EXHIBIT 99.1
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[GRAPHICS OMITTED - LOGO, PHOTOGRAPHS]
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Third Quarter Report
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Nine months ended Discipline Opportunity Strategy
September 30, 2007
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CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES
THIRD QUARTER RESULTS
Commenting on third quarter 2007 results, Canadian Natural's Chairman, Allan
Markin stated, "As we exit the first nine months of the year, we continue with
our defined plan to manage costs while maximizing value. With the Horizon
Project at 84% complete, we remain on track for targeted first oil in the third
quarter of 2008 and maintain our focus on execution. Our defined plan will be
optimized to take into account the new royalty program that was announced by
the Government of Alberta on October 25th and expected to take effect in 2009.
The new royalty program will have a negative impact, which we are still
attempting to fully define, on our development plans in 2008 and in the future.
As a result, we will carefully adjust our activity to ensure we are maximizing
returns for our shareholders."
John Langille, Vice-Chairman, stated, "With respect to our balance sheet, our
debt to book capitalization decreased as expected. On the marketing side, while
we have seen record breaking US dollar reference prices for crude oil, pricing
for natural gas in Canada has been weaker than expected. Warmer weather has
dictated the soft market for natural gas, along with increasing liquefied
natural gas (LNG) imports to the United States. Given that crude oil and
natural gas realized prices are tied to US reference prices, the strengthening
of the Canadian dollar relative to the US dollar has also had a negative impact
on industry cash flows, lessening the impact of higher WTI pricing. However,
Canadian Natural's extensive 2007 hedging program has reduced the impact on our
realized natural gas price."
Steve Laut, President and Chief Operating Officer of Canadian Natural
commented, "In the first nine months of 2007 we continued to demonstrate the
strength and quality of our asset base which facilitates the allocation of our
capital to higher returning projects. North American natural gas production, as
expected, declined in the quarter and will continue to decline for the
remainder of the year, reflecting our reduced capital spending in 2007 due to
the lower returns currently being generated in the natural gas part of the
business. Conversely, North American conventional liquids returns remain strong
and quarterly production increased, reflecting growth at Pelican Lake as well
as thermal wells transitioning off the steaming cycle and into production."
HIGHLIGHTS
Three Months Ended Nine Months Ended
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SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions, except as noted) 2007 2007 2006 2007 2006
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Net earnings $ 700 $ 841 $ 1,116 $ 1,810 $ 2,211
per common share, basic and diluted $ 1.30 $ 1.56 $ 2.08 $ 3.36 $ 4.12
Adjusted net earnings from operations (1) $ 644 $ 595 $ 470 $ 1,860 $ 1,252
per common share, basic and diluted $ 1.19 $ 1.10 $ 0.87 $ 3.44 $ 2.33
Cash flow from operations (2) $ 1,577 $ 1,513 $ 1,313 $ 4,712 $ 3,639
per common share, basic and diluted $ 2.92 $ 2.81 $ 2.44 $ 8.74 $ 6.77
Capital expenditures, net of dispositions $ 1,442 $ 1,460 $ 1,661 $ 4,911 $ 5,528
Daily production, before royalties
Natural gas (mmcf/d) 1,647 1,722 1,437 1,695 1,449
Crude oil and NGLs (bbl/d) 333,062 327,494 321,665 329,208 328,053
Equivalent production (boe/d) 607,484 614,461 561,152 611,665 569,590
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(1) ADJUSTED NET EARNINGS FROM OPERATIONS IS A NON-GAAP MEASURE 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 MEASURE THAT THE COMPANY CONSIDERS
KEY AS IT DEMONSTRATES THE COMPANY'S ABILITY TO FUND CAPITAL REINVESTMENT
AND DEBT REPAYMENT. THE DERIVATION OF THIS MEASURE IS DISCUSSED IN THE
MD&A.
o As expected, natural gas production volumes declined from the prior
quarter in 2007 but continued to perform well. Natural gas production for
Q3/07 averaged 1,647 mmcf/d, up 15% from 1,437 mmcf/d for Q3/06 and down
4% from 1,722 mmcf/d for Q2/07. Volumes in Q3/07 continued to reflect
better than expected production from a number of wells, the addition of
Anadarko Canada Corporation ("ACC") acquisition volumes, and continued
high-grading of opportunities.
o Total crude oil and NGLs production for Q3/07 was 333,062 bbl/d. Q3/07
production was 4% higher than Q3/06 volumes of 321,665 bbl/d, and
increased 2% from Q2/07 volumes of 327,494 bbl/d. Increased volumes in
Q3/07 reflected the transition from steam cycles to production cycles for
a number of thermal wells and continued development of Pelican Lake.
o Quarterly cash flow from operations was $1,577 million, an increase of 20%
from Q3/06 and an increase of 4% from Q2/07. The increase from Q3/06
primarily reflected higher commodity realizations, lower year over year
risk management losses, and the impact of higher sales volumes due to the
acquisition of ACC. The increase from Q2/07 represented higher sales
volumes in Q3/07. Cash flow in Q3/07 was negatively impacted by the
strengthening of the Canadian dollar compared to the US dollar. The
average exchange rate for Q3/07 was US$0.9565 per C$1.00 compared with
US$0.9112 per C$1.00 for Q2/07 and US$0.8919 per C$1.00 for Q3/06.
o Q3/07 quarterly net earnings were $700 million, a 37% decrease from Q3/06
and a 17% decrease from Q2/07. Quarterly adjusted net earnings from
operations for Q3/07 were $644 million, an increase of 8% from Q2/07
results and a 37% increase from Q3/06.
o Completed the Q3/07 North American drilling program targeting 153 net
crude oil wells and 106 net natural gas wells with a 95% success ratio in
the quarter, excluding stratigraphic test and service wells. The success
rate is a reflection of Canadian Natural's strong, predictable, low-risk
asset base. Crude oil drilling activity was down from 263 net wells in
Q3/06 due to the timing of the drilling program. Natural gas drilling
decreased 5% from Q3/06, reflecting Canadian Natural's reallocation of
capital towards a higher return crude oil drilling program.
o Maintained a strong undeveloped conventional core land base in Canada of
11.9 million net acres - a key asset for continued value growth.
2 CANADIAN NATURAL RESOURCES LIMITED
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o Continued production improvements at the Pelican Lake Field from new
drilling activity and the expansion of the enhanced crude oil recovery
program. Pelican Lake crude oil production averaged approximately 35,000
bbl/d during the quarter, up 17% or approximately 5,000 bbl/d from Q3/06.
Production is targeted to continue to increase in Q4/07.
o Secured a deep water drilling rig for the Baobab Field. The equipment is
targeted to be mobilized in Q1/08, enabling work to begin on the
restoration of shut-in production. It is forecasted that 3 of the 5
shut-in Baobab wells should come back on stream over the course of 2008
and 2009.
o Work progress on the Horizon Oil Sands Project ("Horizon Project") exited
Q3/07 at 84% complete and remains on track for first oil targeted Q3/08.
o On October 25, 2007 the Province of Alberta issued the details of its
proposed changes to the Alberta crude oil and natural gas royalty regime,
effective January 1, 2009. The Company expects that its 2009 and future
Alberta royalty payments will increase as a result of the proposed royalty
regime changes and that its level of activity in Alberta will be reduced
from what it otherwise would have been in the absence of such royalty
changes. In the current pricing and cost environment, the biggest
reduction in the Company's Alberta activity will be experienced in the
conventional natural gas business. The number of natural gas wells to be
drilled in Alberta by the Company in 2008 and years beyond will be
approximately 30% to 50% less than the number of such wells that would
have otherwise been drilled in the absence of such royalty changes.
o Declared a quarterly cash dividend on common shares of C$0.085 per common
share, payable January 1, 2008, a 13% increase over the 2006 quarterly
dividend.
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/medium 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 NINE MONTHS ENDED
SEP 30, 2007 SEP 30, 2007
(THOUSANDS OF NET ACRES) (NET WELLS) (1)
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Canadian conventional
Northeast British Columbia 2,419 53
Northwest Alberta 1,501 97
Northern Plains 6,523 507
Southern Plains 901 94
Southeast Saskatchewan 117 12
In-situ Oil Sands 482 179
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11,943 942
Horizon Oil Sands Project 115 98
United Kingdom North Sea 298 7
Offshore West Africa 206 4
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12,562 1,051
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(1) DRILLING ACTIVITY INCLUDES STRATIGRAPHIC TEST AND SERVICE WELLS
DRILLING ACTIVITY (NUMBER OF WELLS)
Nine Months Ended
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SEP 30, 2007 Sep 30, 2006
GROSS NET Gross Net
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Crude oil 458 423 471 426
Natural gas 386 303 774 581
Dry 89 77 102 91
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Subtotal 933 803 1,347 1,098
Stratigraphic test / service wells 250 248 310 309
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Total 1,183 1,051 1,657 1,407
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Success rate (excluding stratigraphic test / service wells) 90% 92%
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4 CANADIAN NATURAL RESOURCES LIMITED
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NORTH AMERICA CONVENTIONAL
NORTH AMERICA NATURAL GAS
Three Months Ended Nine Months Ended
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SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
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Natural gas production (mmcf/d) 1,622 1,696 1,416 1,670 1,425
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Net wells targeting natural gas 106 7 111 358 658
Net successful wells drilled 96 6 98 303 581
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Success rate 91% 86% 88% 85% 88%
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o Q3/07 North America natural gas production increased by 15% over Q3/06 and
as expected, decreased by 4% from Q2/07. The increase from Q3/06 reflected
the full impact of the acquisition of ACC natural gas volumes, whereas the
decrease from Q2/07 reflected the Company's strategic decision to scale
back the 2007 drilling program due to reallocation of capital to currently
higher return crude oil projects.
o Canadian Natural targeted 106 net natural gas wells in Q3/07 including 32
wells in the Northern Plains region, 8 wells in the Northwest Alberta
region, 63 well in the Southern Plains region and 3 wells in the Northeast
British Columbia region, with an overall success rate of 91%. This
compares to 111 net targeted natural gas wells in Q3/06, a 5% reduction.
o Planned drilling activity for Q4/07 includes 63 targeted natural gas
wells.
NORTH AMERICA CRUDE OIL AND NGLS
Three Months Ended Nine Months Ended
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SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
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Crude oil and NGLs production (bbl/d) 252,095 240,420 233,440 243,388 230,430
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Net wells targeting crude oil 153 78 263 438 431
Net successful wells drilled 150 75 253 416 417
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Success rate 98% 96% 96% 95% 97%
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o Q3/07 North America crude oil and NGLs production increased 8% from Q3/06
and increased 5% over Q2/07 levels. The majority of the incremental
production volume was contributed by thermal crude oil and Pelican Lake
crude oil. Primrose thermal production in Q3/07 was negatively impacted by
unplanned outages at the processing plant due to lightning strikes and
water treatment issues as well as higher than expected scaling rates on
new pads. As a result, Primrose production was approximately 3,000 bbl/d
less than Q3/07 expectations.
o During Q3/07, drilling activity included 94 net wells targeting heavy
crude oil, 33 net wells targeting Pelican Lake crude oil, 21 net wells
targeting thermal crude oil and 5 net wells targeting light crude oil.
o 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, is anticipated to add approximately 40,000
bbl/d of crude oil. The Primrose East Expansion received Board of
Directors' sanction in 2006 and The Alberta Energy and Utilities Board
regulatory approval in the first quarter of 2007. Drilling and
construction are currently underway, and production is targeted to
commence 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.
CANADIAN NATURAL RESOURCES LIMITED 5
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o In early 2007, Canadian Natural announced its proposed third phase of the
conventional expansion plan with a development plan for the 45,000 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 has
filed its formal regulatory application documents for this project as part
of the Company's normal course of business. Final corporate sanction will
be impacted by the terms of the proposed changes to the Alberta royalty
regime, environmental regulations, and the final determination of
associated capital costs.
o Development of new pads and secondary recovery conversion projects at
Pelican Lake continued as expected throughout Q3/07. Drilling consisted of
34 horizontal wells, with plans to drill 13 additional horizontal wells
for the remainder of 2007. The response from the water and polymer flood
project continues to be positive. Pelican Lake production averaged
approximately 35,000 bbl/d for Q3/07 compared to approximately 30,000
bbl/d for Q3/06.
o Conventional heavy crude oil production volumes increased slightly in
Q3/07 compared to Q2/07. Production levels for primary were below target
due to earlier than expected declines in certain older fields.
o Planned drilling activity for Q4/07 includes 120 net crude oil wells,
excluding stratigraphic test and service wells.
INTERNATIONAL
The Company operates in the North Sea and Offshore West Africa where production
of light quality crude oil is targeted in conjunction with natural gas that may
be produced in association with crude oil production.
Three Months Ended Nine Months Ended
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SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
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Crude oil production (bbl/d)
North Sea 52,013 57,286 53,988 57,020 59,473
Offshore West Africa 28,954 29,788 34,237 28,800 38,150
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Natural gas production (mmcf/d)
North Sea 10 15 11 13 15
Offshore West Africa 15 11 10 12 9
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Net wells targeting crude oil 2.2 3.1 2.2 7.3 9.2
Net successful wells drilled 2.2 3.1 2.2 7.3 9.2
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Success rate 100% 100% 100% 100% 100%
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NORTH SEA
o Planned platform maintenance shutdowns scheduled for Q3/07 at Ninian,
B-Block and T-Block were successfully completed, reducing Q3/07 volumes
compared to Q2/07, as expected. During Q3/07, 1.0 net crude oil well was
drilled along with 0.9 net water injectors.
o The development of the Lyell Field continued with the second well onstream
in Q3/07 through the existing infrastructure. Production from the initial
Lyell producing wells has been below expectations. Although the wells
encountered thick pay sections, the formation is tight and as a result
production dropped from high initial rates to much lower than targeted
stabilized rates. As a result, continued development of the Lyell Field is
under review.
6 CANADIAN NATURAL RESOURCES LIMITED
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o Commissioning of the Columba E raw water injection facilities was
completed in Q2/07 along with 2 water injection wells facilitating water
injection into the reservoir to commence. The subsea wells are currently
injecting 2,500 bbl/d of water, lower than targeted, as they encountered
significantly tighter formations than expected. As a result production
increases from Columba will be delayed.
o In Q3/07, Canadian Natural entered into a Sale and Purchase Agreement for
the disposal, subject to government and partner consents, of its entire
working interest in the Balmoral, Stirling and Glamis Fields (B-Block).
During Q3/07, transition arrangements and consents progressed, with
closing expected during Q4/07 or early in 2008. In 2007, the B-Block has
produced approximately 1,600 bbl/d net to Canadian Natural, representing
less than 0.5% of Canadian Natural's total crude oil and NGLs production
year to date.
OFFSHORE WEST AFRICA
o During Q3/07, 1.2 net wells were drilled with 0.6 additional net wells
drilling at the end of the quarter.
o West Espoir commenced production in mid 2006. During Q3/07, 1 additional
production well and 1 additional injector were added. The West Espoir area
has seen favorable production growth and development drilling is
continuing into 2008 with producers and injectors being brought on-line as
they are completed.
o During Q3/07, in order to increase its throughput handling capability
Canadian Natural awarded a contract for the upgrade of the Espoir Floating
Production Storage and Offtake ("FPSO") vessel. Design and procurement
work commenced during the quarter, with installation of equipment on the
FPSO targeted to start in late 2009.
o A deep water drilling rig has been secured for the Baobab Field. The rig
is now targeted to be mobilized in Q1/08. The Company is targeting to
bring 3 of 5 of the shut-in Baobab wells back into production over the
course of 2008 and 2009.
o At the 90% owned and operated Olowi Field in offshore Gabon, all major
construction contracts have been awarded. The project is on schedule with
drilling targeted to commence in Q2/08 and first crude oil is targeted for
late 2008 or early 2009. Production is targeted to plateau at
approximately 20,000 bbl/d in Q4/09.
HORIZON PROJECT
o Canadian Natural achieved an overall work progress at the end of the
quarter at 84% complete and construction 76% complete. All major vessels
have either been erected or are currently on site. Work scheduled for the
coming months will continue to focus on mechanical construction, which is
scheduled to be completed through a combination of lump sum and
reimbursable contracts.
o The Horizon Project remains on track for targeted first oil in Q3/08.
Project progress achieved 9% progress despite the distraction of
Alberta-wide labour negotiations that occurred throughout the summer.
o Pre-commissioning work has been initiated in the area of Utilities and
Offsites and Bitumen Production, with hydro-testing targeted for
completion.
o Previous decisions to defer several contracts and delay certain projects
to capture cost reduction opportunities has caused overlap between some
construction projects on the site and has resulted in an increase in peak
project manpower requirements. Canadian Natural's supporting camp and
transportation infrastructure has been successfully expanded to
accommodate the higher peak in manpower to ensure workers are adequately
accommodated.
o As a result, some work has been pushed into the more challenging winter
months, resulting in a modest increase in the forecast completion cost for
the Horizon Project. The Company's current Horizon Project completion cost
forecast has been increased from the 5% to 12% range provided in the first
quarter 2007 Horizon Project Update to an 8% to 14% range over the
original $6.8 billion estimate.
CANADIAN NATURAL RESOURCES LIMITED 7
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o The quarterly update for Phase 1 of the Horizon Project is as follows:
PROJECT STATUS SUMMARY
JUNE 30, SEPTEMBER 30, DECEMBER 31,
2007 2007 2007
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ACTUAL ACTUAL ORIGINAL FORECAST ORIGINAL
PLAN PLAN
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Phase 1 - Work progress (cumulative) 75% 84% 88% 90% 94%
Phase 1 - Construction capital spending* (cumulative) 79% 89% 85% 99% 92%
*Relative to overall Phase 1 project capital of $6.8 billion
ACCOMPLISHED TO THE END OF THE THIRD QUARTER OF 2007
DETAILED ENGINEERING
o Overall detailed engineering 98% complete and substantially completed in
most areas.
PROCUREMENT
o Overall procurement progress is 98% complete.
o Have awarded over $5.5 billion in purchase orders and contracts to date.
o Delivered over 35,000 standard loads of all kinds to site.
o Operations and maintenance service and supply agreements are in
negotiation.
MODULARIZATION
o Delivered an additional 80 oversized loads to site for a total of 1,504
loads, which represents approximately 91% of the total requirement.
CONSTRUCTION
o Overall construction progress is 76% complete.
o Mine overburden removal has moved 43.8 million bank cubic meters, which
represents approximately 63% of the total to be moved and is slightly
ahead of schedule.
o Energized Main Electrical Substations.
o Completed construction of Raw Water Pond.
o Started pre-commissioning activities in Bitumen Production Areas.
o Froth tank completed and hydro-tested.
o Commenced extraction plant hydro-testing.
o Permanent power energized in R1/R2 corridors pumphouses.
o Started commissioning of Recycle Water Pond.
MILESTONES FOR THE FOURTH QUARTER OF 2007
o Complete the closure of Dyke 10 (external tailings pond) in Mining.
o Complete erection of Crushing Plants and conveyors in Ore Preparation
Area.
o Complete Primary Separation Cells in Extraction.
o Complete Main Control Room and Distributed Control Systems installation.
o Complete construction of Main Laboratory.
PLANT AND SYSTEM COMMISSIONING SCHEDULE
COMPLETED
o Permanent Potable Water Treatment
o Permanent Sewage Treatment
o Natural Gas Pipeline
o Raw and Recycled Water Pipelines
o River Water Intake and Pumphouse
8 CANADIAN NATURAL RESOURCES LIMITED
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Q4/07
o Raw Water Pond and Pumphouse
o Recycle Water Pond and Pumphouse
o Extraction
o Electrical Distribution System
Q1/08
o Cooling and Heating System
o Main Pipe Rack
Q2/08
o Cogeneration
o Ore Preparation Plant
o Froth Treatment
o Pipeline Corridors
o Hydrogen Plant
o Coker / Diluent Recovery Unit
o Gas Treating and Sulphur Recovery
o Synthetic crude oil pipeline
o Sulphur block pipelines
o West Tank Farm (inter-plant)
Q3/08
o Hydrotreating
o East Tank Farm (product)
OPERATIONS READINESS
o The Company expects to meet its hiring requirements by the end of the year
for the Operations group. Training programs are in place and, in
anticipation of turnover, Operations have commenced the review of systems
in certain plants.
MARKETING Three Months Ended Nine Months Ended
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SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
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Crude oil and NGLs pricing
WTI(1) benchmark price (US$/bbl) $ 75.33 $ 65.02 $ 70.55 $ 66.26 $ 68.29
Lloyd Blend Heavy oil differential from WTI (%) 30% 30% 27% 29% 32%
Corporate average pricing before risk
management (C$/bbl) $ 58.10 $ 53.74 $ 62.55 $ 54.57 $ 55.91
Natural gas pricing
AECO benchmark price (C$/GJ) $ 5.32 $ 6.99 $ 5.72 $ 6.46 $ 6.82
Corporate average pricing before risk
management (C$/mcf) $ 5.87 $ 7.44 $ 5.83 $ 7.03 $ 6.75
==========================================================================================================================
(1) REFERS TO WEST TEXAS INTERMEDIATE (WTI) CRUDE OIL BARREL PRICED AT
CUSHING, OKLAHOMA.
o In Q3/07, the Lloyd Blend heavy crude oil differential as a percent of WTI
was 30%, compared to 27% in Q3/06.
CANADIAN NATURAL RESOURCES LIMITED 9
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o Canadian Natural has committed to 25,000 bbl/d of pipeline capacity on the
Pegasus Pipeline which transports Company crude oil volumes to the U.S.
Gulf Coast as part of the Company's efforts towards working with various
industry groups to find new markets for Western Canadian heavy crude oil
and to ease the logistical constraints in getting crude oil to the area.
The pipeline reversal has had the impact of improving the corporate
realized price on Canadian Natural's heavy crude oil production. The heavy
crude oil sold to the Gulf Coast receives Mayan equivalent pricing, a
premium to the Lloyd Blend price. For Q3/07, the Mayan differential to WTI
averaged US$12.30/bbl or 16%.
o During Q3/07, the Company contributed approximately 134,000 bbl/d of its
heavy crude oil streams to the Western Canadian Select blend as market
conditions resulted in this strategy offering the optimal pricing for
bitumen.
o Natural gas inventories in North America continue to remain high in Q3/07
due to a significant increase in liquefied natural gas (LNG) imports to
the United States along with stable production levels in that country.
These factors contributed to depressed pricing for natural gas for North
America relative to WTI.
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 607,000 boe/d in Q3/07, comprised of approximately 45%
natural gas and 55% crude oil - with 95% of production located in G8
countries with stable and secure economies.
-- Financial stability and liquidity - cash flow from operations of
$4.7 billion for the first nine months of 2007, available unused
bank lines of $1.3 billion at September 30, 2007 and access to
capital debt markets supported by strong credit ratings.
-- Reduced volatility of commodity prices - a proactive commodity
hedging program to reduce the downside risk of volatility in
commodity prices supporting cash flow for its capital expenditure
program throughout the Horizon Project.
o In September 2007, the Company filed a short form prospectus that allows
for the issue of up to US$3.0 billion of debt securities in the United
States until October 2009. Simultaneously the Company filed a short form
shelf prospectus that allows for the issue of up to $3.0 billion of
medium-term notes in Canada until October 2009. If issued, these
securities will bear interest as determined at the date of issuance.
o Declared a quarterly cash dividend on common shares of C$0.085 per common
share, payable January 1, 2008, a 13% increase over the 2006 quarterly
dividend.
OUTLOOK
The Company forecasts 2007 production levels before royalties to average
between 1,664 and 1,676 mmcf/d of natural gas and between 326,000 and 334,000
bbl/d of crude oil and NGLs. Q4/07 production guidance before royalties is
forecast to average between 1,577 and 1,616 mmcf/d of natural gas and between
321,000 and 344,000 bbl/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/.
10 CANADIAN NATURAL RESOURCES LIMITED
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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") constitute
"forward-looking statements" within the meaning of the United States Private
Securities Litigation Reform Act of 1995. These forward-looking statements can
generally be identified as such because of the context of the statements
including words such as 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. Our domestic operations are subject to
governmental risks that may impact our operations. Our domestic operations have
been, and at times in the future may be affected by political developments and
by federal, provincial and local laws and regulations such as restrictions on
production, changes in taxes, royalties and other amounts payable to
governments or governmental agencies, price or gathering rate controls and
environmental protection regulations. 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.
Disclosure related to expected future commodity pricing, production volumes,
royalties, capital expenditures and other 2007 guidance provided throughout
this Management's Discussion and Analysis ("MD&A"), constitutes forward-looking
statements as described above.
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 11
===============================================================================
MANAGEMENT'S DISCUSSION AND ANALYSIS
Management's Discussion and Analysis of the financial condition and results of
operations of the Company should be read in conjunction with the unaudited
interim consolidated financial statements for the nine months ended September
30, 2007 and the MD&A and the audited consolidated financial statements for the
year ended December 31, 2006.
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 the nine and three months ended
September 30, 2006 have been reclassified to conform to the presentation
adopted in the fourth quarter of 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 wellhead.
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 nine and three months ended September 30, 2007 in relation to the
comparable periods in 2006 and the second quarter of 2007. The accompanying
tables form an integral part of this MD&A. This MD&A is dated October 30, 2007.
Additional information relating to the Company, including its Annual
Information Form for the year ended December 31, 2006, is available on SEDAR at
www.sedar.com.
12 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Nine Months Ended
------------- -------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 (1) 2007 2006 (1)
- -----------------------------------------------------------------------------------------------------------------------
Revenue, before royalties $ 3,073 $ 3,152 $ 3,108 $ 9,343 $ 8,817
Net earnings $ 700 $ 841 $ 1,116 $ 1,810 $ 2,211
Per common share - basic and diluted $ 1.30 $ 1.56 $ 2.08 $ 3.36 $ 4.12
Adjusted net earnings from operations (2) $ 644 $ 595 $ 470 $ 1,860 $ 1,252
Per common share - basic and diluted $ 1.19 $ 1.10 $ 0.87 $ 3.44 $ 2.33
Cash flow from operations (3) $ 1,577 $ 1,513 $ 1,313 $ 4,712 $ 3,639
Per common share - basic and diluted $ 2.92 $ 2.81 $ 2.44 $ 8.74 $ 6.77
Capital expenditures, net of dispositions $ 1,442 $ 1,460 $ 1,661 $ 4,911 $ 5,528
=======================================================================================================================
(1) BLENDING COSTS THAT WERE NETTED AGAINST GROSS REVENUES IN PRIOR PERIODS
HAVE BEEN RECLASSIFIED TO TRANSPORTATION EXPENSE TO CONFORM TO THE
PRESENTATION ADOPTED IN THE FOURTH QUARTER OF 2006.
(2) ADJUSTED NET EARNINGS FROM OPERATIONS IS A NON-GAAP MEASURE THAT
REPRESENTS NET EARNINGS ADJUSTED FOR CERTAIN ITEMS OF A NON-OPERATIONAL
NATURE. THE COMPANY EVALUATES ITS PERFORMANCE BASED ON ADJUSTED NET
EARNINGS FROM OPERATIONS. THIS 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.
(3) CASH FLOW FROM OPERATIONS IS A NON-GAAP MEASURE 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.
ADJUSTED NET EARNINGS FROM OPERATIONS
THREE MONTHS ENDED NINE MONTHS ENDED
------------ -------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
($ MILLIONS) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------------------------------------------------------
NET EARNINGS AS REPORTED $ 700 $ 841 $ 1,116 $ 1,810 $ 2,211
STOCK-BASED COMPENSATION EXPENSE (RECOVERY), NET OF TAX (A) 54 74 (92) 145 (25)
UNREALIZED RISK MANAGEMENT LOSS (GAIN), NET OF TAX (B) 57 (35) (496) 384 (508)
UNREALIZED FOREIGN EXCHANGE (GAIN) LOSS, NET OF TAX (C) (167) (214) 9 (408) (31)
EFFECT OF STATUTORY TAX RATE CHANGES ON FUTURE INCOME TAX
LIABILITIES (D) - (71) (67) (71) (395)
----------------------------------------------------------------------------------------------------------------------------
ADJUSTED NET EARNINGS FROM OPERATIONS $ 644 $ 595 $ 470 $ 1,860 $ 1,252
============================================================================================================================
(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 FLOW THROUGH NET EARNINGS OR
ARE CAPITALIZED TO THE HORIZON OIL SANDS PROJECT.
(B) DERIVATIVE FINANCIAL INSTRUMENTS ARE RECORDED AT FAIR VALUE ON THE
BALANCE SHEET, WITH CHANGES IN THE FAIR VALUE OF NON-DESIGNATED
HEDGES 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, OFFSET BY THE IMPACT OF CROSS CURRENCY SWAPS, 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 IN THE SECOND QUARTER OF 2007 RESULTED IN A
REDUCTION OF FUTURE INCOME TAX LIABILITIES OF APPROXIMATELY $71
MILLION IN NORTH AMERICA. INCOME TAX RATE CHANGES IN THE FIRST
QUARTER OF 2006 RESULTED IN AN INCREASE OF FUTURE INCOME TAX
LIABILITIES OF APPROXIMATELY $110 MILLION IN THE UK NORTH SEA. INCOME
TAX RATE CHANGES IN THE SECOND QUARTER OF 2006 RESULTED IN A
REDUCTION OF FUTURE INCOME TAX LIABILITIES OF APPROXIMATELY $438
MILLION IN NORTH AMERICA. INCOME TAX RATE CHANGES IN THE THIRD
QUARTER OF 2006 RESULTED IN A REDUCTION OF FUTURE INCOME LIABILITIES
OF APPROXIMATELY $67 MILLION IN COTE D'IVOIRE, OFFSHORE WEST AFRICA.
CANADIAN NATURAL RESOURCES LIMITED 13
===============================================================================
CASH FLOW FROM OPERATIONS
THREE MONTHS ENDED NINE MONTHS ENDED
------------ ------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
($ MILLIONS) 2007 2007 2006 2007 2006
-----------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 700 $ 841 $ 1,116 $ 1,810 $ 2,211
NON-CASH ITEMS:
DEPLETION, DEPRECIATION AND AMORTIZATION 715 720 589 2,144 1,667
ASSET RETIREMENT OBLIGATION ACCRETION 18 17 17 53 50
STOCK-BASED COMPENSATION EXPENSE (RECOVERY) 78 106 (135) 209 (37)
UNREALIZED RISK MANAGEMENT LOSS (GAIN) 76 (57) (754) 555 (772)
UNREALIZED FOREIGN EXCHANGE (GAIN) LOSS (195) (250) 11 (477) (37)
DEFERRED PETROLEUM REVENUE TAX EXPENSE (RECOVERY) 10 20 (4) 27 40
FUTURE INCOME TAX EXPENSE 175 116 473 391 $ 517
-----------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS $ 1,577 $ 1,513 $ 1,313 $ 4,712 3,639
=======================================================================================================================
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
For the nine months ended September 30, 2007, the Company reported net earnings
of $1,810 million compared to net earnings of $2,211 million for the nine
months ended September 30, 2006. Net earnings for the nine months ended
September 30, 2007 included unrealized after-tax expenses of $50 million
related to the effects of risk management activities, fluctuations in foreign
exchange rates, stock-based compensation expense and the impact of statutory
tax rate changes on future income tax liabilities, compared to net after-tax
income of $959 million for the nine months ended September 30, 2006. Excluding
these items, adjusted net earnings from operations for the nine months ended
September 30, 2007 increased to $1,860 million from $1,252 million for the nine
months ended September 30, 2006. The increase from the comparable period in
2006 was primarily due to increased sales volumes and decreased realized risk
management losses. These factors were partially offset by increased production
expense, increased depletion, depreciation and amortization expense, and the
impact of the strengthening of the Canadian dollar relative to the US dollar.
Net earnings in the third quarter of 2007 were $700 million compared to net
earnings of $1,116 million in the third quarter of 2006 and net earnings of
$841 million in the prior quarter. Net earnings in the third quarter of 2007
included unrealized after-tax income of $56 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 $646
million for the third quarter of 2006 and net after-tax income of $246 million
in the prior quarter. Excluding these items, adjusted net earnings from
operations in the third quarter of 2007 increased to $644 million from $470
million in the third quarter of 2006, and from $595 million in the prior
quarter. The increase in adjusted net earnings from the third quarter of 2006
was primarily due to the impact of increased sales volumes and decreased
realized risk management losses. These factors were partially offset by the
impact of the stronger Canadian dollar relative to the US dollar and increased
depletion, depreciation and amortization expense. The increase from the prior
quarter was primarily due to increased crude oil pricing, decreased production
costs and increased realized risk management gains on natural gas, partially
offset by decreased natural gas pricing and the impact of the stronger Canadian
dollar relative to the US dollar.
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 60% of expected crude oil volumes and natural gas volumes are
hedged for the remainder of 2007.
The Company's outstanding commodity related net financial derivatives as at
September 30, 2007 are detailed on page 41 of this MD&A.
14 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
As disclosed in note 2 to the Company's unaudited interim consolidated
financial statements, commencing January 1, 2007 all derivative financial
instruments are recognized at fair value on the consolidated balance sheet at
each balance sheet date. As effective as the Company's 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 change in the fair value of
the non-designated hedges is based on prevailing forward commodity prices in
effect at the end of each reporting period and is reflected in risk management
activities in consolidated net earnings. The cash settlement amount of the risk
management derivative financial instruments may vary materially depending upon
the underlying crude oil and natural gas prices at the time of final settlement
of the derivative financial instruments, as compared to their mark-to-market
value at September 30, 2007.
Due to the changes in crude oil and natural gas forward pricing and the
reversal of prior-period unrealized gains and losses, the Company recorded a
net unrealized loss of $555 million ($384 million after-tax) on its commodity
risk management activities for the nine months ended September 30, 2007,
including a $76 million ($57 million after-tax) unrealized loss for the three
months ended September 30, 2007. 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. For further details, refer to Risk
Management Activities on page 31 of this MD&A.
The Company also recorded a $209 million ($145 million after-tax) stock-based
compensation expense as a result of the 22% increase in the Company's share
price in the nine months ended September 30, 2007, and a $78 million ($54
million after-tax) stock-based compensation expense as a result of the 7%
increase in the Company's share price for the three months ended September 30,
2007 (Company's share price as at: September 30, 2007 - C$75.56; June 30, 2007
- - C$70.78; December 31, 2006 - C$62.15; September 30, 2006 - C$50.94). 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 net earnings, or capitalized
as part of the Horizon Project during the construction period. The stock-based
compensation liability at September 30, 2007 reflected the Company's potential
cash liability should all the vested options be surrendered for a cash payout
at the market price on September 30, 2007. 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 nine months ended September 30, 2007
increased to $4,712 million from $3,639 million for the nine months ended
September 30, 2006. The increase from the comparable period in 2006 was
primarily due to increased sales volumes and decreased realized risk management
losses, offset by increased production expense, higher cash taxes and the
impact of the strengthening of the Canadian dollar relative to the US dollar.
Cash flow from operations for the third quarter of 2007 increased to $1,577
million from $1,313 million for the third quarter of 2006, and from $1,513
million in the prior quarter. The increase from the third quarter of 2006 was
primarily due to the impact of increased sales volumes and decreased realized
risk management losses, partially offset by the impact of the stronger Canadian
dollar relative to the US dollar. The increase from the prior quarter was
primarily due to increased crude oil pricing, lower production costs and
increased realized risk management gains on natural gas, partially offset by
decreased natural gas production and pricing, higher cash taxes and the impact
of the stronger Canadian dollar relative to the US dollar.
Total production before royalties increased 7% to average 611,665 boe/d for the
nine months ended September 30, 2007 from 569,590 boe/d for the nine months
ended September 30, 2006. Production for the third quarter of 2007 increased 8%
to 607,484 boe/d from 561,152 boe/d in the third quarter of 2006 and decreased
1% from 614,461 boe/d for the prior quarter.
CANADIAN NATURAL RESOURCES LIMITED 15
===============================================================================
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the eight
most recently completed quarters:
($ millions, except per common share amounts) SEP 30 Jun 30 Mar 31 Dec 31
2007 2007 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
Revenue, before royalties $ 3,073 $ 3,152 $ 3,118 $ 2,826
Net earnings $ 700 $ 841 $ 269 $ 313
Net earnings per common share
- Basic and diluted $ 1.30 $ 1.56 $ 0.50 $ 0.58
==========================================================================================================================
Sep 30 Jun 30 Mar 31 Dec 31
($ millions, except per common share amounts) 2006 2006 2006 2005
- --------------------------------------------------------------------------------------------------------------------------
Revenue, before royalties (1) $ 3,108 $ 3,041 $ 2,668 $ 3,319
Net earnings $ 1,116 $ 1,038 $ 57 $ 1,104
Net earnings per common share
- Basic and diluted $ 2.08 $ 1.93 $ 0.11 $ 2.06
==========================================================================================================================
(1) BLENDING COSTS THAT WERE NETTED AGAINST GROSS REVENUES IN PRIOR PERIODS
HAVE BEEN RECLASSIFIED TO TRANSPORTATION EXPENSE TO CONFORM TO THE
PRESENTATION ADOPTED IN THE FOURTH QUARTER OF 2006.
Net earnings over the eight most recently completed quarters generally
reflected fluctuations in realized crude oil and natural gas prices, increased
sales volumes, the impact of mark-to-market accounting of financial instruments
and adjustments to future income tax liabilities due to jurisdictional tax rate
changes. More specifically, volatility in quarterly net earnings was primarily
due to:
o Crude oil pricing Crude oil prices reflected demand growth, continued
geopolitical uncertainties and fluctuations in the Heavy Crude Oil
Differential from WTI ("Heavy Differential") in North America.
o Natural gas pricing Natural gas prices primarily reflected fluctuations in
demand for natural gas and high inventory storage levels as a result of
milder temperatures experienced during 2007 and 2006.
o Crude oil and NGLs sales volumes Crude oil and NGLs sales volumes
primarily reflected increased production from the Company's Primrose
thermal projects, the positive results from the Pelican Lake water and
polymer flood projects, and additional sales volumes from the Anadarko
Canada Corporation ("ACC") acquisition completed in the fourth quarter of
2006.
o Natural gas sales volumes Natural gas sales volumes reflected additional
natural gas volumes as a result of the ACC acquisition and internally
generated growth. The increase was partially offset by production declines
due to the Company's strategic reduction in natural gas drilling activity.
o Foreign exchange rates A general strengthening of the Canadian dollar
relative to the US dollar has decreased the realized price the Company
received for its crude oil and natural gas sales, as sales prices are
based predominately on US dollar denominated benchmarks. Similarly,
unrealized foreign exchange gains and losses were recorded with respect to
US dollar denominated debt balances, UK pounds sterling denominated
working capital balances, and the re-measurement of North Sea future
income tax liabilities denominated in UK pounds sterling to US dollars.
o Commodity and cross currency hedges Net earnings have fluctuated due to
the recognition of realized and unrealized gains and losses from the
mark-to-market of the Company's commodity and cross currency hedges.
16 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
o Changes in tax rates Income tax expense and recovery fluctuations include
jurisdictional tax rate changes substantively enacted in the various
periods.
o Stock-based compensation Net earnings have fluctuated due to the
recognition of realized and unrealized expenses and recoveries from the
mark-to-market of the Company's stock-based compensation liability. The
liability reflected a general increase in the Company's share price over
the eight most recently completed quarters.
o Production expense Production expense has increased primarily due to
industry-wide inflationary cost pressures.
o Depletion, depreciation and amortization Depletion, depreciation and
amortization expense has increased primarily due to overall increases in
finding and development costs associated with crude oil and natural gas
exploration, a higher depletion base related to the ACC acquisition, and
increased estimated future costs to develop the Company's proved
undeveloped reserves, together with the impact of higher sales volumes.
OPERATING HIGHLIGHTS
Three Months Ended Nine Months Ended
------------ ------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
Sales price (2) $ 58.10 $ 53.74 $ 62.55 $ 54.57 $ 55.91
Royalties 6.65 5.46 5.11 5.69 4.61
Production expense 13.13 15.01 13.47 13.97 12.29
- -------------------------------------------------------------------------------------------------------------------
Netback $ 38.32 $ 33.27 $ 43.97 $ 34.91 $ 39.01
- -------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 5.87 $ 7.44 $ 5.83 $ 7.03 $ 6.75
Royalties 0.89 1.10 1.11 1.16 1.31
Production expense 0.88 0.89 0.84 0.91 0.81
- -------------------------------------------------------------------------------------------------------------------
Netback $ 4.10 $ 5.45 $ 3.88 $ 4.96 $ 4.63
- -------------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent ($/boe) (1)
Sales price (2) $ 47.96 $ 49.70 $ 51.21 $ 48.99 $ 49.38
Royalties 6.07 5.99 5.75 6.27 5.99
Production expense 9.62 10.44 10.01 10.05 9.13
- -------------------------------------------------------------------------------------------------------------------
Netback $ 32.27 $ 33.27 $ 35.45 $ 32.67 $ 34.26
===================================================================================================================
(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 17
===============================================================================
BUSINESS ENVIRONMENT
Three Months Ended Nine Months Ended
----------- ------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- ---------------------------------------------------------------------------------------------------------------------
WTI benchmark price (US$/bbl) $ 75.33 $ 65.02 $ 70.55 $ 66.26 $ 68.29
Dated Brent benchmark price (US$/bbl) $ 74.85 $ 68.74 $ 69.58 $ 67.18 $ 67.03
Differential to LLB blend (US$/bbl) $ 22.69 $ 19.42 $ 19.08 $ 19.33 $ 21.82
LLB blend differential from WTI (%) 30% 30% 27% 29% 32%
Condensate benchmark price (US$/bbl) $ 75.93 $ 65.66 $ 70.26 $ 66.82 $ 68.49
NYMEX benchmark price (US$/mmbtu) $ 6.13 $ 7.56 $ 6.52 $ 6.88 $ 7.47
AECO benchmark price (C$/GJ) $ 5.32 $ 6.99 $ 5.72 $ 6.46 $ 6.82
US / Cdn dollar average exchange rate (US$) $ 0.9565 $ 0.9112 $ 0.8919 $ 0.9045 $ 0.8830
=====================================================================================================================
COMMODITY PRICES
Crude oil sales contracts in the North America segment are typically based on
WTI benchmark pricing. WTI averaged US$66.26 per bbl for the nine months ended
September 30, 2007, a decrease of 3% from US$68.29 per bbl for the nine months
ended September 30, 2006. In the third quarter of 2007, WTI averaged US$75.33
per bbl, an increase of 7% from US$70.55 per bbl in the third quarter of 2006,
and an increase of 16% from US$65.02 per bbl in the prior quarter. Increases in
WTI pricing in the third quarter reflected continued strong demand for crude
oil and continued geopolitical events causing market uncertainty and price
volatility. The WTI reference price, in relation to other world benchmark crude
oils, also benefited from the easing of logistical constraints experienced
during the second quarter, particularly at Cushing, Oklahoma.
Crude oil sales contracts for the Company's North Sea and Offshore West Africa
segments are typically based on Brent pricing, which continued to benefit from
strong European and Asian demand in the third quarter of 2007. Dated Brent
("Brent") averaged US$67.18 per bbl for the nine months ended September 30,
2007, comparable to US$67.03 per bbl for the nine months ended September 30,
2006. In the third quarter of 2007, Brent averaged US$74.85 per bbl, an
increase of 8% compared to US$69.58 per bbl for the third quarter of 2006, and
an increase of 9% from US$68.74 per bbl for the prior quarter. As noted above,
the differential between Brent and WTI returned to more historical levels as
logistical constraints at Cushing, Oklahoma eased during the third quarter.
Company-wide, realized crude oil prices for the nine months ended September 30,
2007 decreased slightly as a result of lower benchmark WTI pricing, partially
offset by a narrower Heavy Differential in North America. The Heavy
Differential averaged 29% for the nine months ended September 30, 2007 compared
to 32% for the nine months ended September 30, 2006. For the third quarter of
2007, the Heavy Differential averaged 30% compared to 27% for the third quarter
of 2006. The widening of the Heavy Differential from the comparable period in
2006 was primarily due to increased heavy crude oil production from Western
Canada and reduced demand from US Midwest refineries due to maintenance and
unplanned shut-downs. In the third quarter, 2007 realized prices continued to
be impacted by the stronger Canadian dollar as Company realized prices are
based on US dollar denominated benchmarks.
The Company anticipates continued volatility in the crude oil pricing
benchmarks due to the unpredictable nature of geopolitical events and potential
unplanned refinery outages. The Heavy Differential is expected to continue to
reflect seasonal demand fluctuations.
NYMEX natural gas prices averaged US$6.88 per mmbtu for the nine months ended
September 30, 2007, a decrease of 8% from US$7.47 per mmbtu for the nine months
ended September 30, 2006. In the third quarter of 2007, the NYMEX natural gas
price averaged US$6.13 per mmbtu, a decrease of 6% from US$6.52 per mmbtu for
the third quarter of 2006, and a decrease of 19% from US$7.56 per mmbtu for the
prior quarter. AECO natural gas prices decreased 5% to average $6.46 per GJ for
the nine months ended September 30, 2007, compared to $6.82 per GJ for the nine
months ended September 30, 2006. In the third quarter of 2007 AECO natural gas
prices averaged $5.32 per GJ, a decrease of 7% from $5.72 per GJ in the third
quarter of 2006, and a decrease of 24% from $6.99 per GJ for the prior quarter.
Fluctuations in natural gas prices from the comparable periods in 2006 were
primarily related to weather
18 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
and storage levels. Natural gas inventory levels in North America continued to
remain high in the third quarter of 2007 due to the significant increase in
liquefied natural gas imports into the US and stable production levels in the
US, offset by production declines in Canada due to reduced drilling activity.
OPERATING, ROYALTY 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 crude oil and natural
gas industry, particularly related to drilling activities and oil sands
developments. The strong commodity price environment has also impacted costs in
international basins, specifically the high demand for offshore drilling rigs.
The crude oil and natural gas industry is also experiencing cost pressures
related to environmental regulations, both in North America and
internationally. In Canada, the Federal government is drafting policy and
legislation to control greenhouse gas emissions. In Alberta, provincial
regulations came into effect July 1, 2007, while in the UK greenhouse gas
regulations have been in effect since 2005. The Company has processes in place
to comply with the regulations. The additional requirements of greenhouse gas
legislation will add to the cost of executing projects company wide.
Continued cost pressures and the final outcome of changes to environmental
regulations may adversely impact the Company's future net earnings, cash flow
and capital projects. Further, on October 25, 2007, the Province of Alberta
issued the details of its proposed changes to the Alberta crude oil and natural
gas royalty regime, effective January 1, 2009. These proposed changes include:
o The implementation of a sliding scale for oil sands royalties ranging from
1% to 9% on a gross basis pre-payout and 25% to 40% on a net basis
post-payout depending on benchmark crude oil pricing; and
o New royalty formulas for conventional crude oil and natural gas that are
to operate on sliding scales ranging up to 50% determined by commodity
prices and well productivity.
The Company expects that its 2009 and future Alberta royalty payments will
increase as a result of the proposed royalty regime changes and that its level
of activity in Alberta will be reduced from what it otherwise would have been
in the absence of such royalty changes. In the current pricing and cost
environment, the biggest reduction in the Company's Alberta activity will be
experienced in the conventional natural gas business. The number of natural gas
wells to be drilled in Alberta by the Company in 2008 and years beyond will be
approximately 30% to 50% less than the number of such wells that would have
otherwise been drilled in the absence of such royalty changes.
CANADIAN NATURAL RESOURCES LIMITED 19
===============================================================================
PRODUCT PRICES (1)
Three Months Ended Nine Months Ended
------------- -------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (2)
North America $ 52.47 $ 47.20 $ 55.97 $ 48.68 $ 48.82
North Sea $ 77.55 $ 73.18 $ 78.68 $ 72.86 $ 74.09
Offshore West Africa $ 70.52 $ 72.84 $ 70.59 $ 67.37 $ 69.58
Company average $ 58.10 $ 53.74 $ 62.55 $ 54.57 $ 55.91
NATURAL GAS ($/mcf) (2)
North America $ 5.88 $ 7.47 $ 5.86 $ 7.05 $ 6.81
North Sea $ 5.26 $ 3.92 $ 2.38 $ 4.47 $ 2.36
Offshore West Africa $ 5.31 $ 6.22 $ 4.97 $ 5.76 $ 5.27
Company average $ 5.87 $ 7.44 $ 5.83 $ 7.03 $ 6.75
COMPANY AVERAGE ($/boe)(2) $ 47.96 $ 49.70 $ 51.21 $ 48.99 $ 49.38
PERCENTAGE OF REVENUE
(excluding midstream revenue)
Crude oil and NGLs 67% 57% 72% 60% 65%
Natural gas 33% 43% 28% 40% 35%
================================================================================================================
(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.
The Company's realized crude oil prices decreased to average $54.57 per bbl for
the nine months ended September 30, 2007 from $55.91 per bbl for the nine
months ended September 30, 2006. Realized crude oil prices for the third
quarter of 2007 decreased 7% to average $58.10 per bbl from $62.55 per bbl for
the third quarter of 2006, and increased 8% from $53.74 per bbl for the prior
quarter. The Company's realized crude oil prices decreased slightly from the
nine months ended September 30, 2006 as a result of the stronger Canadian
dollar and lower benchmark WTI pricing, partially offset by a narrower Heavy
Differential in North America. The increase from the prior quarter primarily
reflected higher WTI benchmark pricing.
The Company's realized natural gas price increased 4% to average $7.03 per mcf
for the nine months ended September 30, 2007 from $6.75 per mcf for the nine
months ended September 30, 2006. In the third quarter of 2007, the Company's
realized natural gas price increased slightly to average $5.87 per mcf from
$5.83 per mcf in the third quarter of 2006, and decreased 21% from $7.44 per
mcf for the prior quarter. Fluctuations in natural gas prices from the
comparable periods in 2006 and the second quarter of 2007 were primarily
related to weather and storage levels.
NORTH AMERICA
North America realized crude oil prices decreased slightly to average $48.68
per bbl for the nine months ended September 30, 2007 from $48.82 per bbl for
the nine months ended September 30, 2006. Realized crude oil prices in the
third quarter of 2007 averaged $52.47 per bbl, a 6% decrease from $55.97 per
bbl for the third quarter of 2006, and increased 11% from $47.20 per bbl for
the prior quarter. The decrease in realized crude oil prices from the third
quarter of 2006 was due to the stronger Canadian dollar and the widening of the
Heavy Differential, partially offset by the increase in WTI benchmark price,
while the increase from the prior quarter was due to the increase in WTI
benchmark pricing, partially offset by the widening Heavy Differential and the
stronger Canadian dollar relative to the US dollar.
20 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
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
third quarter, the Company contributed approximately 134,000 bbl/d of heavy
crude oil blends to the Western Canadian Select stream.
North America realized natural gas prices increased 4% to average $7.05 per mcf
for the nine months ended September 30, 2007 from $6.81 per mcf for the nine
months ended September 30, 2006. The realized natural gas price in the third
quarter of 2007 averaged $5.88 per mcf, comparable to $5.86 per mcf for the
third quarter of 2006, and a 21% decrease from $7.47 per mcf for the prior
quarter. Fluctuations in natural gas prices from the comparable periods in 2006
and the second quarter of 2007 were primarily related to the impact of weather
and storage levels.
A comparison of the price received for the Company's North America production
by product type is as follows:
Three Months Ended
---------------
SEP 30 Jun 30 Sep 30
2007 2007 2006
- ---------------------------------------------------------------------------------------------------------
Wellhead Price (1) (2)
Light / medium crude oil and NGLs (C$/bbl) $ 67.55 $ 63.09 $ 72.25
Pelican Lake crude oil (C$/bbl) $ 48.91 $ 44.49 $ 53.84
Primary heavy crude oil (C$/bbl) $ 47.47 $ 42.30 $ 52.15
Thermal heavy crude oil (C$/bbl) $ 48.99 $ 41.09 $ 50.36
Natural gas (C$/mcf) $ 5.88 $ 7.47 $ 5.86
=========================================================================================================
(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 decreased marginally to average $72.86 per
bbl for the nine months ended September 30, 2007 from $74.09 per bbl for the
nine months ended September 30, 2006. Realized crude oil prices in the third
quarter of 2007 averaged $77.55 per bbl, a slight decrease from $78.68 per bbl
in the third quarter of 2006, and increased 6% from $73.18 per bbl for the
prior quarter. Realized crude oil prices in the North Sea during the third
quarter continued to benefit from the impact of strong European and Asian
demand, partially offset by the impact of the stronger Canadian dollar relative
to the US dollar.
OFFSHORE WEST AFRICA
Offshore West Africa realized crude oil prices decreased 3% to average $67.37
per bbl for the nine months ended September 30, 2007 from $69.58 per bbl for
the nine months ended September 30, 2006. Realized crude oil prices in the
third quarter of 2007 averaged $70.52 per bbl, comparable to $70.59 per bbl for
the third quarter of 2006, and decreased 3% from $72.84 per bbl for the prior
quarter. As all revenue in Offshore West Africa is currently recognized on a
liftings basis, realized crude oil prices per barrel in any particular quarter
are dependant on the frequency and timing of liftings, as well as the terms of
the related sales contracts. Realized crude oil prices in Offshore West Africa
during the third quarter continued to benefit from the impact of strong
European and Asian demand, offset by the impact of the stronger Canadian dollar
relative to the US dollar.
CANADIAN NATURAL RESOURCES LIMITED 21
===============================================================================
CRUDE OIL INVENTORY VOLUMES
The Company recognizes revenue on its crude oil production when title transfers
to the customer and delivery has taken place. The related crude oil inventory
volumes by segment, which have not been recognized in revenue, were as follows:
---------------
(bbl) SEP 30 2007 Jun 30 Dec 31
2007 2006
- --------------------------------------------------------------------------------------------------------------------
North America, related to pipeline fill 1,097,526 1,097,526 1,097,526
North Sea, related to timing of liftings 260,648 350,499 910,796
Offshore West Africa, related to timing of liftings 587,486 813,701 113,774
- --------------------------------------------------------------------------------------------------------------------
1,945,660 2,261,726 2,122,096
====================================================================================================================
In the third quarter of 2007, additional net sales of approximately 316,000
barrels of crude oil produced in the Company's international operations, which
were deferred and included in inventory at June 30, 2007, were sold in the
third quarter, increasing cash flow from operations by approximately $19
million.
DAILY PRODUCTION, BEFORE ROYALTIES
Three Months Ended Nine Months Ended
------------ ------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 252,095 240,420 233,440 243,388 230,430
North Sea 52,013 57,286 53,988 57,020 59,473
Offshore West Africa 28,954 29,788 34,237 28,800 38,150
- --------------------------------------------------------------------------------------------------------------------
333,062 327,494 321,665 329,208 328,053
- --------------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,622 1,696 1,416 1,670 1,425
North Sea 10 15 11 13 15
Offshore West Africa 15 11 10 12 9
- --------------------------------------------------------------------------------------------------------------------
1,647 1,722 1,437 1,695 1,449
- --------------------------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d) 607,484 614,461 561,152 611,665 569,590
- --------------------------------------------------------------------------------------------------------------------
PRODUCT MIX
Light/medium crude oil and NGLs 22% 23% 24% 23% 26%
Pelican Lake crude oil 6% 6% 5% 6% 5%
Primary heavy crude oil 16% 15% 16% 15% 16%
Thermal heavy crude oil 11% 9% 12% 10% 11%
Natural gas 45% 47% 43% 46% 42%
====================================================================================================================
22 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
DAILY PRODUCTION, NET OF ROYALTIES
Three Months Ended Nine Months Ended
------------ -----------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 213,680 206,927 205,087 208,370 201,214
North Sea 51,917 57,185 53,911 56,916 59,361
Offshore West Africa 26,158 26,876 31,864 26,311 36,693
- ----------------------------------------------------------------------------------------------------------------
291,755 290,988 290,862 291,597 297,268
- ----------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,373 1,444 1,144 1,395 1,149
North Sea 10 15 11 13 15
Offshore West Africa 14 10 9 11 9
- ----------------------------------------------------------------------------------------------------------------
1,397 1,469 1,164 1,419 1,173
- ----------------------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d) 524,417 535,789 484,872 527,982 492,759
================================================================================================================
Daily production and per barrel statistics are presented throughout this MD&A
on a "before royalty" or "gross" basis. Production on an "after royalty" or
"net" basis is also presented.
The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces; namely
natural gas, light/medium crude oil and NGLs, Pelican Lake crude oil, primary
heavy crude oil and thermal heavy crude oil.
Total production averaged 611,665 boe/d for the nine months ended September 30,
2007, a 7% increase from the nine months ended September 30, 2006. Third
quarter total production in 2007 averaged 607,484 boe/d, an increase of 8% from
561,152 boe/d for the third quarter of 2006, and a decrease of 1% from 614,461
boe/d for the prior quarter.
Total crude oil and NGLs production for the nine months ended September 30,
2007 increased marginally to 329,208 bbl/d from 328,053 bbl/d for the nine
months ended September 30, 2006. In the third quarter of 2007, production
increased 4% to 333,062 bbl/d from 321,665 bbl/d in the third quarter of 2006
and increased 2% from 327,494 bbl/d for the prior quarter. The increase from
the comparable periods of 2006 was primarily due to increased production in
North America, partially offset by lower production in the North Sea due to the
timing of planned maintenance activities and reduced production from the Baobab
Field in Offshore West Africa. Crude oil and NGLs production in the third
quarter of 2007 was within the Company's previously issued guidance of 331,000
to 349,000 bbl/d.
Natural gas production continued to represent the Company's largest product
offering in 2007, accounting for 46% of the Company's total production. Natural
gas production for the nine months ended September 30, 2007 averaged 1,695
mmcf/d compared to 1,449 mmcf/d for the nine months ended September 30, 2006.
In the third quarter of 2007, natural gas production averaged 1,647 mmcf/d
compared to 1,437 mmcf/d for the third quarter of 2006 and 1,722 mmcf/d for the
prior quarter. Natural gas production generally reflects peak production levels
in the spring of each year due to a higher proportion of wells drilled during
the winter months, followed by natural production declines throughout the
remainder of the year. These declines are partially offset by lower
productivity, shallower natural gas drilling in the summer months. The increase
in natural gas production from the comparable periods in 2006 primarily
reflected the ACC acquisition completed in the fourth quarter of 2006,
partially offset by production declines due to the Company's strategic
reduction in natural gas drilling activity. Third quarter natural gas
production was within the Company's previously issued guidance of 1,632 to
1,669 mmcf/d.
Annual revised production guidance for 2007 is targeted to average between
326,000 and 334,000 bbl/d of crude oil and NGLs and between 1,664 and 1,676
mmcf/d of natural gas. Fourth quarter 2007 production guidance is targeted to
average between 321,000 and 344,000 bbl/d of crude oil and NGLs and between
1,577 and 1,616 mmcf/d of natural gas.
CANADIAN NATURAL RESOURCES LIMITED 23
===============================================================================
NORTH AMERICA
North America crude oil and NGLs production for the nine months ended September
30, 2007 increased 6% to average 243,388 bbl/d, up from 230,430 bbl/d for the
nine months ended September 30, 2006. Production in the third quarter of 2007
increased 8% to average 252,095 bbl/d from 233,440 bbl/d for the third quarter
of 2006, and increased 5% from 240,420 bbl/d for the prior quarter. The
increase in crude oil and NGLs production from the prior periods was primarily
due to the positive results from the Pelican Lake project, the cyclic nature of
the Company's thermal production and the ACC acquisition.
North America natural gas production increased 17% to average 1,670 mmcf/d for
the nine months ended September 30, 2007, up from 1,425 mmcf/d for the nine
months ended September 30, 2006. In the third quarter of 2007, natural gas
production increased 15% to 1,622 mmcf/d from 1,416 mmcf/d for the third
quarter of 2006, and decreased 4% from 1,696 mmcf/d for the prior quarter. The
increase in natural gas production from the comparable periods in 2006
reflected the impact of the ACC acquisition, partially offset by production
declines in 2007 due to the Company's strategic decision to reduce natural gas
drilling activity.
NORTH SEA
North Sea crude oil production averaged 57,020 bbl/d for the nine months ended
September 30, 2007, a decrease of 4% from 59,473 bbl/d for the nine months
ended September 30, 2006. Crude oil production in the third quarter of 2007
decreased 4% to 52,013 bbl/d from 53,988 bbl/d for the third quarter of 2006
and decreased 9% from 57,286 bbl/d for the prior quarter. Production levels for
the third quarter of 2007 were in line with expectations, with the decrease
from the prior quarter primarily related to the planned maintenance shutdowns
carried out during the quarter at Ninian, T-Block, and B-Block.
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production decreased 25% to average 28,800 bbl/d
for the nine months ended September 30, 2007 from 38,150 bbl/d for the nine
months ended September 30, 2006. Third quarter 2007 production decreased 15% to
28,954 bbl/d from 34,237 bbl/d for the third quarter of 2006, and decreased 3%
from 29,788 bbl/d for the prior quarter. Production decreased from the
comparable periods in 2006 due to continued challenges with sand and solids
production at the Baobab Field where 5 production wells remain shut in. The
Company has secured a deepwater rig, now targeted in 2008, that should enable
the Company to execute its plan to return certain of the shut-in wells to
production over the course of 2008 and 2009.
24 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
ROYALTIES
Three Months Ended Nine Months Ended
------------ --------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 8.00 $ 6.58 $ 6.79 $ 7.02 $ 6.13
North Sea $ 0.14 $ 0.13 $ 0.11 $ 0.13 $ 0.13
Offshore West Africa $ 6.81 $ 7.12 $ 4.89 $ 5.90 $ 2.74
Company average $ 6.65 $ 5.46 $ 5.11 $ 5.69 $ 4.61
NATURAL GAS ($/mcf) (1)
North America $ 0.90 $ 1.11 $ 1.12 $ 1.17 $ 1.34
North Sea $ - $ - $ - $ - $ -
Offshore West Africa $ 0.51 $ 0.59 $ 0.34 $ 0.50 $ 0.21
Company average $ 0.89 $ 1.10 $ 1.11 $ 1.16 $ 1.31
COMPANY AVERAGE ($/boe) (1) $ 6.07 $ 5.99 $ 5.75 $ 6.27 $ 5.99
PERCENTAGE OF REVENUE (2)
Crude oil and NGLs 11% 10% 8% 10% 8%
Natural gas 15% 15% 19% 16% 19%
Boe 13% 12% 11% 13% 12%
==================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
CANADIAN NATURAL RESOURCES LIMITED 25
===============================================================================
NORTH AMERICA
North America crude oil and NGLs royalties per bbl for the nine months ended
September 30, 2007 continue to reflect strong 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 revenue to
25% of revenue less operating, capital and abandonment costs. Crude oil and
NGLs royalties averaged approximately 15% of revenues for the nine months ended
September 30, 2007, compared to 13% in 2006. Crude oil and NGLs royalties per
bbl are anticipated to average approximately 14% to 16% of revenues for the
year.
Natural gas royalties per mcf generally fluctuate with natural gas prices.
Natural gas royalties averaged approximately 15% of revenues in the third
quarter of 2007 compared to 19% for the third quarter of 2006 and 15% for the
prior quarter. Natural gas royalties decreased in the second and third quarter
of 2007 compared to prior periods in 2006 due to the impact of certain
adjustments, and are anticipated to average approximately 17% to 20% of
revenues for the year.
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 oil and profit oil. Cost recovery oil allows the Company to
recover its capital and production costs and the costs carried by the Company
on behalf of the Government State Oil Company. Profit oil is allocated to the
joint venture partners in accordance with their respective equity interests,
after a portion has been allocated to the Government. These combined revenues
are reported as sales revenue. The Government's share of profit oil
attributable to the Company's equity interest is allocated to royalty expense
and current income tax expense in accordance with the PSCs. The Company's
capital investments in the Espoir Fields were fully recovered in the first
quarter of 2007, increasing royalty rates and current income taxes in
accordance with the PSCs.
Royalty rates as a percentage of revenue averaged approximately 10% for the
third quarter of 2007 compared to 7% for third quarter of 2006 and 10% for the
prior quarter. The increase in royalty rates from the comparable period in 2006
was due to the Company's full recovery of its capital investment in the Espoir
Field in 2007 and the resulting increase in profit oil on which the
Government's entitlement is based. Offshore West Africa royalty rates are
anticipated to average approximately 8% to 10% of revenues for the year.
26 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
PRODUCTION EXPENSE
Three Months Ended Nine Months Ended
------------ -------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 11.69 $ 13.98 $ 12.05 $ 12.87 $ 11.58
North Sea $ 23.61 $ 22.11 $ 20.28 $ 21.23 $ 18.41
Offshore West Africa $ 7.00 $ 7.98 $ 7.97 $ 7.90 $ 6.53
Company average $ 13.13 $ 15.01 $ 13.47 $ 13.97 $ 12.29
NATURAL GAS ($/mcf) (1)
North America $ 0.87 $ 0.87 $ 0.83 $ 0.90 $ 0.80
North Sea $ 2.29 $ 2.26 $ 1.30 $ 2.39 $ 1.35
Offshore West Africa $ 1.39 $ 1.10 $ 1.39 $ 1.32 $ 0.92
Company average $ 0.88 $ 0.89 $ 0.84 $ 0.91 $ 0.81
COMPANY AVERAGE ($/boe) (1) $ 9.62 $ 10.44 $ 10.01 $ 10.05 $ 9.13
===================================================================================================================
(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 nine months ended
September 30, 2007 increased to $12.87 per bbl from $11.58 per bbl for the nine
months ended September 30, 2006. In the third quarter of 2007 production costs
decreased to $11.69 per bbl from $12.05 per bbl for the third quarter of 2006
and from $13.98 per bbl for the prior quarter. Third quarter production expense
per barrel primarily reflects stabilization of industry-wide cost pressures,
lower cost of natural gas for fuel for the Company's thermal operations, and
higher production volumes in Pelican and thermal production areas, where a
large portion of costs are fixed in nature.
North America natural gas production expense per mcf in 2007 increased over the
comparable periods in 2006 primarily due to industry-wide cost pressures in
2006 and early 2007. Third quarter production expense was comparable to the
prior quarter as natural gas well servicing costs in Canada began to stabilize
in the second and third quarters due to decreased industry activity.
NORTH SEA
North Sea crude oil production expense varied on a per barrel basis from the
comparable periods due to planned maintenance shutdowns, varying production
volumes on a relatively fixed cost base and the timing of liftings from various
fields.
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production expense on a per barrel basis varied
from the comparable periods primarily due to the impact of continuing operating
challenges with sand and solids at Baobab, resulting in decreased production
volumes on a relatively fixed operating cost base, and the timing of
maintenance efforts.
CANADIAN NATURAL RESOURCES LIMITED 27
===============================================================================
MIDSTREAM
Three Months Ended Nine Months Ended
------------ --------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions) 2007 2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------
Revenue $ 19 $ 17 $ 19 $ 55 $ 54
Production expense 5 5 6 16 17
- ----------------------------------------------------------------------------------------------------------------
Midstream cash flow 14 12 13 39 37
Depreciation 2 2 2 6 6
- ----------------------------------------------------------------------------------------------------------------
Segment earnings before taxes $ 12 $ 10 $ 11 $ 33 $ 31
================================================================================================================
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 Nine Months Ended
-------------- --------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------
Expense ($ millions) $ 713 $ 718 $ 587 $ 2,138 $ 1,661
$/boe (2) $ 12.68 $ 12.95 $ 10.89 $ 12.79 $ 10.71
==================================================================================================================
(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 nine and three months
ended September 30, 2007 increased in total and on a boe basis from the
comparable periods in 2006 and was consistent with the prior quarter. The
increase in DD&A expense from the prior year was primarily due to overall
increases in finding and development costs associated with crude oil and
natural gas exploration, a higher depletion base related to the ACC
acquisition, and increased estimated future costs to develop the Company's
proved undeveloped reserves, together with the impact of higher sales volumes.
ASSET RETIREMENT OBLIGATION ACCRETION
Three Months Ended Nine Months Ended
------------ ------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------
Expense ($ millions) $ 18 $ 17 $ 17 $ 53 $ 50
$/boe (1) $ 0.32 $ 0.30 $ 0.31 $ 0.32 $ 0.32
================================================================================================================
(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 third quarter of 2007 was consistent with the comparable
periods.
28 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
ADMINISTRATION EXPENSE
Three Months Ended Nine Months Ended
----------- -------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- ---------------------------------------------------------------------------------------------------------------
Net expense ($ millions) $ 53 $ 53 $ 41 $ 166 $ 123
$/boe (1) $ 0.94 $ 0.96 $ 0.76 $ 0.99 $ 0.79
===============================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARES VOLUMES.
Administration expense for the nine and thre September 30, 2007 increased in
total and on a boe basis fable periods in 2006 primarily due to increased
staffing coscosts related to the Company's share bonus program. Administrwas
consistent with the prior quarter in 2007.
STOCK-BASED COMPENSATION EXPENSE (RECOVERY)
Three Months Ended Nine Months Ended
----------- -----------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions) 2007 2007 2006 2007 2006
- ---------------------------------------------------------------------------------------------------------------
Stock option plan expense (recovery) $ 78 $ 106 $ (135) $ 209 $ (37)
===============================================================================================================
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 $209 million ($145 million after-tax) stock-based
compensation expense as a result of the 22% increase in the Company's share
price in the nine months ended September 30, 2007, and a $78 million ($54
million after-tax) stock-based compensation expense as a result of the 7%
increase in the Company's share price for the three months ended September 30,
2007 (Company's share price as at: September 30, 2007 - C$75.56; June 30, 2007
- - C$70.78; December 31, 2006 - C$62.15; September 30, 2006 - C$50.94). 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 nine months ended September 30, 2007, the Company
capitalized $63 million in stock-based compensation on the Horizon Project
(September 30, 2006 - $38 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 September 30, 2007. In
periods when substantial stock price changes occur, the Company is subject to
significant earnings volatility.
For the nine months ended September 30, 2007, the Company paid $321 million for
stock options surrendered for cash settlement (September 30, 2006 - $216
million).
CANADIAN NATURAL RESOURCES LIMITED 29
===============================================================================
INTEREST EXPENSE
Three Months Ended Nine Months Ended
------------ -------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions, except per boe amounts) 2007 2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------
Interest expense, gross $ 160 $ 158 $ 81 $ 472 $ 208
Less: capitalized interest, Horizon Project 95 81 56 247 130
- -----------------------------------------------------------------------------------------------------------------------
Interest expense, net $ 65 $ 77 $ 25 $ 225 $ 78
$/boe (1) $ 1.15 $ 1.40 $ 0.48 $ 1.34 $ 0.51
Average effective interest rate 5.7% 5.4% 5.8% 5.4% 5.8%
=======================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Gross interest expense increased from the comparable periods in 2006
substantially due to increased debt levels associated with the ACC acquisition
and the financing of Horizon Project capital expenditures.
The Company's average effective interest rate for the periods ended September
30, 2007 reflected the impact of the stronger Canadian dollar, offset by higher
cost US dollar denominated debt issued in March 2007 and the impact on the
Company's floating rate debt of increased short term lending rates due to
credit market uncertainty.
30 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.
As disclosed in note 2 to the Company's unaudited interim consolidated
financial statements, commencing January 1, 2007 the Company adopted new
accounting standards issued by the Canadian Institute of Chartered Accountants
relating to the accounting for and disclosure of financial instruments and
comprehensive income.
Adoption of these standards required the Company to record all of its
derivative financial instruments on the balance sheet at estimated fair value
as at January 1, 2007, including those designated as hedges. Designated hedges,
other than cross currency interest rate swaps, were previously not recognized
on the balance sheet but were disclosed in the notes to the financial
statements. The adjustment to recognize the designated hedges on the balance
sheet was recorded as an adjustment to the opening balance of retained earnings
or accumulated other comprehensive income, as appropriate.
With the exception of the foreign currency translation adjustment, these
standards were adopted prospectively; accordingly, comparative amounts for
prior periods have not been restated. The reclassification of the foreign
currency translation adjustment to other comprehensive income was applied
retroactively with prior period restatement.
The effects of adopting these standards on the opening balance sheet were as
follows:
---------------
($ millions) JAN 1, 2007
- --------------------------------------------------------------------------------
Increased current portion of other long-term assets (1) $ 193
Decreased other long-term assets (2) $ (16)
Decreased long-term debt (3) $ (72)
Increased retained earnings (4) $ 10
Increased foreign currency translation adjustment (5) $ 13
Increased accumulated other comprehensive income (6) $ 146
Decreased current portion of future income tax asset (7) $ (62)
Increased future income tax liability (7) $ 18
===============================================================================
(1) RELATES TO THE RECOGNITION OF THE CURRENT PORTION OF THE FAIR VALUE OF
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(2) RELATES TO THE RECOGNITION OF THE LONG-TERM PORTION OF THE FAIR VALUE OF
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW AND FAIR VALUE
HEDGES, AS WELL AS THE RECLASSIFICATION OF TRANSACTION COSTS AND ORIGINAL
ISSUE DISCOUNTS FROM DEFERRED CHARGES TO LONG-TERM DEBT.
(3) RELATES TO THE FAIR VALUE IMPACT OF DERIVATIVE FINANCIAL INSTRUMENTS
DESIGNATED AS FAIR VALUE HEDGES, AS WELL AS THE RECLASSIFICATION OF
TRANSACTION COSTS AND ORIGINAL ISSUE DISCOUNTS.
(4) RELATES TO THE IMPACT ON ADOPTION OF THE MEASUREMENT OF INEFFECTIVENESS ON
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(5) RELATES TO THE RETROACTIVE RESTATEMENT OF FOREIGN CURRENCY TRANSLATION
ADJUSTMENT TO ACCUMULATED OTHER COMPREHENSIVE INCOME.
(6) RELATES TO THE RECOGNITION OF ACCUMULATED OTHER COMPREHENSIVE INCOME
ARISING FROM THE MEASUREMENT OF EFFECTIVENESS ON DERIVATIVE FINANCIAL
INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(7) RELATES TO THE FUTURE INCOME TAX IMPACTS OF THE ABOVE NOTED ADJUSTMENTS.
CANADIAN NATURAL RESOURCES LIMITED 31
===============================================================================
Effective January 1, 2007, the Company's accounting policies for financial
instruments and comprehensive income are as follows:
All derivative financial instruments are recognized at estimated fair value on
the consolidated balance sheet at each balance sheet date. The estimated fair
value of derivative instruments has been determined based on appropriate
internal valuation methodologies and/or third party indications. However, these
estimates may not necessarily be indicative of the amounts that could be
realized or settled in a current market transaction and these differences may
be material.
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. The effective portion of changes in the fair
value of derivative commodity price contracts designated as cash flow hedges is
initially recognized in other comprehensive income and is reclassified to risk
management activities in consolidated net earnings in the same period or
periods in which the crude oil or natural gas is sold. The ineffective portion
of changes in the fair value of these designated contracts is immediately
recognized in risk management activities in consolidated net earnings. All
changes in the fair value of non-designated crude oil and natural gas commodity
price contracts are recognized in risk management activities in consolidated
net earnings.
The Company enters into interest rate swap contracts to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. Changes in the fair value of
interest rate swap contracts designated as fair value hedges and corresponding
changes in the fair value of the hedged long-term debt are included in interest
expense in consolidated net earnings. Changes in the fair value of
non-designated interest rate swap contracts are included in risk management
activities in consolidated net earnings.
Cross currency swap contracts are periodically used to manage currency exposure
on US dollar denominated long-term debt. The cross currency swap contracts
require the periodic exchange of payments with the exchange at maturity of
notional principal amounts on which the payments are based. Changes in the fair
value of the foreign exchange component of cross currency swap contracts
designated as cash flow hedges are included in foreign exchange in consolidated
net earnings. The effective portion of changes in the fair value of the
interest rate component of cross currency swap contracts designated as cash
flow hedges is initially included in other comprehensive income and is
reclassified to interest expense when realized, with the ineffective portion
recognized in risk management activities in consolidated net earnings.
Gains or losses on the termination of financial instruments that have been
designated as cash flow hedges are deferred under accumulated other
comprehensive income on the consolidated balance sheets and amortized into
consolidated net earnings in the period in which the underlying hedged item is
recognized. In the event a designated hedged item is sold, extinguished or
matures prior to the termination of the related derivative instrument, any
unrealized derivative gain or loss is recognized immediately in consolidated
net earnings. Gains or losses on the termination of financial instruments that
have not been designated as hedges are recognized in consolidated net earnings
immediately.
Transaction costs that are directly attributable to the acquisition or issue of
a financial asset or financial liability and original issue discounts on
long-term debt have been included in the carrying value of the financial asset
or liability and are amortized to consolidated net earnings over the life of
the financial instrument using the effective interest method.
32 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
RISK MANAGEMENT
Three Months Ended Nine Months Ended
------------- -----------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions) 2007 2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------
REALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments $ 102 $ 100 $ 419 $ 197 $ 1,172
Natural gas financial instruments (125) (8) (15) (216) 27
- ----------------------------------------------------------------------------------------------------------------
$ (23) $ 92 $ 404 $ (19) $ 1,199
- ----------------------------------------------------------------------------------------------------------------
UNREALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments $ 80 $ 64 $ (601) $ 474 $ (497)
Natural gas financial instruments (4) (121) (152) 81 (268)
Interest rate swaps - - (1) - (7)
- ----------------------------------------------------------------------------------------------------------------
$ 76 $ (57) $ (754) $ 555 $ (772)
- ----------------------------------------------------------------------------------------------------------------
TOTAL $ 53 $ 35 $ (350) $ 536 $ 427
================================================================================================================
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 Nine Months Ended
------------- -------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2007 2007 2006 2007 2006
- ---------------------------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) $ 3.30 $ 3.41 $ 13.15 $ 2.19 $ 13.15
Natural gas ($/mcf) (1) $ (0.83) $ (0.05) (0.11) $ (0.47) $ 0.06
===============================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Complete details related to outstanding derivative financial instruments at
September 30, 2007 are disclosed in note 10 to the Company's unaudited interim
consolidated financial statements. 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.
As effective as the Company's 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 change in the fair value of the non-designated hedges is based on
prevailing forward commodity prices in effect at the end of each reporting
period and is reflected in risk management activities in consolidated net
earnings. The cash settlement amount of the risk management derivative
financial instruments may vary materially depending upon the underlying crude
oil and natural gas prices at the time of final settlement of the derivative
financial instruments, as compared to their mark-to-market value at September
30, 2007. Due to changes in the crude oil and natural gas forward pricing, and
the reversal of prior period unrealized gains and losses, the Company recorded
a net unrealized loss of $555 million ($384 million after-tax) on its commodity
risk management activities for the nine months ended September 30, 2007,
including a $76 million ($57 million after-tax) unrealized loss for the three
months ended September 30, 2007 (June 30, 2007 - unrealized gain of $57
million, $35 million after-tax; September 30, 2006 - unrealized gain of $754
million, $496 million after-tax).
CANADIAN NATURAL RESOURCES LIMITED 33
===============================================================================
FOREIGN EXCHANGE
Three Months Ended Nine Months Ended
------------ ------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions) 2007 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------
Net realized foreign exchange loss $ 22 $ 26 $ 1 $ 53 $ 8
Net unrealized foreign exchange (gain) loss (1) (195) (250) 11 (477) (37)
- --------------------------------------------------------------------------------------------------------------------
$ (173) $ (224) $ 12 $ (424) $ (29)
====================================================================================================================
(1) AMOUNTS ARE REPORTED NET OF THE HEDGING EFFECT OF CROSS CURRENCY INTEREST
RATE SWAPS AS DESCRIBED IN RISK MANAGEMENT ACTIVITIES.
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 results in increased revenue from the sale of the Company's production.
Production expenses are subject to foreign currency 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 net realized foreign exchange loss for the three and nine months ended
September 30, 2007 was primarily due to the result of foreign exchange rate
fluctuations on settlement of working capital items denominated in US dollars
or UK pounds sterling. The net unrealized foreign exchange gain for the three
and nine months ended September 30, 2007 was primarily related to the second
and third quarter strengthening of the Canadian dollar in relation to the US
dollar with respect to the US dollar debt and the re-measurement of North Sea
future income tax liabilities denominated in UK pounds sterling to US dollars.
Included in the net unrealized gain for the nine months ended September 30,
2007 was an unrealized loss of $335 million (June 30, 2007 - unrealized loss of
$207 million) related to the impact of the cross currency interest rate swaps.
The Canadian dollar ended the third quarter at a 31 year high, closing above
parity at US$1.0037 compared to US$0.9404 at June 30, 2007 (September 30, 2006
- - US$0.8966).
During the first quarter of 2007, the Company de-designated the portion of the
US dollar denominated debt previously hedged against its net investment in US
dollar based self-sustaining foreign operations. Accordingly, all foreign
exchange (gains) losses arising each period on U.S. dollar denominated
long-term debt are now recognized in the consolidated statement of earnings.
34 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
TAXES
Three Months Ended Nine Months Ended
------------- -----------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions, except income tax rates) 2007 2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------------
TAXES OTHER THAN INCOME TAX
Current $ 30 $ 9 $ 81 $ 105 $ 175
Deferred 10 20 (4) 27 40
- -------------------------------------------------------------------------------------------------------------------
$ 40 $ 29 $ 77 $ 132 $ 215
- -------------------------------------------------------------------------------------------------------------------
CURRENT INCOME TAX
North America $ 28 $ 12 $ 52 $ 65 $ 92
North Sea 56 54 - 145 -
Offshore West Africa 21 16 6 47 35
- -------------------------------------------------------------------------------------------------------------------
$ 105 $ 82 $ 58 $ 257 $ 127
- -------------------------------------------------------------------------------------------------------------------
FUTURE INCOME TAX EXPENSE $ 175 $ 116 $ 473 $ 391 $ 517
- -------------------------------------------------------------------------------------------------------------------
EFFECTIVE INCOME TAX RATE 28.6% 19.1%(1) 32.2%(4) 26.4%(1) 22.6%(2)(3)(4)
===================================================================================================================
(1) INCLUDES THE EFFECT OF A ONE TIME RECOVERY OF $71 MILLION DUE TO CANADIAN
FEDERAL INCOME TAX RATE REDUCTIONS ENACTED DURING THE SECOND QUARTER OF
2007.
(2) INCLUDES THE EFFECT OF A ONE TIME CHARGE OF $110 MILLION RELATED TO THE
INCREASED SUPPLEMENTARY CHARGE ON OIL AND GAS PROFITS IN THE UK NORTH SEA,
SUBSTANTIVELY ENACTED DURING THE FIRST QUARTER OF 2006.
(3) INCLUDES THE EFFECT OF A ONE TIME RECOVERY OF $438 MILLION DUE TO CANADIAN
FEDERAL, ALBERTA AND SASKATCHEWAN TAX RATE REDUCTIONS ENACTED DURING THE
SECOND QUARTER OF 2006.
(4) INCLUDES THE EFFECT OF A ONE TIME RECOVERY OF $67 MILLION DUE TO COTE
D'IVOIRE CORPORATE INCOME TAX RATE REDUCTIONS ENACTED DURING THE THIRD
QUARTER OF 2006.
Taxes other than income tax primarily includes current and deferred petroleum
revenue tax ("PRT"). PRT is charged on certain fields in the North Sea at the
rate of 50% of net operating income, after allowing for certain deductions
including abandonment expenditures.
Taxable income from the conventional crude oil and natural gas business in
Canada is primarily generated through partnerships, with the related income
taxes payable in a future period. North America current income taxes have been
provided on the basis of the corporate structure and available income tax
deductions and will vary depending upon the nature, timing and amount of
capital expenditures incurred in Canada in any particular year. In particular,
current taxes in 2007 and 2008 will be sensitive to the timing of the Horizon
Project capital expenditures being classified as available for use for Canadian
income tax purposes.
During the nine months ended September 30, 2007, the Company's consolidated
effective income tax rate was primarily reduced due to the effects of the
non-taxable portion of unrealized foreign exchange gains on US dollar debt and
an income tax rate reduction enacted during the second quarter of 2007.
CANADIAN NATURAL RESOURCES LIMITED 35
===============================================================================
CAPITAL EXPENDITURES (1)
Three Months Ended Nine Months Ended
------------- -------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions) 2007 2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------------
EXPENDITURES ON PROPERTY, PLANT AND
EQUIPMENT
Net property acquisitions (dispositions) $ 7 $ 15 $ (6) $ 68 $ 13
Land acquisition and retention 29 22 29 80 182
Seismic evaluations 23 34 26 107 113
Well drilling, completion and equipping 299 288 524 1,301 1,878
Pipeline and production facilities 238 243 270 815 1,003
- -------------------------------------------------------------------------------------------------------------------
TOTAL NET RESERVE REPLACEMENT EXPENDITURES 596 602 843 2,371 3,189
- -------------------------------------------------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 671 704 727 2,049 2,023
Phases 2 and 3 costs 28 19 18 91 25
Capitalized interest, stock-based
compensation and other 120 118 39 329 204
- -------------------------------------------------------------------------------------------------------------------
Total Horizon Project 819 841 784 2,469 2,252
- -------------------------------------------------------------------------------------------------------------------
Midstream 2 - 2 4 11
Abandonments (2) 22 13 24 55 56
Head office 3 4 8 12 20
- -------------------------------------------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES $ 1,442 $ 1,460 $ 1,661 $ 4,911 $ 5,528
===================================================================================================================
BY SEGMENT
North America $ 441 $ 419 $ 667 $ 1,858 $ 2,640
North Sea 121 136 148 395 435
Offshore West Africa 34 46 27 116 104
Other - 1 1 2 10
Horizon Project 819 841 784 2,469 2,252
Midstream 2 - 2 4 11
Abandonments (2) 22 13 24 55 56
Head office 3 4 8 12 20
- -------------------------------------------------------------------------------------------------------------------
Total $ 1,442 $ 1,460 $ 1,661 $ 4,911 $ 5,528
===================================================================================================================
(1) THE NET CAPITAL EXPENDITURES DO NOT INCLUDE ADJUSTMENTS RELATED TO
DIFFERENCES BETWEEN CARRYING VALUE AND TAX VALUE.
(2) ABANDONMENTS REPRESENT EXPENDITURES TO SETTLE ASSET RETIREMENT OBLIGATIONS
AND HAVE BEEN REFLECTED AS CAPITAL EXPENDITURES IN THIS TABLE.
36 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
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 in the nine months ended September 30, 2007 were
$4,911 million compared to $5,528 million in the nine months ended September
30, 2006. The capital expenditures reflected the continued progress on the
Company's larger, future growth projects, most notably the Horizon Project, as
well as overall industry-wide inflationary pressures, offset by the effects of
an overall strategic reduction in the North America natural gas drilling
program.
In the nine months ended September 30, 2007, the Company drilled a total of
1,051 net wells consisting of 303 natural gas wells, 423 crude oil wells, 248
stratigraphic test and service wells and 77 wells that were dry. This compared
to 1,407 net wells drilled in the nine months ended September 30, 2006. The
Company achieved an overall success rate of 90% for the nine months ended
September 30, 2007, excluding stratigraphic test and service wells, compared to
92% for the nine months ended September 30, 2006.
Net capital expenditures in the third quarter of 2007 were $1,442 million
compared to $1,661 million in the third quarter of 2006 and $1,460 million in
the prior quarter. Third quarter 2007 capital expenditures decreased from the
comparable period in 2006 due to the Company's strategic reduction in natural
gas drilling activity, and were comparable to the second quarter of 2007.
In the third quarter of 2007, the Company drilled a total of 268 net wells
consisting of 96 natural gas wells, 152 crude oil wells, 7 stratigraphic test
and service wells and 13 wells that were dry. This compared to 376 net wells in
the third quarter of 2006 and 95 net wells in the prior quarter. The Company
achieved an overall success rate of 95% for the third quarter of 2007,
excluding stratigraphic test and service wells, compared to 94% for the third
quarter of 2006 and 95% for the second quarter of 2007.
NORTH AMERICA
North America, including the Horizon Project, accounted for approximately 90%
of the total capital expenditures for both the nine months ended September 30,
2007 and 2006.
During the nine months ended September 30, 2007, the Company targeted 358 net
natural gas wells, including 52 wells in Northeast British Columbia, 126 wells
in the Northern Plains region, 90 wells in Northwest Alberta, and 90 wells in
the Southern Plains region. The Company also targeted 438 net crude oil wells
during the same period. The majority of these wells were concentrated in the
Company's crude oil Northern Plains region where 260 heavy crude oil wells, 109
Pelican Lake crude oil wells, 44 thermal crude oil wells and 5 light crude oil
wells were drilled. Another 20 wells targeting light crude oil were drilled
outside the Northern Plains region.
Due to significant changes in relative commodity prices between crude oil and
natural gas, the Company continues to access its large crude oil drilling
inventory to maximize value in both the short and long term. With the Company's
focus on drilling crude oil wells in the first nine months of 2007, natural gas
drilling activities were reduced to manage overall capital spending. Deferred
natural gas well locations have been retained in the Company's prospect
inventory. Drilling on ACC acquired lands was optimized as part of the overall
capital program.
In November of 2005, the Company announced a phased expansion of its In-Situ
Oil Sands Assets. As part of the development, the Company is continuing to
develop its Primrose thermal projects. During the first nine months of 2007,
the Company drilled 133 stratigraphic test wells and observation wells, 2 water
source wells and 44 thermal oil wells. Overall Primrose thermal production for
the nine months ended September 30, 2007 and 2006 was approximately 60,000
bbl/d.
The Primrose East Expansion, a new facility located 15 kilometers from the
existing Primrose South steam plant and 25 kilometers from the Wolf Lake
central processing facility, is anticipated to add approximately 40,000 bbl/d.
The Primrose East Expansion received Board of Directors' sanction in 2006 and
The Alberta Energy and Utilities Board regulatory approval in the first quarter
of 2007. Drilling and construction are currently underway, and production is
targeted to commence in 2009.
CANADIAN NATURAL RESOURCES LIMITED 37
===============================================================================
The next phase of the Company's In-Situ Oil Sands Assets expansion is the Kirby
project located 120 kilometers north of the existing Primrose facilities. The
Kirby project is anticipated to add approximately 45,000 bbl/d of production
growth. During September 2007, the Company filed a combined application and
Environmental Impact Assessment for this project with Alberta Environment and
The Alberta Energy and Utilities Board. Final corporate sanction will be
impacted by the terms of the proposed changes to the Alberta royalty regime and
environmental regulations, and their associated costs.
Development of new pads and secondary recovery conversion projects at Pelican
Lake continued as expected throughout the third quarter of 2007. Drilling
consisted of 34 horizontal wells, with plans to drill 13 additional horizontal
wells for the remainder of 2007. The response from the water and polymer flood
projects continues to be positive. Pelican Lake production averaged
approximately 35,000 bbl/d for the third quarter of 2007 compared to 30,000
bbl/d for the third quarter of 2006 and 34,000 bbl/d for the prior period.
Due to 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 Design Basis Memorandum and Engineering Design Specification of
the Canadian Natural Upgrader, outside of the Horizon Project, pending
clarification on the cost of future environmental legislation and a more stable
cost environment.
In the fourth quarter of 2007, the Company's overall drilling activity in North
America is expected to be comprised of 63 natural gas wells and 120 crude oil
wells excluding stratigraphic and service wells.
HORIZON PROJECT
Work progress on the Horizon Project was 84% complete at the end of the third
quarter. First production continues to be targeted to commence in the third
quarter of 2008. The project status as at September 30, 2007 was as follows:
o Overall detailed engineering 98% complete and substantially complete in
most areas;
o Procurement 98% complete with over $5.5 billion in purchase orders and
contracts awarded;
o Overall construction progress is 76% complete;
o Mine overburden removal approximately 63% complete and slightly ahead of
schedule;
o Energized Main Electrical Substations;
o Completed construction of Raw Water Pond;
o Started pre-commissioning activities in Bitumen Production Areas;
o Froth tank completed and hydro-tested;
o Commenced extraction plant hydro-testing;
o Permanent power energized in R1/R2 corridors pumphouses; and
o Started commissioning of Recycle Water Pond.
Major activities for the fourth quarter of 2007 will include:
o Complete the closure of Dyke 10 (external tailings pond) in Mining;
o Complete erection of Crushing Plants and conveyors in Ore Preparation
Area;
o Complete Primary Separation Cells in Extraction;
o Complete Main Control Room and Distributed Control Systems installation;
and
o Complete construction of Main Laboratory.
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 September 30, 2007 was approximately $6.1
billion. Final construction costs for Phase 1 are expected to exceed the
approved budget by approximately 8% to 14% primarily due to inflationary cost
pressures.
38 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
NORTH SEA
In the third quarter of 2007, the Company continued with its planned program of
infill drilling, recompletions, workovers and waterflood optimizations. During
the quarter, 1.0 net crude oil well was drilled along with 0.9 net water
injectors, with no additional net wells drilling at the end of the quarter.
The development of the Lyell Field continued during the third quarter with the
second production well coming onstream through the existing infrastructure.
Production from the initial Lyell producing wells has been below expectations
and continued development of the Lyell Field is under review.
Commissioning of the Columba E Raw Water Injection project was completed in the
second quarter of 2007 and 2 water injection wells were delivered, allowing
water injection into the reservoir to commence.
During the third quarter of 2007, the subsea project to bring gas lift to the
Kyle Field was successfully completed, allowing production potential to be
increased.
In August 2007, the Company entered into a Sale and Purchase Agreement for the
disposal, subject to government and partner consents, of its entire working
interest in the B-Block. Closing of the sale is expected during the fourth
quarter of 2007 or early in 2008.
OFFSHORE WEST AFRICA
During the third quarter of 2007, 1.2 net wells were drilled with 0.6 net wells
drilling at the end of the quarter.
First crude oil from West Espoir commenced production in mid 2006 with 1
additional production well and 1 additional injector well added during the
third quarter of 2007. West Espoir development drilling is expected to continue
into 2008 with producers and injectors being brought on line as they are
completed.
During the third quarter of 2007, the Company awarded a contract for the
upgrade of the Espoir floating production, storage and offtake vessel ("FPSO"),
in order to increase the throughput handling capability of the vessel. Design
and procurement work commenced during the quarter. Production volumes will not
be significantly impacted during the installation work, scheduled to commence
in late 2009.
At the 90% owned and operated Olowi Field in offshore Gabon, all major
construction contracts have been awarded. The project is on schedule with
drilling targeted to commence in the second quarter of 2008 and first crude oil
is targeted in late 2008 or early 2009. Olowi production is targeted to plateau
at approximately 20,000 bbl/d.
CANADIAN NATURAL RESOURCES LIMITED 39
===============================================================================
LIQUIDITY AND CAPITAL RESOURCES
----------------
($ millions, except ratios) SEP 30 Jun 30 Dec 31 Sep 30
2007 2007 2006 2006
- -----------------------------------------------------------------------------------------------------------------------
Working capital deficit (1) $ 824 $ 860 $ 832 $ 1,032
Long-term debt (2) $ 10,686 $ 10,958 $ 11,043 $ 5,500
Shareholders' equity
Share capital $ 2,663 $ 2,649 $ 2,562 $ 2,536
Retained earnings 9,824 9,169 8,141 7,869
Accumulated other comprehensive income (loss) 85 62 (13) (12)
- -----------------------------------------------------------------------------------------------------------------------
Total $ 12,572 $ 11,880 $ 10,690 $ 10,393
Debt to book capitalization (2) (3) 45.9% 48.0% 50.8% 34.6%
Debt to market capitalization (2) 20.8% 22.3% 24.8% 16.7%
After tax return on average common
shareholders' equity (4) 18.8% 23.8% 26.9% 38.2%
After tax return on average capital
employed (2) (5) 10.9% 13.9% 17.2% 26.0%
=======================================================================================================================
(1) CALCULATED AS CURRENT ASSETS LESS CURRENT LIABILITIES.
(2) LONG-TERM DEBT AT SEPTEMBER 30, 2007 IS STATED AT ITS CARRYING VALUE, NET
OF FAIR VALUE ADJUSTMENTS, ORIGINAL ISSUE DISCOUNTS AND TRANSACTIONS
COSTS. AMOUNTS FOR PERIODS PRIOR TO JANUARY 1, 2007 WERE NOT ADJUSTED FOR
THESE ITEMS.
(3) CALCULATED AS CURRENT AND LONG-TERM DEBT; DIVIDED BY THE BOOK VALUE OF
COMMON SHAREHOLDERS' EQUITY PLUS CURRENT AND LONG-TERM DEBT.
(4) CALCULATED AS NET EARNINGS FOR THE TWELVE MONTH TRAILING PERIOD; AS A
PERCENTAGE OF AVERAGE COMMON SHAREHOLDERS' EQUITY FOR THE PERIOD.
(5) 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, INCLUDING CAPITAL RELATED TO
THE HORIZON PROJECT.
The Company's capital resources at September 30, 2007 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, 2006 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 Limited, Baa2 with a stable outlook by Moody's Investors
Service and BBB with a stable outlook by Standard & Poor's.
At September 30, 2007, the Company had undrawn bank lines of credit of $1,309
million. Details related to the Company's long-term debt at September 30, 2007
are disclosed in note 4 to the Company's unaudited interim consolidated
financial statements.
At September 30, 2007, the Company's working capital deficit was $824 million
and included the current portion of the stock-based compensation liability of
$435 million and the current portion of the net mark-to-market liability for
risk management derivative financial instruments of $223 million. The
settlement of the stock-based compensation liability is dependent 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 derivative financial instruments may
vary materially depending upon the underlying crude oil and natural gas prices
40 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
at the time of final settlement of the derivative financial instruments, as
compared to their mark-to-market value at September 30, 2007.
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
September 30, 2007, such as Baobab, Primrose and 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.
Including the additional debt issued to complete the ACC acquisition in the
fourth quarter of 2006, long-term debt was $10,686 million at September 30,
2007, resulting in a debt to book capitalization level of 45.9% (June 30, 2007
- - 48.0%; December 31, 2006 - 50.8%; September 30, 2006 -34.6%). 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 late 2008. While the Company believes that its balance sheet has
the strength and flexibility to complete Phase 1 of the Horizon Project and its
planned capital expenditure programs, the Company has hedged a significant
portion of its crude oil and natural gas 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 60% of expected crude
oil volumes and approximately 60% of expected natural gas volumes are hedged
for the remainder of 2007.
The Company has the following commodity related net financial derivatives
outstanding as at September 30, 2007:
Remaining term Volume Average price Index
- ------------------------------------------------------------------------------------------------------------
CRUDE OIL
Crude oil price collars Oct 2007 - Dec 2007 15,000 bbl/d US$50.00 - US$66.25 Mayan Heavy
Oct 2007 - Dec 2007 50,000 bbl/d US$60.00 - US$71.49 WTI
Oct 2007 - Dec 2007 100,000 bbl/d US$60.00 - US$78.11 WTI
Oct 2007 - Dec 2007 50,000 bbl/d US$65.00 - US$84.52 WTI
Jan 2008 - Mar 2008 50,000 bbl/d US$60.00 - US$80.06 WTI
Jan 2008 - Jun 2008 25,000 bbl/d US$60.00 - US$80.44 WTI
Apr 2008 - Sep 2008 25,000 bbl/d US$60.00 - US$80.46 WTI
Jan 2008 - Dec 2008 20,000 bbl/d US$50.00 - US$65.53 Mayan Heavy
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$75.22 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
Crude oil puts Oct 2007 - Dec 2007 100,000 bbl/d US$45.00 WTI
Oct 2007 - Dec 2007 77,000 bbl/d US$60.00 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
Brent differential swaps Oct 2007 - Dec 2007 50,000 bbl/d US$1.34 WTI/Dated Brent
============================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 41
===============================================================================
Remaining term Volume Average price Index
- ---------------------------------------------------------------------------------------------------------
NATURAL GAS
AECO collars Oct 2007 - Dec 2007 60,000 GJ/d C$8.00 - C$8.79 AECO
Oct 2007 - Oct 2007 500,000 GJ/d C$6.00 - C$10.13 AECO
Oct 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 commodity financial derivatives are expected to be
settled monthly based on the applicable index pricing for the respective
contract month.
LONG-TERM DEBT
As at September 30, 2007, the Company had in place unsecured bank credit
facilities of $6,210 million, comprised of:
o a $100 million demand credit facility;
o a 3-year non-revolving syndicated credit facility of $2,350 million;
o a 5-year revolving syndicated credit facility of $2,230 million;
o a 5-year revolving syndicated credit facility of $1,500 million; and
o a (British pound)15 million demand credit facility related to the
Company's North Sea operations.
During the second quarter of 2007, one of the 5-year revolving syndicated
credit facilities was increased to $2,230 million and a $500 million demand
credit facility was terminated. The revolving syndicated credit facilities were
extended and now mature June 2012. Both facilities are extendible annually for
one year periods at the mutual agreement of the Company and the lenders. If the
facilities are not extended, the full amount of the outstanding principal would
be repayable on the maturity date.
In conjunction with the closing of the acquisition of ACC in November 2006, the
Company executed a $3,850 million, three-year non-revolving syndicated credit
facility maturing in October 2009. In March 2007, $1,500 million was repaid,
reducing the facility to $2,350 million.
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $345 million, including $300 million related to the Horizon
Project, were outstanding at September 30, 2007.
MEDIUM-TERM NOTES
In September 2007, the Company filed a short form shelf prospectus that allows
for the issue of up to $3,000 million of medium-term notes in Canada until
October 2009. If issued, these securities will bear interest as determined at
the date of issuance.
During the first quarter of 2007, $125 million of 7.40% unsecured debentures
due March 1, 2007 were repaid.
SENIOR UNSECURED NOTES
During the second quarter of 2007, US$31 million of the senior unsecured notes
were repaid.
US DOLLAR DEBT SECURITIES
In September 2007, the Company filed a short form prospectus that allows for
the issue of up to US$3,000 million of debt securities in the United States
until October 2009. If issued, these securities will bear interest as
determined at the date of issuance.
In March 2007, the Company issued US$2,200 million of unsecured notes under a
previous US shelf prospectus, comprised of US$1,100 million of unsecured notes
maturing May 2017 and US$1,100 million of unsecured notes maturing March 2038,
bearing interest at 5.70% and 6.25%, respectively. Concurrently, the Company
entered into cross currency interest rate swaps to fix the Canadian dollar
interest and principal repayment amounts on the entire US$1,100 million of
unsecured notes due May 2017 at 5.10% and C$1,287 million. The Company also
entered into a cross currency interest rate swap to fix the Canadian dollar
interest and principal repayment amounts on US$550
42 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
million of unsecured notes due March 2038 at 5.76% and C$644 million. Proceeds
from the securities issued were used to repay bankers' acceptances under the
Company's bank credit facilities.
During the first quarter of 2007, the Company de-designated the portion of the
US dollar denominated debt previously hedged against its net investment in US
dollar based self-sustaining foreign operations. Accordingly, all foreign
exchange (gains) losses arising each period on U.S. dollar denominated
long-term debt are now recognized in the consolidated statement of earnings.
SHARE CAPITAL
As at September 30, 2007, there were 539,584,000 common shares outstanding and
26,056,000 stock options outstanding. As at October 30, 2007, the Company had
539,612,000 common shares outstanding and 25,539,000 stock options outstanding.
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 October 30, 2007, the Company had not purchased any shares during 2007
under the Normal Course Issuer Bid.
In March 2007, the Company's Board of Directors approved an increase in the
annual dividend paid by the Company to $0.34 per common share for 2007. The
increase represents a 13% increase from the prior year, recognizes the
stability of the Company's cash flow, and provides a return to Shareholders.
This is the seventh consecutive year in which the Company has paid dividends
and the sixth consecutive year of an increase in the distribution paid to its
Shareholders. The dividend policy undergoes a periodic review by the Board of
Directors and is subject to change.
CANADIAN NATURAL RESOURCES LIMITED 43
===============================================================================
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations. These
commitments primarily relate to debt repayments, operating leases relating to
office space and offshore FPSOs and drilling rigs, and firm commitments for
gathering, processing and transmission services, as well as expenditures
relating to asset retirement obligations. As at September 30, 2007, no entities
were consolidated under the Canadian Institute of Chartered Accountants
Handbook Accounting Guideline 15, "Consolidation of Variable Interest
Entities". The following table summarizes the Company's commitments as at
September 30, 2007:
Remaining
($ millions) 2007 2008 2009 2010 2011 Thereafter
- ---------------------------------------------------------------------------------------------------------------------
Product transportation and pipeline $ 53 $ 217 $ 146 $ 133 $ 106 $ 1,053
Offshore equipment operating lease
((1)) $ 42 $ 94 $ 131 $ 114 $ 112 $ 481
Offshore drilling ((2)) (3) $ 20 $ 303 $ 186 $ 54 $ 14 $ 2
Asset retirement obligations ((4)) $ 1 $ 3 $ 3 $ 4 $ 4 $ 4,325
Long-term debt ((5)) $ - $ 39 $ 2,360 $ - $ 399 $ 5,483
Office lease $ 6 $ 27 $ 27 $ 27 $ 21 $ -
Electricity and other $ 50 $ 157 $ 165 $ 18 $ 1 $ -
=====================================================================================================================
(1) 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. DURING THE
INITIAL TERM, THE TOTAL ANNUAL PAYMENTS FOR THE GABON FPSO ARE ESTIMATED
TO BE US$50 MILLION.
(2) DURING 2007, THE COMPANY ENTERED INTO A ONE-YEAR AGREEMENT FOR OFFSHORE
DRILLING SERVICES RELATED TO THE BAOBAB FIELD IN COTE D'IVOIRE, OFFSHORE
WEST AFRICA. THE AGREEMENT IS SCHEDULED TO COMMENCE IN 2008, SUBJECT TO
RIG AVAILABILITY. ESTIMATED TOTAL PAYMENTS OF US$100 MILLION, AFTER JOINT
VENTURE RECOVERIES, HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD 2008 -
2009.
(3) DURING 2007, THE COMPANY AWARDED CONTRACTS FOR A DRILLING RIG AND FOR THE
CONSTRUCTION OF WELLHEAD TOWERS IN CONNECTION WITH THE PLANNED OFFSHORE
DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. ESTIMATED TOTAL PAYMENTS OF
US$419 MILLION HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD 2007 -
2011.
(4) 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.
(5) THE LONG-TERM DEBT REPRESENTS PRINCIPAL REPAYMENTS ONLY AND DO NOT REFLECT
FAIR VALUE ADJUSTMENTS, ORIGINAL ISSUE DISCOUNTS OR TRANSACTION COSTS. NO
DEBT REPAYMENTS ARE REFLECTED FOR $2,494 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 September 30, 2007 was approximately $6.1
billion. Final construction costs for Phase 1 are expected to exceed the
approved budget by 8% to 14%.
LEGAL PROCEEDINGS
The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business. The Company believes that any liabilities
that might arise pertaining to such matters would not have a material effect on
its consolidated financial position.
44 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING POLICIES
The preparation of financial statements requires the Company to make
judgements, assumptions and estimates in the application of generally accepted
accounting principles that have a significant impact on the financial results
of the Company. Actual results could differ from those estimates. A
comprehensive discussion of the Company's significant accounting policies is
contained in the MD&A and the audited consolidated financial statements for the
year ended December 31, 2006.
For the impact of new accounting standards related to financial instruments and
comprehensive income, please refer to Risk Management Activities on page 31 of
this MD&A and note 2 of the unaudited interim consolidated financial statements
as at September 30, 2007.
SENSITIVITY ANALYSIS
The following table is indicative of the annualized sensitivities of cash flow
from operations and net earnings from changes in certain key variables. The
analysis is based on business conditions and sales volumes during the third
quarter of 2007, excluding mark-to-market gains (losses) on risk management
activities, and is not necessarily indicative of future results. Each separate
line item in the sensitivity analysis shows the effect of a change in that
variable only; all other variables are held constant.
CASH FLOW
CASH FLOW FROM NET
FROM OPERATIONS NET EARNINGS
OPERATIONS (PER COMMON SHARE, EARNINGS (PER COMMON
($ MILLIONS) BASIC) ($ MILLIONS) SHARE, BASIC)
- ------------------------------------------------------------------------------------------------------------------------
PRICE CHANGES
Crude oil - WTI US$1.00/bbl (1)
Excluding financial derivatives $ 94 $ 0.18 $ 69 $ 0.13
Including financial derivatives $ 72 - 88 $ 0.13 - 0.16 $ 53 - 64 $ 0.10 - 0.12
Natural gas - AECO C$0.10/mcf (1)
Excluding financial derivatives $ 43 $ 0.08 $ 30 $ 0.06
Including financial derivatives $ 26 $ 0.05 $ 18 $ 0.03
VOLUME CHANGES
Crude oil - 10,000 bbl/d $ 127 $ 0.23 $ 65 $ 0.12
Natural gas - 10 mmcf/d $ 15 $ 0.03 $ 5 $ 0.01
FOREIGN CURRENCY RATE CHANGE
$0.01 change in US$ ((1))
Including financial derivatives $ 79 - 81 $ 0.15 $ 29 - 30 $ 0.05 - 0.06
INTEREST RATE CHANGE - 1% $ 38 $ 0.07 $ 38 $ 0.07
========================================================================================================================
(1) 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 45
===============================================================================
OTHER OPERATING HIGHLIGHTS
NETBACK ANALYSIS
Three Months Ended Nine Months Ended
-------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($/boe) (1) 2007 2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------
Sales price (2) $ 47.96 $ 49.70 $ 51.21 $ 48.99 $ 49.38
Royalties 6.07 5.99 5.75 6.27 5.99
Production expense (3) 9.62 10.44 10.01 10.05 9.13
- ------------------------------------------------------------------------------------------------------------------------
NETBACK 32.27 33.27 35.45 32.67 34.26
Midstream contribution (3) (0.26) (0.20) (0.23) (0.23) (0.24)
Administration 0.94 0.96 0.76 0.99 0.79
Interest, net 1.15 1.40 0.48 1.34 0.51
Realized risk management (gain) loss (0.41) 1.66 7.51 (0.11) 7.73
Realized foreign exchange loss 0.38 0.47 0.01 0.31 0.05
Taxes other than income tax - current 0.54 0.16 1.50 0.62 1.13
Current income tax - North America 0.49 0.21 0.97 0.38 0.60
Current income tax - North Sea 0.99 0.99 - 0.87 -
Current income tax - Offshore West Africa 0.37 0.29 0.11 0.28 0.22
- ------------------------------------------------------------------------------------------------------------------------
CASH FLOW $ 28.08 $ 27.33 $ 24.34 $ 28.22 $ 23.47
========================================================================================================================
(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.
46 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
FINANCIAL STATEMENTS
CONSOLIDATED BALANCE SHEETS
------------------
SEP 30 Dec 31
(millions of Canadian dollars, unaudited) 2007 2006
- --------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 21 $ 23
Accounts receivable and other 1,787 1,947
Future income tax 204 163
Current portion of other long-term assets (note 3) 36 106
- --------------------------------------------------------------------------------------------------------
2,048 2,239
PROPERTY, PLANT AND EQUIPMENT (note 12) 33,191 30,767
OTHER LONG-TERM ASSETS (note 3) 43 154
- --------------------------------------------------------------------------------------------------------
$ 35,282 $ 33,160
========================================================================================================
LIABILITIES
CURRENT LIABILITIES
Accounts payable $ 629 $ 842
Accrued liabilities 1,585 1,618
Current portion of other long-term liabilities (note 5) 658 611
- --------------------------------------------------------------------------------------------------------
2,872 3,071
LONG-TERM DEBT (note 4) 10,686 11,043
OTHER LONG-TERM LIABILITIES (note 5) 1,767 1,393
FUTURE INCOME TAX 7,385 6,963
- --------------------------------------------------------------------------------------------------------
22,710 22,470
- --------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
SHARE CAPITAL (note 7) 2,663 2,562
RETAINED EARNINGS 9,824 8,141
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (note 8) 85 (13)
- --------------------------------------------------------------------------------------------------------
12,572 10,690
- --------------------------------------------------------------------------------------------------------
$ 35,282 $ 33,160
========================================================================================================
COMMITMENTS (NOTE 11)
CANADIAN NATURAL RESOURCES LIMITED 47
===============================================================================
CONSOLIDATED STATEMENTS OF EARNINGS
Three Months Ended Nine Months Ended
--------------- --------------
(millions of Canadian dollars, except per common share SEP 30 Sep 30 SEP 30 Sep 30
amounts, unaudited) 2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------
REVENUE $ 3,073 $ 3,108 $ 9,343 $ 8,817
Less: royalties (341) (310) (1,048) (928)
- -----------------------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES 2,732 2,798 8,295 7,889
- -----------------------------------------------------------------------------------------------------------------------
EXPENSES
Production 544 544 1,693 1,430
Transportation and blending 359 331 1,103 1,110
Depletion, depreciation and amortization 715 589 2,144 1,667
Asset retirement obligation accretion (note 5) 18 17 53 50
Administration 53 41 166 123
Stock-based compensation expense (recovery) (note 5) 78 (135) 209 (37)
Interest, net 65 25 225 78
Risk management activities (note 10) 53 (350) 536 427
Foreign exchange (gain) loss (173) 12 (424) (29)
- -----------------------------------------------------------------------------------------------------------------------
1,712 1,074 5,705 4,819
- -----------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 1,020 1,724 2,590 3,070
Taxes other than income tax 40 77 132 215
Current income tax expense (note 6) 105 58 257 127
Future income tax expense (note 6) 175 473 391 517
- -----------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 700 $ 1,116 $ 1,810 $ 2,211
- -----------------------------------------------------------------------------------------------------------------------
NET EARNINGS PER COMMON SHARE (note 9)
Basic and diluted $ 1.30 $ 2.08 $ 3.36 $ 4.12
=======================================================================================================================
48 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Nine Months Ended
----------------
SEP 30 Sep 30
(millions of Canadian dollars, unaudited) 2007 2006
- ---------------------------------------------------------------------------------------------------------------------
COMMON SHARES
Balance - beginning of period $ 2,562 $ 2,442
Issued upon exercise of stock options 19 17
Previously recognized liability on stock options exercised for common shares 82 79
Purchase of common shares under Normal Course Issuer Bid - (2)
- ---------------------------------------------------------------------------------------------------------------------
Balance - end of period 2,663 2,536
- ---------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance - beginning of period, as originally reported 8,141 5,804
Transition adjustment on adoption of financial instruments standards (note 2) 10 -
- ---------------------------------------------------------------------------------------------------------------------
Balance - beginning of period, as restated 8,151 5,804
Net earnings 1,810 2,211
Dividends on common shares (note 7) (137) (120)
Purchase of common shares under Normal Course Issuer Bid - (26)
- ---------------------------------------------------------------------------------------------------------------------
Balance - end of period 9,824 7,869
- ---------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (note 2)
Balance - beginning of period (13) (9)
Transition adjustment on adoption of financial instruments standards 159 -
- ---------------------------------------------------------------------------------------------------------------------
Balance - beginning of period, after effect of transition adjustment 146 (9)
Other comprehensive loss, net of taxes (61) (3)
- ---------------------------------------------------------------------------------------------------------------------
Balance - end of period 85 (12)
- ---------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY $ 12,572 $ 10,393
=====================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Nine Months Ended
---------- -------------
SEP 30 Sep 30 SEP 30 Sep 30
(millions of Canadian dollars, unaudited) 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 700 $ 1,116 $ 1,810 $ 2,211
- --------------------------------------------------------------------------------------------------------------------------
NET CHANGE IN DERIVATIVE FINANCIAL INSTRUMENTS
DESIGNATED AS CASH FLOW HEDGES
Unrealized income during the period (net of taxes of $1
million - three months ended; $9 million - nine months
ended) 10 - 6 -
Reclassification to net earnings (net of taxes of $11 million
- three months ended; $24 million - nine months ended) 24 - (51) -
- --------------------------------------------------------------------------------------------------------------------------
34 - (45) -
- --------------------------------------------------------------------------------------------------------------------------
FOREIGN CURRENCY TRANSLATION ADJUSTMENT
Translation of net investment (11) - (16) (6)
Hedge of net investment, net of tax - - - 3
- --------------------------------------------------------------------------------------------------------------------------
(11) - (16) (3)
- --------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES 23 - (61) (3)
- --------------------------------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME $ 723 $ 1,116 $ 1,749 $ 2,208
==========================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 49
===============================================================================
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended Nine Months Ended
------------- -------------
SEP 30 Sep 30 SEP 30 Sep 30
(millions of Canadian dollars, unaudited) 2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings $ 700 $ 1,116 $ 1,810 $ 2,211
Non-cash items
Depletion, depreciation and amortization 715 589 2,144 1,667
Asset retirement obligation accretion 18 17 53 50
Stock-based compensation expense (recovery) 78 (135) 209 (37)
Unrealized risk management activities 76 (754) 555 (772)
Unrealized foreign exchange (gain) loss (195) 11 (477) (37)
Deferred petroleum revenue tax (recovery) 10 (4) 27 40
Future income tax expense 175 473 391 517
Deferred charges 12 - 7 (8)
Abandonment expenditures (22) (24) (55) (56)
Net change in non-cash working capital (94) (4) (82) (362)
- -----------------------------------------------------------------------------------------------------------------
1,473 1,285 4,582 3,213
- -----------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Issue (repayment) of bankers' acceptances 49 (285) (1,797) 1,115
(Repayment) issue of medium-term notes - - (125) 400
Repayment of senior unsecured notes - - (33) -
Issue of US dollar debt securities - 788 2,553 788
Issue of common shares on exercise of stock options 3 4 19 17
Dividends on common shares (46) (41) (132) (113)
Purchase of common shares - (6) - (28)
Net change in non-cash working capital (17) 2 6 8
- -----------------------------------------------------------------------------------------------------------------
(11) 462 491 2,187
- -----------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant and equipment (1,421) (1,638) (4,861) (5,475)
Net proceeds on sale of property, plant and equipment 1 1 5 3
- -----------------------------------------------------------------------------------------------------------------
Net expenditures on property, plant and equipment (1,420) (1,637) (4,856) (5,472)
Net change in non-cash working capital (32) (113) (219) 66
- -----------------------------------------------------------------------------------------------------------------
(1,452) (1,750) (5,075) (5,406)
- -----------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 10 (3) (2) (6)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 11 15 23 18
- -----------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF PERIOD $ 21 $ 12 $ 21 $ 12
=================================================================================================================
INTEREST PAID $ 158 $ 70 $ 403 $ 179
TAXES PAID
Taxes other than income tax $ 29 $ 106 $ 103 $ 239
Current income tax $ 85 $ 51 $ 157 $ 304
=================================================================================================================
50 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
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,
2006, except as described in note 2. 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 interim financial
statements should be read in conjunction with the Company's audited
consolidated financial statements and notes thereto for the year ended December
31, 2006.
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 the fourth quarter of 2006.
2. CHANGE IN ACCOUNTING POLICY
FINANCIAL INSTRUMENTS AND COMPREHENSIVE INCOME
Effective January 1, 2007, the Company adopted the following new accounting
standards issued by the Canadian Institute of Chartered Accountants relating to
the accounting for and disclosure of financial instruments and comprehensive
income:
o Section 1530 - "Comprehensive Income" introduces the concept of
comprehensive income to Canadian GAAP. Comprehensive income is the change
in equity (net assets) of the Company during a reporting period from
transactions and other events and circumstances from non-owner sources. It
includes all changes in equity during a period except transactions with
owners. The foreign currency translation adjustment, which was previously
a separate component of shareholders' equity, is now recorded as part of
accumulated other comprehensive income.
o Section 3251 - "Equity" replaces Section 3250 - "Surplus" and establishes
standards for the presentation of equity and changes in equity during a
reporting period.
o Section 3855 - "Financial Instruments - Recognition and Measurement"
prescribes when a financial asset, financial liability, or non-financial
derivative should be recognized on the balance sheet as well as its
measurement amount.
o Section 3865 - "Hedges" replaces Accounting Guideline 13 - "Hedging
Relationships" and EIC 128 - "Accounting for Trading, Speculative or
Non-Hedging Derivative Financial Instruments" and specifies how hedge
accounting is to be applied and what disclosures are necessary when hedge
accounting is applied.
Adoption of these standards required the Company to record all of its
derivative financial instruments on the balance sheet at estimated fair value
as at January 1, 2007, including those designated as hedges. Designated hedges,
other than cross currency interest rate swaps, were previously not recognized
on the balance sheet but were disclosed in the notes to the financial
statements. The adjustment to recognize the designated hedges on the balance
sheet was recorded as an adjustment to the opening balance of retained earnings
or accumulated other comprehensive income, as appropriate.
With the exception of the foreign currency translation adjustment, these
standards were adopted prospectively; accordingly, comparative amounts for
prior periods have not been restated. The reclassification of the foreign
currency translation adjustment to other comprehensive income was applied
retroactively with prior period restatement.
CANADIAN NATURAL RESOURCES LIMITED 51
===============================================================================
Effective January 1, 2007, the Company's accounting policies for financial
instruments and comprehensive income are as follows:
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.
All derivative financial instruments are recognized at estimated fair value on
the consolidated balance sheet at each balance sheet date. The estimated fair
value of derivative instruments has been determined based on appropriate
internal valuation methodologies and/or third party indications. However, these
estimates may not necessarily be indicative of the amounts that could be
realized or settled in a current market transaction and these differences may
be material.
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. The effective portion of changes in the fair
value of derivative commodity price contracts designated as cash flow hedges is
initially recognized in other comprehensive income and is reclassified to risk
management activities in consolidated net earnings in the same period or
periods in which the crude oil or natural gas is sold. The ineffective portion
of changes in the fair value of these designated contracts is immediately
recognized in risk management activities in consolidated net earnings. All
changes in the fair value of non-designated crude oil and natural gas commodity
price contracts are recognized in risk management activities in consolidated
net earnings.
The Company enters into interest rate swap contracts to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. Changes in the fair value of
interest rate swap contracts designated as fair value hedges and corresponding
changes in the fair value of the hedged long-term debt are included in interest
expense in consolidated net earnings. Changes in the fair value of
non-designated interest rate swap contracts are included in risk management
activities in consolidated net earnings.
Cross currency swap contracts are periodically used to manage currency exposure
on US dollar denominated long-term debt. The cross currency swap contracts
require the periodic exchange of payments with the exchange at maturity of
notional principal amounts on which the payments are based. Changes in the fair
value of the foreign exchange component of cross currency swap contracts
designated as cash flow hedges are included in foreign exchange in consolidated
net earnings. The effective portion of changes in the fair value of the
interest rate component of cross currency swap contracts designated as cash
flow hedges is initially included in other comprehensive income and is
reclassified to interest expense when realized, with the ineffective portion
recognized in risk management activities in consolidated net earnings.
Gains or losses on the termination of financial instruments that have been
designated as cash flow hedges are deferred under accumulated other
comprehensive income on the consolidated balance sheets and amortized into
consolidated net earnings in the period in which the underlying hedged item is
recognized. In the event a designated hedged item is sold, extinguished or
matures prior to the termination of the related derivative instrument, any
unrealized derivative gain or loss is recognized immediately in consolidated
net earnings. Gains or losses on the termination of financial instruments that
have not been designated as hedges are recognized in consolidated net earnings
immediately.
Transaction costs that are directly attributable to the acquisition or issue of
a financial asset or financial liability and original issue discounts on
long-term debt have been included in the carrying value of the financial asset
or liability and are amortized to consolidated net earnings over the life of
the financial instrument using the effective interest method.
COMPREHENSIVE INCOME
Comprehensive income is comprised of the Company's net earnings and other
comprehensive income. Other comprehensive income includes the effective portion
of changes in the fair value of derivative financial instruments designated as
cash flow hedges and foreign currency translation gains and losses on the net
investment in self-sustaining foreign operations. Other comprehensive income is
shown net of related income taxes.
52 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
The effects of adopting these standards on the opening balance sheet were as
follows:
---------------
JAN 1, 2007
- --------------------------------------------------------------------------------
Increased current portion of other long-term assets (1) $ 193
Decreased other long-term assets (2) $ (16)
Decreased long-term debt (3) $ (72)
Increased retained earnings (4) $ 10
Increased foreign currency translation adjustment (5) $ 13
Increased accumulated other comprehensive income (6) $ 146
Decreased current portion of future income tax asset (7) $ (62)
Increased future income tax liability (7) $ 18
================================================================================
(1) RELATES TO THE RECOGNITION OF THE CURRENT PORTION OF THE FAIR VALUE OF
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(2) RELATES TO THE RECOGNITION OF THE LONG-TERM PORTION OF THE FAIR VALUE OF
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW AND FAIR VALUE
HEDGES, AS WELL AS THE RECLASSIFICATION OF TRANSACTION COSTS AND ORIGINAL
ISSUE DISCOUNTS FROM DEFERRED CHARGES TO LONG-TERM DEBT.
(3) RELATES TO THE FAIR VALUE IMPACT OF DERIVATIVE FINANCIAL INSTRUMENTS
DESIGNATED AS FAIR VALUE HEDGES, AS WELL AS THE RECLASSIFICATION OF
TRANSACTION COSTS AND ORIGINAL ISSUE DISCOUNTS.
(4) RELATES TO THE IMPACT ON ADOPTION OF THE MEASUREMENT OF INEFFECTIVENESS ON
DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(5) RELATES TO THE RETROACTIVE RESTATEMENT OF FOREIGN CURRENCY TRANSLATION
ADJUSTMENT TO ACCUMULATED OTHER COMPREHENSIVE INCOME.
(6) RELATES TO THE RECOGNITION OF ACCUMULATED OTHER COMPREHENSIVE INCOME
ARISING FROM THE MEASUREMENT OF EFFECTIVENESS ON DERIVATIVE FINANCIAL
INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(7) RELATES TO THE FUTURE INCOME TAX IMPACTS OF THE ABOVE NOTED ADJUSTMENTS.
3. OTHER LONG-TERM ASSETS
-----------
SEP 30 Dec 31
2007 2006
- --------------------------------------------------------------------------------
Deferred charges (note 2) $ 58 $ 109
Risk management (note 10) - 128
Other 21 23
- --------------------------------------------------------------------------------
79 260
Less: current portion 36 106
- --------------------------------------------------------------------------------
$ 43 $ 154
================================================================================
CANADIAN NATURAL RESOURCES LIMITED 53
===============================================================================
4. LONG-TERM DEBT
-------------
SEP 30 Dec 31
2007 2006
- -------------------------------------------------------------------------------------------------------------
CANADIAN DOLLAR DENOMINATED DEBT
Bank credit facilities (bankers' acceptances) $ 4,824 $ 6,621
Medium-term notes 800 925
- -------------------------------------------------------------------------------------------------------------
5,624 7,546
- -------------------------------------------------------------------------------------------------------------
US DOLLAR DENOMINATED DEBT
Senior unsecured notes (2007 - US$62 million; and 2006 - US$93 million) 62 108
US dollar debt securities (2007 - US$5,108 million; and 2006 - US$2,908 million) 5,089 3,389
Less - original issue discount on senior unsecured notes and US dollar
debt securities (1) (23) -
- -------------------------------------------------------------------------------------------------------------
5,128 3,497
Change in fair value of interest rate swaps on US dollar debt securities ((2)) (15) -
- -------------------------------------------------------------------------------------------------------------
5,113 3,497
- -------------------------------------------------------------------------------------------------------------
Long-term debt before transaction costs 10,737 11,043
Less - transaction costs (1) (3) (51) -
- -------------------------------------------------------------------------------------------------------------
$ 10,686 $ 11,043
=============================================================================================================
(1) AS DESCRIBED IN NOTE 2, EFFECTIVE JANUARY 1, 2007, THE COMPANY HAS
INCLUDED UNAMORTIZED ORIGINAL ISSUE DISCOUNTS AND DIRECTLY ATTRIBUTABLE
TRANSACTION COSTS IN THE CARRYING VALUE OF THE OUTSTANDING DEBT.
(2) THE CARRYING VALUES OF US$350 MILLION OF 5.45% NOTES DUE OCTOBER 2012 AND
US$350 MILLION OF 4.90% NOTES DUE DECEMBER 2014 HAVE BEEN ADJUSTED BY $15
MILLION TO REFLECT THE FAIR VALUE IMPACT OF HEDGE ACCOUNTING (NOTE 2).
(3) TRANSACTION COSTS PRIMARILY REPRESENT UNDERWRITING COMMISSIONS CHARGED AS
A PERCENTAGE OF THE RELATED DEBT OFFERINGS, AS WELL AS LEGAL, RATING
AGENCY AND OTHER PROFESSIONAL FEES.
BANK CREDIT FACILITIES
As at September 30, 2007, the Company had in place unsecured bank credit
facilities of $6,210 million, comprised of:
o a $100 million demand credit facility;
o a 3-year non-revolving syndicated credit facility of $2,350 million;
o a 5-year revolving syndicated credit facility of $2,230 million;
o a 5-year revolving syndicated credit facility of $1,500 million; and
o a (British pound)15 million demand credit facility related to the
Company's North Sea operations.
During the second quarter of 2007, one of the 5-year revolving syndicated
credit facilities was increased to $2,230 million and a $500 million demand
credit facility was terminated. The revolving syndicated credit facilities were
extended and now mature June 2012. Both facilities are extendible annually for
one year periods at the mutual agreement of the Company and the lenders. If the
facilities are not extended, the full amount of the outstanding principal would
be repayable on the maturity date.
In conjunction with the closing of the acquisition of Anadarko Canada
Corporation in November 2006, the Company executed a $3,850 million, three-year
non-revolving syndicated credit facility maturing in October 2009. In March
2007, $1,500 million was repaid, reducing the facility to $2,350 million.
54 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
The weighted average interest rate of the bank credit facilities outstanding at
September 30, 2007, was 5.4% (December 31, 2006 - 4.8%).
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $345 million, including $300 million related to the Horizon Oil
Sands Project ("Horizon Project"), were outstanding at September 30, 2007.
MEDIUM-TERM NOTES
In September 2007, the Company filed a short form shelf prospectus that allows
for the issue of up to $3,000 million of medium-term notes in Canada until
October 2009. If issued, these securities will bear interest as determined at
the date of issuance.
During the first quarter of 2007, $125 million of 7.40% unsecured debentures
due March 1, 2007 were repaid.
SENIOR UNSECURED NOTES
During the second quarter of 2007, US$31 million of the senior unsecured notes
were repaid.
US DOLLAR DEBT SECURITIES
In September 2007, the Company filed a short form prospectus that allows for
the issue of up to US$3,000 million of debt securities in the United States
until October 2009. If issued, these securities will bear interest as
determined at the date of issuance.
In March 2007, the Company issued US$2,200 million of unsecured notes under a
previous US shelf prospectus, comprised of US$1,100 million of unsecured notes
maturing May 2017 and US$1,100 million of unsecured notes maturing March 2038,
bearing interest at 5.70% and 6.25%, respectively. Concurrently, the Company
entered into cross currency interest rate swaps to fix the Canadian dollar
interest and principal repayment amounts on the entire US$1,100 million of
unsecured notes due May 2017 at 5.10% and C$1,287 million (note 10). The
Company also entered into a cross currency interest rate swap to fix the
Canadian dollar interest and principal repayment amounts on US$550 million of
unsecured notes due March 2038 at 5.76% and C$644 million (note 10). Proceeds
from the securities issued were used to repay bankers' acceptances under the
Company's bank credit facilities.
During the first quarter of 2007, the Company de-designated the portion of the
US dollar denominated debt previously hedged against its net investment in US
dollar based self-sustaining foreign operations. Accordingly, all foreign
exchange (gains) losses arising each period on U.S. dollar denominated
long-term debt are now recognized in the consolidated statement of earnings.
5. OTHER LONG-TERM LIABILITIES
--------------
SEP 30 Dec 31
2007 2006
- --------------------------------------------------------------------------------
Asset retirement obligations $ 1,095 $ 1,166
Stock-based compensation 613 744
Risk management (note 10) 618 -
Other 99 94
- --------------------------------------------------------------------------------
2,425 2,004
Less: current portion 658 611
- --------------------------------------------------------------------------------
$ 1,767 $ 1,393
================================================================================
CANADIAN NATURAL RESOURCES LIMITED 55
===============================================================================
ASSET RETIREMENT OBLIGATIONS
At September 30, 2007, the Company's total estimated cost to settle its asset
retirement obligations was approximately $4,340 million (December 31, 2006 -
$4,497 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:
------------------
NINE MONTHS Year
ENDED Ended
SEP 30, 2007 Dec 31, 2006
- ------------------------------------------------------------------------------------------------------
Balance - beginning of period $ 1,166 $ 1,112
Liabilities incurred 11 26
Liabilities acquired - 56
Liabilities settled (55) (75)
Asset retirement obligation accretion 53 68
Revision of estimates 1 (21)
Foreign exchange (81) -
- ------------------------------------------------------------------------------------------------------
Balance - end of period $ 1,095 $ 1,166
======================================================================================================
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.
------------------
NINE MONTHS Year
ENDED Ended
SEP 30, 2007 Dec 31, 2006
- ------------------------------------------------------------------------------------------------------
Balance - beginning of period $ 744 $ 891
Stock-based compensation 209 139
Payments for options surrendered (321) (264)
Transferred to common shares (82) (101)
Capitalized to Horizon Project 63 79
- ------------------------------------------------------------------------------------------------------
Balance - end of period 613 744
Less: current portion of stock-based compensation 435 611
- ------------------------------------------------------------------------------------------------------
$ 178 $ 133
======================================================================================================
56 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
6. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Nine Months Ended
------------ ----------
SEP 30 Sep 30 SEP 30 Sep 30
2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------
Current income tax - North America $ 28 $ 52 $ 65 $ 92
Current income tax - North Sea 56 - 145 -
Current income tax - Offshore West Africa 21 6 47 35
- --------------------------------------------------------------------------------------------------------------
Current income tax expense 105 58 257 127
Future income tax expense 175 473 391 517
- --------------------------------------------------------------------------------------------------------------
Income tax expense $ 280 $ 531 $ 648 $ 644
==============================================================================================================
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, timing and amount of
capital expenditures incurred in Canada in any particular year.
During the second quarter of 2007, the Canadian Federal Government enacted
income tax rate changes, resulting in a reduction of future income tax
liabilities of approximately $71 million.
During the first quarter of 2006, income tax rate changes resulted in an
increase of future income tax liabilities of approximately $110 million in the
UK North Sea.
During the second quarter of 2006, income tax rate changes resulted in a
reduction of future income tax liabilities of approximately $438 million in
North America.
During the third quarter of 2006, income tax rate changes resulted in a
reduction of future income tax liabilities of approximately $67 million in Cote
d'Ivoire, Offshore West Africa.
7. SHARE CAPITAL
-----------------------------------
Nine Months Ended Sep 30, 2007
ISSUED NUMBER OF SHARES
COMMON SHARES (thousands) AMOUNT
- -----------------------------------------------------------------------------------------------------------
Balance - beginning of period $ 537,903 $ 2,562
Issued upon exercise of stock options 1,681 19
Previously recognized liability on stock options exercised for
common shares - 82
- -----------------------------------------------------------------------------------------------------------
Balance - end of period $ 539,584 $ 2,663
===========================================================================================================
NORMAL COURSE ISSUER BID
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 September 30, 2007, the Company had not purchased any shares under the
Normal Course Issuer Bid.
CANADIAN NATURAL RESOURCES LIMITED 57
===============================================================================
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.
STOCK OPTIONS
----------------------------------------------
Nine Months Ended Sep 30, 2007
STOCK OPTIONS WEIGHTED AVERAGE
(thousands) EXERCISE PRICE
- ---------------------------------------------------------------------------------------------------------------------
Outstanding - beginning of period 34,425 $ 33.77
Granted 1,458 $ 68.36
Exercised for common shares (1,681) $ 11.20
Surrendered for cash settlement (6,240) $ 15.49
Forfeited (1,906) $ 45.70
- ---------------------------------------------------------------------------------------------------------------------
Outstanding - end of period 26,056 $ 40.70
- ---------------------------------------------------------------------------------------------------------------------
Exercisable - end of period 6,967 $ 23.96
=====================================================================================================================
8. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income (loss), net of taxes,
were as follows:
---------------------
SEP 30 Sep 30
2007 2006
- ----------------------------------------------------------------------------------------------------------------------
Derivative financial instruments designated as cash flow hedges $ 114 $ -
Foreign currency translation adjustment (29) (12)
- ----------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) $ 85 $ (12)
======================================================================================================================
9. NET EARNINGS PER COMMON SHARE
Three Months Ended Nine Months Ended
------------- -------------
SEP 30 SEP 30
2007 Sep 30 2006 2007 Sep 30 2006
- -----------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding (thousands) - 539,494 537,292 539,229 537,296
basic and diluted
- -----------------------------------------------------------------------------------------------------------------------
Net earnings - basic and diluted $ 700 $ 1,116 $ 1,810 $ 2,211
- -----------------------------------------------------------------------------------------------------------------------
Net earnings per common share - basic and diluted $ 1.30 $ 2.08 $ 3.36 $ 4.12
=======================================================================================================================
58 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.
As described in note 2, commencing January 1, 2007, the Company recorded all of
its derivative financial instruments on the balance sheet at fair value,
including those designated as hedges. 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.
The estimated fair values of financial derivatives recognized in the risk
management asset (liability) were comprised as follows:
--------------------
NINE MONTHS
ENDED Year Ended
SEP 30, 2007 Dec 31, 2006
- ------------------------------------------------------------------------------------------------------------------------
RISK MANAGEMENT Risk management Deferred
Asset (liability) MARK-TO-MARKET mark-to-market revenue
- ------------------------------------------------------------------------------------------------------------------------
Balance - beginning of period $ 128 $ (877) $ (8)
Retained earnings effect of adoption of financial instrument
standards (note 2) 14 - -
Net cost of outstanding put options 129 455 -
Net change in fair value of outstanding derivative financial
instruments attributable to:
- Risk management activities (555) 995 -
- Interest expense (15) - -
- Foreign exchange (335) 10 -
- Other comprehensive income 157 - -
Amortization of deferred revenue - - 8
- ------------------------------------------------------------------------------------------------------------------------
(477) 583 -
Add: Put premium financing obligations (1) (141) (455) -
- ------------------------------------------------------------------------------------------------------------------------
Balance - end of period (618) 128 -
Less: current portion (223) 88 -
- ------------------------------------------------------------------------------------------------------------------------
$ (395) $ 40 $ -
========================================================================================================================
(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 (gains) losses from risk management activities were as follows:
Three Months Ended Nine Months Ended
------------------- -----------------
SEP 30 Sep 30 SEP 30 Sep 30
2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------
Net realized risk management (gain) loss $ (23) $ 404 $ (19) $ 1,199
Net unrealized risk management
mark-to-market loss (gain) 76 (754) 555 (772)
- ------------------------------------------------------------------------------------------------------------------------
$ 53 $ (350) $ 536 $ 427
========================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 59
===============================================================================
The Company had the following net financial derivatives outstanding as at
September 30, 2007:
Remaining term Volume Average price Index
- -----------------------------------------------------------------------------------------------------------------
CRUDE OIL
Crude oil price collars Oct 2007 - Dec 2007 15,000 bbl/d US$50.00 - US$66.25 Mayan Heavy
Oct 2007 - Dec 2007 50,000 bbl/d US$60.00 - US$71.49 WTI
Oct 2007 - Dec 2007 100,000 bbl/d US$60.00 - US$78.11 WTI
Oct 2007 - Dec 2007 50,000 bbl/d US$65.00 - US$84.52 WTI
Jan 2008 - Mar 2008 50,000 bbl/d US$60.00 - US$80.06 WTI
Jan 2008 - Jun 2008 25,000 bbl/d US$60.00 - US$80.44 WTI
Apr 2008 - Sep 2008 25,000 bbl/d US$60.00 - US$80.46 WTI
Jan 2008 - Dec 2008 20,000 bbl/d US$50.00 - US$65.53 Mayan Heavy
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$75.22 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
Crude oil puts Oct 2007 - Dec 2007 100,000 bbl/d US$45.00 WTI
Oct 2007 - Dec 2007 77,000 bbl/d US$60.00 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
Brent differential swaps Oct 2007 - Dec 2007 50,000 bbl/d US$1.34 WTI/Dated Brent
=================================================================================================================
The net cost of outstanding put options and their respective periods of
settlement are as follows:
Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008
- -----------------------------------------------------------------------------------------------------------------
Cost ($ millions) US$72 US$14 US$15 US$15 US$15
=================================================================================================================
Remaining term Volume Average price Index
- -----------------------------------------------------------------------------------------------------------------
NATURAL GAS
AECO collars Oct 2007 - Dec 2007 60,000 GJ/d C$8.00 - C$8.79 AECO
Oct 2007 - Oct 2007 500,000 GJ/d C$6.00 - C$10.13 AECO
Oct 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 commodity financial derivatives are expected to be
settled monthly based on the applicable index pricing for the respective
contract month.
In addition to the financial derivatives noted above, the Company also entered
into natural gas physical sales contracts for 300,000 GJ/d at an average fixed
price of C$7.33 per GJ at AECO for the month of October 2007.
60 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
Amount
Remaining term ($ millions) Fixed rate Floating rate
- ------------------------------------------------------------------------------------------------------------------
INTEREST RATE
Swaps - fixed to floating Oct 2007 - Oct 2012 US$350 5.45% LIBOR (1) + 0.81%
Oct 2007 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
==================================================================================================================
(1) LONDON INTERBANK OFFERED RATE
Amount Exchange rate Interest rate Interest rate
Remaining term ($ millions) (US$/C$) (US$) (C$)
- --------------------------------------------------------------------------------------------------------------------
CROSS CURRENCY
Swaps Oct 2007 - Aug 2016 US$250 1.116 6.00% 5.40%
Oct 2007 - May 2017 US$1,100 1.170 5.70% 5.10%
Oct 2007 - Mar 2038 US$550 1.170 6.25% 5.76%
====================================================================================================================
11. COMMITMENTS
The Company has committed to certain payments as follows:
Remaining
2007 2008 2009 2010 2011 Thereafter
- -------------------------------------------------------------------------------------------------------------------
Product transportation and
pipeline $ 53 $ 217 $ 146 $ 133 $ 106 $ 1,053
Offshore equipment operating
leases (1) $ 42 $ 94 $ 131 $ 114 $ 112 $ 481
Offshore drilling (2) (3) $ 20 $ 303 $ 186 $ 54 $ 14 $ 2
Asset retirement
obligations ((4)) $ 1 $ 3 $ 3 $ 4 $ 4 $ 4,325
Office leases $ 6 $ 27 $ 27 $ 27 $ 21 $ -
Electricity and other $ 50 $ 157 $ 165 $ 18 $ 1 $ -
===================================================================================================================
(1) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRMARILY 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. DURING THE INITIAL TERM, THE
TOTAL ANNUAL PAYMENTS FOR THE GABON FPSO ARE ESTIMATED TO BE US$50
MILLION.
(2) DURING 2007, THE COMPANY ENTERED INTO A ONE-YEAR AGREEMENT FOR OFFSHORE
DRILLING SERVICES RELATED TO THE BAOBAB FIELD IN COTE D'IVOIRE, OFFSHORE
WEST AFRICA. THE AGREEMENT IS SCHEDULED TO COMMENCE IN 2008, SUBJECT TO
RIG AVAILABILITY. ESTIMATED TOTAL PAYMENTS OF US$100 MILLION, AFTER JOINT
VENTURE RECOVERIES, HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD 2008 -
2009.
(3) DURING 2007, THE COMPANY AWARDED CONTRACTS FOR A DRILLING RIG AND FOR THE
CONSTRUCTION OF WELLHEAD TOWERS IN CONNECTION WITH THE PLANNED OFFSHORE
DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. ESTIMATED TOTAL PAYMENTS OF
US$419 MILLION HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD 2007 -
2011.
(4) 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 September 30, 2007 was approximately $6.1
billion. Final construction costs for Phase 1 are expected to exceed the
approved budget.
CANADIAN NATURAL RESOURCES LIMITED 61
===============================================================================
12. SEGMENTED INFORMATION
NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA
(millions of Canadian Three Months Nine Months Three Months Nine Months Three Months Nine Months
dollars, unaudited) Ended Ended Ended Ended Ended Ended
Sep 30 Sep 30 Sep 30 Sep 30 Sep 30 Sep 30
-------- --------- --------- -------- -------- --------
2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE 2,459 2,301 7,578 6,823 397 567 1,230 1,264 211 236 516 718
Less: royalties (320) (293) (1,001) (898) (1) (1) (2) (2) (20) (16) (45) (28)
- ------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE, NET OF 2,139 2,008 6,577 5,925 396 566 1,228 1,262 191 220 471 690
ROYALTIES
- ------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production 401 368 1,265 1,036 117 145 353 313 23 27 63 68
Transportation and
blending 366 337 1,122 1,128 4 3 12 11 - - - -
Depletion, depreciation
and amortization 593 454 1,748 1,317 77 90 271 212 43 43 119 132
Asset retirement
obligation accretion 9 9 28 26 8 7 23 22 1 1 2 2
Realized risk management
activities (28) 313 (53) 946 5 91 34 253 - - - -
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES 1,341 1,481 4,110 4,453 211 336 693 811 67 71 184 202
- ------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS (LOSS)
BEFORE THE FOLLOWING 798 527 2,467 1,472 185 230 535 451 124 149 287 488
- ------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration
Stock-based compensation
expense (recovery)
Interest, net
Unrealized risk
management activities
Foreign exchange (gain)
loss
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED
EXPENSES
- ------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES
Taxes other than income
tax
Current income tax expense
Future income tax expense
- ------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS
==============================================================================================================================
62 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
INTER-SEGMENT ELIMINATION
MIDSTREAM AND OTHER TOTAL
(millions of Canadian Three Months Nine Months Three Months Nine Months Three Months Nine Months
dollars, unaudited) Ended Ended Ended Ended Ended Ended
Sep 30 Sep 30 Sep 30 Sep 30 Sep 30 Sep 30
-------- --------- --------- -------- -------- --------
2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE 19 19 55 54 (13) (15) (36) (42) 3,073 3,108 9,343 8,817
Less: royalties - - - - - - - - (341) (310) (1,048) (928)
- ------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE, NET OF 19 19 55 54 (13) (15) (36) (42) 2,732 2,798 8,295 7,889
ROYALTIES
- ------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production 5 6 16 17 (2) (2) (4) (4) 544 544 1,693 1,430
Transportation and blending - - - - (11) (9) (31) (29) 359 331 1,103 1,110
Depletion, depreciation and
amortization 2 2 6 6 - - - - 715 589 2,144 1,667
Asset retirement obligation
accretion - - - - - - - - 18 17 53 50
Realized risk management
activities - - - - - - - - (23) 404 (19) 1,199
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES 7 8 22 23 (13) (11) (35) (33) 1,613 1,885 4,974 5,456
- ------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS (LOSS)
BEFORE THE FOLLOWING 12 11 33 31 - (4) (1) (9) 1,119 913 3,321 2,433
- ------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration 53 41 166 123
Stock-based compensation
expense (recovery) 78 (135) 209 (37)
Interest, net 65 25 225 78
Unrealized risk management
activities 76 (754) 555 (772)
Foreign exchange (gain)
loss (173) 12 (424) (29)
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED EXPENSES 99 (811) 731 (637)
- ------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 1,020 1,724 2,590 3,070
Taxes other than income tax 40 77 132 215
Current income tax expense 105 58 257 127
Future income tax expense 175 473 391 517
- ------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS 700 1,116 1,810 2,211
==============================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 63
===============================================================================
NET ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT
Nine Months Ended
SEP 30, 2007 Sep 30, 2006
----------------------------------------
NET FAIR VALUE CAPITALIZED Net Fair Value Capitalized
EXPENDITURES CHANGES (1) COSTS Expenditures Changes (1) Costs
- --------------------------------------------------------------------------------------------------------------
North America $ 1,858 $ 11 $ 1,869 $ 2,640 $ 14 $ 2,654
North Sea 395 - 395 435 (1) 434
Offshore West Africa 116 - 116 104 12 116
Other 2 - 2 10 - 10
Horizon Project (2) 2,469 - 2,469 2,252 - 2,252
Midstream 4 - 4 11 - 11
Head office 12 - 12 20 - 20
- --------------------------------------------------------------------------------------------------------------
$ 4,856 $ 11 $ 4,867 $ 5,472 $ 25 $ 5,497
==============================================================================================================
(1) ASSET RETIREMENT OBLIGATIONS, FUTURE INCOME TAX ADJUSTMENTS RELATED TO
DIFFERENCES BETWEEN CARRYING VALUE AND TAX VALUE, AND OTHER FAIR VALUE
ADJUSTMENTS.
(2) NET EXPENDITURES FOR THE HORIZON PROJECT ALSO INCLUDE CAPITALIZED INTEREST
AND STOCK-BASED COMPENSATION.
Property, plant and equipment Total assets
------------------ -------------------
SEP 30 Dec 31 SEP 30 Dec 31
2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------
SEGMENTED ASSETS
North America $ 22,021 $ 21,879 $ 23,465 $ 23,670
North Sea 1,867 2,029 2,103 2,248
Offshore West Africa 1,184 1,204 1,321 1,323
Other 26 24 54 46
Horizon Project 7,819 5,350 7,946 5,444
Midstream 205 207 324 355
Head office 69 74 69 74
- -------------------------------------------------------------------------------------------------------------
$ 33,191 $ 30,767 $ 35,282 $ 33,160
=============================================================================================================
CAPITALIZED INTEREST
The Company capitalizes construction period interest based on Horizon Project
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 nine months
ended September 30, 2007, pre-tax interest of $247 million was capitalized to
the Horizon Project (September 30, 2006 - $130 million).
64 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 September 2007. 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 September 30, 2007:
- --------------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 5.5x
Cash flow from operations (2) 11.1x
- --------------------------------------------------------------------------------
(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 65
===============================================================================
CORPORATE INFORMATION
OFFICERS
Allan P. Markin* Peter J. Janson
CHAIRMAN OF THE BOARD VICE-PRESIDENT, ENGINEERING INTEGRATION
N. Murray Edwards* Christopher M. Kean
VICE-PRESIDENT, UTILITIES & OFFSITES VICE-CHAIRMAN OF THE BOARD
John G. Langille* Philip A. Keele
VICE-CHAIRMAN OF THE BOARD VICE-PRESIDENT, MINING
Steve W. Laut* Cameron S. Kramer
PRESIDENT & CHIEF OPERATING OFFICER VICE-PRESIDENT,
DEVELOPMENT OPERATIONS
Douglas A. Proll*
CHIEF FINANCIAL OFFICER & Richard P. Lock
SENIOR VICE-PRESIDENT, FINANCE VICE-PRESIDENT, BITUMEN PRODUCTION
Real M. Cusson* Leon Miura
SENIOR VICE-PRESIDENT, MARKETING VICE-PRESIDENT, UPGRADING
Real J.H. Doucet* S. John Parr
SENIOR VICE-PRESIDENT, OIL SANDS VICE-PRESIDENT, PRODUCTION - EAST
Allen M. Knight* David A. Payne
SENIOR VICE-PRESIDENT, INTERNATIONAL & CORPORATE VICE-PRESIDENT, EXPLOITATION - EAST
DEVELOPMENT
Tim S. McKay* Bill R. Peterson
SENIOR VICE-PRESIDENT, OPERATIONS VICE-PRESIDENT, PRODUCTION - WEST
Lyle G. Stevens* John C. Puckering
SENIOR VICE-PRESIDENT, EXPLOITATION VICE-PRESIDENT, SITE DEVELOPMENT
Jeff W. Wilson* Timothy G. Reed
SENIOR VICE-PRESIDENT, EXPLORATION VICE-PRESIDENT, HUMAN RESOURCES
Corey B. Bieber Sheldon L. Schroeder
VICE-PRESIDENT, FINANCE & INVESTOR RELATIONS VICE-PRESIDENT, PROJECT CONTROL
Jeffery J. Bergeson Ken W. Stagg
VICE-PRESIDENT, EXPLOITATION - WEST VICE-PRESIDENT, EXPLORATION - WEST
Mary-Jo E. Case* Scott G. Stauth
VICE-PRESIDENT, LAND VICE-PRESIDENT, FIELD OPERATIONS
William R. Clapperton Steve C. Suche
VICE-PRESIDENT, REGULATORY, STAKEHOLDER & VICE-PRESIDENT,
ENVIRONMENTAL AFFAIRS INFORMATION & CORPORATE SERVICES
James F. Corson Domenic Torriero
VICE-PRESIDENT, HUMAN RESOURCES, HORIZON VICE-PRESIDENT, EXPLORATION - CENTRAL
Randall S. Davis* Grant M. Williams
VICE-PRESIDENT, FINANCE & ACCOUNTING VICE-PRESIDENT, EXPLORATION - EAST
Allan E. Frankiw Lynn M. Zeidler
VICE-PRESIDENT, PRODUCTION - CENTRAL VICE-PRESIDENT,
HORIZON CONSTRUCTION MANAGEMENT
Larry C. Galea
VICE-PRESIDENT, EXPLOITATION - CENTRAL Bruce E. McGrath
CORPORATE SECRETARY
Jerry W. Harvey
VICE-PRESIDENT, COMMERCIAL OPERATIONS
*Management Committee
66 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
STOCK LISTING BOARD OF DIRECTORS
Toronto Stock Exchange Catherine M. Best
Trading Symbol - CNQ N. Murray Edwards
Honourable Gary A. Filmon, P.C., O.M.
New York Stock Exchange Ambassador Gordon D. Giffin
Trading Symbol - CNQ John G. Langille
Steve W. Laut
Keith A.J. MacPhail
REGISTRAR AND TRANSFER AGENT Allan P. Markin
Computershare Trust Company of Canada Norman F. McIntyre
CALGARY, ALBERTA Honourable Frank J. McKenna, P.C., O.N.B., Q.C.
TORONTO, ONTARIO James S. Palmer, C.M., A.O.E., Q.C.
Computershare Investor Services LLC Eldon R. Smith, M.D.
NEW YORK, NEW YORK David A. Tuer
INTERNATIONAL OPERATIONS
CNR International (U.K.) Limited
Aberdeen, Scotland
INVESTOR RELATIONS
Telephone: (403) 514-7777
Facsimile: (403) 514-7888
Email: ir@cnrl.com
Website: www.cnrl.com
CANADIAN NATURAL RESOURCES LIMITED 67
===============================================================================
C A N A D I A N N A T U R A L R E S O U R C E S L I M I T E D
2500, 855 - 2 Street S.W.,
Calgary, Alberta T2P 4J8 Telephone: (403)
517-6700 Facsimile: (403) 517-7350
Email: ir@cnrl.com
Website: www.cnrl.com
Printed in Canada