Debt to EBITDA (3) 
Debt to book capitalization (4)
Debt to market capitalization 
After tax return on average common shareholders’ equity (5)
After tax return on average capital employed (6)

$ 
$ 

$ 

$ 

$ 
$ 

$ 

$ 

2005

1,774 
3,321 

2,442 
5,804 
(9) 
8,237 
0.7x 
0.6x 
28.7% 
9.7% 
14.3% 
10.4% 

$ 
$ 

$ 

$ 

2004

652 
3,538 

2,408 
4,922 
(6) 
7,324 
 1.0x 
0.9x 
33.8% 
21.4% 
21.4% 
15.3% 

2003

505
2,748

2,353
3,650
3
6,006
0.9x
0.8x 
32.8%
25.1%
25.6%
17.1%

(1) Calculated as current assets less current liabilities.
(2) Calculated as current and long-term debt; divided by cash flow from operations for the year.
(3)  Calculated as current and long-term debt; divided by earnings before interest, taxes, depreciation, depletion and amortization, asset retirement obligation accretion, unrealized foreign exchange, 

stock-based compensation expense and unrealized risk management activities for the year.

(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 net earnings for the year as a percentage of average common shareholders’ equity for the period.
(6)  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.

The Company’s capital resources at December 31, 2005 consist primarily of cash ﬂ ow from operations and available credit facilities. 
Cash ﬂ ow from operations is dependent on factors discussed in the Risks and Uncertainties section of this MD&A. The Company’s 
ability to renew existing credit facilities and raise new debt is dependent upon these factors, maintaining an investment grade debt 
rating  and  the  condition  of  capital  and  credit  markets.  Management  believes  internally  generated  cash  ﬂ ows  supported  by  the 
implementation of the Company’s hedge policy, the ﬂ exibility of its capital expenditure programs supported by its ﬁ ve and ten year 
ﬁ nancial plans, the Company’s existing credit facilities and the Company’s ability to raise new debt, will be sufﬁ cient to sustain its 
operations and support its growth strategy.

At December 31, 2005 the Company had undrawn bank lines of credit of $3,285 million. These credit lines are supported by credit 
facilities, which if not extended, mature in 2008, 2009 and 2010.

At December 31, 2005, the Company’s working capital deﬁ cit was $1,774 million and included the current portion of other long-
term  liabilities  of  $1,471  million,  comprised  of  stock-based  compensation  of  $629  million  and  the  mark-to-market  valuation  of 
non-designated risk management ﬁ nancial derivative instruments of $842 million. 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. The cash settlement amount of the risk management ﬁ nancial derivative instruments may vary 
materially depending upon the underlying crude oil and natural gas prices at the time of ﬁ nal settlement of the ﬁ nancial derivative 
instruments, as compared to their mark-to-market value at December 31, 2005.

The Company is committed to maintaining a strong ﬁ nancial position. In 2005, strong operational results and high commodity prices 
resulted in debt to book capitalization levels of 28.7%. The Company believes it has the necessary ﬁ nancial capacity to complete the 

62

Management’s Discussion & Analysis

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Horizon Project while at the same time not compromising delivery of conventional crude oil and natural gas growth opportunities. 
The  ﬁnancing  of  Phase  1  of  the  Horizon  Project  development  is  guided  by  the  competing  principles  of  retaining  as  much  direct 
ownership interest as possible while maintaining a strong balance sheet. Existing proved development projects, which have largely 
been  funded  prior  to  December  31,  2005,  such  as  Baobab,  Primrose  North  and  West  Espoir  should  provide  identiﬁed  growth  in 
production volumes in 2006 through 2008, and are expected to generate incremental free cash ﬂows during this period. 

In January 2005, the Board of Directors authorized the expansion of the Company’s commodity hedging program to reduce the risk 
of volatility in commodity price markets and to underpin the Company’s cash ﬂow for its capital expenditures program through the 
Horizon Project construction period. This expanded program allows for the hedging of up to 75% of the near 12 months budgeted 
production, up to 50% of the following 13 to 24 months estimated production and up to 25% of production expected in months 25 
to 48 through the use of derivative ﬁnancial instruments. For the purpose of this program, the purchase of crude oil put options is 
in addition to the above parameters. As a result, approximately 75% of budgeted 2006 crude oil volumes have been hedged through 
the use of collars. Approximately 60% of budgeted 2006 natural gas volumes have similarly been hedged through the use of collars. 
In addition, for 2007, put options have been acquired on 200,000 bbl/d at an average ﬂoor price of US$47.50 and a further 100,000 
bbl/d at an average ﬂoor price of US$28.00. The Company has not hedged any production volumes beyond 2007. The Company 
continues to evaluate the need for further hedging in 2007 and beyond, given continuing capital requirements for Horizon and other 
capital projects.

LONG-TERM DEBT
Long-term debt at December 31, 2005 amounted to $3,321 million. The debt to EBITDA ratio decreased to 0.6x and the debt to book 
capitalization decreased to 28.7% compared to a debt to EBITDA ratio of 0.9x and a debt to book capitalization of 33.8% in 2004. 
These ratios are currently below the Company’s guidelines for balance sheet management of debt to EBITDA of 1.5x to 2.0x and debt 
to book capitalization of 35% to 45%.

OPERATING FACILITIES
As at December 31, 2005 the Company had in place unsecured syndicated bank credit facilities of $3,425 million, comprised of:

•   a $100 million operating demand facility;
•   a two-tranche revolving credit and term loan facility of $1,825 million; and 
•   a 5-year revolving and term loan facility of $1,500 million. 

The ﬁrst $1,000 million tranche of the $1,825 million facility is fully revolving for a period of three years to June 2008. The second 
tranche of $825 million is fully revolving for a period of ﬁve years to June 2010. Both tranches are extendible annually for one-year 
periods at the mutual agreement of the Company and the lenders. If not extended, the full amount of the outstanding principal would 
be repayable at the end of year two following the initiation of the term period. The $1,500 million revolving credit and term loan 
facility has a ﬁve-year term, with three, one-year extension provisions. If the facility is not extended, the amount outstanding would 
be repayable in December 2009. These facilities provide that the borrowings may be made by way of operating advances, prime loans, 
bankers’ acceptances, US base rate loans or US dollar LIBOR advances, which bear interest at the bank’s prime rates or at money 
market rates plus applicable margins.

The weighted average interest rate of the bank credit facilities outstanding at December 31, 2005, was 5.44% (2004 – 3.47%).

The  Company  also  has  an  unsecured  £15  million  demand  overdraft  credit  facility  for  the  Company’s  North  Sea  operations.  At 
December 31, 2005 there were no amounts drawn on this facility.

In addition to the outstanding debt, as at December 31, 2005 letters of credit aggregating $24 million have been issued.

MEDIUM-TERM NOTES
In May 2005, the Company issued $400 million of debt securities maturing June 2015, bearing interest at 4.95%. Proceeds from the 
securities issued were used to repay bankers’ acceptances under the Company’s bank credit facilities.

In May 2004, the Company repaid the $125 million 6.85% unsecured debentures due May 2004, which were issued under a previous 
medium-term note program.

In January 2006, the Company issued $400 million of debt securities maturing January 2013, bearing interest at 4.50%. 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 $1.6 billion remaining on its $2 billion shelf prospectus ﬁled in August 2005 that allows for the issue of medium-term 
notes in Canada until September 2007. If issued, these securities will bear interest as determined at the date of issuance.

Management’s Discussion & Analysis

63

SENIOR UNSECURED NOTES
In December 2005, the Company repaid the US$125 million 7.69% senior unsecured notes. The 6.42% senior unsecured notes were 
repaid in May 2004. 

The adjustable rate senior unsecured notes bear interest at 6.54% and have annual principal repayments of US$31 million commencing 
in May 2007, through May 2009. 

PREFERRED SECURITIES
In September 2005, the Company redeemed the US$80 million 8.30% preferred securities due May 25, 2011 for cash consideration 
of US$91 million, including an early repayment premium of US$11 million as required under the Note Purchase Agreement.

US DOLLAR DEBT SECURITIES
In June 2005, the Company ﬁled a short form shelf prospectus that allows for the issue of up to US$2 billion of debt securities in the 
United States until July 2007. If issued, these securities will bear interest as determined at the date of issuance.

In December 2004, the Company issued US$350 million of debt securities maturing December 2014, bearing interest at 4.90% and 
US$350 million of debt securities maturing February 2035, bearing interest at 5.85%. Proceeds from the securities issued were used 
to repay bankers’ acceptances under the Company’s bank credit facilities. The Company has entered into interest rate swap contracts 
to convert the ﬁxed rate interest coupon into a ﬂoating interest rate on the securities due December 2014. 

The ratings of the Company’s debt securities and its relationships with principal banks are important to the Company as it continues 
to expand and grow. Hence, it is the Company’s management intention to maintain a strong balance sheet and ﬁnancial position. The 
Company’s debt securities are rated “Baa1” with a stable outlook by Moody’s Investor Services Inc., “BBB+” by Standard & Poors 
Corporation (“S&P”) and “BBB(high)” with a stable trend by Dominion Bond Rating Services Limited. S&P assigns a rating outlook 
to the Company and not to the individual debt intruments. S&P has assigned a negative outlook to the Company.

SHARE CAPITAL
Shareholders of the Company approved a subdivision or share split of its issued and outstanding common shares on a two-for-one
basis  at  the  Company’s  Annual  and  Special  Meeting  held  on  May  5,  2005.  As  at  December  31,  2005,  there  were  536,348,000 
common shares outstanding. As at February 21, 2006, the Company had 537,156,000 common shares outstanding. 

In January 2005, the Company renewed its Normal Course Issuer Bid allowing it to purchase up to 26,818,012 common shares or 5% 
of the Company’s outstanding common shares on the date of announcement, during the 12-month period beginning January 24, 2005
and ending January 23, 2006. As at December 31, 2005, the Company had purchased 850,000 common shares at an average price of 
$53.29 per common share for a total cost of $45 million. 

In January 2006, the Company announced the renewal of its Normal Course Issuer Bid through the facilities of the Toronto Stock 
Exchange  and  the  New  York  Stock  Exchange  to  purchase  up  to  26,852,545  common  shares  or  5%  of  the  outstanding  common
shares  of  the  Company  on  the  date  of  the  announcement,  during  the  12-month  period  beginning  January  24,  2006  and  ending
January  23,  2007.  As  at  February  21,  2006,  the  Company  had  not  purchased  any  additional  shares  under  the  Normal  Course
Issuer Bid. 

In February 2005, the Board of Directors approved an increase in the annual dividend paid by the Company to $0.225 per common 
share. In May 2005, the Board of Directors approved an increase in the annual dividend paid by the Company to $0.24 per common 
share. In February 2004, the Board of Directors increased the annual dividend paid by the Company to $0.20 per common share, up 
from the previous level of $0.15 per common share.

In February 2006, the Company’s Board of Directors approved an increase in the annual dividend paid by the Company to $0.30 per 
common share for 2006. The increase represents a 27% increase from the prior year, recognizes the stability of the Company’s cash 
ﬂow, and provides a return to Shareholders. This is the sixth consecutive year in which the Company has paid dividends and the ﬁfth 
consecutive year of an increase in the distribution paid to its Shareholders.

64

Management’s Discussion & Analysis

COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various contractual arrangements and commitments that will have 
an impact on the Company’s future operations. These contractual obligations and commitments primarily relate to debt repayments, 
operating leases relating to ofﬁce space and offshore production and storage vessels, and ﬁrm commitments for gathering, processing 
and transmission services, as well as expenditures relating to asset retirement obligations. The Company has not entered into any 
contracts that would require consolidation under CICA Accounting Handbook, AcG-15, Consolidation of Variable Interest Entities. 
The following table summarizes the Company’s commitments as at December 31, 2005:

($ millions)

2006

2007

2008

2009

2010

Thereafter

Product transportation and pipeline (1)
Offshore equipment operating lease
Offshore drilling 
Asset retirement obligations (2)
Long-term debt (3) 
Other (4) 

$
$
$
$
$
$

195
51
132
82
–
61

$
$
$
$
$
$

133
51
100
4
161
62

$
$
$
$
$
$

148
52
35
4
36
21

$
$
$
$
$
$

94
51
–
4
36
29

$
$
$
$
$
$

85
51
–
7
–
23

$
$
$
$
$
$

1,111
180
–
3,224
2,966
8

(1) During the year, the Company entered into a 25 year pipeline transportation agreement commencing in 2008, related to future crude oil production. The agreement is renewable for successive 

10-year periods at the Company’s option. During the initial term, annual toll payments before operating costs will be approximately $35 million.

(2) Represents management’s estimate of the future payments to settle asset retirement obligations related to resource properties, facilities, production platforms and gathering systems, based on 

current legislation and industry operating practices.

(3) No debt repayments are reflected for the bank credit facilities due to the extendable nature of the facilities.
(4) Consists of future expenditures related primarily to office lease, electricity and crude oil processing. 

The Board of Directors has approved the construction costs for Phase 1 of the Horizon Project, which are budgeted to be $6.8 billion, 
including a contingency fund of $700 million, with $1.3 billion incurred in 2005, $2.6 billion to be incurred in 2006 and $2.9 billion 
to be incurred in 2007 and 2008.

The Company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. The Company believes 
that any liabilities that might arise pertaining to such matters would not have a material effect on its consolidated ﬁnancial position.

RESERVES
For the year ended December 31, 2005, the Company retained qualiﬁed independent reserve evaluators, Sproule Associates Limited 
(“Sproule”) and Ryder Scott Company (“Ryder Scott”) to evaluate 100% of the Company’s conventional proved and probable crude 
oil, natural gas liquids (“NGL”) and natural gas reserves (1) and prepare Evaluation Reports on these reserves. Sproule evaluated the 
Company’s North America conventional assets and Ryder Scott evaluated its international conventional assets. The Company has 
been granted an exemption from 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 two principal differences between the two standards. The ﬁrst is the additional 
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 Company has disclosed 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  this  Annual 
Report.  The  Company  has  elected  to  provide  the  net  present  value  (2)  of  these  same  conventional  proved  reserves  as  well  as  the 
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 voluntary additional information, which is disclosed in the 
Company’s most recent Annual Information Form.

Reserves and net present values presented for years prior to 2003 were evaluated in accordance with the standards of National Policy 
2-B which has now been replaced by NI 51-101. The stated reserves were reasonably evaluated as economically productive using 
year-end costs and prices escalated at appropriate rates throughout the productive life of the properties.

For the year ended December 31, 2005, the Company retained a qualiﬁed independent reserves evaluator, GLJ Petroleum Consultants 
(“GLJ”),  to  evaluate  100%  of  Phases  1  through  3  of  the  Company’s  Horizon  Project  and  prepare  an  Evaluation  Report  on  the 
Company’s proved and probable oil sands mining reserves incorporating both the mining and upgrading projects. 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 probable crude oil, NGL and natural gas reserves.

Management’s Discussion & Analysis

65

 
 
 
The Reserve Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures 
with each of Sproule, Ryder Scott 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, NGL and natural gas reserves as well 
as the Company’s quantity of oil sands mining reserves.

Additional reserve disclosure is contained in the supplementary oil and gas information of this Annual Report and the Company’s 
most recent Annual Information Form.

(1) Conventional crude oil, NGL and natural gas includes all of the Company’s light and medium, heavy, and thermal crude oil, natural gas, coal bed methane and natural gas liquid activities. It 

does not include the Company’s oil sands mining assets.

(2) Net present values of conventional reserves are based upon discounted cash flows prior to the consideration of income taxes and existing asset abandonment liabilities. Only future development 

costs and associated material well abandonment liabilities have been applied with the exception of Offshore West Africa where all abandonment liabilities have been included.

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. These inherent risks include, but are not limited to, the following items:

•   Economic risk of ﬁnding and producing 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 and depletion rates.

•   Pricing risk of marketing reserves at an acceptable price given current market conditions. 
•   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.

•   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 at commercially acceptable terms.
•   Foreign exchange risk due to ﬂuctuating exchange rates, as the majority of sales are based in US dollars.
•   Environmental impact risk associated with exploration and development activities.
•   Risk of catastrophic loss due to ﬁre, explosion or acts of nature.
•   Other  risks  associated  with  changing  governmental  policies,  social  instability  and  other  political,  economic  or  diplomatic 

developments in the Company’s international operations.

The Company uses a variety of means to help minimize these risks. The Company maintains a comprehensive insurance program to 
reduce risk to an acceptable level and to protect it against signiﬁcant losses. Operational control is enhanced by focusing efforts on 
large core regions with high working interests and by assuming operatorship of all key facilities. Product mix is diversiﬁed, ranging 
from the production of natural gas to the production of crude oil of various grades. The Company believes this diversiﬁcation reduces 
price risk when compared with over-leverage to one commodity. Sales of crude oil and natural gas are aimed at various markets to 
ensure that undue exposure to any one market does not exist. Financial instruments are utilized to help ensure targets are met and 
to  manage  commodity  prices,  foreign  currency  rates  and  interest  rate  exposure.  The  Company  minimizes  credit  risks  by  entering 
into sales contracts and ﬁnancial derivatives with only highly rated entities and ﬁnancial institutions. The arrangements and policies 
concerning the Company’s ﬁnancial instruments are under constant review and may change depending upon the prevailing market 
conditions.  Refer  to  the  “Risk  management  activities”  section  of  this  MD&A.  In  addition,  the  Company  reviews  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.

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 most recent Annual Information Form.

66

Management’s Discussion & Analysis

ENVIRONMENT
The  Company  continues  to  employ  an  Environmental  Management  Plan  (the  “Plan”)  to  ensure  the  welfare  of  its  employees,  the 
communities in which it operates, and the environment as a whole. Environmental protection is of fundamental importance and is 
undertaken in accordance with guiding principles approved by the Company’s Board of Directors. A detailed copy of the Company’s 
Plan is presented to, and reviewed by, the Board of Directors annually. The Plan is updated quarterly at the Directors’ meetings.

The Company’s environmental management plan and operating guidelines focus on minimizing the impact of ﬁ eld operations while 
meeting regulatory requirements and corporate standards. The Company, as part of this plan, has implemented a proactive program 
that includes:

  •   An annual 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;
  •   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; and
  •   A program to replace the majority of fresh water for steaming with brackish water.

The Company has also established stringent operating standards in four areas:

  •   Using water-based, environmentally friendly drilling muds whenever possible;
  •   Implementing cost effective ways of reducing greenhouse natural gas emissions per unit of production;
  •   Exercising care with respect to all waste produced through effective waste management plans; and
  •   Minimizing produced water volumes onshore and offshore through cost-effective measures.

In 2005, the Company’s capital expenditures included $46 million for abandonment expenditures, an increase from $32 million in 
2004 (2003 – $40 million).

Estimated asset retirement obligation, undiscounted ($ millions)

North America  
North Sea  
Offshore West Africa    

North Sea PRT recovery  

2005

2,050 
1,185 
90 
3,325 
(370) 
2,955 

$ 

$ 

2004

1,770
1,265
25
3,060
(600)
2,460

$ 

$ 

The estimate of the future site restoration liability is based on estimates of future costs to abandon and restore the wells, production 
facilities and offshore production platforms. There are numerous factors that affect these costs including such things as the number 
of wells drilled, well depth and the speciﬁ c environmental legislation. The estimated costs are based on engineering estimates using 
current costs and technology in accordance with present legislation and industry operating practice. The future abandonment costs 
to be incurred by the Company in the North Sea will result in an estimated recovery of PRT of $370 million (2004 – $600 million, 
2003 – $330 million), as abandonment costs are an allowable deduction in determining PRT and may be carried back to reclaim PRT 
previously paid. The PRT recovery reduces the net abandonment liability of the Company to $2,955 million (2004 – $2,460 million, 
2003 – $1,950 million). The North Sea PRT recovery has decreased substantially from 2004 primarily due to improved economics 
related to the various ﬁ elds, including a higher pricing environment and stronger Canadian dollar at December 31, 2005. Under these 
economic conditions, end of ﬁ eld losses at Tiffany previously assumed to be available for relief against PRT due from other ﬁ elds 
is signiﬁ cantly reduced. 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.

KYOTO PROTOCOL
In December 2002, the Canadian Federal Government ratiﬁ ed the Kyoto Protocol (“Kyoto”). The Company continues to work with 
the Federal and Provincial governments on the regulatory framework for greenhouse gases for larger emitters. The framework under 
development would see harmonized regulation between the two levels of government. Both levels of government have indicated that 
existing legislation will be amended in 2006 to create further requirements for reporting emissions, facility-based emission intensity 
targets and regulatory compliance. Compliance with emission intensity targets is expected for 2008, which is the ﬁ rst year of the 
compliance period for the Kyoto Protocol. 

Management’s Discussion & Analysis

67

 
 
 
 
 
 
 
 
 
 
 
 
 
 
    
 
The Company will continue to develop strategies that will enable it to deal with the risks and opportunities associated with new 
climate change policies. In addition, the Company will work with relevant parties to ensure that new policies encourage innovation, 
energy efﬁciency, targeted research and development while not impacting Canada’s competitive position.

Due to the high degree of cost uncertainty when the Federal Government ratiﬁed Kyoto, maximum per tonne cost assurances were 
agreed with large emitters for 2008 – 2012. Beyond 2012 investment concerns were addressed by the Federal Government as outlined 
in eight principles that would guide its negotiations and policies for this later stage. 

CRITICAL ACCOUNTING ESTIMATES
The preparation of ﬁnancial statements requires the Company to make judgements, assumptions and estimates in the application of 
generally accepted accounting principles that have a signiﬁcant impact on the Company’s ﬁnancial position and operations. Actual 
results could differ from those estimates, and those differences could 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 proﬁt or loss except where such disposal constitutes a signiﬁcant portion of the 
Company’s reserves in that country. Under Canadian GAAP, the capitalized costs and 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 constant dollar pricing as required by the SEC. 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.

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  higher  DD&A  rates  compared  to  the  successful 
efforts method.

CRUDE OIL AND NATURAL GAS RESERVES
The Company retains qualiﬁed independent reserves evaluators to evaluate the Company’s proved and probable crude oil and natural 
gas reserves. In 2005, 100% of the Company’s reserves were evaluated by qualiﬁed independent reserves evaluators.

The estimation of reserves involves the exercise of judgement. Forecasts are based on engineering data, 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. 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 reserve estimate would result in a higher or lower DD&A charge to net earnings. Downward revisions 
to reserve estimates could also result in a write-down of crude oil and natural gas property, plant and equipment carrying amounts 
under the ceiling test.

ASSET RETIREMENT OBLIGATION
Under CICA Handbook Section 3110, Asset Retirement Obligations (“ARO”), the Company is required to recognize a liability for 
the future retirement obligations associated with the Company’s 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 based on experience. 

68

Management’s Discussion & Analysis

The estimated fair values of asset retirement obligations 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  asset  retirement  obligations  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 
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 of 6.8%. In subsequent periods, the asset retirement obligation 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 capital cost and accretion on the asset retirement liability. In addition, differences between 
actual and estimated costs to settle the asset retirement obligation, timing of cash ﬂows to settle the obligation and future inﬂation 
rates could result in gains or losses on the ﬁnal settlement of the asset retirement obligations.

An ARO is not recognized for assets with an indeterminate useful life (e.g. pipeline assets) because an amount cannot be reasonably 
estimated. An ARO for these assets will be recorded in the ﬁrst period in which the lives of these assets are determinable.

RISK MANAGEMENT ACTIVITIES
The Company utilizes various instruments to manage its commodity price and foreign currency exposures on revenue, and interest rate 
exposures on US dollar denominated debt. These derivative and ﬁnancial instruments are not used for trading or speculative purposes.

On January 1, 2004, the Company prospectively adopted the Canadian Institute of Chartered Accountants’ (“CICA”) Accounting 
Guideline (“AcG”) 13, “Hedging Relationships” and Emerging Issues Committee (“EIC”) 128, “Accounting for Trading, Speculative 
or Non-Hedging Derivative Financial instruments”. Derivative instruments that do not qualify as hedges, or are not designated as 
hedges, are recorded using the mark-to-market method of accounting whereby instruments are recorded on the consolidated balance 
sheet as either an asset or liability with changes in fair value recognized in net earnings. The estimate of fair value of all derivative 
instruments is based on quoted market prices or, in their absence, third party market indications. The cash settlement amount of the risk 
management ﬁnancial derivative instruments may vary materially depending upon the underlying crude oil and natural gas prices at the 
time of ﬁnal settlement of the ﬁnancial derivative instruments, as compared to their mark-to-market value at December 31, 2005.

PURCHASE PRICE ALLOCATIONS
The costs of corporate and asset acquisitions are allocated to the 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 amount 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 judgments made 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 engineers and outside consultants. The judgments 
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 future price forecasts amongst 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.

CONTROL ENVIRONMENT
Based on their evaluation as of December 31, 2005, the Company’s President and the Chief Financial Ofﬁcer concluded, pursuant to 
Canadian Multilateral Instrument 52-109 Part 2.1, that the Company’s disclosure controls and procedures are effective to ensure that 
information required to be disclosed by the Company in its annual ﬁlings is recorded, processed, summarized and reported within the 
time periods that meet the regulatory requirements. In addition, as of December 31, 2005, there were no changes in the Company’s 
internal controls over ﬁnancial reporting that occurred during 2005 that have materially affected, or are reasonably likely to materially 
affect  its  internal  controls  over  ﬁnancial  reporting.  The  Company  will  continue  to  periodically  evaluate  its  disclosure  controls  and 
procedures and internal controls over ﬁnancial reporting and will make any modiﬁcations from time to time as deemed necessary.

Management’s Discussion & Analysis

69

NEW ACCOUNTING STANDARDS
In January 2005, the CICA issued four new standards relating to the recognition, measurement and disclosure of ﬁnancial instruments. 

•   Section 3855 – “Financial Instruments – Recognition and Measurement” prescribes when a ﬁnancial asset, ﬁnancial liability, or 
non-ﬁnancial derivative is to be recognized on the balance sheet as well as its measurement amount. This Section also speciﬁes 
how ﬁnancial instruments gains and losses are to be presented. Transitional provisions for this Section vary based on the type of 
ﬁnancial instruments under consideration.

•   Section  3865  –  “Hedges”  expands  on  existing  AcG  13  –  “Hedging  Relationships”,  and  Section  1650  “Foreign  Currency 
Translation”,  by  specifying  how  hedge  accounting  is  to  be  applied  and  what  disclosures  are  necessary  when  it  is  applied. 
Retroactive application of this Section is not permitted. 

•   Section  1530  –  “Comprehensive  Income”  introduces  new  standards  for  reporting  and  disclosure  of  comprehensive  income. 
Comprehensive income is the change in equity (net assets) of the Company during a reporting period from transactions and other 
events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from 
investments by owners and distributions to owners. Financial statements of prior periods are required to be restated only for 
non-ﬁnancial instrument items.

•   Section 3251 – “Equity” replaces Section 3250 “Surplus” and establishes standards for the presentation of equity and changes 
in  equity  during  a  reporting  period.  Financial  statements  of  prior  periods  are  required  to  be  restated  only  for  non-ﬁnancial 
instrument  items.  For  all  other  items,  comparative  ﬁnancial  statements  presented  are  not  restated,  but  an  adjustment  to  the 
opening balance of accumulated other comprehensive income may be required. 

The Company plans to adopt these new standards effective January 1, 2007. The effect on the Company’s consolidated ﬁnancial 
statements cannot be reasonably determined at this time as the ﬁnancial derivatives outstanding at December 31, 2006 and their 
related fair values are not known.

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 high shareholder returns. Annual 
budgets are developed, scrutinized throughout the year and changed if necessary in the context of 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 2006 to average 1,468 mmcf/d to 1,551 mmcf/d of natural gas and 335,000 bbl/d to 
373,000 bbl/d of crude oil and NGLs.

The budgeted capital expenditures in 2006 are currently expected to be as follows:

2006 Budget

$

$

1,741
1,097
733
187
63
3,821
2,561
222
128
30
6,762

($ millions) 

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
Capitalized interest and other items
Horizon Project Phases 2/3 engineering
Canadian Natural Upgrader engineering
Total  

70

Management’s Discussion & Analysis

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NORTH AMERICA NATURAL GAS
The 2006 North American natural gas program will be as follows:

(number of wells) 

Northeast British Columbia 
Northwest Alberta  
Northern Plains  
Southern Plains  
Total  

2006 Budget

262
147
251
479
1,139

Drilling  will  comprise  both  deep  and  conventional  targets,  with  new  production  growth  coming  from  the  Company’s  Northeast 
British Columbia and Northwest Alberta areas.

NORTH AMERICA CRUDE OIL AND NGLS
The 2006 North America crude oil drilling program is highlighted by continued development of Primrose North thermal production 
and another strong conventional heavy program, as follows:

(number of wells)

Conventional heavy crude oil 
Thermal heavy crude oil 
Light crude oil  
Pelican Lake crude oil   
Total  

2006 Budget

344
92
111
150
697

The Company continues the disciplined development of its heavy crude oil resources. Conventional heavy crude oil drilling is expected 
to increase, reﬂecting favourable crude oil prices and new opportunities identiﬁed in the property acquisitions made during 2004. Due 
to the nature of heavy crude oil production patterns, where production volumes ramp up during the ﬁrst months of production, much 
of the production resulting from the expanded drill program will not be realized until late 2007.

In 2006, the Company expects to continue its Primrose thermal crude oil expansion plans. Activity in 2006 will be focused on the 
Primrose South expansion. Production from this project is subject to the cycling of steam injection and crude oil production and 
is expected to remain at similar levels to the 2005 production. The waterﬂood conversion project is on schedule with production 
response exceeding expectations. The Polymer Flood pilot project has yielded positive results to date and will continue in 2006.

THE HORIZON PROJECT
The  Horizon  Project  is  designed  as  a  phased  development  and  includes  two  components:  the  mining  of  bitumen  and  an  onsite 
upgrader. Phase 1 production is expected to commence in the second half of 2008 at 110,000 bbl/d of 34° API light, sweet synthetic 
crude  oil  (“SCO”).  The  phased  approach  provides  the  Company  with  improved  cost  and  project  controls  including  labour  and 
materials management, and directionally mitigates the effects of growth on local infrastructure.

Construction costs for Phase 1 of the Horizon Project are estimated at $6.8 billion including a contingency reserve of $700 million, 
with $1.3 billion incurred in 2005, $2.6 billion to be incurred in 2006 and $2.9 billion to be incurred in 2007 and 2008.

Extensive front end design and the high degree of project deﬁnition have enabled the Company to obtain approximately 68% of 
Phase 1 costs on a ﬁxed price basis. The high degree of up front project engineering and pre-planning is expected to reduce the risks 
associated with scope changes.

NORTH SEA
The capital budget in 2006 for the North Sea is $733 million and includes the drilling of approximately 12 net platform wells on 
Ninian, Murchison and Tiffany. The Company will also conduct a mobile drilling program for which 6 subsea producer wells will 
be drilled at Columba E, Lyell, Toni and Thelma. Average crude oil production is expected to increase from 2005 production levels; 
however, natural gas volumes are expected to be ﬂat as natural gas production at the Banff Field is diverted to reinjection.

OFFSHORE WEST AFRICA
In 2006, the capital budget for Offshore West Africa is set at $187 million, of which the Company anticipates $79 million to be spent 
on completing inﬁll drilling at East Espoir and developing the West Espoir Field. West Espoir development is expected to yield ﬁrst 
oil by mid-2006 at approximately 13,000 boe/d. Two additional wells will be completed at Baobab in 2006, allowing production to 
ramp to approximately 35,000 bbl/d net to the Company. $32 million will be expended on development of the Olowi Field offshore 
Gabon in 2006, with ﬁrst oil expected late in 2008.

Management’s Discussion & Analysis

71

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SENSITIVITY ANALYSIS (1)
The following table is indicative of the annualized sensitivities of cash ﬂ ow 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 2005. Each separate item 
in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant.

Price changes
Crude oil – WTI US$1.00/bbl (2)
Excluding financial derivatives  
Including financial derivatives  
Natural gas – AECO C$0.10/mcf (2)
Excluding financial derivatives  
Including financial derivatives 
Volume changes
Crude oil – 10,000 bbl/d  
Natural gas – 10 mmcf/d  
Foreign currency rate change
$0.01 change in C$ in relation to US$ (2)
Interest rate change – 1% 

Cash flow from  Cash flow from
operations 
 ($/share, basic) 

operations 
($ millions) 

Net earnings 
($ millions) 

Net earnings 
($/share, basic)

$ 
$ 

$ 
$ 

$ 
$ 

$ 
$ 

113 
60 

38 
14 

104 
32 

$ 
$ 

$ 
$ 

$ 
$ 

0.21 
0.11 

0.07 
0.03 

0.19 
0.06 

82-84 
7 

$  0.15-0.16 
0.01 
$ 

$ 
$ 

$ 
$ 

$ 
$ 

$ 
$ 

79 
40 

24 
8 

53 
17 

32-33 
7 

$ 
$ 

$ 
$ 

$ 
$ 

$ 
$ 

0.15
0.07

0.05
0.01

0.10
0.03

0.06
0.01

(1) The sensitivities are calculated based on 2005 fourth quarter results excluding mark-to-market gains (losses) on risk management activities.
(2) For details of financial instruments in place, refer to note 10 to the Company’s audited annual consolidated financial statements as at December 31, 2005.

DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES (1)

Q1 

Q2 

Q3 

Q4 

2005

2004

2003

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    
Total  

209,125 
71,139 
7,539 
287,803 

1,430 
23 
2 
1,455 

447,446 
74,956 
7,914 
530,316 

215,693 
62,884 
10,487 
289,064 

1,434 
17 
3 
1,454 

454,602 
65,751 
11,027 
531,380 

231,260 
73,543 
29,921 
334,724 

1,400 
18 
5 
1,423 

464,607 
76,545 
30,759 
571,911 

230,263 
66,798 
43,207 
340,268 

1,402 
15 
6 
1,423 

463,869 
69,361 
44,275 
577,505 

221,669 
68,593 
22,906 
313,168 

1,416 
19 
4 
1,439 

457,695 
71,651 
23,614 
552,960 

206,225 
64,706 
11,558 
282,489 

1,330 
50 
8 
1,388 

427,936 
73,093 
12,806 
513,835 

174,895
56,869
10,628
242,392

1,245
46
8
1,299

382,315
64,469
12,030
458,814

(1)  The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place. For production where revenue has not yet been recognized, the 

related crude oil inventory volumes, by segment, were as follows at December 31, 2005:

(bbls)

North America, related to Corsicana pipeline line fill 
North Sea, related to timing of liftings 
Offshore West Africa, related to timing of liftings, net of government entitlement to profit oil 

At December 31, 2004, variances between production volumes and liftings were not signiﬁ cant.

2005

484,157
747,141
412,841
1,644,139

72

Management’s Discussion & Analysis

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PER UNIT RESULTS (1)

Q1 

Q2 

Q3 

Q4 

2005

2004

$ 

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  
Netback  

$ 

$ 

$ 

$ 

39.81 
3.39 
11.30 
25.12 

6.68 
1.30 
0.69 
4.69 

39.94 
5.42 
8.04 
26.48 

$ 

$ 

$ 

$ 

$ 

$ 

42.51 
3.33 
11.66 
27.52 

7.33 
1.48 
0.71 
5.14 

43.05 
5.85 
8.29 
28.91 

$ 

$ 

$ 

$ 

$ 

$ 

57.35 
5.11 
11.48 
40.76 

8.61 
1.93 
0.76 
5.92 

54.87 
7.84 
8.56 
38.47 

$ 

$ 

$ 

$ 

$ 

$ 

46.38 
3.89 
10.33 
32.16 

11.67 
2.30 
0.76 
8.61 

56.08 
8.01 
7.93 
40.14 

(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Including transportation costs and excluding risk management activities.

NETBACK ANALYSIS
($/boe) (1)

Sales price (2) 
Royalties   
Production expense (3)   
Netback    
Midstream contribution (3)
Administration (4) 
Interest, net  
Realized risk management activities loss  
Realized foreign exchange (gain) loss  
Taxes other than income tax – current  
Current income tax – North America  
Current income tax – Large Corporations Tax  
Current income tax – North Sea  
Current income tax – Offshore West Africa  
Current income tax – other  
Cash flow  

(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Including transportation costs and excluding risk management activities.
(3) Excluding inter-segment eliminations.
(4) Restated to conform to current year presentation.

TRADING AND SHARE STATISTICS

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

46.86 
3.97 
11.17 
31.72 

8.57 
1.75 
0.73 
6.09 

48.77 
6.82 
8.21 
33.74 

2005

48.77 
6.82 
8.21 
33.74 
(0.26) 
0.75 
0.74 
5.13 
(0.15) 
1.01 
0.41 
0.08 
0.77 
0.17 
0.01 
25.08 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

37.99 
3.16 
10.05 
24.78 

6.50 
1.35 
0.67 
4.48 

38.45 
5.37 
7.35 
25.73 

2004

38.45 
5.37 
7.35 
25.73 
(0.26) 
0.66 
1.01 
2.52 
0.02 
1.12 
0.47 
0.05 
0.01 
0.07 
0.01 
20.05 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

2003

32.66
2.77
10.28
19.61

6.21
1.32
0.60
4.29

34.84
5.20
7.15
22.49

2003

34.84
5.20
7.15
22.49
(0.28)
0.52
1.20
1.09
0.05
0.69
0.14
0.06
0.26
0.09
–
18.67

Q1 

Q2 

Q3 

Q4 

2005 Total 

2004 Total (1)

$ 
$ 
$ 

TSX – C$
Trading volume (thousands)
Share price ($/share)
High  
Low  
Close  
Market capitalization at December 31 ($ millions) 
Shares outstanding (thousands)  
NYSE – US$
Trading volume (thousands)  
Share price ($/share)
High  
Low  
Close  
Market capitalization at December 31 ($ millions)  
Shares outstanding (thousands)  

$ 
$ 
$ 

169,018 

37.38 
24.28 
34.18 

48,333 

30.37 
19.74 
28.41 

(1) Restated to reflect two-for-one share split in May 2005.

155,274 

160,121 

153,579 

637,992 

606,024

$ 
$ 
$ 

$ 
$ 
$ 

46.98 
30.54 
44.40 

$ 
$ 
$ 

60.00 
45.52 
52.50 

$ 
$ 
$ 

62.00 
43.55 
57.63 

$ 
$ 
$ 
$ 

62.00 
24.28 
57.63 
30,910 
536,348 

$ 
$ 
$ 
$ 

27.58
15.96
25.63
13,744
536,361

68,743 

66,802 

67,676 

251,554 

125,468

38.03 
24.49 
36.38 

$ 
$ 
$ 

50.73 
36.87 
45.19 

$ 
$ 
$ 

54.05 
36.65 
49.62 

$ 
$ 
$ 
$ 

54.05 
19.74 
49.62 
26,614 
536,348 

$ 
$ 
$ 
$ 

22.37
11.94
21.39
11,470
536,361

Management’s Discussion & Analysis

73

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Management’s Report

The  accompanying  consolidated  ﬁnancial  statements  and  all  information  in  the  annual  report  are  the  responsibility  of  management.  The 
consolidated ﬁnancial statements have been prepared by management in accordance with the accounting policies in the notes to the consolidated 
ﬁnancial statements. 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 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, 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 examine the consolidated ﬁnancial statements in accordance with generally accepted auditing 
standards in Canada and provide an independent professional opinion. 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.  This  committee,  which  is  comprised  of  non-
management directors, meets with management and the external 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
February 21, 2006

Auditors’ Report

Douglas A. Proll CA
Senior Vice President, Finance & 
Chief Financial Ofﬁcer

Randall S. Davis CA
Vice President, Financial
Accounting & Controls

TO THE SHAREHOLDERS OF CANADIAN NATURAL RESOURCES LIMITED,
We  have  audited  the  consolidated  balance  sheets  of  Canadian  Natural  Resources  Limited  as  at  December  31,  2005  and  2004  and  the 
consolidated statements of earnings, retained earnings and cash ﬂows for each of the years in the three year period ended December 31, 2005. 
These consolidated ﬁnancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on 
these ﬁnancial statements based on our audits.

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

In our opinion, these consolidated ﬁnancial statements present fairly, in all material respects, the ﬁnancial position of the Company as at 
December 31, 2005 and 2004 and the results of its operations and its cash ﬂows for each of the years in the three year period ended December 
31, 2005 in accordance with Canadian generally accepted accounting principles.

Chartered Accountants
Calgary, Alberta, Canada
February 21, 2006

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 change described in Note 10 to the consolidated ﬁnancial statements. Our report to the shareholders dated February 21, 2006 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
February 21, 2006

74

Management and Auditors’ Reports

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 6)
  Current portion of other long-term assets (note 2)

Property, plant and equipment (note 3)
Other long-term assets (note 2)

LIABILITIES
Current liabilities
  Accounts payable  
  Accrued liabilities  
  Current portion of long-term debt (note 4)
  Current portion of other long-term liabilities (note 5)

Long-term debt (note 4)   
Other long-term liabilities (note 5)
Future income tax (note 6)

SHAREHOLDERS’ EQUITY
Share capital (note 7) 
Retained earnings  
Foreign currency translation adjustment (note 8)

Commitments (note 11)

Approved by the Board of Directors:

Catherine M. Best  
Chair of the Audit Committee   
and Director  

N. Murray Edwards
Vice-Chairman of the Board of Directors
and Director

2005

2004

18 
1,546 
487 
– 
2,051 
19,694 
107 
21,852 

573 
1,781 
– 
1,471 
3,825 
3,321 
1,434 
5,035 
13,615 

2,442 
5,804 
(9) 
8,237 
21,852 

$ 

$ 

$ 

$ 

28
1,055
83
34
1,200
17,064
108
18,372

379
1,019
194
260
1,852
3,538
1,208
4,450
11,048

2,408
4,922
(6)
7,324
18,372

$ 

$ 

$ 

$ 

Consolidated Financial Statements

75

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated Statements of Earnings

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  
Depletion, depreciation and amortization  
Asset retirement obligation accretion (note 5)
Administration  
Stock-based compensation (note 5)
Interest, net 
Risk management activities (note 10)
Foreign exchange gain   

Earnings before taxes  
Taxes other than income tax (note 6)
Current income tax (note 6)
Future income tax (note 6)
Net earnings  

Net earnings per common share (note 9)
  Basic  
  Diluted  

$ 

2005

10,107 
(1,366) 
8,741 

$ 

2004

7,547 
(1,011) 
6,536 

$ 

1,663 
270 
2,013 
69 
151 
723 
149 
1,952 
(132) 
6,858 
1,883 
194 
286 
353 
1,050 

1.96 
1.95 

$ 

$ 
$ 

1,400 
250 
1,769 
51 
125 
249 
189 
434 
(91) 
4,376 
2,160 
165 
116 
474 
1,405 

2.62 
2.60 

$ 

$ 
$ 

$ 

$ 
$ 

2003

6,155
(872)
5,283

1,209
262
1,509
62
87
200
201
148
(335)
3,343
1,940
107
92
338
1,403

2.62
2.53

Consolidated Statements of Retained Earnings

For the years ended December 31
(millions of Canadian dollars)  

Balance – beginning of year
Net earnings  
Dividends on common shares (note 7)  
Purchase of common shares under Normal Course Issuer Bid (note 7)  
Balance – end of year  

2005

4,922 
1,050 
(127) 
(41) 
5,804 

$ 

$ 

2004  

3,650 
1,405 
(107) 
(26) 
4,922 

$ 

$ 

2003

2,424
1,403
(81)
(96)
3,650

$ 

$ 

76

Consolidated Financial Statements

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated Statements of Cash Flows

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  
  Unrealized risk management activities  
  Unrealized foreign exchange gain  
  Deferred petroleum revenue tax recovery  
  Future income tax    
Deferred charges  
Abandonment expenditures  
Net change in non-cash working capital (note 12)

Financing activities
(Repayment) issue of bank credit facilities  
Issue (repayment) of medium-term notes  
Repayment of senior unsecured notes  
Repayment of preferred securities 
Issue of US dollar debt securities  
Repayment of obligations under capital leases  
Dividends on common shares  
Issue of common shares on exercise of stock options  
Purchase of common shares  
Net change in non-cash working capital (note 12)

Investing activities
Expenditures on property, plant and equipment  
Net proceeds on sale of property, plant and equipment  
Net expenditures on property, plant and equipment  
Net proceeds on sale of other assets 
Net change in non-cash working capital (note 12)

(Decrease) increase in cash 
Cash – beginning of year 
Cash – end of year 

Supplemental disclosure of cash flow information (note 12)

2005

2004

2003

$ 

1,050 

$ 

1,405 

$ 

1,403

2,013 
69 
723 
925 
(103) 
(9) 
353 
(31) 
(46) 
(147) 
4,797 

(435) 
400 
(194) 
(107) 
– 
– 
(121) 
9 
(45) 
19 
(474) 

(5,340) 
454 
(4,886) 
11 
542 
(4,333) 
(10) 
28 
18 

$ 

1,769 
51 
249 
(40) 
(94) 
(45) 
474 
(33) 
(32) 
(14) 
3,690 

357 
(125) 
(54) 
– 
830 
(7) 
(101) 
24 
(33) 
6 
897 

(4,582) 
7 
(4,575) 
– 
(88) 
(4,663) 
(76) 
104 
28 

$ 

1,509
62
200
–
(343)
(9)
338
10
(40)
(48)
3,082

(647)
–
(85)
–
–
(8)
(77)
89
(144)
(11)
(883)

(2,486)
20
(2,466)
–
341
(2,125)
74
30
104

$ 

Consolidated Financial Statements

77

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 operations are focused in North America, 
largely in western Canada, the United Kingdom portion of the North Sea and Offshore West Africa. Within western Canada, the 
Company is developing its Horizon Oil Sands Project (the “Horizon Project”) and maintains its midstream activities. The Horizon 
Project involves a plan to recover bitumen through mining operations, while the midstream activities include the Company’s 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 15.

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 subsidiaries 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.

Depletion,  depreciation  and  amortization,  and  amounts  used  for  ceiling  test  calculations  are  based  on  estimates  of  crude  oil  and 
natural gas reserves and commodity prices, production expenses and capital costs required to develop and produce those reserves. 
Substantially all of the Company’s reserve estimates are evaluated annually by independent engineering ﬁrms. By their nature, estimates 
of reserves and the related future cash ﬂows are subject to measurement uncertainty, and the impact of differences between actual and 
estimated amounts on the consolidated ﬁnancial statements of future periods could 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 could be material.

The measurement of petroleum revenue tax expense 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 could result in material changes to deferred amounts.

(C)  CASH AND CASH EQUIVALENTS
Cash comprises cash on hand and demand deposits. Other investments (term deposits and certiﬁcates of deposit) with an original term 
to maturity of three months or less are reported as cash equivalents on the balance sheet.

(D)  PROPERTY, PLANT AND EQUIPMENT
The Company follows the full cost method of accounting for crude oil and natural gas properties and equipment as prescribed by 
the Canadian Institute of Chartered Accountants (“CICA”). Accordingly, all costs relating to the exploration for and development 
of crude oil and natural gas reserves are capitalized and accumulated in country-by-country cost centres. Administrative overhead 
incurred during the development phase of 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 proﬁt or loss except where such 
disposal constitutes a signiﬁcant portion of the Company’s reserves in that country.

Contractual arrangements that meet the deﬁnition of a lease as speciﬁed in Emerging Issues Committee (“EIC”) 150 – “Determining
Whether an Arrangement Contains a Lease” are accounted for as capital leases or operating leases as appropriate. 

78

Notes to the Consolidated Financial Statements

For  mining  activities,  property  acquisition,  construction  and  development  costs  are  capitalized.  The  Company  reviews  the 
recoverability of the carrying amount of its mining properties when events or circumstances indicate that the carrying amounts may 
not be recoverable.

(E)  DEPLETION, DEPRECIATION AND AMORTIZATION
Costs related to each 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.  Unproved  properties  are  assessed  periodically  to 
determine whether impairment has occurred. When proved reserves are assigned or the value of unproved property is considered to 
be impaired, the cost of the unproved property or the amount of the impairment is added to costs subject to depletion. Certain costs 
for major development projects are not subject to depletion until the projects are available for their intended uses. Processing and 
production facilities are depreciated on a straight-line basis over their estimated lives.

The Company reviews the carrying amount of its 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 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.

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.

Head ofﬁce capital assets are amortized on a declining balance basis over their estimated useful lives.

(F)  CAPITALIZED INTEREST
Beginning in 2005, following the Board of Directors’ approval of the Horizon Project, the Company commenced capitalization of 
construction period interest based on costs incurred and the Company’s cost of borrowing. Interest capitalization will cease once 
construction is substantially complete and the Horizon Project is available for its intended use.

(G)  DEFERRED CHARGES
Deferred charges primarily include deferred ﬁnancing costs associated with the issuance of long-term debt and settlement costs of 
long-term natural gas contracts. Deferred charges are amortized over the original term of the related instrument.

(H)  ASSET RETIREMENT OBLIGATIONS
The Company provides for future asset retirement obligations on its resource properties, facilities, production platforms and gathering 
system 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 life of the asset. 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.

(I)  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 the foreign currency translation adjustment 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 

Notes to the Consolidated Financial Statements
Notes to the Consolidated Financial Statements

79

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 items. Gains or losses on translation are 
included in the consolidated statement of earnings.

Gains or losses on the translation of long-term debt denominated in US dollars are either recognized in net earnings immediately, or 
in the foreign currency translation adjustment (note 8) for translation gains or losses for that portion of the US dollar denominated 
debt designated as a hedge of self-sustaining foreign operations.

(J)  REVENUE RECOGNITION
Revenue from the production of crude oil and natural gas is recognized when title passes to the customer and delivery has taken place. 
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. 

(K)  TRANSPORTATION COSTS
Transportation costs incurred to transport crude oil and natural gas to customers are recorded as a separate cost in the consolidated 
statement of earnings.

(L)  PRODUCTION SHARING CONTRACT
Production generated from Offshore West Africa is currently shared under the terms of various Production Sharing Contracts (“PSC”). 
Revenues are divided into cost recovery revenues and proﬁt revenues. Cost recovery revenues allow the Company to recover its share 
and the government’s share of capital and operating costs carried by the Company. Proﬁt revenues are allocated to the Company in 
accordance with its respective equity interest, after a portion has been allocated to the government. Cost recovery and proﬁt revenues 
are reported as sales revenues. The government’s share of revenues attributable to the Company’s equity interest, except for income 
tax, is reported as a royalty expense in accordance with the PSCs.

(M) PETROLEUM REVENUE TAX
The Company  accounts for the United Kingdom petroleum revenue tax  (“PRT”) by the  life-of-the-ﬁeld  method. The total future 
liability or recovery of PRT is estimated using current reserves and anticipated sales prices and costs. The estimated future PRT is 
apportioned to accounting periods on the basis of total estimated future operating income. Changes in the estimated total future PRT 
are accounted for prospectively.

(N)  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 on 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.

(O) STOCK-BASED COMPENSATION PLANS
The Company accounts for its stock-based compensation plans using the intrinsic value method. The Company’s Stock Option Plan 
(the “Option Plan”) provides current employees with the right to elect to receive common shares or 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. This liability is revalued at each reporting date to reﬂect changes in the market price of the Company’s common shares, 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.

80

Notes to the Consolidated Financial Statements

(P)  RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative ﬁnancial instruments to manage its commodity price, currency and interest rate exposures. 
These derivative ﬁnancial instruments are not used for trading or speculative purposes. Changes in fair value of derivative ﬁnancial 
instruments designated as hedges are not recognized in net earnings until such time as the corresponding gains or losses on the related 
hedged items are also recognized. Changes in fair value of derivative ﬁnancial instruments not designated as hedges are recognized in 
the balance sheet each period with the offset reﬂected in risk management activities in the consolidated statements of earnings.

The  Company  formally  documents  all  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. 

The Company 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. Gains or losses on these contracts are included in risk management activities.

The  Company  enters  into  interest  rate  swap  agreements  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. Gains or losses on interest rate swap contracts designated as hedges are included in interest expense. 
Gains or losses on non-designated interest rate contracts are included in risk management activities.

Cross currency swap agreements 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. Gains or losses on cross currency swap contracts designated as hedges are included in interest expense.

Gains or losses on the termination of ﬁnancial instruments that have been accounted for as hedges are deferred under other assets or 
liabilities on the consolidated balance sheets and amortized into net earnings in the period in which the underlying hedged transaction 
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 net earnings. Gains or losses on the termination of 
ﬁnancial instruments that have not been accounted for as hedges are recognized in net earnings immediately.

(Q)  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 included as a liability are used to purchase 
common shares at the average market price during the year. The dilutive effect of 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.

(R)  RECENTLY ISSUED ACCOUNTING STANDARDS UNDER CANADIAN GAAP
FINANCIAL INSTRUMENTS
In January 2005, the CICA issued four new standards relating to the accounting for and disclosure of ﬁnancial instruments. 

•   Section 3855 – “Financial Instruments – Recognition and Measurement” prescribes when a ﬁnancial asset, ﬁnancial liability, or 
non-ﬁnancial derivative is to be recognized on the balance sheet as well as its measurement amount. This Section also speciﬁes 
how ﬁnancial instruments gains and losses are to be presented. Transitional provisions for this Section vary based on the type of 
ﬁnancial instruments under consideration.

•   Section 3865 – “Hedges” expands on existing Accounting Guideline 13 – “Hedging Relationships,” and Section 1650 “Foreign 
Currency  Translation,”  by  specifying  how  hedge  accounting  is  to  be  applied  and  what  disclosures  are  necessary  when  it  is 
applied. Retroactive application of this Section is not permitted. 

•   Section  1530  –  “Comprehensive  Income”  introduces  new  standards  for  reporting  and  disclosure  of  comprehensive  income. 
Comprehensive income is the change in equity (net assets) of the Company during a reporting period from transactions and other 
events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from 
investments by owners and distributions to owners. Financial statements of prior periods are required to be restated only for 
non-ﬁnancial instrument items.

•   Section 3251 – “Equity” replaces Section 3250 “Surplus” and establishes standards for the presentation of equity and changes 
in  equity  during  a  reporting  period.  Financial  statements  of  prior  periods  are  required  to  be  restated  only  for  non-ﬁnancial 
instrument  items.  For  all  other  items,  comparative  ﬁnancial  statements  presented  are  not  restated,  but  an  adjustment  to  the 
opening balance of accumulated other comprehensive income may be required. 

Notes to the Consolidated Financial Statements

81

The Company plans to adopt these new standards for interim and annual ﬁ nancial statements effective January 1, 2007. The effect on 
the Company’s consolidated ﬁ nancial statements cannot be reasonably determined at this time as the ﬁ nancial derivatives outstanding 
at December 31, 2006 and their related fair values are not known.

(S)  COMPARATIVE FIGURES
Certain ﬁ gures provided for prior years have been reclassiﬁ ed to conform to the presentation adopted in 2005.

Common share data has been restated to reﬂ ect the two-for-one share split in May 2005.

2.  OTHER LONG-TERM ASSETS

Deferred charges 
Risk management (note 10)

Less: current portion    

3.  PROPERTY, PLANT AND EQUIPMENT
2005
Accumulated
depletion and
depreciation 

Cost 

Net

Cost 

2005

107 
– 
107 
– 
107 

$ 

$ 

2004
Accumulated
depletion and
depreciation 

Crude oil and natural gas
  North America  
  North Sea  
  Offshore West Africa  
  Other   
Horizon Project  
Midstream  
Head office  

$ 

$ 

22,258 
2,703 
1,547 
27 
2,169 
251 
124 
29,079 

$ 

$ 

7,948 
1,022 
294 
14 
– 
48 
59 
9,385 

$ 

$ 

14,310 
1,681 
1,253 
13 
2,169 
203 
65 
19,694 

$ 

$ 

19,750 
2,550 
1,091 
22 
672 
241 
101 
24,427 

$ 

$ 

6,356 
727 
190 
14 
– 
32 
44 
7,363 

2004

76
66
142
34
108

Net

13,394
1,823
901
8
672
209
57
17,064

$ 

$ 

$ 

$ 

During the year ended December 31, 2005, the Company capitalized administrative overhead of $41 million (2004 – $49 million, 
2003 – $35 million) relating to exploration and development in the North Sea and Offshore West Africa and $236 million (2004 
– $35 million, 2003 – $23 million) in North America, primarily related to the Horizon Project.

During  the  year  ended  December  31,  2005,  the  Company  capitalized  $72  million  (2004  and  2003  –  $nil)  in  construction  period 
interest costs related to the Horizon Project.

Included in property, plant and equipment are unproved properties and major development projects that are not subject to depletion 
or depreciation:

Crude oil and natural gas
  North America  
  North Sea  
  Offshore West Africa  
  Other   
Horizon Project  

2005

1,372 
28 
182 
13 
2,169 
3,764 

$ 

$ 

2004

1,028
44
528
8
672
2,280

$ 

$ 

82

Notes to the Consolidated Financial Statements

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The Company has used the following estimated benchmark future prices (“escalated pricing”) in its ceiling test prepared in accordance 
with Canadian GAAP, as at December 31, 2005:

2006

2007

2008

2009

2010 

Average
 annual change
 thereafter

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)

4.  LONG-TERM DEBT

$ 
$ 
$ 

$ 

$ 
$ 
$ 

60.81 
37.07 
70.07 

58.81 

11.59 
11.58 
11.34 

$ 
$ 
$ 

$ 

$ 
$ 
$ 

61.61 
37.29 
70.99 

59.58 

10.11 
10.84 
10.70 

$ 
$ 
$ 

$ 

$ 
$ 
$ 

54.60 
34.23 
62.73 

52.54 

8.50 
8.95 
8.81 

$ 
$ 
$ 

$ 

$ 
$ 
$ 

50.19 
32.27 
57.53 

48.10 

7.58 
7.87 
7.73 

Bank credit facilities
  Bankers’ acceptances 
  US dollar bankers’ acceptances (2005 – US$nil, 2004 – US$471 million)  
Medium-term notes
  7.40% unsecured debentures due March 1, 2007  
  4.95% unsecured debentures due June 1, 2015 
Senior unsecured notes 
  7.69% due December 19, 2005 (2005 – US$nil, 2004 – US$125 million)  
  Adjustable rate due May 27, 2009 (2005 – US$93 million, 2004 – US$93 million)  
Preferred securities
  8.30% due June 25, 2011 (2005 – US$nil, 2004 – US$80 million)  
US dollar debt securities
  6.70% due July 15, 2011 (2005 – US$400 million, 2004 – US$400 million)  
  5.45% due October 1, 2012 (2005 – US$350 million , 2004 – US$350 million)  
  4.90% due December 1, 2014 (2005 – US$350 million, 2004 – US$350 million)  
  7.20% due January 15, 2032 (2005 – US$400 million, 2004 – US$400 million)  
  6.45% due June 30, 2033 (2005 – US$350 million, 2004 – US$350 million)  
  5.85% due February 1, 2035 (2005 – US$350 million, 2004 – US$350 million)  

Less: current portion of long-term debt  

$ 
$ 
$ 

$ 

$ 
$ 
$ 

$ 

$ 

47.76 
31.15 
54.65 

45.64 

7.32 
7.57 
7.43 

1.5%
1.6%
1.5%

1.5%

1.5%
1.5%
1.5%

2005

2004

122 
– 

125 
400 

– 
108 

– 

467 
408 
408 
467 
408 
408 
3,321 
– 
3,321 

$  

$ 

–
557

125
–

194
112

96

482
421
421
482
421
421
3,732
194
3,538

BANK CREDIT FACILITIES
As at December 31, 2005 the Company had in place unsecured syndicated bank credit facilities of $3,425 million, comprised of:

  •   a $100 million operating demand facility;
  •   a two-tranche revolving credit and term loan facility of $1,825 million; and 
  •   a 5-year revolving and term loan facility of $1,500 million. 

The ﬁ rst $1,000 million tranche of the $1,825 million facility is fully revolving for a period of three years to June 2008. The second 
tranche of $825 million is fully revolving for a period of ﬁ ve years to June 2010. Both tranches are extendible annually for one-year 
periods at the mutual agreement of the Company and the lenders. If not extended, the full amount of the outstanding principal would 
be repayable at the end of year two following the initiation of the term period. The $1,500 million revolving credit and term loan 
facility has a ﬁ ve-year term, with three, one-year extension provisions. If the facility is not extended, the amount outstanding would 
be repayable in December 2009. These facilities provide that the borrowings may be made by way of operating advances, prime loans, 
bankers’ acceptances, US base rate loans or US dollar LIBOR advances, which bear interest at the bank’s prime rates or at money 
market rates plus applicable margins.
The weighted average interest rate of the bank credit facilities outstanding at December 31, 2005, was 5.44% (2004 – 3.47%).
The Company also has a £15 million demand overdraft credit facility related to the Company’s North Sea operations. At December 
31, 2005 there were no amounts drawn on this facility.
In addition to the outstanding debt, as at December 31, 2005 letters of credit aggregating $24 million (2004 – $24 million) have 
been issued.

Notes to the Consolidated Financial Statements

83

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MEDIUM-TERM NOTES
In May 2005, the Company issued $400 million of debt securities maturing June 2015, bearing interest at 4.95%. Proceeds from the 
securities issued were used to repay bankers’ acceptances under the Company’s bank credit facilities.

In May 2004, the Company repaid the $125 million 6.85% unsecured debentures due May 2004, which were issued under a previous 
medium-term note program.

In January 2006, the Company issued $400 million of debt securities maturing January 2013, bearing interest at 4.50%. 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 $1.6 billion remaining on its $2 billion shelf prospectus ﬁ led in August 2005 that allows for the issue 
of  medium-term  notes  in  Canada  until  September  2007.  If  issued,  these  securities  will  bear  interest  as  determined  at  the  date  of 
issuance.

SENIOR UNSECURED NOTES
In December 2005, the Company repaid the US$125 million 7.69% senior unsecured notes. The 6.42% senior unsecured notes were 
repaid in May 2004. 

The adjustable rate senior unsecured notes bear interest at 6.54% and have annual principal repayments of US$31 million commencing 
in May 2007, through May 2009. 

PREFERRED SECURITIES
In September 2005, the Company redeemed the US$80 million 8.30% preferred securities due May 25, 2011 for cash consideration 
of US$91 million, including an early repayment premium of US$11 million as required under the Note Purchase Program.

US DOLLAR DEBT SECURITIES
In June 2005, the Company ﬁ led a short form prospectus that allows for the issue of up to US$2 billion of debt securities in the United 
States until July 2007. If issued, these securities will bear interest determined as at the date of issuance.

In December 2004, the Company issued US$350 million of debt securities maturing December 2014, bearing interest at 4.90% and 
US$350 million of debt securities maturing February 2035, bearing interest at 5.85%. Proceeds from the securities issued were used 
to repay bankers’ acceptances under the Company’s bank credit facilities. The Company has entered into certain interest rate swap 
contracts to convert the ﬁ xed rate interest coupon into a ﬂ oating interest rate on the securities due December 2014 (note 10).

REQUIRED DEBT REPAYMENTS
Required debt repayments are as follows:

Year  

2006  
2007  
2008  
2009  
2010  
Thereafter

No debt repayments are reﬂ ected for the bank credit facilities due to the extendable nature of the facilities.

5.  OTHER LONG-TERM LIABILITIES

Asset retirement obligations  
Stock-based compensation  
Risk management (note 10)
Other  

Less: current portion    

84

Notes to the Consolidated Financial Statements

2005

1,112 
891 
885 
17 
2,905 
1,471 
1,434 

$ 

$ 

Repayment

$ 
$ 
$ 
$ 
$ 
$ 

$ 

$ 

–
161
36
36
–
2,966

2004

1,119
323
26
–
1,468
260
1,208

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ASSET RETIREMENT OBLIGATIONS
At December 31, 2005, the Company’s total estimated undiscounted costs to settle its asset retirement obligations with respect to crude 
oil and natural gas properties and facilities was approximately $3,325 million (2004 – $3,060 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 an 
average credit-adjusted risk-free interest rate of 6.8%. A reconciliation of the discounted asset retirement obligations is as follows:

Asset retirement obligations
Balance – beginning of year  
  Liabilities incurred    
  Liabilities settled  
  Asset retirement obligation accretion  
  Revision of estimates 
  Foreign exchange  
Balance – end of year    

2005

2004

1,119 
47 
(46) 
69 
(56) 
(21) 
1,112 

$ 

$ 

897
339
(32)
51
(86)
(50)
1,119

$ 

$ 

The Company’s pipelines have an indeterminant 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 ﬁ rst year in which the lives of the 
assets are determinable.

STOCK-BASED COMPENSATION
The  Company  recognizes  a  liability  for  the  potential  cash  settlements  under  its  Option  Plan.  The  current  portion  represents  the 
maximum amount of the liability payable within the next 12-month period if all vested options are surrendered for cash settlement.

Stock-based compensation 
Balance – beginning of year  
  Stock-based compensation provision  
  Cash payment for options surrendered  
  Transferred to common shares  
  Capitalized to Horizon Project  
Balance – end of year    
Less: current portion of stock-based compensation  

6.  TAXES
TAXES OTHER THAN INCOME TAX

Current petroleum revenue tax  
Deferred petroleum revenue tax recovery  
Provincial capital taxes and surcharges  

INCOME TAX
The provision for income tax is as follows:

Current income tax expense
  Current income tax – North America  
  Large Corporations Tax – North America  
  Current income tax – North Sea  
  Current income tax – Offshore West Africa  
  Current income tax – other  

Future income tax expense  
Income tax  

2005

2004

323 
723 
(227) 
(29) 
101 
891 
629 
262 

2004

190 
(45) 
20 
165 

$ 

$ 

$ 

$ 

171
249
(80)
(38)
21
323
243
80

2003

106
(9)
10
107

$ 

$ 

$ 

$ 

2005

181 
(9) 
22 
194 

2005

2004

2003

82 
16 
155 
32 
1 
286 
353 
639 

$ 

$ 

89 
11 
2 
13 
1 
116 
474 
590 

$ 

$ 

43
16
23
10
–
92
338
430

$ 

$ 

$ 

$ 

Notes to the Consolidated Financial Statements

85

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
285
(281)
16
(40)
20
(247)
(31)
(103)
4
10
430

2004

3,677
1,254
102
19
43

(418)
(92)
(54)
(106)
–
(58)
4,367
(83)
4,450

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  
  Large Corporations Tax  
  Deductible UK petroleum revenue tax  
  Foreign tax rate differentials  
  Federal income tax rate reductions  
  Provincial income tax rate reductions  
  Non-taxable portion of foreign exchange  
  Attributed Canadian Royalty Income 
  Other    
Income tax  

2005

38.0% 
716 

2004

39.3% 
849 

$ 

2003

41.1%
797

$ 

$ 

309 
(293) 
16 
(65) 
(1) 
– 
(19) 
(15) 
(21) 
12 
639 

$ 

221 
(270) 
11 
(57) 
(31) 
– 
(66) 
(36) 
(4) 
(27) 
590 

$ 

$ 

The following table summarizes the temporary differences that give rise to the net future income tax asset and liability:

Future income tax liabilities
  Property, plant and equipment  
  Timing of partnership items  
  Unrealized foreign exchange gain on long-term debt  
  Risk management activities 
  Other    
Future income tax assets
  Asset retirement obligations  
  Capital loss carryforwards  
  Attributed Canadian Royalty Income  
  Stock-based compensation  
  Risk management activities 
Deferred petroleum revenue tax  
Future income tax liability  
Less: future income tax asset 
Net future income tax liability  

2005

3,960 
1,646 
112 
– 
31 

(384) 
(79) 
(75) 
(300) 
(304) 
(59) 
4,548 
(487) 
5,035 

$ 

$ 

$ 

$ 

A signiﬁ cant portion of North America’s taxable income is generated by partnerships. Income taxes are incurred on the partnerships’ 
taxable income in the year following their inclusion in the Company’s consolidated net earnings. Current income tax will vary and is 
dependent upon the nature and amount of capital expenditures incurred in Canada.

During 2005, the Government of British Columbia enacted legislation to reduce its corporate income tax rate by 1.5%, effective 
July 1, 2005, resulting in a $19 million reduction in the Company’s future income tax liability.

During 2004, the Government of Alberta enacted legislation to reduce its corporate income tax rate by 1.0% effective April 1, 2004, 
resulting in a $66 million reduction in the Company’s future income tax liability.

During 2003, the Government of Alberta enacted legislation to reduce its corporate income tax rate by 0.5% effective April 1, 2003. 
Also during 2003, the Canadian federal government enacted legislation to change the taxation of resource income. The legislation 
reduces the corporate income tax rate on resource income from 28% to 21% over ﬁ ve years beginning January 1, 2003. Over the 
same period, the deduction for resource allowance is being phased out and a deduction for actual crown royalties paid is being phased 
in. The Company’s future income tax liability was reduced by $31 million with respect to the Alberta corporate income tax rate 
reduction and by $247 million with respect to the federal resource income tax rate changes.

86

Notes to the Consolidated Financial Statements

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7.  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 

Numbers of
shares
(thousands)

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    

536,361 
837 
– 
(850) 
536,348 

$ 

$ 

2005

2004

Numbers of
shares
(thousands) 

534,926 
3,182 
– 
(1,747) 
536,361 

$ 

$ 

Amount

2,353
24
38
(7)
2,408

Amount

2,408 
9 
29 
(4) 
2,442 

SHARE SPLIT
The Company’s shareholders approved a subdivision or share split of its issued and outstanding common shares on a two-for-one 
basis at the Company’s Annual and Special Meeting held on May 5, 2005. All common share and per common share amounts have 
been restated to retroactively reﬂ ect the share split.

NORMAL COURSE ISSUER BID
In January 2005, the Company announced the renewal of its Normal Course Issuer Bid through the facilities of the Toronto Stock 
Exchange and the New York Stock Exchange to purchase up to 26,818,012 common shares or 5% of the outstanding common shares 
of the Company on the date of announcement, during the 12-month period beginning January 24, 2005 and ending January 23, 2006. 
As at December 31, 2005, the Company had purchased 850,000 common shares (2004 – 1,746,800 common shares) at an average 
price of $53.29 per common share (2004 – $19.00 per common share), for a total cost of $45 million (2004 – $33 million). Retained 
earnings was reduced by $41 million (2004 – $26 million), representing the excess of the purchase price of the common shares over 
their stated value. 

On January 20, 2006, the Company announced the renewal of its Normal Course Issuer Bid through the facilities of the Toronto Stock 
Exchange and the New York Stock Exchange to purchase up to 26,852,545 common shares or 5% of the outstanding common shares of 
the Company on the date of the announcement, during the 12-month period beginning January 24, 2006 and ending January 23, 2007.
As at February 21, 2006, the Company had not purchased any additional shares under the Normal Course Issuer Bid.

DIVIDEND POLICY
The Company pays regular quarterly dividends in January, April, July and October of each year. 

On  February  21,  2006,  the  Board  of  Directors  set  the  Company’s  regular  quarterly  dividend  at  $0.075  per  common  share
(2005 – $0.059 per common share, 2004 – $0.050 per common share). 

STOCK OPTIONS
The Option Plan provides for granting of stock options to employees. Stock options granted under the Option Plan have a maximum 
term of six years to expiry and vest equally over a ﬁ ve-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 
permits the holder to purchase one common share of the Company at the stated exercise price.

In June 2003 the Company approved a modiﬁ cation to its Option Plan providing the stock option holder the right to elect to receive 
a cash payment equal to the difference between the exercise price of the stock option and the market price of the Company’s common 
shares on the date of surrender, multiplied by the number of common shares covered by the stock options surrendered, in lieu of 
receiving common shares. The modiﬁ cation to the Option Plan was accounted for prospectively.

Notes to the Consolidated Financial Statements

87

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
For the year ended December 31, 2005, the Company recorded stock-based compensation expense of $723 million (2004 – $249 million, 
2003 – $200 million). In 2005, $101 million was capitalized to the Horizon Project (2004 – $21 million, 2003 – $10 million). As at 
December 31, 2005, the total liability for expected cash settlements under the Option Plan was $891 million (2004 – $323 million), 
of which $629 million (2004 – $243 million) was included as a current liability. During the year ended December 31, 2005, cash 
payments of $227 million were made for 7,523,000 stock options surrendered (2004 – cash payments of $80 million for 7,562,000 
stock options surrendered). The following table summarizes information relating to stock options outstanding at December 31, 2005 
and 2004:

Outstanding – beginning of year  
Granted    
Exercised for common shares  
Surrendered for cash settlement  
Forfeited   
Outstanding – end of year  
Exercisable – end of year  

2005

2004

Stock 
options 
(thousands)

32,522 
7,959 
(837) 
(7,523) 
(1,611) 
30,510 
8,677 

$ 
$ 
$ 
$ 
$ 
$ 
$ 

Weighted
average
exercise 
price

12.37 
32.51 
9.81 
10.49 
19.36 
17.79 
11.21 

Stock 
options 
(thousands)  

35,578 
9,722 
(3,182) 
(7,562) 
(2,034) 
32,522 
7,632 

$ 
$ 
$ 
$ 
$ 
$ 
$ 

Weighted
average
exercise
price

9.86
17.95
7.55
9.36
13.86
12.37
9.92

The range of exercise prices of stock options outstanding and exercisable at December 31, 2005 was as follows:

Range of exercise prices 

$7.85 – $9.99 
$10.00 – $14.99  
$15.00 – $19.99  
$20.00 – $24.99  
$25.00 – $29.99  
$30.00 – $34.99  
$40.00 – $44.99  
$45.00 – $49.99  
$50.00 – $54.99  
$55.00 – $59.35  

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

8,794 
6,690 
6,234 
1,568 
4,301 
1,449 
201 
251 
600 
422 
30,510 

1.41 
2.50 
3.53 
4.82 
4.18 
4.84 
5.45 
5.54 
5.72 
5.88 
3.02 

$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 

9.63 
11.74 
17.07 
22.89 
26.26 
33.22 
40.25 
47.16 
54.43 
55.89 
17.79 

4,835 
2,780 
883 
176 
3 
– 
– 
– 
– 
– 
8,677 

$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 
$ 

9.54
11.54
17.05
22.55
26.26
–
–
–
–
–
11.21

8.  FOREIGN CURRENCY TRANSLATION ADJUSTMENT
The foreign currency translation adjustment represents the unrealized gain (loss) on the Company’s net investment in self-sustaining 
foreign  operations.  Effective  July  1,  2002,  the  Company  designated  certain  US  dollar  denominated  debt  as  a  hedge  against  its 
net  investment  in  US  dollar-based  self-sustaining  foreign  operations.  Accordingly,  translation  gains  and  losses  on  this  US  dollar 
denominated debt are included in the foreign currency translation adjustment.

Balance – beginning of year 
  Unrealized loss on translation of net investment  
  Hedge of net investment with US dollar denominated debt, net of tax  
Balance – end of year    

2005

2004

(6) 
(12) 
9 
(9) 

$ 

$ 

3
(24)
15
(6)

$ 

$ 

88

Notes to the Consolidated Financial Statements

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9.  NET EARNINGS PER COMMON SHARE
The following table provides a reconciliation between basic and diluted amounts per common share:

(thousands of shares)
Weighted average common shares outstanding – basic  
Effect of dilutive stock options (1)
Assumed settlement of preferred securities with common shares  
Weighted average common shares outstanding – diluted  
Net earnings  
Interest on preferred securities, net of tax  
Revaluation of preferred securities, net of tax  
Diluted net earnings  
Net earnings per common share
  Basic  
  Diluted  

2005 

2004(2) 

2003(2)

536,650 
– 
1,775 
538,425 
1,050 
4 
(2) 
1,052 

1.96 
1.95 

536,223 
– 
4,461 
540,684 
1,405 
5 
(4) 
1,406 

2.62 
2.60 

$ 

$ 

$ 
$ 

536,940
4,889
7,816
549,645
1,403
5
(18)
1,390

2.62
2.53

$ 

$ 

$ 
$ 

$ 

$ 

$ 
$ 

(1)  The Option Plan described in note 7 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 diluted earnings per share effective from June 2003, the date of the modification.

(2) Restated to reflect two-for-one share split in May 2005.

10. FINANCIAL INSTRUMENTS
RISK MANAGEMENT
On January 1, 2004, the fair values of all outstanding derivative ﬁ nancial instruments that were not designated as hedges for accounting 
purposes were recorded on the consolidated balance sheet, with an offsetting net deferred revenue amount. Subsequent net changes 
in the fair value of non-designated ﬁ nancial instruments have been recognized on the consolidated balance sheet and in net earnings. 
The estimated fair value for all derivative ﬁ nancial instruments is based on third party indications.

As at December 31, 2005 and 2004, the estimated fair values of non-designated ﬁ nancial derivatives were comprised as follows:

2005

2004

Risk
management 
mark-to-market 

Deferred 
 revenue 

Risk
 management 
 mark-to-market 

Deferred
 revenue

Balance – beginning of year 
  Net cost of put options outstanding as at December 31   
  Net change in fair value of financial instruments

$ 

$ 

66 
190 

$ 

(26) 
– 

$ 

40 
38 

  outstanding as at December 31 
  Amortization of deferred revenue 
Balance – end of year   
Less: put premium financing obligations   

Less: current portion (1)  

(943) 
– 
(687) 
(190) 
(877) 
834 
(43) 

$ 

$ 

– 
18 
(8) 
– 
(8) 
8 
– 

(1) The Company has negotiated payment of put option premiums with various counterparties at the time of actual settlement of the respective option.

Net losses (gains) from risk management activities for the years ended December 31 were as follows:

Net realized risk management loss 
Net unrealized risk management loss (gain) 

2005 

1,027 
925 
1,952 

$ 

$ 

26 
– 
104 
(38) 
66 
34 
32 

2004

474 
(40) 
434 

$ 

$ 

$ 

$ 

$ 

$ 

(40)
–

–
14
(26)
–
(26)
17
(9)

2003

148
–
148

As  at  December  31,  2005,  the  net  unrecognized  liability  related  to  the  estimated  fair  values  of  derivative  ﬁ nancial  instruments 
designated as hedges was $990 million (December 31, 2004 – net unrecognized asset of $33 million).

Notes to the Consolidated Financial Statements

89

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
FINANCIAL CONTRACTS
The Company’s ﬁ nancial instruments recognized in the consolidated balance sheets consist of cash, accounts receivable, accounts 
payable, accrued liabilities, risk management activities, stock-based compensation and long-term debt.

The  estimated  fair  values  of  ﬁ nancial  instruments  have  been  determined  based  on  the  Company’s  assessment  of  available  market 
information,  appropriate  valuation  methodologies  and  third  party  indications.  However,  these  estimates  may  not  necessarily  be 
indicative of the amounts that could be realized or settled in a current market transaction.

The carrying value of cash, accounts receivable, accounts payable, accrued liabilities, stock-based compensation and long-term debt 
with variable interest rates approximate their fair value.

The estimated fair values of other ﬁ nancial instruments were as follows:

Asset (liability)
Derivative financial instruments  
Fixed rate notes  

2005

2004

Carrying value 

Fair value  Carrying value 

Fair value

$ 
$ 

(687) 
( 3,199) 

$ 
$ 

(1,700) 
( 3,367) 

$ 
$ 

66 
(3,175) 

$ 
$ 

33
(3,364)

COMMODITY PRICE RISK MANAGEMENT
The Company uses certain derivative ﬁ nancial instruments to manage its commodity price exposures. These ﬁ nancial instruments 
are entered into solely for hedging purposes and are not used for trading or other speculative purposes. The following summarizes 
transactions outstanding as at December 31, 2005:

Crude oil
Crude oil price collars 

Crude oil puts (1)

Brent differential swaps 

Remaining term 

Volume 

Average price 

Index

Jan 2006 – Dec 2006 
Jan 2006 – Dec 2006 
Jan 2006 – Dec 2006 
Mar 2006 – Jul 2006 
Aug 2006 – Dec 2006 
Jan 2007 – Dec 2007 
Jan 2007 – Dec 2007 
Jan 2006 – Dec 2006 
Jan 2007 – Dec 2007 

167,644 bbl/d 
82,356 bbl/d 
22,000 bbl/d 
55,000 bbl/d 
51,000 bbl/d 
100,000 bbl/d 
100,000 bbl/d 
25,000 bbl/d 
50,000 bbl/d 

US$38.26 – US$48.28 
US$44.75 – US$76.93 
C$46.53 – C$58.67 
US$40.00
US$45.00
US$28.00
US$45.00
US$1.29 
US$1.34 

WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI/Dated Brent
WTI/Dated Brent

(1) Subsequent to year end, the Company settled 17,000 bbl/d of the US$40.00 put options for 2006 and purchased 100,000 bbl/d of US$50.00 put options for 2007.

Remaining term 

Volume 

Average price 

Natural gas
AECO collars 

Jan 2006 – Mar 2006 
Jan 2006 – Mar 2006 
Jan 2006 – Mar 2006 
Apr 2006 – Jun 2006 
Apr 2006 – Jun 2006 
Jul 2006 – Sep 2006 
Jul 2006 – Sep 2006 
Oct 2006 – Dec 2006 
Oct 2006 – Dec 2006 
Oct 2006 – Dec 2006 
Jan 2007 – Mar 2007 

700,000 GJ/d 
400,000 GJ/d 
100,000 GJ/d 
993,000 GJ/d 
100,000 GJ/d 
725,000 GJ/d 
100,000 GJ/d 
244,000 GJ/d 
100,000 GJ/d 
464,000 GJ/d 
700,000 GJ/d 

C$5.88 – C$8.78 
C$6.00 – C$12.29 
C$8.00 – C$27.75 
C$5.71 – C$8.13 
C$7.00 – C$14.16 
C$5.60 – C$7.59 
C$7.00 – C$14.16 
C$5.60 – C$7.59 
C$7.00 – C$14.16 
C$7.50 – C$18.80 
C$7.50 – C$18.80 

Index

AECO
AECO
AECO
AECO
AECO
AECO
AECO
AECO
AECO
AECO
AECO

Commodity related derivative ﬁ nancial instruments designated as hedges at December 31, 2005, were all classiﬁ ed as cash ﬂ ow hedges.

90

Notes to the Consolidated Financial Statements

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 agreements 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, 2005, the Company had the following interest rate swap contracts outstanding:

Remaining term

Amount ($ millions)

Fixed rate

Floating rate

Interest rate
Swaps – fixed to floating

Swaps – floating to fixed

Jan 2006  – Jan 2007
Jan 2006  – Oct 2012
Jan 2006  – Dec 2014
Jan 2006 –  Mar 2007 

US$200 (2)
US$350
US$350
C$6

7.20%
5.45%
4.90%
7.36%

LIBOR (1) + 2.23% 
LIBOR (1) + 0.81%
LIBOR (1) + 0.38%
CDOR (3)

(1) London Interbank Offered Rate
(2) Subsequent to year end the Company received approximately $1 million in settlement of the 7.20% fixed to floating rate swap.
(3) Canadian Deposit Overnight Rate

Interest rate related derivative ﬁnancial instruments designated as hedges at December 31, 2005, were all classiﬁed as fair value hedges.

FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
The Company is exposed to foreign exchange rate risk in Canada on its US dollar denominated debt and on product sales based 
on US dollar denominated benchmarks. The Company is also exposed to foreign exchange rate risk on transactions conducted in 
foreign currencies in its foreign subsidiaries and in the carrying value of its self sustaining foreign subsidiaries. Cross currency swap 
agreements 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. The Company may also enter into foreign currency denominated ﬁnancial instruments to manage future US 
dollar denominated crude oil and natural gas sales. The Company has designated certain US dollar denominated debt as a hedge 
against its net investment in US dollar-based self-sustaining foreign operations (note 8).

COUNTERPARTY CREDIT RISK MANAGEMENT
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  this  risk  by  entering  into  sales  contracts  with  only  highly  rated  entities.  In  addition,  the  Company 
reviews 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. The Company is also exposed to possible losses in the event of non-
performance by counterparties to derivative ﬁnancial instruments; however, the Company manages this credit risk by entering into 
agreements with only highly rated ﬁnancial institutions and other entities.

11. COMMITMENTS
The Company has committed to certain payments as follows:

Product transportation and pipeline (1)
Offshore equipment operating lease 
Offshore drilling 
Asset retirement obligations (2)
Other (3) 

$
$
$
$
$

2006

195
51
132
82
61

$
$
$
$
$

2007

133
51
100
4
62

$
$
$
$
$

2008

148
52
35
4
21

$
$
$
$
$

2009

2010

Thereafter

94
51
–
4
29

$
$
$
$
$

85
51
–
7
23

$
$
$
$
$

1,111
180
–
3,224
8

(1) During the year, the Company entered into a 25 year pipeline transportation agreement commencing in 2008, related to future crude oil production. The agreement is renewable for successive 

10-year periods at the Company’s option. During the initial term, annual toll payments before operating costs will be approximately $35 million.

(2) Represents management’s estimate of the future undiscounted payments to settle asset retirement obligations related to resource properties, facilities, production platforms and pipelines, based 

on current legislation and industry operating practices.

(3) Consists of future expenditures related primarily to office lease, electricity and crude oil processing.

The Board of Directors has approved the construction costs for Phase 1 of the Horizon Project, which are budgeted to be $6.8 billion, 
including a contingency fund of $700 million, with $1.3 billion incurred in 2005, $2.6 billion to be incurred in 2006 and $2.9 billion 
to be incurred in 2007 and 2008.

The Company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. The Company believes 
that any liabilities that might arise pertaining to such matters would not have a material effect on its consolidated ﬁnancial position.

Notes to the Consolidated Financial Statements

91

 
 
 
 
 
 
 
 
 
 
12. 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  

2005

2004

2003

$ 

$ 

$ 

$ 

$ 
$ 

(498) 
196 
716 
414 

(147) 
19 
542 
414 

200 
430 

$ 

$ 

$ 

$ 

$ 
$ 

(329) 
39 
194 
(96) 

(14) 
6 
(88) 
(96) 

192 
218 

$ 

$ 

$ 

$ 

$ 
$ 

35
125
122
282

(48)
(11)
341
282

178
51

13. SEGMENTED INFORMATION
The  Company’s  crude  oil  and  natural  gas  activities  are  conducted  in  three  geographic  segments:  North  America,  North  Sea  and 
Offshore West Africa. These activities relate to the exploration, development, production and marketing of crude oil, natural gas 
liquids and natural gas.

The Company’s Horizon Project has been classiﬁ ed as a separate segment. As the bitumen will be recovered through mining operations, 
this project constitutes a distinct segment from crude oil and natural gas activities. 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 included in the segmented information as other.

Inter-segment eliminations include internal transportation and electricity charges.

North America 

2005 

  2004 

  2003 

Crude oil and natural gas
North Sea 
  2004 

  2003 

  2005 

$  7,932 
(1,350) 
  6,582 

$ 5,979 
  (1,003) 
  4,976 

$ 5,021 
(868) 
  4,153 

$  1,659 
(3) 
  1,656 

$ 1,317 
(2) 
  1,315 

$  953 
1 
954 

  1,211 
287 

976 
256 

845 
264 

  1,595 

  1,444 

  1,209 

34 

28 

26 

870 
  3,997 

362 
  3,066 

157 
  2,501 

379 
20 

306 

34 

157 
896 

370 
32 

265 

22 

112 
801 

314 
30 

252 

36 

(9) 
623 

Offshore West Africa 

  2005 

  2004 

  2003 

$  485 
(13) 
472 

$  222 
(6) 
216 

$  155 
(5) 
150 

53 
– 

104 

1 

– 
158 

36 
– 

53 

1 

– 
90 

38 
– 

41 

– 

– 
79 

$  2,585  

$ 1,910  

$ 1,652  

$  760  

$  514  

$  331  

$  314  

$  126  

$ 

71  

Segmented revenue  
Less: royalties  
Revenue, net of royalties  
Segmented expenses
Production  
Transportation  
Depletion, depreciation
  and amortization  
Asset retirement
  obligation accretion  
Realized risk
  management activities  
Total segmented expenses
Segmented earnings
  before the following 

Non-segmented expenses
Administration
Stock-based compensation 
Interest
Unrealized risk management activities 
Foreign exchange gain 
Total non-segmented expenses 
Earnings before taxes 
Taxes other than income tax 
Current income tax expense  
Future income tax expense   
Net earnings

92

Notes to the Consolidated Financial Statements

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  2005 

Midstream 
  2004 

Inter-segment elimination and other 

  2003 

  2005 

  2004 

  2003 

$ 

77 
– 
77 

24 
– 

8 

– 

– 
32 

$ 

68 
–  
68 

20 
–  

7 

–  

–  
27 

$ 

61 
– 
61 

15 
– 

7 

– 

– 
22 

$ 

(46) 
– 
(46) 

(4) 
(37) 

– 

– 

– 
(41) 

$ 

(39) 
– 
(39) 

(2) 
(38) 

– 

– 

– 
(40) 

$ 

(35) 
– 
(35) 

(3) 
(32) 

– 

– 

  2005 

$ 10,107 
  (1,366) 
  8,741 

Total
  2004 

$ 7,547 
  (1,011) 
  6,536 

  2003

$ 6,155 
(872)
  5,283

  1,663 
270 

  1,400 
250 

  1,209
262

  2,013 

  1,769 

  1,509

69 

51 

62

– 
(35) 

  1,027 
  5,042 

474 
  3,944 

148
  3,190

$ 

45  

$ 

41  

$ 

39  

$ 

(5) 

$ 

1 

$ 

– 

  3,699 

  2,592 

  2,093

151 
723 
149 
925 
(132) 
  1,816 
  1,883 
194 
286 
353 
$  1,050 

125 
249 
189 
(40) 
(91) 
432 
  2,160 
165 
116 
474 
$ 1,405 

87
200
201
–
(335)
153
  1,940
107
92
338
$ 1,403 

Notes to the Consolidated Financial Statements

93

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CAPITAL EXPENDITURES

2005
Non-cash and
fair value 
adjustments (1)

2004 
  Non-cash and
fair value 
adjustments (1)

Cash 
expenditures 

Capitalized
costs 

Cash 
expenditures 

Capitalized
costs

Crude oil and natural gas 
  North America  
  North Sea  
  Offshore West Africa 
  Other   

Horizon Project  
Midstream  
Head office  

$ 

$ 

2,530  
387 
439 
5 
3,361 
1,499 
4 
22 
4,886  

$ 

$ 

(22) 
(136) 
27 
– 
(131) 
– 
– 
– 
(131) 

$ 

$ 

2,508 
251 
466 
5 
3,230  
1,499 
4 
22 
4,755  

$ 

$ 

3,329  
608 
295 
1 
4,233 
291 
16 
35 
4,575  

(1) Asset retirement obligations, future income tax adjustments on non-tax base assets, and other fair value adjustments.

Segmented property, plant and equipment, net  

Crude oil and natural gas 
North America  
North Sea  
Offshore West Africa    
Other 
Horizon Project  
Midstream  
Head office  

Segmented assets 

Crude oil and natural gas 
North America  
North Sea  
Offshore West Africa    
Other 
Horizon Project  
Midstream  
Head office  

$ 

$ 

$ 

$ 

$ 

$ 

508  
172 
– 
– 
680 
– 
– 
– 
680  

2005

14,310 
1,681 
1,253 
13 
2,169 
203 
65 
19,694 

2005

15,939 
1,950 
1,371 
30 
2,239 
258 
65 
21,852 

$ 

$ 

$ 

$ 

$ 

$ 

3,837 
780
295
1
4,913
291
16
35
5,255 

2004

13,394
1,823
901
8
672
209
57
17,064

2004

14,390
2,036
914
35
672
268
57
18,372

14. BUSINESS COMBINATIONS
PETROVERA PARTNERSHIP
In February 2004, the Company acquired certain resource properties in its Northern Plains core region, collectively known as the 
Petrovera Partnership (“Petrovera”), for $471 million.

The acquisition was accounted for based on the purchase method. Results from Petrovera are consolidated with the results of the 
Company effective from the date of acquisition. The allocation of the purchase price to assets acquired and liabilities assumed based 
on their fair values was as follows:

Purchase price: 
Cash consideration  
Cash acquired  
Non-cash working capital deficit assumed  
Total purchase price  

Purchase price allocated as follows: 
Property, plant and equipment  
Future income tax liability  
Asset retirement obligation  

94

Notes to the Consolidated Financial Statements

February 1, 2004

$ 

$ 

$ 

$ 

467
(23)
27
471

643
(129)
(43)
471

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15.  DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY 

ACCEPTED ACCOUNTING PRINCIPLES

The Company’s consolidated ﬁ nancial statements have been prepared in accordance with generally accepted accounting principles in 
Canada (“Canadian GAAP”). These principles conform in all material respects with those in the United States (“US GAAP”) except 
for those noted below. Differences arising from US GAAP disclosure requirements are not addressed.

The application of US GAAP would have the following effects on consolidated net earnings as reported:

(millions of Canadian dollars, except per common share amounts)  

Notes

2005

2004

Net earnings – Canadian GAAP  
Adjustments
  Depletion, net of tax of $3 million (2004 – $2 million; 2003 – $3 million)   
  Derivative financial instruments and hedging activities,

  net of tax of $11 million (2004 – $7 million; 2003 – $20 million)   

  Capitalized interest, net of tax of $11 million 
  Cumulative effect of change in accounting policy, net of tax of $3 million   
Net earnings – US GAAP  

Net earnings – US GAAP per common share
  Basic  
  Diluted  

Comprehensive income under US GAAP would be as follows:

(millions of Canadian dollars) 

Net earnings – US GAAP  
  Derivative financial instruments and hedging activities,

  net of tax of $312 million (2004 – $3 million; 2003 – $9 million)   

  Foreign currency translation adjustment  
  Comprehensive income  

(A)

(B)
(C)
(D)

$ 

1,050 

$ 

1,405 

$ 

4 

4 

(19) 
– 
– 
1,035 

1.93 
1.93 

$ 

$ 
$ 

(9) 
16 
– 
1,416 

2.64 
2.62 

$ 

$ 
$ 

$ 

$ 
$ 

Notes

2005

2004

$ 

1,035 

$ 

1,416 

$ 

(B)
(E)

$ 

(635) 
(3) 
397 

$ 

8 
(9) 
1,415 

The application of US GAAP would have the following effects on the consolidated balance sheets as reported:

(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  
Shareholders’ equity  

(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  
Shareholders’ equity  

Notes

(B)
(A,C)

(B)
(B)
(B)
(A,B,C)
(B,E)

Notes 

(B) 
(A,C) 

(B) 

(A,B,C) 
(B,E) 

Canadian 
GAAP 

2005

Increase 
 (decrease) 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

2,051 
19,694 
107 
21,852 

3,825 
3,321 
1,434 
5,035 
8,237 
21,852 

Canadian 
GAAP 

1,200 
17,064 
108 
18,372 

1,852 
3,538 
1,208 
4,450 
7,324 
18,372 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

338 
(20) 
– 
318 

1,005 
(18) 
8 
(5) 
(672) 
318 

2004

Increase 
 (decrease) 

(33) 
(27) 
– 
(60) 

(44) 
– 
– 
6 
(22) 
(60) 

2003

1,403

4

(49)
–
(4)
1,354

2.52
2.44

2003

1,354

20
(23)
1,351

US
GAAP

2,389
19,674
107
22,170

4,830
3,303
1,442
5,030
7,565
22,170

US
GAAP

1,167
17,037
108
18,312

1,808
3,538
1,208
4,456
7,302
18,312

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

Notes to the Consolidated Financial Statements

95

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES:
(A)   Under Canadian full cost accounting rules, costs capitalized in each cost centre, net of future income taxes, 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”).  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%.

(B)   The Company accounts for its derivative ﬁnancial instruments under Canadian GAAP as described in note 1(P). For US GAAP 
purposes,  Financial  Accounting  Standards  Board  Statement  (“FAS”)  133,  “Accounting  for  Derivative  Financial  Instruments 
and Hedging Activities,” as amended by FAS 138 and FAS 149, establishes US GAAP accounting and reporting standards for 
derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. Generally, 
all derivatives, whether designated in hedging relationships or not, and excluding normal purchases and normal sales, are required 
to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, changes in the fair value of 
the derivative and changes in the fair value of the hedged item attributable to the hedged risk are recognized in the consolidated 
statements of earnings each period. If the derivative is designated as a cash ﬂow hedge, the effective portions of the changes in 
fair value of the derivative are initially recorded in other comprehensive income (“OCI”) each period and are recognized in the 
consolidated statements of earnings when the hedged item is recognized. Therefore, ineffective portions of changes in the fair value 
of hedging instruments are recognized in net earnings immediately for both fair value and cash ﬂow hedges.

 The  determination  of  hedge  effectiveness  and  the  measurement  of  hedge  ineffectiveness  of  cash  ﬂow  hedges  is  based  on  a 
combination of third party indications and internally derived valuations. The Company uses these valuations to estimate the fair 
values of the underlying physical commodity contracts.

(C)   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 has 
been capitalized to the costs of construction beginning in 2004.

(D)   Under  Canadian  GAAP,  when  the  asset  retirement  obligation  standard  was  adopted  prior  period  comparative  balances  were 
restated to reﬂect the effect of the new standard on that year. Under US GAAP, when the asset retirement obligation standard was 
adopted the cumulative effect of the new standard on prior periods was included in earnings in the year adopted.

(E)   Under  US  GAAP,  exchange  gains  and  losses  arising  from  the  translation  of  self-sustaining  foreign  operations  are  included  in 

comprehensive income.

(F)   Recently issued accounting standards under US GAAP:

SHARE-BASED PAYMENT
In  December  2004,  the  Financial  Accounting  Standards  Board  (“FASB”)  issued  FAS  123(R)  “Share-Based  Payment,”  which  is  a 
revision of FAS 123. This standard requires all companies to reﬂect stock based compensation in their statement of earnings for US 
GAAP. The fair value of stock options must be recognized at the date of grant using option pricing models. The fair value must be 
remeasured each quarter and changes in fair value must ﬂow through the statement of earnings. This is a difference from Canadian 
GAAP, where the Company’s options are valued at the difference between the exercise price and the stock price. This standard is 
effective for the ﬁrst interim or annual reporting period of a registrant’s ﬁrst ﬁscal year beginning on or after June 15, 2005. The 
Company plans to adopt this standard January 1, 2006.

ACCOUNTING CHANGES AND ERROR CORRECTIONS
In May 2005, the FASB issued FAS 154 “Accounting Changes and Error Corrections,” which replaces FAS 3 “Reporting Accounting 
Changes in Interim Financial Statements” and APB Opinion 20 “Accounting Changes.” The previous standards required that changes 
in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the 
new accounting principle. The new standard requires that accounting changes be applied retrospectively and that prior accounting 
periods be restated as if the accounting principle had always been used. This change eliminates a difference from Canadian GAAP. 
The new standard will be applied to all future US GAAP accounting policy changes.

96

Notes to the Consolidated Financial Statements

 
 
Supplementary Oil & Gas Information (unaudited)

This supplementary oil and natural gas information is provided in accordance with the United States FAS 69, “Disclosures about Oil 
and Gas Producing Activities”, and where applicable is reconciled to the US GAAP ﬁnancial information.

NET PROVED OIL AND NATURAL GAS RESERVES
The Company retains qualiﬁed independent reserves evaluators to evaluate the Company’s proved oil and natural gas reserves.

•   For the year ended December 31, 2005, the reports by Sproule Associates Limited (“Sproule”) and Ryder Scott Company covered 

100% of the Company’s conventional reserves;

•   For  the  year  ended  December  31,  2004,  the  reports  by  Sproule  and  Ryder  Scott  Company  covered  100%  of  the  Company’s 

conventional reserves;

•   For the year ended December 31, 2003, the reports by Sproule covered 100% of the Company’s conventional reserves; and
•   For the year ended December 31, 2002, the reports by Sproule covered 89% of the Company’s conventional reserves.

Proved oil and natural gas reserves are the estimated quantities of oil, natural gas and natural gas liquids 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 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, 2005, 2004 and 2003:

Crude oil and NGLs (mmbbl)

Net proved reserves
Reserves, December 31, 2002
Extensions and discoveries 
Improved recovery  
Purchases of reserves in place  
Sales of reserves in place 
Production  
Revisions of previous estimates  
Reserves, December 31, 2003
Extensions and discoveries 
Improved recovery  
Purchases of reserves in place  
Sales of reserves in place 
Production  
Revisions of previous estimates  
Reserves, December 31, 2004 
Extensions and discoveries 
Improved recovery  
Purchases of reserves in place  
Sales of reserves in place 
Production  
Revisions of previous estimates  
Reserves, December 31, 2005 
Net proved developed reserves:

December 31, 2002   
December 31, 2003   
December 31, 2004   
  December 31, 2005    

North America

North Sea

Offshore
 West Africa

571 
1 
63 
7 
– 
(56) 
2 
588 
17 
25 
36 
– 
(66) 
48 
648 
98 
3 
– 
(3) 
(70) 
18 
694 

340 
348 
367 
402 

202 
– 
– 
27 
– 
(21) 
14 
222 
– 
45 
38 
– 
(24) 
22 
303 
– 
3 
– 
– 
(25) 
9 
290 

107 
138 
218 
214 

75 
13 
– 
– 
– 
(4) 
1 
85 
– 
– 
– 
– 
(4) 
34 
115 
– 
2 
15 
– 
(8) 
10 
134 

27 
23 
20 
80 

Total

848
14
63
34
–
(81)
17
895
17
70
74
–
(94)
104
1,066
98
8
15
(3)
(103)
37
1,118

474
509
605
696

Supplementary Oil & Gas Information

97

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas (bcf)

Net proved reserves
Reserves, December 31, 2002  
Extensions and discoveries  
Improved recovery  
Purchases of reserves in place  
Sales of reserves in place  
Production  
Revisions of previous estimates  
Reserves, December 31, 2003 
Extensions and discoveries  
Improved recovery  
Purchases of reserves in place  
Sales of reserves in place  
Production  
Revision of previous estimates  
Reserves, December 31, 2004
Extensions and discoveries  
Improved recovery  
Purchases of reserves in place  
Sales of reserves in place  
Production  
Revision of previous estimates  
Reserves, December 31, 2005
Net proved developed reserves: 
  December 31, 2002   
  December 31, 2003   
  December 31, 2004   
  December 31, 2005 

  North America 

North Sea 

Offshore
 West Africa 

2,446 
58 
251 
50 
(3) 
(355) 
(21) 
2,426 
334 
80 
182 
(8) 
(383) 
(40) 
2,591 
506 
30 
6 
(23) 
(411) 
42 
2,741 

2,185 
2,140 
2,213 
2,300 

71 
– 
– 
19 
– 
(17) 
(11) 
62 
– 
– 
10 
– 
(18) 
(27) 
27 
– 
– 
– 
– 
(7) 
9 
29 

57 
46 
12 
16 

71 
6 
– 
– 
– 
(3) 
(10) 
64 
– 
– 
– 
– 
(3) 
11 
72 
– 
– 
– 
– 
(1) 
1 
72 

27 
12 
5 
10 

CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS ACTIVITIES

North 
America 

20,886 
1,372 
22,258 
(7,993) 
14,265 

North 
America 

18,749 
1,028 
19,777 
(6,410) 
13,367 

North 
America 

15,125 
789 
15,914 
(4,984) 
10,930 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

North 
 Sea 

2,675 
28 
2,703 
(1,022) 
1,681 

North 
 Sea 

2,506 
44 
2,550 
(727) 
1,823 

North 
 Sea 

1,905 
56 
1,961 
(522) 
1,439 

2005
Offshore
West Africa 

$ 

$ 

1,365 
182 
1,547 
(294) 
1,253 

2004
Offshore
West Africa 

$ 

$ 

563 
528 
1,091 
(190) 
901 

2003
Offshore
West Africa 

$ 

$ 

566 
231 
797 
(140) 
657 

$ 

$ 

$ 

$ 

$ 

$ 

Other 

14 
13 
27 
(14) 
13 

Other

14 
8 
22 
(14) 
8 

Other

14 
6 
20 
(12) 
8 

$ 

$ 

$ 

$ 

$ 

$ 

(millions of Canadian dollars)

Proved properties  
Unproved properties  

Less: accumulated depletion and depreciation  
Net capitalized costs  

(millions of Canadian dollars)

Proved properties 
Unproved properties 

Less: accumulated depletion and depreciation  
Net capitalized costs  

(millions of Canadian dollars)

Proved properties 
Unproved properties 

Less: accumulated depletion and depreciation  
Net capitalized costs  

98

Supplementary Oil & Gas Information

Total

2,588
64
251
69
(3)
(375)
(42)
2,552
334
80
192
(8)
(404)
(56)
2,690
506
30
6
(23)
(419)
52
2,842

2,269
2,198
2,230
2,326

Total

24,940
1,595
26,535
(9,323)
17,212

Total

21,832
1,608
23,440
(7,341)
16,099

Total

17,610
1,082
18,692
(5,658)
13,034

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COSTS INCURRED IN OIL AND NATURAL GAS ACTIVITIES

(millions of Canadian dollars)

Property acquisitions
  Proved   
  Unproved  
Exploration  
Development  
Finding and development costs  
Asset retirement costs    
Actual retirement expenditures  
Costs incurred  

(millions of Canadian dollars)

Property acquisitions
  Proved   
  Unproved  
Exploration  
Development  
Finding and development costs  
Asset retirement costs    
Actual retirement expenditures  
Costs incurred  

(millions of Canadian dollars)

Property acquisitions
  Proved   
  Unproved  
Exploration  
Development  
Finding and development costs  
Asset retirement costs    
Actual retirement expenditures  
Costs incurred  

North 
America 

North 
 Sea 

2005
Offshore
West Africa 

$ 

$ 

$ 

$ 

$ 

$ 

(448) 
210 
360 
2,288 
2,410 
98 
(46) 
2,462 

North 
America 

1,748 
298 
290 
1,403 
3,739 
98 
(32) 
3,805 

North 
America 

236 
116 
190 
1,227 
1,769 
80 
(30) 
1,819 

$ 

$ 

$ 

$ 

$ 

$ 

(3) 
– 
22 
368 
387 
(136) 
– 
251 

$ 

$ 

63 
(52) 
16 
412 
439 
27 
– 
466 

North 
 Sea 

2004
Offshore
West Africa 

302 
4 
11 
308 
625 
165 
– 
790 

$ 

$ 

– 
– 
35 
259 
294 
(10) 
– 
284 

North 
 Sea 

2003
Offshore
West Africa 

100 
23 
41 
193 
357 
59 
(1) 
415 

$ 

$ 

– 
– 
27 
148 
175 
9 
(9) 
175 

$ 

$ 

$ 

$ 

$ 

$ 

Other 

Total

– 
– 
5 
– 
5 
– 
– 
5 

$ 

$ 

(388)
158
403
3,068
3,241
(11)
(46)
3,184

Other

Total

– 
– 
2 
– 
2 
– 
– 
2 

$ 

$ 

2,050
302
338
1,970
4,660
253
(32)
4,881

Other

Total

– 
– 
7 
– 
7 
– 
– 
7 

$ 

$ 

336
139
265
1,568
2,308
148
(40)
2,416

Supplementary Oil & Gas Information

99

 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES
The Company’s results of operations from oil and natural gas producing activities for the years ended December 31, 2005, 2004 and 
2003 are summarized in the following tables:

(millions of Canadian dollars)

Oil and natural gas revenue, net of royalties  
Production  
Transportation  
Depletion, depreciation and amortization  
Asset retirement obligation accretion  
Petroleum revenue tax   
Income tax  
Results of operations    

(millions of Canadian dollars)

Oil and natural gas revenue, net of royalties  
Production  
Transportation  
Depletion, depreciation and amortization  
Asset retirement obligation accretion  
Petroleum revenue tax   
Income tax  
Results of operations    

(millions of Canadian dollars)

Oil and natural gas revenue, net of royalties  
Production  
Transportation  
Depletion, depreciation and amortization  
Asset retirement obligation accretion 
Petroleum revenue tax   
Income tax  
Results of operations 

North 
America 

5,727 
(1,211) 
(287) 
(1,588) 
(34) 
– 
(1,007) 
1,600 

North 
America 

4,579 
(976) 
(256) 
(1,438) 
(28) 
– 
(690) 
1,191 

North 
America 

3,961 
(845) 
(263) 
(1,203) 
(23) 
– 
(673) 
954 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

North 
 Sea 

1,499 
(379) 
(20) 
(306) 
(34) 
(172) 
(235) 
353 

North 
 Sea 

1,203 
(370) 
(32) 
(265) 
(22) 
(145) 
(148) 
221 

2005

Offshore
West Africa 

472 
(53) 
– 
(104) 
(1) 
– 
(110) 
204 

$ 

$ 

2004

Offshore
West Africa 

216 
(36) 
– 
(53) 
(1) 
– 
(44) 
82 

$ 

$ 

2003

North 
 Sea 

Offshore
West Africa 

962 
(314) 
(30) 
(250) 
(39) 
(97) 
(93) 
139 

$ 

$ 

150 
(38) 
(1) 
(42) 
(1) 
– 
(24) 
44 

$ 

$ 

$ 

$ 

$ 

$ 

Total

7,698
(1,643)
(307)
(1,998)
(69)
(172)
(1,352)
2,157

Total

5,998
(1,382)
(288)
(1,756)
(51)
(145)
(882)
1,494

Total

5,073
(1,197)
(294)
(1,495)
(63)
(97)
(790)
1,137

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED OIL 
AND NATURAL GAS RESERVES AND CHANGES THEREIN
The following standardized measure of discounted future net cash ﬂ ows from proved 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  ﬂ ows.  The  Company  does  not  believe  that  the  standardized  measure  of 
discounted future net cash ﬂ ows will be representative of actual future net cash ﬂ ows and should not be considered to represent the 
fair value of the oil and natural gas properties. Actual net cash ﬂ ows will differ from the presented estimated future net cash ﬂ ows 
due to several factors including:

  •   Future production will include production not only from proved properties, but may also include production from probable and 

potential reserves;

  •   Future production of 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  ﬁ scal  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 site restoration costs will differ from those estimated.

100

Supplementary Oil & Gas Information

 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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  ﬂ ows  relating  to  proved  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 site restoration costs  
Future income taxes  
Future net cash flows    
10% annual discount for timing of future cash flows   
Standardized measure of future net cash flows  

(millions of Canadian dollars)

Future cash inflows  
Future production costs  
Future development and site restoration costs  
Future income taxes  
Future net cash flows    
10% annual discount for timing of future cash flows   
Standardized measure of future net cash flows  

(millions of Canadian dollars)

Future cash inflows 
Future production costs 
Future development and site restoration costs 
Future income taxes  
Future net cash flows    
10% annual discount for timing of future cash flows   
Standardized measure of future net cash flows 

North 
America 

52,266 
(17,310) 
(3,916) 
(10,272) 
20,768 
(7,793) 
12,975 

North 
America 

31,727 
(10,995) 
(2,944) 
(6,438) 
11,350 
(4,385) 
6,965 

North 
America 

32,720 
(9,480) 
(2,393) 
(7,295) 
13,552 
(6,203) 
7,349 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

North 
 Sea 

19,961 
(6,130) 
(3,099) 
(6,631) 
4,101 
(1,144) 
2,957 

North 
 Sea 

15,526 
(6,302) 
(2,832) 
(3,783) 
2,609 
(691) 
1,918 

North 
 Sea 

9,099 
(3,015) 
(1,749) 
(2,801) 
1,534 
(336) 
1,198 

2005

Offshore
West Africa 

8,515 
(1,803) 
(1,032) 
(2,092) 
3,588 
(1,068) 
2,520 

$ 

$ 

2004

Offshore
West Africa 

5,249 
(1,137) 
(631) 
(1,242) 
2,239 
(634) 
1,605 

$ 

$ 

2003

Offshore
West Africa 

$ 

$ 

3,192 
(1,179) 
(697) 
– 
1,316 
(432) 
884 

Total

80,742
(25,243)
(8,047)
(18,995)
28,457
(10,005)
18,452

Total

52,502
(18,434)
(6,407)
(11,463)
16,198
(5,710)
10,488

Total

45,011
(13,674)
(4,839)
(10,096)
16,402
(6,971)
9,431

$ 

$ 

$ 

$ 

$ 

$ 

The principal sources of change in the standardized measure of discounted future net cash ﬂ ows are summarized in the following table:

(millions of Canadian dollars) 

Sales of 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    

2005

(5,785) 
11,056 
3,596 
(971) 
469 
(130) 
961 
1,812 
1,414 
(4,458) 
7,964 
10,488 
18,452 

$ 

$ 

2004

(4,331) 
(553) 
2,120 
(894) 
1,386 
(20) 
1,431 
1,558 
1,357 
(997) 
1,057 
9,431 
10,488 

$ 

$ 

2003

(3,582)
(2,750)
1,360
(346)
594
(8)
144
2,000
(1,411)
426
(3,573)
13,004
9,431

$ 

$ 

Supplementary Oil & Gas Information

101

 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ten-Year Review

Years ended December 31

2005 

2004 

2003 

2002 

2001 

2000 

1999 

1998 

1997 

1996

FINANCIAL INFORMATION
(C$ millions, except per share amounts)
Net earnings  
  Per share – basic (1)
Cash flow from operations (2)
  Per share – basic (1)

Capital expenditures, net of dispositions
(including business combinations) 

Balance Sheet information
Working capital (deficiency) surplus 
Property, plant and equipment, net 
Total assets 
Long-term debt 
Shareholders’ equity 

SHARE INFORMATION
Common shares outstanding (thousands)
Weighted average shares
  outstanding (thousands)
Dividends declared per common share 

Trading statistics (1)
TSX – C$
Trading volume (thousands)
Share Price ($/share)
  High 
  Low 
  Close 
NYSE – US$
Trading volume (thousands)
Share Price ($/share)
  High 
  Low 
  Close 

RATIOS
Debt to cash flow (3)
Debt to book capitalization (3)
Return on average common shareholders’
  equity, after tax (3)
Debt to EBITDA (3)
Daily production before royalties per

  1,403 

  1,405 

  1,050 
88 
$  1.96  $  2.62  $  2.62  $  1.06  $  1.32  $  1.62  $  0.51  $  0.08  $  0.26  $  0.27 
360
$  9.36  $  7.03  $  5.88  $  4.41  $  3.96  $  4.04  $  1.74  $  1.12  $  1.28  $  1.08 

  1,884 

  3,769 

  1,920 

  2,254 

  3,160 

5,021 

213 

724 

639 

503 

539 

444 

758 

104 

31 

  4,932 

  4,633 

  2,506 

  4,069 

  1,885 

  2,823 

  1,901 

610 

  1,119 

  1,204

(652)   

(505)   

(14)   

  (1,774)   
  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 

58 

 36 

 (6)   

 (77)   

 (1)
   4,679     3,135     2,831     1,993 
   8,766     7,439 
   4,976     3,329     3,016     2,144 
   9,290     8,051 
   2,788     2,573     2,157     1,426     1,136    
588 
   3,928     3,297     1,962     1,317     1,250     1,108 

(19)   

536,348  536,361   534,926  535,104  484,804  489,116  445,816  399,236  395,276  389,532 

536,650  536,223   536,940  511,532  485,200  466,804  415,624  397,324  392,168  332,984 
–
$  0.24  $  0.20  $  0.15  $  0.13  $  0.10  $ 

–  $ 

–  $ 

–  $ 

–  $ 

637,992  606,024   590,702  619,316  534,976  567,412  430,460  410,440  402,152  396,888 

$  62.00  $ 27.58  $ 16.81  $ 13.64  $ 13.09  $ 14.05  $  9.65  $  7.88  $ 11.06  $  9.85 
$  24.28  $ 15.96  $ 11.30  $  9.40  $  8.98  $  7.45  $  4.95  $  4.56  $  7.23  $  4.81 
$  57.63  $ 25.63  $ 16.34  $ 11.70  $  9.58  $ 10.38  $  8.81  $  5.75  $  7.65  $  9.40 

251,554  125,468 

 46,916 

31,864 

20,764 

3,172 

– 

– 

– 

$  54.05  $ 22.37  $ 12.85  $  8.72  $  8.63  $  9.46  $ 
$  19.74  $ 11.94  $  7.32  $  5.89  $  5.70  $  6.19  $ 
$  49.62  $ 21.39  $ 12.61  $  7.42  $  6.10  $  6.88  $ 

–  $ 
–  $ 
–  $ 

–  $ 
–  $ 
–  $ 

–  $ 
–  $ 
–  $ 

–

–
–
–

0.7x 
28.7% 

1.0x 
  33.8% 

0.9x 
  32.8% 

1.9x 
  47.1% 

1.5x 
  41.7% 

1.4x 
  44.0% 

3.0x 
  52.4% 

3.2x 
  52.0% 

2.3x 
  47.6% 

1.6x
  34.7%

14.3% 
0.6x 

  21.4% 
0.9x 

  25.6% 
0.8x 

  13.0% 
1.7x 

  17.7% 
1.4x 

  28.8% 
1.2x 

  13.0% 
2.6x 

  2.4% 
2.9x 

  8.8% 
4.8x 

  10.9%
3.0x

ten thousand common shares (boe/d) 

10.3 

9.6 

8.5 

8.2 

7.4 

6.6 

5.0 

4.7 

4.5 

3.6 

Conventional proved and probable

reserves per common share (boe) (4) 

4.8 

4.3 

 4.0 

3.3 

3.1 

2.9 

2.4 

1.9 

1.7 

1.3 

Net asset value
  per common share (1)(5)

$  60.44  $ 33.13  $ 23.35  $ 19.57  $ 16.88  $ 20.54  $ 12.33  $  8.08  $  6.80  $  6.46 

(1) Restated to reflect two-for-one share splits in May 2004 and May 2005.
(2)  Cash flow from operations is a non-GAAP term that represents net earnings adjusted for non-cash items. The Company evaluates its performance based on earnings and cash flow. Cash flow 

from operations may not be comparable to similar measures used by other companies.

(3) Refer to the MD&A, page 62, “Liquidity and Capital Resources”, 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, forcast 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 and $75/acre for all years prior, less long-term debt and existing asset liabilities and adjusted for working capital. See reserves disclosures on pages 40 to 44.

102

Ten-Year Review

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years ended December 31

2005 

2004 

2003 

2002 

2001 

2000 

1999 

1998 

1997 

1996

OPERATING INFORMATION
Conventional crude oil and NGLs (mmbbl)
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 

Conventional natural gas (bcf)
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

785 
290 
148 
   1,223 

695 
303 
125 

672 
222 
106 
  1,123     1,000 

665 
203 
94 
962 

   1,154 
417 
230 
   1,801 

992 
415 
214 
  1,621 

977 
317 
187 
  1,481 

742 
277 
162 
  1,181 

644 
83 
61 
788 

740 
106 
111 
957 

643 
102 
36 
781 

731 
134 
46 
911 

554 
– 
– 
554 

640 
– 
– 
640 

284 
– 
– 
284 

380 
– 
– 
380 

257 
– 
– 
257 

329 
– 
– 
329 

136
–
–
136

185
–
–
185

  3,378 
29 
83 
3,490 

  3,202 
27 
81 
  3,310 

  3,006 
62 
86 
  3,154 

  3,048 
71 
90 
  3,209 

  2,566 
94 
69 
  2,729 

  2,360 
91 
65 
  2,516 

  2,183 
– 
– 
  2,183 

  1,901 
– 
– 
  1,901 

  1,716 
– 
– 
  1,716 

  1,566
–
–
  1,566

  4,372 
69 
127 

  4,100 
57 
102 
   4,568      4,259 

  3,611 
101 
111 
  3,823 

  3,450 
89 
120 
  3,659 

  2,915 
118 
96 
  3,129 

  2,762 
114 
84 
  2,960 

  2,547 
– 
– 
  2,547 

  2,211 
– 
– 
  2,211 

  2,078 
– 
– 
  2,078 

  1,926
–
–
  1,926

(before royalties) (mmboe)

  1,804 

  1,674 

  1,526 

  1,497 

  1,243 

  1,200 

918 

601 

543 

397 

Total proved and probable reserves

(before royalties) (mmboe)

2,562 

  2,330 

  2,118 

  1,791 

  1,479 

  1,404 

  1,065 

749 

675 

506 

Oil sands, mining (mmbbl)
Gross proved and probable reserves

(before royalties) 
  Bitumen 
  Synthetic crude oil *

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 

Total production 

3,430 
  2,878 

– 
– 

– 
– 

– 
– 

– 
– 

– 
– 

– 
– 

– 
– 

– 
– 

–
–

222 
68 
23 
 313    

206 
65 
12 
283 

175 
57 
10 
242 

169 
39 
7 
215 

  1,416 
19 
4 

  1,330 
50 
8 
   1,439     1,388 

  1,245 
46 
8 
  1,299 

  1,204 
27 
1 
  1,232 

167 
36 
3 
206 

906 
12 
– 
918 

155 
17 
2 
174 

793 
1 
–    

794 

87 
– 
– 
87 

721 
– 
– 
721 

76 
– 
– 
76 

673 
– 
– 
673 

71 
– 
– 
71 

626 
– 
– 
626 

37
–
–
37

499
–
–
499

(before royalties) (mboe/d)

553 

514 

 459 

421 

359 

306 

207 

188 

175 

120

Product pricing
  Average crude oil and NGLs price ($/bbl)
  Average natural gas price ($/mcf)

  46.86 
8.57 

  37.99 
6.50 

  32.66 
6.21 

  31.22 
3.77 

  23.45 
5.45 

  31.89 
4.92 

  22.26 
2.52 

  11.98 
2.11 

  18.99 
1.97 

  24.73
1.67

* SCO reserves are based upon upgrading of the bitumen reserves. The reserves shown for bitumen and SCO are not additive.

Ten-Year Review

103

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Corporate information

BOARD OF DIRECTORS
Catherine M. Best (1) (2 – Chair) (3)
Executive  Vice-President,  Risk  Management  &  Chief  Financial 
Ofﬁcer,
Calgary Health Region Calgary, Alberta

N. Murray Edwards (5)
President, Edco Financial Holdings Ltd.
Calgary, Alberta

Honourable Gary A. Filmon, P.C., O.M. (1) (2) (4)
Consultant, Exchange Group
Winnipeg, Manitoba

Ambassador Gordon D. Gifﬁn (1) (2) (4 – Chair)
Senior Partner, McKenna Long & Aldridge LLP
Atlanta, Georgia

John G. Langille
Vice-Chairman, Canadian Natural Resources Limited
Calgary, Alberta

Keith A. J. MacPhail (5) (6)
Chairman, President & Chief Executive Ofﬁcer,
Bonavista Energy Trust
Calgary, Alberta

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 

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, North American Operations 

Douglas A. Proll
Chief Financial Ofﬁcer & Senior Vice-President, Finance 

Allan P. Markin (6)
Chairman of the Board, Canadian Natural Resources Limited
Calgary, Alberta

Norman F. McIntyre (1) (3) (5) (6)
Independent Businessman
Calgary, Alberta

Lyle G. Stevens
Senior Vice-President, Exploitation

Jeff W. Wilson
Senior Vice-President, Exploration 

Mary-Jo E. Case
Vice-President, Land

James S. Palmer, C.M., A.O.E., Q.C. (1) (3 – Chair) (5) (6)
Chairman and Partner, Burnet, Duckworth & Palmer LLP
Calgary, Alberta

Randall S. Davis
Vice-President, Financial Accounting & Controls

Eldon R. Smith, M.D. (1) (3) (4) (6 – Chair)
Professor Emeritus and Former Dean,
Faculty of Medicine, University of Calgary
Calgary, Alberta

David A. Tuer (1) (2) (4) (5 – Chair)
President, Value Creations Inc.
Calgary, Alberta

(1) 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.

(2) Audit Committee member
(3) Compensation Committee member
(4) Nominating and Corporate Governance Committee member
(5) Reserves Committee member
(6) Health, Safety and Environment Committee member

104

Corporate Information

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

INDEPENDENT QUALIFIED RESERVES 
EVALUATORS
GLJ Petroleum Consultants
Calgary, Alberta

Ryder Scott Company
Calgary, Alberta

Sproule Associates Limited
Calgary, Alberta

STOCK LISTING
The Toronto Stock Exchange
CNQ
CNQ.U (Denotes trading in US funds)
The New York Stock Exchange
CNQ

Printed in Canada by Sundog Printing.

Principal photography by Gary Campbell.

Additional photography by Christine Flatt,
Stephan C. Dragomir, Edwin Herrenschmidt, 
Rolf Karis and Canadian Natural team members.

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) 517-7370
Email: ir@cnrl.com

INTERNATIONAL OFFICE
CNR International (U.K.) Limited
St. Magnus House, Guild Street
Aberdeen AB11 6NJ Scotland

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  signiﬁ cant  differences  between  its  corporate 
governance  practices  and  those  required  for  U.S.  companies 
listed on the NYSE. 

Toronto Stock Exchange (“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  and 
material  revisions  to  such  plans.  Canadian  Natural  follows 
TSX  rules  with  respect  to  shareholder  approval  of  equity 
compensation plans.

Canadian Natural has included as exhibits to its Annual Report 
on  Form  40-F  for  the  2005  ﬁ scal  year  ﬁ led  with  the  United 
States Securities and Exchange Commission certiﬁ cates of the 
Chief Executive Ofﬁ cer and Chief Financial Ofﬁ cer certifying 
the quality of its public disclosure.

Corporate Information

IMPORTANT DATES
PRESS RELEASE FIRST QUARTER 2006
Thursday, May 4, 2006

ANNUAL GENERAL MEETING
Thursday, May 4, 2006

PRESS RELEASE SECOND QUARTER 2006
Wednesday, August 2, 2006

PRESS RELEASE THIRD QUARTER 2006
Wednesday, November 1, 2006

CANADIAN NATURAL RESOURCES LIMITED

2500, 855 - 2 Street SW
Calgary, Alberta
Canada T2P 4J8

Phone: 403.517.6700
403.517.7350
Fax:
www.cnrl.com

You can ﬁ nd PDF versions of this and other publications 
from Canadian Natural at www.cnrl.com

You can request documents by calling our head ofﬁ ce 
or via email: ir@cnrl.com