EXHIBIT 99.4
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[GRAPHICS OMITTED - PHOTOGRAPHS] | CANADIAN NATURAL
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diverse |
asset base | disciplined growth | strong leadership | NEWS RELEASE
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CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES
2008 THIRD QUARTER RESULTS
CALGARY, ALBERTA - NOVEMBER 6, 2008 - FOR IMMEDIATE RELEASE
Commenting on the third quarter 2008 results, Canadian Natural Resources Limited
("Canadian Natural" or the "Company")'s Chairman, Allan Markin stated, "The
Company delivered strong results in the third quarter, clearly illustrating how
Canadian Natural is strategically positioned to weather the ups and downs of
economic uncertainty. Our fundamental approach to business does not change due
to market conditions and the true strength of the Company lies in our ability to
create value in both good economic times and bad. As the third quarter
experienced volatile commodity pricing, our results serve as an example of how
our strategy of capital allocation, balance and cost control has led us to a
history of creating value for our shareholders. Canadian Natural is committed to
"doing it right" for all stakeholders. We remain active participants in the
communities in which we operate to ensure we conduct our business safely, to
maximize economic return, and participate with communities both locally and
regionally, while minimizing impact to the environment."
John Langille, Vice-Chairman of Canadian Natural continued, "Third quarter
results show the discipline of Canadian Natural as cash flow from operations and
capital expenditures were balanced for the quarter. Our hedging program is a
reflection of our commitment to internally fund our capital projects. As such,
we have added to our hedges for 2009 for both crude oil and natural gas at
strong prices. Our major projects in Alberta and Offshore West Africa are either
onstream or will be onstream by the first quarter of 2009 and as such, capital
spending on these projects will decrease markedly. The cash flow that has been
going towards these projects, along with the cash flow they will generate, will
provide free cash flow which will first go towards paying down debt, further
strengthening our balance sheet."
President and Chief Operating Officer, Steve Laut, commented, "Balance in our
asset base provides us the ability to optimize capital allocation. These
projects continue to center on heavy crude oil as a result of the favorable
heavy crude oil differential and Canadian Natural's ability to execute on these
projects. The Primrose East expansion, which will contribute up to 40,000
barrels per day of thermal crude oil, has come in ahead of schedule and on
budget. We achieved first steam in September and the project achieved first
production in October. The Olowi project in Offshore West Africa which will
deliver 20,000 barrels per day of light crude oil and is targeted for first
production in the first quarter of 2009. The Horizon Project is nearing
completion with first synthetic crude oil targeted for late in the fourth
quarter. First bitumen crude oil production was achieved in early September and
since then we have produced approximately 160,000 barrels of bitumen for test
purposes. The majority of the processing plants are either fully commissioned or
well into commissioning, and our on-site manpower has been reduced by over 50%
during the quarter. As we look forward to the imminent increase in production
coming from Primrose East, the Horizon Project, Olowi, and Baobab, Canadian
Natural emerges as a stronger, more diversified and robust company."
HIGHLIGHTS
Three Months Ended Nine Months Ended
--------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions, except as noted) 2008 2008 2007 2008 2007
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Net earnings (loss) $ 2,835 $ (347) $ 700 $ 3,215 $ 1,810
per common share, basic and diluted $ 5.25 $ (0.65) $ 1.30 $ 5.95 $ 3.36
Adjusted net earnings from operations (1) $ 963 $ 960 $ 644 $ 2,795 $ 1,860
per common share, basic and diluted $ 1.78 $ 1.78 $ 1.19 $ 5.17 $ 3.44
Cash flow from operations (2) $ 1,815 $ 1,859 $ 1,577 $ 5,399 $ 4,712
per common share, basic and diluted $ 3.36 $ 3.44 $ 2.92 $ 9.99 $ 8.74
Capital expenditures, net of dispositions $ 1,744 $ 2,127 $ 1,442 $ 5,624 $ 4,911
Daily production, before royalties
Natural gas (mmcf/d) 1,490 1,526 1,647 1,518 1,695
Crude oil and NGLs (bbl/d) 306,970 319,077 333,062 317,715 329,208
Equivalent production (boe/d) 555,356 573,437 607,484 570,704 611,665
===============================================================================================================================
(1) ADJUSTED NET EARNINGS FROM OPERATIONS IS A NON-GAAP MEASURE THAT THE
COMPANY UTILIZES TO EVALUATE ITS PERFORMANCE. THE DERIVATION OF THIS
MEASURE IS DISCUSSED IN THE MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A").
(2) CASH FLOW FROM OPERATIONS IS A NON-GAAP MEASURE THAT THE COMPANY CONSIDERS
KEY AS IT DEMONSTRATES THE COMPANY'S ABILITY TO FUND CAPITAL REINVESTMENT
AND REPAY DEBT. THE DERIVATION OF THIS MEASURE IS DISCUSSED IN THE MD&A.
o Total crude oil and NGLs production for Q3/08 was 306,970 bbl/d. Q3/08
crude oil production volumes decreased 4% from Q2/08 of 319,077 bbl/d, and
decreased 8% from Q3/07 of 333,062 bbl/d. Volumes in Q3/08 reflect the
transition between steam and production cycles for Primrose thermal wells,
and continued conversion of production wells to polymer injection wells at
Pelican Lake, along with scheduled turnarounds in the North Sea and
Offshore West Africa.
o Natural gas production volumes for the third quarter represented 45% of the
Company's total production. Natural gas production for Q3/08 averaged 1,490
mmcf/d, down 2% from 1,526 mmcf/d for Q2/08 and down 10% from 1,647 mmcf/d
for Q3/07. The decrease in volumes for Q3/08 from Q3/07 reflected the
reallocation of capital towards higher return crude oil projects. However,
the quarter once again saw a very successful North America natural gas
drilling program.
o Quarterly cash flow from operations was over $1.8 billion, a 2% decrease
from Q2/08 and an increase of 15% from Q3/07. The increase from Q3/07
primarily reflected higher crude oil and natural gas realizations,
partially offset by higher realized risk management losses, higher
royalties and lower sales volumes. The decrease from Q2/08 is primarily a
result of decreased sales volumes and higher production costs, offsetting
lower realized risk management losses and lower royalties.
o Quarterly net earnings for Q3/08 of $2.8 billion includes the effects of
unrealized risk management activity, stock based compensation and
fluctuations in foreign exchange. Excluding these items, quarterly adjusted
net earnings from operations for Q3/08 were $963 million.
o Maintained a strong undeveloped conventional core land base in Canada of
11.7 million net acres - a key asset for continued value growth.
o Improvements at the Pelican Lake Field continue with the conversion of
water flood wells to polymer flood wells, with production averaging
approximately 37,000 bbl/d.
2 CANADIAN NATURAL RESOURCES LIMITED
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o The Primrose East Expansion, which is targeted to add 40,000 bbl/d of
capacity, has made significant progress. First steam commenced in September
of this year, coming in ahead of schedule. First production was achieved in
late October 2008 versus a previous target of Q1/09.
o Drilling has started at Baobab in Offshore Cote d'Ivoire. The equipment was
mobilized in early Q2/08, enabling work to begin on the restoration of
shut-in production with the first well brought on stream in Q3/08. It is
targeted that 3 of the 5 wells will be brought on stream over the course of
2008 and 2009.
o The Olowi Project in Offshore Gabon has experienced some delays in
construction of the FPSO and first oil is now expected in Q1/09. During
Q3/08, construction of the Conductor Supported Platform Deck was completed.
Two appraisal wells have been drilled and development is continuing as
planned.
o Construction and commissioning of the Horizon Oil Sands Project ("Horizon
Project" or the "Project") continued in Q3/08 with first bitumen crude oil
production for testing purposes commencing in early September. First 34(0)
API, light sweet synthetic crude oil production ("SCO") is targeted for
late Q4/08.
o Committed to ship 120,000 bbl/d of heavy crude oil for 20 years on the
proposed Keystone pipeline US Gulf Coast expansion from Hardisty, Alberta
to Port Arthur, Texas.
o Committed to a 100,000 bbl/d heavy crude oil supply agreement with a major
US refiner to supply refineries in the Gulf Coast at market prices for 20
years.
o Declared a quarterly cash dividend on common shares of C$0.10 per common
share, payable January 1, 2009.
CANADIAN NATURAL RESOURCES LIMITED 3
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OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its
activities in core regions where it can dominate the land base and
infrastructure. Undeveloped land is critical to the Company's ongoing growth and
development within these core regions. Land inventories are maintained to enable
continuous exploitation of play types and geological trends, greatly reducing
overall exploration risk. By dominating infrastructure, the Company is able to
maximize utilization of its production facilities, thereby increasing control
over production costs. Further, the Company maintains large project inventories
and production diversification among each of the commodities it produces; namely
natural gas, light/medium crude oil, heavy crude oil and NGLs. A large
diversified project portfolio enables the effective allocation of capital to
higher return opportunities.
OPERATIONS REVIEW
ACTIVITY BY CORE REGION
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NET UNDEVELOPED LAND DRILLING ACTIVITY
AS AT NINE MONTHS ENDED
SEP 30, 2008 SEP 30, 2008
(THOUSANDS OF NET ACRES) (NET WELLS) (1)
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Canadian conventional
Northeast British Columbia 2,284 24.2
Northwest Alberta 1,379 69.7
Northern Plains 6,563 479.1
Southern Plains 854 91.2
Southeast Saskatchewan 124 47.0
In-situ Oil Sands 497 72.0
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11,701 783.2
Horizon Oil Sands Project 115 -
United Kingdom North Sea 268 4.1
Offshore West Africa 207 3.0
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12,291 790.3
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(1) DRILLING ACTIVITY INCLUDES STRATIGRAPHIC TEST AND SERVICE WELLS
DRILLING ACTIVITY (NUMBER OF WELLS)
Nine Months Ended Sep 30
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2008 2007
GROSS NET Gross Net
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Crude oil 529 500 458 423
Natural gas 304 228 386 303
Dry 32 28 89 77
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Subtotal 865 756 933 803
Stratigraphic test / service wells 36 34 250 248
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Total 901 790 1,183 1,051
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Success rate (excluding stratigraphic test / service wells) 96% 90%
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4 CANADIAN NATURAL RESOURCES LIMITED
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NORTH AMERICA CONVENTIONAL
NORTH AMERICA NATURAL GAS
Three Months Ended Nine Months Ended
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SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
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Natural gas production (mmcf/d) 1,467 1,501 1,622 1,494 1,670
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Net wells targeting natural gas 62 8 106 237 358
Net successful wells drilled 62 5 96 228 303
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Success rate 100% 63% 91% 96% 85%
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o Q3/08 North America natural gas production decreased 2% from Q2/08 and
decreased 10% from Q3/07. The year over year decrease reflected natural
declines in base production due to the Company's strategic decision to
reduce spending on natural gas drilling.
o Canadian Natural targeted 62 net natural gas wells in Q3/08. In Northeast
British Columbia, 2 net wells were drilled, while in Northwest Alberta, 7
net wells were drilled. In the Northern Plains, 38 net wells were drilled,
with 15 net wells drilled in the Southern Plains.
o Planned drilling activity for Q4/08 includes 31 natural gas wells compared
to drilling activity for Q4/07 of 92 net natural gas wells.
o Inflationary pressure continues to affect capital and service costs for
natural gas drilling. Cost control and maximizing shareholder value remain
priorities within this business environment.
NORTH AMERICA CRUDE OIL AND NGLS
Three Months Ended Nine Months Ended
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SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
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Crude oil and NGLs production (bbl/d) 239,973 245,616 252,095 244,832 243,388
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Net wells targeting crude oil 244 94 153 514 438
Net successful wells drilled 233 92 150 496 416
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Success rate 95% 98% 98% 96% 95%
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o Q3/08 North America crude oil and NGLs production decreased 2% from Q2/08
and decreased 5% from Q3/07 levels. The decreases are a reflection of
transitioning off the production cycle peaks at Primrose pads and continued
polymer conversion at Pelican Lake.
o The Primrose East Expansion, a new facility located 15 kilometers from the
existing Primrose South steam plant and 25 kilometers from the Wolf Lake
central processing facility, is targeted to add production capacity of
approximately 40,000 bbl/d of crude oil. Drilling and facility construction
is complete, with first steam achieved in September and first production
achieved in October versus the scheduled production target of Q1/09.
Primrose East is the second phase of the 325,000 bbl/d thermal growth
expansion plan identified to unlock the value from Canadian Natural's
thermal crude oil resource base.
o In early 2007, Canadian Natural announced its proposed third phase of the
thermal growth plan with a development plan for the production capacity of
45,000 bbl/d Kirby In-Situ Oil Sands Project located approximately 85 km
northeast of Lac La Biche in the Regional Municipality of Wood Buffalo. The
Company has filed its formal regulatory application documents for this
project as part of the Company's normal course of business.
CANADIAN NATURAL RESOURCES LIMITED 5
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o Development of new pads and secondary recovery conversion projects at
Pelican Lake continued as expected throughout Q3/08. In Q3/08, the Company
drilled 35 horizontal wells with plans to drill an additional 18 horizontal
wells throughout the remainder of 2008. Pelican Lake production averaged
approximately 37,000 bbl/d for Q3/08 compared to approximately 35,000 bbl/d
for Q3/07 and approximately 37,000 bbl/d for Q2/08. The response from the
polymer flood project continues to be positive and the Company is moving
forward on converting regions currently under waterflood to polymer flood
and expanding the polymer flood to new areas.
o Conventional heavy crude oil production volumes remained constant in Q3/08
compared to Q2/08, with volumes as expected.
o During Q3/08, drilling activity targeted 244 net crude oil wells including
152 wells targeting heavy crude oil, 35 wells targeting Pelican Lake crude
oil, 16 wells targeting thermal crude oil and 41 wells targeting light
crude oil.
o Planned drilling activity for Q4/08 includes 222 net crude oil wells,
excluding stratigraphic test and service wells.
o Inflationary pressure continues to affect capital and service costs for
crude oil drilling. Cost control and maximizing shareholder value remain
priorities within this business environment.
INTERNATIONAL
Three Months Ended Nine Months Ended
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SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
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Crude oil production (bbl/d)
North Sea 42,760 45,830 52,013 46,041 57,020
Offshore West Africa 24,237 27,631 28,954 26,842 28,800
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Natural gas production (mmcf/d)
North Sea 9 10 10 10 13
Offshore West Africa 14 15 15 14 12
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Net wells targeting crude oil 0.6 1.6 2.2 4.4 7.3
Net successful wells drilled 0.6 0.8 2.2 3.6 7.3
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Success rate 100% 50% 100% 82% 100%
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NORTH SEA
o At the end of the quarter 0.9 net crude oil wells were in progress. Crude
oil production was down 7% in Q3/08 to 42,760 bbl/d from 45,830 bbl/d in
Q2/08 as a result of planned shutdowns for maintenance at Murchison,
T-Block and Banff.
o Focus continues on infill drilling and workover opportunities with a
workover completed at Murchison during the quarter. A further workover at
Columba E and an oil well at Ninian were in progress at the end of the
quarter.
o Focus on waterflood optimization at Ninian continues with water injection
volumes in the quarter being the highest since Canadian Natural assumed
operatorship in 2002.
6 CANADIAN NATURAL RESOURCES LIMITED
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OFFSHORE WEST AFRICA
o Offshore West Africa's crude oil production decreased 12% in Q3/08 to
24,237 bbl/d from 27,631 bbl/d in Q2/08. A planned shutdown was undertaken
at Baobab during the quarter for maintenance and tie in of the first new
well from the drilling program. Espoir production declined due to the loss
of two wells during the quarter; however a successful well intervention
program restored production at one well during Q3/08 and the second well in
early Q4/08.
o Progress on the Facility Upgrade Project at Espoir to increase capacity of
the Floating, Production, Storage and Offtake Vessel ("FPSO") continues to
progress ahead of schedule and is expected to be completed in Q3/09, an
acceleration of 3 months from the original estimate.
o At Baobab, the Company continued with the deep water drilling program in
order to restore shut-in production with one well brought on stream in
Q3/08. Based on progress to date it is expected that 3 of the 5 Baobab
wells will come on stream over the course of 2008 and 2009.
o The Olowi Project in Offshore Gabon has experienced a delay in construction
of the FPSO and first oil is expected during Q1/09. During Q3/08
construction of the Conductor Supported Platform Deck was completed in
November of 2008. Two appraisal wells have been drilled and development is
continuing as planned.
HORIZON PROJECT
o Canadian Natural continues the completion of the construction,
commissioning and staged start up of the Horizon Project. There have been
some challenges encountered and overcome in the drive to complete the
Project and commence production of SCO. These challenges have primarily
related to commissioning and start up of the more complex components of the
Project. The challenges have been resolved in the Delayed Coker, the
Co-generation Plant and the Hydrogen Plant. Outstanding matters are
currently being resolved in the Naphtha Hydrotreater and Gas Oil
Hydrotreater in the Secondary Upgrading process.
o First SCO production is targeted for late in the fourth quarter of 2008 but
the Company recognizes that there must not be any further delays in the
completion or commissioning of these complex components of the Project. The
construction and operations teams in all areas continue to work together to
resolve issues and continue to test and prepare the site for operations.
o Canadian Natural is continuing with the staged start up of the Horizon
Project. The seven stages to the start up of the Horizon Project, as
outlined in the second quarter update release, and the associated targeted
start up dates are as follow:
- STAGE 1 - Mining. The Mining Operation is ready and continues to move
overburden. The mining team has already delivered over 300,000 tonnes
of mined oil sands to the Plant for test purposes.
- STAGE 2 - Steam Supply. As previously targeted, the utility plants have
been supplying low, medium and high pressure steam for commissioning
and start up purposes since July of this year.
- STAGE 3 - Bitumen Crude Oil Production. The Bitumen Crude Oil
Production operations are fully commissioned except for Froth
Treatment. The delays encountered in Froth Treatment have now been
resolved. The necessary re-work is completed and commissioning is well
underway. As previously targeted, first bitumen crude oil production of
approximately 160,000 barrels for test purposes was achieved in
September.
- STAGE 4 - Electricity Generation. The Co-generation Plant has been
producing steam since late July. Electricity generation has been
commissioned and is ready for operations.
- STAGE 5 - Sulphur Plant/Sour Gas Treating. The Sulphur Plant is
complete and is being turned over to operations for commissioning.
- STAGE 6 - Partially Upgraded Crude Oil Production. The Delayed
Coker/Diluent Recovery Unit Plants were completed in late October, have
been turned over to operations for commissioning and are currently
circulating diesel and waiting for Secondary Upgrading to start up.
CANADIAN NATURAL RESOURCES LIMITED 7
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- STAGE 7 - 34(degree)API, Light Sweet Synthetic Crude Oil Production.
The Naphtha Hydrotreating Plant (Plant 41) is completed and currently
being commissioned. The Gas Oil Hydrotreating Plant (Plant 43) is
completing electrical heat tracing and insulation concurrent with
commissioning. With an estimated start up capacity of 70,000 bbl/d,
first delivery of 34(degree) API, light sweet SCO to the sales pipeline
is currently targeted for late in the fourth quarter of 2008. The
Distillate Hydrotreating Plant (Plant 42) is mechanically complete
except for electrical heat tracing and insulation. First product output
through Plant 42 is currently targeted for the latter part of Q1/09,
enabling production start to ramp up to targeted facility capacity of
110,000 bbl/d of SCO. Targeted production ramp up would see 50-60% of
facility capacity by the end of Q1/09 and reach full targeted facility
capacity by later in 2009.
o The majority of the processing plants are either fully commissioned or well
into commissioning. The remaining work is being carefully managed, ensuring
a successful project by having all the necessary systems operational for
cold weather.
o The safety and well-being of the Horizon Project contractors and operation
staff remains a priority. On-site manpower is ramping down and the Company
has reduced its construction workforce by over 50% during Q3/08 to
approximately 2,500 tradesmen currently on site. The necessary operators
required for start up and a strong management team are all in place.
o A high level overview of progress by major plant facility at the Horizon
Project is as follows:
- MINING - Completed, ready for oil sands mining operation, continues to
move overburden
- ORE PREPARATION PLANT - Completed, ready for operation
- HYDROTRANSPORT - Completed, ready for operation
- PIPERACK - Completed, live and operational
- EXTRACTION - Completed, ready for operation
- FROTH TREATMENT - Completed, in commissioning and testing
- DELAYED COKER/DILUENT RECOVERY UNIT - Completed, circulating diesel
and ready for operation
- CO-GENERATION - Completed, producing steam and power
- SULPHUR PLANT - Completed, turned over to operations for commissioning
and testing
- TANKAGE - Completed, ready for operation
- MAIN CONTROL ROOM - Completed, live and operational
- UTILITIES & SERVICES - Completed, live and operational
- SCO PIPELINE (THIRD PARTY OWNED AND OPERATED) - Completed, ready for
operation
- HYDROGEN PLANT - Completed, turned over to operations for
commissioning and testing
- HYDROTREATERS - Plant 41 has been completed and turned over to
operations for commissioning and testing. Plant 43 is completing
electrical heat tracing and insulation while starting commissioning
and testing. Plant 42 is mechanically complete with electrical heat
tracing and insulation to be completed before turning the plant over
to operations for commissioning and testing.
o Delays and an extended commissioning schedule has led to an increase of
$441 million to the Project forecast construction costs. This results in
the revised total construction cost estimate for Phase 1 of the Horizon
Project to be approximately $9.7 billion. The targeted on-stream cost
estimate is $88,200 bbl/d capacity, including the benefits of the
significant pre-build capital invested for future phases.
8 CANADIAN NATURAL RESOURCES LIMITED
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MARKETING
Three Months Ended Nine Months Ended
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SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
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Crude oil and NGLs pricing
WTI (1) benchmark price (US$/bbl) $ 118.13 $ 124.00 $ 75.33 $ 113.38 $ 66.26
Western Canadian Select blend
differential(2) from WTI (%) 15% 17% 30% 18% 29%
Corporate average pricing before risk
management (C$/bbl) $ 102.30 $ 103.73 $ 58.10 $ 94.72 $ 54.57
Natural gas pricing
AECO benchmark price (C$/GJ) $ 8.78 $ 8.86 $ 5.32 $ 8.16 $ 6.46
Corporate average pricing before risk
management (C$/mcf) $ 8.82 $ 9.89 $ 5.87 $ 8.83 $ 7.03
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(1) REFERS TO WEST TEXAS INTERMEDIATE (WTI) CRUDE OIL BARREL PRICED AT CUSHING,
OKLAHOMA.
(2) BEGINNING IN Q1 2008, THE COMPANY HAS QUANTIFIED THE HEAVY DIFFERENTIAL
USING THE WESTERN CANADIAN SELECT ("WCS") BLEND AS THE HEAVY CRUDE OIL
MARKER. PRIOR PERIOD AMOUNTS HAVE BEEN RECLASSIFIED.
o In Q3/08, the WCS heavy crude oil differential as a percent of WTI was 15%,
compared to 17% in Q2/08. Heavy crude oil differentials improved in Q3/08
due to a strong worldwide demand for diesel and low crack spreads, with
overall high demand for crude oil products. Combined with declining heavy
crude oil production in Mexico, and increased Venezuelan supply shipments
to the Asian markets, US demand has been strong for Canadian heavy crude
oil.
o The Company continues its efforts with other industry players to find new
markets and to ease the logistical constraints in getting Western Canadian
heavy crude oil to new markets, such as the US Gulf Coast. Plans were
recently announced to expand the Keystone crude oil pipeline system
providing additional capacity to the US Gulf Coast by 2012. Canadian
Natural sees this as an important step in its marketing strategy by
allowing Canadian heavy crude oil into the US Gulf Coast market and as such
has committed 120,000 bbl/d to the Keystone Pipeline US Gulf Coast
Expansion for a 20 year period, subject to regulatory approval. The
agreement also includes an option for Canadian Natural to acquire an equity
interest in the Keystone Pipeline.
o Canadian Natural has also entered into a 20 year supply agreement with a
major US refiner for 100,000 bbl/d of heavy crude oil to US Gulf Coast
refineries. These agreements represent a step forward in the defined
marketing plan of Canadian Natural to improve the margins on the Company's
heavy crude oil production and to reduce the volatility historically
experienced in the heavy crude oil market. With the Keystone agreement,
Canadian Natural will retain full ownership of the resource while gaining
access to a key market for Canadian heavy crude oil. The refining capacity
in the US Gulf Coast area is approximately 7.5 million bbl/d. The long term
supply agreement with a US refiner, which is contingent on the completion
of the Keystone Pipeline US Gulf Coast Expansion, ensures a customer at the
end of the Keystone Pipeline for a large portion of Canadian Natural's
heavy crude oil that is shipped at prevailing US Gulf Coast heavy oil
market prices at the points of delivery.
o The Company sees this as a strategic component to its heavy crude oil
development which targets an increase to heavy crude oil production
capacity from just over 200,000 bbl/d today, to over 500,000 bbl/d over the
course of the next 15 years. Canadian heavy crude oil is very competitive
against other international grades available in the US Gulf Coast. For
Q3/08, the differential for the heavy crude oil marker, Mayan grade, was
US$11.47/bbl or 10%.
o During Q3/08, the Company contributed approximately 147,000 bbl/d of its
heavy crude oil streams to the WCS blend as market conditions resulted in
this strategy offering the optimal pricing for bitumen crude oil.
o Natural gas pricing for Q3/08 was volatile compared to prior periods
primarily as a result of fluctuations in demand and storage levels. North
America natural gas inventory levels increased significantly during the
third quarter due to increased shale gas production in the US and lower
weather related demand.
CANADIAN NATURAL RESOURCES LIMITED 9
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FINANCIAL REVIEW
o The current worldwide credit events have resulted in disruptions in the
availability of credit on commercially acceptable terms. In light of these
credit challenges, the Company has undertaken a thorough review of its
liquidity sources as well as its exposure to counterparties and has
concluded that its capital resources are sufficient to meet ongoing short,
medium and long-term commitments. Specifically, the Company continues to
believe that its internally generated cash flow from operations supported
by the implementation of its hedge policy, the flexibility of its capital
expenditure programs supported by its multi-year financial plans, its
existing credit facilities and its ability to raise new debt on
commercially acceptable terms, will provide sufficient liquidity to sustain
its operations in the short, medium and long-term and support its growth
strategy. Further, the Company believes that its counterparties currently
have the financial capacity to settle outstanding obligations in the normal
course of business. A brief summary of the Company's strengths are:
- A diverse asset base geographically and by product - produced in
excess of 555,000 boe/d in Q3/08, comprised of approximately 45%
natural gas and 55% crude oil - with 95% of production located in G8
countries with stable and secure economies.
- Financial stability and liquidity - cash flow from operations of $1.8
billion for Q3/08, with available unused bank lines of $2.4 billion at
September 30, 2008.
- Reduced volatility of commodity prices - a proactive commodity hedging
program to reduce the downside risk of volatility in commodity prices
supporting cash flow for its capital expenditure program.
- A strengthening balance sheet with debt to book capitalization of 41%
and debt to EBITDA of 1.7 times, both within targeted ranges.
o In 2007 and 2008, the Province of Alberta issued certain details of its
proposed changes to the Alberta crude oil and natural gas royalty regime,
effective January 1, 2009. The Company is currently awaiting finalization
and government approval of the royalty regulations, however it expects that
its 2009 and future Alberta royalty payments will increase as a result of
the proposed royalty changes and that its level of activity in Alberta in
aggregate will be reduced from what it otherwise would have been in the
absence of such royalty changes.
o Declared a quarterly cash dividend on common shares of C$0.10 per common
share, payable January 1, 2009.
OUTLOOK
The Company forecasts 2008 production levels before royalties to average between
1,492 and 1,506 mmcf/d of natural gas and between 313,000 and 318,000 bbl/d of
crude oil and NGLs. Q4/08 production guidance before royalties is forecast to
average between 1,430 and 1,455 mmcf/d of natural gas and between 300,000 and
316,000 bbl/d of crude oil and NGLs. Detailed guidance on production levels,
capital allocation and operating costs can be found on the Company's website at
HTTP://WWW.CNRL.COM/INVESTOR_INFO/CORPORATE_GUIDANCE/.
10 CANADIAN NATURAL RESOURCES LIMITED
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MANAGEMENT'S DISCUSSION AND ANALYSIS
FORWARD-LOOKING STATEMENTS
Certain statements in this document or documents incorporated herein by
reference constitute forward-looking statements or information (collectively
referred to herein as "forward-looking statements") within the meaning of
applicable securities legislation. Forward-looking statements can be identified
by the words "believe", "anticipate", "expect", "plan", "estimate", "target",
"continue", "could", "intend", "may", "potential", "predict", "should", "will",
"objective", "project", "forecast", "goal", "guidance", "outlook", "effort",
"seeks", "schedule" or expressions of a similar nature suggesting future outcome
or statements regarding an outlook. Disclosure related to expected future
commodity pricing, production volumes, royalties, operating costs, capital
expenditures and other guidance provided throughout this Management's Discussion
and Analysis ("MD&A"), constitutes forward-looking statements. In addition,
statements relating to "reserves" are deemed to be forward-looking statements as
they involve the implied assessment based on certain estimates and assumptions
that the reserves described can be profitably produced in the future. There are
numerous uncertainties inherent in estimating quantities of proved crude oil and
natural gas reserves and in projecting future rates of production and the timing
of development expenditures. The total amount or timing of actual future
production may vary significantly from reserve and production estimates.
These statements are not guarantees of future performance and are subject to
certain risks and the reader should not place undue reliance on these
forward-looking statements as there can be no assurance that the plans,
initiatives or expectations upon which they are based will occur.
The forward-looking statements are based on current expectations, estimates and
projections about Canadian Natural Resources Limited (the "Company") and the
industry in which the Company operates, which speak only as of the date such
statements were made or as of the date of the report or document in which they
are contained, and are subject to known and unknown risks, uncertainties and
other factors that could cause the actual results, performance or achievements
of the Company to be materially different from any future results, performance
or achievements expressed or implied by such forward-looking statements. Such
factors include, among others: general economic and business conditions which
will, among other things, impact demand for and market prices of the Company's
products; volatility of and assumptions regarding crude oil and natural gas
prices; fluctuations in currency and interest rates; assumptions on which the
Company's current guidance is based; economic conditions in the countries and
regions in which the Company conducts business; political uncertainty, including
actions of or against terrorists, insurgent groups or other conflict including
conflict between states; industry capacity; ability of the Company to implement
its business strategy, including exploration and development activities; impact
of competition; the Company's defense of lawsuits; availability and cost of
seismic, drilling and other equipment; ability of the Company and its
subsidiaries to complete its capital programs; the Company's and its
subsidiaries' ability to secure adequate transportation for its products;
unexpected difficulties in mining, extracting or upgrading the Company's bitumen
products; potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; ability of the Company to attract
the necessary labour required to build its thermal and oil sands mining
projects; operating hazards and other difficulties inherent in the exploration
for and production and sale of crude oil and natural gas; availability and cost
of financing; the Company's and its subsidiaries' success of exploration and
development activities and their ability to replace and expand crude oil and
natural gas reserves; timing and success of integrating the business and
operations of acquired companies; production levels; imprecision of reserve
estimates and estimates of recoverable quantities of crude oil, bitumen, natural
gas and liquids not currently classified as proved; actions by governmental
authorities; government regulations and the expenditures required to comply with
them (especially safety and environmental laws and regulations and the impact of
climate change initiatives on capital and operating costs); asset retirement
obligations; the adequacy of the Company's provision for taxes; and other
circumstances affecting revenues and expenses. The Company's operations have
been, and at times in the future may be, affected by political developments and
by federal, provincial and local laws and regulations such as restrictions on
production, changes in taxes, royalties and other amounts payable to governments
or governmental agencies, price or gathering rate controls and environmental
protection regulations. Should one or more of these risks or uncertainties
materialize, or should any of the Company's assumptions prove incorrect, actual
results may vary in material respects from those projected in the
forward-looking statements. The impact of any one factor on a particular
forward-looking statement is not determinable with certainty as such factors are
dependent upon other factors, and the Company's course of action would depend
upon its assessment of the future considering all information then available.
CANADIAN NATURAL RESOURCES LIMITED 11
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Readers are cautioned that the foregoing list of important factors is not
exhaustive. Unpredictable or unknown factors not discussed in this report could
also have material adverse effects on forward-looking statements. Although the
Company believes that the expectations conveyed by the forward-looking
statements are reasonable based on information available to it on the date such
forward-looking statements are made, no assurances can be given as to future
results, levels of activity and achievements. All subsequent forward-looking
statements, whether written or oral, attributable to the Company or persons
acting on its behalf are expressly qualified in their entirety by these
cautionary statements. Except as required by law, the Company assumes no
obligation to update forward-looking statements should circumstances or
Management's estimates or opinions change.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Management's Discussion and Analysis of the financial condition and results of
operations of the Company should be read in conjunction with the unaudited
interim consolidated financial statements for the nine and three months ended
September 30, 2008 and the MD&A and the audited consolidated financial
statements for the year ended December 31, 2007.
All dollar amounts are referenced in millions of Canadian dollars, except where
noted otherwise. The financial statements have been prepared in accordance with
Canadian generally accepted accounting principles ("GAAP"). This MD&A includes
references to financial measures commonly used in the crude oil and natural gas
industry, such as adjusted net earnings from operations and cash flow from
operations. These financial measures are not defined by GAAP and therefore are
referred to as non-GAAP measures. The non-GAAP measures used by the Company may
not be comparable to similar measures presented by other companies. The Company
uses these non-GAAP measures to evaluate its performance. The non-GAAP measures
should not be considered an alternative to or more meaningful than net earnings,
as determined in accordance with GAAP, as an indication of the Company's
performance. The non-GAAP measures adjusted net earnings from operations and
cash flow from operations are reconciled to net earnings, as determined in
accordance with GAAP, in the "Financial Highlights" section of this MD&A. The
Company also presents certain non-GAAP financial ratios and their derivation in
the "Liquidity and Capital Resources" section of this MD&A.
The calculation of barrels of oil equivalent ("boe") is based on a conversion
ratio of six thousand cubic feet ("mcf") of natural gas to one barrel ("bbl") of
crude oil to estimate relative energy content. This conversion may be
misleading, particularly when used in isolation, since the 6 mcf:1 bbl ratio is
based on an energy equivalency at the burner tip and does not represent the
value equivalency at the wellhead.
Production volumes are presented throughout this MD&A on a "before royalty" or
"gross" basis, and realized prices exclude the effect of risk management
activities and transportation and blending costs, except where noted otherwise.
Production on an "after royalty" or "net" basis is also presented for
information purposes only.
The following discussion refers primarily to the Company's financial results for
the nine and three months ended September 30, 2008 in relation to the comparable
periods in 2007 and the second quarter of 2008. The accompanying tables form an
integral part of this MD&A. This MD&A is dated November 4, 2008. Additional
information relating to the Company, including its Annual Information Form for
the year ended December 31, 2007, is available on SEDAR at www.sedar.com.
11 CANADIAN NATURAL RESOURCES LIMITED
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FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Nine Months Ended
---------------- ----------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- -----------------------------------------------------------------------------------------------------------------------------------
Revenue, before royalties $ 4,583 $ 5,112 $ 3,073 $ 13,662 $ 9,343
Net earnings (loss) $ 2,835 $ (347) $ 700 $ 3,215 $ 1,810
Per common share - basic and diluted $ 5.25 $ (0.65) $ 1.30 $ 5.95 $ 3.36
Adjusted net earnings from operations (1) $ 963 $ 960 $ 644 $ 2,795 $ 1,860
Per common share - basic and diluted $ 1.78 $ 1.78 $ 1.19 $ 5.17 $ 3.44
Cash flow from operations (2) $ 1,815 $ 1,859 $ 1,577 $ 5,399 $ 4,712
Per common share - basic and diluted $ 3.36 $ 3.44 $ 2.92 $ 9.99 $ 8.74
Capital expenditures, net of dispositions $ 1,744 $ 2,127 $ 1,442 $ 5,624 $ 4,911
===================================================================================================================================
(1) ADJUSTED NET EARNINGS FROM OPERATIONS IS A NON-GAAP MEASURE THAT REPRESENTS
NET EARNINGS ADJUSTED FOR CERTAIN ITEMS OF A NON-OPERATIONAL NATURE. THE
COMPANY EVALUATES ITS PERFORMANCE BASED ON ADJUSTED NET EARNINGS FROM
OPERATIONS. THE RECONCILIATION "ADJUSTED NET EARNINGS FROM OPERATIONS"
PRESENTED BELOW LISTS THE AFTER-TAX EFFECTS OF CERTAIN ITEMS OF A
NON-OPERATIONAL NATURE THAT ARE INCLUDED IN THE COMPANY'S FINANCIAL
RESULTS. ADJUSTED NET EARNINGS FROM OPERATIONS MAY NOT BE COMPARABLE TO
SIMILAR MEASURES PRESENTED BY OTHER COMPANIES.
(2) CASH FLOW FROM OPERATIONS IS A NON-GAAP MEASURE THAT REPRESENTS NET
EARNINGS ADJUSTED FOR NON-CASH ITEMS BEFORE WORKING CAPITAL ADJUSTMENTS.
THE COMPANY EVALUATES ITS PERFORMANCE BASED ON CASH FLOW FROM OPERATIONS.
THE COMPANY CONSIDERS CASH FLOW FROM OPERATIONS A KEY MEASURE AS IT
DEMONSTRATES THE COMPANY'S ABILITY TO GENERATE THE CASH FLOW NECESSARY TO
FUND FUTURE GROWTH THROUGH CAPITAL INVESTMENT AND TO REPAY DEBT. THE
RECONCILIATION "CASH FLOW FROM OPERATIONS" PRESENTED BELOW LISTS CERTAIN
NON-CASH ITEMS THAT ARE INCLUDED IN THE COMPANY'S FINANCIAL RESULTS. CASH
FLOW FROM OPERATIONS MAY NOT BE COMPARABLE TO SIMILAR MEASURES PRESENTED BY
OTHER COMPANIES.
ADJUSTED NET EARNINGS FROM OPERATIONS
THREE MONTHS ENDED NINE MONTHS ENDED
------------ -------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
($ MILLIONS) 2008 2008 2007 2008 2007
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NET EARNINGS (LOSS) AS REPORTED $ 2,835 $ (347) $ 700 $ 3,215 $ 1,810
STOCK-BASED COMPENSATION (RECOVERY) EXPENSE, NET OF TAX (A) (221) 328 54 107 145
UNREALIZED RISK MANAGEMENT (GAIN) LOSS, NET OF TAX (B) (1,750) 997 57 (677) 384
UNREALIZED FOREIGN EXCHANGE LOSS (GAIN), NET OF TAX (C) 99 (18) (167) 191 (408)
EFFECT OF STATUTORY TAX RATE AND OTHER LEGISLATIVE CHANGES ON
FUTURE INCOME TAX LIABILITIES (D) - - - (41) (71)
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ADJUSTED NET EARNINGS FROM OPERATIONS $ 963 $ 960 $ 644 $ 2,795 $ 1,860
==============================================================================================================================
(A) THE COMPANY'S EMPLOYEE STOCK OPTION PLAN PROVIDES FOR A CASH PAYMENT
OPTION. ACCORDINGLY, THE INTRINSIC VALUE OF OUTSTANDING VESTED OPTIONS
IS RECORDED AS A LIABILITY ON THE COMPANY'S BALANCE SHEET AND PERIODIC
CHANGES IN THE INTRINSIC VALUE ARE RECOGNIZED IN NET EARNINGS OR ARE
CAPITALIZED AS PART OF THE HORIZON OIL SANDS PROJECT DURING THE
CONSTRUCTION PERIOD.
(B) DERIVATIVE FINANCIAL INSTRUMENTS ARE RECORDED AT FAIR VALUE ON THE
BALANCE SHEET, WITH CHANGES IN FAIR VALUE OF NON-DESIGNATED HEDGES
RECOGNIZED IN NET EARNINGS. THE AMOUNTS ULTIMATELY REALIZED MAY BE
MATERIALLY DIFFERENT THAN REFLECTED IN THE FINANCIAL STATEMENTS DUE TO
CHANGES IN PRICES OF THE UNDERLYING ITEMS HEDGED, PRIMARILY CRUDE OIL
AND NATURAL GAS.
(C) UNREALIZED FOREIGN EXCHANGE GAINS AND LOSSES RESULT PRIMARILY FROM THE
TRANSLATION OF US DOLLAR DENOMINATED LONG-TERM DEBT TO PERIOD-END
EXCHANGE RATES, OFFSET BY THE IMPACT OF CROSS CURRENCY SWAPS, AND ARE
RECOGNIZED IN NET EARNINGS.
(D) ALL SUBSTANTIVELY ENACTED ADJUSTMENTS IN APPLICABLE INCOME TAX RATES
AND OTHER LEGISLATIVE CHANGES ARE APPLIED TO UNDERLYING ASSETS AND
LIABILITIES ON THE COMPANY'S CONSOLIDATED BALANCE SHEET IN DETERMINING
FUTURE INCOME TAX ASSETS AND LIABILITIES. THE IMPACT OF THESE TAX RATE
AND OTHER LEGISLATIVE CHANGES IS RECORDED IN NET EARNINGS DURING THE
PERIOD THE LEGISLATION IS SUBSTANTIVELY ENACTED. INCOME TAX RATE
CHANGES IN THE FIRST QUARTER OF 2008 RESULTED IN A REDUCTION OF FUTURE
INCOME TAX LIABILITIES OF APPROXIMATELY $19 MILLION IN NORTH AMERICA
AND $22 MILLION IN COTE D'IVOIRE, OFFSHORE WEST AFRICA. INCOME TAX
RATE CHANGES IN THE SECOND QUARTER OF 2007 RESULTED IN A REDUCTION OF
FUTURE INCOME TAX LIABILITIES OF APPROXIMATELY $71 MILLION IN NORTH
AMERICA.
CANADIAN NATURAL RESOURCES LIMITED 13
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CASH FLOW FROM OPERATIONS
THREE MONTHS ENDED NINE MONTHS ENDED
-------------- --------------
SEP 30 JUN 30 SEP 30 SEP 30 SEP 30
($ MILLIONS) 2008 2008 2007 2008 2007
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NET EARNINGS (LOSS) $ 2,835 $ (347) $ 700 $ 3,215 $ 1,810
NON-CASH ITEMS:
DEPLETION, DEPRECIATION AND AMORTIZATION 659 670 715 2,017 2,144
ASSET RETIREMENT OBLIGATION ACCRETION 18 17 18 52 53
STOCK-BASED COMPENSATION (RECOVERY) EXPENSE (308) 459 78 151 209
UNREALIZED RISK MANAGEMENT (GAIN) LOSS (2,506) 1,415 76 (983) 555
UNREALIZED FOREIGN EXCHANGE LOSS (GAIN) 113 (20) (195) 219 (477)
DEFERRED PETROLEUM REVENUE TAX (RECOVERY) EXPENSE (7) (34) 10 (62) 27
FUTURE INCOME TAX EXPENSE (RECOVERY) 1,011 (301) 175 790 391
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CASH FLOW FROM OPERATIONS $ 1,815 $ 1,859 $ 1,577 $ 5,399 $ 4,712
===============================================================================================================================
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the nine months ended September 30, 2008 were $3,215 million
compared to $1,810 million for the nine months ended September 30, 2007. Net
earnings for the nine months ended September 30, 2008 included net unrealized
after-tax income of $420 million related to the effects of risk management
activities, changes in foreign exchange rates and stock-based compensation, and
the impact of statutory tax rate changes on future income tax liabilities,
compared to net unrealized after-tax expenses of $50 million for the nine months
ended September 30, 2007. Excluding these items, adjusted net earnings from
operations for the nine months ended September 30, 2008 increased to a record
$2,795 million compared to $1,860 million for the nine months ended September
30, 2007. The increase in adjusted net earnings from the comparable period in
2007 was primarily due to the impact of higher realized pricing, lower
depletion, depreciation and amortization expense, and lower interest and
administration expense. These factors were partially offset by higher realized
risk management losses, higher royalty and production expense, lower sales
volumes, and the impact of the stronger Canadian dollar relative to the US
dollar.
Net earnings for the third quarter of 2008 was $2,835 million compared to net
earnings of $700 million for the third quarter of 2007 and a net loss of $347
million for the prior quarter. The net earnings for the third quarter of 2008
included net unrealized after-tax income of $1,872 million related to the
effects of risk management activities, fluctuations in foreign exchange rates,
and fluctuations in stock-based compensation, compared to net unrealized
after-tax income of $56 million for the third quarter of 2007 and net unrealized
after-tax expenses of $1,307 million for the prior quarter. Excluding these
items, adjusted net earnings from operations for the third quarter of 2008
increased to $963 million compared to $644 million for the third quarter of 2007
and $960 million for the prior quarter. The increase in adjusted net earnings
from the third quarter of 2007 was primarily due to the impact of higher
realized pricing, lower depletion, depreciation and amortization expense, and
lower interest and administration expense. These factors were partially offset
by higher realized risk management losses, higher royalty and production
expense, and lower sales volumes. The increase in adjusted net earnings from the
prior quarter was primarily due to the impact of lower depletion, depreciation
and amortization expense, lower realized risk management losses, lower royalty
expense, lower interest expense, and the impact of the weaker Canadian dollar,
partially offset by the impact of lower sales volumes and higher production
expense.
The impacts of unrealized risk management activities, stock-based compensation
and changes in foreign exchange rates are expected to continue to contribute to
significant quarterly volatility in consolidated net earnings and are discussed
in detail in the relevant sections of this MD&A.
Cash flow from operations for the nine months ended September 30, 2008 increased
to a record $5,399 million compared to $4,712 million for the nine months ended
September 30, 2007. The increase from the comparable period in 2007 was
primarily due to the impact of higher realized pricing, and lower interest and
administration expense, partially offset by higher realized risk management
losses, higher royalty and production expense, higher current income tax
expense, lower sales volumes, and the impact of the stronger Canadian dollar
relative to the US dollar.
14 CANADIAN NATURAL RESOURCES LIMITED
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Cash flow from operations for the third quarter of 2008 increased to $1,815
million compared to $1,577 million for the third quarter of 2007 and decreased
slightly from $1,859 million for the prior quarter. The increase from the third
quarter of 2007 was primarily due to the impact of higher realized pricing, and
lower interest and administration expense, partially offset by higher realized
risk management losses, higher royalty and production expense, higher current
income tax expense, lower sales volumes and the impact of the stronger Canadian
dollar relative to the US dollar. The decrease from the prior quarter was
primarily due to the impact of lower sales volumes and higher production
expense, partially offset by lower realized risk management losses, lower
royalty expense, and the impact of the weaker Canadian dollar.
Total production before royalties for the nine months ended September 30, 2008
decreased 7% to average 570,704 boe/d from 611,665 boe/d for the nine months
ended September 30, 2007. Production for the third quarter of 2008 decreased 9%
to 555,356 boe/d from 607,484 boe/d for the third quarter of 2007 and 3% from
573,437 boe/d for the prior quarter. Total production for the third quarter of
2008 was within the Company's previously issued guidance.
For a discussion of the impact of current worldwide credit market events, please
refer to the "Liquidity and Capital Resources" section of this MD&A.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the eight most
recently completed quarters:
($ millions, except per common share amounts) SEP 30 Jun 30 Mar 31 Dec 31
2008 2008 2008 2007
- --------------------------------------------------------------------------------------------------------------------------------
Revenue, before royalties $ 4,583 $ 5,112 $ 3,967 $ 3,200
Net earnings (loss) $ 2,835 $ (347) $ 727 $ 798
Net earnings (loss) per common share
- Basic and diluted $ 5.25 $ (0.65) $ 1.35 $ 1.48
================================================================================================================================
Sep 30 Jun 30 Mar 31 Dec 31
($ millions, except per common share amounts) 2007 2007 2007 2006
- --------------------------------------------------------------------------------------------------------------------------------
Revenue, before royalties $ 3,073 $ 3,152 $ 3,118 $ 2,826
Net earnings $ 700 $ 841 $ 269 $ 313
Net earnings per common share
- Basic and diluted $ 1.30 $ 1.56 $ 0.50 $ 0.58
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Net earnings (loss) over the eight most recently completed quarters generally
reflected fluctuations in realized crude oil and natural gas prices,
fluctuations in sales volumes, the impact of mark-to-market accounting of
financial instruments and stock-based compensation, fluctuations in depletion,
depreciation and amortization charges and foreign exchange rates, and
adjustments to future income tax liabilities due to statutory tax rate and other
legislative changes. More specifically, volatility in quarterly net earnings was
primarily due to:
o Crude oil pricing
Crude oil prices reflected strong demand, continued geopolitical
uncertainties and fluctuations in the Heavy Crude Oil Differential from WTI
("Heavy Differential") in North America.
o Natural gas pricing
Natural gas prices primarily reflected seasonal fluctuations in both the
demand for natural gas and inventory storage levels, fluctuations in
liquefied natural gas imports into the US, and increased shale gas
production in the US.
o Crude oil and NGLs sales volumes
Crude oil and NGLs sales volumes primarily reflected increased production
from the Company's Primrose thermal projects, the results from the Pelican
Lake water and polymer flood projects, and development of the Espoir Field.
Crude oil and NGLs sales volumes also reflected fluctuations in production
from the North Sea and Offshore West Africa due to timing of maintenance
activities and liftings and the impact of shut-in Baobab production.
CANADIAN NATURAL RESOURCES LIMITED 15
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o Natural gas sales volumes
Natural gas sales volumes primarily reflected additional natural gas
volumes as a result of internally generated growth. These increases were
offset by production declines due to the Company's strategic reduction in
natural gas drilling activity.
o Foreign exchange rates
A general strengthening of the Canadian dollar relative to the US dollar
has decreased the realized price the Company received for its crude oil and
natural gas sales, as sales prices are based predominately on US dollar
denominated benchmarks. Similarly, unrealized foreign exchange gains and
losses were recorded with respect to US dollar denominated debt balances
and the re-measurement of North Sea future income tax liabilities
denominated in UK pounds sterling to US dollars, partially offset by the
impact of cross currency swaps.
o Risk management
Net earnings have fluctuated due to the recognition of realized and
unrealized gains and losses from the mark-to-market and subsequent
settlement of the Company's risk management activities.
o Changes in income tax expense
Income tax expense fluctuations include statutory tax rate and other
legislative changes enacted or substantively enacted in the various
periods.
o Stock-based compensation
Net earnings have fluctuated due to the mark-to-market movements of the
Company's stock-based compensation liability. Stock-based compensation
expense (recovery) reflected fluctuations in the Company's share price over
the eight most recently completed quarters.
o Production expense
Production expense has fluctuated company wide primarily due to the impact
for the demand for services, industry-wide inflationary cost pressures
experienced in prior quarters in all segments, fluctuations in product mix,
and the impact of seasonal costs that are dependent on weather.
o Depletion, depreciation and amortization
Depletion, depreciation and amortization expense has fluctuated due to
changes in sales volumes, finding and development costs associated with
crude oil and natural gas exploration, and estimated future costs to
develop the Company's proved undeveloped reserves.
16 CANADIAN NATURAL RESOURCES LIMITED
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OPERATING HIGHLIGHTS
Three Months Ended Nine Months Ended
-------------- --------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- -------------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
Sales price (2) $ 102.30 $ 103.73 $ 58.10 $ 94.72 $ 54.57
Royalties 14.17 14.82 6.65 12.49 5.69
Production expense 17.61 16.39 13.13 16.24 13.97
- -------------------------------------------------------------------------------------------------------------------------------
Netback $ 70.52 $ 72.52 $ 38.32 $ 65.99 $ 34.91
- -------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
Sales price (2) $ 8.82 $ 9.89 $ 5.87 $ 8.83 $ 7.03
Royalties 1.55 1.86 0.89 1.59 1.16
Production expense 1.05 0.94 0.88 1.01 0.91
- -------------------------------------------------------------------------------------------------------------------------------
Netback $ 6.22 $ 7.09 $ 4.10 $ 6.23 $ 4.96
- -------------------------------------------------------------------------------------------------------------------------------
BARRELS OF OIL EQUIVALENT ($/boe) (1)
Sales price (2) $ 80.60 $ 84.88 $ 47.96 $ 76.73 $ 48.99
Royalties 12.06 13.26 6.07 11.22 6.27
Production expense 12.52 11.60 9.62 11.70 10.05
- -------------------------------------------------------------------------------------------------------------------------------
Netback $ 56.02 $ 60.02 $ 32.27 $ 53.81 $ 32.67
===============================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
CANADIAN NATURAL RESOURCES LIMITED 17
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BUSINESS ENVIRONMENT
Three Months Ended Nine Months Ended
-------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- -----------------------------------------------------------------------------------------------------------------------------------
WTI benchmark price (US$/bbl) $ 118.13 $ 124.00 $ 75.33 $ 113.38 $ 66.26
Dated Brent benchmark price (US$/bbl) $ 114.96 $ 121.39 $ 74.85 $ 111.11 $ 67.18
WCS blend differential from WTI (US$/bbl) (1) $ 17.98 $ 21.62 $ 22.39 $ 20.33 $ 19.04
WCS blend differential from WTI (%) (1) 15% 17% 30% 18% 29%
Condensate benchmark price (US$/bbl) $ 118.57 $ 124.64 $ 75.93 $ 113.89 $ 66.82
NYMEX benchmark price (US$/mmbtu) $ 10.11 $ 10.80 $ 6.13 $ 9.66 $ 6.88
AECO benchmark price (C$/GJ) $ 8.78 $ 8.86 $ 5.32 $ 8.16 $ 6.46
US / Canadian dollar average exchange rate $ 0.9605 $ 0.9900 $ 0.9565 $ 0.9819 $ 0.9045
===================================================================================================================================
(1) BEGINNING IN THE FIRST QUARTER OF 2008, THE COMPANY HAS QUANTIFIED THE
HEAVY DIFFERENTIAL USING THE WESTERN CANADIAN SELECT ("WCS") BLEND AS THE
HEAVY CRUDE OIL MARKER. PRIOR PERIOD AMOUNTS HAVE BEEN RECLASSIFIED.
COMMODITY PRICES
Crude oil sales contracts in the North America segment are typically based on
WTI benchmark pricing. WTI averaged US$113.38 per bbl for the nine months ended
September 30, 2008, an increase of 71% from US$66.26 per bbl for the nine months
ended September 30, 2007. WTI averaged US$118.13 per bbl for the third quarter
of 2008, an increase of 57% from US$75.33 per bbl for the third quarter of 2007,
and a decrease of 5% from US$124.00 per bbl for the prior quarter. WTI pricing
during the third quarter of 2008 continued to reflect strong demand for crude
oil, tight supply and ongoing geopolitical uncertainty, particularly in July
2008 when WTI crude oil futures hit an all time high of approximately US$147.00
per bbl. WTI pricing significantly weakened toward the end of the third quarter
and traded below US$70.00 in October 2008. This decrease in WTI pricing was
partially offset by a significant weakening in the Canadian dollar compared to
the US dollar, with the Canadian dollar falling below US$0.80 in October 2008.
Crude oil sales contracts for the Company's North Sea and Offshore West Africa
segments are typically based on Dated Brent ("Brent") pricing, which generally
continued to benefit from strong European and Asian demand. Brent averaged
US$111.11 per bbl for the nine months ended September 30, 2008; an increase of
65% compared to US$67.18 per bbl for the nine months ended September 30, 2007.
In the third quarter of 2008, Brent averaged US$114.96 per bbl, an increase of
54% compared to US$74.85 per bbl for the third quarter of 2007, and a decrease
of 5% from US$121.39 per bbl for the prior quarter. Similar to WTI pricing,
Brent pricing significantly weakened toward the end of the third quarter.
The Company's realized crude oil prices increased from the nine months ended
September 30, 2007 primarily as a result of increased WTI and Brent pricing and
a narrower Heavy Differential, offset by the impact of a strong Canadian dollar.
The Heavy Differential averaged 18% for the nine months ended September 30, 2008
compared to 29% for the nine months ended September 30, 2007. For the third
quarter of 2008, the Heavy Differential averaged 15% compared to 30% for the
third quarter of 2007, and 17% for the prior quarter. The narrowing of the Heavy
Differential from the comparable periods was primarily due to increased demand
for heavy crude oil due to reduced refinery cracking margins and increased
demand for diesel. Realized prices continued to be adversely impacted by the
strong Canadian dollar.
The Company anticipates continued volatility in the crude oil pricing benchmarks
due to the unpredictable nature of supply and demand factors, geopolitical
events and the potential of a global economic slowdown resulting from the
worldwide financial crisis. The Heavy Differential is expected to continue to
reflect seasonal demand fluctuations and refinery cracking margins.
NYMEX natural gas prices averaged US$9.66 per mmbtu for the nine months ended
September 30, 2008, an increase of 40% from US$6.88 per mmbtu for the nine
months ended September 30, 2007. For the third quarter of 2008, NYMEX natural
gas prices averaged US$10.11 per mmbtu, an increase of 65% from US$6.13 per
mmbtu for the third quarter of 2007, and a decrease of 6% from US$10.80 per
mmbtu for the prior quarter. AECO natural gas prices for the nine months ended
September 30, 2008 increased 26% to average $8.16 per GJ from $6.46 per GJ for
18 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
the nine months ended September 30, 2007. For the third quarter of 2008, AECO
natural gas prices averaged $8.78 per GJ, an increase of 65% from $5.32 per GJ
in the third quarter of 2007 and a decrease of 1% from $8.86 per GJ for the
prior quarter. Fluctuations in natural gas prices from the comparable periods
were primarily related to demand and storage levels. North America natural gas
inventory levels increased significantly during the third quarter of 2008 due to
increased shale gas production in the US and lower weather related demand.
OPERATING, ROYALTY AND CAPITAL COSTS
Strong commodity prices in recent years have resulted in increased demand and
costs for oilfield services worldwide. This has led to inflationary operating
and capital cost pressures throughout the crude oil and natural gas industry,
particularly related to drilling activities and oil sands developments.
The crude oil and natural gas industry is also experiencing cost pressures
related to environmental regulations, both in North America and internationally.
In Canada, the Federal Government has indicated its intent to develop
regulations that would be in effect in 2010 to address industrial greenhouse gas
("GHG") emissions. The Federal Government has also outlined national and
sectoral reduction targets for several categories of air pollutants. In Alberta,
GHG regulations came into effect July 1, 2007, affecting facilities emitting
more than 100 kilotonnes of CO2e annually. Two of the Company's facilities, the
Primrose/Wolf Lake in-situ heavy crude oil facilities and the Hays sour natural
gas plant, are captured under the regulations. In the UK, GHG regulations have
been in effect since 2005. During Phase 1 (2005 -2007) of the UK National
Allocation Plan the Company operated below its CO2 allocation. For Phase 2 (2008
- - 2012) the Company's CO2 allocation has been decreased below the Company's
estimated current operations emissions. The Company continues to focus on
implementing reduction programs based on efficiency audits to reduce CO2
emissions at its major facilities and on trading mechanisms to ensure compliance
with requirements now in effect.
Commencing July 1, 2008, the British Columbia carbon tax is being assessed at
$10/tonne of CO2e on fuel consumed in the province, increasing to $30/tonne by
July 1, 2012.
Continued cost pressures and the final outcome of changes to environmental
regulations may adversely impact the Company's future net earnings, cash flow
and capital projects.
In 2007 and 2008, the Province of Alberta issued certain details of its proposed
changes to the Alberta crude oil and natural gas royalty regime, effective
January 1, 2009. These proposed changes include:
o The implementation of a new bitumen valuation methodology and a sliding
scale for oil sands royalties ranging from 1% to 9% on a gross revenue
basis pre-payout and 25% to 40% on a net revenue basis post-payout
depending on benchmark crude oil pricing; and
o New royalty formulas for conventional crude oil and natural gas that are to
operate on sliding scales ranging up to 50% determined by commodity prices
and well productivity.
The Company is currently awaiting finalization and government approval of the
royalty regulations. However, the Company expects that its 2009 and future
Alberta royalty payments will increase as a result of the proposed royalty
changes and that its level of activity in Alberta in aggregate will be reduced
from what it otherwise would have been in the absence of such royalty changes.
CANADIAN NATURAL RESOURCES LIMITED 19
===============================================================================
PRODUCT PRICES
Three Months Ended Nine Months Ended
---------------- ----------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1) (2)
North America $ 99.05 $ 97.94 $ 52.47 $ 89.83 $ 48.68
North Sea $ 109.82 $ 129.57 $ 77.55 $ 111.82 $ 72.86
Offshore West Africa $ 125.71 $ 114.56 $ 70.52 $ 110.93 $ 67.37
Company average $ 102.30 $ 103.73 $ 58.10 $ 94.72 $ 54.57
NATURAL GAS ($/mcf) (1) (2)
North America $ 8.83 $ 9.94 $ 5.88 $ 8.86 $ 7.05
North Sea $ 3.65 $ 4.27 $ 5.26 $ 3.73 $ 4.47
Offshore West Africa $ 11.18 $ 8.97 $ 5.31 $ 9.33 $ 5.76
Company average $ 8.82 $ 9.89 $ 5.87 $ 8.83 $ 7.03
COMPANY AVERAGE ($/boe) (1) (2) $ 80.60 $ 84.88 $ 47.96 $ 76.73 $ 48.99
PERCENTAGE OF GROSS REVENUE (2)
(excluding midstream revenue)
Crude oil and NGLs 70% 68% 67% 69% 60%
Natural gas 30% 32% 33% 31% 40%
==========================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
The Company's realized crude oil prices increased 74% to average $94.72 per bbl
for the nine months ended September 30, 2008 from $54.57 per bbl for the nine
months ended September 30, 2007. Realized crude oil prices for the third quarter
of 2008 increased 76% to average $102.30 per bbl from $58.10 per bbl for the
third quarter of 2007, and decreased 1% from $103.73 per bbl for the prior
quarter. The Company's realized crude oil prices increased from the comparable
periods in 2007 primarily as a result of increased WTI and Brent benchmark
prices and a narrower Heavy Differential, partially offset by a strong Canadian
dollar relative to the US dollar. The decrease from the prior quarter was
primarily due to declining WTI and Brent benchmark prices, partially offset by a
narrower Heavy Differential and the impact of the weakening Canadian dollar
relative to the US dollar.
The Company's realized natural gas price increased 26% to average $8.83 per mcf
for the nine months ended September 30, 2008 from $7.03 per mcf for the nine
months ended September 30, 2007. Realized natural gas prices for the third
quarter of 2008 increased 50% to average $8.82 per mcf from $5.87 per mcf for
the third quarter of 2007, and decreased 11% from $9.89 per mcf for the prior
quarter. The increase in realized natural gas prices from the comparable periods
in 2007 primarily reflected increased benchmark prices due to increased
industrial consumption, colder weather experienced late in the first quarter of
2008, and lower liquefied natural gas imports into the US in the first half of
2008. The decrease in realized natural gas prices from the prior quarter was
primarily due to higher storage levels due to increased shale gas production in
the US, and lower demand resulting from milder weather experienced during the
third quarter of 2008.
20 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
NORTH AMERICA
North America realized crude oil prices increased 85% to average $89.83 per bbl
for the nine months ended September 30, 2008 from $48.68 per bbl for the nine
months ended September 30, 2007. Realized crude oil prices increased 89% to
average $99.05 per bbl for the third quarter of 2008 from $52.47 per bbl for the
third quarter of 2007, and increased 1% from $97.94 bbl for the prior quarter.
The increase from the comparable periods in 2007 was due to the increase in WTI
benchmark pricing and a narrower Heavy Differential. The increase from the prior
quarter was due to a narrower Heavy Differential and the impact of the weakening
Canadian dollar relative to the US dollar, partially offset by declining WTI
benchmark pricing.
In North America, the Company continues to focus on its crude oil marketing
strategy, including the development of a blending strategy that expands markets
within current pipeline infrastructure, supporting pipeline projects that will
provide capacity to transport crude oil to new markets, and working with
refiners to add incremental heavy crude oil conversion capacity. During the
third quarter, the Company contributed approximately 147,000 bbl/d of heavy
crude oil blends to the WCS stream. The Company has also entered into a 20 year
transportation agreement to commit to ship 120,000 bbl/d of heavy sour crude oil
on the proposed 500,000 bbl/d Keystone Pipeline US Gulf Coast expansion from
Hardisty, Alberta to the US Gulf Coast. Contemporaneously, the Company also
entered into a 20 year crude oil purchase and sales agreement to sell 100,000
bbl/d of heavy sour crude oil to a major US refiner. Deliveries under the
agreements are expected to commence in 2012 upon completion of the pipeline
expansion and are subject to Keystone's receipt of regulatory approval of the
pipeline expansion as well as minimum levels of shipper commitments.
North America realized natural gas prices increased 26% to average $8.86 per mcf
for the nine months ended September 30, 2008 from $7.05 per mcf for the nine
months ended September 30, 2007. Realized North America natural gas prices
increased 50% to average $8.83 per mcf for the third quarter of 2008 from $5.88
per mcf for the third quarter of 2007, and decreased 11% from $9.94 per mcf for
the prior quarter. The fluctuations in natural gas prices from the comparable
periods in 2007 and the prior quarter were primarily related to the fluctuations
in benchmark prices.
Comparisons of the prices received for the Company's North America production by
product type were as follows:
---------------------
SEP 30 Jun 30 Sep 30
2008 2008 2007
- -----------------------------------------------------------------------------------------------------------------
WELLHEAD PRICE (1) (2)
Light/medium crude oil and NGLs (C$/bbl) $ 108.13 $ 113.92 $ 67.55
Pelican Lake crude oil (C$/bbl) $ 95.58 $ 98.28 $ 48.91
Primary heavy crude oil (C$/bbl) $ 97.30 $ 95.39 $ 47.47
Thermal heavy crude oil (C$/bbl) $ 97.06 $ 88.72 $ 48.99
Natural gas (C$/mcf) $ 8.83 $ 9.94 $ 5.88
=================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
NORTH SEA
North Sea realized crude oil prices increased 53% to average $111.82 per bbl for
the nine months ended September 30, 2008 from $72.86 per bbl for the nine months
ended September 30, 2007. Realized North Sea crude oil prices increased 42% to
average $109.82 per bbl for the third quarter of 2008 from $77.55 per bbl for
the third quarter of 2007, and decreased by 15% from $129.57 per bbl for the
prior quarter. Realized crude oil prices per bbl in any particular quarter are
dependant on the terms of the various sales contracts, the frequency and timing
of liftings of certain fields, and prevailing crude prices at the time of
lifting. Realized crude oil prices in the North Sea during the third quarter
continued to benefit from the impact of strong European and Asian demand,
partially offset by the impact of the strong Canadian dollar.
OFFSHORE WEST AFRICA
Offshore West Africa realized crude oil prices increased 65% to average $110.93
per bbl for the nine months ended September 30, 2008 from $67.37 per bbl for the
nine months ended September 30, 2007. Realized Offshore West Africa crude oil
prices increased 78% to average $125.71 per bbl for the third quarter of 2008
from $70.52 per bbl for the third quarter of 2007, and increased 10% from
$114.56 per bbl for the prior quarter. Realized crude oil prices per bbl in any
particular quarter are dependant on the terms of the various sales contracts,
the frequency and timing of liftings of each field, and prevailing crude prices
CANADIAN NATURAL RESOURCES LIMITED 21
===============================================================================
at the time of lifting. Realized crude oil prices in Offshore West Africa during
the third quarter continued to benefit from the impact of strong European and
Asian demand, offset by the impact of the strong Canadian dollar.
CRUDE OIL INVENTORY VOLUMES
The Company recognizes revenue on its crude oil production when title transfers
to the customer and delivery has taken place. The related crude oil volumes by
segment, which have not been recognized in revenue, were as follows:
-----------------
SEP 30 Jun 30 Dec 31
(bbl) 2008 2008 2007
- -------------------------------------------------------------------------------------------------------------------
North America, related to pipeline fill 1,097,526 1,097,526 1,097,526
North Sea, related to timing of liftings 628,642 802,576 1,032,723
Offshore West Africa, related to timing of liftings 862,183 377,741 8,578
- -------------------------------------------------------------------------------------------------------------------
2,588,351 2,277,843 2,138,827
===================================================================================================================
In the third quarter of 2008, an additional 311,000 barrels of crude oil
produced in the Company's international operations was not lifted and was
therefore included in inventory at September 30, 2008. Notwithstanding an
overall increase in inventory, consolidated cash flow from operations increased
by approximately $10 million, primarily due to fluctuations in prevailing crude
oil prices.
DAILY PRODUCTION, BEFORE ROYALTIES
Three Months Ended Nine Months Ended
---------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- ---------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 239,973 245,616 252,095 244,832 243,388
North Sea 42,760 45,830 52,013 46,041 57,020
Offshore West Africa 24,237 27,631 28,954 26,842 28,800
- ---------------------------------------------------------------------------------------------------------------------------
306,970 319,077 333,062 317,715 329,208
- ---------------------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,467 1,501 1,622 1,494 1,670
North Sea 9 10 10 10 13
Offshore West Africa 14 15 15 14 12
- ---------------------------------------------------------------------------------------------------------------------------
1,490 1,526 1,647 1,518 1,695
- ---------------------------------------------------------------------------------------------------------------------------
TOTAL BARRELS OF OIL EQUIVALENT (boe/d) 555,356 573,437 607,484 570,704 611,665
- ---------------------------------------------------------------------------------------------------------------------------
PRODUCT MIX
Light/medium crude oil and NGLs 21% 22% 22% 22% 23%
Pelican Lake crude oil 7% 6% 6% 7% 6%
Primary heavy crude oil 16% 16% 16% 16% 15%
Thermal heavy crude oil 11% 12% 11% 11% 10%
Natural gas 45% 44% 45% 44% 46%
===========================================================================================================================
22 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
DAILY PRODUCTION, NET OF ROYALTIES
Three Months Ended Nine Months Ended
-------------- ----------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- ---------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 202,419 202,264 213,680 207,072 208,370
North Sea 42,665 45,734 51,917 45,945 56,916
Offshore West Africa 19,050 24,136 26,158 22,216 26,311
- ---------------------------------------------------------------------------------------------------------------------------
264,134 272,134 291,755 275,233 291,597
- ---------------------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,217 1,227 1,373 1,234 1,395
North Sea 9 10 10 10 13
Offshore West Africa 11 13 14 12 11
- ---------------------------------------------------------------------------------------------------------------------------
1,237 1,250 1,397 1,256 1,419
- ---------------------------------------------------------------------------------------------------------------------------
TOTAL BARRELS OF OIL EQUIVALENT (boe/d) 470,268 480,418 524,417 484,593 527,982
===========================================================================================================================
Daily production and per bbl statistics are presented throughout this MD&A on a
"before royalty" or "gross" basis. Production on an "after royalty" or "net"
basis is also presented.
The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces; namely
natural gas, light/medium crude oil and NGLs, Pelican Lake crude oil, primary
heavy crude oil and thermal heavy crude oil.
Total production averaged 570,704 boe/d for the nine months ended September 30,
2008, a 7% decrease from 611,665 boe/d for the nine months ended September 30,
2007. Production for the third quarter of 2008 decreased 9% to average 555,356
boe/d, from 607,484 boe/d for the third quarter of 2007, and a 3% decrease from
573,437 boe/d for the prior quarter.
Total crude oil and NGLs production for the nine months ended September 30, 2008
decreased 3% to 317,715 bbl/d from 329,208 bbl/d for the nine months ended
September 30, 2007. Third quarter total crude oil and NGLs production decreased
8% to 306,970 bbl/d from 333,062 bbl/d for the third quarter of 2007, and
decreased 4% from 319,077 bbl/d for the prior quarter. The decrease from the
comparable periods was primarily due to lower production in the North Sea and
Offshore West Africa due to the timing of field turnarounds and the cyclic
nature of the Company's thermal production. Crude oil and NGLs production in the
third quarter of 2008 was near the midpoint of the Company's previously issued
guidance of 299,000 to 316,000 bbl/d.
Natural gas production continued to represent the Company's largest product
offering, accounting for 45% of the Company's total production in the third
quarter of 2008. Natural gas production for the nine months ended September 30,
2008 averaged 1,518 mmcf/d compared to 1,695 mmcf/d for the nine months ended
September 30, 2007. Third quarter natural gas production averaged 1,490 mmcf/d
compared to 1,647 mmcf/d for the third quarter of 2007 and 1,526 mmcf/d for the
prior quarter. The decrease in natural gas production from the comparable
periods primarily reflected production declines due to the Company's strategic
reduction in natural gas drilling activity. Third quarter natural gas production
was at the high end of the Company's previously issued guidance of 1,466 to
1,490 mmcf/d.
For 2008, annual production guidance is targeted to average between 313,000 and
318,000 bbl/d of crude oil and NGLs and between 1,492 and 1,506 mmcf/d of
natural gas. Fourth quarter 2008 production guidance is targeted to average
between 300,000 and 316,000 bbl/d of crude oil and NGLs and between 1,430 and
1,455 mmcf/d of natural gas.
CANADIAN NATURAL RESOURCES LIMITED 23
===============================================================================
NORTH AMERICA
North America crude oil and NGLs production for the nine months ended September
30, 2008 increased 1% to average 244,832 bbl/d from 243,388 bbl/d for the nine
months ended September 30, 2007. Third quarter North America crude oil and NGLs
production decreased 5% to average 239,973 bbl/d from 252,095 bbl/d for the
third quarter of 2007, and decreased 2% from 245,616 bbl/d for the prior
quarter. The fluctuations in crude oil and NGLs production from the prior
periods was primarily due to the cyclic nature of the Company's thermal
production.
For the nine months ended September 30, 2008, natural gas production decreased
11% to 1,494 mmcf/d from 1,670 mmcf/d for the nine months ended September 30,
2007. For the third quarter of 2008, natural gas production decreased 10% to
1,467 mmcf/d from 1,622 mmcf/d for the third quarter of 2007, and decreased 2%
from 1,501 mmcf/d for the prior quarter. The decrease in natural gas production
from the prior periods reflected production declines due to the Company's
strategic decision to reduce natural gas drilling activity to focus on higher
return crude oil projects.
NORTH SEA
North Sea crude oil production for the nine months ended September 30, 2008
decreased 19% to 46,041 bbl/d from 57,020 bbl/d for the nine months ended
September 30, 2007. Third quarter North Sea crude oil production decreased 18%
to 42,760 bbl/d from 52,013 bbl/d for the third quarter of 2007 and by 7% from
45,830 bbl/d for the prior quarter. Third quarter production was at the low end
of guidance with the decrease from the prior quarter due to the extended
duration of the Murchison shutdown. Three planned maintenance shutdowns were
successfully completed during the third quarter of 2008 at the Murchison,
T-Block, and Banff Fields. Two platforms at the Ninian Field will be shutdown
for maintenance in the fourth quarter.
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production decreased 7% to 26,842 bbl/d for the
nine months ended September 30, 2008 from 28,800 bbl/d for the nine months ended
September 30, 2007. Third quarter Offshore West Africa crude oil production
decreased 16% to 24,237 bbl/d from 28,954 bbl/d for the third quarter of 2007,
and by 12% from 27,631 bbl/d for the prior quarter. During the third quarter, a
shutdown was taken at the Baobab Field for maintenance and to tie in the first
new well delivered from the redrilling program. This well was onstream at
quarter end and additional production is anticipated to be delivered in the
fourth quarter. A well intervention program at Espoir had restored one shut-in
production well during the quarter, with a second in progress at quarter end.
24 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
ROYALTIES
Three Months Ended Nine Months Ended
---------------- ----------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- ---------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 15.76 $ 17.46 $ 8.00 $ 14.26 $ 7.02
North Sea $ 0.24 $ 0.27 $ 0.14 $ 0.23 $ 0.13
Offshore West Africa $ 26.90 $ 14.49 $ 6.81 $ 18.89 $ 5.90
Company average $ 14.17 $ 14.82 $ 6.65 $ 12.49 $ 5.69
NATURAL GAS ($/mcf) (1)
North America $ 1.55 $ 1.88 $ 0.90 $ 1.60 $ 1.17
Offshore West Africa $ 2.24 $ 1.13 $ 0.51 $ 1.59 $ 0.50
Company average $ 1.55 $ 1.86 $ 0.89 $ 1.59 $ 1.16
COMPANY AVERAGE ($/boe) (1) $ 12.06 $ 13.26 $ 6.07 $ 11.22 $ 6.27
PERCENTAGE OF REVENUE (2)
Crude oil and NGLs 14% 14% 11% 13% 10%
Natural gas 18% 19% 15% 18% 16%
Boe 15% 16% 13% 15% 13%
===========================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
NORTH AMERICA
North America crude oil and NGLs royalties per bbl for the nine months ended
September 30, 2008 continue to reflect strong realized crude oil prices. Crude
oil and NGLs royalties averaged approximately 16% of revenues for the third
quarter of 2008, compared to 15% for the third quarter in 2007 and 18% in the
prior quarter. Crude oil and NGLs royalties per bbl are anticipated to average
16% to 18% of gross revenue for 2008.
Natural gas royalties per mcf generally fluctuate with natural gas prices.
Natural gas royalties averaged approximately 18% of revenues for the third
quarter of 2008 compared to 15% for the third quarter of 2007 and 19% for the
prior quarter. Natural gas royalties are anticipated to average 17% to 20% of
gross revenue for 2008.
NORTH SEA
North Sea government royalties on crude oil were eliminated effective January 1,
2003. The remaining royalty is a gross overriding royalty on the Ninian Field.
CANADIAN NATURAL RESOURCES LIMITED 25
===============================================================================
OFFSHORE WEST AFRICA
Offshore West Africa production is governed by the terms of the various
Production Sharing Contracts ("PSCs"). Under the PSCs, revenues are divided into
cost recovery oil and profit oil. Cost recovery oil allows the Company to
recover its capital and production costs and the costs carried by the Company on
behalf of the Government State Oil Company. Profit oil is allocated to the joint
venture partners in accordance with their respective equity interests, after a
portion has been allocated to the Government. The Government's share of profit
oil attributable to the Company's equity interest is allocated between royalty
expense and current income tax expense in accordance with the PSCs. The
Company's capital investments in the Espoir Fields were fully recovered in the
first quarter of 2007, increasing royalty rates and current income taxes in
accordance with the terms of the PSCs.
Royalty rates as a percentage of revenue averaged approximately 21% for the
third quarter of 2008 compared to 10% for the third quarter of 2007 and 13% for
the prior quarter. Royalty expense in the third quarter reflected a higher
proportion of Espoir sales in the period, which have higher royalty rates. This
increase was compounded by the impact of the reduction in the Cote d'Ivoire
corporate income tax rate enacted in the first quarter of 2008, which increased
the allocation of the Government's share of profit oil to royalties. Offshore
West Africa royalty rates are anticipated to average 14% to 17% of gross revenue
for 2008.
PRODUCTION EXPENSE
Three Months Ended Nine Months Ended
---------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- ---------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 16.23 $ 15.44 $ 11.69 $ 15.17 $ 12.87
North Sea $ 29.21 $ 25.61 $ 23.61 $ 25.52 $ 21.23
Offshore West Africa $ 7.74 $ 9.79 $ 7.00 $ 8.60 $ 7.90
Company average $ 17.61 $ 16.39 $ 13.13 $ 16.24 $ 13.97
NATURAL GAS ($/mcf) (1)
North America $ 1.03 $ 0.93 $ 0.87 $ 0.99 $ 0.90
North Sea $ 3.09 $ 2.68 $ 2.29 $ 2.68 $ 2.39
Offshore West Africa $ 1.58 $ 1.27 $ 1.39 $ 1.36 $ 1.32
Company average $ 1.05 $ 0.94 $ 0.88 $ 1.01 $ 0.91
COMPANY AVERAGE ($/boe) (1) $ 12.52 $ 11.60 $ 9.62 $ 11.70 $ 10.05
===========================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
NORTH AMERICA
North America crude oil and NGLs production expense for the nine months ended
September 30, 2008 increased 18% to $15.17 per bbl from $12.87 per bbl for the
nine months ended September 30, 2007. Third quarter North America crude oil and
NGLs production expense increased 39% to $16.23 per bbl from $11.69 per bbl for
the third quarter of 2007 and increased 5% from $15.44 per bbl for the prior
quarter. The increase in production expense per bbl from the comparable periods
was primarily a result of the higher cost of natural gas for fuel for the
Company's thermal operations and increased property tax and power costs. The
increase in the third quarter of 2008 was also a result of the timing of steam
cycles at thermal properties and the impact of lower production volumes on the
fixed cost portion of production costs.
North America natural gas production expense for the nine months ended September
30, 2008 increased 10% to $0.99 per mcf from $0.90 per mcf for the nine months
ended September 30, 2007. Third quarter North America natural gas production
expense increased 18% to $1.03 per mcf from $0.87 per mcf for the third quarter
of 2007 and increased 11% from $0.93 per mcf for the prior quarter. The increase
in production expense per mcf from the comparable periods in 2007 was primarily
26 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
a result of lower production volumes on the fixed cost portion of production
costs. The increase from the prior quarter was a result of higher repair and
maintenance activity during the third quarter of 2008, together with the impact
of lower production volumes.
NORTH SEA
North Sea crude oil production expense increased on a per bbl basis from the
comparable periods in 2007 and the prior quarter due to lower production volumes
on a relatively fixed operating cost base as well as higher planned maintenance
costs.
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production expense decreased on a per bbl basis
from the prior quarter primarily due to the impact of the timing of liftings at
the Baobab and Espoir Fields, resulting in a greater proportion of relatively
lower fixed cost Espoir sales in the quarter. The increase over the comparable
periods in 2007 was largely due to lower production volumes on a relatively
fixed operating cost base.
MIDSTREAM
Three Months Ended Nine Months Ended
---------------- ----------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions) 2008 2008 2007 2008 2007
- -----------------------------------------------------------------------------------------------------------------------------
Revenue $ 20 $ 20 $ 19 $ 60 $ 55
Production expense 6 8 5 19 16
- -----------------------------------------------------------------------------------------------------------------------------
Midstream cash flow 14 12 14 41 39
Depreciation 2 2 2 6 6
- -----------------------------------------------------------------------------------------------------------------------------
Segment earnings before taxes $ 12 $ 10 $ 12 $ 35 $ 33
=============================================================================================================================
The Company's midstream assets consist of three crude oil pipeline systems and a
50% working interest in an 84-megawatt cogeneration plant at Primrose.
Approximately 80% of the Company's heavy crude oil production is transported to
international mainline liquid pipelines via the 100% owned and operated ECHO
Pipeline, the 62% owned and operated Pelican Lake Pipeline and the 15% owned
Cold Lake Pipeline. The midstream pipeline assets allow the Company to control
the transport of its own production volumes as well as earn third party revenue.
This transportation control enhances the Company's ability to manage the full
range of costs associated with the development and marketing of its heavier
crude oil.
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
Three Months Ended Nine Months Ended
---------------- ----------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- ------------------------------------------------------------------------------------------------------------------------------
Expense ($ millions) $ 657 $ 668 $ 713 $ 2,011 $ 2,138
$/boe (2) $ 12.93 $ 12.88 $ 12.68 $ 12.89 $ 12.79
==============================================================================================================================
(1) DD&A EXCLUDES DEPRECIATION ON MIDSTREAM ASSETS.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Depletion, Depreciation and Amortization ("DD&A") for the nine months ended
September 30, 2008 and the third quarter decreased in total from the comparable
periods in 2007 and the prior quarter, primarily due to the impact of lower
sales volumes.
CANADIAN NATURAL RESOURCES LIMITED 27
===============================================================================
ASSET RETIREMENT OBLIGATION ACCRETION
Three Months Ended Nine Months Ended
---------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------------
Expense ($ millions) $ 18 $ 17 $ 18 $ 52 $ 53
$/boe (1) $ 0.35 $ 0.33 $ 0.32 $ 0.33 $ 0.32
==========================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Asset retirement obligation accretion expense represents the increase in the
carrying amount of the asset retirement obligation due to the passage of time.
Accretion expense for the nine months ended September 30, 2008 and the third
quarter was consistent with the comparable periods.
ADMINISTRATION EXPENSE
Three Months Ended Nine Months Ended
---------------- ----------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- ----------------------------------------------------------------------------------------------------------------------------
Expense ($ millions) $ 46 $ 45 $ 53 $ 134 $ 166
$/boe (1) $ 0.91 $ 0.87 $ 0.94 $ 0.86 $ 0.99
============================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Administration expense for the nine months ended September 30, 2008 and the
third quarter decreased in total from the comparable periods in 2007 primarily
due to decreased staffing costs, including costs related to the Company's share
bonus program, as well as decreased office lease costs.
STOCK-BASED COMPENSATION (RECOVERY) EXPENSE
Three Months Ended Nine Months Ended
---------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions) 2008 2008 2007 2008 2007
- ----------------------------------------------------------------------------------------------------------------------------
(Recovery) expense $ (308) $ 459 $ 78 $ 151 $ 209
============================================================================================================================
The Company's Stock Option Plan (the "Option Plan") provides current employees
(the "option holders") with the right to elect to receive common shares or a
direct cash payment in exchange for options surrendered. The design of the
Option Plan balances the need for a long-term compensation program to retain
employees with the benefits of reducing the impact of dilution on current
Shareholders and the reporting of the obligations associated with stock options.
Transparency of the cost of the Option Plan is increased as changes in the
intrinsic value of outstanding stock options are recognized each period. The
cash payment feature provides option holders with substantially the same
benefits and allows them to realize the value of their options through a
simplified administration process.
The Company recorded a $151 million ($107 million after-tax) stock-based
compensation expense for the nine months ended September 30, 2008 as a result of
normal course graded vesting of options granted in prior periods and the impact
of vested options exercised or surrendered during the period, and a $308 million
($221 million after-tax) stock-based compensation recovery primarily due to a
28% decrease in the Company's share price for the three months ended September
30, 2008 (Company's share price as at: September 30, 2008 - C$73.00; June 30,
2008 - C$100.84; December 31, 2007 - C$72.58; September 30, 2007 - C$75.56). As
required by GAAP, the Company records a liability for potential cash payments to
settle its outstanding employee stock options each reporting period based on the
difference between the exercise price of the stock options and the market price
of the Company's common shares, pursuant to a graded vesting schedule. The
liability is revalued quarterly to reflect changes in the market price of the
Company's common shares and the options exercised or surrendered in the period,
with the net change recognized in net earnings, or capitalized during the
construction period in the case of the Horizon Project. For the nine months
ended September 30, 2008, the Company capitalized $33 million in stock-based
compensation on the Horizon Project (September 30, 2007 - $63 million). The
stock-based compensation liability reflected the Company's potential cash
28 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
liability should all the vested options be surrendered for a cash payout at the
market price on September 30, 2008. In periods when substantial stock price
changes occur, the Company's earnings are subject to significant volatility. The
Company utilizes its stock-based compensation plan to attract and retain
employees in a competitive environment. All employees participate in this plan.
For the nine months ended September 30, 2008, the Company paid $202 million for
stock options surrendered for cash settlement (September 30, 2007 - $321
million).
INTEREST EXPENSE
Three Months Ended Nine Months Ended
-------------- --------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions, except per boe amounts) 2008 2008 2007 2008 2007
- ----------------------------------------------------------------------------------------------------------------------------
Expense, gross $ 150 $ 141 $ 160 $ 451 $ 472
Less: capitalized interest, Horizon Project 125 110 95 346 247
- ----------------------------------------------------------------------------------------------------------------------------
Expense, net $ 25 $ 31 $ 65 $ 105 $ 225
$/boe (1) $ 0.49 $ 0.60 $ 1.15 $ 0.67 $ 1.34
Average effective interest rate 5.0% 4.8% 5.7% 5.2% 5.4%
============================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Gross interest expense and the Company's average effective interest rate
decreased in the nine months ended September 30, 2008 from the comparable
periods in 2007 primarily due to decreased short term borrowing rates and the
impact of the stronger Canadian dollar.
On commencement of operations of Phase 1 of the Horizon Project, interest
capitalization will cease on this Phase, increasing interest expense
accordingly.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its
commodity price, currency and interest rate exposures. The Company's risk
management program is not used for speculative purposes.
Three Months Ended Nine Months Ended
--------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions) 2008 2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs financial instruments $ 792 $ 944 $ 102 $ 2,199 $ 197
Natural gas financial instruments 16 10 (125) (21) (216)
Foreign currency swaps (17) - - (17) -
- --------------------------------------------------------------------------------------------------------------------------
Realized loss (gain) $ 791 $ 954 $ (23) $ 2,161 $ (19)
- --------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs financial instruments $ (2,423) $ 1,380 $ 80 $ (992) $ 474
Natural gas financial instruments (68) 38 (4) 29 81
Foreign currency swaps (15) (3) - (20) -
- --------------------------------------------------------------------------------------------------------------------------
Unrealized (gain) loss $ (2,506) $ 1,415 $ 76 $ (983) $ 555
- --------------------------------------------------------------------------------------------------------------------------
Net (gain) loss $ (1,715) $ 2,369 $ 53 $ 1,178 $ 536
==========================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 29
===============================================================================
The net realized loss (gain) from crude oil and natural gas financial
instruments would have decreased (increased) the Company's average realized
prices as follows:
Three Months Ended Nine Months Ended
---------------- ----------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
2008 2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) $ 28.37 $ 32.84 $ 3.30 $ 25.39 $ 2.19
Natural gas ($/mcf) (1) $ 0.11 $ 0.07 $ (0.83) $ (0.05) $ (0.47)
==========================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
Complete details related to outstanding derivative financial instruments at
September 30, 2008 are disclosed in note 10 to the Company's unaudited interim
consolidated financial statements.
The commodity derivative financial instruments currently outstanding have not
been designated as hedges for accounting purposes (the "non-designated hedges").
The fair value of these non-designated hedges is based on prevailing forward
commodity prices in effect at the end of each reporting period and is reflected
in risk management activities in consolidated net earnings. The cash settlement
amount of the risk management derivative financial instruments may vary
materially depending upon the underlying crude oil and natural gas prices at the
time of final settlement of the derivative financial instruments, as compared to
their mark-to-market value at September 30, 2008.
Due to changes in crude oil and natural gas forward pricing and the reversal of
prior period unrealized gains and losses, the Company recorded a net unrealized
gain of $983 million ($677 million after-tax) on its risk management activities
for the nine months ended September 30, 2008, including a $2,506 million ($1,750
million after-tax) net unrealized gain for the third quarter of 2008 (June 30,
2008 - unrealized loss of $1,415 million, $997 million after-tax; September 30,
2007 - unrealized loss of $76 million, $57 million after-tax).
FOREIGN EXCHANGE
Three Months Ended Nine Months Ended
--------------- ----------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions) 2008 2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------------
Net realized (gain) loss $ (40) $ (11) $ 22 $ (63) $ 53
Net unrealized loss (gain) (1) 113 (20) (195) 219 (477)
- --------------------------------------------------------------------------------------------------------------------------
Net loss (gain) $ 73 $ (31) $ (173) $ 156 $ (424)
==========================================================================================================================
(1) AMOUNTS ARE REPORTED NET OF THE HEDGING EFFECT OF CROSS CURRENCY SWAPS AS
DESCRIBED IN RISK MANAGEMENT ACTIVITIES.
The Company's operating results are affected by fluctuations in the exchange
rates between the Canadian dollar, US dollar, and UK pound sterling. A majority
of the Company's revenue is based on reference to US dollar benchmark prices. An
increase in the value of the Canadian dollar in relation to the US dollar
results in decreased revenue from the sale of the Company's production.
Conversely, a decrease in the value of the Canadian dollar in relation to the US
dollar results in increased revenue from the sale of the Company's production.
Production expenses in the North Sea are subject to foreign currency
fluctuations due to changes in the exchange rate of the UK pound sterling to the
US dollar, while production expenses in Offshore West Africa are subject to
foreign currency fluctuations due to changes in the exchange rate of the
Canadian dollar to the US dollar. The value of the Company's US dollar
denominated debt is also impacted by the value of the Canadian dollar in
relation to the US dollar.
The net unrealized foreign exchange loss for the nine months ended September 30,
2008 was primarily related to the weakening of the Canadian dollar in relation
to the US dollar with respect to the US dollar debt, offset by the impact of the
re-measurement of North Sea future income tax liabilities denominated in UK
pounds sterling to US dollars. Included in the net unrealized loss for the nine
months ended September 30, 2008 was an unrealized gain of $136 million (nine
months ended September 30, 2007 - unrealized loss of $335 million) related to
the impact of the cross currency swaps. The net realized foreign exchange gain
for the nine months ended September 30, 2008 was primarily due to the result of
foreign exchange rate fluctuations on settlement of working capital items
denominated in US dollars or UK pounds sterling and the repayment of US dollar
denominated debt. The Canadian dollar ended the third quarter at US$0.9435
compared to US$0.9817 at June 30, 2008 (December 31, 2007 - US$1.0120, September
30, 2007 - US$1.0037.
30 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
TAXES
Three Months Ended Nine Months Ended
--------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions, except income tax rates) 2008 2008 2007 2008 2007
- ----------------------------------------------------------------------------------------------------------------------------
Current $ 52 $ 96 $ 30 $ 218 $ 105
Deferred (7) (34) 10 (62) 27
- ----------------------------------------------------------------------------------------------------------------------------
Taxes other than income tax $ 45 $ 62 $ 40 $ 156 $ 132
- ----------------------------------------------------------------------------------------------------------------------------
North America $ 6 $ 6 $ 28 $ 33 $ 65
North Sea 121 111 56 328 145
Offshore West Africa 44 34 21 116 47
- ----------------------------------------------------------------------------------------------------------------------------
Current income tax 171 151 105 477 257
Future income tax 1,011 (301) 175 790 391
- ----------------------------------------------------------------------------------------------------------------------------
1,182 (150) 280 1,267 648
Income tax rate and other legislative
changes (1) (2) - - - 41 71
- ----------------------------------------------------------------------------------------------------------------------------
$ 1,182 $ (150) $ 280 $ 1,308 $ 719
- ----------------------------------------------------------------------------------------------------------------------------
Effective income tax rate before
non-recurring benefits 29.4% 30.2% 28.6% 29.2% 29.3%
============================================================================================================================
(1) INCLUDES THE EFFECT OF A ONE TIME RECOVERY OF $19 MILLION DUE TO BRITISH
COLUMBIA CORPORATE INCOME TAX RATE REDUCTIONS AND $22 MILLION DUE TO COTE
D'IVOIRE CORPORATE INCOME TAX RATE REDUCTIONS ENACTED OR SUBSTANTIVELY
ENACTED DURING THE FIRST QUARTER OF 2008.
(2) INCLUDES THE EFFECT OF A ONE TIME RECOVERY OF $71 MILLION DUE TO CANADIAN
FEDERAL INCOME TAX RATE REDUCTIONS ENACTED DURING THE SECOND QUARTER OF
2007.
Taxes other than income tax primarily includes current and deferred petroleum
revenue tax ("PRT"). PRT is charged on certain fields in the North Sea at the
rate of 50% of net operating income, after allowing for certain deductions
including related capital and abandonment expenditures.
Taxable income from the conventional crude oil and natural gas business in
Canada is primarily generated through partnerships, with the related income
taxes payable in a future period. North America current income taxes have been
provided on the basis of the corporate structure and available income tax
deductions and will vary depending upon the nature, timing and amount of capital
expenditures incurred in Canada in any particular year.
CANADIAN NATURAL RESOURCES LIMITED 31
===============================================================================
CAPITAL EXPENDITURES (1)
Three Months Ended Nine Months Ended
--------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($ millions) 2008 2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------------------
EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT
Net property acquisitions $ 47 $ 263 $ 7 $ 302 $ 68
Land acquisition and retention 32 24 29 68 80
Seismic evaluations 40 18 23 85 107
Well drilling, completion and equipping 421 286 299 1,159 1,301
Production and related facilities 311 270 238 900 815
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL NET RESERVE REPLACEMENT EXPENDITURES 851 861 596 2,514 2,371
- --------------------------------------------------------------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 635 875 671 2,175 2,049
Phase 1 operating and capital inventory 27 14 - 82 -
Phase 1 commissioning costs 84 34 - 167 -
Phases 2/3 costs 83 82 28 242 91
Capitalized interest, stock-based
compensation and other 46 247 120 402 329
- --------------------------------------------------------------------------------------------------------------------------------
Total Horizon Project 875 1,252 819 3,068 2,469
- --------------------------------------------------------------------------------------------------------------------------------
Midstream 2 3 2 6 4
Abandonments (2) 10 7 22 23 55
Head office 6 4 3 13 12
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES $ 1,744 $ 2,127 $ 1,442 $ 5,624 $ 4,911
================================================================================================================================
BY SEGMENT
North America $ 578 $ 617 $ 441 $ 1,858 $ 1,858
North Sea 78 79 121 202 395
Offshore West Africa 195 164 34 453 116
Other - 1 - 1 2
Horizon Project 875 1,252 819 3,068 2,469
Midstream 2 3 2 6 4
Abandonments (2) 10 7 22 23 55
Head office 6 4 3 13 12
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL $ 1,744 $ 2,127 $ 1,442 $ 5,624 $ 4,911
================================================================================================================================
(1) THE NET CAPITAL EXPENDITURES EXCLUDE ADJUSTMENTS RELATED TO DIFFERENCES
BETWEEN CARRYING VALUE AND TAX VALUE, AND OTHER FAIR VALUE ADJUSTMENTS.
(2) ABANDONMENTS REPRESENT EXPENDITURES TO SETTLE ASSET RETIREMENT OBLIGATIONS
AND HAVE BEEN REFLECTED AS CAPITAL EXPENDITURES IN THIS TABLE.
32 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
The Company's strategy is focused on building a diversified asset base that is
balanced among various products. In order to facilitate efficient operations,
the Company concentrates its activities in core regions where it can dominate
the land base and infrastructure. The Company focuses on maintaining its land
inventories to enable the continuous exploitation of play types and geological
trends, greatly reducing overall exploration risk. By dominating infrastructure,
the Company is able to maximize utilization of its production facilities,
thereby increasing control over production costs.
Net capital expenditures for the nine months ended September 30, 2008 were
$5,624 million compared to $4,911 million for the nine months ended September
30, 2007. Net capital expenditures for the third quarter of 2008 were $1,744
million compared to $1,442 million for the third quarter of 2007 and $2,127
million for the prior quarter. The capital expenditures primarily reflected the
continued progress on the Company's larger, future growth projects, most notably
the Horizon Project, Primrose East, and Gabon, offset by the effects of an
overall strategic reduction in the North America natural gas drilling program.
For the nine months ended September 30, 2008, the Company drilled a total of 790
net wells consisting of 228 natural gas wells, 500 crude oil wells, 34
stratigraphic test and service wells and 28 wells that were dry. This compared
to 1,051 net wells drilled for the nine months ended September 30, 2007. The
Company achieved an overall success rate of 96% for the nine months ended
September 30, 2008, excluding stratigraphic test and service wells, compared to
90% for the nine months ended September 30, 2007.
For the third quarter of 2008, the Company drilled a total of 315 net wells
consisting of 62 natural gas wells, 234 crude oil wells, 8 stratigraphic test
and service wells and 11 wells that were dry. This compared to 268 net wells
drilled for the third quarter of 2007 and 115 net wells for the prior quarter.
The Company achieved an overall success rate of 96% for the third quarter of
2008, excluding stratigraphic test and service wells, compared to 95% for the
third quarter of 2007 and 94% for the prior quarter.
NORTH AMERICA
North America, excluding the Horizon Project, accounted for approximately 34% of
the total capital expenditures for the nine months ended September 30, 2008
compared to 39% for the nine months ended September 30, 2007.
During the nine months ended September 30, 2008, the Company targeted 237 net
natural gas wells, including 24 wells in Northeast British Columbia, 86 wells in
the Northern Plains region, 58 wells in Northwest Alberta, and 69 wells in the
Southern Plains region. The Company also targeted 514 net crude oil wells during
the same period. The majority of these wells were concentrated in the Company's
crude oil Northern Plains region where 288 heavy crude oil wells, 92 Pelican
Lake crude oil wells, 52 thermal crude oil wells and 6 light crude oil wells
were targeted. Another 76 wells targeting light crude oil were drilled outside
the Northern Plains region.
Due to significant differences in relative commodity prices between crude oil
and natural gas during the nine months ended September 30, 2008, the Company
continued to access its large crude oil drilling inventory to maximize value in
both the short and long term. Due to the Company's focus on drilling crude oil
wells in 2007 and 2008, natural gas drilling activities have been reduced to
manage overall capital spending. Deferred natural gas well locations have been
retained in the Company's prospect inventory.
As part of the phased expansion of its In-Situ Oil Sands Assets, the Company is
continuing to develop its Primrose thermal projects. Overall Primrose thermal
production averaged approximately 61,000 bbl/d for the third quarter of 2008
compared to 60,000 bbl/d for the third quarter of 2007 and approximately 67,000
bbl/d for the prior quarter.
The Primrose East Expansion, a new facility located 15 kilometers from the
existing Primrose South steam plant and 25 kilometers from the Wolf Lake central
processing facility, is anticipated to add approximately 40,000 bbl/d of
production capacity when complete. Drilling and construction of facilities is
complete. First steaming commenced in September 2008 and first production was
achieved in the fourth quarter of 2008.
The next planned phase of the Company's In-Situ Oil Sands Assets expansion is
the Kirby project located 120 kilometers north of the existing Primrose
facilities. The Kirby project is anticipated to add approximately 45,000 bbl/d
of production capacity. During 2007, the Company filed a combined application
and Environmental Impact Assessment for this project with Alberta Environment
and the Alberta Energy and Utilities Board. Final corporate sanction and project
scope will be impacted by environmental regulations and their associated costs.
Development of new pads and secondary recovery conversion projects at Pelican
Lake continued as expected throughout the third quarter of 2008. Drilling
consisted of 35 horizontal wells in the third quarter. The response from the
CANADIAN NATURAL RESOURCES LIMITED 33
===============================================================================
water and polymer flood projects continues to be positive. Pelican Lake
production averaged approximately 37,000 bbl/d for the second and third quarter
of 2008 compared to approximately 35,000 bbl/d for the third quarter of 2007.
For the fourth quarter of 2008, the Company's overall planned drilling activity
in North America is expected to be comprised of 31 natural gas wells and 222
crude oil wells, excluding stratigraphic and service wells.
HORIZON PROJECT
First production of synthetic crude oil is currently targeted to commence late
in the fourth quarter of 2008. A high level overview of progress by major plant
facility at the Horizon Project is as follows:
o MINING - Completed, ready for oil sands mining operation, continues to move
overburden;
o ORE PREPARATION PLANT - Completed, ready for operation;
o HYDROTRANSPORT - Completed, ready for operation;
o PIPERACK - Completed, live and operational;
o EXTRACTION - Completed, ready for operation;
o FROTH TREATMENT - Completed, in commissioning and testing;
o DELAYED COKER / DILUENT RECOVERY UNIT - Completed, circulating diesel and
ready for operation;
o CO-GENERATION - Completed, producing steam and power;
o SULPHUR PLANT - Completed, turned over to operations for commissioning and
testing;
o TANKAGE - Completed, ready for operation;
o MAIN CONTROL ROOM - Completed, live and operational;
o UTILITIES & SERVICES - Completed, live and operational;
o SCO PIPELINE (THIRD PARTY OWNED AND OPERATED) - Completed, ready for
operation;
o HYDROGEN PLANT - Completed, turned over to operations for commissioning and
testing; and
o HYDROTREATERS - Plant 41 has been completed and turned over to operations
for commissioning and testing. Plant 43 is completing electrical heat
tracing and insulation while starting commissioning. Plant 42 is
mechanically complete with electrical heat tracing and insulation to be
completed before turning over to operations for commissioning and testing.
Construction delays and an extended commissioning schedule have lead to an
increase of $441 million to the project forecast construction costs. This
results in the revised total construction cost estimate for Phase 1 of the
Horizon Project to be approximately $9.7 billion.
NORTH SEA
In the third quarter of 2008, the Company continued with its planned program of
infill drilling, recompletions, workovers and waterflood optimizations. At the
end of the quarter 0.9 net wells were in progress.
The Company also continued with its strategy of long term investment in the
facilities and infrastructure at the Ninian and Murchison fields, completing a
turnaround at Murchison which included the successful implementation of a new
control system. During the third quarter turnarounds were also completed at the
T-Block and Banff fields within planned timeframes.
OFFSHORE WEST AFRICA
During the third quarter of 2008, 1.5 net wells were drilled, including 0.9 net
stratigraphic wells, with an additional 0.6 net wells drilling at the end of the
quarter.
At Espoir a workover was successfully completed restoring production to
a shut-in well. Another workover was in progress at the end of the quarter. The
first well in the current year Baobab drilling program was completed in the
quarter and brought on production. At the 90% owned and operated Olowi Field in
offshore Gabon the substructure was put in place in readiness for installation
of the Conductor Supported Platform, which was installed in early November, and
construction continued on the wellhead towers, subsea facilities and the
floating production storage and offtake vessel ("FPSO"). Drilling commenced
early in the second quarter of 2008 and continued in the third quarter with
first crude oil now targeted for the first quarter of 2009 due to delays in the
completion of the construction of the FPSO. Olowi production is targeted to
plateau at approximately 20,000 bbl/d net to the Company.
34 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CAPITAL BUDGET AND PRODUCTION GUIDANCE FOR 2009
The Company has completed its capital and operating budget planning for the 2009
fiscal year and will continue to implement its strategy of maintaining a large
portfolio of varied projects, which it believes will enable it, over an extended
period of time, to provide consistent growth in production and create
shareholder value. In response to the current economic climate, the Company's
total forecasted capital spending for 2009 has been reduced to approximately
$4.0 billion. Annual production for 2009 is forecasted to average between
386,000 and 426,000 bbl/d of crude oil and NGLs and between 1,285 and 1,350
mmcf/d of natural gas. As necessary, the 2009 budget is subject to revision
throughout the upcoming year in the context of targeted financial ratios,
project returns, product pricing expectations and balance in project risk and
time horizons.
LIQUIDITY AND CAPITAL RESOURCES
-------------------
SEP 30 Jun 30 Dec 31 Sep 30
($ millions, except ratios) 2008 2008 2007 2007
- -------------------------------------------------------------------------------------------------------------------------
Working capital deficit (1) $ 1,103 $ 3,180 $ 1,382 $ 824
Long-term debt (2) $ 11,633 $ 11,040 $ 10,940 $ 10,686
Share capital $ 2,761 $ 2,754 $ 2,674 $ 2,663
Retained earnings 13,628 10,847 10,575 9,824
Accumulated other comprehensive income 116 6 72 85
- -------------------------------------------------------------------------------------------------------------------------
Shareholders' equity $ 16,505 $ 13,607 $ 13,321 $ 12,572
Debt to book capitalization (2) (3) 41% 45% 45% 46%
Debt to market capitalization (2) (4) 23% 17% 22% 21%
After tax return on average common
shareholders' equity (5) 29% 14% 22% 19%
After tax return on average capital
employed (2) (6) 16% 8% 12% 11%
=========================================================================================================================
(1) CALCULATED AS CURRENT ASSETS LESS CURRENT LIABILITIES.
(2) LONG-TERM DEBT IS STATED AT ITS CARRYING VALUE, NET OF FAIR VALUE
ADJUSTMENTS, ORIGINAL ISSUE DISCOUNTS AND TRANSACTION COSTS.
(3) CALCULATED AS LONG-TERM DEBT; DIVIDED BY THE BOOK VALUE OF COMMON
SHAREHOLDERS' EQUITY PLUS LONG-TERM DEBT.
(4) CALCULATED AS LONG-TERM DEBT; DIVIDED BY THE MARKET VALUE OF COMMON
SHAREHOLDERS' EQUITY PLUS LONG-TERM DEBT.
(5) CALCULATED AS NET EARNINGS FOR THE TWELVE MONTH TRAILING PERIOD; AS A
PERCENTAGE OF AVERAGE COMMON SHAREHOLDERS' EQUITY FOR THE PERIOD.
(6) CALCULATED AS NET EARNINGS PLUS AFTER-TAX INTEREST EXPENSE FOR THE TWELVE
MONTH TRAILING PERIOD; AS A PERCENTAGE OF AVERAGE CAPITAL EMPLOYED FOR THE
PERIOD. AVERAGE CAPITAL EMPLOYED IS THE AVERAGE SHAREHOLDERS' EQUITY AND
LONG-TERM DEBT FOR THE PERIOD, INCLUDING $9,725 MILLION IN AVERAGE CAPITAL
EMPLOYED RELATED TO THE HORIZON PROJECT (JUNE 30, 2008 - $8,781 MILLION;
DECEMBER 31, 2007 - $7,001 MILLION; SEPTEMBER 30, 2007 - $6,120 MILLION).
At September 30, 2008, the Company's capital resources consisted primarily of
cash flow from operations, available bank credit facilities and access to debt
capital markets. Cash flow from operations is dependent on factors discussed in
the "Risks and Uncertainties" section of the Company's December 31, 2007 annual
MD&A. The Company's ability to renew existing credit facilities and raise new
debt is also dependent upon these factors, as well as maintaining an investment
grade debt rating and the condition of capital and credit markets.
The current worldwide credit events has resulted in unprecedented disruptions in
the availability of credit on commercially acceptable terms. In light of these
credit challenges, the Company has undertaken a thorough review of its liquidity
sources as well as its exposure to counterparties and has concluded that its
capital resources are sufficient to meet ongoing short, medium and long-term
commitments. Specifically, the Company continues to believe that its internally
generated cash flow from operations supported by the implementation of its hedge
policy, the flexibility of its capital expenditure programs supported by its
multi-year financial plans, its existing credit facilities and its ability to
raise new debt on commercially acceptable terms, will provide sufficient
liquidity to sustain its operations in the short, medium and long-term and
support its growth strategy. Further, the Company believes that its
counterparties currently have the financial capacity to settle outstanding
obligations in the normal course of business.
CANADIAN NATURAL RESOURCES LIMITED 35
===============================================================================
On an ongoing basis, the Company continues to focus on the following areas:
o Monitoring cash flow from operations which is the primary source of funds;
o Reviewing bank credit facilities and public debt indentures to ensure they
are in compliance with applicable covenant packages;
o Monitoring credit markets, governments, world banks and the Company's bank
syndicates to identify associated risks and exposures;
o Maintaining an active commodity risk management program that manages
exposure to crude oil and natural gas price volatility. The Company
believes that this is an effective tool to manage short and medium term
changes in spot commodity prices. The Company also monitors its commodity
risk counterparties to ensure they are in position to settle obligations
within the contractually agreed terms of settlement;
o Monitoring exposure to individual customers, contractors, suppliers and
joint venture partners on a regular basis and when appropriate, ensuring
that parental guarantees or letters of credit are in place to minimize the
impact in the event of default; and
o Preparation of the Company's 2009 capital and operating budgets to provide
the required flexibility to deal with commodity price volatility,
commitments in respect of capital and operating expenditures, and
commitments to retire its non-revolving bank credit facility maturing in
October 2009. The Company manages the allocation of maintenance and growth
capital to ensure it is expended in a prudent and appropriate manner.
At the end of the third quarter of 2008, the Company had $2,373 million of
available credit under its bank credit facilities, which together with net cash
flow to be generated in 2009, is forecasted to be sufficient to repay the
October 2009 maturity of the $2,350 million non-revolving bank credit facility.
Further, the Company's current debt ratings are BBB (high) with a negative trend
by DBRS Limited, Baa2 with a stable outlook by Moody's Investors Service and BBB
with a stable outlook by Standard & Poor's. The Company does not have any direct
exposure to asset-backed commercial paper.
Further details related to the Company's long-term debt at September 30, 2008
are disclosed in note 3 to the Company's unaudited interim consolidated
financial statements.
At September 30, 2008, the Company's working capital deficit was $1,103 million
and included the current portion of the stock-based compensation liability of
$378 million and the current portion of the net mark-to-market liability for
risk management derivative financial instruments of $330 million. The settlement
of the stock-based compensation liability is dependent upon both the surrender
of vested stock options for cash settlement by employees and the value of the
Company's share price at the time of surrender. The cash settlement amount of
the risk management derivative financial instruments may vary materially
depending upon the underlying crude oil and natural gas prices at the time of
final settlement of the derivative financial instruments, as compared to their
mark-to-market value at September 30, 2008.
The financing of Phase 1 of the Horizon Project development was guided by the
competing principles of retaining as much direct ownership interest as possible
while maintaining a strong balance sheet. The Company believes it has the
necessary financial capacity to complete the Horizon Project, while at the same
time not compromising conventional crude oil and natural gas growth
opportunities.
Long-term debt was $11,633 million at September 30, 2008, resulting in a debt to
book capitalization ratio of 41% (June 30, 2008 - 45%; December 31, 2007 - 45%;
September 30, 2007 - 46%). As expected, this ratio is now near the midpoint of
the 35% to 45% range targeted by management primarily due to the net earnings
contribution for the year and the impact of the strengthening US dollar exchange
rate on the Company's US dollar denominated long-term debt. The Company remains
committed to maintaining a strong balance sheet and flexible capital structure.
While the Company believes that it has the balance sheet strength and
flexibility to complete the Horizon Project, as well as its other planned
capital expenditure programs, the Company has hedged a portion of its crude oil
and natural gas production for 2008 and 2009 at prices that protect investment
returns. In the future, the Company may also consider the divestiture of certain
non-strategic and non-core properties to gain additional balance sheet
flexibility.
The Company's commodity hedging program reduces the risk of volatility in
commodity prices and supports the Company's cash flow for its capital
expenditures throughout the Horizon Project construction period. This program
currently allows for the hedging of up to 75% of the production for the
remainder of 2008. For the purpose of this program, the purchase of put options
is in addition to the above parameters. In accordance with the policy,
approximately 49% of budgeted crude oil volumes are hedged using collars for the
remainder of 2008. In addition, 50,000 bbl/d of crude oil volumes are protected
by put options for the remainder of 2008 at a strike price of US$55.00 per bbl.
36 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
Commencing January 1, 2009, the Company's commodity hedging program has been
revised by its Board of Directors to allow for the hedging of up to 50% of the
near 12 months budgeted production and up to 25% of the following 13 to 24
months estimated production. The purchase of put options will continue to be in
addition to the above parameters. In 2009, approximately 6% of estimated crude
oil volumes are hedged using collars and 92,000 bbl/d of crude oil volumes are
protected by put options at a strike price of US$100.00 per bbl.
The Company has the following commodity related net financial derivatives
outstanding at September 30, 2008:
Remaining term Volume Weighted average price Index
- --------------------------------------------------------------------------------------------------------------------
CRUDE OIL
Crude oil price collars Oct 2008 - Dec 2008 20,000 bbl/d US$50.00 - US$65.53 Mayan Heavy
Oct 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$75.22 WTI
Oct 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.05 WTI
Oct 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.98 WTI
Oct 2008 - Dec 2008 25,000 bbl/d US$70.00 - US$112.63 WTI
Jan 2009 - Dec 2009 25,000 bbl/d US$70.00 - US$111.56 WTI
Crude oil puts Oct 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
Jan 2009 - Dec 2009 92,000 bbl/d US$100.00 WTI
====================================================================================================================
The Company's outstanding commodity financial derivatives are expected to be
settled monthly based on the applicable index pricing for the respective
contract month.
Subsequent to September 30, 2008, the Company entered into 4,000 bbl/d of
US$70.00 - US$90.00 WTI collars for the period April 2009 to June 2009. In
addition, the Company entered into 500,000 GJ/d of natural gas AECO collars with
a floor of C$6.00 and a ceiling ranging from C$8.50 to C$8.80 for the period
November 2008 to March 2009.
LONG-TERM DEBT
As at September 30, 2008, the Company had in place unsecured bank credit
facilities of $6,233 million, comprised of:
o a $125 million demand credit facility;
o a non-revolving syndicated credit facility of $2,350 million maturing
October 2009;
o a revolving syndicated credit facility of $2,230 million maturing June
2012;
o a revolving syndicated credit facility of $1,500 million maturing June
2012; and
o a 15 million pounds demand credit facility related to the Company's North
Sea operations.
The revolving syndicated credit facilities are extendible annually for one year
periods at the mutual agreement of the Company and the lenders. If the
facilities are not extended, the full amount of the outstanding principal would
be repayable on the maturity date.
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $367 million, including $300 million related to the Horizon Project,
were outstanding at September 30, 2008.
MEDIUM-TERM NOTES
The Company has $2,600 million remaining on its outstanding $3,000 million base
shelf prospectus filed in September 2007 that allows for the issue of
medium-term notes in Canada until October 2009. If issued, these securities will
bear interest as determined at the date of issuance.
SENIOR UNSECURED NOTES
During the second quarter of 2008, US$31 million of the senior unsecured notes
were repaid.
US DOLLAR DEBT SECURITIES
During the third quarter of 2008, US$8 million of US dollar debt securities were
repaid.
In January 2008, the Company issued US$1,200 million of unsecured notes under a
US base shelf prospectus, comprised of US$400 million of 5.15% unsecured notes
due February 2013, US$400 million of 5.90% unsecured notes due February 2018,
and US$400 million of 6.75% unsecured notes due February 2039. Proceeds from the
securities issued were used to repay bankers' acceptances under the Company's
bank credit facilities. After issuing these securities, the Company has US$1,800
CANADIAN NATURAL RESOURCES LIMITED 37
===============================================================================
million remaining on its outstanding US$3,000 million base shelf prospectus
filed in September 2007 that allows for the issue of US dollar debt securities
in the United States until October 2009. If issued, these securities will bear
interest as determined at the date of issuance.
SHARE CAPITAL
As at September 30, 2008, there were 540,857,000 common shares outstanding and
25,161,000 stock options outstanding. As at November 4, 2008, the Company had
540,885,000 common shares outstanding and 24,958,000 stock options outstanding.
In February 2008, the Company's Board of Directors approved an increase in the
annual dividend paid by the Company to $0.40 per common share for 2008. The
increase represents an 18% increase from 2007, recognizes the stability of the
Company's cash flow, and provides a return to Shareholders. This is the eighth
consecutive year in which the Company has paid dividends and the seventh
consecutive year of an increase in the distribution paid to its Shareholders.
The dividend policy undergoes a periodic review by the Board of Directors and is
subject to change.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations. These
commitments primarily relate to debt repayments; operating leases relating to
offshore FPSOs, drilling rigs and office space; firm commitments for gathering,
processing and transmission services; as well as expenditures relating to asset
retirement obligations. As at September 30, 2008, no entities were consolidated
under the Canadian Institute of Chartered Accountants Handbook Accounting
Guideline 15, "Consolidation of Variable Interest Entities". The following table
summarizes the Company's commitments as at September 30, 2008:
Remaining
($ millions) 2008 2009 2010 2011 2012 Thereafter
- -----------------------------------------------------------------------------------------------------------------------------
Product transportation and
pipeline $ 61 $ 181 $ 164 $ 135 $ 114 $ 1,101
Offshore equipment operating
lease (1) $ 51 $ 134 $ 121 $ 119 $ 96 $ 425
Offshore drilling (2) (3) $ 85 $ 218 $ 54 $ - $ - $ -
Asset retirement obligations (4) $ 10 $ 4 $ 5 $ 4 $ 4 $ 4,614
Long-term debt (5) $ - $ 2,379 $ 400 $ 424 $ 371 $ 6,683
Interest expense (6) $ 122 $ 589 $ 518 $ 496 $ 438 $ 5,569
Office lease $ 6 $ 26 $ 29 $ 22 $ 2 $ -
Other $ 50 $ 380 $ 260 $ 36 $ 30 $ 74
==============================================================================================================================
(1) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF OBLIGATIONS
RELATED TO FPSOS. DURING 2006, THE COMPANY ENTERED INTO AN AGREEMENT TO
LEASE AN ADDITIONAL FPSO COMMENCING IN 2009, IN CONNECTION WITH THE PLANNED
OFFSHORE DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. DURING THE INITIAL
TERM, THE TOTAL ANNUAL PAYMENTS FOR THE GABON FPSO ARE ESTIMATED TO BE
US$50 MILLION.
(2) DURING 2007, THE COMPANY ENTERED INTO A ONE-YEAR AGREEMENT FOR OFFSHORE
DRILLING SERVICES RELATED TO THE BAOBAB FIELD IN COTE D'IVOIRE, OFFSHORE
WEST AFRICA. THE AGREEMENT COMMENCED IN THE THIRD QUARTER OF 2008, ON
DELIVERY OF THE RIG. ESTIMATED TOTAL REMAINING PAYMENTS OF US$54 MILLION,
AFTER JOINT VENTURE RECOVERIES, HAVE BEEN INCLUDED IN THIS TABLE FOR THE
PERIOD 2008 - 2009.
(3) DURING 2007, THE COMPANY AWARDED CONTRACTS FOR A DRILLING RIG AND FOR THE
CONSTRUCTION OF WELLHEAD TOWERS IN CONNECTION WITH THE PLANNED OFFSHORE
DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. ESTIMATED TOTAL REMAINING
PAYMENTS OF US$279 MILLION HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD
2008 - 2010.
(4) AMOUNTS REPRESENT MANAGEMENT'S ESTIMATE OF THE FUTURE UNDISCOUNTED PAYMENTS
TO SETTLE ASSET RETIREMENT OBLIGATIONS RELATED TO RESOURCE PROPERTIES,
FACILITIES, AND PRODUCTION PLATFORMS, BASED ON CURRENT LEGISLATION AND
INDUSTRY OPERATING PRACTICES. AMOUNTS DISCLOSED FOR THE PERIOD 2008 - 2012
REPRESENT THE MINIMUM REQUIRED EXPENDITURES TO MEET THESE OBLIGATIONS.
ACTUAL EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED THESE MINIMUM
AMOUNTS.
(5) THE LONG-TERM DEBT REPRESENTS PRINCIPAL REPAYMENTS ONLY AND DOES NOT
REFLECT FAIR VALUE ADJUSTMENTS, ORIGINAL ISSUE DISCOUNTS OR TRANSACTION
COSTS. NO DEBT REPAYMENTS ARE REFLECTED FOR $1,440 MILLION OF REVOLVING
BANK CREDIT FACILITIES DUE TO THE EXTENDABLE NATURE OF THE FACILITIES.
(6) INTEREST EXPENSE AMOUNTS REPRESENT THE SCHEDULED FIXED-RATE AND
VARIABLE-RATE CASH PAYMENTS RELATED TO LONG-TERM DEBT. INTEREST ON
VARIABLE-RATE LONG-TERM DEBT WAS ESTIMATED BASED UPON PREVAILING INTEREST
RATES AS AT SEPTEMBER 30, 2008.
In addition to the amounts disclosed above, the Company has budgeted revised
construction costs of approximately $785 million related to the planned
completion of Phase 1 of the Horizon Project.
38 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
LEGAL PROCEEDINGS
The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business. In addition, the Company is subject to certain
contractor construction claims related to the Horizon Project. The Company
believes that any liabilities that might arise pertaining to any such matters
would not have a material effect on its consolidated financial position.
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING POLICIES
The preparation of financial statements requires the Company to make judgements,
assumptions and estimates in the application of generally accepted accounting
principles that have a significant impact on the financial results of the
Company. Actual results could differ from those estimates. A comprehensive
discussion of the Company's significant accounting policies is contained in the
MD&A and the audited consolidated financial statements for the year ended
December 31, 2007.
For the impact of new accounting standards related to capital disclosures,
inventory and financial instruments, refer to note 2 of the unaudited interim
consolidated financial statements as at September 30, 2008.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
In February 2008, the Canadian Institute of Chartered Accountants confirmed that
effective January 1, 2011, Canadian GAAP for publicly accountable entities will
be replaced in full with International Financial Reporting Standards ("IFRS") as
promulgated by the International Accounting Standards Board. The Company is
currently assessing the impact of adopting IFRS and is developing a plan to
achieve convergence to IFRS by January 1, 2011.
SENSITIVITY ANALYSIS
The following table is indicative of the annualized sensitivities of cash flow
from operations and net earnings from changes in certain key variables. The
analysis is based on business conditions and sales volumes during the third
quarter of 2008, excluding mark-to-market gains (losses) on risk management
activities and capitalized interest, and is not necessarily indicative of future
results. Each separate line item in the sensitivity analysis shows the effect of
a change in that variable only with all other variables being held constant.
CASH FLOW FROM CASH FLOW FROM
OPERATIONS NET EARNINGS
OPERATIONS (PER COMMON SHARE, NET EARNINGS (PER COMMON SHARE,
($ MILLIONS) BASIC) ($ MILLIONS) BASIC)
- ---------------------------------------------------------------------------------------------------------------------------
PRICE CHANGES
Crude oil - WTI US$1.00/bbl (1)
Excluding financial derivatives $ 89 $ 0.17 $ 66 $ 0.12
Including financial derivatives $ 63 $ 0.12 $ 47 $ 0.09
Natural gas - AECO C$0.10/mcf (1)
Excluding financial derivatives $ 40 $ 0.07 $ 28 $ 0.05
Including financial derivatives $ 39 $ 0.07 $ 28 $ 0.05
VOLUME CHANGES
Crude oil - 10,000 bbl/d $ 234 $ 0.43 $ 146 $ 0.27
Natural gas - 10 mmcf/d $ 23 $ 0.04 $ 11 $ 0.02
FOREIGN CURRENCY RATE CHANGE
$0.01 change in US$ (1)
Including financial derivatives $ 94 - 96 $ 0.17 - 0.18 $ 26 $ 0.05
INTEREST RATE CHANGE - 1% $ 32 $ 0.06 $ 32 $ 0.06
===========================================================================================================================
(1) FOR DETAILS OF OUTSTANDING FINANCIAL INSTRUMENTS IN PLACE, REFER TO NOTE 10
OF THE COMPANY'S UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS.
CANADIAN NATURAL RESOURCES LIMITED 39
===============================================================================
OTHER OPERATING HIGHLIGHTS
NETBACK ANALYSIS
Three Months Ended Nine Months Ended
--------------- ---------------
SEP 30 Jun 30 Sep 30 SEP 30 Sep 30
($/boe) (1) 2008 2008 2007 2008 2007
- -----------------------------------------------------------------------------------------------------------------------
Sales price (2) $ 80.60 $ 84.88 $ 47.96 $ 76.73 $ 48.99
Royalties 12.06 13.26 6.07 11.22 6.27
Production expense (3) 12.52 11.60 9.62 11.70 10.05
- -----------------------------------------------------------------------------------------------------------------------
NETBACK 56.02 60.02 32.27 53.81 32.67
Midstream contribution (3) (0.28) (0.24) (0.26) (0.26) (0.23)
Administration 0.91 0.87 0.94 0.86 0.99
Interest, net 0.49 0.60 1.15 0.67 1.34
Realized risk management loss (gain) 15.56 18.38 (0.41) 13.86 (0.11)
Realized foreign exchange (gain) loss (0.80) (0.20) 0.38 (0.41) 0.31
Taxes other than income tax - current 1.02 1.84 0.54 1.40 0.62
Current income tax - North America 0.09 0.11 0.49 0.21 0.38
Current income tax - North Sea 2.39 2.15 0.99 2.11 0.87
Current income tax - Offshore West Africa 0.87 0.65 0.37 0.74 0.28
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOW $ 35.77 $ 35.86 $ 28.08 $ 34.63 $ 28.22
=======================================================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
(3) EXCLUDING INTERSEGMENT ELIMINATION.
40 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
FINANCIAL STATEMENTS
CONSOLIDATED BALANCE SHEETS
---------------------
SEP 30 Dec 31
(millions of Canadian dollars, unaudited) 2008 2007
- ------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 14 $ 21
Accounts receivable and other 1,967 1,662
Future income tax 194 480
Current portion of other long-term assets - 18
- ------------------------------------------------------------------------------------------------------------
2,175 2,181
PROPERTY, PLANT AND EQUIPMENT (note 12) 37,628 33,902
OTHER LONG-TERM ASSETS 26 31
- ------------------------------------------------------------------------------------------------------------
$ 39,829 $ 36,114
============================================================================================================
LIABILITIES
CURRENT LIABILITIES
Accounts payable $ 408 $ 379
Accrued liabilities 2,091 1,567
Current portion of other long-term liabilities (note 4) 779 1,617
- ------------------------------------------------------------------------------------------------------------
3,278 3,563
LONG-TERM DEBT (note 3) 11,633 10,940
OTHER LONG-TERM LIABILITIES (note 4) 1,282 1,561
FUTURE INCOME TAX 7,131 6,729
- ------------------------------------------------------------------------------------------------------------
23,324 22,793
- ------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
SHARE CAPITAL (note 6) 2,761 2,674
RETAINED EARNINGS 13,628 10,575
ACCUMULATED OTHER COMPREHENSIVE INCOME (note 7) 116 72
- ------------------------------------------------------------------------------------------------------------
16,505 13,321
- ------------------------------------------------------------------------------------------------------------
$ 39,829 $ 36,114
============================================================================================================
COMMITMENTS (NOTE 11)
CANADIAN NATURAL RESOURCES LIMITED 41
===============================================================================
CONSOLIDATED STATEMENTS OF EARNINGS
Three Months Ended Nine Months Ended
------------------- ------------------
(millions of Canadian dollars, except per common SEP 30 Sep 30 SEP 30 Sep 30
share amounts, unaudited) 2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------------------
REVENUES $ 4,583 $ 3,073 $ 13,662 $ 9,343
Less: royalties (612) (341) (1,749) (1,048)
- --------------------------------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES 3,971 2,732 11,913 8,295
- --------------------------------------------------------------------------------------------------------------------------------
EXPENSES
Production 639 544 1,836 1,693
Transportation and blending 472 359 1,646 1,103
Depletion, depreciation and amortization 659 715 2,017 2,144
Asset retirement obligation accretion (note 4) 18 18 52 53
Administration 46 53 134 166
Stock-based compensation (recovery) expense (note 4) (308) 78 151 209
Interest, net 25 65 105 225
Risk management activities (note 10) (1,715) 53 1,178 536
Foreign exchange loss (gain) 73 (173) 156 (424)
- --------------------------------------------------------------------------------------------------------------------------------
(91) 1,712 7,275 5,705
- --------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 4,062 1,020 4,638 2,590
Taxes other than income tax 45 40 156 132
Current income tax expense (note 5) 171 105 477 257
Future income tax expense (note 5) 1,011 175 790 391
- --------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 2,835 $ 700 $ 3,215 $ 1,810
- --------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS PER COMMON SHARE (note 9)
Basic and diluted $ 5.25 $ 1.30 $ 5.95 $ 3.36
================================================================================================================================
42 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Nine Months Ended
-------------------
SEP 30 Sep 30
(millions of Canadian dollars, unaudited) 2008 2007
- ----------------------------------------------------------------------------------------------------------------------
SHARE CAPITAL (note 6)
Balance - beginning of period $ 2,674 $ 2,562
Issued upon exercise of stock options 17 19
Previously recognized liability on stock options exercised for common shares 70 82
- ----------------------------------------------------------------------------------------------------------------------
Balance - end of period 2,761 2,663
- ----------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance - beginning of period 10,575 8,151
Net earnings 3,215 1,810
Dividends on common shares (note 6) (162) (137)
- ----------------------------------------------------------------------------------------------------------------------
Balance - end of period 13,628 9,824
- ----------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (note 7)
Balance - beginning of period 72 146
Other comprehensive income (loss), net of taxes 44 (61)
- ----------------------------------------------------------------------------------------------------------------------
Balance - end of period 116 85
- ----------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY $ 16,505 $ 12,572
======================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Nine Months Ended
-------------- ----------------
SEP 30 Sep 30 SEP 30 Sep 30
(millions of Canadian dollars, unaudited) 2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------------
NET EARNINGS $ 2,835 $ 700 $ 3,215 $ 1,810
- --------------------------------------------------------------------------------------------------------------------------
NET CHANGE IN DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED
AS CASH FLOW HEDGES
Unrealized income during the period, net of taxes of
$13 million (2007 - $1 million) - three months ended;
$2 million (2007 - $9 million) - nine months ended 89 10 24 6
Reclassification to net earnings, net of taxes of
$1 million (2007 - $11 million) - three months ended;
$6 million (2007 - $24 million) - nine months ended 3 24 (11) (51)
- --------------------------------------------------------------------------------------------------------------------------
92 34 13 (45)
FOREIGN CURRENCY TRANSLATION ADJUSTMENT
Translation of net investment 18 (11) 31 (16)
- --------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES 110 23 44 (61)
- --------------------------------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME $ 2,945 $ 723 $ 3,259 $ 1,749
===========================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 43
===============================================================================
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended Nine Months Ended
---------------- ----------------
SEP 30 Sep 30 SEP 30 Sep 30
(millions of Canadian dollars, unaudited) 2008 2007 2008 2007
- ---------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings $ 2,835 $ 700 $ 3,215 $ 1,810
Non-cash items
Depletion, depreciation and amortization 659 715 2,017 2,144
Asset retirement obligation accretion 18 18 52 53
Stock-based compensation (recovery) expense (308) 78 151 209
Unrealized risk management (gain) loss (2,506) 76 (983) 555
Unrealized foreign exchange loss (gain) 113 (195) 219 (477)
Deferred petroleum revenue tax (recovery) expense (7) 10 (62) 27
Future income tax expense 1,011 175 790 391
Other 4 12 23 7
Abandonment expenditures (10) (22) (23) (55)
Net change in non-cash working capital (132) (94) 16 (82)
- ---------------------------------------------------------------------------------------------------------------------------
1,677 1,473 5,415 4,582
- ---------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Issue (repayment) of bank credit facilities, net 331 49 (909) (1,797)
Repayment of medium-term notes - - - (125)
Repayment of senior unsecured notes - - (31) (33)
(Repayment) issue of US dollar debt securities (8) - 1,215 2,553
Issue of common shares on exercise of stock options 3 3 17 19
Dividends on common shares (54) (46) (154) (132)
Net change in non-cash working capital (32) (17) (2) 6
- ---------------------------------------------------------------------------------------------------------------------------
240 (11) 136 491
- ---------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant and equipment (1,739) (1,421) (5,616) (4,861)
Net proceeds on sale of property, plant and equipment 5 1 15 5
- ---------------------------------------------------------------------------------------------------------------------------
Net expenditures on property, plant and equipment (1,734) (1,420) (5,601) (4,856)
Net change in non-cash working capital (191) (32) 43 (219)
- ---------------------------------------------------------------------------------------------------------------------------
(1,925) (1,452) (5,558) (5,075)
- ---------------------------------------------------------------------------------------------------------------------------
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (8) 10 (7) (2)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 22 11 21 23
- ---------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF PERIOD $ 14 $ 21 $ 14 $ 21
===========================================================================================================================
INTEREST PAID $ 184 $ 158 $ 462 $ 403
TAXES PAID
Taxes other than income tax $ 162 $ 29 $ 217 $ 103
Current income tax $ 178 $ 85 $ 123 $ 157
===========================================================================================================================
44 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(tabular amounts in millions of Canadian dollars, unless otherwise stated,
unaudited)
1. ACCOUNTING POLICIES
The interim consolidated financial statements of Canadian Natural Resources
Limited (the "Company") include the Company and all of its subsidiaries and
partnerships, and have been prepared following the same accounting policies as
the audited consolidated financial statements of the Company as at December 31,
2007, except as described in note 2. The interim consolidated financial
statements contain disclosures that are supplemental to the Company's annual
audited consolidated financial statements. Certain disclosures that are normally
required to be included in the notes to the annual audited consolidated
financial statements have been condensed. These interim financial statements
should be read in conjunction with the Company's audited consolidated financial
statements and notes thereto for the year ended December 31, 2007.
COMPARATIVE FIGURES
Certain prior period figures have been reclassified to conform to the
presentation adopted in 2008.
2. CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2008 the Company adopted the following accounting and
disclosure standards issued by the Canadian Institute of Chartered Accountants:
o CAPITAL DISCLOSURES - Section 1535 - "Capital Disclosures" requires
entities to disclose their objectives, policies and processes for managing
capital, as well as quantitative data about capital. The standard also
requires the disclosure of any externally imposed capital requirements and
compliance with those requirements. The standard does not define capital.
This standard affects disclosure only and did not impact the Company's
accounting for capital (note 8).
o INVENTORIES - Section 3031 - "Inventories" replaces Section 3030 -
"Inventories" and establishes new standards for the measurement of cost of
inventories and expands disclosure requirements for inventories. Adoption
of this standard did not have a material impact on the Company's financial
statements.
o FINANCIAL INSTRUMENTS - Section 3862 - "Financial Instruments - Disclosure"
and Section 3863 - "Financial Instruments - Presentation" replace Section
3861 - "Financial Instruments - Disclosure and Presentation". Section 3862
enhances disclosure requirements concerning risks and requires quantitative
and qualitative disclosures about exposures to risks arising from financial
instruments. Section 3863 carries forward the presentation requirements
from Section 3861 unchanged. These standards affect disclosures only and do
not impact the Company's accounting for financial instruments (note 10).
CANADIAN NATURAL RESOURCES LIMITED 45
===============================================================================
3. LONG-TERM DEBT
----------
SEP 30 Dec 31
2008 2007
- -----------------------------------------------------------------------------------------------------------
CANADIAN DOLLAR DENOMINATED DEBT
Bank credit facilities (bankers' acceptances) $ 3,787 $ 4,696
Medium-term notes 1,200 1,200
- -----------------------------------------------------------------------------------------------------------
4,987 5,896
- -----------------------------------------------------------------------------------------------------------
US DOLLAR DENOMINATED DEBT
Senior unsecured notes (2008 - US$31 million; 2007 - US$62 million) 33 61
US dollar debt securities (2008 - US$6,300 million; 2007 - US$5,108 million) 6,677 5,048
Less - original issue discount on senior unsecured notes and US dollar
debt securities (1) (24) (23)
- -----------------------------------------------------------------------------------------------------------
6,686 5,086
Fair value of interest rate swaps on US dollar debt securities (2) 16 9
- -----------------------------------------------------------------------------------------------------------
6,702 5,095
- -----------------------------------------------------------------------------------------------------------
Long-term debt before transaction costs 11,689 10,991
Less - transaction costs (1) (3) (56) (51)
- -----------------------------------------------------------------------------------------------------------
$ 11,633 $ 10,940
===========================================================================================================
(1) THE COMPANY HAS INCLUDED UNAMORTIZED ORIGINAL ISSUE DISCOUNTS AND DIRECTLY
ATTRIBUTABLE TRANSACTION COSTS IN THE CARRYING VALUE OF THE OUTSTANDING
DEBT.
(2) THE CARRYING VALUES OF US$350 MILLION OF 5.45% NOTES DUE OCTOBER 2012 AND
US$350 MILLION OF 4.90% NOTES DUE DECEMBER 2014 HAVE BEEN ADJUSTED BY $16
MILLION (2007 - $9 MILLION) TO REFLECT THE FAIR VALUE IMPACT OF HEDGE
ACCOUNTING.
(3) TRANSACTION COSTS PRIMARILY REPRESENT UNDERWRITING COMMISSIONS CHARGED AS A
PERCENTAGE OF THE RELATED DEBT OFFERINGS, AS WELL AS LEGAL, RATING AGENCY
AND OTHER PROFESSIONAL FEES.
BANK CREDIT FACILITIES
As at September 30, 2008, the Company had in place unsecured bank credit
facilities of $6,233 million, comprised of:
o a $125 million demand credit facility;
o a non-revolving syndicated credit facility of $2,350 million maturing
October 2009;
o a revolving syndicated credit facility of $2,230 million maturing June
2012;
o a revolving syndicated credit facility of $1,500 million maturing June
2012; and
o a 15 million pounds demand credit facility related to the Company's
North Sea operations.
The revolving syndicated credit facilities are extendible annually for one year
periods at the mutual agreement of the Company and the lenders. If the
facilities are not extended, the full amount of the outstanding principal would
be repayable on the maturity date.
The weighted average interest rate of the bank credit facilities outstanding at
September 30, 2008, was 3.7% (December 31, 2007 - 5.2%).
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $367 million, including $300 million related to the Horizon Oil
Sands Project ("Horizon Project"), were outstanding at September 30, 2008.
MEDIUM-TERM NOTES
The Company has $2,600 million remaining on its outstanding $3,000 million base
shelf prospectus filed in September 2007 that allows for the issue of
medium-term notes in Canada until October 2009. If issued, these securities will
bear interest as determined at the date of issuance.
46 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
SENIOR UNSECURED NOTES
During the second quarter of 2008, US$31 million of the senior unsecured notes
were repaid.
US DOLLAR DEBT SECURITIES
During the third quarter of 2008, US$8 million of US dollar debt securities were
repaid.
In January 2008, the Company issued US$1,200 million of unsecured notes under a
US base shelf prospectus, comprised of US$400 million of 5.15% unsecured notes
due February 2013, US$400 million of 5.90% unsecured notes due February 2018,
and US$400 million of 6.75% unsecured notes due February 2039. Proceeds from the
securities issued were used to repay bankers' acceptances under the Company's
bank credit facilities. After issuing these securities, the Company has US$1,800
million remaining on its outstanding US$3,000 million base shelf prospectus
filed in September 2007 that allows for the issue of US dollar debt securities
in the United States until October 2009. If issued, these securities will bear
interest as determined at the date of issuance.
4. OTHER LONG-TERM LIABILITIES
-----------
SEP 30 Dec 31
2008 2007
- --------------------------------------------------------------------------------
Asset retirement obligations $ 1,151 $ 1,074
Stock-based compensation 441 529
Risk management (note 10) 349 1,474
Other 120 101
- --------------------------------------------------------------------------------
2,061 3,178
Less: current portion 779 1,617
- --------------------------------------------------------------------------------
$ 1,282 $ 1,561
================================================================================
ASSET RETIREMENT OBLIGATIONS
At September 30, 2008, the Company's total estimated undiscounted costs to
settle its asset retirement obligations were approximately $4,641 million
(December 31, 2007 - $4,426 million). These costs will be incurred over the
lives of the operating assets and have been discounted using a weighted average
credit-adjusted risk free rate of 6.6% (December 31, 2007 - 6.6%). A
reconciliation of the discounted asset retirement obligations is as follows:
------------------
NINE MONTHS Year
ENDED Ended
SEP 30, 2008 Dec 31, 2007
- --------------------------------------------------------------------------------
Balance - beginning of period $ 1,074 $ 1,166
Liabilities incurred 15 21
Liabilities acquired (disposed) 3 (65)
Liabilities settled (23) (71)
Asset retirement obligation accretion 52 70
Revision of estimates - 35
Foreign exchange 30 (82)
- --------------------------------------------------------------------------------
Balance - end of period $ 1,151 $ 1,074
================================================================================
CANADIAN NATURAL RESOURCES LIMITED 47
===============================================================================
STOCK-BASED COMPENSATION
The Company recognizes a liability for the potential cash settlements under its
Stock Option Plan. The current portion represents the maximum amount of the
liability payable within the next twelve month period if all vested options are
surrendered for cash settlement.
-----------------
NINE MONTHS Year
ENDED Ended
SEP 30, 2008 Dec 31, 2007
- --------------------------------------------------------------------------------
Balance - beginning of period $ 529 $ 744
Stock-based compensation 151 193
Payments for options surrendered (202) (375)
Transferred to common shares (70) (91)
Capitalized to Horizon Project 33 58
- --------------------------------------------------------------------------------
Balance - end of period 441 529
Less: current portion 378 390
- --------------------------------------------------------------------------------
$ 63 $ 139
================================================================================
5. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Nine Months Ended
--------- ---------
SEP 30 Sep 30 SEP 30 Sep 30
2008 2007 2008 2007
- --------------------------------------------------------------------------------
Current income tax
- North America $ 6 $ 28 $ 33 $ 65
Current income tax
- North Sea 121 56 328 145
Current income tax
- Offshore West Africa 44 21 116 47
- --------------------------------------------------------------------------------
Current income tax expense 171 105 477 257
Future income tax expense 1,011 175 790 391
- --------------------------------------------------------------------------------
Income tax expense $ 1,182 $ 280 $ 1,267 $ 648
================================================================================
Taxable income from the conventional crude oil and natural gas business in
Canada is primarily generated through partnerships, with the related income
taxes payable in a future period. North America current income taxes have been
provided on the basis of the corporate structure and available income tax
deductions and will vary depending upon the nature, timing and amount of capital
expenditures incurred in Canada in any particular year.
During the first quarter of 2008, enacted or substantively enacted income tax
rate changes resulted in a reduction of future income tax liabilities of
approximately $19 million in British Columbia and $22 million in Cote d'Ivoire,
Offshore West Africa.
During the second quarter of 2007, the Canadian Federal Government enacted
income tax rate changes, resulting in a reduction of future income tax
liabilities of approximately $71 million.
48 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
6. SHARE CAPITAL
------------------------------------
Nine Months Ended Sep 30, 2008
ISSUED NUMBER OF SHARES
COMMON SHARES (thousands) AMOUNT
- ----------------------------------------------------------------------------------------------------------------------
Balance - beginning of period 539,729 $ 2,674
Issued upon exercise of stock options 1,128 17
Previously recognized liability on stock options exercised for common
shares - 70
- ----------------------------------------------------------------------------------------------------------------------
Balance - end of period 540,857 $ 2,761
======================================================================================================================
DIVIDEND POLICY
In February 2008, the Board of Directors set the regular quarterly dividend at
$0.10 per common share. The Company has paid regular quarterly dividends in
January, April, July, and October of each year since 2001. The dividend policy
undergoes a periodic review by the Board of Directors and is subject to change.
STOCK OPTIONS
Nine Months Ended Sep 30, 2008
STOCK OPTIONS WEIGHTED AVERAGE
(thousands) EXERCISE PRICE
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding - beginning of period 30,659 $ 47.23
Granted 1,327 $ 87.19
Surrendered for cash settlement (3,560) $ 25.87
Exercised for common shares (1,128) $ 14.83
Forfeited (2,137) $ 55.63
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding - end of period 25,161 $ 53.09
- ------------------------------------------------------------------------------------------------------------------------------------
Exercisable - end of period 6,683 $ 37.67
====================================================================================================================================
7. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of accumulated other comprehensive income, net of taxes, were as
follows:
----------
SEP 30 Sep 30
2008 2007
- --------------------------------------------------------------------------------
Derivative financial instruments designated as
cash flow hedges $ 114 $ 114
Foreign currency translation adjustment 2 (29)
- --------------------------------------------------------------------------------
$ 116 $ 85
================================================================================
CANADIAN NATURAL RESOURCES LIMITED 49
===============================================================================
8. CAPITAL DISCLOSURES
As required by Canadian generally accepted accounting principles ("GAAP"),
effective January 1, 2008, the Company must provide certain disclosures
regarding its objectives, policies and processes for managing capital, as well
as provide certain quantitative data about capital. As the Company does not have
any externally imposed capital requirements, for the purposes of this
disclosure, the Company has defined its capital to mean its long-term debt and
consolidated shareholders' equity, as determined each reporting date.
The Company's objectives when managing its capital structure are to maintain
financial flexibility and balance to enable the Company to access capital
markets to sustain its on-going operations and to support its growth strategies.
The Company primarily monitors capital on the basis of an internally derived
non-GAAP financial measure referred to as its "debt to book capitalization
ratio", which is the arithmetic ratio of long-term debt divided by the sum of
the carrying value of shareholders' equity plus long-term debt. The Company aims
over time to maintain its debt to book capitalization ratio in the range of 35%
to 45%. However, the Company may exceed the high end of such target range if it
is investing in capital projects, undertaking acquisitions, or in periods of
lower commodity prices. The Company may be below the low end of the target range
when cash flow from operating activities is greater than current investment
activities. The ratio is currently near the midpoint of the target range
primarily due to the debt financing of the construction of the Horizon project,
together with the impact of the strengthening in the US dollar exchange rate on
the Company's US dollar denominated long-term debt.
Readers are cautioned that as the debt to book capitalization ratio has no
defined meaning under GAAP, this financial measure may not be comparable to
similar measures provided by other reporting entities. Further, there can be no
assurances that the Company will continue to use this measure to monitor capital
or will not alter the method of calculation of this measure at some point in the
future.
-------------
SEP 30 Dec 31
2008 2007
- --------------------------------------------------------------------------------
Long-term debt $ 11,633 $ 10,940
Total shareholders' equity $ 16,505 $ 13,321
Debt to book capitalization 41% 45%
================================================================================
9. NET EARNINGS PER COMMON SHARE
Three Months Ended Nine Months Ended
------------- -------------
SEP 30 Sep 30 SEP 30 Sep 30
2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding 540,819 539,494 540,557 539,229
(thousands) - basic and diluted
- --------------------------------------------------------------------------------------------------------------------
Net earnings - basic and diluted $ 2,835 $ 700 $ 3,215 $ 1,810
- --------------------------------------------------------------------------------------------------------------------
Net earnings per common share - basic and diluted $ 5.25 $ 1.30 $ 5.95 $ 3.36
====================================================================================================================
50 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
10. FINANCIAL INSTRUMENTS
The carrying values of the Company's financial instruments by category are as
follows:
--------------------------------------------------------------------------
SEP 30, 2008
- ---------------------------------------------------------------------------------------------------------------
LOANS AND HELD FOR TRADING OTHER FINANCIAL
RECEIVABLES AT AT LIABILITIES AT
Asset (liability) AMORTIZED COST FAIR VALUE AMORTIZED COST
- ---------------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ - $ 14 $ -
Accounts receivable 1,344 - -
Accounts payable - - (408)
Accrued liabilities - - (2,091)
Risk management - (349) -
Long-term debt - - (11,633)
- ---------------------------------------------------------------------------------------------------------------
$ 1,344 $ (335) $ (14,132)
===============================================================================================================
--------------------------------------------------------------------------
Dec 31, 2007
- ---------------------------------------------------------------------------------------------------------------
Loans and Held for Other financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized cost
- ---------------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ - $ 21 $ -
Accounts receivable 1,143 - -
Accounts payable - - (379)
Accrued liabilities - - (1,567)
Risk management - (1,474) -
Long-term debt - - (10,940)
- ---------------------------------------------------------------------------------------------------------------
$ 1,143 $ (1,453) $ (12,886)
===============================================================================================================
The carrying value of the Company's financial instruments approximates their
fair value, except for fixed-rate long-term debt as noted below:
-------------------
SEP 30, 2008 Dec 31, 2007
- --------------------------------------------------------------------------------
CARRYING FAIR Carrying Fair
VALUE VALUE value value
- --------------------------------------------------------------------------------
Fixed-rate long-term debt (1) $ 7,846 $ 6,961 $ 6,244 $ 6,259
================================================================================
(1) THE CARRYING VALUES OF US$350 MILLION OF 5.45% NOTES DUE OCTOBER 2012 AND
US$350 MILLION OF 4.90% NOTES DUE DECEMBER 2014 HAVE BEEN ADJUSTED BY $16
MILLION (2007 - $9 MILLION) TO REFLECT THE FAIR VALUE IMPACT OF HEDGE
ACCOUNTING.
CANADIAN NATURAL RESOURCES LIMITED 51
===============================================================================
RISK MANAGEMENT
The Company uses derivative financial instruments to manage its commodity price,
foreign currency and interest rate exposures. These financial instruments are
entered into solely for hedging purposes and are not used for speculative
purposes.
The estimated fair value of derivative financial instruments has been determined
based on appropriate internal valuation methodologies and/or third party
indications. Fair values determined using valuation models require the use of
assumptions concerning the amount and timing of future cash flows and discount
rates. In determining these assumptions, the Company has relied primarily on
external readily observable market inputs including quoted commodity prices and
volatility, interest rate yield curves, and foreign exchange rates. The
resulting fair value estimates may not necessarily be indicative of the amounts
that could be realized or settled in a current market transaction and these
differences may be material.
The changes in estimated fair values of derivative financial instruments
included in the risk management asset (liability) were recognized in the
financial statements as follows:
-------------------
NINE MONTHS ENDED Year Ended
SEP 30, 2008 Dec 31, 2007
- ---------------------------------------------------------------------------------------------------------------------------
Asset (liability) RISK MANAGEMENT Risk management
MARK-TO-MARKET mark-to-market
- ---------------------------------------------------------------------------------------------------------------------------
Balance - beginning of period $ (1,474) $ 128
Retained earnings effect of adoption of financial instrument standards - 14
Net cost of outstanding put options 272 58
Net change in fair value of outstanding derivative financial instruments
attributable to:
- Risk management activities 983 (1,400)
- Interest expense 7 9
- Foreign exchange 136 (350)
- Other comprehensive income 3 125
- ---------------------------------------------------------------------------------------------------------------------------
(73) (1,416)
Add: Put premium financing obligations (1) (276) (58)
- ---------------------------------------------------------------------------------------------------------------------------
Balance - end of period (349) (1,474)
Less: current portion (330) (1,227)
- ---------------------------------------------------------------------------------------------------------------------------
$ (19) $ (247)
===========================================================================================================================
(1) THE COMPANY HAS NEGOTIATED PAYMENT OF PUT OPTION PREMIUMS WITH VARIOUS
COUNTERPARTIES AT THE TIME OF ACTUAL SETTLEMENT OF THE RESPECTIVE OPTIONS.
THESE OBLIGATIONS HAVE BEEN REFLECTED IN THE NET RISK MANAGEMENT ASSET
(LIABILITY).
Net losses (gains) from risk management activities were as follows:
Three Months Ended Nine Months Ended
- -------------------------------------------------------------------------------------------------------------------------
SEP 30 Sep 30 SEP 30 Sep 30
2008 2007 2008 2007
- -------------------------------------------------------------------------------------------------------------------------
Net realized risk management loss (gain) $ 791 $ (23) $ 2,161 $ (19)
Net unrealized risk management (gain) loss (2,506) 76 (983) 555
- -------------------------------------------------------------------------------------------------------------------------
$ (1,715) $ 53 $ 1,178 $ 536
=========================================================================================================================
52 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
FINANCIAL RISK FACTORS
a) MARKET RISK
Market risk is the risk that the fair value or future cash flows of a financial
instrument will fluctuate because of changes in market prices. The Company's
market risk is comprised of commodity price risk, interest rate risk, and
foreign currency exchange risk.
COMMODITY PRICE RISK
The Company uses commodity price financial derivatives to manage its exposure to
commodity price risk associated with the sale of its future crude oil and
natural gas production. At September 30, 2008, the Company had the following net
financial derivatives outstanding to manage its commodity price exposures:
Remaining term Volume Weighted average price Index
- ---------------------------------------------------------------------------------------------------------------------------
CRUDE OIL
Crude oil price collars Oct 2008 - Dec 2008 20,000 bbl/d US$50.00 - US$65.53 Mayan Heavy
Oct 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$75.22 WTI
Oct 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.05 WTI
Oct 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.98 WTI
Oct 2008 - Dec 2008 25,000 bbl/d US$70.00 - US$112.63 WTI
Jan 2009 - Dec 2009 25,000 bbl/d US$70.00 - US$111.56 WTI
Crude oil puts Oct 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
Jan 2009 - Dec 2009 92,000 bbl/d US$100.00 WTI
===========================================================================================================================
At September 30, 2008, the net cost of outstanding put options and their
respective periods of settlement was as follows:
Q4 2008 Q1 2009 Q2 2009 Q3 2009 Q4 2009
- ----------------------------------------------------------------------------------------------------------------------------
Cost ($ millions) US$15 US$60 US$60 US$61 US$61
============================================================================================================================
The Company's outstanding commodity financial derivatives are expected to be
settled monthly based on the applicable index pricing for the respective
contract month.
Subsequent to September 30, 2008, the Company entered into 4,000 bbl/d of
US$70.00 - US$90.00 WTI collars for the period April 2009 to June 2009. In
addition, the Company entered into 500,000 GJ/d of natural gas AECO collars with
a floor of C$6.00 and a ceiling ranging from C$8.50 to C$8.80 for the period
November 2008 to March 2009.
CANADIAN NATURAL RESOURCES LIMITED 53
===============================================================================
INTEREST RATE RISK
The Company is exposed to interest rate risk on its fixed and floating rate
long-term debt. The Company enters into interest rate swap agreements to manage
its fixed to floating interest rate mix on long-term debt. The interest rate
swap contracts require the periodic exchange of payments without the exchange of
the notional principal amounts on which the payments are based. At September 30,
2008, the Company had the following interest rate swap contracts outstanding:
Remaining term Amount ($ millions) Fixed rate Floating rate
- --------------------------------------------------------------------------------------------------------------------
INTEREST RATE
Swaps - fixed to floating(2) Oct 2008 - Oct 2012 US$350 5.45% LIBOR (1) + 0.81%
Oct 2008 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
====================================================================================================================
(1) LONDON INTERBANK OFFERED RATE
(2) SUBSEQUENT TO SEPTEMBER 30, 2008, THE COMPANY UNWOUND US$350 MILLION OF
5.45% INTEREST RATE SWAPS FOR NET PROCEEDS OF APPROXIMATELY US$16 MILLION
All interest rate related derivative financial instruments designated as hedges
at September 30, 2008 were classified as fair value hedges.
FOREIGN CURRENCY EXCHANGE RATE RISK
The Company is exposed to foreign currency exchange rate risk in Canada
primarily related to its US dollar denominated long-term debt and working
capital. The Company is also exposed to foreign currency exchange rate risk on
transactions conducted in other currencies in its subsidiaries and in the
carrying value of its self-sustaining foreign subsidiaries. The Company
periodically enters into cross currency swap agreements and foreign currency
forward agreements to manage known currency exposure on US dollar denominated
long-term debt and working capital. The cross currency swap contracts require
the periodic exchange of payments with the exchange at maturity of notional
principal amounts on which the payments are based. At September 30, 2008, the
Company had the following cross currency swap contracts outstanding:
Remaining term Amount Exchange rate Interest rate Interest rate
($ millions) (US$/C$) (US$) (C$)
- --------------------------------------------------------------------------------------------------------------------
CROSS CURRENCY
Swaps Oct 2008 - Aug 2016 US$250 1.116 6.00% 5.40%
Oct 2008 - May 2017 US$1,100 1.170 5.70% 5.10%
Oct 2008 - Mar 2038 US$550 1.170 6.25% 5.76%
====================================================================================================================
All cross currency related derivative financial instruments designated as hedges
at September 30, 2008 were classified as cash flow hedges.
In addition to the cross currency swap contracts noted above, the Company
utilizes foreign currency forward contracts to manage certain foreign currency
cash management needs. At September 30, 2008, the Company had US$776 million of
these contracts outstanding, with terms of approximately 30 days or less.
54 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
FINANCIAL INSTRUMENT SENSITIVITIES
As required by Canadian GAAP, the Company must provide certain quantitative
sensitivities related to its financial instruments. The following table
summarizes the annualized sensitivities of the Company's net earnings and other
comprehensive income to changes in the fair value of financial instruments
outstanding as at September 30, 2008 resulting from changes in the specified
variable, with all other variables held constant. These sensitivities are
limited to the impact of changes in a specified variable applied to financial
instruments only and do not represent the impact of a change in the variable on
the operating results of the Company taken as a whole. Further, these
sensitivities are theoretical, as changes in one variable may contribute to
changes in another variable, which may magnify or counteract the sensitivities.
In addition, changes in fair value generally can not be extrapolated because the
relationship of a change in an assumption to the change in fair value may not be
linear.
---------------------- --------------------------
Impact on Impact on other
net earnings comprehensive income
- --------------------------------------------------------------------------------------------------
COMMODITY PRICE RISK
Increase WTI US$1.00/bbl $ (25) $ -
Decrease WTI US$1.00/bbl $ 25 $ -
INTEREST RATE RISK
Increase interest rate 1% $ (26) $ 7
Decrease interest rate 1% $ 26 $ (8)
FOREIGN CURRENCY EXCHANGE RATE RISK
Increase exchange rate by US$0.01 $ (32) $ -
Decrease exchange rate by US$0.01 $ 32 $ -
==================================================================================================
b) CREDIT RISK
Credit risk is the risk that a party to a financial instrument will cause a
financial loss for the Company by failing to discharge an obligation.
The Company's accounts receivable are mainly with customers in the crude oil and
natural gas industry and are subject to normal industry credit risks. The
Company manages these risks by reviewing its exposure to individual companies on
a regular basis and where appropriate, ensures that parental guarantees or
letters of credit are in place to minimize the impact in the event of default.
Substantially all of the Company's accounts receivables are due within normal
trade terms.
The Company is also exposed to possible losses in the event of nonperformance by
counterparties to derivative financial instruments; however, the Company manages
this credit risk by entering into agreements with substantially all investment
grade financial institutions and other entities. At September 30, 2008, the
Company had net risk management assets of $111 million with specific
counterparties related to derivative financial instruments (December 31, 2007 -
$20 million).
CANADIAN NATURAL RESOURCES LIMITED 55
===============================================================================
c) LIQUIDITY RISK
Liquidity risk is the risk that the Company will encounter difficulty in meeting
obligations associated with financial liabilities.
Management of liquidity risk requires the Company to maintain sufficient cash
and cash equivalents, along with other sources of capital, consisting primarily
of cash flow from operating activities, available credit facilities, and access
to debt capital markets, to meet obligations as they become due. Due to
fluctuations in the timing of the receipt and/or disbursement of operating cash
flows, the Company maintains adequate bank credit facilities to provide
liquidity.
The maturity dates for financial liabilities are as follows:
Less than 1 to less than 2 to less than
1 year 2 years 5 years Thereafter
- ------------------------------------------------------------------------------------------------------------------------
Accounts payable $ 408 $ - $ - $ -
Accrued liabilities $ 2,091 $ - $ - $ -
Risk management $ 330 $ (36) $ 27 $ 28
Long-term debt (1) $ 33 $ 2,346 $ 2,019 $ 5,859
========================================================================================================================
(1) THE LONG-TERM DEBT REPRESENTS PRINCIPAL REPAYMENTS ONLY AND DOES NOT
REFLECT FAIR VALUE ADJUSTMENTS, ORIGINAL ISSUE DISCOUNTS OR TRANSACTION
COSTS. NO DEBT REPAYMENTS ARE REFLECTED FOR $1,440 MILLION OF REVOLVING
BANK CREDIT FACILITIES DUE TO THE EXTENDABLE NATURE OF THE FACILITIES.
11. COMMITMENTS
As at September 30, 2008, the Company had committed to certain payments as
follows:
Remaining 2008 2009 2010 2011 2012 Thereafter
- -----------------------------------------------------------------------------------------------------------------------------------
Product transportation and
pipeline $ 61 $ 181 $ 164 $ 135 $ 114 $ 1,101
Offshore equipment operating
leases (1) $ 51 $ 134 $ 121 $ 119 $ 96 $ 425
Offshore drilling (2) (3) $ 85 $ 218 $ 54 $ - $ - $ -
Asset retirement
obligations (4) $ 10 $ 4 $ 5 $ 4 $ 4 $ 4,614
Office leases $ 6 $ 26 $ 29 $ 22 $ 2 $ -
Other $ 50 $ 380 $ 260 $ 36 $ 30 $ 74
===================================================================================================================================
(1) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF OBLIGATIONS
RELATED TO FLOATING PRODUCTION, STORAGE AND OFFTAKE VESSELS ("FPSO").
DURING 2006, THE COMPANY ENTERED INTO AN AGREEMENT TO LEASE AN ADDITIONAL
FPSO COMMENCING IN 2009, IN CONNECTION WITH THE PLANNED OFFSHORE
DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. DURING THE INITIAL TERM, THE
TOTAL ANNUAL PAYMENTS FOR THE GABON FPSO ARE ESTIMATED TO BE US$50 MILLION.
(2) DURING 2007, THE COMPANY ENTERED INTO A ONE-YEAR AGREEMENT FOR OFFSHORE
DRILLING SERVICES RELATED TO THE BAOBAB FIELD IN COTE D'IVOIRE, OFFSHORE
WEST AFRICA. THE AGREEMENT COMMENCED IN THE SECOND QUARTER OF 2008, ON
DELIVERY OF THE RIG. ESTIMATED TOTAL REMAINING PAYMENTS OF US$54 MILLION,
AFTER JOINT VENTURE RECOVERIES, HAVE BEEN INCLUDED IN THIS TABLE FOR THE
PERIOD 2008 - 2009.
(3) DURING 2007, THE COMPANY AWARDED CONTRACTS FOR A DRILLING RIG AND FOR THE
CONSTRUCTION OF WELLHEAD TOWERS IN CONNECTION WITH THE PLANNED OFFSHORE
DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. ESTIMATED TOTAL REMAINING
PAYMENTS OF US$279 MILLION HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD
2008 - 2010.
(4) AMOUNTS REPRESENT MANAGEMENT'S ESTIMATE OF THE FUTURE UNDISCOUNTED PAYMENTS
TO SETTLE ASSET RETIREMENT OBLIGATIONS RELATED TO RESOURCE PROPERTIES,
FACILITIES, AND PRODUCTION PLATFORMS, BASED ON CURRENT LEGISLATION AND
INDUSTRY OPERATING PRACTICES. AMOUNTS DISCLOSED FOR THE PERIOD 2008 - 2012
REPRESENT THE MINIMUM REQUIRED EXPENDITURES TO MEET THESE OBLIGATIONS.
ACTUAL EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED THESE MINIMUM
AMOUNTS.
In addition to the amounts disclosed above, the Company has budgeted revised
construction costs of approximately $785 million related to the planned
completion of Phase 1 of the Horizon Project.
56 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
12. SEGMENTED INFORMATION
NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA
(millions of Canadian Three Months Nine Months Three Months Nine Months Three Months Nine Months
dollars, Ended Ended Ended Ended Ended Ended
unaudited) Sep 30 Sep 30 Sep 30 Sep 30 Sep 30 Sep 30
--------- ------- -------- -------- -------- ---------
2008 2007 2008 2007 2008 2007 2008 2007 2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE 3,883 2,459 11,380 7,578 462 397 1,507 1,230 234 211 758 516
Less: royalties (561) (320) (1,617) (1,001) (1) (1) (3) (2) (50) (20) (129) (45)
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE, NET OF 3,322 2,139 9,763 6,577 461 396 1,504 1,228 184 191 629 471
ROYALTIES
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production 498 401 1,424 1,265 123 117 340 353 15 23 61 63
Transportation and
blending 483 366 1,674 1,122 3 4 8 12 1 - 1 -
Depletion, depreciation
and amortization 556 593 1,684 1,748 75 77 233 271 26 43 94 119
Asset retirement
obligation accretion 12 9 32 28 6 8 19 23 - 1 1 2
Realized risk management
loss (gain) 791 (28) 2,162 (53) - 5 (1) 34 - - - -
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES 2,340 1,341 6,976 4,110 207 211 599 693 42 67 157 184
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS BEFORE
THE FOLLOWING 982 798 2,787 2,467 254 185 905 535 142 124 472 287
- --------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration
Stock-based compensation
(recovery) expense
Interest, net
Unrealized risk
management (gain) loss
Foreign exchange loss
(gain)
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED
EXPENSES
- --------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES
Taxes other than income
tax
Current income tax expense
Future income tax expense
- --------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS
================================================================================================================================
CANADIAN NATURAL RESOURCES LIMITED 57
===============================================================================
MIDSTREAM INTER-SEGMENT ELIMINATION AND OTHER TOTAL
(millions of Canadian Three Months Nine Months Three Months Nine Months Three Months Nine Months
dollars, Ended Ended Ended Ended Ended Ended
unaudited) Sep 30 Sep 30 Sep 30 Sep 30 Sep 30 Sep 30
--------- ------- -------- -------- -------- ---------
2008 2007 2008 2007 2008 2007 2008 2007 2008 2007 2008 2007
- -------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE 20 19 60 55 (16) (13) (43) (36) 4,583 3,073 13,662 9,343
Less: royalties - - - - - - - - (612) (341) (1,749) (1,048)
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE, NET 20 19 60 55 (16) (13) (43) (36) 3,971 2,732 11,913 8,295
OF ROYALTIES
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production 6 5 19 16 (3) (2) (8) (4) 639 544 1,836 1,693
Transportation and
blending - - - - (15) (11) (37) (31) 472 359 1,646 1,103
Depletion, depreciation
and amortization 2 2 6 6 - - - - 659 715 2,017 2,144
Asset retirement
obligation accretion - - - - - - - - 18 18 52 53
Realized risk
management loss
(gain) - - - - - - - - 791 (23) 2,161 (19)
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES 8 7 25 22 (18) (13) (45) (35) 2,579 1,613 7,712 4,974
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS
BEFORE THE FOLLOWING 12 12 35 33 2 - 2 (1) 1,392 1,119 4,201 3,321
- --------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration 46 53 134 166
Stock-based compensation
(recovery) expense (308) 78 151 209
Interest, net 25 65 105 225
Unrealized risk
management (gain)
loss (2,506) 76 (983) 555
Foreign exchange loss
(gain) 73 (173) 156 (424)
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED (2,670) 99 (437) 731
EXPENSES
- --------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES 4,062 1,020 4,638 2,590
Taxes other than income
tax 45 40 156 132
Current income tax
expense 171 105 477 257
Future income tax expense 1,011 175 790 391
- --------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS 2,835 700 3,215 1,810
================================================================================================================================
58 CANADIAN NATURAL RESOURCES LIMITED
===============================================================================
NET ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT
Nine Months Ended
SEP 30, 2008 Sep 30, 2007
----------------------------------------------------
NON Non
CASH/FAIR Cash/Fair
NET VALUE CAPITALIZED Net Value Capitalized
EXPENDITURES CHANGES(1) COSTS Expenditures Changes(1) Costs
- --------------------------------------------------------------------------------------------------------------------------------
North America $ 1,858 $ 18 $ 1,876 $ 1,858 $ 11 $ 1,869
North Sea 202 - 202 395 - 395
Offshore West Africa 453 (3) 450 116 - 116
Other 1 - 1 2 - 2
Horizon Project (2) 3,068 - 3,068 2,469 - 2,469
Midstream 6 - 6 4 - 4
Head office 13 - 13 12 - 12
- --------------------------------------------------------------------------------------------------------------------------------
$ 5,601 $ 15 $ 5,616 $ 4,856 $ 11 $ 4,867
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(1) ASSET RETIREMENT OBLIGATIONS, FUTURE INCOME TAX ADJUSTMENTS RELATED TO
DIFFERENCES BETWEEN CARRYING VALUE AND TAX VALUE, AND OTHER FAIR VALUE
ADJUSTMENTS.
(2) NET EXPENDITURES FOR THE HORIZON PROJECT ALSO INCLUDE CAPITALIZED INTEREST
AND STOCK-BASED COMPENSATION.
Property, plant and equipment Total assets
---------------- ------------------
SEP 30 Dec 31 SEP 30 Dec 31
2008 2007 2008 2007
- --------------------------------------------------------------------------------------------------------------------------------
SEGMENTED ASSETS
North America $ 22,238 $ 22,033 $ 23,863 $ 23,617
North Sea 1,839 1,728 2,044 1,957
Offshore West Africa 1,533 1,188 1,653 1,354
Other 26 25 44 41
Horizon Project 11,719 8,651 11,801 8,740
Midstream 205 205 356 333
Head office 68 72 68 72
- --------------------------------------------------------------------------------------------------------------------------------
$ 37,628 $ 33,902 $ 39,829 $ 36,114
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CAPITALIZED INTEREST
The Company capitalizes construction period interest based on Horizon Project
costs incurred and the Company's cost of borrowing. Interest capitalization on a
particular development phase ceases once construction is substantially complete
and this phase of the Horizon Project is available for its intended use. For the
nine months ended September 30, 2008, pre-tax interest of $346 million was
capitalized to the Horizon Project (September 30, 2007 - $247 million).
CANADIAN NATURAL RESOURCES LIMITED 59
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SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with the Company's
continuous offering of medium-term notes pursuant to the short form prospectus
dated September 2007. These ratios are based on the Company's interim
consolidated financial statements that are prepared in accordance with
accounting principles generally accepted in Canada.
Interest coverage ratios for the twelve month period ended September 30, 2008:
- --------------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 7.7x
Cash flow from operations (2) 12.5x
================================================================================
(1) NET EARNINGS PLUS INCOME TAXES AND INTEREST EXPENSE; DIVIDED BY THE SUM OF
INTEREST EXPENSE AND CAPITALIZED INTEREST.
(2) CASH FLOW FROM OPERATIONS PLUS CURRENT INCOME TAXES AND INTEREST EXPENSE;
DIVIDED BY THE SUM OF INTEREST EXPENSE AND CAPITALIZED INTEREST.
60 CANADIAN NATURAL RESOURCES LIMITED
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CONFERENCE CALL
A conference call will be held at 7:00 a.m. Mountain Time, 9:00 a.m. Eastern
Time on Thursday, November 6, 2008. The North American conference call number is
1-866-226-1793 and the outside North American conference call number is
001-416-641-6128. Please call in about 10 minutes before the starting time in
order to be patched into the call. The conference call will also be broadcast
live on the internet and may be accessed through the Canadian Natural website at
www.cnrl.com.
A taped rebroadcast will be available until 6:00 p.m. Mountain Time, Thursday
November 13, 2008. To access the postview in North America, dial 1-800-408-3053.
Those outside of North America, dial 001-416-695-5800. The passcode to use is
3268893.
WEBCAST
This call is being webcast by Vcall and can be accessed on Canadian Natural's
website at WWW.CNRL.COM/INVESTOR_INFO/CALENDAR.HTML.
The webcast is also being distributed over PrecisionIR's Investor Distribution
Network to both institutional and individual investors. Investors can listen to
the call through www.vcall.com or by visiting any of the investor sites in
PrecisionIR's Individual Investor Network.
2008 FOURTH QUARTER RESULTS
2008 fourth quarter results are scheduled for release on Thursday, March 5,
2009. A conference call will be held on that day at 7:00 a.m. Mountain Time,
9:00 a.m. Eastern Time.
For further information, please contact:
CANADIAN NATURAL RESOURCES LIMITED
2500, 855 - 2nd Street S.W.
Calgary, Alberta
T2P 4J8
TELEPHONE: (403) 514-7777 ALLAN P. MARKIN
FACSIMILE: (403) 514-7888 Chairman
EMAIL: IR@CNRL.COM
WEBSITE: WWW.CNRL.COM JOHN G. LANGILLE
Vice-Chairman
TRADING SYMBOL - CNQ STEVE W. LAUT
Toronto Stock Exchange President &
New York Stock Exchange Chief Operating Officer
DOUGLAS A. PROLL
Chief Financial Officer &
Senior Vice-President, Finance
COREY B. BIEBER
Vice-President,
Finance & Investor Relations
CANADIAN NATURAL RESOURCES LIMITED 61
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