EXHIBIT 99.1
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[PHOTOGRAPHS OMITTED] [LOGO OMITTED]
THE PREMIUM VALUE, CANADIAN NATURAL
DEFINED GROWTH, INDEPENDENT
NEWS RELEASE
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CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES
RECORD QUARTERLY AND ANNUAL PRODUCTION VOLUMES
AND STRONG FINANCIAL RESULTS
CALGARY, ALBERTA - MARCH 7, 2007 - FOR IMMEDIATE RELEASE
In commenting on fourth quarter 2006 results, Canadian Natural's Chairman,
Allan Markin stated, "2006 was a year of both challenges and tremendous
opportunities. Higher commodity prices were accompanied by significant cost
inflation throughout each of our basins, meaning that we had to be even more
vigilant at ensuring full cycle economics were maintained - we responded by
optimizing our capital allocation to projects that provided the highest return
on capital. For example, we were one of the first in the industry to address
the effects of this inflation through significant reductions in natural gas
drilling commencing with the second quarter of last year. In late 2006 we were
able to complete a major acquisition of natural gas assets at an attractive
price, which greatly expanded our project portfolio. In completing this
transaction, we further reduced drill bit activity and our exposure to cost
inflation for 2007. Integration of people and assets is now complete and we are
looking forward to developing our expanded and exceptional portfolio of crude
oil and natural gas opportunities. Our management team are firm believers that
this re-allocation of capital in 2006 will create significant value in future
years."
John Langille, Vice-Chairman, commented "Canadian Natural continues to believe
in strong fiscal management. In particular, we have a very strong hedge program
underpinning our 2007 cash flows and this, combined with better than expected
heavy oil differentials and continued operating and capital discipline, is
expected to facilitate our return to the mid range of our targeted debt levels
in 2008. Based upon current strip pricing and projected production levels, we
would expect to generate 2007 cash flows in excess of $6 billion, above the
high end of our original 2007 financial budget."
Canadian Natural's President and Chief Operating Officer, Steve Laut, in
commenting on the Company's annual results stated, "Our cultural focus on
execution is affording us success notwithstanding cost and operational
challenges. On the conventional operations side, we are operating very well in
a challenging environment, delivering 2006 proved and probable finding and
development costs of $10.09/boe. Our focused teams are determining cost
effective alternatives to develop our project portfolio, and deliver on our
defined growth plans. On the marketing side, we are aggressively pursuing new
markets for our massive heavy oil resource while still managing a large hedge
position to ensure cash flow certainty in the short run. Finally, at our
Horizon Oil Sands Project ("Horizon Project"), our project management and
construction teams continue to deliver. With the Horizon Project 57% complete
at the end of 2006 and forecast to achieve approximately 90% completion by the
end of 2007, at present we continue to expect final Phase 1 construction costs
to not be materially different than our original $6.8 billion target cost with
an on-schedule commissioning in the third quarter of 2008. While there are
still numerous challenges and inflationary pressures, I believe that our teams
have performed very well, again highlighting Canadian Natural's cultural focus
on execution."
HIGHLIGHTS
Quarterly Results Year End Results
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($ millions, except as noted) Q4/06 Q3/06 Q4/05 2006 2005
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Net earnings $ 313 $ 1,116 $ 1,104 $ 2,524 $ 1,050
per common share, basic $ 0.58 $ 2.08 $ 2.06 $ 4.70 $ 1.96
Adjusted net earnings from operations (1) $ 412 $ 470 $ 601 $ 1,664 $ 2,034
per common share, basic $ 0.77 $ 0.87 $ 1.12 $ 3.10 $ 3.79
Cash flow from operations (2) $ 1,293 $ 1,313 $ 1,490 $ 4,932 $ 5,021
per common share, basic $ 2.41 $ 2.44 $ 2.78 $ 9.18 $ 9.36
Capital expenditures, net of dispositions $ 6,497 $ 1,661 $ 1,679 $ 12,025 $ 4,932
Debt to book capitalization 51% 35% 29% 51% 29%
Daily production, before royalties
Natural gas (mmcf/d) 1,620 1,437 1,423 1,492 1,439
Crude oil and NGLs (bbl/d) 343,705 321,665 340,268 331,998 313,168
Equivalent production (boe/d) 613,764 561,152 577,505 580,724 552,960
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(1) ADJUSTED NET EARNINGS FROM OPERATIONS IS A NON-GAAP TERM THAT THE COMPANY
UTILIZES TO EVALUATE ITS PERFORMANCE. THE DERIVATION OF THIS ITEM IS
DISCUSSED IN THE MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A").
(2) CASH FLOW FROM OPERATIONS IS A NON-GAAP TERM THAT THE COMPANY CONSIDERS
KEY AS IT DEMONSTRATES ITS ABILITY TO FUND CAPITAL REINVESTMENT AND DEBT
REPAYMENT. THE DERIVATION OF THIS ITEM IS DISCUSSED IN THE MD&A.
o Record North America natural gas production in Q4/06 represented an
increase of 13% from Q3/06 and a 14% increase over Q4/05 due to the
acquisition of Anadarko Canada Corporation ("ACC"), a subsidiary of
Anadarko Petroleum Corporation volumes in November, which was partially
offset by normal production declines and the effects of a reduced drilling
emphasis due to a re-allocation of capital away from higher cost organic
natural gas development.
o Record crude oil production volumes in Q4/06 represented a 7% increase
from Q3/06 and 1% from Q4/05. The increase from Q3/06 was largely the
result of higher North Sea and thermal crude oil volumes as well as the
ACC acquisition. The increase from Q4/05 was driven by higher Canadian
crude oil production partially offset by lower international volumes.
o Quarterly cash flow of $1.3 billion, essentially flat with Q3/06 and a 13%
decrease from Q4/05. The decrease from Q4/05 reflected lower natural gas
pricing, higher production expenses and the impact of a stronger Canadian
dollar relative to the US dollar. These factors were offset by the impact
of higher crude oil pricing, higher crude oil and NGLs and natural gas
sales volumes and lower realized risk management losses.
o Quarterly net earnings of $313 million, representing a 72% decrease from
both Q3/06 and Q4/05. Net earnings in Q4/06 included unrealized after-tax
expenses of $99 million related to the effects of risk management
activities, foreign exchange losses and stock-based compensation expense,
compared to net after-tax income of $503 million in Q4/05 and $646 million
of after-tax income in Q3/06.
o Quarterly adjusted net earnings from operations of $412 million, 12% lower
than Q3/06 results and a 31% decrease from Q4/05 reflecting lower cash
flow and higher DD&A rates.
o Completed the acquisition and integration of ACC. ACC, which was acquired
for aggregate cash consideration of $4,641 million including working
capital and other adjustments and was included in Canadian Natural's
results effective November 2006. Substantially all of ACC's land and
production bases are located in Western Canada and are premium quality,
concentrated natural gas weighted assets with strong netbacks and long
reserve lives.
o Independent qualified reserve evaluators evaluated 100% of the Company's
conventional crude oil and natural gas reserves under constant prices and
costs as at December 31, 2006:
2 CANADIAN NATURAL RESOURCES LIMITED
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-- Total net proved reserves from conventional operations at the end of
2006 amounted to 1.3 billion barrels of crude oil and NGLs and 3.8
trillion cubic feet of natural gas. Total net proved conventional
reserves increased by 22%, with net proved crude oil reserves
increasing by 18% and net proved natural gas reserves increasing by
34%.
-- Net proved reserve additions from conventional operations equaled 295%
of 2006 net production, at a finding and onstream cost of $16.16 per
barrel of oil equivalent. The Company's three-year average proved
finding and onstream costs was $14.28 per barrel of oil equivalent.
-- Total net proved and probable reserves from conventional operations at
the end of 2006 amounted to 2.1 billion barrels of crude oil and NGLs
and 5.0 trillion cubic feet of natural gas. Total proved and probable
net conventional reserves increased by 30%, with net proved and
probable crude oil reserves increasing by 28% and net proved and
probable natural gas reserves increasing by 35%.
-- Net proved and probable reserve additions from conventional operations
equaled 472% of 2006 net production, at a finding and onstream cost of
$10.09 per barrel of oil equivalent. The Company's three-year average
net proved and probable finding and onstream costs was $9.88 per
barrel of oil equivalent.
-- Using net proved and probable finding and onstream costs, the Company
achieved an overall recycle ratio of 3.3x (2.0x using only proved
reserve additions) during 2006.
o Independent qualified reserve evaluators evaluated 100% of the Company's
Phase 1 to Phase 3 oil sands mining reserves for the Horizon Project under
constant prices as at December 31, 2006, which resulted in 2.3 billion
barrels of gross lease proved bitumen reserves and 3.5 billion barrels of
gross lease proved and probable bitumen reserves. This represents an
increase from the December 31, 2005 evaluation which had 2.2 billion
barrels of gross lease proved bitumen reserves and 3.4 billion barrels of
gross lease proved and probable bitumen reserves.
o Completed a Q4/06 drilling program of 265 net wells, excluding
stratigraphic test and service wells, with an 89% success ratio,
reflecting Canadian Natural's strong, predictable, low-risk asset base.
o Increased an already strong undeveloped conventional land base in Canada
to 12.6 million net acres - a key asset in today's highly competitive
industry - including an additional 1.5 million net undeveloped acres
acquired through the ACC acquisition.
o The Horizon Project remains slightly ahead of schedule as at December 31,
2006. The Horizon Project exited 2006 57% complete with approximately $5.1
billion in purchase orders and contracts having been awarded to date. Cost
pressures are causing cost estimates for certain isolated pieces of the
project to be above target cost. However, at present such cost increases
are not expected to, in aggregate, result in Phase 1 construction costs of
the project being materially different than the original target cost of
$6.8 billion. Further, Canadian Natural remains on track for commissioning
during the third quarter of 2008.
o Continued production improvements at Pelican Lake Field arising from new
drilling activity and the expansion of the enhanced crude oil recovery
program. Pelican Lake crude oil production averaged approximately 29,200
bbl/d during the quarter, up 5% or approximately 1,600 bbl/d from Q4/05.
Production is expected to continue to increase in Q1/07 and throughout the
rest of 2007.
o The Company's commodity hedging program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its
capital expenditure program throughout the Horizon Project construction
period. This 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. For the purpose of this program, the purchase of crude oil put options
is in addition to the above parameters. In accordance with the policy,
approximately 65% of expected crude oil volumes and approximately 75% of
expected natural gas volumes have been hedged for 2007. In addition,
77,000 bbl/d of crude oil volumes are protected by put options for 2007 at
a strike price of US$60.00 per barrel. The Company is extending its hedge
program into 2008 whereby 150,000 bbl/d of crude oil volumes have been
hedged (100,000 bbl/d of price collars with a US$60.00 floor and 50,000
bbl/d of put options with a US$55.00 strike price). In addition, 900,000
GJ/d of natural gas volumes have been hedged through the use of price
collars for the first quarter of 2008 (400,000 GJ/d with a floor of $7.00
and 500,000 GJ/d with a floor of $7.50).
o Seventh straight year of dividend increases. The 2007 quarterly dividend
will increase 13% from $0.075 per common share to $0.085 per common share,
effective with the April 2007 payment.
CANADIAN NATURAL RESOURCES LIMITED 3
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OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its
activities in core regions where it can dominate the land base and
infrastructure. Undeveloped land is critical to the Company's ongoing growth
and development within these core regions. Land inventories are maintained to
enable 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. Further, the Company maintains large project
inventories and production diversification among each of the commodities it
produces; namely natural gas, light and heavy crude oil and NGLs. A large
diversified project portfolio enables the effective allocation of capital to
higher return opportunities.
OPERATIONS REVIEW
ACTIVITY BY CORE REGION
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NET UNDEVELOPED LAND DRILLING ACTIVITY
AS AT YEAR ENDED
DEC 31, 2006 DEC 31, 2006
(THOUSANDS OF NET ACRES) (NET WELLS)
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Canadian conventional
Northeast British Columbia 2,721 196
Northwest Alberta 1,750 194
Northern Plains 6,765 728
Southern Plains 870 120
Southeast Saskatchewan 117 75
In-situ Oil Sands 407 247
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12,630 1,560
Horizon Oil Sands Project 116 163
United Kingdom North Sea 299 9
Offshore West Africa 207 6
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13,252 1,738
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DRILLING ACTIVITY (number of wells)
Year Ended Dec 31
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2006 2005
GROSS NET Gross Net
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Crude oil 666 603 685 627
Natural gas 855 641 1,071 890
Dry 133 119 136 117
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Subtotal 1,654 1,363 1,892 1,634
Stratigraphic test / service wells 376 375 251 248
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Total 2,030 1,738 2,143 1,882
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Success rate (excluding stratigraphic test / service wells) 91% 93%
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4 CANADIAN NATURAL RESOURCES LIMITED
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NORTH AMERICA NATURAL GAS Quarterly Results Year End Results
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Q4/06 Q3/06 Q4/05 2006 2005
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Natural gas production (mmcf/d) 1,594 1,416 1,402 1,468 1,416
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Net wells targeting natural gas 74 111 295 732 975
Net successful wells drilled 60 98 279 641 890
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Success rate 81% 88% 95% 88% 91%
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o The 13% increase in production reflected the inclusion of ACC production
effective November 2006 partially offset by normal production declines and
the effects of the Company's strategic decision to reduce organic growth
spending due to high industry costs. As a result of the strategic move to
reduce natural gas drilling, the Company experienced a 75% decrease in
Q4/06 drilling compared to Q4/05.
o ACC was fully integrated into Canadian Natural within weeks of closing
with the assets performing at or above expectation.
o High drilling success rates reflect Canadian Natural's low-risk
exploitation approach and high quality land base. The Q4/06 drilling
program represented an active program across the Company's core regions.
In Northeast British Columbia 9 net wells targeting natural gas were
drilled, while in Northwest Alberta 23 net wells were drilled, including 6
Cardium targets. In Northern and Southern Plains, a total of 2 net deep,
11 net coal bed methane, 9 net shallow and 20 net conventional natural gas
wells were targeted.
o Planned drilling activity for Q1/07 includes 241 wells targeting natural
gas compared to a total of 499 wells drilled in Q1/06, again reflecting
the Company's decision to proactively reduce exposure to over-inflated
service and supply costs.
NORTH AMERICA CRUDE OIL AND NGLS Quarterly Results Year End Results
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Q4/06 Q3/06 Q4/05 2006 2005
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Crude oil and NGLs production (bbl/d) 249,565 233,440 230,263 235,253 221,669
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Net wells targeting crude oil 188 263 191 619 642
Net successful wells drilled 174 253 185 591 612
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Success rate 93% 96% 97% 95% 95%
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o In contrast to natural gas, the crude oil program utilizes fewer third
party services and experienced lower cost inflation while receiving higher
wellhead pricing. In 2006, the Company contracted two slant drilling rigs
to ensure availability of these specialized rigs on a go forward basis to
execute the long-term drilling of heavy crude oil. Due to the timing of
crude oil production profiles, the benefit of the ramped drilling program
during the second half of 2006 will not be fully realized until mid 2007.
o Q4/06 North America crude oil and NGLs production increased 7% over Q3/06
and 8% over Q4/05. This performance reflected continued success at the
Primrose thermal crude oil project where new pads have transitioned from
the steaming cycle to the production cycle, as well as continued
production improvements at Pelican Lake. Many of the newer Primrose pads
have recently commenced a steaming phase in Q1/07, which will result in
decreased production during the first quarter of 2007.
o During Q4/06, drilling activity included 110 net wells targeting heavy
crude oil, 39 net wells targeting Pelican Lake crude oil, 18 net wells
CANADIAN NATURAL RESOURCES LIMITED 5
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targeting thermal crude oil and 21 net wells targeting light crude oil.
The majority of the wells were drilled in the Northern Plains core region.
Production from this crude oil drilling program will be reflected in the
Company's results in the first half of 2007.
o The Primrose East expansion program continues with a planned expansion of
the crude oil processing facility from 80,000 bbl/d to 120,000 bbl/d, as
well as the construction of a steam generation plant and new pad drilling
that will add production gains targeted at 40,000 bbl/d in 2009. Primrose
East is the second phase of the 300,000 bbl/d conventional expansion plan
identified to unlock the value from Canadian Natural's thermal crude oil
resource base. Detailed engineering, procurement and site clearing are
underway.
o At Pelican Lake, the development of land acreage and secondary recovery
implementation projects continued as planned, with 39 horizontal producing
wells drilled and 10 production wells converted to injection wells (four
for water and six for polymer injection) in Q4/06. Results from the
polymer flood continue to be positive and 4 additional polymer skids were
installed in Q4/06. The program continues to be optimized and the results
will be monitored. Production remained relatively flat with Q3/06 levels
largely reflecting reduced production associated with converting producer
wells into injector wells.
o Planned drilling activity for Q1/07 includes 199 net crude oil wells.
o In early 2007, Canadian Natural issued its proposed development plan for
the 30,000 bbl/d Kirby In-Situ Oil Sands Project located approximately 85
km northeast of Lac La Biche in the Regional Municipality of Wood Buffalo.
The Company is targeting to file its formal regulatory application
documents for this project in the latter half of 2007.
CANADIAN NATURAL UPGRADER PROJECT
Originally announced in the fall of 2005, the Scoping Study for the Canadian
Natural Upgrader continued during Q4/06 and into early 2007. The terms of
reference for this study involved the evaluation of product alternatives,
location, technology, gasification and integration with existing assets using
the same disciplined approach utilized in the Horizon Project. The next steps
in this process would include a Design Basis Memorandum ("DBM") and Engineering
Design Specification ("EDS") which would be required to be completed prior to
construction and sanctioning of the project by the Board of Directors.
Based upon the results of the Scoping Study, which identified growing concerns
relating to increased environmental costs for upgraders located in Canada,
inflationary capital cost pressures and narrowing heavy oil differentials in
North America, the Company has, at this point in time, deferred the DBM and EDS
pending clarification on the cost of future environmental legislation and a
more stable cost environment.
INTERNATIONAL
The Company operates in the North Sea and Offshore West Africa where production
of lighter quality crude oil is targeted in conjunction with natural gas that
may be produced in association with crude oil production.
Quarterly Results Year End Results
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Q4/06 Q3/06 Q4/05 2006 2005
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Crude oil production (bbl/d)
North Sea 61,786 53,988 66,798 60,056 68,593
Offshore West Africa 32,354 34,237 43,207 36,689 22,906
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Natural gas production (mmcf/d)
North Sea 16 11 15 15 19
Offshore West Africa 10 10 6 9 4
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Net wells targeting crude oil 2.3 2.2 5.9 11.5 17.3
Net successful wells drilled 2.3 2.2 5.0 11.5 15.0
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Success rate 100% 100% 85% 100% 87%
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6 CANADIAN NATURAL RESOURCES LIMITED
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NORTH SEA
o Canadian Natural continues to execute its exploitation strategy in the
North Sea. The first stage of this exploitation program is based upon
optimizing existing facilities and waterfloods. Canadian Natural continues
to apply this first stage of exploitation on its holdings in the North
Sea. The second stage of exploitation incorporates more near pool
development and exploration in order to maximize utilization of the common
facilities and ultimately extend all fields' economic lives. Examples of
this type of work are the ongoing development at the Columba Terraces and
the Lyell Field.
o During Q4/06, 2.5 net wells were drilled with an additional 2 net wells
drilling at quarter end. Production levels during the quarter were in line
with expectations, following successful completion of planned maintenance
in the third quarter and continued strong performance at Banff Field
following completion of gas compression upgrade work.
o The Columba E Raw Water Injection project continued during Q4/06. Drilling
commenced on the first of the 2 planned water injection wells, with both
wells expected to be completed during the second quarter of 2007.
o Plans for the further development of the Lyell Field progressed. The
timeline of the project entails drilling 4 net wells and the workover of 2
existing net wells. During Q4/06, the Company completed the construction,
installation and tie-in of subsea infrastructure, and commenced drilling
the first of the planned wells.
OFFSHORE WEST AFRICA
o During Q4/06, 1.8 net wells were drilled with 1 additional net well
drilling at quarter end.
o At the Espoir Field, crude oil production exceeded expectations during
Q4/06, averaging approximately 19,000 bbl/d net to Canadian Natural during
the quarter. A third production well at West Espoir was brought onstream
in Q4/06, as were two water injection wells. Development drilling will
continue until 2008, with wells being brought onstream as they are
completed. Production at Espoir will be impacted by a planned maintenance
shutdown during Q1/07.
o Net production at Baobab averaged approximately 13,000 bbl/d during the
quarter, reflecting the shut in of production from five of the ten
production wells, due to ongoing challenges with sand and solids
production. This has resulted in approximately 15,500 bbl/d of reduced
production capacity at the field. Canadian Natural is currently
investigating the rig market to identify suitable availability to proceed
to the second phase of the field development, including potentially
recompleting the wells that are currently experiencing production
limitations. Current production remains stable with no sand production
issues.
o In Gabon, the Olowi project received Board sanction for development in
November 2006. Development plans include a floating production, storage
and offtake vessel ("FPSO"), handling production from four shallow water
wellhead towers. During Q4/06, the Company signed a lease agreement for
the FPSO with a primary term of ten years, with arrival of the vessel
scheduled for 2008. A further contract was awarded for the wellhead
towers, with additional contracts expected to be awarded during Q1/07.
First oil is currently targeted for late-2008, with an anticipated plateau
of 20,000 bbl/d.
HORIZON PROJECT
o Phase 1 of the Horizon Project continues slightly ahead of schedule with
first production of 110,000 bbl/d of light, sweet SCO targeted to commence
in the third quarter of 2008.
o The progress on major milestones, a key component in achieving critical
path success, is slightly ahead of schedule and safety performance also
remained ahead of target.
o During Q4/06, the Company awarded a further C$300 million of contracts,
including several that were previously deferred in order to optimize
pricing. This brings the total awarded contracts to C$5.1 billion. To
date, all major plants have been passed through hazard/operability
engineering review without requiring major scope change, providing even
greater cost certainty. The construction is at a point where the critical
foundations are complete and the site is transitioning as steel is
erected, modules are placed and equipment is set.
CANADIAN NATURAL RESOURCES LIMITED 7
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o Canadian Natural continues to effectively execute well defined strategies.
At this point in time for the work done to date (engineering, procurement
and construction) - which translates to a 57% overall project completion
level - the Company is at the target cost forecast. Field construction
itself is 42% complete and work on the mechanical and piping stage is
underway where new challenges will be faced, including ongoing cost
pressures on non-issued contracts, productivity on the job site and usage
of overtime.
o The Company has now entered into the majority of the construction
contracts and as the last 43% of the overall project is undertaken, the
aforementioned challenges and associated cost pressures are causing cost
estimates for certain isolated pieces of the project to be above target
cost. However, at present such cost increases are not expected to, in
aggregate, result in total construction costs of the project being
materially different than the original target construction cost of $6.8
billion. Further, Canadian Natural remains on track for commissioning
during the third quarter of 2008.
o The Company is currently conducting the EDS stage of engineering on the
next phase (Phase 2) and in conjunction with that, is evaluating the
opportunity to combine the next two phases (Phase 2 and Phase 3). Several
options are being developed to ensure shareholder value-creation and to
manage the risks associated with expansion in a high cost inflationary
environment.
o The quarterly update for Phase 1 of the Horizon Project is as follows:
--------------------------
Q4/06 Q1/07
PROJECT STATUS SUMMARY
ACTUAL Plan Plan
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Phase 1 - Work progress (cumulative) 57% 55% 65%
Phase 1 - Construction capital spending (cumulative)* 59% 58% 68%
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* RELATES TO OVERALL PHASE 1 CONSTRUCTION CAPITAL OF $6.8 BILLION.
ACCOMPLISHED DURING THE FOURTH QUARTER OF 2006
DETAILED ENGINEERING
o Overall detailed engineering 94% complete and is substantially completed
in most areas.
PROCUREMENT
o Overall progress 84% complete. Most major equipment is purchased and on
site.
o Awarded over $5.1 billion in purchase orders and contracts to date.
o Awarded General Mechanical Contracts for Hydrotreater and Cogeneration
areas.
MODULARIZATION
o Delivered an additional 327 oversized loads to site for a total of 973
loads, representing approximately 59% of the Phase 1 total to be shipped.
CONSTRUCTION
o Overall progress 42% complete.
o Set 333 main piperack modules.
o Exceeded the 2006 High Voltage (35kV) cable pull plan by 15% (30,500
meters), ensuring that all critical pulls have been completed.
8 CANADIAN NATURAL RESOURCES LIMITED
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o 5 of 6 Modular Substations have been installed and re-instated at site,
with High Voltage cable terminations ongoing.
o Mine overburden removal has moved 25 million bank cubic meters, which is
approximately 35% complete and 4% ahead of target.
o Ore Preparation Area completed construction of the Mechanically Stabilized
Earth Shear Wall and transported the 800 tonne module assemblies onto
their foundations.
o Bitumen Production Administration Building was completed and occupied.
o Camp 3 was completed and ready for occupancy.
o Commenced Flotation Cell and Pump Box installation in Extraction.
o Began work on R1 and R2 pump house for piping corridors.
o Commenced installation of large bore piping in Coker/DRU.
MILESTONES FOR THE FIRST QUARTER OF 2007
o Complete Primary Separation Cell Piping in Extraction.
o Ready High Pressure natural gas piping for Commissioning.
o Initiate module setting in Hydrotreater area.
o Complete Cooling Tower erection.
o Complete installation of the last remaining 35kV substation.
OPERATIONS READINESS
o Canadian Natural has had operations staff involved in the design,
procurement and construction of the Horizon Project from project
commencement. Canadian Natural believes this has resulted in a design that
will be less difficult to commission and start-up had there been no
operations staff involved. The operations staff is responsible for the
commissioning and start-up of the facilities and have already prepared a
commissioning and start-up schedule which is directly linked to the
construction schedule. This allows the project team to identify challenges
early on and ensure that adequate contingency plans are in place.
o Currently there are 134 operations staff employed in the development of
start-up procedures, preparation of training programs, recruitment of
additional staff, establishment of maintenance programs and operating
several plant systems.
o The operations team has had the opportunity to test-run many programs
through the early operation of plant systems. The team is currently
operating some mine equipment and several plant facilities such as water
treatment, sewage treatment, communications, natural gas and power
distribution. As a result, the team has already developed several early
learnings that have been incorporated into later start-up plans.
o Throughout 2007, increasing focus will be placed upon commissioning and
start-up as operations staff levels increase and procedures are optimized.
CANADIAN NATURAL RESOURCES LIMITED 9
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MARKETING Quarterly Results Year End Results
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Q4/06 Q3/06 Q4/05 2006 2005
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Crude oil and NGLs pricing
WTI (1) benchmark price (US$/bbl) $ 60.21 $ 70.55 $ 60.04 $ 66.25 $ 56.61
Lloyd Blend Heavy oil differential from WTI (%) 35% 27% 40% 33% 37%
Corporate average pricing before risk
management (C$/bbl) $ 47.27 $ 62.55 $ 46.38 $ 53.65 $ 46.86
Natural gas pricing
AECO benchmark price (C$/GJ) $ 6.03 $ 5.72 $ 11.07 $ 6.62 $ 8.05
Corporate average pricing before risk
management (C$/mcf) $ 6.66 $ 5.83 $ 11.67 $ 6.72 $ 8.57
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(1) REFERS TO WEST TEXAS INTERMEDIATE CRUDE OIL BARREL PRICED AT CUSHING,
OKLAHOMA.
o Heavy crude oil differentials, as expected, widened in Q4/06 from Q3/06
averaging 35% of WTI, reflecting normal seasonality. The differential
remained favorable in comparison to Q4/05, due to the addition of heavy
oil pipeline capacity to the US Gulf Coast in spring 2006. The Company has
committed to 25,000 bbl/d of pipeline capacity on the Pegasus Pipeline,
which carries heavy crude oil from the terminus of the current pipeline
sales lines at Patoka, Illinois to the East Texas refining complex near
Nederland. Canadian Natural also continues to work with various industry
groups and strategic partners to find new markets for Western Canadian
heavy crude oil in order to mitigate the impact of supply and demand
shocks on the heavy crude oil market in North America. In early Q1/07, the
Company has experienced a narrowing of the differential to under 30%,
below seasonally expected differentials.
o During Q4/06, the Company contributed approximately 135,000 bbl/d of its
heavy crude oil streams to the Western Canadian Select ("WCS") blend as
market conditions resulted in this strategy offering the optimal pricing
for bitumen.
FINANCIAL REVIEW
o Canadian Natural has structured its financial position to profitably grow
its conventional crude oil and natural gas operations over the next
several years and to build the financial capacity to complete the Horizon
Project and other major projects. A brief summary of its strengths are:
-- A diverse asset base geographically and by product - produced in
excess of 613,000 boe/d in Q4/06, comprised of approximately 44%
natural gas and 56% crude oil - with 95% of production located in G7
countries with stable and secure economies.
-- Financial stability and liquidity - approximately $7.8 billion of bank
credit facilities, with an aggregate $1,115 million of unused bank
lines available at December 31, 2006.
o The Company's commodity hedging program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its
capital expenditure program throughout the Horizon Project construction
period. This 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. For the purpose of this program, the purchase of crude oil put options
is in addition to the above parameters. In accordance with the policy,
approximately 65% of expected crude oil volumes and approximately 75% of
expected natural gas volumes have been hedged for 2007. In addition,
77,000 bbl/d of crude oil volumes are protected by put options for 2007 at
a strike price of US$60.00 per barrel. The Company is extending its hedge
program into 2008 whereby 150,000 bbl/d of crude oil volumes have been
hedged (100,000 bbl/d of price collars with a US$60.00 floor and 50,000
bbl/d of put options with a US$55.00 strike price). In addition, 900,000
10 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
GJ/d of natural gas volumes have been hedged through the use of price
collars for the first quarter of 2008 (400,000 GJ/d with a floor of $7.00
and 500,000 GJ/d with a floor of $7.50).
o As effective as commodity hedges are against reference commodity prices, a
substantial portion of the derivative financial 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, the unrealized
risk management asset reflected, at December 31, 2006, the implied price
differentials for the non-designated hedges for future years. 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,
2006. Due to changes in the crude oil and natural gas forward pricing, and
the reversal of prior year unrealized losses, the Company recorded a net
unrealized gain of $1,013 million ($674 million after-tax) on its risk
management activities for the year ended December 31, 2006 (December 31,
2005 - unrealized loss of $925 million, $607 million after-tax), including
an unrealized gain of $241 million ($166 million after-tax) for the three
months ended December 31, 2006 (December 31, 2005 - unrealized gain of
$825 million, $583 million after-tax; September 30, 2006 - unrealized gain
of $754 million, $496 million after-tax).
o During 2006 under the terms of the Normal Course Issuer Bid that allows
for the repurchase by the Company of up to 26.9 million shares through the
facilities of the Toronto Stock Exchange and the New York Stock Exchange,
485,000 common shares were repurchased for cancellation at an average
price of $57.33/share. No shares were repurchased under this facility
during Q4/06. In Q1/07 this facility was renewed, allowing for the
repurchase of up to 26.9 million shares, again through the facilities of
the Toronto Stock Exchange and the New York Stock Exchange.
o Seventh straight year of dividend increases. The 2007 quarterly dividends
will increase 13% from $0.075 per common share to $0.085 per common share,
effective with the April 2007 payment.
OUTLOOK
The Company forecasts 2007 production levels before royalties to average
between 1,594 and 1,664 mmcf/d of natural gas and between 315 and 360 mbbl/d of
crude oil and NGLs. Q1/07 production guidance before royalties is forecast to
average between 1,696 and 1,717 mmcf/d of natural gas and between 315 and 331
mbbl/d of crude oil and NGLs. Detailed guidance on revised production levels,
capital allocation and operating costs can be found on the Company's website at
http://www.cnrl.com/investor_info/corporate_guidance/.
Detailed guidance on revised production levels, capital allocation and
operating costs can be found on the Company's website at
HTTP://WWW.CNRL.COM/INVESTOR_INFO/CORPORATE_GUIDANCE/.
CANADIAN NATURAL RESOURCES LIMITED 11
===============================================================================
YEAR-END RESERVES
DETERMINATION OF RESERVES
o For the year ended December 31, 2006, 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 proved and probable oil and natural gas reserves
and prepare Evaluation Reports on the Company's total reserves. Sproule
evaluated the Company's North American assets and Ryder Scott evaluated
its international 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 an
additional requirement to disclose both proved, and proved and probable
reserves, as well as related 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 cost between the two standards is
not material.
o The Company has disclosed proved reserves using constant prices and costs
as mandated by the SEC and has also provided proved and probable reserves
under the same parameters as voluntary additional information.
o The SEC requires that oil sands mining reserves be disclosed separately
from conventional oil and gas disclosure. Canadian Natural retained a
qualified independent reserve evaluator, GLJ Petroleum Consultants Ltd.
("GLJ"), to evaluate Phase 1 to Phase 3 of the Company's Horizon Project.
Adhering to SEC Industry Guide 7 requirements, the gross lease proved
bitumen reserves as of December 31, 2006 under constant prices were 2.3
billion barrels. The gross lease proved and probable bitumen reserves were
3.5 billion barrels.
o The Reserves 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 as to the Company's reserves.
NORTH AMERICA CONVENTIONAL NET RESERVES
o Natural gas proved reserves increased by 35%, replacing 323% of 2006
production. Similarly, crude oil and NGLs proved reserves increased by
28%, replacing 357% of production. This was accomplished at all-in finding
and on-stream cost of $15.86 per barrel of oil equivalent for proved
reserves and $9.53 per barrel of oil equivalent for proved and probable
reserves.
INTERNATIONAL CONVENTIONAL NET RESERVES
o North Sea proved reserves grew by 10 million barrels of oil equivalent to
305 million barrels of oil equivalent or about 16% of total proved Company
reserves. Reserve additions were primarily achieved through optimization
of waterflood design, an infill drilling program and recompletions.
o In Offshore West Africa, where the Government share of production is
contractually determined as a percentage of production volume and
apportioned between income tax and royalties for reserves and accounting
purposes, proved reserves decreased to 139 million barrels of oil
equivalent as a 2006 corporate income tax rate reduction effectively
increased the royalty allocations. Generally, the Company receives a
greater portion of production until capital development costs are recouped
whereupon government allocation of production substantially increases.
With the current high world crude oil price, these projects generally
require fewer of the reserves to cover payout of capital costs, thereby
reducing the reserves ultimately allocated to the Company over the field
life.
12 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CONVENTIONAL PROVED UNDEVELOPED NET RESERVES ("PUDS")
o In the Evaluation Reports, 47% of crude oil proved reserves were assigned
to the proved undeveloped category. This is a 9 percentage point increase
from the 38% recorded in 2005. Of the 2006 crude oil PUD reserves, 57% are
associated with our thermal oil sands projects where extensive pool
delineation and geological analysis justifies continued development and
expansion.
o In the Evaluation Reports, 22% of natural gas proved reserves were
assigned to the proved undeveloped category reflecting the generally
shorter lead times required for natural gas developments in Canada.
CONVENTIONAL PROVED AND PROBABLE NET RESERVES
o In the Evaluation Reports, total proved and probable reserves increased by
30%, driven largely by the 42% increase in North America.
RESERVES OF CONVENTIONAL CRUDE OIL AND NATURAL GAS, NET OF ROYALTIES(1)
DECEMBER 31, 2006
PROVED PROVED PROVED PROVED AND
DEVELOPED(2) UNDEVELOPED(2) TOTAL(2) PROBABLE(3)
- -----------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (mmbbl)
North America 420 467 887 1,502
North Sea 214 85 299 422
Offshore West Africa 63 67 130 195
- -----------------------------------------------------------------------------------------------------------------------
697 619 1,316 2,119
- -----------------------------------------------------------------------------------------------------------------------
NATURAL GAS (bcf)
North America 2,934 771 3,705 4,857
North Sea 17 20 37 93
Offshore West Africa 12 44 56 99
- -----------------------------------------------------------------------------------------------------------------------
2,963 835 3,798 5,049
- -----------------------------------------------------------------------------------------------------------------------
TOTAL RESERVES (mmboe) 1,191 758 1,949 2,961
- -----------------------------------------------------------------------------------------------------------------------
RESERVE REPLACEMENT RATIO(4) (%) 295% 472%
- -----------------------------------------------------------------------------------------------------------------------
COST TO DEVELOP(5) ($/boe)
10% discount 1.33 6.46 3.32 3.08
15% discount 1.12 5.80 2.94 2.66
- -----------------------------------------------------------------------------------------------------------------------
PRESENT VALUE OF CONVENTIONAL RESERVES(6)
($ millions)
10% discount 20,028 7,469 27,497 37,291
15% discount 17,296 5,247 22,543 29,350
=======================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 13
===============================================================================
RESERVES OF CONVENTIONAL CRUDE OIL AND NATURAL GAS, NET OF ROYALTIES(1)
DECEMBER 31, 2005
PROVED PROVED PROVED PROVED AND
DEVELOPED(2) UNDEVELOPED(2) TOTAL(2) PROBABLE(3)
- ----------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (mmbbl)
North America 402 292 694 1,035
North Sea 214 76 290 417
Offshore West Africa 80 54 134 206
- ----------------------------------------------------------------------------------------------------------------------
696 422 1,118 1,658
- ----------------------------------------------------------------------------------------------------------------------
NATURAL GAS (bcf)
North America 2,300 441 2,741 3,548
North Sea 16 13 29 69
Offshore West Africa 10 62 72 110
- ----------------------------------------------------------------------------------------------------------------------
2,326 516 2,842 3,727
- ----------------------------------------------------------------------------------------------------------------------
TOTAL RESERVES (mmboe) 1,083 509 1,592 2,279
- ----------------------------------------------------------------------------------------------------------------------
RESERVE REPLACEMENT RATIO(4) (%) 145% 195%
- ----------------------------------------------------------------------------------------------------------------------
COST TO DEVELOP(5) ($/boe)
10% discount 0.79 5.69 2.36 2.55
15% discount 0.67 5.15 2.11 2.25
- ----------------------------------------------------------------------------------------------------------------------
PRESENT VALUE OF CONVENTIONAL RESERVES(6)
($ millions)
10% discount 24,275 6,342 30,617 38,682
15% discount 20,939 4,881 25,820 31,642
======================================================================================================================
OIL SANDS MINING RESERVES(1)(7)
The following table sets out Canadian Natural's reserves of bitumen and
synthetic crude oil from the Horizon Project Oil Sands leases.
--------------------------
AS OF DEC 31, 2006 AS OF DEC 31, 2005
PROVED PROVED AND PROVED PROVED AND
TOTAL PROBABLE TOTAL PROBABLE
- -------------------------------------------------------------------------------------------------------------------
Gross reserves*, before royalties (mmbbl)
Bitumen 2,275 3,530 2,235 3,430
Synthetic crude oil 1,866 2,962 1,833 2,878
===================================================================================================================
* REPRESENTS GROSS LEASE RESERVES. SCO RESERVES ARE BASED UPON UPGRADING OF
THE BITUMEN RESERVES. THE RESERVES SHOWN FOR BITUMEN AND SCO ARE NOT
ADDITIVE.
14 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CONVENTIONAL CRUDE OIL AND NGLS RESERVES RECONCILIATION, NET OF ROYALTIES(1)
NORTH NORTH OFFSHORE
PROVED RESERVES (MMBBL) AMERICA SEA WEST AFRICA TOTAL
- ------------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2004 648 303 115 1,066
- ------------------------------------------------------------------------------------------------------------------------
Extensions and discoveries 98 -- -- 98
Infill drilling 3 3 2 8
Improved recovery -- -- -- --
Property purchases -- -- 15 15
Property disposals (3) -- -- (3)
Production (70) (25) (8) (103)
Revisions of prior estimates 18 9 10 37
- ------------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2005 694 290 134 1,118
- ------------------------------------------------------------------------------------------------------------------------
Extensions and discoveries 53 3 -- 56
Infill drilling 190 14 -- 204
Improved recovery -- 12 -- 12
Property purchases 26 -- -- 26
Property disposals -- -- -- --
Production (75) (22) (13) (110)
Revisions of prior estimates (1) 2 9 10
- ------------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2006 887 299 130 1,316
- ------------------------------------------------------------------------------------------------------------------------
PROVED AND PROBABLE RESERVES (MMBBL)
- ------------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2004 926 415 196 1,537
- ------------------------------------------------------------------------------------------------------------------------
Extensions and discoveries 200 -- -- 200
Infill drilling 3 5 6 14
Improved recovery -- -- -- --
Property purchases -- -- 17 17
Property disposals (4) -- -- (4)
Production (70) (25) (8) (103)
Revisions of prior estimates (20) 22 (5) (3)
- ------------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2005 1,035 417 206 1,658
- ------------------------------------------------------------------------------------------------------------------------
Extensions and discoveries 128 3 -- 131
Infill drilling 384 17 -- 401
Improved recovery -- 12 -- 12
Property purchases 34 -- -- 34
Property disposals -- -- -- --
Production (75) (22) (13) (110)
Revisions of prior estimates (4) (5) 2 (7)
- ------------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2006 1,502 422 195 2,119
========================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 15
===============================================================================
CONVENTIONAL NATURAL GAS RESERVES RECONCILIATION, NET OF ROYALTIES(1)
NORTH NORTH OFFSHORE
PROVED RESERVES (BCF) AMERICA SEA WEST AFRICA TOTAL
- ----------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2004 2,591 27 72 2,690
- ----------------------------------------------------------------------------------------------------------------------
Extensions and discoveries 506 -- -- 506
Infill drilling 22 -- -- 22
Improved recovery 8 -- -- 8
Property purchases 6 -- -- 6
Property disposals (23) -- -- (23)
Production (411) (7) (1) (419)
Revisions of prior estimates 42 9 1 52
- -----------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2005 2,741 29 72 2,842
- ----------------------------------------------------------------------------------------------------------------------
Extensions and discoveries 250 -- -- 250
Infill drilling 71 -- -- 71
Improved recovery 3 -- -- 3
Property purchases 1,111 -- -- 1,111
Property disposals (1) -- -- (1)
Production (433) (5) (3) (441)
Revisions of prior estimates (37) 13 (13) (37)
- ----------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2006 3,705 37 56 3,798
- ----------------------------------------------------------------------------------------------------------------------
PROVED AND PROBABLE RESERVES (BCF)
- ----------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2004 3,319 57 90 3,466
- ----------------------------------------------------------------------------------------------------------------------
Extensions and discoveries 645 -- -- 645
Infill drilling 23 -- 1 24
Improved recovery 14 -- -- 14
Property purchases 8 -- -- 8
Property disposals (30) -- -- (30)
Production (411) (7) (1) (419)
Revisions of prior estimates (20) 19 20 19
- ----------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2005 3,548 69 110 3,727
- ----------------------------------------------------------------------------------------------------------------------
Extensions and discoveries 307 -- -- 307
Infill drilling 95 -- -- 95
Improved recovery 4 -- -- 4
Property purchases 1,466 -- -- 1,466
Property disposals (1) -- -- (1)
Production (433) (5) (3) (441)
Revisions of prior estimates (129) 29 (8) (108)
- ----------------------------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2006 4,857 93 99 5,049
======================================================================================================================
16 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
The following information for reserves before royalties is provided for
comparative purposes:
CONVENTIONAL RESERVES, BEFORE ROYALTIES(1)
DECEMBER 31, 2006
PROVED PROVED PROVED PROVED AND
DEVELOPED(2) UNDEVELOPED(2) TOTAL(2) PROBABLE(3)
- -----------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (mmbbl)
North America 495 548 1,043 1,753
North Sea 214 85 299 421
Offshore West Africa 70 75 145 223
- -----------------------------------------------------------------------------------------------------------------
779 708 1,487 2,397
- -----------------------------------------------------------------------------------------------------------------
NATURAL GAS (bcf)
North America 3,587 920 4,507 5,898
North Sea 17 20 37 93
Offshore West Africa 15 54 69 121
- -----------------------------------------------------------------------------------------------------------------
3,619 994 4,613 6,112
- -----------------------------------------------------------------------------------------------------------------
TOTAL RESERVES (mmboe) 1,382 874 2,256 3,416
=================================================================================================================
DECEMBER 31, 2005
PROVED PROVED PROVED PROVED AND
DEVELOPED(2) UNDEVELOPED(2) TOTAL(2) PROBABLE(3)
- -----------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (mmbbl)
North America 462 323 785 1,154
North Sea 214 76 290 417
Offshore West Africa 86 62 148 230
- -----------------------------------------------------------------------------------------------------------------
762 461 1,223 1,801
- -----------------------------------------------------------------------------------------------------------------
NATURAL GAS (bcf)
North America 2,844 534 3,378 4,372
North Sea 16 13 29 69
Offshore West Africa 11 72 83 127
- -----------------------------------------------------------------------------------------------------------------
2,871 619 3,490 4,568
- -----------------------------------------------------------------------------------------------------------------
TOTAL RESERVES (mmboe) 1,240 564 1,804 2,562
=================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 17
===============================================================================
CONVENTIONAL FINDING AND ONSTREAM COSTS
Three Year
2006 2005 2004 Total
- ---------------------------------------------------------------------------------------------------------------------
NET RESERVE REPLACEMENT EXPENDITURES 8,727 3,361 4,259 16,347
($ millions)
NET RESERVE ADDITIONS (mmboe) ((8))
Proved 540 251 354 1,145
Proved and probable 865 337 453 1,655
FINDING AND ON STREAM COSTS ($/boe) ((9))
Proved 16.16 13.41 12.03 14.28
Proved and probable 10.09 9.97 9.40 9.88
=====================================================================================================================
- ------------
(1) RESERVE ESTIMATES AND PRESENT VALUE CALCULATIONS ARE BASED UPON YEAR END
CONSTANT REFERENCE PRICE ASSUMPTIONS AS DETAILED BELOW AS WELL AS CONSTANT
YEAR-END COSTS.
COMPANY WTI @ HARDISTY NORTH
AVERAGE CUSHING HEAVY SEA
PRICE OKLAHOMA 12(0) API BRENT
CRUDE OIL AND NGLS (C$/BBL) (US$/BBL) (C$/BBL) (US$/BBL)
- ---------------------------------------------------------------------------------------------------------------------
2006 51.11 61.05 41.94 58.93
2005 46.12 61.04 32.64 58.21
2004 32.14 44.04 17.45 40.47
=====================================================================================================================
COMPANY BRITISH COLUMBIA
AVERAGE HENRY HUB ALBERTA HUNTINGDON
PRICE LOUISIANA AECO C SUMAS
NATURAL GAS (C$/MCF) (US$/MMBTU) (C$/MMBTU) (C$/MMBTU)
- ---------------------------------------------------------------------------------------------------------------------
2006 6.07 5.52 6.13 6.52
2005 9.45 10.08 9.99 9.53
2004 6.44 6.62 6.78 6.94
=====================================================================================================================
A FOREIGN EXCHANGE RATE OF US$0.86/C$1.00 WAS USED IN THE 2006 EVALUATION;
US$0.86/C$1.00 WAS USED IN THE 2005 EVALUATION; US$0.83/C$1.00 WAS USED IN
THE 2004 EVALUATION.
- ------------
(2) 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.
(3) 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.
(4) RESERVE REPLACEMENT RATIOS WERE CALCULATED USING ANNUAL NET RESERVE
ADDITIONS COMPRISED OF ALL CHANGE CATEGORIES DIVIDED BY THE NET PRODUCTION
FOR THAT YEAR.
(5) COST TO DEVELOP REPRESENTS TOTAL DISCOUNTED FUTURE CAPITAL FOR EACH
RESERVES CATEGORY EXCLUDING ABANDONMENT CAPITAL DIVIDED BY THE RESERVES
ASSOCIATED WITH THAT CATEGORY.
(6) PRESENT VALUE OF RESERVES ARE BASED UPON DISCOUNTED CASH FLOWS ASSOCIATED
WITH PRICES AND OPERATING EXPENSES HELD CONSTANT INTO THE FUTURE, BEFORE
INCOME TAXES. FUTURE DEVELOPMENT COSTS AND ASSOCIATED MATERIAL WELL
ABANDONMENT COSTS HAVE BEEN APPLIED AGAINST FUTURE NET REVENUES.
(7) SYNTHETIC CRUDE OIL RESERVES ARE BASED ON UPGRADING OF THE BITUMEN
RESERVES USING TECHNOLOGIES IMPLEMENTED AT THE HORIZON PROJECT. THE
RESERVE VALUES SHOWN FOR BITUMEN AND SYNTHETIC CRUDE OIL ARE NOT ADDITIVE.
(8) RESERVES ADDITIONS ARE COMPRISED OF ALL CATEGORIES OF RESERVES CHANGES,
EXCLUSIVE OF PRODUCTION.
(9) RESERVES FINDING AND ON STREAM COSTS ARE DETERMINED BY DIVIDING TOTAL
CAPITAL CASH EXPENDITURES FOR EACH YEAR BY NET RESERVES ADDITIONS FOR THAT
YEAR. IT EXCLUDES COSTS ASSOCIATED WITH HEAD OFFICE, ABANDONMENTS,
MIDSTREAM AND THE HORIZON PROJECT.
18 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
MANAGEMENT'S DISCUSSION AND ANALYSIS
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
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 the Company "believes", "anticipates", "expects", "plans", "estimates",
"targets", 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, 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, 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; 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 upon other factors, 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 are made, no assurances can be
given as to future results, levels of activity and achievements. All subsequent
forward-looking statements, whether written or oral, attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by these cautionary statements. Except as required by law, the Company
assumes no obligation to update forward-looking statements should circumstances
or Management's estimates or opinions change.
CANADIAN NATURAL RESOURCES LIMITED 19
===============================================================================
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
unaudited interim consolidated financial statements for the year and three
months ended December 31, 2006 and the MD&A and the audited consolidated
financial statements for the year ended December 31, 2005.
All dollar amounts are referenced in millions of Canadian dollars, except where
noted otherwise. The financial statements have been prepared in accordance with
Canadian generally accepted accounting principles ("GAAP"). This MD&A includes
references to financial measures commonly used in the crude oil and natural gas
industry, such as adjusted net earnings from operations and cash flow from
operations. These financial measures are not defined by 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 GAAP, as an indication of the
Company's performance. The measures adjusted net earnings from operations and
cash flow from operations are reconciled to net earnings in the "Financial
Highlights" section.
Certain figures related to the presentation of gross revenues and gross
transportation and blending provided for prior periods have been reclassified
to conform to the presentation adopted in 2006.
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 presented throughout this MD&A on a "before royalty" or
"gross" basis, and realized prices exclude the effect of risk management
activities, except where noted otherwise. Production on an "after royalty" or
"net" basis is also presented for information purposes only.
The following discussion refers primarily to the Company's financial results
for the year and three months ended December 31, 2006 in relation to the
comparable periods in 2005 and the third quarter of 2006. The accompanying
tables form an integral part of this MD&A. This MD&A is dated March 3, 2007.
Additional information relating to the Company, including its Annual
Information Form for the year ended December 31, 2005, is available on SEDAR at
www.sedar.com.
20 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
FINANCIAL HIGHLIGHTS
(millions, except per common share amounts)
Three Months Ended Year Ended
------------ -------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- ------------------------------------------------------------------------------------------------------------------------
Revenue, before royalties (1) $ 2,826 $ 3,108 $ 3,319 $ 11,643 $ 11,130
Net earnings $ 313 $ 1,116 $ 1,104 $ 2,524 $ 1,050
Per common share - basic $ 0.58 $ 2.08 $ 2.06 $ 4.70 $ 1.96
- diluted $ 0.58 $ 2.08 $ 2.06 $ 4.70 $ 1.95
Adjusted net earnings from operations (2) $ 412 $ 470 $ 601 $ 1,664 $ 2,034
Per common share - basic $ 0.77 $ 0.87 $ 1.12 $ 3.10 $ 3.79
- diluted $ 0.77 $ 0.87 $ 1.12 $ 3.10 $ 3.78
Cash flow from operations (3) $ 1,293 $ 1,313 $ 1,490 $ 4,932 $ 5,021
Per common share - basic $ 2.41 $ 2.44 $ 2.78 $ 9.18 $ 9.36
- diluted $ 2.41 $ 2.44 $ 2.78 $ 9.18 $ 9.33
Capital expenditures, net of dispositions $ 6,497 $ 1,661 $ 1,679 $ 12,025 $ 4,932
========================================================================================================================
- ------------
(1) BLENDING COSTS PREVIOUSLY NETTED AGAINST GROSS REVENUES IN PRIOR PERIODS
HAVE BEEN RECLASSIFIED TO TRANSPORTATION EXPENSE TO CONFORM TO THE
PRESENTATION ADOPTED IN 2006.
(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.
THREE MONTHS ENDED YEAR ENDED
------------- -------------
DEC 31 SEP 30 DEC 31 DEC 31 DEC 31
($ MILLIONS) 2006 2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS AS REPORTED $ 313 $ 1,116 $ 1,104 $ 2,524 $ 1,050
STOCK-BASED COMPENSATION EXPENSE (RECOVERY), NET OF TAX(A) 120 (92) 75 95 481
UNREALIZED RISK MANAGEMENT (GAIN) LOSS, NET OF TAX(B) (166) (496) (583) (674) 607
UNREALIZED FOREIGN EXCHANGE LOSS (GAIN), NET OF TAX(C) 145 9 5 114 (85)
EFFECT OF STATUTORY TAX RATE CHANGES ON FUTURE INCOME TAX
LIABILITIES(D) -- (67) -- (395) (19)
- -------------------------------------------------------------------------------------------------------------------------------
ADJUSTED NET EARNINGS FROM OPERATIONS $ 412 $ 470 $ 601 $ 1,664 $ 2,034
===============================================================================================================================
- ------------
(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,
OR ARE CAPITALIZED TO THE HORIZON OIL SANDS PROJECT.
(B) FINANCIAL INSTRUMENTS NOT DESIGNATED AS HEDGES ARE RECORDED AT FAIR VALUE
ON THE 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. INCOME TAX RATE CHANGES DURING
2006 RESULTED IN A REDUCTION OF FUTURE INCOME TAX LIABILITIES OF
APPROXIMATELY $438 MILLION IN NORTH AMERICA, AN INCREASE OF FUTURE INCOME
TAX LIABILITIES OF APPROXIMATELY $110 MILLION IN THE UK NORTH SEA AND A
REDUCTION OF FUTURE INCOME TAX LIABILITIES OF APPROXIMATELY $67 MILLION IN
COTE D'IVOIRE. DURING 2005, NORTH AMERICA INCOME TAX RATE CHANGES RESULTED
IN A REDUCTION OF FUTURE INCOME TAX LIABILITIES OF APPROXIMATELY $19
MILLION.
CANADIAN NATURAL RESOURCES LIMITED 21
===============================================================================
(3) CASH FLOW FROM OPERATIONS IS A NON-GAAP TERM THAT REPRESENTS NET EARNINGS
ADJUSTED FOR NON-CASH ITEMS. THE COMPANY EVALUATES ITS PERFORMANCE BASED
ON CASH FLOW FROM OPERATIONS. THE COMPANY CONSIDERS CASH FLOW FROM
OPERATIONS A KEY MEASURE AS IT DEMONSTRATES THE COMPANY'S ABILITY TO
GENERATE THE CASH FLOW NECESSARY TO FUND FUTURE GROWTH THROUGH CAPITAL
INVESTMENT AND TO REPAY DEBT. CASH FLOW FROM OPERATIONS MAY NOT BE
COMPARABLE TO SIMILAR MEASURES PRESENTED BY OTHER COMPANIES.
THREE MONTHS ENDED YEAR ENDED
------------- ------------
DEC 31 SEP 30 DEC 31 DEC 31 DEC 31
($ MILLIONS) 2006 2006 2005 2006 2005
- --------------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 313 $ 1,116 $ 1,104 $ 2,524 $ 1,050
NON-CASH ITEMS:
DEPLETION, DEPRECIATION AND AMORTIZATION 724 589 550 2,391 2,013
ASSET RETIREMENT OBLIGATION ACCRETION 18 17 16 68 69
STOCK-BASED COMPENSATION EXPENSE (RECOVERY) 176 (135) 125 139 723
UNREALIZED RISK MANAGEMENT (GAIN) LOSS (241) (754) (825) (1,013) 925
UNREALIZED FOREIGN EXCHANGE LOSS (GAIN) 171 11 5 134 (103)
DEFERRED PETROLEUM REVENUE TAX (RECOVERY) EXPENSE (3) (4) 1 37 (9)
FUTURE INCOME TAX EXPENSE 135 473 514 652 353
- --------------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS $ 1,293 $ 1,313 $ 1,490 $ 4,932 $ 5,021
==========================================================================================================================
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
For the year ended December 31, 2006, the Company reported record net earnings
of $2,524 million compared to net earnings of $1,050 million for the year ended
December 31, 2005. Net earnings for the year ended December 31, 2006 included
unrealized after-tax income of $860 million related to the effects of risk
management activities, statutory tax rate changes on future income tax
liabilities, fluctuations in foreign exchange rates and stock-based
compensation expense, compared to $984 million of net after-tax expenses for
the year ended December 31, 2005. Excluding these items, adjusted net earnings
from operations for the year ended December 31, 2006 decreased to $1,664
million from $2,034 million for the year ended December 31, 2005, primarily due
to decreased natural gas pricing, increased realized risk management losses on
crude oil, increased production expense and depletion, depreciation and
amortization expense and the impact of a stronger Canadian dollar relative to
the US dollar. These factors were partially offset by stronger benchmark crude
oil pricing and increased crude oil and NGLs and natural gas sales volumes.
Fourth quarter 2006 net earnings were $313 million compared to net earnings of
$1,104 million in the fourth quarter of 2005 and net earnings of $1,116 million
in the prior quarter. Net earnings in the fourth quarter of 2006 included
unrealized after-tax expenses of $99 million related to the effects of risk
management activities, fluctuations in foreign exchange rates and stock-based
compensation expense, compared to net after-tax income of $503 million in the
fourth quarter of 2005 and $646 million of after-tax income in the prior
quarter. Excluding these items, adjusted net earnings from operations in the
fourth quarter of 2006 decreased to $412 million from $601 million in the
comparable period in 2005, and decreased from $470 million in the prior
quarter. The decrease from the comparable period in 2005 was primarily due to
decreased natural gas pricing, increased Company-wide production expense,
increased depletion, depreciation and amortization expense and the impact of a
stronger Canadian dollar relative to the US dollar. These factors were
partially offset by the impact of increased crude oil pricing, increased crude
oil and NGLs and natural gas sales volumes and decreased realized risk
management losses on crude oil. The decrease from the prior quarter was
primarily due to decreased crude oil and NGLs pricing and increased depletion,
depreciation and amortization expense, partially offset by increased natural
gas pricing, increased crude oil and NGLs and natural gas sales volumes and
decreased realized risk management losses. Operating results in the fourth
quarter of 2006 were impacted by the acquisition of Anadarko Canada Corporation
("ACC") completed in November 2006. The Company completed the acquisition of
ACC, a subsidiary of Anadarko Petroleum Corporation, for net cash consideration
of $4,641 million including working capital and other adjustments.
Substantially all of ACC's land and production base is located in Western
Canada and consists of natural gas weighted assets. The operating results of
ACC have been consolidated with the results of the Company effective November
2006. This acquisition increased fourth quarter 2006 sales volumes by
22 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
approximately 44,800 boe/d. Natural gas production from the ACC properties
averaged 354 mmcf/d for the two months of November and December.
The Company expects that consolidated net earnings will continue to reflect
significant quarterly volatility due to the impact of risk management
activities, stock-based compensation expense and fluctuations in foreign
exchange rates.
The Company's commodity hedging program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its capital
expenditure program throughout the Horizon Oil Sands Project ("Horizon
Project") construction period. This 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. For the purpose of this program, the purchase of crude oil put options
is in addition to the above parameters. In accordance with the policy,
approximately 65% of expected crude oil volumes and approximately 75% of
expected natural gas volumes have been hedged for 2007. In addition, 77,000
bbl/d of crude oil volumes are protected by put options for 2007 at a strike
price of US$60.00 per barrel. The Company is extending its hedge program into
2008 whereby 150,000 bbl/d of crude oil volumes have been hedged (100,000 bbl/d
of price collars with a US$60.00 floor and 50,000 bbl/d of put options with a
US$55.00 strike price). In addition, 900,000 GJ/d of natural gas volumes have
been hedged through the use of price collars for the first quarter of 2008
(400,000 GJ/d with a floor of $7.00 and 500,000 GJ/d with a floor of $7.50).
As effective as the Company's hedges are against reference commodity prices, a
portion of the derivative financial 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, the unrealized risk management asset reflects, at December
31, 2006, the implied price differentials for the non-designated hedges for
future periods. 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, 2006.
Due to the changes in crude oil and natural gas forward pricing, and the
reversal of prior year unrealized losses, the Company recorded a net unrealized
gain of $1,013 million ($674 million after-tax) on its risk management
activities for the year ended December 31, 2006, including an unrealized gain
of $241 million ($166 million after-tax) for the three months ended December
31, 2006. Mark-to-market unrealized gains and losses do not impact the
Company's current cash flow or its ability to finance ongoing capital programs.
The Company continues to believe that its risk management program meets its
objective of securing funding for its capital projects and does not intend to
alter its current strategy of obtaining price certainty for its crude oil and
natural gas sales.
The Company also recorded a $139 million ($95 million after-tax) stock-based
compensation expense for the year ended December 31, 2006 in connection with
the 8% increase in the Company's share price, and a $176 million ($120 million
after-tax) stock-based compensation expense as a result of the 22% increase in
the Company's share price for the three months ended December 31, 2006
(Company's share price as at: December 31, 2006 - C$62.15; September 30, 2006 -
C$50.94; December 31, 2005 - C$57.63). As required by GAAP, the Company records
a liability for potential cash payments to settle its outstanding employee
stock options each reporting period, based on the difference between the
exercise price of the stock options and the market price of the Company's
common shares, pursuant to a graded vesting schedule. The liability is revalued
each quarter to reflect the 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 earnings, or capitalized as part of the Horizon Project
during the construction period. The stock-based compensation liability
reflected the Company's potential cash liability should all the vested options
be surrendered for a cash payout at the market price on December 31, 2006. In
periods when substantial share price changes occur, the Company's net earnings
are subject to significant volatility. The Company utilizes its stock-based
compensation plan to attract and retain employees in a competitive environment.
All employees participate in this plan.
Cash flow from operations for the year ended December 31, 2006 decreased
slightly to $4,932 million from $5,021 million for the year ended December 31,
2005. The decrease was primarily due to decreased natural gas pricing,
increased realized risk management losses, increased production expense and the
impact of a stronger Canadian dollar relative to the US dollar. These factors
were partially offset by stronger benchmark crude oil pricing and increased
crude oil and NGLs and natural gas sales volumes.
CANADIAN NATURAL RESOURCES LIMITED 23
===============================================================================
Cash flow from operations in the fourth quarter of 2006 decreased to $1,293
million from $1,490 million for the fourth quarter of 2005 and $1,313 million
in the prior quarter. The decrease from the fourth quarter of 2005 was
primarily due to decreased natural gas pricing, increased production expense
and the impact of a stronger Canadian dollar relative to the US dollar. These
factors were offset by the impact of increased crude oil pricing, increased
crude oil and NGLs and natural gas sales volumes and decreased realized risk
management losses.
Total production before royalties increased 5% to average a record 580,724
boe/d for the year ended December 31, 2006 from 552,960 boe/d for the year
ended December 31, 2005. Production for the fourth quarter of 2006 increased 6%
to 613,764 boe/d from 577,505 boe/d in the fourth quarter of 2005 and increased
9% from 561,152 boe/d in the prior quarter.
The increase in crude oil and NGLs production for the year and three months
ended December 31, 2006 from the comparable periods reflected increased
production from the Company's Primrose thermal projects, the positive results
from the Pelican Lake waterflood project, additional production volumes as a
result of the ACC acquisition, development of West and East Espoir and the full
year's impact of production from the Baobab Field located offshore Cote
d'Ivoire. Production from the Baobab Field commenced August 2005.
The increase in natural gas production for the year and three months ended
December 31, 2006 from the comparable periods primarily reflected additional
natural gas production as a result of the ACC acquisition. Natural gas
production from the ACC properties averaged 354 mmcf/d for the two months of
November and December. The increase was partially offset by declining
production due to the Company's strategic reduction in natural gas drilling
activity and increased North America crude oil drilling, made in response to
sustained low natural gas prices and inflationary cost pressures.
OPERATING HIGHLIGHTS
Three Months Ended Year Ended
------------ -------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
Sales price (2) $ 47.27 $ 62.55 $ 46.38 $ 53.65 $ 46.86
Royalties 4.10 5.11 3.89 4.48 3.97
Production expense 12.32 13.47 10.33 12.29 11.17
- -------------------------------------------------------------------------------------------------------------------
Netback $ 30.85 $ 43.97 $ 32.16 $ 36.88 $ 31.72
- -------------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
Sales price (2) $ 6.66 $ 5.83 $ 11.67 $ 6.72 $ 8.57
Royalties 1.26 1.11 2.30 1.29 1.75
Production expense 0.86 0.84 0.76 0.82 0.73
- -------------------------------------------------------------------------------------------------------------------
Netback $ 4.54 $ 3.88 $ 8.61 $ 4.61 $ 6.09
- -------------------------------------------------------------------------------------------------------------------
BARRELS OF OIL EQUIVALENT ($/boe) (1)
Sales price (2) $ 43.91 $ 51.21 $ 56.08 $ 47.92 $ 48.77
Royalties 5.62 5.75 8.01 5.89 6.82
Production expense 9.16 10.01 7.93 9.14 8.21
- -------------------------------------------------------------------------------------------------------------------
Netback $ 29.13 $ 35.45 $ 40.14 $ 32.89 $ 33.74
===================================================================================================================
- ------------
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
24 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
BUSINESS ENVIRONMENT
Three Months Ended Year Ended
-------------- ---------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- ------------------------------------------------------------------------------------------------------------------------------
WTI benchmark price (US$/bbl) $ 60.21 $ 70.55 $ 60.04 $ 66.25 $ 56.61
Dated Brent benchmark price (US$/bbl) $ 59.68 $ 69.58 $ 56.93 $ 65.18 $ 54.45
Differential to LLB blend (US$/bbl) $ 21.31 $ 19.08 $ 24.09 $ 21.69 $ 20.83
LLB blend differential from WTI (%) 35% 27% 40% 33% 37%
Condensate benchmark price (US$/bbl) $ 59.59 $ 70.26 $ 60.41 $ 66.24 $ 57.25
NYMEX benchmark price (US$/mmbtu) $ 6.61 $ 6.52 $ 12.83 $ 7.26 $ 8.56
AECO benchmark price (C$/GJ) $ 6.03 $ 5.72 $ 11.07 $ 6.62 $ 8.05
US / Canadian dollar average
exchange rate (US$) 0.8781 0.8919 0.8523 0.8818 0.8253
==============================================================================================================================
COMMODITY PRICES
World benchmark crude oil prices increased during the first part of the year
due to ongoing demand growth and geopolitical uncertainties. However, pricing
significantly declined later in the year, reflecting high crude oil
inventories. In December 2006 West Texas Intermediate ("WTI") averaged US$62.09
per bbl, a decline of 21% from the record high of US$78.40 per bbl reached in
July 2006. WTI averaged US$66.25 per bbl for the year ended December 31, 2006,
an increase of 17% compared to US$56.61 per bbl for the year ended December 31,
2005. In the fourth quarter of 2006, WTI averaged US$60.21 per bbl, up slightly
from US$60.04 per bbl in the comparable period in 2005, and decreased 15% from
US$70.55 per bbl in the prior quarter.
The Company's realized crude oil price increased from the comparable periods in
2005 as a result of the increased WTI price and the narrower Heavy Crude Oil
Differential from WTI ("Heavy Differential"). Heavy Differentials averaged 33%
for the year ended December 31, 2006 compared to 37% for the year ended
December 31, 2005. In the fourth quarter of 2006, Heavy Differentials averaged
35% compared to 40% for the fourth quarter of 2005, but widened compared to the
prior quarter. The narrowing of the Heavy Differentials from the comparable
periods in 2005 was primarily due to reduced availability of imported grades
from Venezuela and Mexico, reduced Canadian production of heavy crude oil and
the removal of logistical constraints in accessing new markets in the US Gulf
Coast due to the Pegasus and Spearhead pipelines commencing operations during
2006. The widening of the Heavy Differentials from the prior quarter reflected
reduced seasonal demand for asphalt products. The increase in realized crude
oil prices from the comparable periods in 2005 was partially offset by the
negative impact of a strengthening Canadian dollar relative to the US dollar. A
strengthening Canadian dollar reduces the Canadian dollar sales price the
Company receives for its crude oil sales, as crude oil prices are based on US
dollar denominated benchmarks.
The Company anticipates continued volatility in the crude oil markets as
inventory levels remain high and given the unpredictable nature of geopolitical
events.
Dated Brent ("Brent") averaged US$65.18 per bbl for the year ended December 31,
2006, an increase of 20% compared to US$54.45 per bbl for the year ended
December 31, 2005. In the fourth quarter of 2006, Brent averaged US$59.68 per
bbl, an increase of 5% from US$56.93 per bbl in the comparable period in 2005
and decreased 14% from US$69.58 per bbl in the prior quarter. Crude oil sales
contracts for the Company's North Sea and Offshore West Africa segments are
typically based on Brent pricing, which benefited from strong European and
Asian demand in 2006.
NYMEX natural gas prices averaged US$7.26 per mmbtu for the year ended December
31, 2006, a decrease of 15% from US$8.56 per mmbtu for the year ended December
31, 2005. In the fourth quarter of 2006, the NYMEX natural gas price decreased
48% to average US$6.61 per mmbtu from US$12.83 per mmbtu in the comparable
period in 2005, and increased marginally from US$6.52 per mmbtu in the prior
quarter. AECO natural gas pricing for the year ended December 31, 2006
decreased 18% from the year ended December 31, 2005 to average C$6.62 per GJ.
AECO natural gas pricing for the fourth quarter of 2006 decreased 46% from the
comparable period in 2005 and increased 5% from the prior quarter to average
C$6.03 per GJ. The decrease in natural gas pricing in 2006 from the comparable
CANADIAN NATURAL RESOURCES LIMITED 25
===============================================================================
periods in 2005 reflected the impact of exceptionally mild winter weather and
reduced heating demand, relatively stable summer weather and reduced cooling
demand and the continuing impact of high natural gas inventory levels.
The Company anticipates a challenging natural gas pricing environment in the
near term given the high storage levels. Longer term natural gas pricing will
continue to be weather dependent.
OPERATING AND CAPITAL COSTS
Strong commodity prices in recent years have resulted in increased demand and
costs for oilfield services worldwide. This has lead to inflationary production
and capital cost pressures throughout the North America oil and gas industry,
particularly related to natural gas drilling activity and oil sands
developments. The strong commodity price environment has also impacted costs in
international basins. Specifically, the high demand for offshore drilling rigs
continues and securing rigs on commercially acceptable terms is an ongoing
challenge.
The oil and gas industry is also experiencing cost pressures related to
increasingly stringent environmental regulations, both in North America and
internationally. In addition, environmental regulations in Canada intended to
reduce greenhouse gas emissions are pending and the impact of the legislation
is uncertain at this time.
These increased cost pressures and environmental regulations may adversely
impact the Company's future net earnings, cash flow and capital projects.
PRODUCT PRICES (1)
Three Months Ended Year Ended
------------ -------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- ------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (2)
North America $ 40.27 $ 55.97 $ 37.96 $ 46.52 $ 39.62
North Sea $ 67.72 $ 78.68 $ 66.88 $ 72.62 $ 66.57
Offshore West Africa $ 63.50 $ 70.59 $ 60.19 $ 67.99 $ 59.91
Company average $ 47.27 $ 62.55 $ 46.38 $ 53.65 $ 46.86
NATURAL GAS ($/mcf) (2)
North America $ 6.70 $ 5.86 $ 11.79 $ 6.77 $ 8.65
North Sea $ 3.48 $ 2.38 $ 3.40 $ 2.66 $ 3.17
Offshore West Africa $ 5.72 $ 4.97 $ 5.13 $ 5.37 $ 5.91
Company average $ 6.66 $ 5.83 $ 11.67 $ 6.72 $ 8.57
COMPANY AVERAGE ($/boe) (2) $ 43.91 $ 51.21 $ 56.08 $ 47.92 $ 48.77
PERCENTAGE OF REVENUE
(excluding midstream revenue)
Crude oil and NGLs 60% 72% 48% 64% 54%
Natural gas 40% 28% 52% 36% 46%
===============================================================================================================
- ------------
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
26 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
The Company's realized crude oil prices increased 14% to average $53.65 per bbl
for the year ended December 31, 2006 from $46.86 per bbl for the year ended
December 31, 2005. Realized crude oil prices for the fourth quarter of 2006
averaged $47.27 per bbl, a marginal increase from $46.38 per bbl in the fourth
quarter of 2005, and decreased 24% from $62.55 per bbl in the prior quarter.
The increase for the year ended December 31, 2006 from the year ended December
31, 2005 was due to increased benchmark crude oil prices and a narrower Heavy
Differential, partially offset by the impact of a stronger Canadian dollar. The
decrease in the fourth quarter of 2006 from the prior quarter primarily
reflected decreased benchmark crude oil prices and higher crude oil
inventories, and the widening Heavy Differential in Canada due to reduced
seasonal demand for asphalt products.
The Company's realized natural gas price decreased 22% to average $6.72 per mcf
for the year ended December 31, 2006 from $8.57 per mcf for the year ended
December 31, 2005. In the fourth quarter of 2006, the Company's realized
natural gas price decreased 43% from $11.67 per mcf in the fourth quarter of
2005 but increased 14% from $5.83 per mcf in the prior quarter. The decrease
from the comparable periods in 2005 reflected record levels of natural gas
inventory in North America, primarily due to the impact of exceptionally mild
winter weather in 2006 that reduced heating demand and relatively stable summer
weather that reduced cooling demand. The increase from the prior quarter
reflected seasonal pricing increases due to heating demand.
NORTH AMERICA
North America realized crude oil prices increased 17% to average $46.52 per bbl
for the year ended December 31, 2006 from $39.62 per bbl for the year ended
December 31, 2005. Realized crude oil prices in the fourth quarter of 2006
averaged $40.27 per bbl, a 6% increase from $37.96 per bbl in the comparable
period in 2005, and decreased 28% from $55.97 per bbl in the prior quarter. The
increase from the comparable periods in 2005 was due to increased benchmark
crude oil prices and a narrower Heavy Differential, partially offset by the
impact of a stronger Canadian dollar. The decrease in the fourth quarter of
2006 from the prior quarter primarily reflected decreased benchmark crude oil
prices and higher crude oil inventories, and the widening Heavy Differential
due to reduced seasonal demand.
In North America, the Company continues to focus on its crude oil marketing
strategy, including the development of a blending strategy that expands markets
within current pipeline infrastructure, supporting pipeline projects that will
provide capacity to transport crude oil to new markets, and working with
refiners to add incremental heavy crude oil conversion capacity. During the
fourth quarter, the Company contributed approximately 135,000 bbl/d of heavy
crude oil blends to the Western Canadian Select ("WCS") stream. The Company
also continues to work with refiners to advance expansion of heavy crude oil
conversion capacity, and is working with pipeline companies to develop new
capacity to the Canadian West Coast and the US Gulf Coast where crude oil
cargos can be sold on a world-wide basis. With a view to expanding markets for
its heavy crude oil, the Company has committed to 25,000 bbl/d of capacity on
the Pegasus Pipeline, which carries crude oil to the Gulf of Mexico. The
Pegasus Pipeline is made up of a series of segments extending from Patoka,
Illinois to Nederland, Texas, near the Gulf Coast. The Company's first sales
from the Pegasus Pipeline occurred in April 2006. In the third quarter of 2006,
the Company entered into an agreement to supply 25,000 bbl/d of heavy crude oil
production to a new merchant upgrader to be constructed in Alberta. The
agreement is for a period of five years, with first deliveries anticipated to
occur in 2010 upon completion of construction of the facilities.
North America realized natural gas prices decreased 22% to average $6.77 per
mcf for the year ended December 31, 2006 from $8.65 per mcf for the year ended
December 31, 2005. The realized natural gas price in the fourth quarter of 2006
averaged $6.70 per mcf, a decrease of 43% from $11.79 per mcf in the fourth
quarter of 2005, and increased 14% from $5.86 per mcf in the prior quarter. The
decrease from the comparable periods in 2005 was primarily due to reduced
winter heating demand and reduced summer cooling demand in 2006.
CANADIAN NATURAL RESOURCES LIMITED 27
===============================================================================
A comparison of the price received for the Company's North America production
by product type is as follows:
----------------
DEC 31 Sep 30 Dec 31
2006 2006 2005
- ----------------------------------------------------------------------------------------------------------
Wellhead Price (1) (2)
Light / medium crude oil and NGLs (C$/bbl) $ 54.11 $ 72.25 $ 61.33
Pelican Lake crude oil (C$/bbl) $ 37.89 $ 53.84 $ 34.86
Primary heavy crude oil (C$/bbl) $ 36.16 $ 52.15 $ 31.00
Thermal heavy crude oil (C$/bbl) $ 36.06 $ 50.36 $ 28.84
Natural gas (C$/mcf) $ 6.70 $ 5.86 $ 11.79
==========================================================================================================
- ------------
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
NORTH SEA
North Sea realized crude oil prices increased 9% to average $72.62 per bbl for
the year ended December 31, 2006 from $66.57 per bbl for the year ended
December 31, 2005. Realized crude oil prices in the fourth quarter of 2006
increased marginally to average $67.72 per bbl from $66.88 per bbl in the
fourth quarter of 2005 and decreased 14% from $78.68 per bbl in the prior
quarter. The increase in the realized crude oil price from the comparable
periods in 2005 was due mainly to the impact of strong European and Asian
demand on Brent pricing, partially offset by the strengthening Canadian dollar
in 2006 compared to 2005. The decrease from the prior quarter primarily
reflected decreased benchmark crude oil prices and higher crude oil
inventories.
OFFSHORE WEST AFRICA
Offshore West Africa realized crude oil prices increased 13% to average $67.99
per bbl for the year ended December 31, 2006 from $59.91 per bbl for the year
ended December 31, 2005. Realized crude oil prices for the fourth quarter of
2006 increased 5% to average $63.50 per bbl from $60.19 per bbl in the fourth
quarter of 2005 and decreased 10% from $70.59 per bbl in the prior quarter. The
increase in the realized crude oil price from the comparable periods in 2005
was due mainly to the impact of strong European and Asian demand on Brent
pricing, partially offset by the strengthening Canadian dollar. The decrease
from the prior quarter primarily reflected decreased benchmark crude oil prices
and higher crude oil inventories.
CRUDE OIL INVENTORY VOLUMES
The Company recognizes revenue on its crude oil production when title transfers
to the customer and delivery has taken place. The related life-to-date crude
oil inventory volumes by segment, which have not been recognized in revenue,
were as follows:
---------------
DEC 31 Sep 30 Dec 31
(bbl) 2006 2006 2005
- -----------------------------------------------------------------------------------------------------------
North America, related to pipeline fill 1,097,526 1,097,526 484,157
North Sea, related to timing of liftings 910,796 243,635 747,141
Offshore West Africa, related to timing of liftings 113,774 711,096 412,841
- -----------------------------------------------------------------------------------------------------------
2,122,096 2,052,257 1,644,139
===========================================================================================================
In the fourth quarter of 2006, net sales of approximately 70,000 barrels of
crude oil produced in the Company's international operations were deferred and
excluded from the fourth quarter results of operations. This change in crude
oil inventory volumes increased cash flow from operations by approximately $15
million in the fourth quarter of 2006, due to the increase in higher netback
Offshore West Africa sales volumes, partially offset by the decrease in lower
netback North Sea sales volumes.
28 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
DAILY PRODUCTION, BEFORE ROYALTIES
Three Months Ended Year Ended
-------------- --------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 249,565 233,440 230,263 235,253 221,669
North Sea 61,786 53,988 66,798 60,056 68,593
Offshore West Africa 32,354 34,237 43,207 36,689 22,906
- -------------------------------------------------------------------------------------------------------------------------------
343,705 321,665 340,268 331,998 313,168
- -------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,594 1,416 1,402 1,468 1,416
North Sea 16 11 15 15 19
Offshore West Africa 10 10 6 9 4
- -------------------------------------------------------------------------------------------------------------------------------
1,620 1,437 1,423 1,492 1,439
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d) 613,764 561,152 577,505 580,724 552,960
- -------------------------------------------------------------------------------------------------------------------------------
PRODUCT MIX
Light/medium crude oil and NGLs 24% 24% 28% 26% 26%
Pelican Lake crude oil 5% 5% 5% 5% 4%
Primary heavy crude oil 15% 16% 17% 16% 17%
Thermal heavy crude oil 12% 12% 9% 11% 10%
Natural gas 44% 43% 41% 42% 43%
===============================================================================================================================
DAILY PRODUCTION, NET OF ROYALTIES
Three Months Ended Year Ended
------------- --------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 217,751 205,087 198,047 205,382 191,751
North Sea 61,658 53,911 66,664 59,940 68,487
Offshore West Africa 30,817 31,864 42,081 35,212 22,293
- -------------------------------------------------------------------------------------------------------------------------------
310,226 290,862 306,792 300,534 282,531
- -------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,291 1,144 1,124 1,185 1,125
North Sea 16 11 15 15 18
Offshore West Africa 9 9 6 9 4
- -------------------------------------------------------------------------------------------------------------------------------
1,316 1,164 1,145 1,209 1,147
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d) 529,515 484,872 497,679 502,024 473,742
===============================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 29
===============================================================================
Daily production and per barrel statistics are presented throughout the MD&A on
a "before royalty" or "gross" basis. Production on an "after royalty" or "net"
basis is also presented.
The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces; namely
natural gas, light/medium crude oil and NGLs, Pelican Lake crude oil, primary
heavy crude oil and thermal heavy crude oil.
Total production averaged a record 580,724 boe/d for the year ended December
31, 2006, a 5% increase from the year ended December 31, 2005. Fourth quarter
total production in 2006 averaged a record 613,764 boe/d, an increase of 6%
from the fourth quarter of 2005 and an increase of 9% from the prior quarter.
The increase in crude oil and NGLs production from the comparable periods in
2005 and the prior quarter reflected increased production from the Company's
Primrose thermal projects, the positive results from the Pelican Lake
waterflood project, additional production volumes from the ACC acquisition,
development of West and East Espoir and the full year's impact of production
from the Baobab Field located offshore Cote d'Ivoire. Production from the
Baobab Field commenced August 2005. The increase in natural gas production from
the comparable periods in 2005 and the prior quarter primarily reflected
additional natural gas production from the ACC acquisition. The increase was
partially offset by the production decrease due to the Company's strategic
reduction in natural gas drilling activity and increased North America crude
oil drilling, made in response to sustained low natural gas prices and
inflationary cost pressures.
Total crude oil and NGLs production for the year ended December 31, 2006
increased 6% to 331,998 bbl/d from 313,168 bbl/d for the year ended December
31, 2005. In the fourth quarter of 2006, production increased slightly to
343,705 bbl/d from 340,268 bbl/d in the fourth quarter of 2005 and increased 7%
from 321,665 bbl/d in the prior quarter. Crude oil and NGLs production in the
fourth quarter of 2006 was on the high end of the Company's previously issued
guidance of 324,000 to 344,000 bbl/d.
Natural gas production continues to represent the Company's largest product
offering, accounting for over 40% of the Company's total production. Natural
gas production for the year ended December 31, 2006 averaged 1,492 mmcf/d
compared to 1,439 mmcf/d for the year ended December 31, 2005. In the fourth
quarter of 2006, natural gas production increased 14% to average 1,620 mmcf/d
from 1,423 mmcf/d in the fourth quarter of 2005 and increased 13% from 1,437
mmcf/d in the prior quarter. Fourth quarter natural gas production was at the
low end of the Company's previously issued guidance of 1,620 to 1,658 mmcf/d,
primarily due to the impact of the Company's decision to reduce natural gas
drilling activity in 2006 in response to inflationary costs in western Canada.
In 2007, annual production is forecasted to average between 315,000 and 360,000
bbl/d of crude oil and NGLs and between 1,594 and 1,664 mmcf/d of natural gas.
First quarter 2007 production guidance is forecasted to average between 315,000
and 331,000 bbl/d of crude oil and NGLs and between 1,696 and 1,717 mmcf/d of
natural gas.
NORTH AMERICA
North America crude oil and NGLs production for the year ended December 31,
2006 increased 6% to average 235,253 bbl/d from 221,669 bbl/d for the year
ended December 31, 2005. Production in the fourth quarter of 2006 increased 8%
to average 249,565 bbl/d from 230,263 bbl/d in the fourth quarter of 2005 and
increased 7% from 233,440 bbl/d in the prior quarter. The increase in crude oil
and NGLs production from the comparable periods in 2005 and the prior quarter
was primarily due to increased production from the Company's Primrose thermal
projects, the positive results from the Pelican Lake waterflood project and the
ACC acquisition.
North America natural gas production averaged 1,468 mmcf/d for the year ended
December 31, 2006, an increase of 4% from 1,416 mmcf/d for the year ended
December 31, 2005. Fourth quarter 2006 production increased 14% to average
1,594 mmcf/d from 1,402 mmcf/d in the fourth quarter of 2005 and increased 13%
from 1,416 mmcf/d in the prior quarter. The increase in natural gas production
from the comparable periods in 2005 and the prior quarter reflected November
and December natural gas production from the ACC acquisition, partially offset
by production declines due to the Company's decision to reduce natural gas
drilling activity. The ACC acquisition was completed in November with results
included from that date. To date, the ACC properties are performing as
expected.
30 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
NORTH SEA
North Sea crude oil production for the year ended December 31, 2006 averaged
60,056 bbl/d, a 12% decrease from 68,593 bbl/d for the year ended December 31,
2005. Crude oil production in the fourth quarter of 2006 decreased 8% to
average 61,786 bbl/d from 66,798 bbl/d in the comparable period in 2005, and
increased 14% from the prior quarter production of 53,988 bbl/d. Production
levels for the fourth quarter were in line with expectations, reflecting the
production effects of planned maintenance shutdowns in the third quarter of
2006.
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production for the year ended December 31, 2006
increased 60% to 36,689 bbl/d from 22,906 bbl/d for the year ended December 31,
2005. Production during the fourth quarter of 2006 decreased 25% from 43,207
bbl/d in the fourth quarter of 2005 and decreased 5% from the prior quarter.
The increase from the year ended December 31, 2005 was primarily due to the
impact of a full year's production from the Baobab Field, first crude oil from
West Espoir and a successful infill drilling campaign at East Espoir. The
increase was partially offset by continuing challenges with sand and solids
production at the Baobab Field that resulted in the shut in of 5 production
wells. The Company does not plan to recomplete these wells until such time as a
deepwater rig can be secured on commercially acceptable terms.
ROYALTIES
Three Months Ended Year Ended
-------------- ----------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 5.13 $ 6.79 $ 5.39 $ 5.86 $ 5.37
North Sea $ 0.14 $ 0.11 $ 0.14 $ 0.13 $ 0.10
Offshore West Africa $ 3.02 $ 4.89 $ 1.57 $ 2.81 $ 1.62
Company average $ 4.10 $ 5.11 $ 3.89 $ 4.48 $ 3.97
NATURAL GAS ($/mcf) (1)
North America $ 1.29 $ 1.12 $ 2.34 $ 1.31 $ 1.78
North Sea $ -- $ -- $ -- $ -- $ --
Offshore West Africa $ 0.27 $ 0.34 $ 0.14 $ 0.22 $ 0.16
Company average $ 1.26 $ 1.11 $ 2.30 $ 1.29 $ 1.75
COMPANY AVERAGE ($/boe) (1) $ 5.62 $ 5.75 $ 8.01 $ 5.89 $ 6.82
PERCENTAGE OF REVENUE (2)
Crude oil and NGLs 9% 8% 8% 8% 8%
Natural gas 19% 19% 20% 19% 20%
Company average boe 13% 11% 14% 12% 14%
===============================================================================================================================
- ------------
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
CANADIAN NATURAL RESOURCES LIMITED 31
===============================================================================
NORTH AMERICA
North America crude oil and NGL royalties per bbl for the year and three months
ended December 31, 2006 were primarily a reflection of increased realized crude
oil prices and the full recovery of the Company's capital investments in the
Primrose North and South Fields in the third quarter of 2006. Upon full
recovery, Crown royalty rates on the Primrose North and South Fields increased
from 1% of gross revenue to 25% of gross revenue less operating, capital and
abandonment costs. North America crude oil and NGL royalties averaged
approximately 13% of gross revenues in 2006. Crude oil and NGLs royalties per
bbl are anticipated to be 14% to 16% of gross revenues in 2007.
Natural gas royalties per mcf decreased from the comparable periods in 2005 and
increased from the prior quarter in line with benchmark natural gas prices.
Benchmark natural gas prices in 2006 decreased from the comparable periods in
2005 primarily in response to reduced demand and increased storage levels.
Strengthening benchmark natural gas prices in the fourth quarter of 2006
resulted in increased natural gas royalties. North America natural gas
royalties averaged approximately 19% in 2006 and are anticipated to be 21% to
23% of gross revenues in 2007.
NORTH SEA
North Sea government royalties on crude oil were eliminated effective January
1, 2003. The remaining royalty is a gross overriding royalty on the Ninian
Field.
OFFSHORE WEST AFRICA
Offshore West Africa production is governed by the terms of the various
Production Sharing Contracts ("PSCs"). Under the PSCs, revenues are divided
into cost recovery revenue and profit 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. These revenues are
reported as sales revenue. Profit revenue is allocated to the joint venture
partners in accordance with their respective equity interests, after a portion
has been allocated to the Government. The Government's share of profit revenue
attributable to the Company's equity interest is allocated to royalty expense
and current income tax expense in accordance with the PSCs. The Company's
capital investments in the Espoir Field are expected to be fully recovered in
the first quarter of 2007, increasing royalty rates and current income taxes in
accordance with the PSCs. The Company's capital investments in the Baobab Field
are now not expected to be fully recovered until approximately 2012 due to the
ongoing production curtailments resulting from limitations to sand screen
effectiveness.
In connection with corporate income tax rate reductions enacted by the
Government of Cote d'Ivoire during the third quarter that were effective
January 1, 2006, royalty rates as a percentage of gross revenue increased from
approximately 3% in 2005 to approximately 4% in 2006. As a result, production
volumes net of royalties decreased approximately 2% in 2006 from 2005, in
accordance with the terms of the PSC's. Royalty rates in 2007 are anticipated
to be 13% to 15% of gross revenue due to the Company's expected full recovery
of its capital investments in the Espoir Field.
32 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
PRODUCTION EXPENSE
Three Months Ended Year Ended
-------------- ---------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- -----------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 12.13 $ 12.05 $ 10.92 $ 11.73 $ 10.49
North Sea $ 14.76 $ 20.28 $ 12.11 $ 17.57 $ 14.94
Offshore West Africa $ 10.05 $ 7.97 $ 5.62 $ 7.45 $ 6.50
Company average $ 12.32 $ 13.47 $ 10.33 $ 12.29 $ 11.17
NATURAL GAS ($/mcf) (1)
North America $ 0.84 $ 0.83 $ 0.74 $ 0.81 $ 0.71
North Sea $ 1.54 $ 1.30 $ 1.96 $ 1.40 $ 2.44
Offshore West Africa $ 2.01 $ 1.39 $ 0.80 $ 1.19 $ 1.05
Company average $ 0.86 $ 0.84 $ 0.76 $ 0.82 $ 0.73
COMPANY AVERAGE ($/boe) (1) $ 9.16 $ 10.01 $ 7.93 $ 9.14 $ 8.21
=============================================================================================================================
- ------------
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
NORTH AMERICA
North America crude oil and NGLs production expense for the year ended December
31, 2006 increased to $11.73 per bbl from $10.49 per bbl for the year ended
December 31, 2005. Crude oil and NGLs production expense for the fourth quarter
of 2006 increased to $12.13 per bbl from $10.92 per bbl for the fourth quarter
of 2005 and increased marginally from $12.05 per bbl in the prior quarter. The
increase in production expense from the comparable periods in 2005 was
primarily due to increased industry wide service costs. Production expense in
the fourth quarter of 2006 compared to the fourth quarter of 2005 and the prior
quarter also reflected increased cyclic steaming costs related to the Company's
thermal crude oil projects due to the timing of secondary steaming cycles.
North America natural gas production expense per mcf for the year and three
months ended December 31, 2006 increased over the comparable periods in 2005
due to increased cost pressures, but was comparable to the prior quarter.
On a total boe basis, North America fourth quarter production expense of $8.49
per bbl was unchanged from the prior quarter primarily due to the increased
percentage of lower cost natural gas sales volumes attributable to the ACC
acquisition, offset by the increased percentage of higher cost thermal crude
oil sales volumes. Production expense per boe in 2007 is anticipated to
continue to reflect industry wide inflationary cost pressures.
NORTH SEA
North Sea crude oil production expense varied on a per barrel basis from the
comparable periods due to planned maintenance shutdowns, varying sales volumes
on a relatively fixed cost base and the timing of liftings from various fields.
CANADIAN NATURAL RESOURCES LIMITED 33
===============================================================================
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production expense on a per barrel basis
increased from the comparable periods in 2005 and the prior quarter primarily
due to continuing operating challenges with sand and solids resulting in
decreased production volumes at Baobab, on a relatively fixed operating cost
base.
MIDSTREAM
Three Months Ended Year Ended
--------------- ----------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
($ millions) 2006 2006 2005 2006 2005
- -----------------------------------------------------------------------------------------------------------------------------
Revenue $ 18 $ 19 $ 21 $ 72 $ 77
Production expense 6 6 8 23 24
- -----------------------------------------------------------------------------------------------------------------------------
Midstream cash flow 12 13 13 49 53
Depreciation 2 2 2 8 8
- -----------------------------------------------------------------------------------------------------------------------------
Segment earnings before taxes $ 10 $ 11 $ 11 $ 41 $ 45
=============================================================================================================================
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.
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
Three Months Ended Year Ended
---------------- ----------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- -----------------------------------------------------------------------------------------------------------------------------
Expense ($ millions) $ 722 $ 587 $ 548 $ 2,383 $ 2,005
$/boe (2) $ 12.80 $ 10.89 $ 10.44 $ 11.27 $ 10.02
=============================================================================================================================
- ------------
(1) DD&A EXCLUDES DEPRECIATION ON MIDSTREAM ASSETS.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Depletion, Depreciation and Amortization ("DD&A") for the year and three months
ended December 31, 2006 increased in total and on a boe basis from the
comparable periods in 2005 and the prior quarter. The increase was primarily as
a result of increased production combined with overall increases in finding and
development costs associated with crude oil and natural gas exploration in
North America, a higher depletion base due to the ACC acquisition, and
increased estimated future costs to develop the Company's proved undeveloped
reserves.
34 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
ASSET RETIREMENT OBLIGATION ACCRETION
Three Months Ended Year Ended
-------------- ---------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- -----------------------------------------------------------------------------------------------------------------------------
Expense ($ millions) $ 18 $ 17 $ 16 $ 68 $ 69
$/boe (1) $ 0.32 $ 0.31 $ 0.30 $ 0.32 $ 0.34
=============================================================================================================================
- ------------
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Asset retirement obligation accretion expense is the increase in the carrying
amount of the asset retirement obligation due to the passage of time. Accretion
expense for the year and three months ended December 31, 2006 was consistent
with the prior periods.
ADMINISTRATION EXPENSE
Three Months Ended Year Ended
-------------- ----------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- -----------------------------------------------------------------------------------------------------------------------------
Net expense ($ millions) $ 57 $ 41 $ 36 $ 180 $ 151
$/boe (1) $ 1.01 $ 0.76 $ 0.68 $ 0.85 $ 0.75
=============================================================================================================================
- ------------
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Administration expense for the year and three months ended December 31, 2006
increased in total and on a boe basis from the comparable periods, primarily
due to increased insurance premiums, increased staffing and administrative
costs, costs associated with the integration of ACC, and overall inflationary
pressures.
STOCK-BASED COMPENSATION EXPENSE (RECOVERY)
Three Months Ended Year Ended
-------------- ---------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
($ millions) 2006 2006 2005 2006 2005
- -----------------------------------------------------------------------------------------------------------------------------
Stock option plan expense (recovery) $ 176 $ (135) $ 125 $ 139 $ 723
=============================================================================================================================
The Company's Stock Option Plan (the "Option Plan") provides current employees
(the "option holders") with the right to elect to receive common shares or a
direct cash payment in exchange for options surrendered. The design of the
Option Plan balances the need for a long-term compensation program to retain
employees with the benefits of reducing the impact of dilution on current
Shareholders and the reporting of the obligations associated with stock
options. Transparency of the cost of the Option Plan is increased 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
benefits and allows them to realize the value of their options through a
simplified administration process.
The Company recorded a $139 million ($95 million after-tax) stock-based
compensation expense for the year ended December 31, 2006 in connection with
the 8% increase in the Company's share price, and a $176 million ($120 million
after-tax) stock-based compensation expense as a result of the 22% increase in
the Company's share price in the fourth quarter of 2006 (Company's share price
as at: December 31, 2006 - C$62.15; September 30, 2006 - C$50.94; December 31,
2005 - C$57.63). As required by GAAP, the Company's outstanding stock options
are valued each reporting period based on the difference between the exercise
price of the stock options and the market price of the Company's common shares,
pursuant to a graded vesting schedule. The liability is revalued quarterly to
reflect 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. For the year ended December 31, 2006, the Company
CANADIAN NATURAL RESOURCES LIMITED 35
===============================================================================
capitalized $79 million in stock-based compensation on the Horizon Project
(December 31, 2005 - $101 million). The stock-based compensation liability
reflected the Company's potential cash liability should all the vested options
be surrendered for a cash payout at the market price on December 31, 2006. In
periods when substantial stock price changes occur, the Company is subject to
significant earnings volatility.
For the year ended December 31, 2006, the Company paid $264 million for stock
options surrendered for cash settlement (December 31, 2005 - $227 million).
INTEREST EXPENSE
Three Months Ended Year Ended
------------- --------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
($ millions) 2006 2006 2005 2006 2005
- --------------------------------------------------------------------------------------------------------------------------
Interest expense, gross $ 128 $ 81 $ 55 $ 336 $ 221
Less: capitalized interest, Horizon Project 66 56 27 196 72
- --------------------------------------------------------------------------------------------------------------------------
Interest expense, net $ 62 $ 25 $ 28 $ 140 $ 149
$/boe (1) $ 1.08 $ 0.48 $ 0.53 $ 0.66 $ 0.74
Average effective interest rate 5.6% 5.8% 5.7% 5.7% 5.6%
==========================================================================================================================
- ------------
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Gross interest expense increased from the comparable periods in 2005 and the
prior quarter primarily due to increased debt levels associated with the ACC
acquisition and the financing of Horizon Project capital expenditures. The
increase from the comparable periods in 2005 was partially offset by the impact
of the strengthening Canadian dollar, which decreased interest expense on the
Company's US dollar denominated debt securities.
36 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
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 intended for trading or speculative purposes.
Changes in fair value of derivative financial instruments formally 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 formally
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 derivative financial instruments designated
as hedging transactions at the inception of the hedging relationship, in
accordance with the Company's risk management policies. The effectiveness of
the hedging relationship is evaluated, both at inception of the hedge and on an
ongoing basis.
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. Realized gains or losses on these contracts are
included in risk management activities. Unrealized gains or losses on commodity
price contracts not formally documented as hedges are also 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 formally designated as hedges are included in interest
expense. Gains or losses on non-designated interest rate contracts are included
in risk management activities.
The Company enters into cross-currency swap agreements 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 the foreign exchange component of all cross-currency swap
contracts are included in risk management activities. Gains or losses on the
interest component of cross-currency swap contracts designated as hedges are
included in interest expense.
Gains or losses on the termination of derivative 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.
CANADIAN NATURAL RESOURCES LIMITED 37
===============================================================================
RISK MANAGEMENT
Three Months Ended Year Ended
-------------- ---------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
($ millions) 2006 2006 2005 2006 2005
- --------------------------------------------------------------------------------------------------------------------------
REALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments $ 223 $ 419 $ 235 $ 1,395 $ 753
Natural gas financial instruments (97) (15) 242 (70) 283
Interest rate swaps -- -- (1) -- (9)
- --------------------------------------------------------------------------------------------------------------------------
$ 126 $ 404 $ 476 $ 1,325 $ 1,027
- --------------------------------------------------------------------------------------------------------------------------
UNREALIZED (GAIN) LOSS
Crude oil and NGLs financial instruments $ (239) $ (601) $ (514) $ (736) $ 847
Natural gas financial instruments 8 (152) (307) (260) 77
Interest rate and cross-currency swaps (10) (1) (4) (17) 1
- --------------------------------------------------------------------------------------------------------------------------
$ (241) $ (754) $ (825) $ (1,013) $ 925
- --------------------------------------------------------------------------------------------------------------------------
TOTAL $ (115) $ (350) $ (349) $ 312 $ 1,952
==========================================================================================================================
The net realized losses (gains) from crude oil and NGLs and natural gas
financial instruments decreased (increased) the Company's average realized
prices as follows:
Three Months Ended Year Ended
-------------- ---------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
2006 2006 2005 2006 2005
- --------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)(1) $ 7.09 $ 13.15 $ 7.67 $ 11.57 $ 6.68
Natural gas ($/mcf)(1) $ (0.65) $ (0.11) $ 1.85 $ (0.13) $ 0.54
==========================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
As effective as commodity hedges are against reference commodity prices, a
substantial portion of the derivative financial 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, the unrealized risk management asset reflected,
at December 31, 2006, the implied price differentials for the non-designated
hedges for future years. 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, 2006. Due to changes in the crude oil and natural gas forward
pricing, and the reversal of prior year unrealized losses, the Company recorded
a net unrealized gain of $1,013 million ($674 million after-tax) on its risk
management activities for the year ended December 31, 2006 (December 31, 2005 -
unrealized loss of $925 million, $607 million after-tax), including an
unrealized gain of $241 million ($166 million after-tax) for the three months
ended December 31, 2006 (December 31, 2005 - unrealized gain of $825 million,
$583 million after-tax; September 30, 2006 - unrealized gain of $754 million,
$496 million after-tax).
In addition to the net risk management asset recognized on the balance sheet at
December 31, 2006, the net unrecognized asset related to the estimated fair
values of derivative financial instruments designated as hedges was $222
million (December 31, 2005 - net unrecognized liability of $990 million).
Details related to outstanding derivative financial instruments at December 31,
2006 are disclosed in note 10 to the Company's unaudited interim consolidated
financial statements.
38 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
Effective January 1, 2007, the Company will adopt new accounting standards
relating to the accounting for and disclosure of financial instruments. In
2007, the Company will record all of its derivative financial instruments on
the balance sheet at fair value, including those designated as hedges.
Designated hedges are currently not recognized on the balance sheet but are
disclosed in the notes to the consolidated financial statements.
FOREIGN EXCHANGE
Three Months Ended Year Ended
----------- --------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
($ millions) 2006 2006 2005 2006 2005
- ---------------------------------------------------------------------------------------------------------------------
Realized foreign exchange (gain) loss $ (20) $ 1 $ (16) $ (12) $ (29)
Unrealized foreign exchange loss (gain) 171 11 5 134 (103)
- ---------------------------------------------------------------------------------------------------------------------
$ 151 $ 12 $ (11) $ 122 $ (132)
=====================================================================================================================
The Company's operating results are affected by fluctuations in the exchange
rates between the Canadian dollar, US dollar, and UK pound sterling. A majority
of the Company's revenue is based on reference to US dollar benchmark prices.
An increase in the value of the Canadian dollar in relation to the US dollar
results in decreased revenue from the sale of the Company's production.
Conversely a decrease in the value of the Canadian dollar in relation to the US
dollar will result in increased revenue from the sale of the Company's
production. Production expenses are subject to fluctuations due to changes in
the exchange rate of the UK pound sterling to the US dollar on 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.
The realized foreign exchange gain for the year and three months ended December
31, 2006 was primarily the result of foreign exchange rate fluctuations on
working capital items denominated in US dollars or UK pounds sterling. The
unrealized foreign exchange loss for the year and three months ended December
31, 2006 was primarily related to the fourth quarter weakening of the Canadian
dollar in relation to the US dollar with respect to the US dollar debt, and
working capital in North America denominated in US dollars, as well as the
re-measurement of North Sea future income tax liabilities denominated in UK
pounds sterling. The Canadian dollar ended the fourth quarter at US$0.8581
compared to US$0.8577 at December 31, 2005 (September 30, 2006 - US$0.8966).
In order to mitigate a portion of the volatility associated with fluctuations
in exchange rates, the Company has designated certain US dollar denominated
debt as a hedge against its net investment in US dollar based self-sustaining
foreign operations. Accordingly, translation gains and losses on this US dollar
denominated debt are included in the foreign currency translation adjustment in
Shareholders' Equity in the consolidated balance sheets.
CANADIAN NATURAL RESOURCES LIMITED 39
===============================================================================
TAXES
Three Months Ended Year Ended
------------- -------------------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
($ millions, except income tax rates) 2006 2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------------
TAXES OTHER THAN INCOME TAX
Current $ 44 $ 81 $ 50 $ 219 $ 203
Deferred (3) (4) 1 37 (9)
- -------------------------------------------------------------------------------------------------------------------------
$ 41 $ 77 $ 51 $ 256 $ 194
- -------------------------------------------------------------------------------------------------------------------------
CURRENT INCOME TAX
North America $ 51 $ 52 $ 8 $ 143 $ 99
North Sea 30 -- 31 30 155
Offshore West Africa 14 6 19 49 32
- -------------------------------------------------------------------------------------------------------------------------
$ 95 $ 58 $ 58 $ 222 $ 286
- -------------------------------------------------------------------------------------------------------------------------
FUTURE INCOME TAX EXPENSE $ 135 $ 473 $ 514 $ 652 $ 353
- -------------------------------------------------------------------------------------------------------------------------
EFFECTIVE INCOME TAX RATE 42.3% 32.2%(3) 34.1% 25.7%(1)(2)(3) 37.8%
=========================================================================================================================
- ------------
(1) INCLUDES THE EFFECT OF A CHARGE OF $110 MILLION RELATED TO THE INCREASED
SUPPLEMENTARY CHARGE ON OIL AND GAS PROFITS IN THE UK NORTH SEA,
SUBSTANTIVELY ENACTED IN THE FIRST QUARTER OF 2006.
(2) INCLUDES THE EFFECT OF A RECOVERY OF $438 MILLION DUE TO CANADIAN FEDERAL,
ALBERTA AND SASKATCHEWAN CORPORATE INCOME TAX RATE REDUCTIONS ENACTED
DURING THE SECOND QUARTER OF 2006.
(3) INCLUDES THE EFFECT OF A RECOVERY OF $67 MILLION DUE TO COTE D'IVOIRE
CORPORATE INCOME TAX RATE REDUCTIONS ENACTED DURING THE THIRD QUARTER OF
2006.
Taxes other than income tax includes current and deferred petroleum revenue tax
("PRT") and Canadian provincial capital taxes. PRT is charged on certain fields
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 primarily generated through partnerships, with the related income
taxes payable in a future period. North America current income taxes have been
provided on the basis of the corporate structure and available income tax
deductions and will vary depending upon the nature and amount of capital
expenditures incurred in Canada in any particular year.
Income tax rate changes during 2006 resulted in a reduction of future income
tax liabilities of approximately $438 million in North America, an increase of
future income tax liabilities of approximately $110 million in the UK North Sea
and a reduction of future income tax liabilities of approximately $67 million
in Cote d'Ivoire.
40 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CAPITAL EXPENDITURES (1)
Three Months Ended Year Ended
--------- --------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
($ millions) 2006 2006 2005 2006 2005
- ------------------------------------------------------------------------------------------------------------------------------
EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT
Net property acquisitions (dispositions) $ 4,720 $ (6) $ 19 $ 4,733 $ (320)
Land acquisition and retention 28 29 97 210 254
Seismic evaluations 17 26 40 130 132
Well drilling, completion and equipping 462 524 629 2,340 2,000
Pipeline and production facilities 311 270 314 1,314 1,295
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL NET RESERVE REPLACEMENT EXPENDITURES 5,538 843 1,099 8,727 3,361
- ------------------------------------------------------------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs (2) 745 727 469 2,768 1,249
Phases 2 and 3 costs 54 18 -- 79 --
Capitalized interest, stock-based compensation
and other (2) 134 39 88 338 250
- ------------------------------------------------------------------------------------------------------------------------------
Total Horizon Project 933 784 557 3,185 1,499
- ------------------------------------------------------------------------------------------------------------------------------
Midstream 1 2 1 12 4
Abandonments (3) 19 24 16 75 46
Head office 6 8 6 26 22
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES $ 6,497 $ 1,661 $ 1,679 $12,025 $ 4,932
- ------------------------------------------------------------------------------------------------------------------------------
BY SEGMENT
North America $ 5,296 $ 667 $ 862 $ 7,936 $ 2,530
North Sea 211 148 118 646 387
Offshore West Africa 30 27 119 134 439
Other 1 1 -- 11 5
Horizon Project 933 784 557 3,185 1,499
Midstream 1 2 1 12 4
Abandonments (3) 19 24 16 75 46
Head office 6 8 6 26 22
- ------------------------------------------------------------------------------------------------------------------------------
Total $ 6,497 $ 1,661 $ 1,679 $12,025 $ 4,932
==============================================================================================================================
- ------------
(1) CAPITAL EXPENDITURES DO NOT INCLUDE NON-CASH PROPERTY, PLANT AND EQUIPMENT
ADDITIONS OR DISPOSALS.
(2) CERTAIN PRIOR PERIOD AMOUNTS HAVE BEEN RECLASSIFIED WITH RESPECT TO
STOCK-BASED COMPENSATION COSTS.
(3) ABANDONMENTS REPRESENT EXPENDITURES TO SETTLE ASSET RETIREMENT OBLIGATIONS
AND HAVE BEEN REFLECTED AS CAPITAL EXPENDITURES IN THIS TABLE.
CANADIAN NATURAL RESOURCES LIMITED 41
===============================================================================
The Company's strategy is focused on building a diversified asset base that is
balanced among various products. In order to facilitate efficient operations,
the Company concentrates its activities in core regions where it can dominate
the land base and infrastructure. The Company focuses on maintaining its land
inventories to enable the continuous exploitation of play types and geological
trends, greatly reducing overall exploration risk. By dominating
infrastructure, the Company is able to maximize utilization of its production
facilities, thereby increasing control over production costs.
Net capital expenditures for the year ended December 31, 2006 were $12,025
million compared to $4,932 million in the year ended December 31, 2005. The
increase primarily related to the $4,641 million(1) acquisition of ACC
(including working capital and other adjustments) and the continued progress on
the Company's larger, future growth projects, most notably the Horizon Project.
Excluding ACC and the Horizon Project, net capital expenditures were $4,199
million in 2006 compared to $3,433 in 2005, reflecting the impact of $320
million in net property dispositions in 2005 and industry-wide inflationary
pressures. In the year ended December 31, 2006, the Company drilled a total of
1,738 net wells consisting of 641 natural gas wells, 603 crude oil wells, 375
stratigraphic test and service wells, and 119 wells that were dry. The 375
stratigraphic test and service wells include 163 stratigraphic test wells
related to the Horizon Project. This compared to 1,882 net wells drilled in the
year ended December 31, 2005. The Company achieved an overall success rate of
91% for the year ended December 31, 2006, excluding the stratigraphic test and
service wells (December 31, 2005 - 93%).
Excluding ACC acquisition expenditures of $4,641 million(1), net capital
expenditures in the fourth quarter of 2006 were $1,856 million compared to
$1,679 million in the comparable period in 2005 and $1,661 million in the prior
quarter. In the fourth quarter of 2006, the Company drilled a total of 331 net
wells consisting of 60 natural gas wells, 177 crude oil wells, 66 stratigraphic
test and service wells and 28 wells that were dry. The Company achieved an
overall success rate of 89% for the fourth quarter of 2006, excluding
stratigraphic test and service wells.
(1) THE PRELIMINARY ALLOCATION OF THE ACC PURCHASE PRICE TO ASSETS ACQUIRED
AND LIABILITIES ASSUMED BASED ON THEIR FAIR VALUES WAS AS FOLLOWS:
SUMMARY OF PURCHASE PRICE ALLOCATION:
- -------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT $ 6,249
LESS - FUTURE INCOME TAXES (1,438)
- ASSET RETIREMENT COSTS (56)
- -------------------------------------------------------------------------------
CONSIDERATION FOR CRUDE OIL AND NATURAL GAS PROPERTIES $ 4,755
NON-CASH WORKING CAPITAL DEFICIT ASSUMED AND OTHER (105)
LONG-TERM DEBT ASSUMED (9)
- -------------------------------------------------------------------------------
NET PURCHASE PRICE - CASH CONSIDERATION $ 4,641
===============================================================================
NORTH AMERICA
North America, including the Horizon Project and the ACC acquisition, accounted
for approximately 94% of the total capital expenditures for the year ended
December 31, 2006 compared to approximately 83% for the year ended December 31,
2005.
During 2006, the Company targeted 732 net natural gas wells, including 181
wells in Northeast British Columbia, 262 wells in the Northern Plains region,
177 wells in Northwest Alberta, and 112 wells in the Southern Plains region.
The Company also targeted 619 net crude oil wells during the year. The majority
of these wells were concentrated in the Company's crude oil Northern Plains
region where 292 heavy crude oil wells, 144 Pelican Lake crude oil wells, and 8
light crude oil wells were drilled. Another 114 wells targeting light crude oil
were drilled outside the Northern Plains as well as 61 thermal crude oil wells
in the Company's In-Situ Oil Sands area. In the fourth quarter of 2006, the
Company drilled 74 net wells targeting natural gas and 188 net wells targeting
crude oil.
Due to significant changes in relative commodity prices between crude oil and
natural gas, the Company has taken the opportunity to access its large crude
oil drilling inventory to maximize value in both the short and long term. To
optimize netbacks in the short term, the Company will continue to focus on
drilling crude oil wells in 2007 and, accordingly, will reduce natural gas
drilling activity to manage overall capital spending. Deferred natural gas
wells will be retained in the Company's prospect inventory, and will be drilled
42 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
as natural gas commodity prices improve. Drilling on ACC acquired lands will be
optimized as part of the overall capital program.
As part of the development of the Company's In-Situ Oil Sands Assets, the
Company is continuing to develop its Primrose thermal projects. At the end of
2006, the Company had drilled 186 stratigraphic test wells and observation
wells and 61 thermal oil wells. With first steaming for the Primrose North
expansion commencing in November 2005, overall Primrose thermal production in
2006 increased to approximately 64,000 bbl/d from 53,000 bbl/d in 2005. Initial
steaming of the projects was completed in the fourth quarter of 2006.
In November of 2005, the Company announced a phased expansion of its In-Situ
Oil Sands Assets. The next phase of this development is the Primrose East
Expansion, a new facility located 15 kilometers from the existing Primrose
South steam plant and 25 kilometers from the Wolf Lake central processing
facility. This phase of the expansion is anticipated to add an additional
40,000 bbl/d and received Board of Director's sanction in 2006. Detailed
engineering and procurement is currently underway. The Company anticipates
receiving regulatory approval for Primrose East in the first half of 2007, with
drilling and construction planned to begin in the third quarter of 2007, and
production expected to commence in 2009.
The next phase of the Company's In-Situ Oil Sands Assets expansion is the Kirby
project located 120 km north of the existing Primrose facilities. The Kirby
project is anticipated to add an additional 30,000 bbl/d of production growth.
The Company is targeting to file its formal regulatory application documents
for this project in the latter half of 2007. First steaming is anticipated to
begin in 2011.
Development of new acreage and secondary recovery conversion projects at
Pelican Lake continued as expected through 2006. Drilling consisted of 144
horizontal wells, with plans to drill 132 additional horizontal wells in 2007.
The response from the polymer flood pilot continues to be positive. Based on
the results of the pilot, the Company commenced the installation of 12
additional polymer skids in 2006 as part of the commercial polymer flood
project. Pelican Lake production averaged approximately 30,000 bbl/d in 2006.
Originally announced in the fall of 2005, the Scoping Study for the Canadian
Natural Upgrader continued during Q4/06 and into early 2007. The terms of
reference for this study involved the evaluation of product alternatives,
location, technology, gasification and integration with existing assets using
the same disciplined approach utilized in the Horizon Project. The next steps
in this process would include a Design Basis Memorandum ("DBM") and Engineering
Design Specification ("EDS") which would be required to be completed prior to
construction and sanctioning of the project by the Board of Directors.
Based upon the results of the Scoping Study, which identified growing concerns
relating to increased environmental costs for upgraders located in Canada,
inflationary capital cost pressures and narrowing heavy oil differentials in
North America, the Company has, at this point in time, deferred the DBM and EDS
pending clarification on the cost of future environmental legislation and a
more stable cost environment.
In the first quarter of 2007, the Company's overall drilling activity in North
America is expected to be comprised of 241 natural gas wells and 199 crude oil
wells excluding stratigraphic and service wells.
HORIZON PROJECT
The Horizon Project continued on schedule and on budget with construction 57%
complete at year-end. The project status as at December 31, 2006 was as
follows:
o Detailed engineering was 94% complete;
o Over $5.1 billion in purchase orders and contracts have been awarded to
date;
o Several key mechanical contracts were awarded;
o Set 333 piperack modules;
o Mine overburden removal was approximately 35% complete; and
o Site preparation and underground infrastructure was completed.
CANADIAN NATURAL RESOURCES LIMITED 43
===============================================================================
Major activities for the first quarter of 2007 will include:
o Preparation of the high pressure natural gas piping for commissioning;
o Completion of the erection of the cooling tower; and
o Completion of the installation of the last 35kV substation.
The Company does not anticipate a material change from the budgeted $6.8
billion Phase 1 construction cost. First production of light, sweet Synthetic
Crude Oil from Phase 1 construction is targeted to commence in the third
quarter of 2008.
NORTH SEA
In the fourth quarter, the Company continued with its planned program of infill
drilling, recompletions, workovers and waterflood optimizations. During the
quarter, 2.5 net wells were drilled, with an additional 2 net wells drilling at
quarter end.
The development of the Lyell Field progressed during the fourth quarter with
the completion of construction, installation and tie-in of subsea
infrastructure. Tranche 1 of the Lyell Field development comprises the drilling
of 4 net wells and the workover of 2 existing wells. Production from the Lyell
Field is expected to be at full capacity by the third quarter of 2007.
During the fourth quarter, construction of the Columba E Raw Water Injection
project continued. The project consists of 2 injection wells.
OFFSHORE WEST AFRICA
During the fourth quarter of 2006, 1.8 net wells were drilled with 1 net well
drilling at the end of the quarter.
First crude oil from West Espoir commenced from 2 wells brought on-line during
the third quarter. In the fourth quarter 1 production well and 2 water
injectors were added. The West Espoir area development drilling will continue
until 2008 with producers and injectors being brought on-line as they are
completed.
The Company purchased a 90% interest in the Olowi PSC offshore Gabon in October
2005, received Government approval of its development plan for this acquisition
during the first quarter of 2006 and received Board sanction for development in
November 2006. Development plans include a floating production, storage and
offtake vessel ("FPSO"), handling production from 4 shallow-water producing
platforms. During the fourth quarter of 2006 the Company signed a lease
agreement for a FPSO with a primary term of ten years, commencing 2008.
44 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
LIQUIDITY AND CAPITAL RESOURCES
----------
DEC 31 Sep 30 Dec 31
($ millions, except ratios) 2006 2006 2005
- ------------------------------------------------------------------------------------------------------
Working capital deficit (1) $ 832 $ 1,032 $ 1,774
Long-term debt $ 11,043 $ 5,500 $ 3,321
Shareholders' equity
Share capital $ 2,562 $ 2,536 $ 2,442
Retained earnings 8,141 7,869 5,804
Foreign currency translation adjustment (13) (12) (9)
- ------------------------------------------------------------------------------------------------------
Total $ 10,690 $ 10,393 $ 8,237
Debt to book capitalization (2) 50.8% 34.6% 28.7%
Debt to market capitalization 24.8% 16.7% 9.7%
After tax return on average common
shareholders' equity (3) 26.9% 38.2% 14.3%
After tax return on average capital
employed (4) 17.2% 26.0% 10.4%
======================================================================================================
(1) CALCULATED AS CURRENT ASSETS LESS CURRENT LIABILITIES.
(2) CALCULATED AS CURRENT AND LONG-TERM DEBT; DIVIDED BY THE BOOK VALUE OF
COMMON SHAREHOLDERS' EQUITY PLUS CURRENT AND LONG-TERM DEBT.
(3) CALCULATED AS NET EARNINGS FOR THE TWELVE MONTH TRAILING PERIOD AS A
PERCENTAGE OF AVERAGE COMMON SHAREHOLDERS' EQUITY FOR THE PERIOD.
(4) CALCULATED AS NET EARNINGS PLUS AFTER-TAX INTEREST EXPENSE FOR THE TWELVE
MONTH TRAILING PERIOD; AS A PERCENTAGE OF AVERAGE CAPITAL EMPLOYED FOR THE
PERIOD. AVERAGE CAPITAL EMPLOYED IS THE AVERAGE SHAREHOLDERS' EQUITY AND
CURRENT AND LONG-TERM DEBT FOR THE PERIOD.
The Company's capital resources at December 31, 2006 consisted primarily of
cash flow from operations, available credit facilities and access to debt
capital markets. Cash flow from operations is dependent on factors discussed in
the Risks and Uncertainties section of the Company's December 31, 2005 annual
MD&A. The Company's ability to renew existing credit facilities and raise new
debt is also dependent upon these factors, as well as maintaining an investment
grade debt rating and the condition of capital and credit markets. Management
believes internally generated cash flows supported by the implementation of the
Company's hedge policy, the flexibility of its capital expenditure programs
supported by its five- and ten-year financial plans, the Company's existing
credit facilities and the Company's ability to raise new debt on commercially
acceptable terms, will be sufficient to sustain its operations and support its
growth strategy. The Company's current debt ratings are BBB (high) with a
negative trend by DBRS, Baa2 with a stable outlook by Moody's Investor
Services, Inc. and BBB with a stable outlook by Standard and Poors Corporation.
At December 31, 2006, the Company had undrawn bank lines of credit of $1,115
million. Details related to the Company's credit facilities outstanding at
December 31, 2006 are disclosed in note 4 to the Company's unaudited interim
consolidated financial statements.
At December 31, 2006, the Company's working capital deficit was $832 million
and included the current portion of the stock-based compensation liability of
$611 million and the current portion of the net mark-to-market asset for
non-designated risk management financial derivative instruments of $88 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 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, 2006.
CANADIAN NATURAL RESOURCES LIMITED 45
===============================================================================
The Company believes it has the necessary financial capacity to complete the
Horizon Project, while at the same time not compromising 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, 2006, such as Baobab, Primrose and West Espoir, and the
acquisition of ACC, are anticipated to provide identified growth in production
volumes in 2007 through 2009, and generate incremental free cash flows during
this period.
Primarily due to the additional debt issued to complete the ACC acquisition,
long-term debt increased to $11,043 million at December 31, 2006, resulting in
a debt to book capitalization level of 50.8% as at December 31, 2006,
(September 30, 2006 - 34.6%; December 31, 2005 - 28.7%). While this ratio is
above the 35% to 45% range targeted by management, the Company remains
committed to maintaining a strong balance sheet and flexible capital structure,
and expects its debt to book capitalization ratio to be near the midpoint of
the range in 2008. While the Company believes that its balance sheet has the
strength and flexibility to accommodate the ACC acquisition, to ensure balance
sheet strength going forward, the Company has hedged a significant portion of
its natural gas and crude oil production for 2007 and 2008 at prices that
protect investment returns. In the future, the Company may also consider the
divestiture of non-strategic and non-core properties to gain additional balance
sheet flexibility.
The Company's commodity hedging program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its capital
expenditure program throughout the Horizon Project construction period. This
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. For the purpose of this
program, the purchase of crude oil put options is in addition to the above
parameters. In accordance with the policy, approximately 65% of expected crude
oil volumes and approximately 75% of expected natural gas volumes have been
hedged for 2007. In addition, 77,000 bbl/d of crude oil volumes are protected
by put options for 2007 at a strike price of US$60.00 per barrel. The Company
is extending its hedge program into 2008 whereby 150,000 bbl/d of crude oil
volumes have been hedged (100,000 bbl/d of price collars with a US$60.00 floor
and 50,000 bbl/d of put options with a US$55.00 strike price). In addition,
900,000 GJ/d of natural gas volumes have been hedged through the use of price
collars for the first quarter of 2008 (400,000 GJ/d with a floor of $7.00 and
500,000 GJ/d with a floor of $7.50).
In addition to the strategic location of the assets that ACC brings to the
Company, this acquisition allows the Company to further high grade its project
inventory and focus capital expenditures in the current highly inflationary
service market. As a result of the acquisition, the Company has reduced its
2007 conventional crude oil and natural gas capital budget by $900 million
compared to 2006 capital spending, while maintaining the capital expenditures
to complete Phase 1 of the Horizon Project.
LONG-TERM DEBT
The Company's long-term debt of $11,043 million at December 31, 2006 was
comprised of drawings under its bank credit facilities and debt issuances under
medium and long-term unsecured notes.
BANK CREDIT FACILITIES
As at December 31, 2006 the Company had in place unsecured bank credit
facilities of $7,809 million, comprised of:
o a $100 million demand credit facility;
o a $500 million demand credit facility;
o a 3-year non-revolving syndicated credit facility of $3,850 million;
o a 5-year revolving syndicated credit facility of $1,825 million;
o a 5-year revolving syndicated credit facility of $1,500 million; and
o a (pound)15 million demand credit facility related to the Company's North
Sea operations.
46 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
During the second quarter, the revolving syndicated credit facilities were
renegotiated and are fully revolving for a period of five years maturing June
2011. Both facilities are extendible annually for one year periods at the
mutual agreement of the Company and the lenders. If the facilities are not
extended, the full amount of the outstanding principal would be repayable on
the maturity date.
In conjunction with the closing of the acquisition of ACC, the Company executed
a $3,850 million, three-year non-revolving syndicated credit facility maturing
in October 2009. This facility is subject to certain prepayment requirements up
to a maximum of $1,500 million.
During the fourth quarter, the Company obtained a $500 million credit facility
repayable on demand.
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $338 million, including $300 million related to the Horizon
Project, were outstanding at December 31, 2006.
MEDIUM-TERM NOTES
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.
Subsequent to December 31, 2006, the 7.40% unsecured debentures due March 1,
2007 were repaid.
US DOLLAR DEBT SECURITIES
In August 2006, the Company issued US$250 million of unsecured notes maturing
August 2016 and US$450 million of unsecured notes maturing February 2037,
bearing interest at 6.00% and 6.50%, respectively. Concurrently, the Company
entered into cross-currency interest-rate swaps to fix the Canadian dollar
interest and principal repayment amounts on the US$250 million notes at 5.40%
and C$279 million, respectively. Proceeds from the securities issued were used
to repay bankers' acceptances under the Company's bank credit facilities.
In November 2006, the shelf prospectus, filed in June 2005, was increased from
US$2 billion to US$3 billion, leaving US$2.3 billion available for issue in the
United States until July 2007. If issued, these securities will bear interest
as determined at the date of issuance.
SHARE CAPITAL
As at December 31, 2006, there were 537,903,000 common shares outstanding and
34,425,000 stock options outstanding. As at March 3, 2007, the Company had
538,913,000 common shares outstanding and 31,565,000 stock options outstanding.
During 2006, the Company purchased 485,000 common shares for cancellation (2005
- - 850,000 common shares) at an average price of $57.33 per common share (2005 -
$53.29 per common share), for a total cost of $28 million (2005 - $45 million)
pursuant to the Normal Course Issuer Bids previously filed.
In January 2007, the Company renewed its Normal Course Issuer Bid to purchase,
through the facilities of the Toronto Stock Exchange and the New York Stock
Exchange, during the 12-month period beginning January 24, 2007 and ending
January 23, 2008, up to 26,941,730 common shares or 5% of the outstanding
common shares of the Company then outstanding on the date of the announcement.
As at March 3, 2007, the Company had not purchased any additional shares under
the Normal Course Issuer Bid.
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.
In March 2007, the Company's Board of Directors approved an increase in the
annual dividend paid by the Company to $0.34 per common share for 2007. The
increase represents a 13% increase from the prior year, recognizes the
stability of the Company's cash flow, and provides a return to Shareholders.
This is the seventh consecutive year in which the Company has paid dividends
and the sixth consecutive year of an increase in the distribution paid to its
Shareholders. The dividend policy undergoes a periodic review by the Board of
Directors and is subject to change.
CANADIAN NATURAL RESOURCES LIMITED 47
===============================================================================
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations. These
commitments primarily relate to debt repayments, operating leases relating to
office space and offshore FPSOs and drilling rigs, and firm commitments for
gathering, processing and transmission services, as well as expenditures
relating to asset retirement obligations. As at December 31, 2006, no entities
were consolidated under the Canadian Institute of Chartered Accountants
Handbook Accounting Guideline 15, "Consolidation of Variable Interest
Entities". The following table summarizes the Company's commitments as at
December 31, 2006:
($ millions) 2007 2008 2009 2010 2011 Thereafter
- --------------------------------------------------------------------------------------------------------------------------------
Product transportation and pipeline (1) $ 213 $ 193 $ 134 $ 123 $ 99 $ 1,042
Offshore equipment operating lease (2) $ 77 $ 52 $ 52 $ 52 $ 50 $ 131
Offshore drilling $ 73 $ 83 $ 12 $ 12 $ 4 $ 4
Asset retirement obligations (3) $ 3 $ 3 $ 3 $ 4 $ 4 $ 4,480
Long-term debt (4) $ 161 $ 45 $ 3,876 $ - $ 466 $ 3,713
Office lease $ 26 $ 32 $ 33 $ 34 $ 22 $ --
Electricity and other $ 51 $ 10 $ 17 $ 18 $ 1 $ --
================================================================================================================================
- ------------
(1) 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) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF OBLIGATIONS
RELATED TO FPSOS. DURING 2006, THE COMPANY ENTERED INTO AN AGREEMENT TO
LEASE AN ADDITIONAL FPSO COMMENCING IN 2008, IN CONNECTION WITH THE
PLANNED OFFSHORE DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. THE NEW FPSO
LEASE AGREEMENT CONTAINS CANCELLATION PROVISIONS AT THE OPTION OF THE
COMPANY, SUBJECT TO ESCALATING TERMINATION PAYMENTS THROUGHOUT 2007 TO A
MAXIMUM OF US$395 MILLION.
(3) AMOUNTS REPRESENT MANAGEMENT'S ESTIMATE OF THE FUTURE UNDISCOUNTED
PAYMENTS TO SETTLE ASSET RETIREMENT OBLIGATIONS RELATED TO RESOURCE
PROPERTIES, FACILITIES, AND PRODUCTION PLATFORMS, BASED ON CURRENT
LEGISLATION AND INDUSTRY OPERATING PRACTICES. AMOUNTS DISCLOSED FOR THE
PERIOD 2007 - 2011 REPRESENT THE MINIMUM REQUIRED EXPENDITURES TO MEET
THESE OBLIGATIONS. ACTUAL EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED
THESE MINIMUM AMOUNTS.
(4) THE LONG-TERM DEBT REPRESENTS PRINCIPAL REPAYMENTS ONLY. NO DEBT
REPAYMENTS ARE REFLECTED FOR $2,782 MILLION OF REVOLVING BANK CREDIT
FACILITIES DUE TO THE EXTENDABLE NATURE OF THE FACILITIES.
In 2005, the Board of Directors of the Company approved the construction costs
for Phase 1 of the Horizon Project, with an approved budget of $6.8 billion.
Cumulative construction spending to December 31, 2006 was approximately $4.0
billion. Final construction costs for Phase 1 may differ from the approved
budget due to changes in the final scope and timing of completion of the
project, and/or inflationary cost pressures.
LEGAL PROCEEDINGS
The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business. The Company believes that any liabilities
that might arise pertaining to such matters would not have a material effect on
its consolidated financial position.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements requires the Company to make
judgements, assumptions and estimates in the application of generally accepted
accounting principles that have a significant impact on the financial results
of the Company. Actual results could differ from those estimates. A
comprehensive discussion of the Company's significant accounting policies is
contained in the MD&A and the audited consolidated financial statements for the
year ended December 31, 2005.
48 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
SENSITIVITY ANALYSIS (1)
The following table is indicative of the annualized sensitivities of cash flow
from operations and net earnings from changes in certain key variables. The
analysis is based on business conditions and sales volumes during the fourth
quarter of 2006, and is not necessarily indicative of future results. Each
separate line item in the sensitivity analysis shows the effect of a change in
that variable only; all other variables are held constant.
CASH FLOW
CASH FLOW FROM NET
FROM OPERATIONS NET EARNINGS
OPERATIONS (PER COMMON EARNINGS (PER COMMON
($ MILLIONS) SHARE, BASIC) ($ MILLIONS) SHARE, BASIC)
- ----------------------------------------------------------------------------------------------------------------------------------
PRICE CHANGES
Crude oil - WTI US$1.00/bbl (2)
Excluding financial derivatives $ 116 $ 0.22 $ 81 $ 0.15
Including financial derivatives $ 26-110 $ 0.05-0.21 $ 20-77 $ 0.04-0.14
Natural gas - AECO C$0.10/mcf (2)
Excluding financial derivatives $ 26 $ 0.05 $ 14 $ 0.03
Including financial derivatives $ 1-8 $ 0.00-0.02 $ 2-4 $ 0.00-0.01
VOLUME CHANGES
Crude oil - 10,000 bbl/d $ 98 $ 0.18 $ 44 $ 0.08
Natural gas - 10 mmcf/d $ 17 $ 0.03 $ 6 $ 0.01
FOREIGN CURRENCY RATE CHANGE
$0.01 change in C$ in relation to US$ (2)
Excluding financial derivatives $ 80-82 $ 0.15 $ 23-24 $ 0.04
INTEREST RATE CHANGE - 1% $ 48 $ 0.09 $ 48 $ 0.09
===================================================================================================================================
- ------------
(1) THE SENSITIVITIES ARE CALCULATED BASED ON 2006 FOURTH QUARTER RESULTS AND
EXCLUDE MARK-TO-MARKET GAINS (LOSSES) ON RISK MANAGEMENT ACTIVITIES.
(2) FOR DETAILS OF OUTSTANDING FINANCIAL INSTRUMENTS IN PLACE, REFER TO NOTE
10 OF THE COMPANY'S UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS.
CANADIAN NATURAL RESOURCES LIMITED 49
===============================================================================
OTHER OPERATING HIGHLIGHTS
NETBACK ANALYSIS
Three Months Ended Year Ended
--------- ---------
DEC 31 Sep 30 Dec 31 DEC 31 Dec 31
($/boe) (1) 2006 2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------------------
Sales price (2) $ 43.91 $ 51.21 $ 56.08 $ 47.92 $ 48.77
Royalties 5.62 5.75 8.01 5.89 6.82
Production expense (3) 9.16 10.01 7.93 9.14 8.21
- -------------------------------------------------------------------------------------------------------------------------------
NETBACK 29.13 35.45 40.14 32.89 33.74
Midstream contribution (3) (0.22) (0.23) (0.25) (0.23) (0.26)
Administration 1.01 0.76 0.68 0.85 0.75
Interest, net 1.08 0.48 0.53 0.66 0.74
Realized risk management loss 2.25 7.51 9.07 6.27 5.13
Realized foreign exchange (gain) loss (0.34) 0.01 (0.29) (0.06) (0.15)
Taxes other than income tax - current 0.78 1.50 0.93 1.04 1.01
Current income tax - North America 0.91 0.97 0.17 0.68 0.50
Current income tax - North Sea 0.54 -- 0.59 0.14 0.77
Current income tax - Offshore West Africa 0.24 0.11 0.35 0.23 0.17
- -------------------------------------------------------------------------------------------------------------------------------
CASH FLOW $ 22.88 $ 24.34 $ 28.36 $ 23.31 $ 25.08
===============================================================================================================================
- ------------
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
(3) EXCLUDING INTERSEGMENT ELIMINATION.
50 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
FINANCIAL STATEMENTS
CONSOLIDATED BALANCE SHEETS
----------
DEC 31 Dec 31
(millions of Canadian dollars, unaudited) 2006 2005
- -------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 23 $ 18
Accounts receivable and other 1,947 1,546
Future income tax 163 487
Current portion of other long-term assets (note 3) 106 -
- -----------------------------------------------------------------------------------------
2,239 2,051
PROPERTY, PLANT AND EQUIPMENT (note 12) 30,767 19,694
OTHER LONG-TERM ASSETS (note 3) 154 107
- -----------------------------------------------------------------------------------------
$ 33,160 $ 21,852
=========================================================================================
LIABILITIES
CURRENT LIABILITIES
Accounts payable $ 842 $ 573
Accrued liabilities 1,618 1,781
Current portion of other long-term liabilities (note 5) 611 1,471
- -----------------------------------------------------------------------------------------
3,071 3,825
LONG-TERM DEBT (note 4) 11,043 3,321
OTHER LONG-TERM LIABILITIES (note 5) 1,393 1,434
FUTURE INCOME TAX 6,963 5,035
- -----------------------------------------------------------------------------------------
$ 22,470 $ 13,615
- -----------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
SHARE CAPITAL (note 8) 2,562 2,442
RETAINED EARNINGS 8,141 5,804
FOREIGN CURRENCY TRANSLATION ADJUSTMENT (13) (9)
- -----------------------------------------------------------------------------------------
10,690 8,237
- -----------------------------------------------------------------------------------------
$ 33,160 $ 21,852
=========================================================================================
COMMITMENTS (NOTE 11)
CANADIAN NATURAL RESOURCES LIMITED 51
===============================================================================
CONSOLIDATED STATEMENTS OF EARNINGS
Three Months Ended Year Ended
---------- ----------
(millions of Canadian dollars, except per DEC 31 Dec 31 DEC 31 Dec 31
common share amounts, unaudited) 2006 2005 2006 2005
- ------------------------------------------------------------------------------------------------------------------------------
REVENUE $ 2,826 $ 3,319 $ 11,643 $ 11,130
Less: royalties (317) (421) (1,245) (1,366)
- ------------------------------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES 2,509 2,898 10,398 9,764
- ------------------------------------------------------------------------------------------------------------------------------
EXPENSES
Production 519 423 1,949 1,663
Transportation and blending 333 353 1,443 1,293
Depletion, depreciation and amortization 724 550 2,391 2,013
Asset retirement obligation accretion (note 5) 18 16 68 69
Administration 57 36 180 151
Stock-based compensation (note 5) 176 125 139 723
Interest, net 62 28 140 149
Risk management activities (note 10) (115) (349) 312 1,952
Foreign exchange loss (gain) 151 (11) 122 (132)
- ------------------------------------------------------------------------------------------------------------------------------
1,925 1,171 6,744 7,881
- ------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 584 1,727 3,654 1,883
Taxes other than income tax 41 51 256 194
Current income tax (note 7) 95 58 222 286
Future income tax (note 7) 135 514 652 353
- ------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 313 $ 1,104 $ 2,524 $ 1,050
- ------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS PER COMMON SHARE (note 9)
Basic $ 0.58 $ 2.06 $ 4.70 $ 1.96
Diluted $ 0.58 $ 2.06 $ 4.70 $ 1.95
==============================================================================================================================
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended
----------
DEC 31 Dec 31
(millions of Canadian dollars, unaudited) 2006 2005
- ------------------------------------------------------------------------------------------------------------------------------
BALANCE - BEGINNING OF YEAR $ 5,804 $ 4,922
Net earnings 2,524 1,050
Dividends on common shares (note 8) (161) (127)
Purchase of common shares under Normal Course Issuer Bid (note 8) (26) (41)
- ------------------------------------------------------------------------------------------------------------------------------
BALANCE - END OF YEAR $ 8,141 $ 5,804
==============================================================================================================================
52 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended Year Ended
---------- ----------
DEC 31 Dec 31 DEC 31 Dec 31
(millions of Canadian dollars, unaudited) 2006 2005 2006 2005
- ----------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings $ 313 $ 1,104 $ 2,524 $ 1,050
Non-cash items
Depletion, depreciation and amortization 724 550 2,391 2,013
Asset retirement obligation accretion 18 16 68 69
Stock-based compensation 176 125 139 723
Unrealized risk management activities (241) (825) (1,013) 925
Unrealized foreign exchange loss (gain) 171 5 134 (103)
Deferred petroleum revenue tax (recovery) expense (3) 1 37 (9)
Future income tax 135 514 652 353
Deferred charges 6 2 (2) (31)
Abandonment expenditures (19) (16) (75) (46)
Net change in non-cash working capital (317) (68) (679) (147)
- ----------------------------------------------------------------------------------------------------------------------------
963 1,408 4,176 4,797
- ----------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Issue (repayment) of bank credit facilities 5,384 74 6,499 (435)
Issue of medium-term notes -- -- 400 400
Repayment of senior unsecured notes -- (194) -- (194)
Issue of US dollar debt securities -- -- 788 --
Repayment of preferred securities -- -- -- (107)
Issue of common shares on exercise of stock options 4 3 21 9
Dividends on common shares (40) (32) (153) (121)
Purchase of common shares -- (29) (28) (45)
Net change in non-cash working capital 29 3 37 19
- ----------------------------------------------------------------------------------------------------------------------------
5,377 (175) 7,564 (474)
- ----------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant and equipment (1,791) (1,764) (7,266) (5,340)
Net proceeds on sale of property, plant and equipment 68 101 71 454
- ----------------------------------------------------------------------------------------------------------------------------
Net expenditures on property, plant and equipment (1,723) (1,663) (7,195) (4,886)
Acquisition of Anadarko Canada Corporation (note 2) (4,641) -- (4,641) --
Net proceeds on sale of other assets -- -- -- 11
Net change in non-cash working capital 35 436 101 542
- ----------------------------------------------------------------------------------------------------------------------------
(6,329) (1,227) (11,735) (4,333)
- ----------------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 11 6 5 (10)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 12 12 18 28
- ----------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF PERIOD $ 23 $ 18 $ 23 $ 18
============================================================================================================================
INTEREST PAID $ 83 $ 48 $ 262 $ 200
TAXES PAID
Taxes other than income tax $ 52 $ 21 $ 291 $ 192
Current income tax $ 108 $ 46 $ 412 $ 238
============================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 53
===============================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (tabular amounts in millions of
Canadian dollars, unaudited)
1. ACCOUNTING POLICIES
The interim consolidated financial statements of Canadian Natural Resources
Limited (the "Company") include the Company and all of its subsidiaries and
partnerships, and have been prepared following the same accounting policies as
the audited consolidated financial statements of the Company as at December 31,
2005. The interim consolidated financial statements contain disclosures that
are supplemental to the Company's annual audited consolidated financial
statements. Certain disclosures that are normally required to be included in
the notes to the annual audited consolidated financial statements have been
condensed. These financial statements should be read in conjunction with the
Company's audited consolidated financial statements and notes thereto for the
year ended December 31, 2005.
COMPARATIVE FIGURES
Certain figures relating to the presentation of gross revenues and gross
transportation and blending provided for the prior year have been reclassified
to conform to the presentation adopted in 2006.
2. ACQUISITION OF ANADARKO CANADA CORPORATION
In November 2006, the Company completed the acquisition of all of the issued
and outstanding common shares of Anadarko Canada Corporation ("ACC"), a
subsidiary of Anadarko Petroleum Corporation, for net cash consideration of
$4,641 million including working capital and other adjustments. Substantially
all of ACC's land and production base are located in Western Canada.
The acquisition was accounted for using the purchase method. Operating results
from ACC have been consolidated with the results of the Company effective from
November 2, 2006, the date of acquisition, and are reported in the North
America segment. The preliminary allocation of the net purchase price is
subject to change as actual amounts are determined. The preliminary allocation
of the net purchase price to assets acquired and liabilities assumed based on
their fair values was as follows:
Net purchase price:
----------
Net cash consideration(1) $ 4,641
================================================================================
Net purchase price allocated as follows:
Non-cash working capital deficit assumed and other $ (105)
Property, plant and equipment 6,249
Long-term debt (9)
Asset retirement obligation (56)
Future income tax (1,438)
- --------------------------------------------------------------------------------
$ 4,641
================================================================================
(1) NET CASH CONSIDERATION WAS REDUCED BY $88 MILLION TO REFLECT THE SETTLEMENT
OF US DOLLAR CURRENCY FORWARD CONTRACTS DESIGNATED AS HEDGES OF THE ACC
SHARE PURCHASE PRICE.
54 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
3. OTHER LONG-TERM ASSETS
----------
DEC 31 Dec 31
2006 2005
- ------------------------------------------------------------------------------------------------
Deferred charges $ 109 $ 107
Risk management (note 10) 128 -
Other 23 -
- ------------------------------------------------------------------------------------------------
260 107
Less: current portion 106 -
- ------------------------------------------------------------------------------------------------
$ 154 $ 107
================================================================================================
4. LONG-TERM DEBT
---------
DEC 31 Dec 31
2006 2005
- ------------------------------------------------------------------------------------------------
Bank credit facilities
Bankers' acceptances $ 6,621 $ 122
Medium-term notes 925 525
Senior unsecured notes (2006 and 2005 - US$93 million) 108 108
US dollar debt securities (2006 - US$2,908; and 2005 - US$2,200 million) 3,389 2,566
- ------------------------------------------------------------------------------------------------
$ 11,043 $ 3,321
================================================================================================
BANK CREDIT FACILITIES
As at December 31, 2006, the Company had in place unsecured bank credit
facilities of $7,809 million, comprised of:
o a $100 million demand credit facility;
o a $500 million demand credit facility;
o a 3-year non-revolving syndicated credit facility of $3,850 million;
o a 5-year revolving syndicated credit facility of $1,825 million;
o a 5-year revolving syndicated credit facility of $1,500 million; and
o a (pound)15 million demand credit facility related to the Company's North
Sea operations.
During the second quarter, the revolving syndicated credit facilities were
renegotiated and are fully revolving for a period of five years maturing June
2011. Both facilities are extendible annually for one year periods at the
mutual agreement of the Company and the lenders. If the facilities are not
extended, the full amount of the outstanding principal would be repayable on
the maturity date.
In conjunction with the closing of the acquisition of ACC (note 2), the Company
executed a $3,850 million, three-year non-revolving syndicated credit facility
maturing in October 2009. This facility is subject to certain prepayment
requirements up to a maximum of $1,500 million.
During the fourth quarter, the Company obtained a $500 million credit facility
repayable on demand.
CANADIAN NATURAL RESOURCES LIMITED 55
===============================================================================
The weighted average interest rate of the bank credit facilities outstanding at
December 31, 2006, was 4.8% (December 31, 2005 - 4.0%).
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $338 million, including $300 million related to the Horizon
Project, were outstanding at December 31, 2006.
MEDIUM-TERM NOTES
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.
Subsequent to December 31, 2006, the 7.40% unsecured debentures due March 1,
2007 were repaid.
US DOLLAR DEBT SECURITIES
In August 2006, the Company issued US$250 million of unsecured notes maturing
August 2016 and US$450 million of unsecured notes maturing February 2037,
bearing interest at 6.00% and 6.50%, respectively. Concurrently, the Company
entered into cross-currency interest-rate swaps to fix the Canadian dollar
interest and principal repayment amounts on the US$250 million notes at 5.40%
and C$279 million (note 10). Proceeds from the securities issued were used to
repay bankers' acceptances under the Company's bank credit facilities.
In November 2006, the shelf prospectus, filed in June 2005, was increased from
US$2 billion to US$3 billion, leaving US$2.3 billion available for issue in the
United States until July 2007. If issued, these securities will bear interest
as determined at the date of issuance.
5. OTHER LONG-TERM LIABILITIES
----------
DEC 31 Dec 31
2006 2005
- ------------------------------------------------------------------------------
Asset retirement obligations $ 1,166 $ 1,112
Stock-based compensation 744 891
Risk management (note 10) - 885
Other 94 17
- ------------------------------------------------------------------------------
2,004 2,905
Less: current portion 611 1,471
- ------------------------------------------------------------------------------
$ 1,393 $ 1,434
==============================================================================
56 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
ASSET RETIREMENT OBLIGATIONS
At December 31, 2006, the Company's total estimated undiscounted cost to settle
its asset retirement obligations was approximately $4,497 million (December 31,
2005 - $3,325 million). These costs will be incurred over the lives of the
operating assets and have been discounted using an average credit-adjusted risk
free rate of 6.7%. A reconciliation of the discounted asset retirement
obligations is as follows:
---------------
YEAR Year
ENDED Ended
DEC 31, 2006 Dec 31, 2005
- ------------------------------------------------------------------------------------------
Balance - beginning of year $ 1,112 $ 1,119
Liabilities incurred 26 47
Liabilities acquired (note 2) 56 -
Liabilities settled (75) (46)
Asset retirement obligation accretion 68 69
Revision of estimates (21) (56)
Foreign exchange - (21)
- ------------------------------------------------------------------------------------------
Balance - end of year $ 1,166 $ 1,112
==========================================================================================
The Company's pipelines have indeterminate lives 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 years
in which the lives of the assets are determinable.
STOCK-BASED COMPENSATION
The Company recognizes a liability for the potential cash settlements under its
Stock 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.
---------------
YEAR Year
ENDED Ended
DEC 31, 2006 Dec 31, 2005
- ------------------------------------------------------------------------------------------
Balance - beginning of year $ 891 $ 323
Stock-based compensation 139 723
Current year payment for options surrendered (264) (227)
Transferred to common shares (101) (29)
Capitalized to Horizon Project 79 101
- ------------------------------------------------------------------------------------------
Balance - end of year 744 891
Less: current portion of stock-based compensation 611 629
- ------------------------------------------------------------------------------------------
$ 133 $ 262
==========================================================================================
CANADIAN NATURAL RESOURCES LIMITED 57
===============================================================================
6. EMPLOYEE FUTURE BENEFITS
In connection with the acquisition of ACC, the Company assumed obligations to
provide defined contribution pension benefits to certain ACC employees
continuing their employment with the Company, and defined benefit pension and
other post-retirement benefits to former ACC employees, under registered and
unregistered pension plans.
The estimated future cost of providing defined benefit pension and other
post-retirement benefits to former ACC employees is actuarially determined
using management's best estimates of demographic and financial assumptions. The
discount rate of 5% used to determine accrued benefit obligations is based on a
year end market rate of interest for high-quality debt instruments with cash
flows that match the timing and amount of expected benefit payments. Company
contributions to the defined contribution plan are expensed as incurred. The
benefit obligation under the registered pension plan at December 31, 2006 was
$29 million. As required by government regulations, the Company has set aside
funds with an independent trustee to meet these benefit obligations. As at
December 31, 2006, these plan assets had a fair value of $54 million. The
unregistered pension plans are unfunded and have a benefit obligation of $15
million at December 31, 2006.
7. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Year Ended
--------- --------
DEC 31 Dec 31 DEC 31 Dec 31
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------------
Current income tax - North America $ 51 $ 8 $143 $ 99
Current income tax - North Sea 30 31 30 155
Current income tax - Offshore West Africa 14 19 49 32
- -------------------------------------------------------------------------------------------------------------------------
Current income tax 95 58 222 286
Future income tax 135 514 652 353
- -------------------------------------------------------------------------------------------------------------------------
Income tax expense $230 $572 $874 $639
=========================================================================================================================
Taxable income from the conventional crude oil and natural gas business in
Canada is primarily generated through partnerships, with the related income
taxes payable in a future period. North America current income taxes have been
provided on the basis of the corporate structure and available income tax
deductions and will vary depending upon the nature and amount of capital
expenditures incurred in Canada in any particular year.
During 2006, income tax rate changes resulted in a reduction of future income
tax liabilities of approximately $438 million in North America, an increase of
future income tax liabilities of approximately $110 million in the UK North Sea
and a reduction of future income tax liabilities of approximately $67 million
in Cote d'Ivoire.
8. SHARE CAPITAL
-------------------------------------------------
Year Ended Dec 31, 2006
ISSUED NUMBER OF SHARES
COMMON SHARES (thousands) AMOUNT
- -------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year 536,348 $ 2,442
Issued upon exercise of stock options 2,040 21
Previously recognized liability on stock options exercised for
common shares - 101
Purchase of common shares under Normal Course Issuer Bid (485) (2)
- -------------------------------------------------------------------------------------------------------------------------
Balance - end of year 537,903 $ 2,562
=========================================================================================================================
58 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
NORMAL COURSE ISSUER BID
During 2006, the Company purchased 485,000 common shares for cancellation at an
average price of $57.33 per common share, for a total cost of $28 million.
Retained earnings was reduced by $26 million, representing the excess of the
purchase price of the common shares over their average carrying value. In
January 2007, the Company renewed its Normal Course Issuer Bid to purchase,
through the facilities of the Toronto Stock Exchange and the New York Stock
Exchange, during the 12-month period beginning January 24, 2007 and ending
January 23, 2008, up to 26,941,730 common shares or 5% of the outstanding
common shares of the Company then outstanding on the date of the announcement.
As at March 3, 2007, the Company had not purchased any additional shares under
the Normal Course Issuer Bid.
DIVIDEND POLICY
In March 2007, the Board of Directors set the regular quarterly dividend at
$0.085 per common share. The Company has paid regular quarterly dividends in
January, April, July, and October of each year since 2001. The dividend policy
undergoes a periodic review by the Board of Directors and is subject to change.
In February 2006, the Board of Directors set the regular quarterly dividend at
$0.075 per common share (2005 - $0.059 per common share).
STOCK OPTIONS
-----------------------------------------------------
Year Ended Dec 31, 2006
STOCK OPTIONS WEIGHTED AVERAGE
(thousands) EXERCISE PRICE
- ---------------------------------------------------------------------------------------------------------
Outstanding - beginning of year 30,510 $ 17.79
Granted 13,084 $ 59.61
Exercised for common shares (2,040) $ 10.67
Surrendered for cash settlement (5,180) $ 12.60
Forfeited (1,949) $ 37.51
- ---------------------------------------------------------------------------------------------------------
Outstanding - end of year 34,425 $ 33.77
- ---------------------------------------------------------------------------------------------------------
Exercisable - end of year 9,177 $ 14.73
=========================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 59
===============================================================================
9. NET EARNINGS PER COMMON SHARE
Three Months Ended Year Ended
---------- ----------
DEC 31 Dec 31 DEC 31 Dec 31
2006 2005 2006 2005
- ---------------------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding (thousands)
Basic 537,616 536,482 537,339 536,650
Assumed settlement of preferred securities with
common shares(1) -- -- -- 1,775
- ---------------------------------------------------------------------------------------------------------------------------------
Diluted 537,616 536,482 537,339 538,425
- ---------------------------------------------------------------------------------------------------------------------------------
Net earnings $ 313 $ 1,104 $ 2,524 $ 1,050
Interest on preferred securities, net of tax(1) -- -- -- 4
Revaluation on preferred securities, net of tax(1) -- -- -- (2)
- ---------------------------------------------------------------------------------------------------------------------------------
Diluted net earnings $ 313 $ 1,104 $ 2,524 $ 1,052
- ---------------------------------------------------------------------------------------------------------------------------------
Net earnings per common share
Basic $ 0.58 $ 2.06 $ 4.70 $ 1.96
Diluted $ 0.58 $ 2.06 $ 4.70 $ 1.95
=================================================================================================================================
- ------------
(1) THE PREFERRED SECURITIES WERE REDEEMED IN SEPTEMBER 2005.
60 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
10. FINANCIAL INSTRUMENTS
RISK MANAGEMENT
The Company uses derivative financial instruments to manage its commodity
price, foreign currency and interest rate exposures. These financial
instruments are entered into solely for hedging purposes and are not intended
for trading or other speculative purposes.
The estimated fair values of non-designated financial derivatives were
comprised as follows:
------------------------------------
YEAR ENDED Year Ended
DEC 31, 2006 Dec 31, 2005
- --------------------------------------------------------------------------------------------------------------------------------
Asset (liability) RISK MANAGEMENT DEFERRED Risk management Deferred
MARK-TO-MARKET REVENUE mark-to-market revenue
- --------------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year $ (877) $ (8) $ 66 $ (26)
Net cost of outstanding put options 455 - 190 -
Net change in fair value of outstanding
derivative financial instruments 1,005 - (943) -
Amortization of deferred revenue - 8 - 18
- --------------------------------------------------------------------------------------------------------------------------------
583 - (687) (8)
Add: Put premium financing obligations(1) (455) - (190) -
- --------------------------------------------------------------------------------------------------------------------------------
Balance - end of year 128 - (877) (8)
Less: current portion 88 - (834) (8)
- --------------------------------------------------------------------------------------------------------------------------------
$ 40 $ - $ (43) $ -
================================================================================================================================
- ------------
(1) THE COMPANY HAS NEGOTIATED PAYMENT OF PUT OPTION PREMIUMS WITH VARIOUS
COUNTER-PARTIES AT THE TIME OF ACTUAL SETTLEMENT OF THE RESPECTIVE
OPTIONS. THESE OBLIGATIONS HAVE BEEN REFLECTED IN THE NET RISK MANAGEMENT
ASSET (LIABILITY).
Net losses (gains) from risk management activities for the periods ended
December 31 were as follows:
Three Months Ended Year Ended
-------------- ---------------
DEC 31 Dec 31 DEC 31 Dec 31
2006 2005 2006 2005
- --------------------------------------------------------------------------------------------------------------------------------
Net realized risk management loss $ 126 $ 476 $ 1,325 $ 1,027
Net unrealized risk management
mark-to-market (gain) loss (241) (825) (1,013) 925
- --------------------------------------------------------------------------------------------------------------------------------
$ (115) $ (349) $ 312 $ 1,952
=================================================================================================================================
As at December 31, 2006, the net unrecognized asset related to the estimated
fair values of derivative financial instruments designated as hedges was $222
million (December 31, 2005 - net unrecognized liability of $990 million).
CANADIAN NATURAL RESOURCES LIMITED 61
===============================================================================
The Company had the following net financial derivatives outstanding as at
December 31, 2006:
Remaining term Volume Average price Index
- -----------------------------------------------------------------------------------------------------------------------------
CRUDE OIL
Price collars Jan 2007 - Dec 2007 15,000 bbl/d US$50.00 - US$66.25 Mayan Heavy
Jan 2007 - Dec 2007 50,000 bbl/d US$60.00 - US$71.49 WTI
Jan 2007 - Dec 2007 100,000 bbl/d US$60.00 - US$78.11 WTI
Jan 2007 - Dec 2007 50,000 bbl/d US$65.00 - US$84.52 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.05 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.98 WTI
Put options(1) Jan 2007 - Dec 2007 100,000 bbl/d US$45.00 WTI
Jan 2007 - Dec 2007 100,000 bbl/d US$60.00 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
WTI/Dated
Brent differential swaps Jan 2007 - Dec 2007 50,000 bbl/d US$1.34 Brent
=============================================================================================================================
The cost of outstanding put options and their respective periods of settlement
are as follows:
Q1 2007 Q2 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008
- -----------------------------------------------------------------------------------------------------------------------------
Cost(1) ($ millions) US$82 US$83 US$83 US$83 US$14 US$15 US$15 US$15
=============================================================================================================================
(1) SUBSEQUENT TO DECEMBER 31, 2006, THE COMPANY UNWOUND 23,000 BBL/D OF
US$60.00 WTI PUT OPTIONS FOR THE PERIOD FEBRUARY 2007 TO DECEMBER 2007,
FOR CASH CONSIDERATION OF US$40 MILLION.
Remaining term Volume Average price Index
- -----------------------------------------------------------------------------------------------------------------------------
NATURAL GAS
AECO collars Jan 2007 - Mar 2007 100,000 GJ/d C$7.00 - C$11.63 AECO
Jan 2007 - Mar 2007 200,000 GJ/d C$7.25 - C$8.38 AECO
Jan 2007 - Mar 2007 162,500 GJ/d C$7.25 - C$9.48 AECO
Jan 2007 - Mar 2007 162,500 GJ/d C$7.50 - C$8.94 AECO
Jan 2007 - Mar 2007 300,000 GJ/d C$7.50 - C$18.77 AECO
Jan 2007 - Mar 2007 400,000 GJ/d C$8.50 - C$11.22 AECO
Jan 2007 - Dec 2007 60,000 GJ/d C$8.00 - C$8.79 AECO
Apr 2007 - Oct 2007 500,000 GJ/d C$6.00 - C$10.13 AECO
Apr 2007 - Oct 2007 500,000 GJ/d C$7.00 - C$8.24 AECO
Nov 2007 - Mar 2008 400,000 GJ/d C$7.00 - C$14.08 AECO
Nov 2007 - Mar 2008 500,000 GJ/d C$7.50 - C$10.81 AECO
=============================================================================================================================
The Company's outstanding financial derivatives will be settled monthly based
on the applicable index pricing for the respective contract month.
In addition to the financial derivatives noted above, the Company also entered
into natural gas physical sales contracts for 325,000 GJ/d at an average fixed
price of C$9.17 per GJ at AECO for the period January to March 2007 and 300,000
GJ/d at an average fixed price of C$7.33 per GJ at AECO for the period April
2007 to October 2007.
62 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
Amount
Remaining term ($ millions) Fixed rate Floating rate
- ------------------------------------------------------------------------------------------------------------------------------
INTEREST RATE
Swaps - fixed to floating Jan 2007 - Oct 2012 US$350 5.45% LIBOR(1) + 0.81%
Jan 2007 - Dec 2014 US$350 4.90% LIBOR(1) + 0.38%
Swaps - floating to fixed Jan 2007 - Mar 2007 C$2 7.36% CDOR(2)
==============================================================================================================================
- ------------
(1) LONDON INTERBANK OFFERED RATE
(2) CANADIAN DEPOSIT OVERNIGHT RATE
Remaining term Amount Exchange rate Interest rate Interest rate
($ millions) (US$/C$) (US$) (C$)
- ------------------------------------------------------------------------------------------------------------------------------
CURRENCY
Swaps Jan 2007 - Aug 2016 US$250 1.116 6.00% 5.40%
==============================================================================================================================
11. COMMITMENTS
The Company has committed to certain payments as follows:
2007 2008 2009 2010 2011 Thereafter
- -------------------------------------------------------------------------------------------------------------------------------
Product transportation and $ 213 $ 193 $ 134 $ 123 $ 99 $ 1,042
pipeline (1)
Offshore equipment
operating lease (2) $ 77 $ 52 $ 52 $ 52 $ 50 $ 131
Offshore drilling $ 73 $ 83 $ 12 $ 12 $ 4 $ 4
Asset retirement
obligations (3) $ 3 $ 3 $ 3 $ 4 $ 4 $ 4,480
Office lease $ 26 $ 32 $ 33 $ 34 $ 22 $ -
Electricity and other $ 51 $ 10 $ 17 $ 18 $ 1 $ -
===============================================================================================================================
- ------------
(1) THE COMPANY HAS 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, THE ANNUAL TOLL PAYMENTS BEFORE OPERATING COSTS
WILL BE APPROXIMATELY $35 MILLION.
(2) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF OBLIGATIONS
RELATED TO FLOATING PRODUCTION, STORAGE AND OFFTAKE VESSELS ("FPSO").
DURING 2006, THE COMPANY ENTERED INTO AN AGREEMENT TO LEASE AN ADDITIONAL
FPSO COMMENCING IN 2008, IN CONNECTION WITH THE PLANNED OFFSHORE
DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. THE NEW FPSO LEASE AGREEMENT
CONTAINS CANCELLATION PROVISIONS AT THE OPTION OF THE COMPANY, SUBJECT TO
ESCALATING TERMINATION PAYMENTS THROUGHOUT 2007 TO A MAXIMUM OF US$395
MILLION.
(3) AMOUNTS REPRESENT MANAGEMENT'S ESTIMATE OF THE FUTURE UNDISCOUNTED
PAYMENTS TO SETTLE ASSET RETIREMENT OBLIGATIONS RELATED TO RESOURCE
PROPERTIES, FACILITIES, AND PRODUCTION PLATFORMS, BASED ON CURRENT
LEGISLATION AND INDUSTRY OPERATING PRACTICES. AMOUNTS DISCLOSED FOR THE
PERIOD 2007 - 2011 REPRESENT THE MINIMUM REQUIRED EXPENDITURES TO MEET
THESE OBLIGATIONS. ACTUAL EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED
THESE MINIMUM AMOUNTS.
In 2005, the Board of Directors of the Company approved the construction costs
for Phase 1 of the Horizon Project, with an approved budget of $6.8 billion.
Cumulative construction spending to December 31, 2006 was approximately $4.0
billion. Final construction costs for Phase 1 may differ from the approved
budget due to changes in the final scope and timing of completion of the
project, and/or inflationary cost pressures.
CANADIAN NATURAL RESOURCES LIMITED 63
===============================================================================
12. SEGMENTED INFORMATION
NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA
Three Months Three Months Three Months
Ended Year Ended Ended Year Ended Ended Year Ended
Dec 31 Dec 31 Dec 31 Dec 31 Dec 31 Dec 31
----- ----- ----- ----- ----- -----
(millions of Canadian
dollars, unaudited) 2006 2005 2006 2005 2006 2005 2006 2005 2006 2005 2006 2005
- ---------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE 2,243 2,663 9,066 8,955 352 371 1,616 1,659 232 280 950 485
Less: royalties (305) (413) (1,203) (1,350) (1) (1) (3) (3) (11) (7) (39) (13)
- ---------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE, NET OF 1,938 2,250 7,863 7,605 351 370 1,613 1,656 221 273 911 472
ROYALTIES
- ---------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production 400 322 1,436 1,211 77 68 390 379 38 26 106 53
Transportation and blending 337 359 1,465 1,310 4 4 15 20 1 - 1 -
Depletion, depreciation and
amortization 580 412 1,897 1,595 85 70 297 306 57 66 189 104
Asset retirement obligation
accretion 9 9 35 34 9 6 31 34 - 1 2 1
Realized risk management
activities 76 432 1,022 870 50 44 303 157 - - - -
- ---------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES 1,402 1,534 5,855 5,020 225 192 1,036 896 96 93 298 158
- ---------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS (LOSS)
BEFORE THE FOLLOWING 536 716 2,008 2,585 126 178 577 760 125 180 613 314
- ---------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration
Stock-based compensation
Interest, net
Unrealized risk management
activities
Foreign exchange loss (gain)
- ---------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED EXPENSES
- ---------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES
Taxes other than income tax
Current income tax expense
Future income tax expense
- ---------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS
=================================================================================================================================
64 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
INTER-SEGMENT
MIDSTREAM ELIMINATION AND OTHER TOTAL
Three Months Three Months Three Months
Ended Year Ended Ended Year Ended Ended Year Ended
Dec 31 Dec 31 Dec 31 Dec 31 Dec 31 Dec 31
------ ----- ------ ----- ------ -----
(millions of Canadian
dollars, unaudited) 2006 2005 2006 2005 2006 2005 2006 2005 2006 2005 2006 2005
- ----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE 18 21 72 77 (19) (16) (61) (46) 2,826 3,319 11,643 11,130
Less: royalties - - - - - - - - (317) (421) (1,245) (1,366)
- ----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE, NET OF 18 21 72 77 (19) (16) (61) (46) 2,509 2,898 10,398 9,764
ROYALTIES
- ----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production 6 8 23 24 (2) (1) (6) (4) 519 423 1,949 1,663
Transportation and
blending - - - - (9) (10) (38) (37) 333 353 1,443 1,293
Depletion, depreciation
and amortization 2 2 8 8 - - - - 724 550 2,391 2,013
Asset retirement
obligation accretion - - - - - - - - 18 16 68 69
Realized risk management
activities - - - - - - - - 126 476 1,325 1,027
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES 8 10 31 32 (11) (11) (44) (41) 1,720 1,818 7,176 6,065
- ----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS (LOSS)
BEFORE THE FOLLOWING 10 11 41 45 (8) (5) (17) (5) 789 1,080 3,222 3,699
- ----------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration 57 36 180 151
Stock-based compensation 176 125 139 723
Interest, net 62 28 140 149
Unrealized risk
management activities (241) (825) (1,013) 925
Foreign exchange loss
(gain) 151 (11) 122 (132)
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED 205 (647) (432) 1,816
EXPENSES
- ----------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 584 1,727 3,654 1,883
Taxes other than income
tax 41 51 256 194
Current income tax expense 95 58 222 286
Future income tax
expense 135 514 652 353
- ----------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS 313 1,104 2,524 1,050
==================================================================================================================================
CANADIAN NATURAL RESOURCES LITED 65
===============================================================================
NET ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT
Year Ended
DEC 31, 2006 Dec 31, 2005
------------------------------------------------------
NON-CASH/ Non-Cash/
CASHS FAIR VALUE CAPITALIZED Cash Fair Value Capitalized
EXPENDITURES CHANGES(1) COSTS Expenditures Changes(1) Costs
- ----------------------------------------------------------------------------------------------------------------------------------
North America $ 7,936 $ 1,521 $ 9,457 $ 2,530 $ (22) $ 2,508
North Sea 646 (14) 632 387 (136) 251
Offshore West Africa 134 1 135 439 27 466
Other 11 - 11 5 - 5
Horizon Project(2) 3,185 - 3,185 1,499 - 1,499
Midstream 12 - 12 4 - 4
Head office 26 - 26 22 - 22
- ----------------------------------------------------------------------------------------------------------------------------------
$ 11,950 $ 1,508 $ 13,458 $ 4,886 $ (131) $ 4,755
==================================================================================================================================
- ------------
(1) ASSET RETIREMENT OBLIGATIONS, FUTURE INCOME TAX ADJUSTMENTS ON NON-TAX
BASE ASSETS, AND OTHER FAIR VALUE ADJUSTMENTS.
(2) CASH EXPENDITURES FOR THE HORIZON PROJECT ALSO INCLUDE CAPITALIZED
INTEREST AND STOCK-BASED COMPENSATION.
Property, plant and equipment Total assets
----------- ----------
DEC 31 Dec 31 DEC 31 Dec 31
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------------------
SEGMENTED ASSETS
North America $ 21,879 $ 14,310 $ 23,670 $ 15,939
North Sea 2,029 1,681 2,248 1,950
Offshore West Africa 1,204 1,253 1,323 1,371
Other 24 13 46 30
Horizon Project 5,350 2,169 5,444 2,239
Midstream 207 203 355 258
Head office 74 65 74 65
- -------------------------------------------------------------------------------------------------------------------------------
$ 30,767 $ 19,694 $ 33,160 $ 21,852
===============================================================================================================================
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 on Phase 1 will cease once construction is substantially
complete and this phase of the Horizon Project is available for its intended
use. For the year ended December 31, 2006, pre-tax interest of $196 million was
capitalized to the Horizon Project (December 31, 2005 - $72 million).
66 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with the Company's
continuous offering of medium-term notes pursuant to the short form prospectus
dated August 2005. These ratios are based on the Company's interim consolidated
financial statements that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended December 31, 2006:
- -------------------------------------------------------------------------------
Interest coverage (times)
Net earnings(1) 10.5x
Cash flow from operations(2) 15.8x
- -------------------------------------------------------------------------------
- ------------
(1) NET EARNINGS PLUS INCOME TAXES AND INTEREST EXPENSE; DIVIDED BY THE SUM OF
INTEREST EXPENSE AND CAPITALIZED INTEREST.
(2) CASH FLOW FROM OPERATIONS PLUS CURRENT INCOME TAXES AND INTEREST EXPENSE;
DIVIDED BY THE SUM OF INTEREST EXPENSE AND CAPITALIZED INTEREST.
CANADIAN NATURAL RESOURCES LIMITED 67
===============================================================================
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern
Time on Wednesday, March 7, 2007. The North American conference call number is
1-800-769-8320 and the outside North American conference call number is
001-416-695-6130. Please call in about 10 minutes before the starting time in
order to be patched into the call. The conference call will also be broadcast
live on the internet and may be accessed through the Canadian Natural website
at www.cnrl.com.
A taped rebroadcast will be available until 6:00 p.m. Mountain Time Wednesday,
March 14, 2007. To access the postview in North America, dial 1-888-509-0081.
Those outside of North America, dial 001-416-695-5275. The passcode to use is
638222.
WEBCAST
This call is being webcast by Vcall and can be accessed on Canadian Natural's
website at www.cnrl.com/investor_info/calendar.html.
The webcast is also being distributed over PrecisionIR's Investor Distribution
Network to both institutional and individual investors. Investors can listen to
the call through www.vcall.com or by visiting any of the investor sites in
PrecisionIR's Individual Investor Network.
2007 FIRST QUARTER RESULTS
2007 first quarter results are scheduled for release on Thursday, May 3, 2007.
A conference call will be held on that day at 9:00 a.m. Mountain Time, 11:00
a.m. Eastern Time.
ANNUAL AND SPECIAL MEETING OF THE SHAREHOLDERS
Canadian Natural Resources Limited's Annual and Special Meeting of the
Shareholders will be held on Thursday, May 3, 2007 at 3:00 p.m. Mountain Time
at the Metropolitan Centre, Calgary, Alberta. All shareholders are invited to
attend.
For further information, please contact:
CANADIAN NATURAL RESOURCES LIMITED
2500, 855 - 2nd Street S.W.
Calgary, Alberta
T2P 4J8
TELEPHONE: (403) 514-7777 ALLAN P. MARKIN
Chairman
JOHN G. LANGILLE
Vice-Chairman
FACSIMILE: (403) 514-7888
EMAIL: ir@cnrl.com STEVE W. LAUT
WEBSITE: www.cnrl.com President &
Chief Operating Officer
TRADING SYMBOL - CNQ DOUGLAS A. PROLL
Toronto Stock Exchange Chief Financial Officer &
New York Stock Exchange Senior Vice-President, Finance
COREY B. BIEBER
Vice-President,
Finance & Investor Relations
68 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
- --------------------------------------------------------------------------------
[PHOTOGRAPHS OMITTED] [LOGO OMITTED]
THE PREMIUM VALUE, CANADIAN NATURAL
DEFINED GROWTH, INDEPENDENT
NEWS RELEASE
- --------------------------------------------------------------------------------
CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES DIVIDEND
CALGARY, ALBERTA - MARCH 7, 2007 - FOR IMMEDIATE RELEASE
Canadian Natural Resources Limited announces its Board of Directors has
declared a quarterly cash dividend on its common shares of C$0.085 (eight and
one half cents) per common share. The dividend will be payable April 1, 2007 to
shareholders of record at the close of business on March 16, 2007.
Canadian Natural is a senior oil and natural gas production company, with
continuing operations in its core areas located in Western Canada, the U.K.
portion of the North Sea and Offshore West Africa.
For further information, please contact:
CANADIAN NATURAL RESOURCES LIMITED
2500, 855 - 2nd Street S.W.
Calgary, Alberta
T2P 4J8
ALLAN P. MARKIN DOUGLAS A. PROLL
TELEPHONE: (403) 514-7777 Chairman Chief Financial Officer and
FACSIMILE: (403) 514-7888 Senior Vice-President, Finance
EMAIL: ir@cnrl.com JOHN G. LANGILLE
WEBSITE: www.cnrl.com Vice-Chairman COREY B. BIEBER
Vice-President,
TRADING SYMBOL - CNQ STEVE W. LAUT Finance and Investor Relations
Toronto Stock Exchange President and
New York Stock Exchange Chief Operating Officer