UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
Pursuant to Section 13a-16 15d-16 of the
Securities Exchange Act of 1934
This Form 6-K is hereby incorporated by reference into the
Corporation's Registration Statement on Form - F9 (File No. 333-13666)
Interim Report for the
Nine month period ended SEPTEMBER 30, 2002
------------------------------------------
CANADIAN NATURAL RESOURCES LIMITED
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Canada 1-8795 Not applicable
---------------------------- ----------- ----------------
(State or other jurisdiction (Commission (I.R.S. Employer
of incorporation) File Number) Identification No.)
2500, 855 - 2nd Street S.W., Calgary, Alberta, Canada T2P 4J8
----------------------------------------------------- -------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (403) 517-6700
Indicate by check mark whether the registrant files or will file annual
reports under cover Form 20-F or Form 40-F.
Form 20-F [_] Form 40-F [X]
Indicate by check mark whether the registrant by furnishing the
information contained in this Form is also thereby furnishing the information to
the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of
1934.
Yes [_] No [X]
If "Yes" is marked, indicate below the file number assigned to the
registrant in connection with Rule 12g3-2(b): 82-______.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
CANADIAN NATURAL RESOURCES LIMITED
(Registrant)
Date: November 06, 2002 By: /s/ B.E. MCGRATH
------------------------------
B.E. McGRATH
Corporate Secretary
[GRAPHIC OMITTED
LOGO: CNR PRESS
CANADIAN NATURAL RESOURCES LIMITED RELEASE]
================================================================================
CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES
2002 THIRD QUARTER RESULTS
CALGARY, ALBERTA - NOVEMBER 6, 2002 - FOR IMMEDIATE RELEASE
================================================================================
CANADIAN NATURAL ANNOUNCES RECORD QUARTERLY CASH FLOW
In commenting on third quarter 2002 results, Canadian Natural's Chairman, Allan
Markin, stated "Canadian Natural Resources has continued to undertake steps that
strengthened the Company's position as a major international independent. The
acquisition of Rio Alto Exploration Ltd. added significant production and upside
potential on the natural gas front. We will take a methodical approach to
developing the Northwest Alberta properties and have already identified
opportunities for economically unlocking the Cardium natural gas potential. Over
the next few years this acquisition will add significantly to the portfolio of
natural gas exploration and development opportunities available to the Company."
"Also during the quarter, a major acquisition of properties in the northern
portion of the North Sea solidified our presence there. We now control and have
majority ownership interests in these assets, similar to our holdings throughout
the rest of the world. Our focus has always been exploitation and this
acquisition will enable the Company to carry out this business plan in the North
Sea."
"During the quarter, production from the Ladyfern field started its steep
decline. We always expected 70% production declines, but were unsure of when
they would commence. We knew that this decline would have to be replaced and so
given weaker natural gas pricing, determined it prudent to defer other natural
gas drilling to 2003. Consequently, our natural gas drilling is only one-third
of what it was last year. In 2003, our natural gas drilling activity will exceed
2001 levels to stem further expected declines from Ladyfern and keep 2003
natural gas production constant from entry to exit."
"Our 2003 budget points out two recurring themes that will continue for the next
several years. First, growth on total base production will continue at rates
approximating 10% per annum. Second, an increasing amount of capital spent today
is related to projects that do not add production or cash flow until future
years. As an example, in 2003, expenditures relating to the drilling of high
pressure wells at Primrose, development costs relating to the Baobab field and
the Horizon Oil Sands Project will not yield cash returns until future years.
The 2003 budget provides manageable, efficient 10% production growth and a
strong base for sustainable growth in the future."
"I would like to thank all of the employees that were instrumental in
accomplishing a seamless integration of newly acquired properties into Canadian
Natural. By working together we have been able to minimize disruptions and
ensure delivery of value to our shareholders."
HIGHLIGHTS OF THE THIRD QUARTER
o Natural gas sales volumes of 1,427 million cubic feet per day, an
increase of 54% from the third quarter of last year and a 32% increase
from the previous quarter of this year.
o Oil and liquids sales volumes of 242 thousand barrels per day.
Production of primary heavy oil and thermal heavy oil accounted for 22%
of production on a barrel of oil equivalent basis, down from 24% during
the previous quarter.
o Record quarterly cash flow of $644 million ($4.83 per common share)
compared with $437 million ($3.62 per common share) in the third
quarter of 2001 and $475 million ($3.86 per common share) in the
previous quarter.
o Net earnings of $117 million ($0.88 per common share) compared with $81
million ($0.67 per common share) for the third quarter of 2001 and $145
million ($1.18 per common share) in the previous quarter. Adjusted net
earnings amounted to $164 million ($1.23 per common share) compared
with $143 million ($1.18 per common share) for the third quarter of
2001 and $118 million ($0.96 per common share) in the previous quarter.
o Realized an 18% increase in the wellhead price for its oil and liquids
sales over the corresponding quarter of 2001, as a result of lower
price differentials for heavy oil production.
o Successfully completed the $2.3 billion acquisition of Rio Alto
Exploration Ltd. ("Rio Alto") with closing effective July 1, 2002. This
acquisition added significant natural gas production resulting in
Canadian Natural becoming one of North America's largest natural gas
producers.
o Successfully negotiated the acquisition of ownership interests and
transition to operator of two producing platforms in the North Sea
resulting in Canadian Natural now owning an average interest of 75% and
operating 90% of its producing properties in the North Sea.
o Continued the Design Basis Memorandum for the proposed Horizon Oil
Sands Project, located 80 kilometers north of Fort McMurray in
Northeastern Alberta, which is expected to produce approximately 230
thousand barrels per day of light synthetic crude oil.
o Brought one additional producing well on-stream at the Espoir field
offshore Cote d'Ivoire during the quarter. Additional producing wells
scheduled for completion during the third quarter were delayed due to
slower than expected drilling. An additional well was spud in October,
2002 and two wells will now be completed in December. Commercial
development plans continued on the Baobab field.
o Successfully negotiated a 50% working interest and operatorship for
Block 16 located offshore Angola. This high risk/high potential
exploration block is located in one of the world's most prospective oil
basins.
o Successfully completed a United States debt offering of US $350 million
of 10-year notes at an interest rate of 5.45% and US $350 million of
31-year notes at an interest rate of 6.45%.
CANADIAN NATURAL RESOURCES LIMITED 2
================================================================================
ADJUSTED NET EARNINGS
The following reconciliation lists the after-tax effects of certain items for
each of the periods reported.
THREE MONTHS ENDED NINE MONTHS ENDED
---------------------- -----------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001 2002 2001
====== ====== ====== ====== ======
($ MILLIONS, EXCEPT PER SHARE AMOUNTS)
Net earnings attributable to common
shareholders as reported $ 117 $ 145 $ 81 $ 362 $ 590
Unrealized foreign exchange loss
(gain) (1) 42 (64) 57 (35) 61
Unrealized foreign exchange loss (gain)
on preferred securities(1) 5 (6) 5 (1) 6
Effect of statutory tax rate changes on
future income tax liabilities(2) -- 13 -- 13 (46)
Reduction in carrying value of foreign
assets(3) -- 30 -- 30 --
-----------------------------------------
Adjusted net earnings attributable to
common shareholders $ 164 $ 118 $ 143 $ 369 $ 611
=========================================
Per share - basic $1.23 $0.96 $1.18 $2.93 $5.03
- diluted $1.20 $0.88 $1.16 $2.83 $4.89
=====================================================================================
(1) GAINS AND LOSSES ON THE TRANSLATION OF LONG-TERM DEBT AND PREFERRED
SECURITIES TO PERIOD END EXCHANGE RATES ARE IMMEDIATELY RECOGNIZED IN NET
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS.
(2) 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 LIABILITIES. THE IMPACT OF THESE TAX RATE
CHANGES ARE RECORDED IN NET EARNINGS DURING THE PERIOD THE LEGISLATION IS
SUBSTANTIVELY ENACTED. DURING THE SECOND QUARTER OF 2002, THE UNITED KINGDOM
INCREASED INCOME TAXES APPLICABLE TO THE OIL AND NATURAL GAS INDUSTRY AND A
CANADIAN PROVINCE REDUCED CORPORATE INCOME TAX RATES.
(3) FOLLOWING AN UNSUCCESSFUL EXPLORATORY WELL ON BLOCK 19 IN ANGOLA AND THE
DECISION TO WITHDRAW FROM AN EXPLORATION BLOCK IN NIGERIA, ALL CAPITALIZED
COSTS RELATED TO THESE PROJECTS WERE CHARGED TO NET EARNINGS.
OPERATIONS REVIEW
PRODUCTION
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 oil, Pelican Lake oil, primary heavy oil and thermal heavy
oil.
Third quarter 2002 natural gas production averaged 1,427 mmcf/d, an increase of
54% from the third quarter of 2001 and a 32% increase from the second quarter of
2002. Natural gas production accounted for 50% of the Company's production this
quarter and reflected the July 1, 2002 acquisition of Rio Alto and the
commencement of natural declines at Ladyfern. Production from properties owned
by Rio Alto at the time of the acquisition was 410 mmcf/d and after the effect
of normal depletion exited the quarter at 384 mmcf/d. Ladyfern production
declined from an average of 201 mmcf/d in the second quarter of 2002 to 178
mmcf/d during the third quarter. The Company currently expects this field to
continue declines in the order of 70% through 2003. This steep decline commenced
in late August as pressures declined and the most down-dip well in the pool
watered out. Water encroachment continues into a second well, with the effect
that significant declines continue and current production, net to Canadian
Natural, of 130 - 140 mmcf/d. Canadian Natural expected such declines to occur,
but was unsure of the timing and magnitude of the water influx, which in
formations such as the Slave Point is difficult to forecast. The Company
purposefully reduced 2002 natural gas drilling activity to build drilling
prospect inventory to offset these anticipated declines. Access to many parts of
the western Canadian natural gas basin is possible in winter months
CANADIAN NATURAL RESOURCES LIMITED 3
================================================================================
only, precluding an acceleration of replacement drilling. The following schedule
provides a summary of natural gas production:
NATURAL GAS PRODUCTION LEVELS
DAILY
PRODUCTION
(MMCF/D)
------------
Third quarter 2002 opening volume 1,071
Additions: Volume additions through drilling and recompletions 69
Rio Alto acquisition 410
Declines: Normal decline in base production (50)
Normal decline in Rio Alto properties (26)
Ladyfern declines (54)
------------
Third quarter 2002 exit volume 1,420
================================================================================
Production of oil and liquids in the third quarter of 2002 was 28% higher than
the previous quarter and 17% higher than the corresponding period of last year.
Increases in North America reflected additional heavy oil drilling activity and
acquired production. North Sea volumes increased both as a result of the
acquisition of additional interests in the northern sector of the North Sea and
the correction of a pipeline blockage at the Kyle field. Offshore West Africa
volumes increased as one additional producing well was brought on-stream at the
Espoir field.
The Company's production composition is as follows:
Q3 2002 Q2 2002 Q3 2001
============== ============ ============
MBOE/D % MBOE/D % MBOE/D %
------ - ------ - ------ -
Natural gas 237.9 50 179.6 49 154.0 43
Light oil and NGLs 102.8 21 70.1 19 77.7 21
Pelican Lake oil 32.0 7 30.8 8 34.4 10
Primary heavy oil 66.9 14 51.3 14 58.1 16
Thermal heavy oil 40.3 8 37.2 10 36.8 10
----- -- ----- -- ----- --
479.9 100 369.0 100 361.0 100
================================================================================
The Company expects production levels in the fourth quarter of 2002 to average
1,350 to 1,365 mmcf/d of natural gas and 240 to 250 mbbls/d of oil and liquids.
This results in expected annual 2002 production levels of approximately 1,230
mmcf/d of natural gas (2001 - 918 mmcf/d) and approximately 216 mbbls/d of oil
and liquids (2001 - 206 mbbls/d).
CANADIAN NATURAL RESOURCES LIMITED 4
================================================================================
DRILLING ACTIVITY (NUMBER OF WELLS)
NINE MONTHS ENDED SEPTEMBER 30
-------------------------------
2002 2001
==== ====
GROSS NET GROSS NET
----- --- ----- ---
Oil 290 253 264 228
Natural gas 165 150 541 460
Dry 27 23 38 32
--- --- --- ---
Subtotal 482 426 843 720
Injection/strat tests 416 408 251 250
--- --- --- ---
Total 898 834 1,094 970
=== === ===== ===
Success rate (EXCLUDING INJECTION/STRAT TESTS) 95% 96%
================================================================================
Canadian Natural drilled 60 net oil wells and 27 net natural gas wells during
the third quarter of 2002. These wells were concentrated in the Company's heavy
oil areas of North Alberta/West Saskatchewan, the light oil areas of Southeast
Saskatchewan and its four natural gas core areas. The total success rate for
Canadian Natural's drilling program was 97% during the third quarter, excluding
injection/stratigraphic test wells.
The number of net wells drilled during the first nine months of the year
(excluding injection/stratigraphic test wells) decreased 41% from the prior
year, comprised of a 67% reduction in natural gas well drilling and an 11%
increase in oil well drilling. The decrease in natural gas drilling reflects the
Company's decision to defer natural gas drilling to offset anticipated future
Ladyfern production declines and reflects its capital allocation policy which
opportunistically has shifted additional capital into heavy oil drilling to take
advantage of favourable market pricing.
During the first nine months of the year, the Company drilled 408 net
injection/stratigraphic test wells on the oil sands leases in the Horizon Oil
Sands Project and in North Alberta/West Saskatchewan.
PRICING
Netbacks received for Canadian Natural's heavy oil and Pelican Lake oil
production improved significantly over the last year due to both higher WTI
pricing and the narrowing of price differentials to WTI. Canadian Natural
expects these heavy oil differentials to widen during the fourth quarter due to
seasonality and additional production from western Canada. This differential is
still expected to be significantly lower, however, than differentials
experienced during the fourth quarter of 2001 when a refinery closure resulted
in reduced heavy oil demand.
In 2003, as part of its overall risk management program, the Company has placed
costless collars on a portion of its oil production. During January to June,
2003 sales of a total of 104,000 bbls/d are subject to a floor price of US
$22.09 with a ceiling price of US $27.26. In July and August, 2003 sales of a
total of 60,000 bbls/d are subject to a floor price of US $23.00 with a ceiling
price of US $27.85.
During the third quarter of 2002 natural gas pricing in Canada was subject to
abnormally high differentials to NYMEX benchmark pricing. This was the result of
common carrier pipeline maintenance activities and its subsequent impact on
exports of natural gas to the United States.
CANADIAN NATURAL RESOURCES LIMITED 5
================================================================================
A comparison of the price received for the Company's North American production
is as follows:
PRICING
INDICATIONS AS AT
NOV 4, 2002 Q3 2002 Q2 2002 Q3 2001
================ =============== ================ ================
WTI benchmark price (US $/BBL) $ 26.95 $ 28.25 $ 26.26 $ 26.57
Differential to LLB blend (US $/BBL) $ 8.44 $ 5.97 $ 6.04 $ 8.10
Condensate benchmark price (US $/BBL) $ 27.78 $ 28.14 $ 26.36 $ 26.70
NYMEX benchmark price (US $/MMBTU) $ 3.87 $ 3.26 $ 3.37 $ 2.99
AECO benchmark price (CDN $/MMBTU) $ 5.31 $ 3.25 $ 4.43 $ 3.93
Canadian Natural's Wellhead Price(1)
Light oil and NGLs (CDN $/BBL) $ 36.07 $ 34.36 $ 31.90 $ 35.03
Pelican Lake oil (CDN $/BBL) $ 23.71 $ 30.58 $ 25.05 $ 24.99
Primary heavy oil (CDN $/BBL) $ 23.10 $ 30.11 $ 24.54 $ 23.69
Thermal heavy oil (CDN $/BBL) $ 22.58 $ 29.23 $ 23.73 $ 22.46
Natural gas (CDN $/MCF) $ 4.96 $ 3.15 $ 3.72 $ 3.12
=======================================================================================================================
(1) INCLUDING FINANCIAL INSTRUMENTS.
ACTIVITY BY CORE REGION
NET UNDEVELOPED LAND DRILLING ACTIVITY
AS AT PERIOD ENDED
SEPTEMBER 30, 2002 SEPTEMBER 30, 2002
(THOUSANDS OF NET ACRES) (NET WELLS)
======================== ==================
Northeast British Columbia 1,393 43
Northwest Alberta 1,952 11
North Alberta/West Saskatchewan 4,261 464
Horizon Oil Sands 237 256
South Alberta 889 50
Southeast Saskatchewan 166 5
United Kingdom North Sea 401 2
Offshore West Africa 1,862 3
=======================================================================================
2003 BUDGET
Canadian Natural continues its strategy of maintaining a large portfolio of
varied projects, which enables the Company over an extended period of time to
provide consistent growth in production and high shareholder returns. Annual
budgets are developed, scrutinized throughout the year and changed if necessary
in the context of project returns, product pricing expectations, and balance in
project risks and time horizons. Canadian Natural maintains a high ownership
level and operatorship level in all of its properties and can therefore control
the nature, timing and extent of expenditures in each of its project areas.
Canadian Natural is presently budgeting a cash flow from operations in 2003 of
$2,350 million to $2,500 million. This cash flow is derived from production of
1,280 to 1,330 mmcf/d of natural gas and 240,000 to 260,000 bbls/d of oil and
liquids, and applying the current strip pricing parameters averaging WTI price
of US $24.00, a WTI to LLB oil differential price of US $8.50 and an AECO
natural gas price of $5.20 per mcf.
CANADIAN NATURAL RESOURCES LIMITED 6
================================================================================
The budgeted capital expenditures in 2003 are currently expected to be as
follows:
($ MILLIONS) 2003
=============
Canadian natural gas properties $ 691
Canadian oil properties 517
Horizon oil sands 211
International oil properties - United Kingdom 281
International oil properties - Offshore West Africa 280
Property acquisitions 300
=============
$ 2,280
================================================================================
NORTH AMERICA CONVENTIONAL
As a result of 2002's strong Ladyfern production increases during the first half
of the year, Canadian Natural reduced current year natural gas drilling activity
with a view to building prospect inventories in anticipation of expected high
Ladyfern declines. The Ladyfern pool in Northeast British Columbia has been a
tremendous success for Canadian Natural. Production ramped up very quickly and
the pool is being depleted in a quick, orderly fashion. Ladyfern is a rare pool
and difficult to replicate.
Canadian Natural plans to continue its exploration program in deeper formations
in Northeast British Columbia, including the Slave Point trend, where two and
possibly three wells will be drilled during the winter of 2003. The Slave Point
horizon is technically complex making it a high-risk exploration target.
Canadian Natural's exploration activities benefit from owning the area's largest
database of 2-D and 3-D seismic information and from its extensive landholdings
in the region.
The acquisition of Rio Alto effective July 1, 2002 provides Canadian Natural
with a high quality natural gas producing base as well as a new core area in
Northwest Alberta with extensive opportunities on a large undeveloped land base.
The undeveloped land contains multiple zones for natural gas production
supported by a large amount of seismic data and pipeline and natural gas plant
infrastructure. Canadian Natural will commence development of this land in the
first quarter of 2003 with the drilling of up to 52 wells. Approximately 17
wells will target the Cardium zone which is a complex geological zone requiring
both horizontal and vertical wells to test the production capabilities of the
formation.
During 2002 Canadian Natural drastically reduced the number of natural gas wells
drilled from 476 net natural gas wells drilled in 2001. The Company's natural
gas drilling program will be expanded in 2003 with the planned drilling of 580
wells on lands with natural gas potential. Approximately 240 of the wells will
be drilled in the first quarter on lands with winter only access. The remainder
of the well program, including approximately 250 southern Alberta shallow wells,
are scheduled for lands with year round access that can be drilled throughout
the year.
The experimental Pelican Lake emulsion flood continued to meet expectations
during the third quarter, with injections continuing since early April 2002. If
successful, this project will substantially increase the recovery factor from
the thin Pelican Lake sands. This field contains approximately three billion
barrels of original oil-in-place but is only expected to achieve a 6% recovery
factor using primary technologies. Based upon positive laboratory testing, this
project could double or triple recovery factors if the technology can be
implemented in the field. Data will continue to be gathered on the success of
this test throughout the last half of 2002. The Company plans to optimize the
emulsion project with a demonstration project during 2003.
Canadian Natural recently received regulatory approval to utilize high pressure
steaming at its thermal oil project at Primrose in eastern Alberta. In 2003, two
new pads containing a total of 24 wells each incorporating high pressure
steaming will be drilled on these lands. Steaming of these wells will commence
in the third quarter of 2003 with initial oil production following in mid 2004.
NORTH AMERICA HORIZON OIL SANDS PROJECT
CANADIAN NATURAL RESOURCES LIMITED 7
================================================================================
Following filing at the end of June of the Horizon Oil Sands project for
regulatory approvals, Canadian Natural commenced the Design Basis Memorandum
which is the second of the three phases of engineering design work.
It is currently anticipated that the Design Basis Memorandum will be completed
during the first quarter of 2003, at which point a decision to commence
Engineering Design Specifications ("EDS") will be made. Given current
uncertainty surrounding implementation of the Kyoto protocol by the Canadian
Government, and any specific terms thereof, a limited form of EDS or a major
scope change to use facilities outside of Canada may be initiated. At this time,
Canadian Natural has reduced its planned 2003 capital expenditures on the
Horizon Project by $100 million pending the clarification of the implementation
of the Kyoto protocol. The impact of a limited form of EDS or scope change would
likely defer commencement of first production by one year to late 2008. A
slowed-EDS, however, would enable the Company to achieve detailed engineering
design in excess of its targeted 85% prior to the start of construction, further
reducing risk of construction cost overruns.
UNITED KINGDOM
During the quarter Canadian Natural completed a property acquisition in the
northern North Sea that increased ownership levels in the Ninian, Murchison,
Lyell and Columba Terraces fields. Canadian Natural is now operator designee on
each of these fields. As part of the transaction the Company also received an
interest in the Strathspey field and 12 licences covering 20 exploration blocks
and part blocks surrounding the Ninian and Murchison platforms. Increased
ownership in related pipeline and terminaling infrastructure was also acquired.
Ownership and operatorship levels are now similar in the North Sea to those
levels found throughout Canadian Natural's other worldwide investments.
In the central North Sea, the blockage in the Kyle export natural gas pipeline
was repaired and production was restored in July, 2002. One additional well at
Banff, where Canadian Natural holds a 56% working interest, is currently
drilling.
In 2003, Canadian Natural has budgeted to spend a total of $281 million on its
international holdings in the United Kingdom. These funds will be directed
towards drilling of an additional 17 wells in the northern North Sea and one
additional well in the central North Sea. Other exploitation and waterflood
optimization programs will also be carried out in both areas to increase the
productivity and recovery factors in these known pools of light oil.
OFFSHORE WEST AFRICA
During the quarter, Canadian Natural continued the development of the 59% owned
and operated Espoir field located offshore Cote d'Ivoire with the drilling and
completion of the third producing well in the field. Additional producing wells
were expected to be onstream by the fourth quarter of the year, however slower
drilling of the fourth producing well in the field caused by drilling in
unanticipated uphole faults has delayed completion of the development program.
The fifth producer well has been spud, and it and the fourth producer will be
completed and tied in during the fourth quarter of 2002. The delay in these
wells in turn delays completion of additional producer and injector wells.
Inability to ramp up injectivity results in a slower build up of waterflood
pressures in the upper zones. Perforation of this upper zone is correspondingly
delayed until later in 2003.
Canadian Natural is proceeding with development plans on the Baobab field
located offshore Cote d'Ivoire. While determination of optimum facilities size
continues, it is anticipated that gross production in the range of 50-65 mbbls/d
of oil to a new FPSO could commence in late 2004/early 2005. Field development
plans have been submitted to the Government with finalization expected in the
next few months.
Political unrest in Cote d'Ivoire during the third quarter has had no impact on
the Company's operations. The Company has developed contingency plans to
continue Cote d'Ivoire operations from another nearby country. It is important
to note that insurrections to date have largely been concentrated in the
northern areas of the country, far away from the Company's offshore development
and far from Abidjan, where the Company's offices are located.
Canadian Natural's 2003 expenditure budget forecasts expenditures totaling $280
million in offshore West Africa. Expenditures incurred in Cote d'Ivoire of $220
million will result in the finalization of drilling and completion
CANADIAN NATURAL RESOURCES LIMITED 8
================================================================================
operations at Espoir, an exploration well at Acajou, and finalization of
development plans and fourth quarter drillingat Baobab. In Angola, Canadian
Natural has budgeted the drilling of a well in newly acquired Block 16
commencing in the third quarter.
FINANCIAL REVIEW
Canadian Natural recognizes the need for a strong financial position in order to
withstand volatile oil and natural gas commodity prices and the operational
risks inherent in the oil and natural gas business environment.
In September, the Company issued US $350 million of 10-year, 5.45% unsecured
notes and US $350 million of 31-year, 6.45% unsecured notes to purchasers in the
United States. The proceeds from the sale of the notes were used primarily to
repay bank indebtedness. The securities were rated "Baa1" by Moody's Investors
Service, Inc., "BBB+" by Standard & Poor's Corporation and "BBB (high)" by
Dominion Bond Rating Service Limited. The notes were issued under the short form
base shelf prospectus dated August 16, 2002, which allows for the issuance of
debt securities in an aggregate principal amount of up to US $1 billion.
Following these issues of debt securities the Company had:
o Approximately $1.3 billion of available unused bank credit lines.
o Fixed/floating interest rate mix of 47/53.
o An overall average borrowing cost of approximately 4.5% for the third
quarter of 2002.
o 73% of borrowings denominated in US $.
o Non-bank based borrowings of 75% of total long-term debt.
Long-term debt at September 30, 2002 amounted to $4.2 billion and reflected a
2.3x debt to cash flow ratio and a debt to book capitalization of 47.2%. This
increase in debt reflects the third quarter acquisition of Rio Alto and excludes
the cash flows and earnings prior to June 30, 2002.
The ratings for our debt securities and our relationships with our principal
banks are extremely important to us as we continue to expand and grow the
Company. Therefore, we will continually undertake to strengthen our balance
sheet and financial position.
In response to the expected demand for oil and natural gas, the related pricing
and to protect capital expenditure programs, the Company has entered into
several financial instruments to manage exposure to market volatility. The
details of these positions are set out in note 8 to the consolidated financial
statements. The Company will continue to actively pursue additional hedging
opportunities.
The regular fourth quarter dividend payment will occur on January 1, 2003 and
will be made to shareholders of record at the close of business on December 13,
2002.
CANADIAN NATURAL RESOURCES LIMITED 9
================================================================================
MANAGEMENT'S DISCUSSION AND ANALYSIS
Management's discussion and analysis ("MD&A") of the financial condition and
results of operations should be read in conjunction with the unaudited interim
consolidated financial statements for the nine months ended September 30, 2002
and the MD&A and the audited consolidated financial statements for the year
ended December 31, 2001.
Per barrel of oil equivalent ("boe") amounts have been calculated using a
conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
ACQUISITIONS
Effective July 1, 2002, the Company paid cash of $850.0 million and issued
10,008,000 common shares to acquire all of the issued and outstanding common
shares of Rio Alto Exploration Ltd. ("Rio Alto") by way of a plan of
arrangement. Also effective July 1, 2002, the Company acquired certain northern
North Sea assets in the United Kingdom for cash consideration of US $120.0
million and the Company's 5% interest in the Harding field. These acquisitions
are included in the results of operations commencing July 1, 2002.
THREE MONTHS ENDED NINE MONTHS ENDED
---------------------------------------------- ----------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001(1) 2002 2001(1)
============== ============== ============= ============= =============
FINANCIAL HIGHLIGHTS ($ MILLIONS, EXCEPT
PER SHARE AMOUNTS)
Revenue $ 1,173 $ 863 $ 811 $ 2,753 $ 2,922
Cash flow from operations attributable
to common shareholders(2) $ 644 $ 475 $ 437 $ 1,477 $ 1,594
Per share - basic $ 4.83 $ 3.86 $ 3.62 $ 11.73 $ 13.14
- diluted $ 4.71 $ 3.70 $ 3.54 $ 11.28 $ 12.61
Net earnings attributable to common
shareholders(3) $ 117 $ 145 $ 81 $ 362 $ 590
Per share - basic $ 0.88 $ 1.18 $ 0.67 $ 2.87 $ 4.86
- diluted $ 0.86 $ 1.09 $ 0.66 $ 2.78 $ 4.72
Acquisition of Rio Alto $ 2,309 $ - $ - $ 2,309 $ -
Capital expenditures, net of dispositions $ 621 $ 305 $ 352 $ 1,384 $ 1,355
==================================================================================================================================
(1) RESTATED FOR CHANGE IN ACCOUNTING POLICY (SEE CONSOLIDATED FINANCIAL
STATEMENT NOTES 1 AND 2).
(2) AFTER DIVIDEND ON PREFERRED SECURITIES.
(3) AFTER DIVIDEND AND REVALUATION OF PREFERRED SECURITIES.
CANADIAN NATURAL RESOURCES LIMITED 10
================================================================================
THREE MONTHS ENDED NINE MONTHS ENDED
---------------------------------------------- ----------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001(1) 2002 2001(1)
============== ============== ============= ============= =============
OPERATING HIGHLIGHTS
OIL AND LIQUIDS ($/BBL, EXCEPT DAILY PRODUCTION)
Daily production (BBLS/D) 242,051 189,386 207,065 206,822 209,128
Sales price $ 33.57 $ 28.27 $ 28.37 $ 29.23 $ 25.28
Royalties 3.56 3.02 2.47 3.01 2.41
Production expense 8.67 7.95 7.29 8.19 7.68
-------------- -------------- ------------- ------------- -------------
Netback $ 21.34 $ 17.30 $ 18.61 $ 18.03 $ 15.19
-------------- -------------- ------------- ------------- -------------
NATURAL GAS ($/MCF, EXCEPT DAILY PRODUCTION)
Daily production (MMCF/D) 1,427 1,078 924 1,188 887
Sales price $ 3.13 $ 3.68 $ 3.12 $ 3.28 $ 6.01
Royalties 0.67 0.77 0.67 0.67 1.49
Production expense 0.55 0.57 0.50 0.57 0.50
-------------- -------------- ------------- ------------- -------------
Netback $ 1.91 $ 2.34 $ 1.95 $ 2.04 $ 4.02
-------------- -------------- ------------- ------------- -------------
BARRELS OF OIL EQUIVALENT ($/BOE, EXCEPT DAILY
PRODUCTION)
Daily production (BOE/D) 479,949 369,022 361,029 404,745 356,905
Sales price $ 26.26 $ 25.29 $ 24.25 $ 24.57 $ 29.76
Royalties 3.80 3.79 3.14 3.49 5.10
Production expense 6.01 5.76 5.47 5.85 5.75
-------------- -------------- ------------- ------------- -------------
Netback $ 16.45 $ 15.74 $ 15.64 $ 15.23 $ 18.91
==================================================================================================================================
(1) RESTATED FOR CHANGE IN ACCOUNTING POLICY (SEE CONSOLIDATED FINANCIAL
STATEMENT NOTE 1).
Cash flow and net earnings for the three months ended September 30, 2002
increased from the comparable period in 2001 due to increased production, higher
product prices and lower current income tax in the North Sea. These factors were
partially offset by higher oil hedging losses, higher royalties and higher
production expense as well as increased administration and interest expenses.
Net earnings was also impacted by higher depletion, depreciation and
amortization costs and higher future income tax expense. Third quarter cash flow
increased from the second quarter due to increased production and higher oil and
liquids prices. Net earnings for the quarter decreased from the prior quarter
due to higher depletion, depreciation and amortization costs and the effects of
the fluctuating Canadian dollar, resulting in unrealized foreign exchange losses
on the Company's US dollar denominated debt. Year-to-date cash flow and net
earnings decreased from the comparable period in 2001 due to lower natural gas
prices, higher production expense and higher administration costs. Net earnings
was also impacted by higher depletion, depreciation and amortization costs, but
was partially offset by unrealized foreign exchange gains on the Company's US
dollar denominated debt.
CANADIAN NATURAL RESOURCES LIMITED 11
================================================================================
THREE MONTHS ENDED NINE MONTHS ENDED
---------------------------------------------- ------------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001 2002 2001
============== ============== ============= ============= ===============
DAILY PRODUCTION
OIL AND LIQUIDS (BBLS/D)
North America 185,990 158,196 162,890 165,608 169,261
North Sea 47,114 25,685 40,356 34,629 36,422
Offshore West Africa 8,947 5,505 3,819 6,585 3,445
--------------- ----------------- --------------- ---------------- ---------------
Total 242,051 189,386 207,065 206,822 209,128
--------------- ----------------- --------------- ---------------- ---------------
NATURAL GAS (MMCF/D)
North America 1,395 1,058 906 1,162 877
North Sea 29 20 18 25 10
Offshore West Africa 3 - - 1 -
--------------- ----------------- --------------- ---------------- ---------------
Total 1,427 1,078 924 1,188 887
--------------- ----------------- --------------- ---------------- ---------------
PRODUCT MIX
Light oil and NGLs 21.4% 19.0% 21.5% 20.2% 20.9%
Pelican Lake oil 6.7% 8.3% 9.5% 7.4% 10.1%
Primary heavy oil 13.9% 13.9% 16.1% 13.7% 16.2%
Thermal heavy oil 8.4% 10.1% 10.2% 9.8% 11.4%
Natural gas 49.6% 48.7% 42.7% 48.9% 41.4%
=========================================================================================================================
North America oil and liquids production increased for the three months ended
September 30, 2002 over the comparable periods due to the acquisition of Rio
Alto and the acquisition of additional producing heavy oil properties in eastern
Alberta. Oil and liquids production also increased due to an active drilling
program in the second and third quarter 2002 focusing on heavy oil and Pelican
Lake properties. North Sea oil production increased from the comparable
three-month periods due to the acquisition of additional interests in the
Ninian, Murchison, Lyell and Columba fields in exchange for US $120.0 million
and the Company's interest in the Harding field (see discussion of capital
expenditures). Oil production from the Kyle field increased from the prior
quarter as a result of rectifying a pipeline blockage in the export natural gas
pipeline downstream of the Curlew floating production, storage and offtake
vessel in early July 2002. Oil production from the Kyle field was restricted for
most of the second quarter 2002 because of the blockage. The increase in North
Sea oil production was partially offset by planned maintenance shutdowns of the
Ninian North and Ninian Central platforms during August. Offshore West Africa
oil production increased from the comparable periods as a result of production
commencing from the Company's operated Espoir field, located offshore Cote
d'Ivoire, in February 2002. The third producer well commenced production in
early July. Production from this field is anticipated to increase over the next
several months as additional wells are drilled during the first phase of
development.
Natural gas production increased overall and in the North America segment from
comparable periods due to the acquisition of Rio Alto. North American natural
gas production also increased year-over-year as a result of the focus of the
2001 capital expenditure program on natural gas development, which resulted in
the development of the Ladyfern field. Production from Ladyfern averaged 182
mmcf/d for the first nine months of 2002. Natural gas production from the
Ladyfern field decreased from an average of 201 mmcf/d in the second quarter of
2002 to 178 mmcf/d during the third quarter. Current production from Ladyfern is
approximately 135 mmcf/d and the Company expects a 70% decline rate through
2003. Production of natural gas in the North Sea increased from the previous
quarter due to the rectification of the pipeline blockage impacting production
from the Kyle field.
CANADIAN NATURAL RESOURCES LIMITED 12
================================================================================
THREE MONTHS ENDED NINE MONTHS ENDED
---------------------------------------------- ------------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001 2002 2001
============== ============== ============= ============= ===============
PRODUCT PRICES
OIL AND LIQUIDS ($/BBL)
North America $ 31.07 $ 26.27 $ 26.02 $ 26.85 $ 21.77
North Sea $ 41.68 $ 39.36 $ 37.28 $ 38.77 $ 40.41
Offshore West Africa $ 42.78 $ 33.92 $ 34.66 $ 38.95 $ 38.03
Company average $ 33.57 $ 28.27 $ 28.37 $ 29.23 $ 25.28
NATURAL GAS ($/MCF)
North America $ 3.15 $ 3.72 $ 3.13 $ 3.29 $ 6.05
North Sea $ 1.98 $ 1.80 $ 2.51 $ 2.56 $ 2.21
Offshore West Africa $ 4.97 $ - $ - $ 4.97 $ -
Company average $ 3.13 $ 3.68 $ 3.12 $ 3.28 $ 6.01
PERCENTAGE OF REVENUE
Oil and liquids 64.6% 57.5% 67.1% 60.9% 49.8%
Natural gas 35.4% 42.5% 32.9% 39.1% 50.2%
====================================================================================================================================
The North American realized oil and liquids price for the nine months ended
September 30, 2002 increased from the comparable period in 2001 primarily as a
result of narrower heavy oil differentials. Heavy oil differentials averaged US
$5.91 per bbl in the first nine months of 2002 compared to US $10.93 per bbl for
the first nine months of 2001. The narrowing of the heavy oil differentials is
due to supply and demand fundamentals as well as the recommencement of a heavy
oil refinery in the US Midwest in the second quarter of 2002. The third quarter
2002 North American realized oil and liquids price increased from the comparable
periods due to higher worldwide oil prices. West Texas Intermediate ("WTI")
averaged US $28.25 per bbl for the quarter ended September 30, 2002 compared to
US $26.26 per bbl and US $26.57 per bbl for the quarters ended June 30, 2002 and
September 30, 2001, respectively. North Sea and offshore West Africa oil prices
increased from the comparable three-month periods due to the strengthening of
oil prices.
Natural gas prices in North America for the third quarter ended September 30,
2002 decreased from the previous quarter due to lower AECO prices. Natural gas
prices were impacted in the quarter by restrictions on export capacity out of
Alberta due to temporary anomalies resulting from maintenance downtime on common
carrier pipeline systems. AECO prices decreased 27% in the third quarter 2002 to
average $3.25 per mmbtu compared to $4.43 per mmbtu in the second quarter 2002.
The Company expects natural gas prices to increase due to the impact that
reduced drilling levels will have on supply and as North American storage levels
and weather patterns return to normal. Natural gas prices for the nine months
ended September 30, 2002 decreased from the comparable period due to lower
demand in the North American market and warmer than average winter temperatures,
which resulted in higher natural gas storage levels. AECO prices averaged $3.68
per mmbtu for the first nine months of 2002 compared to $7.27 per mmbtu for the
first nine months of 2001.
The Company enters into various financial instruments to protect the downside
prices received on the sale of a portion of its oil and natural gas production.
The price realized from the sale of oil was reduced by $1.62 per bbl in the
quarter ended September 30, 2002 ($1.85 per bbl and $0.22 per bbl reductions,
respectively, in the quarters ended June 30, 2002 and September 30, 2001). The
price realized from the sale of natural gas was increased by $0.05 per mcf in
the third quarter of 2002 ($0.09 per mcf and $0.10 per mcf reductions,
respectively, in the quarters ended June 30, 2002 and September 30, 2001).
CANADIAN NATURAL RESOURCES LIMITED 13
================================================================================
THREE MONTHS ENDED NINE MONTHS ENDED
---------------------------------------------- ------------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001 2002 2001
============== ============== ============= ============= ===============
ROYALTIES
OIL AND LIQUIDS ($/BBL)
North America $ 3.92 $ 3.29 $ 2.61 $ 3.28 $ 2.47
North Sea $ 2.56 $ 1.76 $ 1.97 $ 2.06 $ 2.29
Offshore West Africa $ 1.34 $ 1.11 $ 2.03 $ 1.36 $ 1.02
Company average $ 3.56 $ 3.02 $ 2.47 $ 3.01 $ 2.41
NATURAL GAS ($/MCF)
North America $ 0.69 $ 0.79 $ 0.68 $ 0.68 $ 1.50
Offshore West Africa $ 0.15 $ - $ - $ 0.15 $ -
Company average $ 0.67 $ 0.77 $ 0.67 $ 0.67 $ 1.49
COMPANY AVERAGE ($/BOE) $ 3.80 $ 3.79 $ 3.14 $ 3.49 $ 5.10
PERCENTAGE OF REVENUE (EXCLUDING FINANCIAL
INSTRUMENTS)
Oil and liquids 10.1% 10.0% 8.7% 9.8% 9.5%
Natural gas 21.8% 20.4% 20.8% 20.4% 23.2%
====================================================================================================================================
Oil and liquids royalties in North America increased over the comparable periods
due to higher product prices. North America oil and liquids royalties also
increased due to some heavy oil projects reaching payout and no longer
qualifying for reduced royalty rates. North Sea oil royalties increased for the
three months ended September 30, 2002 from the prior quarter and comparable
period in 2001 due to the acquisition of additional interests in the royalty
paying Ninian, Murchison and Columba fields. North Sea oil royalties for the
nine months ended September 30, 2002 decreased from the comparable period in
2001 due to lower world oil prices. Offshore West Africa oil royalties decreased
in the third quarter of 2002 from the comparable period in 2001 as a result of
production ceasing from the higher royalty rate Kiame field in April 2002. Oil
royalties for offshore West Africa increased in the third quarter of 2002
compared to the second quarter 2002 due to higher world oil prices. Offshore
West Africa oil royalties for the nine months ended September 30, 2002 increased
from the comparable periods in 2001 due to the Kiame field not being subject to
royalties for a portion of 2001. The Kiame field was the only field on
production in 2001 in this segment.
North American natural gas royalties changed from the comparable periods as a
result of fluctuations in the sales price of natural gas. Natural gas royalties
as a percentage of revenue increased from the comparable three-month periods due
to Rio Alto properties having a larger proportion of their production subject to
crown royalties, which have a higher royalty rate compared to freehold
royalties.
CANADIAN NATURAL RESOURCES LIMITED 14
================================================================================
THREE MONTHS ENDED NINE MONTHS ENDED
---------------------------------------------- ---------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001(1) 2002 2001(1)
============== ============== ============= ============= ============
PRODUCTION EXPENSE
OIL AND LIQUIDS ($/BBL)
North America $ 6.10 $ 6.52 $ 6.82 $ 6.50 $ 7.20
North Sea $ 18.30 $ 15.72 $ 8.09 $ 15.25 $ 8.50
Offshore West Africa $ 11.23 $ 12.76 $ 19.05 $ 13.60 $ 22.61
Company average $ 8.67 $ 7.95 $ 7.29 $ 8.19 $ 7.68
NATURAL GAS ($/MCF)
North America $ 0.52 $ 0.55 $ 0.50 $ 0.54 $ 0.50
North Sea $ 1.78 $ 1.90 $ 0.74 $ 1.65 $ 0.69
Offshore West Africa $ 1.77 $ - $ - $ 1.77 $ -
Company average $ 0.55 $ 0.57 $ 0.50 $ 0.57 $ 0.50
COMPANY AVERAGE ($/BOE) $ 6.01 $ 5.76 $ 5.47 $ 5.85 $ 5.75
=================================================================================================================================
(1) RESTATED FOR CHANGE IN ACCOUNTING POLICY (SEE CONSOLIDATED FINANCIAL
STATEMENT NOTE 1).
North American oil and liquids production expense decreased from the comparable
periods due to lower costs of natural gas, which is used to produce the steam to
heat thermal heavy oil formations. Oil and liquids production expense also
decreased in North America from the prior quarter due to the allocation of fixed
costs over greater production volumes. North Sea oil production expense
increased over the comparable periods due to costs associated with planned
maintenance shutdowns of the Ninian North and Ninian Central platforms during
August. These maintenance shutdowns reduced production volumes and increased
production expenses during the quarter. Offshore West Africa oil production
expense decreased from the comparable periods due to increased production from
the Espoir field and production ceasing from the higher production expense Kiame
field.
Natural gas production expense in North America increased over the comparable
periods in 2001 due to an increase in the toll rates and the percentage of
natural gas produced through the gathering and processing system in British
Columbia. Natural gas production expense decreased in the third quarter of 2002
from the second quarter of 2002 due to the acquisition of Rio Alto, which has
lower natural gas production expenses, and as a result of the expiry of the
Ladyfern McMahon service fee at the end of June 2002.
THREE MONTHS ENDED NINE MONTHS ENDED
------------------------------------------------ -----------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001 2002 2001
============== =============== ============== ============= ==============
DEPLETION, DEPRECIATION AND AMORTIZATION(1)
Expense ($ MILLIONS) $ 401.1 $ 289.3 $ 235.3 $ 922.4 $ 658.8
$/boe $ 9.08 $ 8.61 $ 7.09 $ 8.35 $ 6.76
====================================================================================================================================
(1) DD&A DOES NOT INCLUDE MIDSTREAM OPERATIONS.
Depletion, depreciation and amortization ("DD&A") increased for the three and
nine months ended September 30, 2002 over the comparable periods due to the
allocation of fair values to Rio Alto capital assets and future abandonment
costs associated with the acquisition of additional interests in the North Sea.
DD&A also increased for the nine months ended September 30, 2002 over the
comparable 2001 period as a result of the Company's
CANADIAN NATURAL RESOURCES LIMITED 15
================================================================================
decision to exit from its interests in Block 19 in Angola and in the Aje field
in Nigeria. The Company wrote off all related capitalized costs in those
countries, totaling $51 million, in the second quarter of 2002.
THREE MONTHS ENDED NINE MONTHS ENDED
------------------------------------------------ -----------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001 2002 2001
============== =============== ============== ============= ==============
ADMINISTRATION EXPENSE
Net expense ($ MILLIONS) $ 17.8 $ 12.3 $ 9.4 $ 43.6 $ 25.6
$/boe $ 0.40 $ 0.37 $ 0.28 $ 0.39 $ 0.26
====================================================================================================================================
The Company's administration expense increased from the comparable periods
mainly due to higher staffing levels associated with the growth in production
and the expanding asset base.
THREE MONTHS ENDED NINE MONTHS ENDED
------------------------------------------------ -----------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001 2002 2001
============== =============== ============== ============= ==============
INTEREST EXPENSE
Interest expense ($ MILLIONS) $ 48.9 $ 28.6 $ 32.2 $ 106.2 $ 106.4
$/boe $ 1.11 $ 0.85 $ 0.97 $ 0.96 $ 1.09
Average effective interest rate 4.5% 4.4% 5.4% 4.3% 5.7%
====================================================================================================================================
Interest expense for the three months ended September 30, 2002 increased from
the comparable periods due to higher average outstanding debt levels associated
with the acquisition of Rio Alto. Interest expense for the nine months ended
September 30, 2002 remained consistent with the previous year as a result of the
impact of lower effective interest rates offset by higher debt levels.
THREE MONTHS ENDED NINE MONTHS ENDED
------------------------------------------------ -----------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001 2002 2001
============== =============== ============== ============= ==============
MIDSTREAM ($ MILLIONS)
Revenue $ 13.3 $ 13.5 $ 5.0 $ 37.2 $ 22.5
Operating costs 3.1 3.4 1.3 9.6 8.3
-------------- --------------- -------------- -------------- --------------
Cash flow 10.2 10.1 3.7 27.6 14.2
Depreciation 1.9 1.9 0.9 5.7 2.6
-------------- --------------- -------------- -------------- --------------
Segment earnings before taxes $ 8.3 $ 8.2 $ 2.8 $ 21.9 $ 11.6
====================================================================================================================================
The Company's midstream assets consist of the 100% owned and operated ECHO
pipeline, the 15% interest in the Cold Lake pipeline system, the 62% interest in
the operated Pelican Lake pipeline and the 50% interest in the 80 megawatt
co-generation system located in the Primrose area. The midstream pipeline assets
allow the Company to transport its own production volumes as well as earn third
party revenue from excess capacity. Through these assets, the Company transports
approximately 85% of its heavy oil to the international mainline liquid
pipelines. These midstream assets enhance the Company's ability to control the
full range of costs associated with the development and marketing of its heavy
oil.
Revenue from midstream assets increased from the comparable periods in 2001 due
to the expansion of the ECHO pipeline and the commencement of operations from
the Cold Lake pipeline system in late December 2001. The
CANADIAN NATURAL RESOURCES LIMITED 16
================================================================================
increased pipeline revenues are partially offset by the decline in electricity
revenue. Electricity revenues declined over the same period in 2001 due to lower
prices received.
THREE MONTHS ENDED NINE MONTHS ENDED
------------------------------------------------ -----------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001 2002 2001
============== =============== ============== ============= ==============
TAXES
TAXES OTHER THAN INCOME TAX ($ MILLIONS)
Current $ 13.0 $ 11.8 $ 21.1 $ 38.3 $ 59.2
Deferred 0.6 1.6 (1.3) 3.6 (1.2)
-------------- --------------- -------------- -------------- --------------
Total $ 13.6 $ 13.4 $ 19.8 $ 41.9 $ 58.0
-------------- --------------- -------------- -------------- --------------
CURRENT INCOME TAX ($ MILLIONS)
North Sea $ 3.0 $ 2.3 $ 16.5 $ 16.3 $ 51.5
Offshore West Africa 3.7 1.1 - 5.3 -
Large Corporations Tax 5.6 4.5 3.2 14.4 10.4
-------------- --------------- -------------- -------------- --------------
Total $ 12.3 $ 7.9 $ 19.7 $ 36.0 $ 61.9
-------------- --------------- -------------- -------------- --------------
FUTURE INCOME TAX ($ MILLIONS) $ 76.4 $ 107.9 $ 61.0 $ 222.6 $ 280.7
EFFECTIVE INCOME TAX RATE 41.7% 45.1% 40.4% 41.5% 31.9%
====================================================================================================================================
Taxes other than income tax consist of current and deferred petroleum revenue
tax, other international taxes and provincial resource surcharges. The
fluctuations in taxes other than income tax from comparable periods is due to
the fluctuations in world oil prices, primarily in the North Sea.
North Sea current income tax expense for the nine months ended September 30,
2002 decreased from the comparable period in 2001 due to decreased earnings
before taxes. Current income tax in the North Sea also decreased due to the UK
Government increasing the first year capital allowance rate for plant and
machinery expenditures to 100% from the previous rate of 25% during the second
quarter of 2002. Current income tax expense in the third quarter 2002 increased
from the prior quarter due to higher taxable income. Offshore West Africa
current income tax increased from the comparable periods due to increased
production and higher worldwide oil prices. Large Corporations Tax increased
from the comparable periods due to the higher taxable capital base as a result
of increased debt levels and shareholders' equity.
Future income tax expense decreased from the prior quarter as a result of the
inclusion in the second quarter 2002 of the effects of increased tax rates on
profits from North Sea oil and natural gas production. A 10% supplementary
charge, in addition to the current corporate tax rate of 30%, took effect April
17, 2002 and excludes any deduction for financing costs. The implementation of
the supplementary charge resulted in a one-time increase in the UK future income
tax liability of $34 million in the second quarter of 2002. The increase in
future income tax expense in the second quarter of 2002 was partially offset by
a $21 million reduction in the future income tax liability as a result of a
decrease in a Canadian province's corporate income tax rate. The Company's
future income taxes payable and property, plant and equipment have been
increased by $39 million to provide for the exchange of non-tax base assets in
the North Sea for the first nine months of 2002.
CANADIAN NATURAL RESOURCES LIMITED 17
================================================================================
THREE MONTHS ENDED NINE MONTHS ENDED
---------------------------------------------- ---------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001(1) 2002 2001(1)
============== ============== ============= ============= ==========
CAPITAL EXPENDITURES ($ MILLIONS)
ACQUISITION OF RIO ALTO $ 2,308.7 $ - $ - $ 2,308.7 $ -
--------------- -------------- ------------- -------------- ----------
EXPENDITURES ON PROPERTY, PLANT AND
EQUIPMENT
Net property acquisitions $ 333.3 $ 33.1 $ 24.6 $ 401.7 $ 270.8
Land acquisition and retention 48.4 19.2 35.8 95.4 85.0
Seismic evaluations 4.9 14.6 8.6 44.3 65.8
Well drilling, completion and equipping 144.1 135.9 148.6 486.8 528.8
Pipeline and production facilities 56.5 66.6 109.7 247.4 326.1
--------------- -------------- ------------- -------------- ----------
TOTAL NET RESERVE REPLACEMENT EXPENDITURES 587.2 269.4 327.3 1,275.6 1,276.5
Project Horizon 9.9 16.6 1.9 48.8 15.8
Midstream - 5.2 16.1 14.8 51.8
Abandonments 19.8 11.9 5.0 38.5 6.0
Head office 3.9 1.7 1.8 6.7 4.7
--------------- -------------- ------------- -------------- ----------
TOTAL NET CAPITAL EXPENDITURES $ 620.8 $ 304.8 $ 352.1 $ 1,384.4 $ 1,354.8
=============== ============== ============= ============== ==========
BY SEGMENT (EXCLUDING ACQUISITION OF RIO ALTO)
North America $ 331.8 $ 232.5 $ 280.9 $ 984.4 $ 1,078.7
North Sea 230.2 13.2 32.2 212.0 63.5
Offshore West Africa 58.8 53.9 22.9 173.2 160.8
Midstream - 5.2 16.1 14.8 51.8
--------------- -------------- ------------- -------------- -------------
Total $ 620.8 $ 304.8 $ 352.1 $ 1,384.4 $ 1,354.8
====================================================================================================================================
(1) CERTAIN FIGURES PROVIDED FOR PRIOR PERIODS HAVE BEEN RECLASSIFIED TO
CONFORM TO THE PRESENTATION ADOPTED IN 2002.
North America capital expenditures during the third quarter 2002 include the
acquisition of Rio Alto and additional producing and non-producing heavy oil
properties, primarily in the Lindbergh area of eastern Alberta. The Rio Alto
acquisition provides the Company with a new core area for natural gas
exploration and exploitation activities in western Canada. Capital expenditures
for the nine months ended September 30, 2002, include the drilling of 150 net
natural gas wells and 248 net oil wells.
North Sea capital expenditures for the three months ended September 30, 2002,
include the consolidation of interests in the Ninian, Murchison, Lyell and
Columba fields. The Company also acquired an interest in the Strathspey field,
12 licences covering 20 exploration blocks and part blocks, and additional
equity interests in the Brent and Ninian pipelines and the Sullom Voe Terminal.
The acquisition consideration includes a cash payment of US $120.0 million and
the Company's 5% interest in the Harding field. Capital expenditures for the
nine months ended September 30, 2002, also include the consolidation of the
Company's ownership interests in the Ninian, Banff and Kyle fields in exchange
for its interests in the Pierce and Claymore fields and cash. North Sea capital
expenditures also include the drilling of wells at the Kyle and Columba E
fields, as well as the ongoing infill drilling program in the Ninian field.
CANADIAN NATURAL RESOURCES LIMITED 18
================================================================================
Offshore West Africa capital expenditures include the continued development of
the Espoir field. During the third quarter 2002, a third producer well was
completed in mid-July. The Company plans to drill two additional wells as part
of the first development phase in the fourth quarter of 2002. In the third
quarter 2002, the Company also entered into a production sharing agreement
("PSA") for Block 16, offshore Angola. The Company will operate the block and
retain a 50% working interest. The PSA was effective September 1, 2002 for an
initial four-year exploration phase.
SEP 30 JUN 30 DEC 31 SEP 30
2002 2002 2001(1) 2001(1)
----------------- ----------------- --------------- -------------
LIQUIDITY AND CAPITAL RESOURCES ($ MILLIONS,
EXCEPT RATIOS)
Working capital deficit $ 364.4 $ 128.9 $ 5.6 $ 154.1
Long-term debt 4,169.6 2,404.4 2,669.2 2,311.8
----------------- ----------------- --------------- -------------
Total $ 4,534.0 $ 2,533.3 $ 2,674.8 $ 2,465.9
================= ================= =============== =============
SHAREHOLDERS' EQUITY
Preferred securities $ 126.9 $ 121.5 $ 127.4 $ 126.3
Share capital 2,289.0 1,756.2 1,698.3 1,693.9
Retained earnings 2,222.7 2,122.0 1,908.5 1,867.6
Foreign currency translation adjustment 22.7 30.3 72.8 -
----------------- ----------------- --------------- -------------
Total $ 4,661.3 $ 4,030.0 $ 3,807.0 $ 3,687.8
================= ================= =============== =============
Debt to cash flow(2) 2.3X 1.5x 1.4x 1.1x
Debt to book capitalization 47.2% 37.4% 41.2% 38.5%
Debt to market capitalization 37.9% 27.1% 34.9% 32.4%
After tax return on average common shareholders'
equity(2) 10.6% 10.3% 18.7% 24.9%
After tax return on average capital
employed(2) 7.3% 7.2% 12.2% 15.5%
=================================================================================================================================
(1) RESTATED FOR CHANGE IN ACCOUNTING POLICY (SEE CONSOLIDATED FINANCIAL
STATEMENTS NOTE 2).
(2) BASED ON TRAILING 12-MONTH PERIOD AND DO NOT INCLUDE AMOUNTS RELATED TO
ACQUIRED ASSETS FOR THE PERIOD PRIOR TO JUNE 30, 2002.
The ratios above have been calculated with the outstanding preferred securities
of the Company classified as equity. If the preferred securities were classified
as long-term debt, debt to cash flow for the trailing 12-month period ended
September 30, 2002, would be 2.4x (June 30, 2002 - 1.6x, December 31, 2001 -
1.5x, September 30, 2001 - 1.1x). Debt to book capitalization would be 48.7% at
September 30, 2002 (June 30, 2002 - 39.3%, December 31, 2001 - 43.2%, September
30, 2001 - 40.6%) had the preferred securities been classified as long-term
debt, while debt to market capitalization would be 39.0%, 28.5%, 36.6% and
34.2%, respectively.
CANADIAN NATURAL RESOURCES LIMITED 19
================================================================================
SENSITIVITY ANALYSIS (1)
Annualized sensitivities to certain factors, which would influence the Company's
financial results, are estimated as follows:
CASH FLOW CASH FLOW
FROM FROM NET NET
OPERATIONS(2) OPERATIONS(2) EARNINGS(2) EARNINGS(2)
(PER SHARE) (PER SHARE)
($ MILLIONS) (BASIC) ($ MILLIONS) (BASIC)
============ ============ ============ ===========
PRICE CHANGES
Oil - WTI US $1.00/bbl(3)
Excluding financial derivatives $108 $0.81 $80 $0.60
Including financial derivatives $49-$52 $0.36-$0.39 $36-$39 $0.27-$0.29
Natural gas - AECO Cdn $0.10/mcf(3)
Excluding financial derivatives $40 $0.30 $24 $0.18
Including financial derivatives $35 $0.26 $22 $0.16
VOLUME CHANGES
Oil - 10,000 bbls/d $60 $0.45 $14 $0.10
Natural gas - 10 mmcf/d $7 $0.05 $1 $0.01
FOREIGN CURRENCY RATE CHANGE
$0.01 change in Cdn $ in relation to
US $(3)
Excluding financial derivatives $58 $0.43 $36 $0.27
Including financial derivatives $50-$55 $0.38-$0.41 $31-$34 $0.23-$0.25
INTEREST RATE CHANGE - 1% $22 $0.17 $14 $0.10
=========================================================================================================================
(1) THE SENSITIVITIES ARE CALCULATED BASED ON 2002 THIRD QUARTER RESULTS.
(2) ATTRIBUTABLE TO COMMON SHAREHOLDERS.
(3) FOR DETAILS OF FINANCIAL INSTRUMENTS IN PLACE, SEE CONSOLIDATED
FINANCIAL STATEMENT NOTE 8.
CANADIAN NATURAL RESOURCES LIMITED 20
================================================================================
OTHER OPERATING HIGHLIGHTS
THREE MONTHS ENDED NINE MONTHS ENDED
--------------------------------------------- ----------------------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
2002 2002 2001(1) 2002 2001(1)
============= =============== ============= ============= =============
NETBACK ANALYSIS ($/BOE, EXCEPT DAILY PRODUCTION)
Daily production (BOE/D) 479,949 369,022 361,029 404,745 356,905
Sales price $ 26.26 $ 25.29 $ 24.25 $ 24.57 $ 29.76
Royalties 3.80 3.79 3.14 3.49 5.10
Production expense 6.01 5.76 5.47 5.85 5.75
------------- ------------- -------------- ------------- -------------
NETBACK 16.45 15.74 15.64 15.23 18.91
Midstream contribution (0.23) (0.30) (0.11) (0.25) (0.15)
Administration 0.40 0.37 0.28 0.39 0.26
Interest 1.11 0.85 0.97 0.96 1.09
Realized foreign exchange (gain) loss (0.04) 0.03 0.02 0.01 0.02
Taxes other than income tax (current) 0.29 0.35 0.64 0.35 0.61
Current income tax (North Sea) 0.07 0.07 0.49 0.15 0.53
Current income tax (Offshore West Africa) 0.08 0.03 - 0.05 -
Current income tax (Large Corporations Tax) 0.13 0.14 0.10 0.13 0.11
------------- ------------- -------------- ------------- -------------
CASH FLOW $ 14.64 $ 14.20 $ 13.25 $ 13.44 $ 16.44
==================================================================================================================================
(1) RESTATED FOR CHANGE IN ACCOUNTING POLICY (SEE CONSOLIDATED FINANCIAL
STATEMENT NOTES 1 AND 2).
NINE MONTHS ENDED SEPTEMBER 30, 2002
--------------------------------------------------------------------------
NORTH NORTH OFFSHORE TOTAL
AMERICA SEA WEST AFRICA
============== ================ ================ ================
SEGMENTED NETBACK
OIL AND LIQUIDS ($/BBL, EXCEPT DAILY PRODUCTION)
Daily production (BBLS/D) 165,608 34,629 6,585 206,822
Sales price $ 26.85 $ 38.77 $ 38.95 $ 29.23
Royalties 3.28 2.06 1.36 3.01
Production expense 6.50 15.25 13.60 8.19
-------------- ---------------- ---------------- ----------------
Netback(1) $ 17.07 $ 21.46 $ 23.99 $ 18.03
-------------- ---------------- ---------------- ----------------
NATURAL GAS ($/MCF, EXCEPT DAILY PRODUCTION)
Daily production (MMCF/D) 1,162 25 1 1,188
Sales price $ 3.29 $ 2.56 $ 4.97 $ 3.28
Royalties 0.68 - 0.15 0.67
Production expense 0.54 1.65 1.77 0.57
-------------- ---------------- ---------------- ----------------
Netback(1) $ 2.07 $ 0.91 $ 3.05 $ 2.04
-------------- ---------------- ---------------- ----------------
BARRELS OF OIL EQUIVALENT ($/BOE, EXCEPT DAILY
PRODUCTION)
Daily production (BOE/D) 359,161 38,846 6,738 404,745
Sales price $ 23.05 $ 36.27 $ 38.74 $ 24.57
Royalties 3.71 1.83 1.34 3.49
Production expense 4.76 14.67 13.54 5.85
-------------- ---------------- ---------------- ----------------
Netback(1) $ 14.58 $ 19.77 $ 23.86 $ 15.23
================================================================================================================================
(1) NETBACKS DO NOT INCLUDE MIDSTREAM OPERATIONS.
CANADIAN NATURAL RESOURCES LIMITED 21
================================================================================
SEPTEMBER 30 DECEMBER 31
2002 2001
=============== ==============
CONSOLIDATED BALANCE SHEETS (MILLIONS OF CANADIAN DOLLARS) (UNAUDITED)
ASSETS
CURRENT ASSETS
Cash $ 15.2 $ 15.0
Accounts receivable and other 659.6 509.0
--------------- -------------
674.8 524.0
PROPERTY, PLANT AND EQUIPMENT (NET) 12,481.5 8,442.9
DEFERRED CHARGES (NOTE 4) 58.3 -
--------------- -------------
$ 13,214.6 $ 8,966.9
=================================================================================================
LIABILITIES
CURRENT LIABILITIES
Accounts payable $ 354.1 $ 249.5
Accrued liabilities 659.2 264.2
Current portion of long-term debt (NOTE 5) 25.9 15.9
--------------- -------------
1,039.2 529.6
LONG-TERM DEBT (NOTE 5) 4,169.6 2,669.2
FUTURE SITE RESTORATION 365.5 193.8
FUTURE INCOME TAX 2,979.0 1,767.3
--------------- -------------
8,553.3 5,159.9
--------------- -------------
SHAREHOLDERS' EQUITY
PREFERRED SECURITIES (NOTE 2) 126.9 127.4
SHARE CAPITAL (NOTE 6) 2,289.0 1,698.3
RETAINED EARNINGS 2,222.7 1,908.5
FOREIGN CURRENCY TRANSLATION ADJUSTMENT 22.7 72.8
--------------- -------------
4,661.3 3,807.0
--------------- -------------
$ 13,214.6 $ 8,966.9
=================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 22
================================================================================
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
----------------------------------- ------------------------------------
2002 2001 2002 2001
=============== =============== ================ ===============
CONSOLIDATED STATEMENTS OF EARNINGS (MILLIONS
OF CANADIAN DOLLARS, EXCEPT PER SHARE
AMOUNTS) (UNAUDITED)
REVENUE (NOTE 10) $ 1,172.6 $ 810.5 $ 2,752.9 $ 2,922.4
Less: royalties (167.7) (104.2) (386.0) (497.1)
--------------- --------------- ---------------- ---------------
1,004.9 706.3 2,366.9 2,425.3
--------------- --------------- ---------------- ---------------
EXPENSES
Production 268.4 183.1 656.2 568.5
Depletion, depreciation and amortization 403.0 236.2 928.1 661.4
Administration 17.8 9.4 43.6 25.6
Interest 48.9 32.2 106.2 106.4
Foreign exchange loss (gain) (NOTE 2) 40.2 57.3 (33.2) 62.4
--------------- --------------- ---------------- ---------------
778.3 518.2 1,700.9 1,424.3
--------------- --------------- ---------------- ---------------
EARNINGS BEFORE TAXES 226.6 188.1 666.0 1,001.0
Taxes other than income tax 13.6 19.8 41.9 58.0
Current income tax 12.3 19.7 36.0 61.9
Future income tax 76.4 61.0 222.6 280.7
--------------- --------------- ---------------- ---------------
NET EARNINGS 124.3 87.6 365.5 600.4
Dividend on preferred securities (NET OF TAX) (1.5) (1.4) (4.5) (4.3)
Revaluation of preferred securities (NOTE 2) (5.4) (4.9) 0.5 (6.4)
--------------- --------------- ---------------- ---------------
NET EARNINGS ATTRIBUTABLE TO COMMON
SHAREHOLDERS $ 117.4 $ 81.3 $ 361.5 $ 589.7
=============== =============== ================ ===============
NET EARNINGS PER COMMON SHARE ATTRIBUTABLE TO COMMON SHAREHOLDERS (NOTE 7)
Basic $ 0.88 $ 0.67 $ 2.87 $ 4.86
Diluted $ 0.86 $ 0.66 $ 2.78 $ 4.72
==================================================================================================================================
NINE MONTHS ENDED SEPTEMBER 30
------------------------------
2002 2001
============= =============
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (MILLIONS OF CANADIAN DOLLARS) (UNAUDITED)
BALANCE - BEGINNING OF PERIOD AS PREVIOUSLY REPORTED $ 1,979.5 $ 1,406.0
Change in accounting policy - foreign exchange (NOTE 2) (71.0) (15.4)
------------- -------------
BALANCE - BEGINNING OF PERIOD AS RESTATED 1,908.5 1,390.6
Net earnings 365.5 600.4
Dividend on common shares (NOTE 6) (47.3) (36.5)
Dividend on preferred securities (NET OF TAX) (4.5) (4.3)
Revaluation of preferred securities (NOTE 2) 0.5 (6.4)
Purchase of common shares (NOTE 6) - (76.2)
------------- -------------
BALANCE - END OF PERIOD $ 2,222.7 $ 1,867.6
============================================================================================
CANADIAN NATURAL RESOURCES LIMITED 23
================================================================================
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
------------------------------------ -------------------------------------
2002 2001 2002 2001
================ ================ ================ ================
CONSOLIDATED STATEMENTS OF CASH FLOWS (MILLIONS OF CANADIAN DOLLARS) (UNAUDITED)
OPERATING ACTIVITIES
Net earnings $ 124.3 $ 87.6 $ 365.5 $ 600.4
Non-cash items
Depletion, depreciation and
amortization 403.0 236.2 928.1 661.4
Deferred petroleum revenue tax 0.6 (1.3) 3.6 (1.2)
Future income tax 76.4 61.0 222.6 280.7
Unrealized foreign exchange loss (gain) 42.1 56.5 (34.6) 60.7
---------------- ---------------- ----------------- ----------------
Cash flow provided from operations 646.4 440.0 1,485.2 1,602.0
Deferred charges (58.3) - (58.3) -
Net change in non-cash working capital (34.1) 16.7 (46.3) (9.6)
---------------- ---------------- ----------------- ----------------
554.0 456.7 1,380.6 1,592.4
---------------- ---------------- ----------------- ----------------
FINANCING ACTIVITIES
Repay bank credit facilities (326.7) (709.8) (1,149.2) (792.9)
Issue of US debt securities 1,107.8 615.2 1,749.3 615.2
Repay senior unsecured notes (15.9) - (15.9) -
Repay lease obligations (1.9) - (1.9) -
Repay limited recourse loan - - - (11.8)
Issue of capital stock 10.4 16.0 69.3 38.3
Purchase of common shares - (18.7) - (113.3)
Dividend on common shares (15.4) (12.1) (42.8) (24.3)
Dividend on preferred securities (2.6) (2.6) (7.8) (7.7)
Net change in non-cash working capital (17.4) 8.3 (17.6) 7.5
---------------- ---------------- ----------------- ----------------
738.3 (103.7) 583.4 (289.0)
---------------- ---------------- ----------------- ----------------
INVESTING ACTIVITIES
Acquisition of Rio Alto, net of cash
acquired (NOTE 3) (843.2) - (843.2) -
Expenditures on property, plant and
equipment (635.7) (354.0) (1,457.4) (1,369.2)
Net proceeds on sale of property, plant and
equipment 14.9 1.9 73.0 14.4
---------------- ---------------- ----------------- ----------------
Net expenditures on property, plant and
equipment (1,464.0) (352.1) (2,227.6) (1,354.8)
Investment in Rio Alto International Inc. (15.7) - (15.7) -
Net change in non-cash working capital 201.4 2.1 279.5 58.4
---------------- ---------------- ----------------- ----------------
(1,278.3) (350.0) (1,963.8) (1,296.4)
---------------- ---------------- ----------------- ----------------
INCREASE IN CASH 14.0 3.0 0.2 7.0
CASH - BEGINNING OF PERIOD 1.2 32.0 15.0 28.0
---------------- ---------------- ----------------- ----------------
CASH - END OF PERIOD $ 15.2 $ 35.0 $ 15.2 $ 35.0
===================================================================================================================================
For supplementary information, see note 9.
CANADIAN NATURAL RESOURCES LIMITED 24
================================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (TABULAR AMOUNTS IN MILLIONS OF
CANADIAN DOLLARS)
1. ACCOUNTING POLICIES
The 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 and methods of
computation as the audited consolidated financial statements of the Company as
at December 31, 2001, except as described below and in note 2. The interim
consolidated financial statements contain disclosures that are supplemental to
the Company's annual consolidated financial statements. Certain disclosures that
are normally required to be included in the notes to the annual consolidated
financial statements have been condensed. These financial statements should be
read in conjunction with the Company's audited consolidated financial statements
and notes thereto for the year ended December 31, 2001.
HEDGE OF NET INVESTMENT IN SELF-SUSTAINING FOREIGN OPERATIONS
Effective July 1, 2002, the Company designated a portion of its US dollar
denominated debt as a hedge against its net investment in US dollar based
self-sustaining foreign operations. Accordingly, translation gains and losses on
this portion of the US dollar denominated debt are included in the foreign
currency translation adjustment in shareholders' equity in the consolidated
balance sheets. The effect of this hedge was to reduce foreign exchange losses
and decrease the foreign currency translation adjustment by $41.7 million for
the three months ended September 30, 2002.
MIDSTREAM OPERATIONS
As a result of the Company's increasing midstream activities, the Company
determined that effective January 1, 2002, the midstream activities within North
America constitute a distinct operating segment. The Company carries its
midstream assets at the lower of capitalized cost and net recoverable amount.
Midstream assets are depreciated over their estimated useful lives of 20 to 30
years.
COMPARATIVE FIGURES
Certain figures provided for prior periods have been reclassified to conform to
the presentation adopted in 2002.
2. CHANGE IN ACCOUNTING POLICY
FOREIGN CURRENCY TRANSLATION
Effective January 1, 2002, the Company retroactively adopted the Canadian
Institute of Chartered Accountants' new accounting standard with respect to
foreign currency translation. As a result of adopting this new standard, gains
or losses on the translation of long-term debt denominated in US dollars are no
longer deferred and amortized over the term of the debt, but are recognized in
net earnings immediately. This new standard has been adopted retroactively and
prior periods have been restated.
The new standard affects the Company's accounting for US denominated long-term
debt and preferred securities. Adoption of the new accounting policy had the
following effects on the Company's consolidated financial statements:
CANADIAN NATURAL RESOURCES LIMITED 25
================================================================================
THREE MONTHS ENDED NINE MONTHS ENDED YEAR ENDED
-------------------------------- ------------------------------- -------------
SEP 30 SEP 30 SEP 30 SEP 30 DEC 31
2002 2001 2002 2001 2001
============== =============== ============== ============== =============
Decrease deferred foreign exchange loss $ - $ (63.9) $ - $ (63.9) $ (61.9)
Increase (decrease) preferred securities $ 5.4 $ 8.1 $ (0.5) $ 8.1 $ 9.1
Increase (decrease) opening retained
earnings $ 12.1 $ (20.9) $ (71.0) $ (15.4) $ (15.4)
Foreign exchange loss (gain) $ 69.7 $ 46.1 $ (7.5) $ 50.1 $ 48.1
Revaluation of preferred securities $ 5.4 $ 4.9 $ (0.5) $ 6.4 $ 7.4
===================================================================================================================================
3. ACQUISITION OF RIO ALTO EXPLORATION LTD.
Effective July 1, 2002, the Company paid cash of $850.0 million and issued
10,008,000 common shares with an attributed value of $522.4 million to acquire
all of the issued and outstanding common shares of Rio Alto Exploration Ltd.
("Rio Alto") by way of a plan of arrangement (the "Plan of Arrangement"). Rio
Alto was engaged in the exploration for and production of oil and natural gas in
western Canada and South America. Under the Plan of Arrangement, Rio Alto's
South American properties were sold to a new company, Rio Alto Resources
International Inc. ("Rio Alto International"), and each shareholder of Rio Alto
received one share of Rio Alto International.
The acquisition of Rio Alto has strengthened the Company's exposure to natural
gas production in western Canada and will provide additional cash flow to fund
future capital projects.
The acquisition was accounted for based on the purchase method. Results from Rio
Alto are consolidated with the results of the Company effective July 1, 2002.
The preliminary estimate of the allocation of the purchase price to assets
acquired and liabilities assumed based on their fair values is set out in the
following table:
JULY 1
2002
===================
Purchase price:
Share consideration $ 522.4
Cash consideration 850.0
-------------------
Total consideration 1,372.4
Long-term debt assumed 936.3
-------------------
Total purchase price $ 2,308.7
===================
Net assets acquired:
Property, plant and equipment $ 3,383.9
Future income tax (975.1)
Future site restoration (35.9)
Cash 6.8
Non-cash working capital (71.0)
-------------------
Total net assets acquired $ 2,308.7
===============================================================================
The purchase price allocation is based on preliminary estimates of the fair
values of the assets acquired, the liabilities assumed and the costs to complete
the acquisition. The preliminary allocation is subject to change as actual
amounts are determined.
CANADIAN NATURAL RESOURCES LIMITED 26
================================================================================
4. DEFERRED CHARGES
The deferred charges relate to settlement payments made to terminate long-term
natural gas contracts and financial contracts. The deferred charges are
recognized against revenue over the original term of the contracts.
5. LONG-TERM DEBT
SEPTEMBER 30 DECEMBER 31
2002 2001
============ =============
Bank credit facilities
Canadian dollar debt $ 891.2 $ 1,003.4
US dollar debt (2002 - US $100 MILLION,
2001 - US $296 MILLION) 158.6 471.4
Medium-term notes 250.0 250.0
US debt securities (2002 - US $1,500 MILLION,
2001 - US $400 MILLION) 2,378.7 637.0
Senior unsecured notes (2002 - US $318 MILLION,
2001 - US $203 MILLION) 499.8 323.3
Obligations under capital leases 17.2 -
------------ -------------
4,195.5 2,685.1
Current portion of long-term debt (25.9) (15.9)
------------ -------------
$ 4,169.6 $ 2,669.2
=======================================================================================
BANK CREDIT FACILITIES
At September 30, 2002, the Company had unsecured bank credit facilities of
approximately $3,100 million comprised of a $100 million operating demand
facility, a revolving credit and term loan facility of $1,500 million, a
revolving credit and term loan facility of US $150 million, a $500 million
acquisition term credit facility repayable July 3, 2004 and a $725 million
revolving credit and term loan facility. The $725 million credit and term loan
facility was repaid and cancelled in October 2002.
At September 30, 2002, in conjunction with certain borrowings under its credit
agreements, the Company irrevocably placed $140 million in escrow to be used
solely for the repayment of those borrowings. This transaction was recognized as
an in-substance defeasance and the debt was considered to be extinguished as at
September 30, 2002.
Debt under the bank credit facilities totaling $100 million is subject to an
interest rate swap that fixes the rate at 5.08% plus a stamping fee (note 8).
In addition to the outstanding debt, letters of credit aggregating $31.3 million
have been issued.
CANADIAN NATURAL RESOURCES LIMITED 27
================================================================================
US DEBT SECURITIES
On January 23, 2002, the Company issued US $400 million of US debt securities,
maturing January 15, 2032, bearing interest at 7.20%. Proceeds from the notes
issued were used to repay bankers' acceptances under the Company's bank credit
facilities. Subsequently, the Company entered into interest rate swap contracts
that convert the fixed rate interest coupon into a floating interest rate for a
portion of the term (note 8).
On August 16, 2002, the Company filed a short form shelf prospectus allowing for
the issue of debt securities up to an aggregate principal amount of US $1
billion. On September 16, 2002, the Company issued US $350 million of US debt
securities maturing October 1, 2012, bearing interest at 5.45% and US $350
million of US debt securities maturing June 30, 2033, bearing interest at 6.45%.
Proceeds from the notes issued were used to repay bankers' acceptances under the
Company's bank credit facilities.
SENIOR UNSECURED NOTES
On July 1, 2002, the Company assumed US $125 million of senior notes maturing
December 19, 2005, bearing interest at 7.69%. Through a currency swap, the
interest and principal repayment amounts are fixed at 7.30% and $193.7 million,
respectively (note 8).
OBLIGATIONS UNDER CAPITAL LEASES
The obligations under capital leases bear interest at an average interest rate
of 6.90% and are secured by the related assets.
6. SHARE CAPITAL
ISSUED
SEPTEMBER 30, 2002
------------------------------
NUMBER OF SHARES AMOUNT
(THOUSANDS)
================ ==========
Common shares
Balance - January 1, 2002 121,201 $ 1,698.3
Issued to acquire Rio Alto 10,008 522.4
Exercise of stock options 2,083 67.0
Issue of flow-through shares (NET OF TAX) 60 1.3
---------------- -----------
Balance - September 30, 2002 133,352 $ 2,289.0
================================================================================
On July 1, 2002, the Company issued 10,008,000 common shares at an attributed
value of $522.4 million as part of the consideration to acquire Rio Alto (note
3).
In January 2002, the Company issued 60,000 flow-through common shares to a
director of the Company at a price of $39.00 per common share, for total
proceeds of $2.3 million. The value of the common shares was determined as the
closing market price on The Toronto Stock Exchange on the day prior to the
allotment of the common shares.
CANADIAN NATURAL RESOURCES LIMITED 28
================================================================================
NORMAL COURSE ISSUER BID
On January 17, 2001, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of The Toronto Stock Exchange and the New York
Stock Exchange to purchase up to 6,114,726 common shares or 5% of the common
shares outstanding of the Company on the date of announcement during the
12-month period beginning January 22, 2001 and ending January 21, 2002. As at
January 21, 2002, the Company had purchased 2,537,800 common shares for a total
cost of $113.3 million. The excess cost over book value of the shares purchased
was applied to contributed surplus and retained earnings.
In January 2002, the Company renewed its Normal Course Issuer Bid, allowing the
Company to purchase up to 6,060,180 common shares or 5% of the Company's common
shares outstanding on the date of announcement, during the 12-month period
beginning January 23, 2002 and ending January 22, 2003. As at September 30,
2002, no common shares had been purchased under the renewed Normal Course Issuer
Bid.
DIVIDEND POLICY
On January 17, 2001, the Company announced a dividend policy to pay regular
quarterly dividends of $0.10 per common share payable in January, April, July
and October of each year.
In February 2002, the Board of Directors increased the Company's regular
quarterly dividend to $0.125 per common share commencing with the April 1, 2002
payment.
STOCK OPTIONS
SEPTEMBER 30, 2002
---------------------------------
STOCK OPTIONS WEIGHTED AVERAGE
EXERCISE PRICE
(THOUSANDS)
============= ================
Outstanding - January 1, 2002 12,051 $ 34.77
Granted 3,174 41.88
Exercised (2,083) 32.15
Forfeited (353) 38.77
------------- ----------------
Outstanding - September 30, 2002 12,789 $ 36.85
============= ================
Exercisable - September 30, 2002 3,683 $ 32.60
================================================================================
CANADIAN NATURAL RESOURCES LIMITED 29
================================================================================
STOCK-BASED COMPENSATION COSTS
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
----------------------- -----------------------
2002 2001 2002 2001
=========== ========== ========== ==========
Stock-based compensation costs $ 6.6 $ 4.9 $ 18.1 $ 13.7
Net earnings attributable to common
shareholders
As reported $ 117.4 $ 81.3 $ 61.5 $ 589.7
Pro forma $ 110.8 $ 76.4 $ 43.4 $ 576.0
Net earnings per common share
attributable to common shareholders
Basic
As reported $ 0.88 $ 0.67 $ 2.87 $ 4.86
Pro forma $ 0.83 $ 0.63 $ 2.73 $ 4.75
Diluted
As reported $ 0.86 $ 0.66 $ 2.78 $ 4.72
Pro forma $ 0.81 $ 0.62 $ 2.64 $ 4.62
==============================================================================================
The pro forma amounts shown above do not include the compensation costs
associated with stock options granted prior to January 1, 2000.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
----------------------- -----------------------
2002 2001 2002 2001
=========== ========== ========== ==========
Fair value of options granted (PER COMMON
SHARE)
Directors, officers and executives $ - $ - $ 14.70 $ 16.52
Other employees $ 13.17 $ 13.72 $ 12.36 $ 13.69
Risk-free interest rate 3.3% 5.3% 3.7% 5.2%
Expected life (YEARS)
Directors, officers and executives - - 5.5 5.5
Other employees 3.6 3.6 3.6 3.6
Expected volatility 35% 34% 37% 39%
Expected dividend yield 1.1% 0.9% 1.2% 1.0%
==============================================================================================
CANADIAN NATURAL RESOURCES LIMITED 30
================================================================================
7. NET EARNINGS AND CASH FLOW FROM OPERATIONS PER COMMON SHARE
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
----------------------- -----------------------
2002 2001 2002 2001
=========== ========== ========== ==========
Weighted average common shares
outstanding (THOUSANDS)
Basic 133,201 120,815 125,950 121,349
Effect of dilutive stock options 3,507 2,638 3,095 2,979
Assumed settlement of preferred
securities with common shares(1) - - 2,609 2,759
----------- ---------- --------- ----------
Diluted 136,708 123,453 131,654 127,087
=========== ========== ========= ==========
Net earnings attributable to common
shareholders $ 117.4 $ 81.3 $ 361.5 $ 589.7
Dividend on preferred securities(1) - - 4.5 4.3
Revaluation of preferred securities(1) - - (0.5) 6.4
----------- ---------- --------- ----------
Diluted net earnings attributable to common
shareholders $ 117.4 $ 81.3 $ 365.5 $ 600.4
=========== ========== ========= ==========
Net earnings per common share
attributable to common shareholders
Basic $ 0.88 $ 0.67 $ 2.87 $ 4.86
Diluted $ 0.86 $ 0.66 $ 2.78 $ 4.72
Cash flow from operations attributable to
common shareholders $ 643.8 $ 437.4 $ 1,477.4 $ 1,594.3
Dividend on preferred securities(1) - - 7.8 7.7
----------- ---------- --------- ----------
Diluted cash flow from operations
attributable to common shareholders $ 643.8 $ 437.4 $ 1,485.2 $ 1,602.0
=========== ========== ========= ==========
Cash flow from operations per common share
attributable to common shareholders
Basic $ 4.83 $ 3.62 $ 11.73 $ 13.14
Diluted $ 4.71 $ 3.54 $ 11.28 $ 12.61
==============================================================================================
(1) PREFERRED SECURITIES ARE ANTI-DILUTIVE FOR THE THREE MONTHS ENDED
SEPTEMBER 30, 2002 AND SEPTEMBER 30, 2001, BUT ARE DILUTIVE FOR THE
NINE MONTHS ENDED SEPTEMBER 30, 2002 AND SEPTEMBER 30, 2001.
CANADIAN NATURAL RESOURCES LIMITED 31
================================================================================
8. FINANCIAL INSTRUMENTS
The Company uses certain derivative financial instruments to manage its
commodity prices, foreign currency and interest rate exposures. These financial
instruments are entered into solely for hedging purposes and are not used for
trading or other speculative purposes. The Company has the following financial
derivatives outstanding as at the date hereof:
REMAINING TERM VOLUME AVERAGE PRICE INDEX
===================== ============== ====================== ================
OIL
Brent differential swaps
Oct. 2002 - Dec. 2002 20,000 bbls/d US $1.28 Dated Brent/WTI
Jan. 2003 - Dec. 2003 15,000 bbls/d US $1.00 Dated Brent/WTI
Oil price collars
Oct. 2002 - Dec. 2002 153,500 bbls/d US $21.92 - US $26.94 WTI
Jan. 2003 - Jun. 2003 104,000 bbls/d US $22.09 - US $27.26 WTI
Jul. 2003 - Aug. 2003 60,000 bbls/d US $23.00 - US $27.85 WTI
Oil price fixed
Oct. 2002 - Dec. 2002 7,000 bbls/d US $22.13 WTI
=============================================================================================================================
REMAINING TERM VOLUME AVERAGE PRICE INDEX
===================== ============== ====================== ================
NATURAL GAS
NYMEX fixed
Oct. 2002 90,000 mmbtu/d US $2.85 NYMEX
Nov. 2002 - Dec. 2002 30,000 mmbtu/d US $3.27 NYMEX
NYMEX collar
Nov. 2002 - Oct. 2003 30,000 mmbtu/d US $2.88 - US $6.12 NYMEX
Sumas fixed
Oct. 2002 - Oct. 2003 10,000 mmbtu/d Cdn $2.85 Sumas
AECO collars
Oct. 2002 - Dec. 2002 100,000 GJ/d Cdn $4.25 - Cdn $6.03 AECO
Nov. 2002 - Mar. 2003 30,000 GJ/d Cdn $4.00 - Cdn $8.43 AECO
Nov. 2002 - Oct. 2003 40,000 GJ/d Cdn $3.50 - Cdn $5.38 AECO
AECO fixed
Oct. 2002 5,000 GJ/d Cdn $2.71 AECO
=============================================================================================================================
REMAINING TERM AMOUNT AVERAGE
EXCHANGE RATE
($ MILLIONS) (US $/CDN $)
===================== ============== =============
FOREIGN CURRENCY
Currency fixed Oct. 2002 US $0.4/month 1.37
Currency collars Oct. 2002 - May 2003 US $4.2/month 1.43 - 1.53
Oct. 2002 - Aug. 2004 US $25.0/month 1.51 - 1.59
======================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 32
================================================================================
REMAINING TERM AMOUNT EXCHANGE INTEREST INTEREST
RATE RATE RATE
($ MILLIONS) (US $/CDN $) (US $) (CDN $)
========================= ============ ============== ============ ==============
CURRENCY SWAP Oct. 2002 - Dec. 2005 US $125 1.55 7.69% 7.30%
==========================================================================================================
REMAINING TERM AMOUNT FIXED RATE FLOATING RATE
($ MILLIONS)
===================== ================= ================= ====================
INTEREST RATE
Swaps - fixed to floating Oct. 2002 - Jul. 2004 US $200 6.70% LIBOR + 2.09%
Oct. 2002 - Jul. 2006 US $200 6.70% LIBOR + 1.58%
Oct. 2002 - Jan. 2005 US $200 7.20% LIBOR + 3.00%
Oct. 2002 - Jan. 2007 US $200 7.20% LIBOR + 2.23%
Swap - floating to
fixed Oct. 2002 - Mar. 2004 Cdn $100 5.08%
===================================================================================================================
9. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
-------------------- ---------------------
2002 2001 2002 2001
========= ======== ========= ========
Interest paid $ 56.5 $ 25.8 $ 103.8 $ 99.0
Taxes paid $ 28.9 $ 37.8 $ 92.5 $ 118.5
==============================================================================
CANADIAN NATURAL RESOURCES LIMITED 33
================================================================================
10. SEGMENTED INFORMATION
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
------------------------------------ -------------------------------------
2002 2001 2002 2001
================ ================ ================= ================
REVENUE
North America $ 936.6 $ 651.6 $ 2,259.7 $ 2,456.3
North Sea 186.2 141.7 384.7 407.8
Offshore West Africa 36.5 12.2 71.3 35.8
Midstream 13.3 5.0 37.2 22.5
---------------- ---------------- ----------------- ----------------
$ 1,172.6 $ 810.5 $ 2,752.9 $ 2,922.4
---------------- ---------------- ----------------- ----------------
NET EARNINGS
North America $ 112.9 $ 74.8 $ 387.8 $ 503.5
North Sea (0.1) 15.6 (20.1) 94.9
Offshore West Africa 6.7 (4.4) (14.8) (4.6)
Midstream 4.8 1.6 12.6 6.6
---------------- ---------------- ----------------- ----------------
124.3 87.6 365.5 600.4
Dividend on preferred securities (NET OF TAX) (1.5) (1.4) (4.5) (4.3)
Revaluation of preferred securities (5.4) (4.9) 0.5 (6.4)
---------------- ---------------- ----------------- ----------------
NET EARNINGS ATTRIBUTABLE TO COMMON
SHAREHOLDERS $ 117.4 $ 81.3 $ 361.5 $ 589.7
================ ================ ================= ================
ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT
(EXCLUDING ACQUISITION OF RIO ALTO)
North America $ 331.8 $ 280.9 $ 984.4 $ 1,164.8
North Sea 295.6 32.2 251.4 63.5
Offshore West Africa 58.7 22.9 173.1 160.8
Midstream - 16.1 14.8 51.8
---------------- ---------------- ----------------- ----------------
$ 686.1 $ 352.1 $ 1,423.7 $ 1,440.9
===================================================================================================================================
Property, plant and equipment and future income taxes payable have been
increased by $39.3 million (2001 increased by $86.1 million) to provide for the
tax effect of the sale and acquisition of assets in the North Sea and North
America with a tax basis that differs from the purchase and sale price.
PROPERTY, PLANT AND EQUIPMENT TOTAL ASSETS
-------------------------------------------- ---------------------------------------
SEPTEMBER 30 DECEMBER 31 SEPTEMBER 30 DECEMBER 31
2002 2001 2002 2001
===================== ===================== ================= ================
SEGMENTED ASSETS
North America $ 10,644.8 $ 6,984.0 $ 11,256.4 $ 7,392.5
North Sea 1,140.5 866.2 1,219.2 941.6
Offshore West Africa 508.3 409.9 534.6 433.2
Midstream 187.9 182.8 204.4 199.6
--------------------- --------------------- ----------------- ----------------
$ 12,481.5 $ 8,442.9 $ 13,214.6 $ 8,966.9
===============================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 34
================================================================================
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 July 24, 2001. These ratios are based on the Company's consolidated
financial statements that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the 12-month period ended September 30, 2002:
Interest coverage (TIMES)
Net earnings 6.1(1)
Cash flow from operations attributable to common shareholders 14.5(2)
================================================================================
(1) NET EARNINGS PLUS INCOME TAXES AND INTEREST EXPENSE; DIVIDED BY
INTEREST EXPENSE.
(2) CASH FLOW FROM OPERATIONS ATTRIBUTABLE TO COMMON
SHAREHOLDERS PLUS CURRENT INCOME TAXES AND INTEREST EXPENSE; DIVIDED BY
INTEREST EXPENSE.
The interest coverage ratios have been calculated without including the annual
carrying charges relating to the outstanding preferred securities of the
Company. If the preferred securities were classified as long-term debt, these
annual carrying charges would be included in interest. If these annual carrying
charges had been included in the calculations, the net earnings coverage ratio
for the 12-month period ended September 30, 2002, would be 5.6x and the cash
flow coverage ratio for the 12-month period ended September 30, 2002 would be
13.5x.
CANADIAN NATURAL RESOURCES LIMITED 35
================================================================================
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Standard Time, 11:00 a.m.
Eastern Standard Time, on Wednesday, November 6, 2002. The North American
conference call number is 1-888-424-1091 and the outside North America
conference call number is 1-416-641-6662. Please call in about 10 minutes before
the starting time in order to be patched into the call. Should you experience
difficulty in connecting to the call, those in North America should please call
1-800-473-0602. Those outside North America should please call 1-905-502-3723.
Media are invited to participate in listen-only mode.
Replay: A taped rebroadcast will be available until November 13, 2002,
inclusive. To access postview in North America, dial 1-800-558-5253 and enter
the passcode 20848655. Those outside of North America dial 1-416-626-4100 and
enter the passcode number 20847905.
2002 YEAR END RESULTS
2002 year end results are scheduled for release Wednesday, February 26, 2003. A
conference call will be held at 9:00 a.m. Mountain Standard Time, 11:00 a.m.
Eastern Standard Time.
For further information, please contact:
CANADIAN NATURAL RESOURCES LIMITED
2500, 855 - 2 Street S.W.
Calgary, Alberta
T2P 4J8
ALLAN P. MARKIN
Chairman
TELEPHONE: (403) 514-7777
Facsimile: (403) 517-7370 JOHN G. LANGILLE
Email: investor.relations@cnrl.com President
Website: www.cnrl.com
STEVE W. LAUT
Executive Vice-President
TRADING SYMBOLS Operations
Toronto Stock Exchange - CNQ
New York Stock Exchange - CED COREY B. BIEBER
Director
Investor Relations
Certain information regarding the Company contained herein may constitute
forward-looking statements under applicable securities laws. Such statements
are subject to known or unknown risks and uncertainties that may cause actual
results to differ materially from those anticipated or implied in the
forward-looking statements.
CANADIAN NATURAL RESOURCES LIMITED 36
================================================================================