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[PHOTOGRAPHS OMITTED] [LOGO OMITTED]
CANADIAN NATURAL
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Second Quarter Report
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Six months ended | | |
June 30, 2007 | Discipline | Opportunity | Strategy
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CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES
RECORD PRODUCTION IN THE FIRST SIX MONTHS
Commenting on second quarter 2007 results, Canadian Natural's Chairman, Allan
Markin stated, "As we exit the first half of the year, we continue with our
defined plan to manage costs while maximizing value. On the conventional side,
the strength of our natural gas program and the quality of our assets was
demonstrated through a very productive winter drilling program and successes
from a variety of wells that have performed above expectations. Our crude oil
program also continues to deliver with solid results in North America. Looking
to Horizon, at 75% complete, we remain on track for targeted start-up in the
third quarter of 2008 and maintain our focus on execution. "
John Langille, Vice Chairman, stated, "The Company generated a record cash flow
of just over $3.1 billion in the first half of 2007. Heavy crude oil
differentials widened from Q1/07 but were favorable in Q2/07 considering the
significant heavy crude oil conversion capacity shut downs in the US Midwest.
The differentials continue to be positively impacted by the pipeline reversals
to the Gulf Coast and our marketing of blended products. This reaffirms our
belief that our marketing strategy is effective. Our active commodity hedge
program underpins our cash flows during the Horizon Project construction period
and reduces downside exposure in today's volatile commodity markets."
Steve Laut, President and Chief Operating Officer of Canadian Natural commented
"In the first half of 2007 we demonstrated the strength and quality of our
asset base as well as our ability to effectively allocate capital to those
activities that maximize value. At present, returns and recycle ratios for
crude oil are significantly higher than those for natural gas, and therefore
crude oil will continue to be the focus of our capital program for the
remainder of the year. The high grading of our natural gas inventory has
resulted in better than expected natural gas production; however, with minimal
scheduled drilling for the remainder of the year, natural gas production will
decline somewhat in the second half of 2007. Crude oil production remained
strong throughout Q2/07 with volumes expected to grow from Q2/07 to Q3/07 as
our thermal projects come off a steaming cycle."
HIGHLIGHTS
Three Months Ended Six Months Ended
---------------- ----------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
($ millions, except as noted) 2007 2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------------------
Net earnings $ 841 $ 269 $ 1,038 $ 1,110 $ 1,095
per common share, basic and diluted $ 1.56 $ 0.50 $ 1.93 $ 2.06 $ 2.04
Adjusted net earnings from operations (1) $ 595 $ 621 $ 514 $ 1,216 $ 782
per common share, basic and diluted $ 1.10 $ 1.15 $ 0.96 $ 2.25 $ 1.46
Cash flow from operations (2) $ 1,513 $ 1,622 $ 1,287 $ 3,135 $ 2,326
per common share, basic and diluted $ 2.81 $ 3.01 $ 2.40 $ 5.82 $ 4.33
Capital expenditures, net of dispositions $ 1,460 $ 2,009 $ 1,558 $ 3,469 $ 3,867
Daily production, before royalties
Natural gas (mmcf/d) 1,722 1,717 1,475 1,719 1,456
Crude oil and NGLs (bbl/d) 327,494 327,001 338,852 327,249 331,299
Equivalent production (boe/d) 614,461 613,114 584,611 613,790 573,879
===================================================================================================================================
(1) ADJUSTED NET EARNINGS FROM OPERATIONS IS A NON-GAAP TERM THAT THE COMPANY
UTILIZES TO EVALUATE ITS PERFORMANCE. THE DERIVATION OF THIS ITEM IS
DISCUSSED IN THE MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A").
(2) CASH FLOW FROM OPERATIONS IS A NON-GAAP TERM THAT THE COMPANY CONSIDERS
KEY AS IT DEMONSTRATES THE COMPANY'S ABILITY TO FUND CAPITAL REINVESTMENT
AND DEBT REPAYMENT. THE DERIVATION OF THIS ITEM IS DISCUSSED IN THE MD&A.
o Natural gas production volumes remained strong and represented 47% of the
Company's total production. Natural gas production for Q2/07 averaged
1,722 mmcf/d, up 17% from 1,475 mmcf/d for Q2/06 and up marginally from
1,717 mmcf/d for Q1/07. Volumes in Q2/07 reflected better than expected
production from a number of wells, the addition of Anadarko Canada
acquisition volumes, and continued high-grading of opportunities. Stronger
production has resulted in Canadian Natural exceeding Q2/07 guidance.
o Annual natural gas production guidance has been increased to reflect the
volumes recorded during the first half of 2007.
o Total crude oil and NGLs production for Q2/07 was at the top end of
guidance for the quarter at 327,494 bbl/d. Q2/07 production was 3% lower
from Q2/06 of 338,852 bbl/d and was comparable to 327,001 bbl/d for Q1/07.
Volumes are expected to increase in Q3/07 as a number of thermal wells
transition from steam cycles to production cycles.
o Quarterly cash flow was $1.5 billion, a decrease of 7% from Q1/07 and an
increase of 18% from Q2/06. The increase from Q2/06 primarily reflects
higher after-hedging commodity realizations year over year, whereas the
decrease from Q1/07 primarily represents wider heavy crude oil
differentials and lower natural gas pricing. Cash flow in Q2/07 was
negatively impacted by the strengthening Canadian dollar to US dollar
average exchange rate of US$0.9112 compared with US$0.8535 for Q1/07 and
US$0.8918 for Q1/06.
o Q2/07 achieved quarterly net earnings of $841 million, a 213% increase
from Q1/07 and a 19% decrease from Q2/06. The quarterly adjusted net
earnings from operations for Q2/07 were $595 million, a 4% decrease from
Q1/07 results and a 16% increase from Q2/06. o
2 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
o Completed the Q2/07 North American drilling program targeting 78 net crude
oil wells and 7 net natural gas wells, excluding stratigraphic test and
service wells, with a 95% success ratio. The success rate is a reflection
of Canadian Natural's strong, predictable, low-risk asset base. Crude oil
drilling activity remained unchanged from Q2/06. Natural gas drilling
decreased by 85% compared to Q2/06, 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
12.6 million net acres - a key asset for continued growth.
o Primary heavy crude oil production increased by approximately 3,500 bbl/d
in Q2/07 from Q1/07 levels due to stronger production results,
recompletions and workovers, and increased drilling activity levels.
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 34,000
bbl/d during the quarter, up 12% or approximately 4,000 bbl/d from Q2/06.
Production is targeted to continue to increase throughout the remainder of
2007.
o Secured a deep water drilling rig for the Baobab Field. The equipment will
be mobilized in late 2007 or first half 2008, enabling work to begin on
the restoration of shut-in production. It is targeted that 3 of the 5
shut-in Baobab wells should come back on stream over the course of 2008.
o The Horizon Oil Sands Project ("Horizon Project") exited Q2/07 75%
complete and on track for a targeted Q3/08 start-up.
o Declared a quarterly cash dividend on common shares of C$0.085 per common
share, payable July 1, 2007, 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
-----------------------------------------------------
NET UNDEVELOPED LAND DRILLING ACTIVITY
AS AT SIX MONTHS ENDED
JUN 30, 2007 JUN 30, 2007
(THOUSANDS OF NET ACRES) (NET WELLS)
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Canadian conventional
Northeast British Columbia 2,462 50
Northwest Alberta 1,523 88
Northern Plains 6,578 347
Southern Plains 907 28
Southeast Saskatchewan 122 10
In-situ Oil Sands 406 155
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11,998 678
Horizon Oil Sands Project 115 98
United Kingdom North Sea 298 5
Offshore West Africa 206 2
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12,617 783
================================================================================================================
NOTE: DRILLING ACTIVITY INCLUDES STRATIGRAPHIC TEST AND SERVICE WELLS
DRILLING ACTIVITY (NUMBER OF WELLS)
Six Months Ended Jun 30
------------------------
2007 2006
GROSS NET Gross Net
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Crude oil 290 271 196 171
Natural gas 254 207 616 483
Dry 74 64 80 68
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Subtotal 618 542 892 722
Stratigraphic test / service wells 241 241 310 309
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Total 859 783 1,202 1,031
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Success rate (excluding stratigraphic test / service wells) 88% 91%
==============================================================================================================
4 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
NORTH AMERICA CONVENTIONAL
NORTH AMERICA NATURAL GAS
Three Months Ended Six Months Ended
-------------- ---------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
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Natural gas production (mmcf/d) 1,696 1,694 1,448 1,694 1,430
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Net wells targeting natural gas 7 245 48 252 547
Net successful wells drilled 6 201 43 207 483
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Success rate 86% 82% 90% 82% 88%
=======================================================================================================================
o Q2/07 North America natural gas production increased 17% over Q2/06 and
was comparable to Q1/07. The increase reflects completion of a successful
winter drilling program and the continued high-grading of assets in
conjunction with a focused drilling program. Production will decline
somewhat in the second half of the year as a result of 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 7 net natural gas wells in Q2/07 including 2
wells in the Northern Plains region, 4 wells in the Northwest Alberta
region and 1 well in the Southern Plains region, with an overall success
rate of 86%. This compares to 48 net targeted natural gas wells in Q2/06,
an 85% reduction from Q2/06 to Q2/07.
o Planned drilling activity for Q3/07 includes 121 targeted natural gas
wells, comparable to the Q3/06 drilling activity of 111 targeted natural
gas wells.
o The Company has seen decreased third party service costs along with
productivity gains as a result of the industry-wide trend towards scaling
back natural gas drilling within the Western Canadian Sedimentary Basin
(WCSB).
NORTH AMERICA CRUDE OIL AND NGLS
Three Months Ended Six Months Ended
--------------- ---------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
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Crude oil and NGLs production (bbl/d) 240,420 237,489 234,780 238,962 228,901
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Net wells targeting crude oil 78 207 78 285 168
Net successful wells drilled 75 191 76 266 164
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Success rate 96% 92% 97% 93% 98%
==============================================================================================================================
o Q2/07 North America crude oil and NGLs production increased 1% from Q1/07
and increased 2% over Q2/06 levels. Conventional heavy crude oil and
Pelican Lake crude oil experienced solid performance and production
growth that offset the slight decrease in thermal volumes for Q2/07,
which was largely a result of the timing of the normal steaming cycle.
o During Q2/07, drilling activity included 22 net wells targeting heavy
crude oil, 40 net wells targeting Pelican Lake crude oil, 14 net wells
targeting thermal crude oil and 2 net wells targeting light crude oil.
CANADIAN NATURAL RESOURCES LIMITED 5
===============================================================================
o The Primrose East Expansion, a new facility located 15 kilometres from
the existing Primrose South steam plant and 25 kilometres 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.
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.
o In early 2007, Canadian Natural issued its proposed third phase of the
conventional expansion plan with a development plan for the 30,000 bbl/d
Kirby In-Situ Oil Sands Project located approximately 85 km northeast of
Lac La Biche in the Regional Municipality of Wood Buffalo. The Company is
targeting to file its formal regulatory application documents for this
project in the latter half of 2007. Final corporate sanction may depend
upon the results of potential changes to royalty regimes and
environmental regulations, and their associated costs.
o Development of new pads and secondary recovery conversion projects at
Pelican Lake continued as expected throughout the Q2/07. Drilling
consisted of 40 horizontal wells, with plans to drill 52 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 34,000 bbl/d for Q2/07 compared to
approximately 30,000 bbl/d for Q2/06.
o Conventional heavy crude oil production volumes increased by
approximately 3,500 bbl/d in Q2/07 from Q1/07 due to increased drilling
activity levels, recompletions and workovers that commenced during the
second half of 2006 as a result of the narrowing heavy crude oil
differential.
o Planned drilling activity for Q3/07 includes 147 net crude oil wells,
excluding stratigraphic test and service wells.
POTENTIAL CHANGES TO LEGISLATION
o The Alberta provincial government is currently reviewing its crude oil
and natural gas royalty regime. The results of this review, which are not
determinable at this date, are expected in the fall of 2007 and may place
additional costs on the crude oil and natural gas industry.
o The crude oil and natural gas industry is also experiencing cost
pressures related to changes 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. Additional
requirements resulting from greenhouse gas legislation will add to the
cost of executing projects company wide.
6 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
INTERNATIONAL
The Company operates in the North Sea and Offshore West Africa where production
of lighter quality crude oil is targeted in conjunction with natural gas that
may be produced in association with crude oil production.
Three Months Ended Six Months Ended
----------------- --------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
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Crude oil production (bbl/d)
North Sea 57,286 61,869 63,703 59,565 62,261
Offshore West Africa 29,788 27,643 40,369 28,722 40,137
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Natural gas production (mmcf/d)
North Sea 15 15 17 15 17
Offshore West Africa 11 8 10 10 9
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Net wells targeting crude oil 3.1 2.0 2.8 5.1 7.0
Net successful wells drilled 3.1 2.0 2.8 5.1 7.0
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Success rate 100% 100% 100% 100% 100%
===========================================================================================================================
NORTH SEA
o Canadian Natural continues to execute its exploitation strategy in the
North Sea. The first ongoing stage of this exploitation program is based
upon optimizing existing facilities and waterfloods. The second stage of
exploitation incorporates more near pool development and exploration in
order to maximize utilization of the common facilities and ultimately
extend all fields' economic lives. Ongoing development at Ninian, the
Columba Terraces and the Lyell Field continued in Q2/07.
o In Q2/07, 1.9 net crude oil wells were drilled along with 1.8 net water
injectors, with an additional 1.9 net wells drilling at the end of the
quarter.
o The development of the Lyell Field continued with the first well onstream
in Q2 through the existing infrastructure. A second well is scheduled for
completion in early Q3/07. Tranche 1 of the development comprises two
production wells in 2007, and an additional one production well and one
well workover in 2008.
o Construction of the Columba E raw water injection facilities continued
during the quarter. During Q2/07, commissioning of the facilities was
completed and 2 water injection wells were delivered, allowing water
injection into the reservoir to commence.
o Completed the successful Ninian Central platform turnaround in Q2/07.
Planned platform shutdowns are scheduled for Q3/07 at Ninian, B-Block and
T-Block, which will impact production in the third quarter.
OFFSHORE WEST AFRICA
o During Q2/07, 1.2 net wells were drilled with 0.6 additional net wells
drilling at the end of the quarter.
o First crude oil from West Espoir commenced production in mid 2006 with 3
production wells and 2 injector wells, followed by an additional
production well in Q1/07. During Q2/07, 2 additional production wells
were added. The West Espoir area has seen favorable production growth and
development drilling is continuing until 2008 with producers and
injectors being brought on-line as they are completed.
o A deep water drilling rig has been secured for the Baobab Field. The rig
will be mobilized in late 2007 or first half 2008 with the Company
targeting to bring 3 of 5 of the shut-in Baobab wells back into
production over the course of 2008.
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 scheduled to commence in Q2/08 and first crude oil is targeted
for late 2008. Production is targeted to plateau at approximately 20,000
bbl/d.
CANADIAN NATURAL RESOURCES LIMITED 7
===============================================================================
HORIZON PROJECT
o Canadian Natural achieved a major milestone on the Horizon Project during
Q2/07, with overall work progress at the end of the quarter reaching 75%
complete and field construction approaching two thirds complete. All
major vessels have either been erected or are currently on site. Work
scheduled for the coming months will 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 start-up in the third
quarter of 2008. Project progress slowed slightly during the quarter due
in part to labour productivity, the temporary work shut down on the tank
farm and delays associated with a realignment of certain contract
packages to match scope to the marketplace contractor supply to better
manage costs.
o Despite the challenges of a construction market in Alberta operating at
high capacity, the Company has been able to build the on-site manpower to
over 7,000 personnel. With the success of the Fly-In Fly-Out program and
Managed Open Site policy Canadian Natural has been able to add workers as
required.
o Management of costs continues to be a focus for the team and the Horizon
Project currently remains within the Company's forecast estimate of 5% to
12% above the original $6.8 billion Board Authorization for construction
capital spending.
o The quarterly update for Phase 1 of the Horizon Project is as follows:
--------------------------
PROJECT STATUS SUMMARY JUN 30, 2007 Sep 30, 2007
ACTUAL Plan Plan
- ------------------------------------------------------------------------------------------------------
Phase 1 - Work progress (cumulative) 75% 77% 88%
Phase 1 - Construction capital spending (cumulative)* 79% 77% 85%
======================================================================================================
* RELATES TO OVERALL PHASE 1 CONSTRUCTION CAPITAL OF $6.8 BILLION.
ACCOMPLISHED DURING Q2/07
Detailed Engineering
- --------------------
o Overall detailed engineering 97% complete and substantially complete in
most areas.
Procurement
- -----------
o Overall procurement progress is 95% complete.
o Have awarded over $5.4 billion in purchase orders and contracts to date.
o Delivered to site over 30,000 standard loads.
o Operations and maintenance service and supply agreements are in
negotiation.
Modularization
- --------------
o Delivered an additional 172 oversized loads to site during the quarter
for a total of 1,424 loads, which represents approximately 86% of the
total requirement.
Construction
- ------------
o Overall construction progress is 63% complete.
o Mine overburden removal has moved over 37 million bank cubic meters,
which represents approximately 54% of the total to be moved and is 1%
ahead of schedule.
o Construction of cofferdam for the Tar River Diversion completed in
Mining.
o Fabrication of Crushing Plants, Surge Facility and Conveyor Structure is
100% complete in the Ore Preparation Plant.
o Started erection of Conveyors in Ore Preparation.
o Completed Hot Water Tank in Extraction.
o Hydro-tested Primary Separation Cells and Hot Water Tank.
8 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
o Completed construction and hydro-testing of Inclined Plate Settlers in
Froth Treatment.
o Flare Stacks installed in Upgrading.
o Mechanically completed cooling tower piping.
o Mechanically completed Inhibited Water and Cooling Water Pumphouse
buildings.
o 42" Water Pipeline completed.
o Wet Gas Compressor received and installed.
o Completed installation of Coker and Diluent Recovery Unit process
structures.
o Completed interconnecting welding of Primary Upgrading's piperacks.
o Energize main electrical substations R1/R2.
MILESTONES FOR THE THIRD QUARTER OF 2007
o Complete construction of Raw Water Pond.
o Extraction plant hydro-testing.
o Start of pre-commissioning activities in all Bitumen Production Areas.
o Permanent Power energized in R1/R2 corridors pump houses.
o Electrically energize Main Electrical Substation.
o Start commissioning of Recycle Water Pond.
OPERATIONS READINESS
o Canadian Natural is also well into the planning for commissioning and
start-up. The commissioning plans are established to identify the
priority systems that will be required later this year and early in 2008.
The Company is currently hiring and training operating personnel, setting
up procedures and systems and continues to develop the start-up
strategies to ensure the Horizon Project stays on track for first crude
oil.
CANADIAN NATURAL RESOURCES LIMITED 9
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MARKETING Three Months Ended Six Months Ended
-------------- ---------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- ---------------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs pricing
WTI(1) benchmark price (US$/bbl) $ 65.02 $ 58.23 $ 70.70 $ 61.64 $ 67.14
Lloyd Blend Heavy oil differential from WTI (%) 30% 27% 25% 29% 35%
Corporate average pricing before risk
management (C$/bbl) $ 53.74 $ 51.71 $ 60.05 $ 52.72 $ 52.22
Natural gas pricing
AECO benchmark price (C$/GJ) $ 6.99 $ 7.07 $ 5.95 $ 7.03 $ 7.37
Corporate average pricing before risk
management (C$/mcf) $ 7.44 $ 7.74 $ 6.16 $ 7.59 $ 7.21
=================================================================================================================================
(1) REFERS TO WEST TEXAS INTERMEDIATE CRUDE OIL BARREL PRICED AT CUSHING,
OKLAHOMA.
o In Q2/07, the Company experienced a widening of the Lloyd Blend heavy
crude oil differential of WTI to 30% due to refinery conversion capacity
outages, which for Q2/07 represented approximately 150,000 bbl/d of heavy
crude oil refining capacity shut downs in PADD II. Given the level of
reduced conversion capacity the Company believes a 30% differential of
WTI to be favorable, considering past history for similar outages.
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, which receives a premium to the Lloyd Blend price.
For Q2/07, the Mayan differential to WTI averaged $12.45/bbl or 19%.
o During Q2/07, 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 Fluctuations in North American natural gas prices from comparable periods
in 2006 related to weather and storage levels.
10 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
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 614,400 boe/d in Q2/07, comprised of approximately 47%
natural gas and 53% crude oil - with 95% of production located in G7
countries with stable and secure economies.
-- Financial stability and liquidity - first half cash flow of $3.1
billion, available unused bank lines of $1.4 billion at June 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 Declared a quarterly cash dividend on common shares of C$0.085 per common
share, payable July 1, 2007, a 13% increase over the 2006 quarterly
dividend.
OUTLOOK
The Company forecasts 2007 production levels before royalties to average
between 1,649 and 1,688 mmcf/d of natural gas and between 322,000 and 348,000
bbl/d of crude oil and NGLs. Q3/07 production guidance before royalties is
forecast to average between 1,632 and 1,669 mmcf/d of natural gas and between
331,000 and 349,000 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/.
CANADIAN NATURAL RESOURCES LIMITED 11
===============================================================================
MANAGEMENT'S DISCUSSION AND ANALYSIS
FORWARD-LOOKING STATEMENTS
Certain statements in this document or documents incorporated herein by
reference for Canadian Natural Resources Limited (the "Company") may constitute
"forward-looking statements" within the meaning of the United States Private
Litigation Reform Act of 1995. These forward-looking statements can generally
be identified as such because of the context of the statements including words
such as the Company "believes", "anticipates", "expects", "plans", "estimates",
"targets", or words of a similar nature.
The forward-looking statements are based on current expectations and are
subject to known and unknown risks, uncertainties and other factors that may
cause the actual results, performance or achievements of the Company, or
industry results, to be materially different from any future results,
performance or achievements expressed or implied by such forward-looking
statements. Such factors include, among others: general economic and business
conditions which will, among other things, impact demand for and market prices
of the Company's products; foreign currency exchange rates; economic conditions
in the countries and regions in which the Company conducts business; political
uncertainty, including actions of or against terrorists, insurgent groups or
other conflict including conflict between states; industry capacity; ability of
the Company to implement its business strategy, including exploration and
development activities; impact of competition, availability and cost of
seismic, drilling and other equipment; ability of the Company to complete its
capital programs; ability of the Company to transport its products to market;
potential delays or changes in plans with respect to exploration or development
projects or capital expenditures; ability of the Company to attract the
necessary labour required to build its projects; operating hazards and other
difficulties inherent in the exploration for and production and sale of crude
oil and natural gas; availability and cost of financing; success of exploration
and development activities; timing and success of integrating the business and
operations of acquired companies; production levels; uncertainty of reserve
estimates; actions by governmental authorities; government regulations and the
expenditures required to comply with them (especially safety and environmental
laws and regulations); asset retirement obligations; and other circumstances
affecting revenues and expenses. The impact of any one factor on a particular
forward-looking statement is not determinable with certainty as such factors
are interdependent upon other factors, and the Company's course of action would
depend upon its assessment of the future considering all information then
available.
Disclosure related to 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.
12 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
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 six months ended June 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 six and three months ended June
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 six and three months ended June 30, 2007 in relation to the comparable
periods in 2006 and the first quarter of 2007. The accompanying tables form an
integral part of this MD&A. This MD&A is dated July 31, 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.
CANADIAN NATURAL RESOURCES LIMITED 13
===============================================================================
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Six Months Ended
--------------- ---------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 (1) 2007 2006 (1)
- ----------------------------------------------------------------------------------------------------------------------------
Revenue, before royalties $ 3,152 $ 3,118 $ 3,041 $ 6,270 $ 5,709
Net earnings $ 841 $ 269 $ 1,038 $ 1,110 $ 1,095
Per common share - basic and diluted $ 1.56 $ 0.50 $ 1.93 $ 2.06 $ 2.04
Adjusted net earnings from operations (2) $ 595 $ 621 $ 514 $ 1,216 $ 782
Per common share - basic and diluted $ 1.10 $ 1.15 $ 0.96 $ 2.25 $ 1.46
Cash flow from operations (3) $ 1,513 $ 1,622 $ 1,287 $ 3,135 $ 2,326
Per common share - basic and diluted $ 2.81 $ 3.01 $ 2.40 $ 5.82 $ 4.33
Capital expenditures, net of dispositions $ 1,460 $ 2,009 $ 1,558 $ 3,469 $ 3,867
============================================================================================================================
(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 TERM THAT REPRESENTS
NET EARNINGS ADJUSTED FOR CERTAIN ITEMS OF A NON-OPERATIONAL NATURE. THE
COMPANY EVALUATES ITS PERFORMANCE BASED ON ADJUSTED NET EARNINGS FROM
OPERATIONS. THE FOLLOWING RECONCILIATION LISTS THE AFTER-TAX EFFECTS OF
CERTAIN ITEMS OF A NON-OPERATIONAL NATURE THAT ARE INCLUDED IN THE
COMPANY'S FINANCIAL RESULTS. ADJUSTED NET EARNINGS FROM OPERATIONS MAY NOT
BE COMPARABLE TO SIMILAR MEASURES PRESENTED BY OTHER COMPANIES.
THREE MONTHS ENDED SIX MONTHS ENDED
----------- ------------
JUN 30 MAR 31 JUN 30 JUN 30 JUN 30
($ MILLIONS) 2007 2007 2006 2007 2006
---------------------------------------------------------------------------------------------------------------------
NET EARNINGS AS REPORTED $ 841 $ 269 $ 1,038 $ 1,110 $ 1,095
STOCK-BASED COMPENSATION EXPENSE (RECOVERY), NET OF TAX(A) 74 17 (21) 91 67
UNREALIZED RISK MANAGEMENT (GAIN) LOSS, NET OF TAX(B) (35) 362 (17) 327 (12)
UNREALIZED FOREIGN EXCHANGE GAIN, NET OF TAX(C) (214) (27) (48) (241) (40)
EFFECT OF STATUTORY TAX RATE CHANGES ON FUTURE INCOME TAX
LIABILITIES(D) (71) - (438) (71) (328)
---------------------------------------------------------------------------------------------------------------------
ADJUSTED NET EARNINGS FROM OPERATIONS $ 595 $ 621 $ 514 $ 1,216 $ 782
=====================================================================================================================
(a) THE COMPANY'S EMPLOYEE STOCK OPTION PLAN PROVIDES FOR A CASH PAYMENT
OPTION. ACCORDINGLY, THE INTRINSIC VALUE OF THE OUTSTANDING VESTED
OPTIONS IS RECORDED AS A LIABILITY ON THE COMPANY'S BALANCE SHEET AND
PERIODIC CHANGES IN THE INTRINSIC VALUE, NET OF TAXES, FLOW THROUGH
NET EARNINGS, OR ARE CAPITALIZED TO THE HORIZON OIL SANDS PROJECT.
(b) DERIVATIVE FINANCIAL INSTRUMENTS ARE RECORDED AT FAIR VALUE ON THE
BALANCE SHEET, WITH CHANGES IN THE FAIR VALUE OF NON-DESIGNATED
HEDGES, NET OF TAXES, FLOWING THROUGH NET EARNINGS. THE AMOUNTS
ULTIMATELY REALIZED MAY BE MATERIALLY DIFFERENT THAN REFLECTED IN THE
FINANCIAL STATEMENTS DUE TO CHANGES IN PRICES OF THE UNDERLYING ITEMS
HEDGED, PRIMARILY CRUDE OIL AND NATURAL GAS.
(c) UNREALIZED FOREIGN EXCHANGE GAINS AND LOSSES RESULT PRIMARILY FROM THE
TRANSLATION OF US DOLLAR DENOMINATED LONG-TERM DEBT TO PERIOD-END
EXCHANGE RATES AND ARE IMMEDIATELY RECOGNIZED IN NET EARNINGS.
(d) ALL SUBSTANTIVELY ENACTED ADJUSTMENTS IN APPLICABLE INCOME TAX RATES
ARE APPLIED TO UNDERLYING ASSETS AND LIABILITIES ON THE COMPANY'S
BALANCE SHEET IN DETERMINING FUTURE INCOME TAX ASSETS AND LIABILITIES.
THE IMPACT OF THESE TAX RATE CHANGES IS RECORDED IN NET EARNINGS
DURING THE PERIOD THE LEGISLATION IS SUBSTANTIVELY ENACTED. INCOME TAX
RATE CHANGES 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 $438 MILLION IN NORTH AMERICA.
14 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
(3) CASH FLOW FROM OPERATIONS IS A NON-GAAP TERM THAT REPRESENTS NET EARNINGS
ADJUSTED FOR NON-CASH ITEMS. THE COMPANY EVALUATES ITS PERFORMANCE BASED ON
CASH FLOW FROM OPERATIONS. THE COMPANY CONSIDERS CASH FLOW FROM OPERATIONS
A KEY MEASURE AS IT DEMONSTRATES THE COMPANY'S ABILITY TO GENERATE THE CASH
FLOW NECESSARY TO FUND FUTURE GROWTH THROUGH CAPITAL INVESTMENT AND TO
REPAY DEBT. CASH FLOW FROM OPERATIONS MAY NOT BE COMPARABLE TO SIMILAR
MEASURES PRESENTED BY OTHER COMPANIES.
THREE MONTHS ENDED SIX MONTHS ENDED
-------------- --------------
JUN 30 MAR 31 JUN 30 JUN 30 JUN 30
($ MILLIONS) 2007 2007 2006 2007 2006
---------------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 841 $ 269 $ 1,038 $ 1,110 $ 1,095
NON-CASH ITEMS:
DEPLETION, DEPRECIATION AND AMORTIZATION 720 709 557 1,429 1,078
ASSET RETIREMENT OBLIGATION ACCRETION 17 18 16 35 33
STOCK-BASED COMPENSATION EXPENSE 106 25 (34) 131 98
UNREALIZED RISK MANAGEMENT (GAIN) LOSS (57) 536 (26) 479 (18)
UNREALIZED FOREIGN EXCHANGE (GAIN) LOSS (250) (32) (58) (282) (48)
DEFERRED PETROLEUM REVENUE TAX (RECOVERY) EXPENSE 20 (3) 18 17 44
FUTURE INCOME TAX EXPENSE (RECOVERY) 116 100 (224) 216 44
---------------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS $ 1,513 $ 1,622 $ 1,287 $ 3,135 $ 2,326
===========================================================================================================================
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
For the six months ended June 30, 2007, the Company reported net earnings of
$1,110 million compared to net earnings of $1,095 million for the six months
ended June 30, 2006. Net earnings for the six months ended June 30, 2007
included unrealized after-tax expenses of $106 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 $313
million for the six months ended June 30, 2006. Excluding these items, adjusted
net earnings from operations for the six months ended June 30, 2007 increased
to $1,216 million from $782 million for the six months ended June 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 and increased depletion,
depreciation and amortization expense.
Net earnings in the second quarter of 2007 were $841 million compared to net
earnings of $1,038 million in the second quarter of 2006 and net earnings of
$269 million in the prior quarter. Net earnings in the second quarter of 2007
included unrealized after-tax income of $246 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 $524 million for
the second quarter of 2006 and net after-tax expenses of $352 million in the
prior quarter. Excluding these items, adjusted net earnings from operations in
the second quarter of 2007 increased to $595 million from $514 million in the
second quarter of 2006, and decreased from $621 million in the prior quarter.
The increase in adjusted net earnings from the second quarter of 2006 was
primarily due to the impact of increased natural gas pricing, increased sales
volumes, and decreased realized risk management losses. These factors were
partially offset by the impact of a stronger Canadian dollar relative to the US
dollar, decreased crude oil pricing related to lower WTI benchmark pricing and
a wider Heavy Crude Oil Differential from WTI ("Heavy Differential"), increased
production expense and increased depletion, depreciation and amortization
expense. The decrease from the prior quarter was primarily due to decreased
natural gas pricing, increased realized risk management losses on crude oil,
and the impact of a stronger Canadian dollar relative to the US dollar,
partially offset by increased crude oil pricing.
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,
CANADIAN NATURAL RESOURCES LIMITED 15
===============================================================================
approximately 60% of expected crude oil volumes and approximately 70% of
expected natural gas volumes are hedged for the remainder of 2007. In addition,
77,000 bbl/d of crude oil volumes are protected by WTI put options for the
remainder of 2007 at a strike price of US$60.00 per barrel.
The Company has hedged 220,000 bbl/d of crude oil volumes for the year 2008. Of
the 220,000 bbl/d, 20,000 bbl/d are hedged by Mayan price collars with a
US$50.00 floor, 150,000 bbl/d are hedged by WTI price collars with a US$60.00
floor and 50,000 bbl/d are hedged by WTI put options with a US$55.00 strike
price. The Company has also entered into an additional 50,000 bbl/d of WTI
price collars with a US$60.00 floor for the first quarter of 2008. In addition,
900,000 GJ/d of natural gas volumes are hedged by AECO price collars for the
first quarter of 2008; 400,000 GJ/d with a $7.00 floor and 500,000 GJ/d with a
$7.50 floor.
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 June 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 $479 million ($327 million after-tax) on its commodity
risk management activities for the six months ended June 30, 2007, including a
$57 million ($35 million after-tax) unrealized gain for the three months ended
June 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 32 of this MD&A.
The Company also recorded a $131 million ($91 million after-tax) stock-based
compensation expense as a result of the 14% increase in the Company's share
price in the six months ended June 30, 2007, and a $106 million ($74 million
after-tax) stock-based compensation expense as a result of the 11% increase in
the Company's share price for the three months ended June 30, 2007 (Company's
share price as at: June 30, 2007 - C$70.78; March 31, 2007 - C$63.75; December
31, 2006 - C$62.15; June 30, 2006 - C$61.72). 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 June 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 June
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 six months ended June 30, 2007 increased to a
record $3,135 million from $2,326 million for the six months ended June 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.
Cash flow from operations for the second quarter of 2007 increased to $1,513
million from $1,287 million for the second quarter of 2006, and decreased from
$1,622 million in the prior quarter. The increase from the second quarter of
2006 was primarily due to the impact of increased natural gas pricing,
increased sales volumes, and decreased realized risk management losses. These
factors were partially offset by the impact of a stronger Canadian dollar
relative to the US dollar, decreased crude oil WTI benchmark pricing and a
wider Heavy Differential, and increased production expense. The decrease from
the prior quarter was primarily due to decreased natural gas pricing, increased
realized risk management losses on crude oil, and the impact of a stronger
Canadian dollar relative to the US dollar, partially offset by increased crude
oil pricing.
16 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
Total production before royalties increased 7% to average 613,790 boe/d for the
six months ended June 30, 2007 from 573,879 boe/d for the six months ended June
30, 2006. Production for the second quarter of 2007 increased 5% to 614,461
boe/d from 584,611 boe/d in the second quarter of 2006 and was comparable to
613,114 boe/d for the prior quarter.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the eight most
recently completed quarters:
($ millions, except per common share amounts) JUN 30 Mar 31 Dec 31 Sep 30
2007 2007 2006 2006
- ------------------------------------------------------------------------------------------------------------------
Revenue, before royalties (1) $ 3,152 $ 3,118 $ 2,826 $ 3,108
Net earnings $ 841 $ 269 $ 313 $ 1,116
Net earnings per common share
- Basic and diluted $ 1.56 $ 0.50 $ 0.58 $ 2.08
==================================================================================================================
Jun 30 Mar 31 Dec 31 Sep 30
($ millions, except per common share amounts) 2006 2006 2005 2005
- ------------------------------------------------------------------------------------------------------------------
Revenue, before royalties (1) $ 3,041 $ 2,668 $ 3,319 $ 3,163
Net earnings $ 1,038 $ 57 $ 1,104 $ 151
Net earnings per common share
- Basic and diluted $ 1.93 $ 0.11 $ 2.06 $ 0.28
==================================================================================================================
(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 treatment 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 Differential in
North America. Hurricane activity in the Gulf of Mexico in the third
quarter of 2005 further contributed to increased world benchmark crude
oil prices.
o Natural gas pricing. Natural gas prices primarily reflected fluctuations
in demand for natural gas and in inventory storage levels as a result of
milder temperatures experienced during 2007 and 2006 and hurricane
activity in the third quarter of 2005.
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, additional production volumes from the Anadarko
Canada Corporation ("ACC") acquisition completed in the fourth quarter of
2006, development of West and East Espoir, and production from the Baobab
Field located offshore Cote d'Ivoire, which commenced in the third
quarter of 2005.
o Natural gas sales volumes. Natural gas sales volumes reflected additional
natural gas production from the ACC acquisition and internally generated
growth. The increase was partially offset by the production decrease due
to the Company's strategic reduction in natural gas drilling activity
made in response to low natural gas prices in 2006 and inflationary cost
pressures.
o The value of the Canadian dollar relative to the US dollar. A fluctuating
Canadian dollar relative to the US dollar impacted the realized price the
Company received for its crude oil and natural gas sales, as sales prices
are based predominately on US dollar denominated benchmarks.
o Realized and unrealized gains and losses from the mark-to-market
treatment of the Company's commodity and cross currency hedges.
o Jurisdictional tax rate changes substantively enacted in the various
periods.
CANADIAN NATURAL RESOURCES LIMITED 17
===============================================================================
o Unrealized foreign exchange gains and losses due to the fluctuation of
the Canadian dollar in relation to the US dollar with respect to the US
dollar debt balances, UK pounds sterling denominated working capital
balances, as well as the re-measurement of North Sea future income tax
liabilities denominated in UK pounds sterling.
o Unrealized expenses and recoveries due to the mark-to-market treatment 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 Increased production expense primarily due to industry-wide inflationary
cost pressures.
o Increased depletion, depreciation and amortization expense primarily
associated with the ACC acquisition, increased finding and development
costs associated with crude oil and natural gas exploration and increased
estimated future costs to develop the Company's proved undeveloped
reserves.
OPERATING HIGHLIGHTS
Three Months Ended Six Months Ended
-------------- --------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
Sales price (2) $ 53.74 $ 51.71 $ 60.05 $ 52.72 $ 52.22
Royalties 5.46 4.92 5.14 5.19 4.34
Production expense 15.01 13.81 11.92 14.40 11.63
- --------------------------------------------------------------------------------------------------------------------------
Netback $ 33.27 $ 32.98 $ 42.99 $ 33.13 $ 36.25
- --------------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 7.44 $ 7.74 $ 6.16 $ 7.59 $ 7.21
Royalties 1.10 1.48 1.11 1.29 1.40
Production expense 0.89 0.97 0.80 0.93 0.80
- --------------------------------------------------------------------------------------------------------------------------
Netback $ 5.45 $ 5.29 $ 4.25 $ 5.37 $ 5.01
- --------------------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent ($/boe) (1)
Sales price (2) $ 49.70 $ 49.32 $ 50.36 $ 49.50 $ 48.39
Royalties 5.99 6.76 5.80 6.37 6.11
Production expense 10.44 10.10 8.85 10.27 8.66
- --------------------------------------------------------------------------------------------------------------------------
Netback $ 33.27 $ 32.46 $ 35.71 $ 32.86 $ 33.62
==========================================================================================================================
(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.
18 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
BUSINESS ENVIRONMENT
Three Months Ended Six Months Ended
-------------- --------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
WTI benchmark price (US$/bbl) $ 65.02 $ 58.23 $ 70.70 $ 61.64 $ 67.14
Dated Brent benchmark price (US$/bbl) $ 68.74 $ 57.76 $ 69.63 $ 63.28 $ 65.74
Differential to LLB blend (US$/bbl) $ 19.42 $ 15.80 $ 17.79 $ 17.62 $ 23.21
LLB blend differential from WTI (%) 30% 27% 25% 29% 35%
Condensate benchmark price (US$/bbl) $ 65.66 $ 58.78 $ 71.51 $ 62.28 $ 67.59
NYMEX benchmark price (US$/mmbtu) $ 7.56 $ 6.96 $ 6.83 $ 7.26 $ 7.96
AECO benchmark price (C$/GJ) $ 6.99 $ 7.07 $ 5.95 $ 7.03 $ 7.37
US / Cdn dollar average exchange rate (US$) $ 0.9112 $ 0.8535 $ 0.8918 $ 0.8812 $ 0.8786
==========================================================================================================================
COMMODITY PRICES
Crude oil sales contracts in the North America segment are typically based on
WTI benchmark pricing. WTI averaged US$61.64 per bbl for the six months ended
June 30, 2007, a decrease of 8% from US$67.14 per bbl for the six months ended
June 30, 2006. In the second quarter of 2007, WTI averaged US$65.02 per bbl, a
decrease of 8% from US$70.70 per bbl in the second quarter of 2006, and an
increase of 12% from US$58.23 per bbl in the prior quarter. Fluctuations in WTI
pricing in the second quarter were mainly due to continued geopolitical events
causing increased market uncertainty, as well as a series of US refinery
outages resulting in logistical constraints and inventory build up,
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 second quarter of 2007. Dated Brent
("Brent") averaged US$63.28 per bbl for the six months ended June 30, 2007, a
decrease of 4% compared to US$65.74 per bbl for the six months ended June 30,
2006. In the second quarter of 2007, Brent averaged US$68.74 per bbl, a
decrease of 1% compared to US$69.63 per bbl for the second quarter of 2006, and
an increase of 19% from US$57.76 per bbl for the prior quarter. The widening
differential between Brent and WTI was due to strong European and Asian market
demands and logistical constraints at Cushing, Oklahoma, impacting inventory
levels and WTI pricing.
Company-wide, realized crude oil prices for the six months ended June 30, 2007
increased slightly as a result of the narrower Heavy Differential in North
America, partially offset by lower benchmark WTI and Brent pricing. Heavy
Differentials averaged 29% for the six months ended June 30, 2007 compared to
35% for the six months ended June 30, 2006. For the second quarter of 2007,
Heavy Differentials averaged 30% compared to 25% for the second quarter of
2006, and 27% for the prior quarter. The widening of the Heavy Differentials
from the comparable periods was primarily due to reduced US refinery
utilization. Second quarter 2007 realized prices were also impacted by the
stronger Canadian dollar, which decreased the Canadian dollar sales price the
Company received for its crude oil sales, 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$7.26 per mmbtu for the six months ended
June 30, 2007, a decrease of 9% from US$7.96 per mmbtu for the six months ended
June 30, 2006. In the second quarter of 2007, the NYMEX natural gas price
averaged US$7.56 per mmbtu, an increase of 11% from US$6.83 per mmbtu for the
second quarter of 2006, and an increase of 9% from US$6.96 per mmbtu for the
prior quarter. AECO natural gas prices decreased 5% to average $7.03 per GJ for
the six months ended June 30, 2007, compared to $7.37 per GJ for the six months
ended June 30, 2006. In the second quarter of 2007 AECO natural gas prices
averaged $6.99 per GJ, an increase of 17% from $5.95 per GJ in the second
quarter of 2006, and comparable to $7.07 per GJ for the prior quarter.
Fluctuations in natural gas prices from the comparable periods in 2006 were
primarily related to weather and storage levels. Natural gas inventory levels
CANADIAN NATURAL RESOURCES LIMITED 19
===============================================================================
in North America continued to remain high in the second quarter of 2007,
notwithstanding production declines in Canada due to reduced drilling activity,
due to the significant increase in liquefied natural gas imports and stable
production levels in the US.
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 oil and gas industry,
particularly related to natural gas and heavy oil 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. Additional requirements of greenhouse gas
legislation will add to the cost of executing projects company wide.
The Alberta provincial government is currently reviewing the oil and gas
royalty regime, which may result in changes to the Company's royalty
obligations in future years.
The increased cost pressures, the impact of environmental regulations, and the
outcome of the royalty review may adversely impact the Company's future net
earnings, cash flow and capital projects.
20 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
PRODUCT PRICES (1)
Three Months Ended Six Months Ended
--------------- ---------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (2)
North America $ 47.20 $ 46.09 $ 54.94 $ 46.66 $ 45.04
North Sea $ 73.18 $ 68.83 $ 73.19 $ 70.84 $ 70.68
Offshore West Africa $ 72.84 $ 58.60 $ 72.97 $ 65.34 $ 69.10
Company average $ 53.74 $ 51.71 $ 60.05 $ 52.72 $ 52.22
NATURAL GAS ($/mcf) (2)
North America $ 7.47 $ 7.79 $ 6.21 $ 7.62 $ 7.28
North Sea $ 3.92 $ 4.49 $ 2.33 $ 4.21 $ 2.36
Offshore West Africa $ 6.22 $ 5.97 $ 5.30 $ 6.11 $ 5.43
Company average $ 7.44 $ 7.74 $ 6.16 $ 7.59 $ 7.21
COMPANY AVERAGE ($/boe)(2) $ 49.70 $ 49.32 $ 50.36 $ 49.50 $ 48.39
PERCENTAGE OF REVENUE
(excluding midstream revenue)
Crude oil and NGLs 57% 56% 68% 57% 54%
Natural gas 43% 44% 32% 43% 46%
===================================================================================================================
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
The Company's realized crude oil prices increased slightly to average $52.72
per bbl for the six months ended June 30, 2007 from $52.22 per bbl for the six
months ended June 30, 2006. Realized crude oil prices for the second quarter of
2007 decreased 11% to average $53.74 per bbl from $60.05 per bbl for the second
quarter of 2006, and increased 4% from $51.71 per bbl for the prior quarter.
The Company's realized crude oil prices increased slightly from the six months
ended June 30, 2006 primarily as a result of a narrower Heavy Differential,
partially offset by decreased WTI and Brent benchmark pricing.
The Company's realized natural gas price increased 5% to average $7.59 per mcf
for the six months ended June 30, 2007 from $7.21 per mcf for the six months
ended June 30, 2006. In the second quarter of 2007, the Company's realized
natural gas price increased 21% to average $7.44 per mcf from $6.16 per mcf in
the second quarter of 2006, and decreased 4% from $7.74 per mcf for the prior
quarter. Fluctuations in natural gas prices from the comparable periods in 2006
were primarily related to weather and storage levels. The decrease in realized
natural gas prices from the prior quarter primarily reflected normal
seasonality and milder temperatures during 2007, partially offset by the impact
of an overall reduction in natural gas drilling activity in Canada in response
to industry wide inflationary pressures.
NORTH AMERICA
North America realized crude oil prices increased 4% to average $46.66 per bbl
for the six months ended June 30, 2007 from $45.04 per bbl for the six months
ended June 30, 2006. Realized crude oil prices in the second quarter of 2007
averaged $47.20 per bbl, a 14% decrease from $54.94 per bbl for the second
quarter of 2006, and increased 2% from $46.09 per bbl for the prior quarter.
The increase from the six months ended June 30, 2006 was due to a narrower
Heavy Differential, partially offset by a decrease in WTI benchmark pricing.
The decrease in realized crude oil prices from the second quarter of 2006 was
CANADIAN NATURAL RESOURCES LIMITED 21
===============================================================================
due to the widening of the Heavy Differential and the decrease 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 a
stronger Canadian dollar relative to the US dollar.
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
second 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 5% to average $7.62 per mcf
for the six months ended June 30, 2007 from $7.28 per mcf for the six months
ended June 30, 2006. The realized natural gas price in the second quarter of
2007 averaged $7.47 per mcf, an increase of 20% from $6.21 per mcf for the
second quarter of 2006, and decreased 4% from $7.79 per mcf for the prior
quarter. Fluctuations in natural gas prices from the comparable periods in 2006
were primarily related to weather and storage levels. The decrease in realized
natural gas prices from the prior quarter primarily reflected normal
seasonality and milder temperatures during 2007, partially offset by the impact
of an overall reduction in natural gas drilling activity in Canada in response
to industry wide inflationary pressures.
A comparison of the price received for the Company's North America production
by product type is as follows:
-----------------
JUN 30 MAR 31 JUN 30
2007 2007 2006
- ---------------------------------------------------------------------------------------------------------
Wellhead Price (1) (2)
Light / medium crude oil and NGLs (C$/bbl) $ 63.09 $ 59.48 $ 69.25
Pelican Lake crude oil (C$/bbl) $ 44.49 $ 44.44 $ 56.01
Primary heavy crude oil (C$/bbl) $ 42.30 $ 41.83 $ 51.78
Thermal heavy crude oil (C$/bbl) $ 41.09 $ 40.31 $ 47.64
Natural gas (C$/mcf) $ 7.47 $ 7.79 $ 6.21
=========================================================================================================
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
NORTH SEA
North Sea realized crude oil prices increased marginally to average $70.84 per
bbl for the six months ended June 30, 2007 from $70.68 per bbl for the six
months ended June 30, 2006. Realized crude oil prices in the second quarter of
2007 averaged $73.18 per bbl and increased 6% from $68.83 per bbl for the prior
quarter. Realized crude oil prices in the North Sea during the second quarter
continued to benefit from the impact of strong European and Asian demand.
OFFSHORE WEST AFRICA
Offshore West Africa realized crude oil prices decreased 5% to average $65.34
per bbl for the six months ended June 30, 2007 from $69.10 per bbl for the six
months ended June 30, 2006. Realized crude oil prices in the second quarter of
2007 averaged $72.84 per bbl, comparable to $72.97 per bbl for the second
quarter of 2006, and increased 24% from $58.60 per bbl for the prior quarter.
Realized crude oil prices in Offshore West Africa during the second quarter
continued to benefit from the impact of strong European and Asian demand.
22 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
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) JUN 30 2007 Mar 31 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 350,499 401,296 910,796
Offshore West Africa, related to timing of liftings 813,701 230,623 113,774
- ------------------------------------------------------------------------------------------------------------------
2,261,726 1,729,445 2,122,096
==================================================================================================================
In the second quarter of 2007, net production of approximately 530,000 barrels
of crude oil produced in the Company's international operations was deferred and
included in inventory at June 30, 2007, reducing cash flow from operations by
approximately $34 million.
DAILY PRODUCTION, BEFORE ROYALTIES
Three Months Ended Six Months Ended
-------------- --------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 240,420 237,489 234,780 238,962 228,901
North Sea 57,286 61,869 63,703 59,565 62,261
Offshore West Africa 29,788 27,643 40,369 28,722 40,137
- --------------------------------------------------------------------------------------------------------------------
327,494 327,001 338,852 327,249 331,299
- --------------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,696 1,694 1,448 1,694 1,430
North Sea 15 15 17 15 17
Offshore West Africa 11 8 10 10 9
- --------------------------------------------------------------------------------------------------------------------
1,722 1,717 1,475 1,719 1,456
- --------------------------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d) 614,461 613,114 584,611 613,790 573,879
- --------------------------------------------------------------------------------------------------------------------
PRODUCT MIX
Light/medium crude oil and NGLs 23% 24% 26% 24% 27%
Pelican Lake crude oil 6% 5% 5% 5% 5%
Primary heavy crude oil 15% 15% 16% 15% 16%
Thermal heavy crude oil 9% 9% 11% 9% 10%
Natural gas 47% 47% 42% 47% 42%
====================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 23
===============================================================================
DAILY PRODUCTION, NET OF ROYALTIES
Three Months Ended Six Months Ended
-------------- ---------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- ---------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 206,927 204,401 205,674 205,671 199,246
North Sea 57,185 61,754 63,552 59,457 62,131
Offshore West Africa 26,876 25,897 39,335 26,389 39,148
- ---------------------------------------------------------------------------------------------------------------------
290,988 292,052 308,561 291,517 300,525
- ---------------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,444 1,367 1,183 1,406 1,152
North Sea 15 15 17 15 17
Offshore West Africa 10 8 10 9 9
- ---------------------------------------------------------------------------------------------------------------------
1,469 1,390 1,210 1,430 1,178
- ---------------------------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d) 535,789 523,730 510,243 529,793 496,768
=====================================================================================================================
Daily production and per barrel statistics are presented throughout the MD&A on
a "before royalty" or "gross" basis. Production on an "after royalty" or "net"
basis is also presented.
The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces; namely
natural gas, light/medium crude oil and NGLs, Pelican Lake crude oil, primary
heavy crude oil and thermal heavy crude oil.
Total production averaged 613,790 boe/d for the six months ended June 30, 2007,
a 7% increase from the six months ended June 30, 2006. Second quarter total
production in 2007 averaged 614,461 boe/d, an increase of 5% from 584,611 boe/d
for the second quarter of 2006, and was comparable to 613,114 boe/d for the
prior quarter.
Total crude oil and NGLs production for the six months ended June 30, 2007
decreased slightly to 327,249 bbl/d, from 331,299 bbl/d for the six months ended
June 30, 2006. In the second quarter of 2007, production decreased 3% to 327,494
bbl/d from 338,852 bbl/d in the second quarter of 2006 and was comparable to
327,001 bbl/d for the prior quarter. The decrease from the comparable periods of
2006 was primarily due to the timing of planned maintenance activities in the
North Sea and reduced production from the Baobab Field in Offshore West Africa,
partially offset by increased production in North America. Notwithstanding these
factors, crude oil and NGLs production in the second quarter of 2007 was at the
high end of the Company's previously issued guidance of 313,000 to 329,000
bbl/d.
Natural gas production continued to represent the Company's largest product
offering, accounting for 47% of the Company's total production. Natural gas
production for the six months ended June 30, 2007 averaged 1,719 mmcf/d compared
to 1,456 mmcf/d for the six months ended June 30, 2006. In the second quarter of
2007, natural gas production averaged 1,722 mmcf/d compared to 1,475 mmcf/d for
the second quarter of 2006 and 1,717 mmcf/d for the prior quarter. The increase
in natural gas production from the comparable periods in 2006 primarily
reflected the ACC acquisition completed in the fourth quarter of 2006 and the
completion of scheduled natural gas drilling activity in 2007 in advance of
spring break-up. The increase from the comparable periods in 2006 was partially
offset by production declines due to the Company's strategic reduction in
natural gas drilling activity and increased North America crude oil drilling,
made in response to sustained low natural gas prices and inflationary cost
pressures. Second quarter natural gas production was above the Company's
previously issued guidance of 1,677 to 1,698 mmcf/d.
Annual revised production guidance for 2007 is targeted to average between
322,000 and 348,000 bbl/d of crude oil and NGLs and between 1,649 and 1,688
mmcf/d of natural gas. Third quarter 2007 production guidance is targeted to
average between 331,000 and 349,000 bbl/d of crude oil and NGLs and between
1,632 and 1,669 mmcf/d of natural gas.
24 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
NORTH AMERICA
North America crude oil and NGLs production for the six months ended June 30,
2007 increased 4% to average 238,962 bbl/d, up from 228,901 bbl/d for the six
months ended June 30, 2006. Production in the second quarter of 2007 increased
2% to average 240,420 bbl/d from 234,780 bbl/d for the second quarter of 2006,
and increased 1% from 237,489 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 water and polymer flood projects and the ACC
acquisition, partially offset by the timing of steaming cycles related to the
Company's thermal crude oil projects.
North America natural gas production increased 18% to average 1,694 mmcf/d for
the six months ended June 30, 2007 up from 1,430 mmcf/d for the six months ended
June 30, 2006. In the second quarter of 2007, natural gas production increased
17% to 1,696 mmcf/d from 1,448 mmcf/d for the second quarter of 2006, and was
comparable to 1,694 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 and the completion of scheduled natural gas drilling activity in
advance of spring break up. The increase was partially offset by production
declines due to the Company's strategic decision to reduce natural gas drilling
activity.
NORTH SEA
North Sea crude oil production averaged 59,565 bbl/d for the six months ended
June 30, 2007, a decrease of 4% from 62,261 bbl/d for the six months ended June
30, 2006. Crude oil production in the second quarter of 2007 decreased 10% to
57,286 bbl/d from 63,703 bbl/d for the second quarter of 2006 and decreased 7%
from 61,869 bbl/d for the prior quarter. Production levels for the second
quarter of 2007 were in line with expectations and reflected the planned
maintenance shutdowns carried out during the quarter on the water injection
systems on the Ninian platforms.
Crude oil production volumes are anticipated to decrease marginally in the third
quarter of 2007 due to planned maintenance shutdowns at Ninian North, Ninian
Central, T-Block and B-Block.
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production decreased 28% to average 28,722 bbl/d
for the six months ended June 30, 2007 from 40,137 bbl/d for the six months
ended June 30, 2006. Second quarter 2007 production decreased 26% to 29,788
bbl/d from 40,369 bbl/d for the second quarter of 2006, and increased 8% from
27,643 bbl/d for the prior quarter. Second quarter production decreased from the
comparable period 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 for mobilization expected in late 2007 or
early 2008 that should enable the Company to execute its defined plan to
determine the cause of the sand screen failings and may return certain of these
shut-in wells to production over the course of 2008.
CANADIAN NATURAL RESOURCES LIMITED 25
===============================================================================
ROYALTIES
Three Months Ended Six Months Ended
---------------- --------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 6.58 $ 6.42 $ 6.81 $ 6.50 $ 5.77
North Sea $ 0.13 $ 0.13 $ 0.17 $ 0.13 $ 0.15
Offshore West Africa $ 7.12 $ 3.70 $ 1.87 $ 5.32 $ 1.71
Company average $ 5.46 $ 4.92 $ 5.14 $ 5.19 $ 4.34
NATURAL GAS ($/mcf) (1)
North America $ 1.11 $ 1.50 $ 1.13 $ 1.30 $ 1.43
North Sea $ - $ - $ - $ - $ -
Offshore West Africa $ 0.59 $ 0.38 $ 0.14 $ 0.50 $ 0.13
Company average $ 1.10 $ 1.48 $ 1.11 $ 1.29 $ 1.40
COMPANY AVERAGE ($/boe) (1) $ 5.99 $ 6.76 $ 5.80 $ 6.37 $ 6.11
PERCENTAGE OF REVENUE (2)
Crude oil and NGLs 10% 10% 9% 10% 8%
Natural gas 15% 19% 18% 17% 20%
Boe 12% 14% 12% 13% 13%
==========================================================================================================================
(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.
26 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
NORTH AMERICA
North America crude oil and NGLs royalties per bbl for the six months ended
June 30, 2007 reflected increased realized crude oil prices and the full
recovery of the Company's capital investments in the Primrose North and South
Fields in the third quarter of 2006. Upon full recovery, Crown royalty rates on
the Primrose North and South Fields increased from 1% of gross revenue to 25%
of gross revenue less operating, capital and abandonment costs. Crude oil and
NGLs royalties averaged approximately 14% of gross revenues in 2007, compared
to 12% for the second quarter of 2006. Crude oil and NGLs royalties per bbl are
anticipated to average approximately 14% to 16% of gross revenues for the year.
Natural gas royalties per mcf generally fluctuate with natural gas prices.
Natural gas royalties averaged approximately 15% of gross revenues in the
second quarter of 2007 compared to 18% for the second quarter of 2006 and 19%
for the prior quarter. Natural gas royalties decreased in the second quarter of
2007 compared to prior periods due to the impact of certain adjustments, and
are anticipated to average approximately 18% to 20% of gross 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. These combined revenues are
reported as sales revenue. 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. 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. The Company's capital investment in the Baobab Field
is not expected to be fully recovered until approximately 2010 - 2011 due to
the ongoing production curtailments resulting from limitations to sand screen
effectiveness.
Royalty rates as a percentage of gross revenue averaged approximately 10% for
the second quarter of 2007 compared to 3% for second quarter of 2006 and 6% for
the prior quarter. The increase in royalty rates from the comparable periods
was due to the Company's full recovery of its capital investment in the Espoir
Field in the first quarter of 2007 and the resulting increase in profit oil on
which the Government's entitlement is based. Offshore West Africa royalty rates
are anticipated to be 13% to 15% of gross revenues for the year.
CANADIAN NATURAL RESOURCES LIMITED 27
===============================================================================
PRODUCTION EXPENSE
Three Months Ended Six Months Ended
--------------- --------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 13.98 $ 13.00 $ 11.71 $ 13.50 $ 11.33
North Sea $ 22.11 $ 18.57 $ 17.18 $ 20.21 $ 17.02
Offshore West Africa $ 7.98 $ 8.93 $ 5.61 $ 8.48 $ 5.85
Company average $ 15.01 $ 13.81 $ 11.92 $ 14.40 $ 11.63
NATURAL GAS ($/mcf) (1)
North America $ 0.87 $ 0.95 $ 0.79 $ 0.91 $ 0.79
North Sea $ 2.26 $ 2.58 $ 1.47 $ 2.42 $ 1.37
Offshore West Africa $ 1.10 $ 1.48 $ 0.36 $ 1.26 $ 0.65
Company average $ 0.89 $ 0.97 $ 0.80 $ 0.93 $ 0.80
COMPANY AVERAGE ($/boe) (1) $ 10.44 $ 10.10 $ 8.85 $ 10.27 $ 8.66
===================================================================================================================
(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 six months ended
June 30, 2007 increased to $13.50 per bbl from $11.33 per bbl for the six
months ended June 30, 2006. In the second quarter of 2007, production costs
increased to $13.98 per bbl from $11.71 per bbl for the second quarter of 2006
and from $13.00 per bbl for the prior quarter. Second quarter production
expense primarily reflected continued increasing industry-wide costs in the
heavy oil industry, the timing of steaming cycles related to the Company's
thermal crude oil projects, increased costs associated with additional
injection wells related to the Company's Pelican Lake water and polymer flood
projects and increased costs related to fuel and property taxes.
North America natural gas production expense per mcf for the second quarter of
2007 increased over the comparable periods in 2006 primarily due to
industry-wide cost pressures. In the second quarter of 2007, natural gas well
servicing costs in Canada began to decline due to lower industry activity,
resulting in a decrease in production expense compared to the first quarter of
2007.
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. The Company has revised its North Sea production expense guidance for
2007 to between $19.50 to $20.50 per barrel.
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production expense on a per barrel basis varied
from the comparable periods primarily due to the impact of continuing operating
challenges with sand and solids, resulting in decreased production volumes at
Baobab on a relatively fixed operating cost base, and the timing of repair and
maintenance work.
28 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
MIDSTREAM
Three Months Ended Six Months Ended
---------------- ----------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
($ millions) 2007 2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------
Revenue $ 17 $ 19 $ 17 $ 36 $ 35
Production expense 5 6 6 11 11
- ------------------------------------------------------------------------------------------------------------------------
Midstream cash flow 12 13 11 25 24
Depreciation 2 2 2 4 4
- ------------------------------------------------------------------------------------------------------------------------
Segment earnings before taxes $ 10 $ 11 $ 9 $ 21 $ 20
========================================================================================================================
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 Six Months Ended
---------------- ----------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------
Expense ($ millions) $ 718 $ 707 $ 555 $ 1,425 $ 1,074
$/boe (2) $ 12.95 $ 12.73 $ 10.66 $ 12.84 $ 10.62
=======================================================================================================================
(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 six and three months
ended June 30, 2007 increased in total and on a boe basis from the comparable
periods in 2006 and the prior quarter. The increase in DD&A expense was
primarily as a result of increased sales volumes combined with 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.
ASSET RETIREMENT OBLIGATION ACCRETION
Three Months Ended Six Months Ended
---------------- ---------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------
Expense ($ millions) $ 17 $ 18 $ 16 $ 35 $ 33
$/boe (1) $ 0.30 $ 0.32 $ 0.32 $ 0.31 $ 0.33
=======================================================================================================================
(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 second quarter of 2007 was consistent with the comparable
periods.
CANADIAN NATURAL RESOURCES LIMITED 29
===============================================================================
ADMINISTRATION EXPENSE
Three Months Ended Six Months Ended
---------------- ----------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------
Net expense ($ millions) $ 53 $ 60 $ 40 $ 113 $ 82
$/boe (1) $ 0.96 $ 1.08 $ 0.78 $ 1.02 $ 0.81
========================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Administration expense for the six months ended June 30, 2007 increased in
total and on a boe basis from the six months ended June 30, 2006 primarily due
to increased staffing costs, including costs related to the Company's share
bonus program. The decrease in administration expense from the prior quarter in
2007 was primarily due to decreased staffing costs associated with the effect
of graded vesting on the share bonus program.
STOCK-BASED COMPENSATION EXPENSE (RECOVERY)
Three Months Ended Six Months Ended
---------------- ---------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
($ millions) 2007 2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------
Stock option plan expense (recovery) $ 106 $ 25 $ (34) $ 131 $ 98
========================================================================================================================
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 $131 million ($91 million after-tax) stock-based
compensation expense as a result of the 14% increase in the Company's share
price in the six months ended June 30, 2007, and a $106 million ($74 million
after-tax) stock-based compensation expense as a result of the 11% increase in
the Company's share price for the three months ended June 30, 2007 (Company's
share price as at: June 30, 2007 - C$70.78; March 31, 2007 - C$63.75; December
31, 2006 - C$62.15; June 30, 2006 - C$61.72). 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 six months
ended June 30, 2007, the Company capitalized $39 million in stock-based
compensation on the Horizon Project (June 30, 2006 - $66 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 June 30, 2007. In periods when substantial stock price changes
occur, the Company is subject to significant earnings volatility.
For the six months ended June 30, 2007, the Company paid $221 million for stock
options surrendered for cash settlement (June 30, 2006 - $183 million).
30 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
INTEREST EXPENSE
Three Months Ended Six Months Ended
---------------- ----------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
($ millions, except per boe amounts) 2007 2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------------------
Interest expense, gross $ 158 $ 154 $ 69 $ 312 $ 127
Less: capitalized interest, Horizon Project 81 71 41 152 74
- -----------------------------------------------------------------------------------------------------------------------------------
Interest expense, net $ 77 $ 83 $ 28 $ 160 $ 53
$/boe (1) $ 1.40 $ 1.49 $ 0.53 $ 1.44 $ 0.52
Average effective interest rate 5.4% 5.4% 5.7% 5.4% 5.7%
===================================================================================================================================
(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 period ended June 30,
2007 reflected the impact of a stronger Canadian dollar, partially offset by
higher cost US dollar denominated debt issued in March 2007.
CANADIAN NATURAL RESOURCES LIMITED 31
===============================================================================
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.
32 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
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.
CANADIAN NATURAL RESOURCES LIMITED 33
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RISK MANAGEMENT
Three Months Ended Six Months Ended
---------------- ----------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
($ millions) 2007 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------------
REALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments $ 100 $ (5) $ 421 $ 95 $ 753
Natural gas financial instruments (8) (83) (14) (91) 42
- --------------------------------------------------------------------------------------------------------------------------------
$ 92 $ (88) $ 407 $ 4 $ 795
- --------------------------------------------------------------------------------------------------------------------------------
UNREALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments $ 64 $ 330 $ (10) $ 394 $ 104
Natural gas financial instruments (121) 206 (12) 85 (116)
Interest rate swaps - - (4) - (6)
- --------------------------------------------------------------------------------------------------------------------------------
$ (57) $ 536 $ (26) $ 479 $ (18)
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL $ 35 $ 448 $ 381 $ 483 $ 777
================================================================================================================================
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 Six Months Ended
---------------- ----------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
2007 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) $ 3.41 $ (0.17) $ 14.18 $ 1.61 $ 13.15
Natural gas ($/mcf) (1) $ (0.05) $ (0.54) $ (0.11) $ (0.29) $ 0.16
================================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Details related to outstanding derivative financial instruments at June 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 June 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 $479 million ($327 million after-tax) on its commodity
risk management activities for the six months ended June 30, 2007, including a
$57 million ($35 million after-tax) unrealized gain for the three months ended
June 30, 2007 (March 31, 2007 - unrealized loss of $536 million, $362 million
after-tax; June 30, 2006 - unrealized gain of $26 million, $17 million
after-tax).
34 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
FOREIGN EXCHANGE
Three Months Ended Six Months Ended
---------------- ----------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
($ millions) 2007 2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------------
Net realized foreign exchange loss $ 26 $ 5 $ 12 $ 31 $ 7
Net unrealized foreign exchange gain (1) (250) (32) (58) (282) (48)
- ------------------------------------------------------------------------------------------------------------------------------
$ (224) $ (27) $ (46) $ (251) $ (41)
==============================================================================================================================
(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 six months ended June
30, 2007 was primarily the result of settlement of working capital items
denominated in US dollars or UK pounds sterling and the impact of foreign
exchange rate fluctuations. The net unrealized foreign exchange gain for the
three and six months ended June 30, 2007 was primarily related to the second
quarter strengthening of the Canadian dollar in relation to the US dollar with
respect to the US dollar debt. Included in the net unrealized gain for the six
months ended June 30, 2007 is an unrealized loss of $207 million (March 31,
2007 - unrealized loss of $37 million) related to the impact of the cross
currency interest rate swaps. The Canadian dollar ended the second quarter at
US$0.9404 compared to US$0.8674 at March 31, 2007 (June 30, 2006 - US$0.8969).
During the first quarter of 2007, the Company de-designated the portion of the
US dollar denominated debt previously hedged against its net investment in US
dollar based self-sustaining foreign operations. Accordingly, all foreign
exchange (gains) losses arising each period on U.S. dollar denominated
long-term debt are now recognized in the consolidated statement of earnings.
CANADIAN NATURAL RESOURCES LIMITED 35
===============================================================================
TAXES
Three Months Ended Six Months Ended
---------------- ----------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
($ millions, except income tax rates) 2007 2007 2006 2007 2006
- ---------------------------------------------------------------------------------------------------------------------------------
TAXES OTHER THAN INCOME TAX
Current $ 9 $ 66 $ 59 $ 75 $ 94
Deferred 20 (3) 18 17 44
- ---------------------------------------------------------------------------------------------------------------------------------
$ 29 $ 63 $ 77 $ 92 $ 138
- ---------------------------------------------------------------------------------------------------------------------------------
CURRENT INCOME TAX
North America $ 12 $ 25 $ 22 $ 37 $ 40
North Sea 54 35 (1) 89 -
Offshore West Africa 16 10 16 26 29
- ---------------------------------------------------------------------------------------------------------------------------------
$ 82 $ 70 $ 37 $ 152 $ 69
- ---------------------------------------------------------------------------------------------------------------------------------
FUTURE INCOME TAX EXPENSE (RECOVERY) $ 116 $ 100 $ (224) $ 216 $ 44
- ---------------------------------------------------------------------------------------------------------------------------------
EFFECTIVE INCOME TAX RATE 19.1%(1) 38.7% (21.9)%(3) 24.9%(1) 9.4%(2)(3)
=================================================================================================================================
(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 $438 MILLION DUE TO
CANADIAN FEDERAL, ALBERTA AND SASKATCHEWAN TAX RATE REDUCTIONS ENACTED
DURING THE SECOND QUARTER OF 2006.
Taxes other than income tax primarily includes current and deferred petroleum
revenue tax ("PRT"). PRT is charged on certain fields in the North Sea at the
rate of 50% of net operating income, after allowing for certain deductions
including abandonment expenditures.
Taxable income from the conventional crude oil and natural gas business in
Canada is primarily generated through partnerships, with the related income
taxes payable in a future period. North America current income taxes have been
provided on the basis of the corporate structure and available income tax
deductions and will vary depending upon the nature and amount of capital
expenditures incurred in Canada in any particular year.
36 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CAPITAL EXPENDITURES (1)
Three Months Ended Six Months Ended
-------------- --------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
($ millions) 2007 2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------------
EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT
Net property acquisitions $ 15 $ 46 $ 7 $ 61 $ 19
Land acquisition and retention 22 29 54 51 153
Seismic evaluations 34 50 35 84 87
Well drilling, completion and equipping 288 714 418 1,002 1,354
Pipeline and production facilities 243 334 233 577 733
- -----------------------------------------------------------------------------------------------------------------------------
TOTAL NET RESERVE REPLACEMENT EXPENDITURES 602 1,173 747 1,775 2,346
- -----------------------------------------------------------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 704 674 680 1,378 1,296
Phases 2 and 3 costs 19 44 6 63 7
Capitalized interest, stock-based compensation
and other 118 91 96 209 165
- -----------------------------------------------------------------------------------------------------------------------------
Total Horizon Project 841 809 782 1,650 1,468
- -----------------------------------------------------------------------------------------------------------------------------
Midstream - 2 6 2 9
Abandonments (2) 13 20 17 33 32
Head office 4 5 6 9 12
- -----------------------------------------------------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES $ 1,460 $ 2,009 $ 1,558 $ 3,469 $ 3,867
=============================================================================================================================
BY SEGMENT
North America $ 419 $ 998 $ 569 $ 1,417 $ 1,973
North Sea 136 138 149 274 287
Offshore West Africa 46 36 27 82 77
Other 1 1 2 2 9
Horizon Project 841 809 782 1,650 1,468
Midstream - 2 6 2 9
Abandonments (2) 13 20 17 33 32
Head office 4 5 6 9 12
- -----------------------------------------------------------------------------------------------------------------------------
Total $ 1,460 $ 2,009 $ 1,558 $ 3,469 $ 3,867
=============================================================================================================================
(1) THE NET CAPITAL EXPENDITURES DO NOT INCLUDE NON-CASH PROPERTY, PLANT AND
EQUIPMENT ADDITIONS OR DISPOSALS.
(2) ABANDONMENTS REPRESENT EXPENDITURES TO SETTLE ASSET RETIREMENT
OBLIGATIONS AND HAVE BEEN REFLECTED AS CAPITAL EXPENDITURES IN THIS
TABLE.
CANADIAN NATURAL RESOURCES LIMITED 37
===============================================================================
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 six months ended June 30, 2007 were $3,469
million compared to $3,867 million in the six months ended June 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 an overall strategic reduction
in the North America natural gas drilling program.
In the six months ended June 30, 2007, the Company drilled a total of 783 net
wells consisting of 207 natural gas wells, 271 crude oil wells, 241
stratigraphic test and service wells and 64 wells that were dry. This compared
to 1,031 net wells drilled in the six months ended June 30, 2006. The Company
achieved an overall success rate of 88% for the six months ended June 30, 2007,
excluding stratigraphic test and service wells, compared to 91% for the six
months ended June 30, 2006.
Net capital expenditures in the second quarter of 2007 were $1,460 million
compared to $1,558 million in the second quarter of 2006 and $2,009 million in
the prior quarter. Second quarter 2007 capital expenditures decreased from the
comparable period in 2006 due to the Company's strategic reduction in natural
gas drilling activity, and decreased from the first quarter of 2007 as a result
of reduced drilling activity due to spring break-up.
In the second quarter of 2007, the Company drilled a total of 95 net wells
consisting of 6 natural gas wells, 78 crude oil wells, 7 stratigraphic test and
service wells and 4 wells that were dry. This compared to 141 net wells in the
second quarter of 2006 and 688 net wells in the prior quarter. The Company
achieved an overall success rate of 95% for the second quarter of 2007,
excluding stratigraphic test and service wells, compared to 95% for the second
quarter of 2006 and 87% for the first quarter of 2007.
NORTH AMERICA
North America, including the Horizon Project, accounted for approximately 90%
of the total capital expenditures for the six months ended June 30, 2007 and
for the six months ended June 30, 2006.
During the six months ended June 30, 2007, the Company targeted 252 net natural
gas wells, including 49 wells in Northeast British Columbia, 94 wells in the
Northern Plains region, 82 wells in Northwest Alberta, and 27 wells in the
Southern Plains region. The Company also targeted 285 net crude oil wells
during the six months ended June 30, 2007. The majority of these wells were
concentrated in the Company's crude oil Northern Plains region where 166 heavy
crude oil wells, 76 Pelican Lake crude oil wells, 23 thermal crude oil wells
and 5 light crude oil wells were drilled. Another 15 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 six 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, and will be drilled as natural gas commodity prices improve.
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 six months of 2007, the
Company drilled 130 stratigraphic test wells and observation wells, 2 water
source wells and 23 thermal oil wells. Overall Primrose thermal production for
the six months ended June 30, 2007 increased to approximately 57,000 bbl/d from
approximately 55,000 bbl/d for the six months ended June 30, 2006.
The Primrose East Expansion, a new facility located 15 kilometres from the
existing Primrose South steam plant and 25 kilometres 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.
38 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
The next phase of the Company's In-Situ Oil Sands Assets expansion is the Kirby
project located 120 kilometres north of the existing Primrose facilities. The
Kirby project is anticipated to add approximately 30,000 bbl/d of production
growth. The Company is targeting to file its formal regulatory application
documents for this project in the latter half of 2007. Final corporate sanction
may depend upon the results of potential changes to royalty regimes and
environmental regulations, and their associated costs.
Development of new pads and secondary recovery conversion projects at Pelican
Lake continued as expected throughout the second quarter of 2007. Drilling
consisted of 40 horizontal wells, with plans to drill 52 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 34,000 bbl/d for the second quarter of 2007 compared to 30,000
bbl/d for the second quarter of 2006 and 32,000 bbl/d for the prior period.
Originally announced in the fall of 2005, the scoping study for the Canadian
Natural Upgrader, outside of the Horizon Project, continued into the first
quarter of 2007. The terms of reference for this study involved the evaluation
of product alternatives, location, technology, gasification and integration
with existing assets using the same disciplined approach utilized in the
Horizon Project. The next steps in this process would include a Design Basis
Memorandum ("DBM") and Engineering Design Specification ("EDS"), which would be
required to be completed prior to construction and sanctioning of the project
by the Board of Directors.
Based upon the results of the scoping study, which identified growing concerns
relating to increased environmental costs for upgraders located in Canada,
inflationary capital cost pressures and narrowing heavy oil differentials in
North America, the Company has, at this point in time, deferred the DBM and EDS
pending clarification on the cost of future environmental legislation and a
more stable cost environment.
In the third quarter of 2007, the Company's overall drilling activity in North
America is expected to be comprised of 121 natural gas wells and 147 crude oil
wells excluding stratigraphic and service wells.
HORIZON PROJECT
Work progress on the Horizon Project was 75% complete at the end of the second
quarter. First production continues to be targeted to commence in the third
quarter of 2008. The project status as at June 30, 2007 was as follows:
o Overall detailed engineering 97% completed and substantially complete in
most areas;
o Procurement 95% completed with over $5.4 billion in purchase orders and
contracts awarded;
o Overall construction progress is 63% complete.
o Mine overburden removal approximately 54% completed and is 1% ahead of
schedule.
o Construction of cofferdam for the Tar River Diversion completed in
Mining.
o Fabrication of Crushing Plants, Surge Facility and Conveyor Structure is
100% complete in the Ore Preparation Plant.
o Started erection of Conveyors in Ore Preparation.
o Completed Hot Water Tank in Extraction.
o Hydro-tested Primary Separation Cells and Hot Water Tank.
o Completed construction and hydro-testing of Inclined Plate Settlers in
Froth Treatment.
o Flare Stacks installed in Upgrading.
o Mechanically completed Cooling Tower piping.
o Mechanically completed Inhibited Water and Cooling Water Pumphouse
buildings.
o 42" Water Pipeline completed.
o Wet Gas Compressor received and installed.
o Completed installation of Coker and Diluent Recovery Unit process
structures.
o Completed interconnecting welding of Primary Upgrading's piperacks.
o Energized main electrical substations R1/R2.
CANADIAN NATURAL RESOURCES LIMITED 39
===============================================================================
Major activities for the third quarter of 2007 will include:
o Complete construction of Raw Water Pond;
o Extraction Plant hydro-testing;
o Start of pre-commissioning activities in all Bitumen Production Areas;
o Permanent power energized in R1/R2 corridors pumphouses;
o Electrically energize Main Electrical Substation; and
o Start commissioning of Recycle Water Pond.
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 June 30, 2007 was approximately $5.4
billion. Final construction costs for Phase 1 are expected to exceed the
approved budget by 5% to 12% primarily due to inflationary cost pressures.
NORTH SEA
In the second quarter of 2007, the Company continued with its planned program
of infill drilling, recompletions, workovers and waterflood optimizations.
During the quarter, 3.7 net wells were drilled, with an additional 1.9 net
wells drilling at the end of the quarter.
The development of the Lyell Field progressed during the second quarter.
Tranche 1 of the Lyell Field development comprises 2 production wells scheduled
for completion in 2007, and one production well and one well workover scheduled
for completion in 2008. Full capacity production from the Lyell Field has been
deferred to 2008 to optimize capital allocation in the North Sea.
During the second quarter of 2007, construction of the Columba E Raw Water
Injection project continued. Commissioning was completed and 2 water injection
wells were delivered. Production is anticipated to reach full capacity in 2008.
OFFSHORE WEST AFRICA
During the second 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 in mid-2006 from 3 production wells
and 2 injector wells. An additional production well was added during the first
quarter of 2007, with 2 additional production wells being brought on line
during the second quarter of 2007. West Espoir development drilling is expected
to continue until 2008 with producers and injectors being brought on line as
they are completed.
The Company purchased a 90% interest in the Olowi PSC offshore Gabon in 2005,
and received Government approval and Board sanction for development in 2006.
Development plans include a floating production, storage and offtake vessel
("FPSO"), handling production from 4 shallow-water producing platforms. During
2006 and the first half of 2007, the Company signed a lease agreement for a
FPSO with a primary term of ten years, commencing in 2008, and awarded
additional contracts for a drilling rig and for the construction of the
wellhead towers. Drilling is scheduled to commence in mid-2008 with first crude
oil anticipated in late 2008. Olowi production is targeted to plateau at
approximately 20,000 bbl/d.
40 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
LIQUIDITY AND CAPITAL RESOURCES
------------------
($ millions, except ratios) JUN 30 Mar 31 Dec 31 Jun 30
2007 2007 2006 2006
- ----------------------------------------------------------------------------------------------------------------------------
Working capital deficit (1) $ 860 $ 1,104 $ 832 $ 1,554
Long-term debt (2) $ 10,958 $ 11,307 $ 11,043 $ 5,004
Shareholders' equity
Share capital $ 2,649 $ 2,635 $ 2,562 $ 2,516
Retained earnings 9,169 8,374 8,141 6,798
Accumulated other comprehensive income (loss) 62 (45) (13) (12)
- ----------------------------------------------------------------------------------------------------------------------------
Total $ 11,880 $ 10,964 $ 10,690 $ 9,302
Debt to book capitalization (2) (3) 48.0% 50.8% 50.8% 35.0%
Debt to market capitalization (2) 22.3% 24.8% 24.8% 13.1%
After tax return on average common
shareholders' equity (4) 23.8% 27.5% 26.9% 29.3%
After tax return on average capital
employed (2) (5) 13.9% 16.5% 17.2% 20.2%
============================================================================================================================
(1) CALCULATED AS CURRENT ASSETS LESS CURRENT LIABILITIES.
(2) LONG-TERM DEBT AT JUNE 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.
The Company's capital resources at June 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, Baa2 with a stable outlook by Moody's Investor
Services, Inc. and BBB with a stable outlook by Standard and Poors Corporation.
At June 30, 2007, the Company had undrawn bank lines of credit of $1,427
million. Details related to the Company's long-term debt at June 30, 2007 are
disclosed in note 4 to the Company's unaudited interim consolidated financial
statements.
At June 30, 2007, the Company's working capital deficit was $860 million and
included the current portion of the stock-based compensation liability of $453
million and the current portion of the net mark-to-market liability for risk
management derivative financial instruments of $149 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 at the time of
final settlement of the derivative financial instruments, as compared to their
mark-to-market value at June 30, 2007.
CANADIAN NATURAL RESOURCES LIMITED 41
===============================================================================
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
June 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 $10,958 million at June 30, 2007,
resulting in a debt to book capitalization level of 48.0% (March 31, 2007 -
50.8%; December 31, 2006 - 50.8%; June 30, 2006 -35.0%). 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 natural gas and crude oil production for 2007 and 2008 at prices
that protect investment returns. In the future, the Company may also consider
the divestiture of non-strategic and non-core properties to gain additional
balance sheet flexibility.
The Company's commodity hedging program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its capital
expenditure program throughout the Horizon Project construction period. This
program allows for the hedging of up to 75% of the near 12 months budgeted
production, up to 50% of the following 13 to 24 months estimated production and
up to 25% of production expected in months 25 to 48. For the purpose of this
program, the purchase of crude oil put options is in addition to the above
parameters. In accordance with the policy, approximately 60% of expected crude
oil volumes and approximately 70% of expected natural gas volumes are hedged
for the remainder of 2007. In addition, 77,000 bbl/d of crude oil volumes are
protected by WTI put options for the remainder of 2007 at a strike price of
US$60.00 per barrel.
The Company has hedged 220,000 bbl/d of crude oil volumes for the year 2008. Of
the 220,000 bbl/d, 20,000 bbl/d are hedged by Mayan price collars with a
US$50.00 floor, 150,000 bbl/d are hedged by WTI price collars with a US$60.00
floor and 50,000 bbl/d are hedged by WTI put options with a US$55.00 strike
price. The Company has also entered into an additional 50,000 bbl/d of WTI
price collars with a US$60.00 floor for the first quarter of 2008. In addition,
900,000 GJ/d of natural gas volumes are hedged by AECO price collars for the
first quarter of 2008; 400,000 GJ/d with a $7.00 floor and 500,000 GJ/d with a
$7.50 floor.
The Company has also reduced its 2007 conventional crude oil and natural gas
capital budget by $900 million compared to 2006 capital spending, while
maintaining the capital expenditures to complete Phase 1 of the Horizon
Project.
LONG-TERM DEBT
As at June 30, 2007, the Company had in place unsecured bank credit facilities
of $6,212 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 the $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.
42 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
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 June 30, 2007.
MEDIUM-TERM NOTES
During the first quarter of 2007, $125 million of 7.40% unsecured debentures
due March 1, 2007 were repaid.
The Company has $1,600 million remaining on its $2,000 million shelf prospectus
filed in August 2005 that allows for the issue of medium-term notes in Canada
until September 2007. If issued, these securities will bear interest as
determined at the date of issuance.
SENIOR UNSECURED NOTES
During the second quarter of 2007, US$31 million of the senior unsecured notes
were repaid.
US DOLLAR DEBT SECURITIES
In March 2007, the Company issued US$2,200 million of unsecured notes under the
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 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 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 June 30, 2007, there were 539,385,000 common shares outstanding and
27,768,000 stock options outstanding. As at July 31, 2007, the Company had
539,459,000 common shares outstanding and 27,281,000 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 July 31, 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 $0.34 per common share for 2007. The
increase represents a 13% increase from the prior year, recognizes the
stability of the Company's cash flow, and provides a return to Shareholders.
This is the seventh consecutive year in which the Company has paid dividends
and the sixth consecutive year of an increase in the distribution paid to its
Shareholders. The dividend policy undergoes a periodic review by the Board of
Directors and is subject to change.
CANADIAN NATURAL RESOURCES LIMITED 43
===============================================================================
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations. These
commitments primarily relate to debt repayments, operating leases relating to
office space and offshore FPSOs and drilling rigs, and firm commitments for
gathering, processing and transmission services, as well as expenditures
relating to asset retirement obligations. As at June 30, 2007, no entities were
consolidated under the Canadian Institute of Chartered Accountants Handbook
Accounting Guideline 15, "Consolidation of Variable Interest Entities". The
following table summarizes the Company's commitments as at June 30, 2007:
Remaining
($ millions) 2007 2008 2009 2010 2011 Thereafter
- ---------------------------------------------------------------------------------------------------------------------
Product transportation and
pipeline (1) $ 133 $ 217 $ 147 $ 135 $ 105 $ 1,055
Offshore equipment operating
lease (2) $ 195 $ 48 $ 48 $ 48 $ 46 $ 108
Offshore drilling (3) (4) $ 187 $ 168 $ 50 $ 50 $ 48 $ 162
Asset retirement obligations (5) $ 2 $ 3 $ 3 $ 4 $ 4 $ 4,422
Long-term debt (6) $ - $ 42 $ 2,377 $ - $ 425 $ 5,798
Office lease $ 15 $ 31 $ 31 $ 32 $ 22 $ -
Electricity and other $ 89 $ 158 $ 165 $ 18 $ 1 $ -
=====================================================================================================================
(1) THE COMPANY ENTERED INTO A 25-YEAR PIPELINE TRANSPORTATION AGREEMENT
COMMENCING IN 2008, RELATED TO FUTURE CRUDE OIL PRODUCTION. THE AGREEMENT
IS RENEWABLE FOR SUCCESSIVE 10-YEAR PERIODS AT THE COMPANY'S OPTION.
DURING THE INITIAL TERM, ANNUAL TOLL PAYMENTS BEFORE OPERATING COSTS WILL
BE APPROXIMATELY $35 MILLION.
(2) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF
OBLIGATIONS RELATED TO FLOATING PRODUCTION, STORAGE AND OFFTAKE VESSELS
("FPSO"). DURING 2006, THE COMPANY ENTERED INTO AN AGREEMENT TO LEASE AN
ADDITIONAL FPSO COMMENCING IN 2008, IN CONNECTION WITH THE PLANNED
OFFSHORE DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. THE NEW FPSO LEASE
AGREEMENT CONTAINS CANCELLATION PROVISIONS AT THE OPTION OF THE COMPANY,
SUBJECT TO ESCALATING TERMINATION PAYMENTS THROUGHOUT 2007 TO A MAXIMUM
OF US$395 MILLION. AS AT JUNE 30, 2007, US$140 MILLION OF POTENTIAL
TERMINATION PAYMENTS HAVE BEEN INCLUDED AS A 2007 COMMITMENT IN THIS
TABLE.
(3) 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 THE FOURTH QUARTER
OF 2007, SUBJECT TO RIG AVAILABILITY. MINIMUM ESTIMATED TOTAL PAYMENTS OF
US$100 MILLION, AFTER JOINT VENTURE RECOVERIES, HAVE BEEN INCLUDED IN
THIS TABLE FOR THE PERIOD 2007 - 2008.
(4) 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. IN ADDITION TO INCURRED
CONSTRUCTION COSTS, THE WELLHEAD TOWERS AGREEMENT CONTAINS CANCELLATION
PROVISIONS AT THE OPTION OF THE COMPANY, SUBJECT TO VARYING TERMINATION
PAYMENTS BASED ON PRO-RATA PERCENTAGES OF THE CONTRACT PRICE THROUGHOUT
JUNE 2009, SUBJECT TO A MAXIMUM OF US$95 MILLION. THE DRILLING RIG
AGREEMENT CONTAINS CANCELLATION PROVISIONS AT THE OPTION OF THE COMPANY,
SUBJECT TO ESCALATING TERMINATION PAYMENTS TO A MAXIMUM OF US$55 MILLION
IN 2008. AS AT JUNE 30, 2007, US$120 MILLION OF POTENTIAL CANCELLATION
AND TERMINATION PAYMENTS HAVE BEEN INCLUDED AS A 2007 COMMITMENT IN THIS
TABLE.
(5) 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.
(6) 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 $2,431 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 June 30, 2007 was approximately $5.4
billion. Final construction costs for Phase 1 are expected to exceed the
approved budget by 5% to 12%.
LEGAL PROCEEDINGS
The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business. The Company believes that any liabilities
that might arise pertaining to such matters would not have a material effect on
its consolidated financial position.
44 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING POLICIES
The preparation of financial statements requires the Company to make
judgements, assumptions and estimates in the application of generally accepted
accounting principles that have a significant impact on the financial results
of the Company. Actual results could differ from those estimates. A
comprehensive discussion of the Company's significant accounting policies is
contained in the MD&A and the audited consolidated financial statements for the
year ended December 31, 2006.
For the impact of new accounting standards related to financial instruments and
comprehensive income, please refer to Risk Management Activities on page 32 of
this MD&A and note 2 of the unaudited interim consolidated financial statements
as at June 30, 2007.
SENSITIVITY ANALYSIS (1)
The following table is indicative of the annualized sensitivities of cash flow
from operations and net earnings from changes in certain key variables. The
analysis is based on business conditions and sales volumes during the second
quarter of 2007, and is not necessarily indicative of future results. Each
separate line item in the sensitivity analysis shows the effect of a change in
that variable only; all other variables are held constant.
CASH FLOW
CASH FLOW FROM NET
FROM OPERATIONS NET EARNINGS
OPERATIONS (PER COMMON SHARE, EARNINGS (PER COMMON
($ MILLIONS) BASIC) ($ MILLIONS) SHARE, BASIC)
- --------------------------------------------------------------------------------------------------------------------------
PRICE CHANGES
Crude oil - WTI US$1.00/bbl (2)
Excluding financial derivatives $ 96 $ 0.18 $ 70 $ 0.13
Including financial derivatives $ 87 - 96 $ 0.16 - 0.18 $ 63 - 70 $ 0.12 - 0.13
Natural gas - AECO C$0.10/mcf (2)
Excluding financial derivatives $ 42 $ 0.08 $ 29 $ 0.05
Including financial derivatives $ 23 - 33 $ 0.04 - 0.06 $ 16 - 23 $ 0.03 - 0.04
VOLUME CHANGES
Crude oil - 10,000 bbl/d $ 107 $ 0.20 $ 52 $ 0.10
Natural gas - 10 mmcf/d $ 20 $ 0.04 $ 9 $ 0.02
FOREIGN CURRENCY RATE CHANGE
$0.01 change in US$ (2)
Including financial derivatives $ 83 - 85 $ 0.15 - 0.16 $ 28 - 29 $ 0.05
INTEREST RATE CHANGE - 1% $ 38 $ 0.07 $ 38 $ 0.07
==========================================================================================================================
(1) THE SENSITIVITIES ARE CALCULATED BASED ON 2007 SECOND QUARTER RESULTS AND
EXCLUDE MARK-TO-MARKET GAINS (LOSSES) ON RISK MANAGEMENT ACTIVITIES.
(2) FOR DETAILS OF OUTSTANDING FINANCIAL INSTRUMENTS IN PLACE, REFER TO NOTE
10 OF THE COMPANY'S UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS.
CANADIAN NATURAL RESOURCES LIMITED 45
===============================================================================
OTHER OPERATING HIGHLIGHTS
NETBACK ANALYSIS
Three Months Ended Six Months Ended
--------------- ----------------
JUN 30 Mar 31 Jun 30 JUN 30 Jun 30
($/boe) (1) 2007 2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------------------------
Sales price (2) $ 49.70 $ 49.32 $ 50.36 $ 49.50 $ 48.39
Royalties 5.99 6.76 5.80 6.37 6.11
Production expense (3) 10.44 10.10 8.85 10.27 8.66
- -------------------------------------------------------------------------------------------------------------------------------
NETBACK 33.27 32.46 35.71 32.86 33.62
Midstream contribution (3) (0.20) (0.24) (0.23) (0.22) (0.24)
Administration 0.96 1.08 0.78 1.02 0.81
Interest, net 1.40 1.49 0.53 1.44 0.52
Realized risk management loss (gain) 1.66 (1.58) 7.81 0.04 7.85
Realized foreign exchange loss 0.47 0.10 0.25 0.28 0.07
Taxes other than income tax - current 0.16 1.18 1.13 0.67 0.93
Current income tax - North America 0.21 0.45 0.42 0.33 0.39
Current income tax - North Sea 0.99 0.62 (0.01) 0.81 -
Current income tax - Offshore West Africa 0.29 0.18 0.30 0.23 0.29
- -------------------------------------------------------------------------------------------------------------------------------
CASH FLOW $ 27.33 $ 29.18 $ 24.73 $ 28.26 $ 23.00
===============================================================================================================================
(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
---------------------
JUN 30 Dec 31
(millions of Canadian dollars, unaudited) 2007 2006
- ---------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 11 $ 23
Accounts receivable and other 1,737 1,947
Future income tax 190 163
Current portion of other long-term assets (note 3) 36 106
- ---------------------------------------------------------------------------------------------------------------
1,974 2,239
PROPERTY, PLANT AND EQUIPMENT (note 12) 32,601 30,767
OTHER LONG-TERM ASSETS (note 3) 56 154
- ---------------------------------------------------------------------------------------------------------------
$ 34,631 $ 33,160
===============================================================================================================
LIABILITIES
CURRENT LIABILITIES
Accounts payable $ 547 $ 842
Accrued liabilities 1,685 1,618
Current portion of other long-term liabilities (note 5) 602 611
- ---------------------------------------------------------------------------------------------------------------
2,834 3,071
LONG-TERM DEBT (note 4) 10,958 11,043
OTHER LONG-TERM LIABILITIES (note 5) 1,747 1,393
FUTURE INCOME TAX 7,212 6,963
- ---------------------------------------------------------------------------------------------------------------
22,751 22,470
- ---------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
SHARE CAPITAL (note 7) 2,649 2,562
RETAINED EARNINGS 9,169 8,141
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (note 8) 62 (13)
- ---------------------------------------------------------------------------------------------------------------
11,880 10,690
- ---------------------------------------------------------------------------------------------------------------
$ 34,631 $ 33,160
===============================================================================================================
COMMITMENTS (NOTE 11)
CANADIAN NATURAL RESOURCES LIMITED 47
===============================================================================
CONSOLIDATED STATEMENTS OF EARNINGS
Three Months Ended Six Months Ended
--------------- ----------------
(millions of Canadian dollars, except per common JUN 30 Jun 30 JUN 30 Jun 30
share amounts, unaudited) 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
REVENUE $ 3,152 $ 3,041 $ 6,270 $ 5,709
Less: royalties (331) (302) (707) (618)
- --------------------------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES 2,821 2,739 5,563 5,091
- --------------------------------------------------------------------------------------------------------------------------
EXPENSES
Production 584 467 1,149 886
Transportation and blending 385 402 744 779
Depletion, depreciation and amortization 720 557 1,429 1,078
Asset retirement obligation accretion (note 5) 17 16 35 33
Administration 53 40 113 82
Stock-based compensation expense (recovery) (note 5) 106 (34) 131 98
Interest, net 77 28 160 53
Risk management activities (note 10) 35 381 483 777
Foreign exchange gain (224) (46) (251) (41)
- --------------------------------------------------------------------------------------------------------------------------
1,753 1,811 3,993 3,745
- --------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 1,068 928 1,570 1,346
Taxes other than income tax 29 77 92 138
Current income tax expense (note 6) 82 37 152 69
Future income tax expense (recovery) (note 6) 116 (224) 216 44
- --------------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 841 $ 1,038 $ 1,110 $ 1,095
- --------------------------------------------------------------------------------------------------------------------------
NET EARNINGS PER COMMON SHARE (note 9)
Basic and diluted $ 1.56 $ 1.93 $ 2.06 $ 2.04
==========================================================================================================================
48 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Six Months Ended
-------------------
JUN 30 Jun 30
(millions of Canadian dollars, unaudited) 2007 2006
- -----------------------------------------------------------------------------------------------------------------------
COMMON SHARES
Balance - beginning of period $ 2,562 $ 2,442
Issued upon exercise of stock options 16 13
Previously recognized liability on stock options exercised for common shares 71 63
Purchase of common shares under Normal Course Issuer Bid - (2)
- -----------------------------------------------------------------------------------------------------------------------
Balance - end of period 2,649 2,516
- -----------------------------------------------------------------------------------------------------------------------
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 1,110 1,095
Dividends on common shares (note 7) (92) (81)
Purchase of common shares under Normal Course Issuer Bid - (20)
- -----------------------------------------------------------------------------------------------------------------------
Balance - end of period 9,169 6,798
- -----------------------------------------------------------------------------------------------------------------------
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 (84) (3)
- -----------------------------------------------------------------------------------------------------------------------
Balance - end of period 62 (12)
- -----------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY $ 11,880 $ 9,302
=======================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Six Months Ended
-------------- ------------------
JUN 30 Jun 30 JUN 30 Jun 30
(millions of Canadian dollars, unaudited) 2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 841 $ 1,038 $ 1,110 $ 1,095
- -------------------------------------------------------------------------------------------------------------------------
NET CHANGE IN DERIVATIVE FINANCIAL INSTRUMENTS
DESIGNATED AS CASH FLOW HEDGES
Unrealized income (loss) during the period
(net of taxes of $47 million - three months
ended; $8 million - six months ended) 112 - (4) -
Reclassification to net earnings (net of taxes
of $nil - three months ended; $35 million -
six months ended) (1) - (75) -
- -------------------------------------------------------------------------------------------------------------------------
111 - (79) -
- -------------------------------------------------------------------------------------------------------------------------
FOREIGN CURRENCY TRANSLATION ADJUSTMENT
Translation of net investment (4) (4) (5) (6)
Hedge of net investment, net of tax - 3 - 3
- -------------------------------------------------------------------------------------------------------------------------
(4) (1) (5) (3)
- -------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES 107 (1) (84) (3)
- -------------------------------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME $ 948 $ 1,037 $ 1,026 $ 1,092
=========================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 49
===============================================================================
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended Six Months Ended
---------------- -----------------
JUN 30 Jun 30 JUN 30 Jun 30
(millions of Canadian dollars, unaudited) 2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings $ 841 $ 1,038 $ 1,110 $ 1,095
Non-cash items
Depletion, depreciation and amortization 720 557 1,429 1,078
Asset retirement obligation accretion 17 16 35 33
Stock-based compensation expense (recovery) 106 (34) 131 98
Unrealized risk management activities (57) (26) 479 (18)
Unrealized foreign exchange gain (250) (58) (282) (48)
Deferred petroleum revenue tax 20 18 17 44
Future income tax expense (recovery) 116 (224) 216 44
Deferred charges 8 7 (5) (8)
Abandonment expenditures (13) (17) (33) (32)
Net change in non-cash working capital 131 (47) 12 (358)
- -----------------------------------------------------------------------------------------------------------------------------
1,639 1,230 3,109 1,928
- -----------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Issue (repayment) of bankers' acceptances 167 781 (1,846) 1,400
(Repayment) issue of medium-term notes - - (125) 400
Repayment of senior unsecured notes (33) - (33) -
Issue of US dollar debt securities - - 2,553 -
Issue of common shares on exercise of stock options 3 3 16 13
Dividends on common shares (46) (40) (86) (72)
Purchase of common shares - (22) - (22)
Net change in non-cash working capital 45 4 23 6
- -----------------------------------------------------------------------------------------------------------------------------
136 726 502 1,725
- -----------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant and equipment (1,447) (1,543) (3,440) (3,837)
Net proceeds on sale of property, plant and equipment - 2 4 2
- -----------------------------------------------------------------------------------------------------------------------------
Net expenditures on property, plant and equipment (1,447) (1,541) (3,436) (3,835)
Net change in non-cash working capital (331) (412) (187) 179
- -----------------------------------------------------------------------------------------------------------------------------
(1,778) (1,953) (3,623) (3,656)
- -----------------------------------------------------------------------------------------------------------------------------
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (3) 3 (12) (3)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 14 12 23 18
- -----------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF PERIOD $ 11 $ 15 $ 11 $ 15
=============================================================================================================================
INTEREST PAID $ 87 $ 57 $ 245 $ 109
TAXES PAID
Taxes other than income tax $ 39 $ 52 $ 74 $ 133
Current income tax $ 1 $ 80 $ 72 $ 253
=============================================================================================================================
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
------------
JUN 30 Dec 31
2007 2006
- --------------------------------------------------------------------------------
Deferred charges (note 2) $ 70 $ 109
Risk management (note 10) - 128
Other 22 23
- -------------------------------------------------------------------------------
92 260
Less: current portion 36 106
- -------------------------------------------------------------------------------
$ 56 $ 154
===============================================================================
CANADIAN NATURAL RESOURCES LIMITED 53
===============================================================================
4. LONG-TERM DEBT
-------------
JUN 30 Dec 31
2007 2006
- ------------------------------------------------------------------------------------------------------------------
CANADIAN DOLLAR DENOMINATED DEBT
Bank credit facilities (bankers' acceptances) $ 4,775 $ 6,621
Medium-term notes 800 925
- ------------------------------------------------------------------------------------------------------------------
5,575 7,546
- ------------------------------------------------------------------------------------------------------------------
US DOLLAR DENOMINATED DEBT
Senior unsecured notes (2007 - US$62 million; and 2006 - US$93 million) 66 108
US dollar debt securities (2007 - US$5,108 million; and 2006 - US$2,908 million) 5,432 3,389
Less - original issue discount on senior unsecured notes and US dollar
debt securities (1) (23) -
- ------------------------------------------------------------------------------------------------------------------
5,475 3,497
Change in fair value of interest rate swaps on US dollar debt securities ((2)) (39) -
- ------------------------------------------------------------------------------------------------------------------
5,436 3,497
- ------------------------------------------------------------------------------------------------------------------
Long-term debt before transaction costs 11,011 11,043
Less - transaction costs (1) (3) (53) -
- ------------------------------------------------------------------------------------------------------------------
$ 10,958 $ 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 $39
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 June 30, 2007, the Company had in place unsecured bank credit facilities
of $6,212 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 the $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
June 30, 2007, was 4.8% (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 June 30, 2007.
MEDIUM-TERM NOTES
During the first quarter of 2007, $125 million of 7.40% unsecured debentures
due March 1, 2007 were repaid.
The Company has $1,600 million remaining on its $2,000 million shelf prospectus
filed in August 2005 that allows for the issue of medium-term notes in Canada
until September 2007. If issued, these securities will bear interest as
determined at the date of issuance.
SENIOR UNSECURED NOTES
During the second quarter of 2007, US$31 million of the senior unsecured notes
were repaid.
US DOLLAR DEBT SECURITIES
In March 2007, the Company issued US$2,200 million of unsecured notes under the
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
---------------------
JUN 30 Dec 31
2007 2006
- -------------------------------------------------------------------------------
Asset retirement obligations $ 1,128 $ 1,166
Stock-based compensation 622 744
Risk management (note 10) 495 -
Other 104 94
- --------------------------------------------------------------------------------
2,349 2,004
Less: current portion 602 611
- --------------------------------------------------------------------------------
$ 1,747 $ 1,393
===============================================================================
CANADIAN NATURAL RESOURCES LIMITED 55
===============================================================================
ASSET RETIREMENT OBLIGATIONS
At June 30, 2007, the Company's total estimated cost to settle its asset
retirement obligations was approximately $4,438 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:
-----------------------
SIX MONTHS Year
ENDED Ended
JUN 30, 2007 Dec 31, 2006
- --------------------------------------------------------------------------------------------------------
Balance - beginning of period $ 1,166 $ 1,112
Liabilities incurred 8 26
Liabilities acquired - 56
Liabilities settled (33) (75)
Asset retirement obligation accretion 35 68
Revision of estimates 1 (21)
Foreign exchange (49) -
- --------------------------------------------------------------------------------------------------------
Balance - end of period $ 1,128 $ 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.
----------------------
SIX MONTHS Year
ENDED Ended
JUN 30, 2007 Dec 31, 2006
- -------------------------------------------------------------------------------------------------------
Balance - beginning of period $ 744 $ 891
Stock-based compensation 131 139
Payments for options surrendered (221) (264)
Transferred to common shares (71) (101)
Capitalized to Horizon Project 39 79
- -------------------------------------------------------------------------------------------------------
Balance - end of period 622 744
Less: current portion of stock-based compensation 453 611
- -------------------------------------------------------------------------------------------------------
$ 169 $ 133
=======================================================================================================
56 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
6. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Six Months Ended
-------------- ------------
JUN 30 Jun 30 JUN 30 Jun 30
2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------
Current income tax - North America $ 12 $ 22 $ 37 $ 40
Current income tax - North Sea 54 (1) 89 -
Current income tax - Offshore West Africa 16 16 26 29
- --------------------------------------------------------------------------------------------------------------------
Current income tax expense 82 37 152 69
Future income tax expense (recovery) 116 (224) 216 44
- --------------------------------------------------------------------------------------------------------------------
Income tax expense (recovery) $ 198 $ (187) $ 368 $ 113
====================================================================================================================
Taxable income from the conventional crude oil and natural gas business in
Canada is primarily generated through partnerships, with the related income
taxes payable in a future period. North America current income taxes have been
provided on the basis of the corporate structure and available income tax
deductions and will vary depending upon the nature and amount of capital
expenditures incurred in Canada in any particular year.
During 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.
7. SHARE CAPITAL
---------------------------------------------
Six Months Ended Jun 30, 2007
ISSUED NUMBER OF SHARES
COMMON SHARES (thousands) AMOUNT
- ----------------------------------------------------------------------------------------------------------------
Balance - beginning of period 537,903 $ 2,562
Issued upon exercise of stock options 1,482 16
Previously recognized liability on stock options exercised for
common shares - 71
- -----------------------------------------------------------------------------------------------------------------
Balance - end of period 539,385 $ 2,649
=================================================================================================================
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 June 30, 2007, the Company had not purchased any shares under the Normal
Course Issuer Bid.
DIVIDEND POLICY
In March 2007, the Board of Directors set the regular quarterly dividend at
$0.085 per common share. The Company has paid regular quarterly dividends in
January, April, July, and October of each year since 2001. The dividend policy
undergoes a periodic review by the Board of Directors and is subject to change.
CANADIAN NATURAL RESOURCES LIMITED 57
===============================================================================
STOCK OPTIONS
--------------------------------------------
Six Months Ended Jun 30, 2007
STOCK OPTIONS WEIGHTED AVERAGE
(thousands) EXERCISE PRICE
- -------------------------------------------------------------------------------------------------------
Outstanding - beginning of period 34,425 $ 33.77
Granted 801 $ 64.58
Exercised for common shares (1,482) $ 10.84
Surrendered for cash settlement (4,543) $ 15.21
Forfeited (1,433) $ 44.95
- -------------------------------------------------------------------------------------------------------
Outstanding - end of period 27,768 $ 38.39
- -------------------------------------------------------------------------------------------------------
Exercisable - end of period 7,842 $ 22.33
=======================================================================================================
8. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income (loss) were as follows:
----------------------
JUN 30 Jun 30
2007 2006
- ----------------------------------------------------------------------------------------------------------------
Derivative financial instruments designated as cash flow hedges $ 80 $ -
Foreign currency translation adjustment (18) (12)
- ----------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) $ 62 $ (12)
================================================================================================================
9. NET EARNINGS PER COMMON SHARE
Six Months Ended
------------- ---------------
JUN 30 Jun 30 JUN 30 Jun 30
2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding (thousands) - 539,296 537,351 539,094 537,188
basic and diluted
- ------------------------------------------------------------------------------------------------------------------------
Net earnings - basic and diluted $ 841 $ 1,038 $ 1,110 $ 1,095
- ------------------------------------------------------------------------------------------------------------------------
Net earnings per common share - basic and diluted $ 1.56 $ 1.93 $ 2.06 $ 2.04
=========================================================================================================================
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:
---------------------------
SIX MONTHS ENDED Year Ended
JUN 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 215 455 -
Net change in fair value of outstanding derivative financial
instruments attributable to:
- Risk management activities (479) 995 -
- Interest expense (39) - -
- Foreign exchange (207) 10 -
- Other comprehensive income 112 - -
Amortization of deferred revenue - - 8
- -----------------------------------------------------------------------------------------------------------------------------
(256) 583 -
Add: Put premium financing obligations (1) (239) (455) -
- -----------------------------------------------------------------------------------------------------------------------------
Balance - end of period (495) 128 -
Less: current portion (149) 88 -
- -----------------------------------------------------------------------------------------------------------------------------
$ (346) $ 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 losses (gains) from risk management activities were as follows:
Three Months Ended Six Months Ended
------------------- --------------------
JUN 30 Jun 30 JUN 30 Jun 30
2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------------
Net realized risk management loss $ 92 $ 407 $ 4 $ 795
Net unrealized risk management
mark-to-market (gain) loss (57) (26) 479 (18)
- ----------------------------------------------------------------------------------------------------------------------
$ 35 $ 381 $ 483 $ 777
======================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 59
===============================================================================
The Company had the following net financial derivatives outstanding as at June
30, 2007:
Remaining term Volume Average price Index
- ----------------------------------------------------------------------------------------------------------------------
CRUDE OIL
Crude oil price collars Jul 2007 - Dec 2007 15,000 bbl/d US$50.00 - US$66.25 Mayan Heavy
Jul 2007 - Dec 2007 50,000 bbl/d US$60.00 - US$71.49 WTI
Jul 2007 - Dec 2007 100,000 bbl/d US$60.00 - US$78.11 WTI
Jul 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 - 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 Jul 2007 - Dec 2007 100,000 bbl/d US$45.00 WTI
Jul 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 Jul 2007 - Dec 2007 50,000 bbl/d US$1.34 WTI/Dated Brent
======================================================================================================================
The net cost of outstanding put options and their respective periods of
settlement are as follows:
Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008
- ----------------------------------------------------------------------------------------------------------------------
Cost ($ millions) US$72 US$72 US$14 US$15 US$15 US$15
======================================================================================================================
Remaining term Volume Average price Index
- ---------------------------------------------------------------------------------------------------------------------
NATURAL GAS
AECO collars Jul 2007 - Dec 2007 60,000 GJ/d C$8.00 - C$8.79 AECO
Jul 2007 - Oct 2007 500,000 GJ/d C$6.00 - C$10.13 AECO
Jul 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 will be settled
monthly based on the applicable index pricing for the respective contract
month.
In addition to the financial derivatives noted above, the Company also entered
into natural gas physical sales contracts for 300,000 GJ/d at an average fixed
price of C$7.33 per GJ at AECO for the remaining period July 2007 to October
2007.
60 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
Remaining term Amount ($ millions) Fixed rate Floating rate
- -------------------------------------------------------------------------------------------------------------------
INTEREST RATE
Swaps - fixed to floating Jul 2007 - Oct 2012 US$350 5.45% LIBOR (1) + 0.81%
Jul 2007 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
===================================================================================================================
(1) LONDON INTERBANK OFFERED RATE
Remaining term Amount Exchange rate Interest rate Interest rate
($ millions) (US$/C$) (US$) (C$)
- -------------------------------------------------------------------------------------------------------------------
CROSS CURRENCY
Swaps Jul 2007 - Aug 2016 US$250 1.116 6.00% 5.40%
Jul 2007 - May 2017 US$1,100 1.170 5.70% 5.10%
Jul 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 (1) $ 133 $ 217 $ 147 $ 135 $ 105 $ 1,055
Offshore equipment operating $ $
leases (2) $ 195 48 48 $ 48 $ 46 $ 108
Offshore drilling (3) (4) $ 187 $ 168 $ 50 $ 50 $ 48 $ 162
Asset retirement $ $
obligations (5) $ 2 3 3 $ 4 $ 4 $ 4,422
Office leases $ 15 $ 31 $ 31 $ 32 $ 22 $ -
Electricity and other $ 89 $ 158 $ 165 $ 18 $ 1 $ -
============================================================================================================================
(1) THE COMPANY ENTERED INTO A 25-YEAR PIPELINE TRANSPORTATION AGREEMENT
COMMENCING IN 2008, RELATED TO FUTURE CRUDE OIL PRODUCTION. THE AGREEMENT
IS RENEWABLE FOR SUCCESSIVE 10-YEAR PERIODS AT THE COMPANY'S OPTION.
DURING THE INITIAL TERM, THE ANNUAL TOLL PAYMENTS BEFORE OPERATING COSTS
WILL BE APPROXIMATELY $35 MILLION.
(2) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF
OBLIGATIONS RELATED TO FLOATING PRODUCTION, STORAGE AND OFFTAKE VESSELS
("FPSO"). DURING 2006, THE COMPANY ENTERED INTO AN AGREEMENT TO LEASE AN
ADDITIONAL FPSO COMMENCING IN 2008, IN CONNECTION WITH THE PLANNED
OFFSHORE DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. THE NEW FPSO LEASE
AGREEMENT CONTAINS CANCELLATION PROVISIONS AT THE OPTION OF THE COMPANY,
SUBJECT TO ESCALATING TERMINATION PAYMENTS THROUGHOUT 2007 TO A MAXIMUM
OF US$395 MILLION. AS AT JUNE 30, 2007, US$140 MILLION OF POTENTIAL
TERMINATION PAYMENTS HAVE BEEN INCLUDED AS A 2007 COMMITMENT IN THIS
TABLE.
(3) 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 THE FOURTH QUARTER
OF 2007, SUBJECT TO RIG AVAILABILITY. MINIMUM ESTIMATED TOTAL PAYMENTS OF
US$100 MILLION, AFTER JOINT VENTURE RECOVERIES, HAVE BEEN INCLUDED IN
THIS TABLE FOR THE PERIOD 2007 - 2008.
(4) 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. IN ADDITION TO INCURRED
CONSTRUCTION COSTS, THE WELLHEAD TOWERS AGREEMENT CONTAINS CANCELLATION
PROVISIONS AT THE OPTION OF THE COMPANY, SUBJECT TO VARYING TERMINATION
PAYMENTS BASED ON PRO-RATA PERCENTAGES OF THE CONTRACT PRICE THROUGHOUT
JUNE 2009, SUBJECT TO A MAXIMUM OF US$95 MILLION. THE DRILLING RIG
AGREEMENT CONTAINS CANCELLATION PROVISIONS AT THE OPTION OF THE COMPANY,
SUBJECT TO ESCALATING TERMINATION PAYMENTS TO A MAXIMUM OF US$55 MILLION
IN 2008. AS AT JUNE 30, 2007, US$120 MILLION OF POTENTIAL CANCELLATION
AND TERMINATION PAYMENTS HAVE BEEN INCLUDED AS A 2007 COMMITMENT IN THIS
TABLE.
(5) 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 June 30, 2007 was approximately $5.4
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
Three Months Six Months Three Months Six Months Three Months Six Months
(millions of Canadian Ended Ended Ended Ended Ended Ended
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30 Jun 30 Jun 30
--------- ------- --------- --------- --------- ----------
2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE 2,584 2,406 5,119 4,522 402 377 833 697 161 255 305 482
Less: royalties (315) (295) (681) (605) - - (1) (1) (16) (7) (25) (12)
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE, NET OF 2,269 2,111 4,438 3,917 402 377 832 696 145 248 280 470
ROYALTIES
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production 442 356 864 668 120 87 236 168 18 19 40 41
Transportation and
blending 391 407 756 791 4 5 8 8 - - - -
Depletion, depreciation
and amortization 595 448 1,155 863 87 62 194 122 36 45 76 89
Asset retirement
obligation accretion 10 9 19 17 7 7 15 15 - - 1 1
Realized risk management
activities 67 316 (25) 633 25 91 29 162 - - - -
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES 1,505 1,536 2,769 2,972 243 252 482 475 54 64 117 131
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS (LOSS)
BEFORE THE FOLLOWING 764 575 1,669 945 159 125 350 221 91 184 163 339
- --------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration
Stock-based compensation
expense (recovery)
Interest, net
Unrealized risk
management activities
Foreign exchange gain
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED
EXPENSES
- --------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES
Taxes other than income
tax
Current income tax expense
Future income tax expense
(recovery)
- --------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS
================================================================================================================================
62 CANADIAN NATURAL RESOURCES LIMITED
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MIDSTREAM INTER-SEGMENT ELIMINATION AND OTHER TOTAL
Three Months Six Months Three Months Six Months Three Months Six Months
(millions of Canadian Ended Ended Ended Ended Ended Ended
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30 Jun 30 Jun 30
--------- ------- --------- --------- --------- ----------
2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE 17 17 36 35 (12) (14) (23) (27) 3,152 3,041 6,270 5,709
Less: royalties - - - - - - - - (331) (302) (707) (618)
- -------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE, NET OF 17 17 36 35 (12) (14) (23) (27) 2,821 2,739 5,563 5,091
ROYALTIES
- -------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production 5 6 11 11 (1) (1) (2) (2) 584 467 1,149 886
Transportation and blending - - - - (10) (10) (20) (20) 385 402 744 779
Depletion, depreciation and
amortization 2 2 4 4 - - - - 720 557 1,429 1,078
Asset retirement obligation
accretion - - - - - - - - 17 16 35 33
Realized risk management
activities - - - - - - - - 92 407 4 795
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES 7 8 15 15 (11) (11) (22) (22) 1,798 1,849 3,361 3,571
- -------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS (LOSS)
BEFORE THE FOLLOWING 10 9 21 20 (1) (3) (1) (5) 1,023 890 2,202 1,520
- -------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration 53 40 113 82
Stock-based compensation
expense (recovery) 106 (34) 131 98
Interest, net 77 28 160 53
Unrealized risk management
activities (57) (26) 479 (18)
Foreign exchange gain (224) (46) (251) (41)
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED EXPENSES (45) (38) 632 174
- -------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 1,068 928 1,570 1,346
Taxes other than income tax 29 77 92 138
Current income tax expense 82 37 152 69
Future income tax expense
(recovery) 116 (224) 216 44
- -------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS 841 1,038 1,110 1,095
===============================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 63
===============================================================================
NET ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT
Six Months Ended
JUN 30, 2007 Jun 30, 2006
----------------------------------------------------
NON-CASH/ Non-Cash/
NET CASH FAIR VALUE CAPITALIZED Net Cash Fair Value Capitalized
EXPENDITURES CHANGES (1) COSTS Expenditures Changes (1) Costs
- -------------------------------------------------------------------------------------------------------------------------------
North America $ 1,417 $ 8 $ 1,425 $ 1,973 $ 5 $ 1,978
North Sea 274 - 274 287 - 287
Offshore West Africa 82 - 82 77 - 77
Other 2 - 2 9 - 9
Horizon Project (2) 1,650 - 1,650 1,468 - 1,468
Midstream 2 - 2 9 - 9
Head office 9 - 9 12 - 12
- -------------------------------------------------------------------------------------------------------------------------------
$ 3,436 $ 8 $ 3,444 $ 3,835 $ 5 $ 3,840
===============================================================================================================================
(1) ASSET RETIREMENT OBLIGATIONS, FUTURE INCOME TAX ADJUSTMENTS ON NON-TAX
BASE ASSETS, AND OTHER FAIR VALUE ADJUSTMENTS.
(2) CASH EXPENDITURES FOR THE HORIZON PROJECT ALSO INCLUDE CAPITALIZED
INTEREST AND STOCK-BASED COMPENSATION.
Property, plant and equipment Total assets
-------------------- ----------------------
JUN 30 Dec 31 JUN 30 Dec 31
2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
SEGMENTED ASSETS
North America $ 22,166 $ 21,879 $ 23,637 $ 23,670
North Sea 1,939 2,029 2,150 2,248
Offshore West Africa 1,194 1,204 1,304 1,323
Other 26 24 49 46
Horizon Project 7,000 5,350 7,106 5,444
Midstream 205 207 314 355
Head office 71 74 71 74
- --------------------------------------------------------------------------------------------------------------------------
$ 32,601 $ 30,767 $ 34,631 $ 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 six months
ended June 30, 2007, pre-tax interest of $152 million was capitalized to the
Horizon Project (June 30, 2006 - $74 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 August 2005. These ratios are based on the Company's interim consolidated
financial statements that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended June 30, 2007:
- --------------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 7.5x
Cash flow from operations (2) 12.1x
===============================================================================
(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-CHAIRMAN OF THE BOARD VICE-PRESIDENT, UTILITIES & OFFSITES
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 & VICE-PRESIDENT, EXPLOITATION - EAST
CORPORATE DEVELOPMENT
Bill R. Peterson
Tim S. McKay* VICE-PRESIDENT, PRODUCTION - WEST
SENIOR VICE-PRESIDENT, OPERATIONS
John C. Puckering
Lyle G. Stevens* VICE-PRESIDENT, SITE DEVELOPMENT
SENIOR VICE-PRESIDENT, EXPLOITATION
Timothy G. Reed
Jeff W. Wilson* VICE-PRESIDENT, HUMAN RESOURCES
SENIOR VICE-PRESIDENT, EXPLORATION
Sheldon L. Schroeder
Corey B. Bieber VICE-PRESIDENT, PROJECT CONTROL
VICE-PRESIDENT, FINANCE & INVESTOR RELATIONS
Ken W. Stagg
Jeffery J. Bergeson VICE-PRESIDENT, EXPLORATION - WEST
VICE-PRESIDENT, EXPLOITATION - WEST
Scott G. Stauth
Mary-Jo E. Case* VICE-PRESIDENT, FIELD OPERATIONS
VICE-PRESIDENT, LAND
Steve C. Suche
William R. Clapperton VICE-PRESIDENT,
VICE-PRESIDENT, REGULATORY, STAKEHOLDER & INFORMATION & CORPORATE SERVICES
ENVIRONMENTAL AFFAIRS
Domenic Torriero
James F. Corson VICE-PRESIDENT, EXPLORATION - CENTRAL
VICE-PRESIDENT, HUMAN RESOURCES, HORIZON
Grant M. Williams
Randall S. Davis* VICE-PRESIDENT, EXPLORATION - EAST
VICE-PRESIDENT, FINANCE & ACCOUNTING
Lynn M. Zeidler
Allan Frankiw VICE-PRESIDENT,
VICE-PRESIDENT, PRODUCTION - CENTRAL HORIZON CONSTRUCTION MANAGEMENT
Larry C. Galea Bruce E. McGrath
VICE-PRESIDENT, EXPLOITATION - CENTRAL 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
Norman F. McIntyre
Computershare Trust Company of Canada Honourable Frank J. McKenna, P.C., O.N.B., Q.C.
CALGARY, ALBERTA James S. Palmer, C.M., A.O.E., Q.C.
TORONTO, ONTARIO Eldon R. Smith, M.D.
David A. Tuer
Computershare Investor Services LLC
NEW YORK, NEW YORK
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
68 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================