CALGARY, ALBERTA (NYSE: CNQ):
Commenting on the Fourth Quarter of 2007 and year end results,
Canadian Natural Chairman, Allan Markin stated, "Another solid year
of value creation was achieved in 2007 reflecting a strong,
well-balanced asset base. Our North American and International
conventional assets provide balance between natural gas and crude
oil, a solid foundation for future growth and generate significant
free cash flow. The Horizon Project, our world class oil sands
project, is targeted to produce first oil in Q3/08, creating
tremendous value for shareholders. We continue to have a direct and
indirect, positive impact on the communities in which we operate
and remain committed to working together with stakeholders in these
communities. This is even more important in today's challenging
environment of cost pressures, commodity price volatility and ever
changing governmental regulation."
John Langille, Vice Chairman, stated, "Our balance sheet ended
the year at 45% debt to book capitalization compared with 51% one
year ago and we will continue to strengthen our balance sheet
during 2008 and into 2009, creating additional flexibility to take
advantage of opportunities as they arise. Based upon strip pricing
and production guidance, we estimate that 2008 cash flow may
approach $6.0 billion, resulting in a targeted 2008 year end debt
to book capitalization of approximately 40%, even after the
announced upward revisions to our 2008 capital cost guidance for
the Horizon Project. We have the financial strength and the ability
to execute on the growth opportunities which we have in the near,
medium and long-term."
Steve Laut, President and Chief Operating Officer of Canadian
Natural commented, "In 2007 we effectively executed on our program
and delivered results at or exceeding our budget at reasonable
costs. Our proved finding and on-stream costs of $14.28 per barrel
of oil equivalent, represents a 12% decrease from 2006. Looking
forward, 2008 is the year of execution for Canadian Natural as we
deliver four major projects. First, Primrose East, the next stage
in the development of our expansive thermal in-situ assets, will
begin steaming in late 2008 and is targeted to add approximately
40,000 bbl/d of capacity in 2009. Secondly, the Olowi project in
Offshore Gabon is targeted to start producing first oil in late
2008 and will reach peak production of 20,000 bbl/d. Thirdly, the
deep water drilling rig for our Baobab project in Offshore Cote
d'Ivoire is expected to arrive in mid-year 2008. It is anticipated
that the resulting repairs to at least three of the five shut-in
Baobab wells, will add up to 10,000 bbl/d of capacity by mid 2009.
Lastly, we are targeting to have first oil at the Horizon Project,
our 110,000 bbl/d oil sands mining project in Q3/08. Again, 2008 is
the year of execution and 2009 is the year of reward."
HIGHLIGHTS
Quarterly Results Year End Results
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($ millions, except
as noted) Q4/07 Q3/07 Q4/06 2007 2006
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Net earnings $ 798 $ 700 $ 313 $ 2,608 $ 2,524
per common share,
basic and diluted $ 1.48 $ 1.30 $ 0.58 $ 4.84 $ 4.70
Adjusted net earnings from
operations (1) $ 546 $ 644 $ 412 $ 2,406 $ 1,664
per common share, basic
and diluted $ 1.02 $ 1.19 $ 0.77 $ 4.46 $ 3.10
Cash flow from
operations (2) $ 1,486 $ 1,577 $ 1,293 $ 6,198 $ 4,932
per common share, basic
and diluted $ 2.75 $ 2.92 $ 2.41 $ 11.49 $ 9.18
Capital expenditures,
net of dispositions $ 1,514 $ 1,442 $ 6,497 $ 6,425 $ 12,025
Daily production, before
royalties
Natural gas (mmcf/d) 1,589 1,647 1,620 1,668 1,492
Crude oil and NGLs
(bbl/d) 337,240 333,062 343,705 331,232 331,998
Equivalent production
(boe/d) 601,908 607,484 613,764 609,206 580,724
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(1) Adjusted net earnings from operations is a non-GAAP measure that the
Company utilizes to evaluate its performance. The derivation of this
item is discussed in the Management's Discussion and Analysis ("MD&A").
(2) Cash flow from operations is a non-GAAP measure that the Company
considers key as it demonstrates the Company's ability to fund capital
reinvestment and debt repayment. The derivation of this measure is
discussed in the MD&A.
Annual
- Total natural gas production in 2007 averaged 1,668 mmcf/d, an
increase of 12% from 2006, primarily due to a full year of
production from the Anadarko Canada Corporation acquisition in
November of 2006. As anticipated, 2007 entry to exit natural gas
production volumes declined but the assets continued to perform
well.
- Total crude oil and NGLs production in 2007 averaged 331,232
bbl/d, a slight decrease from 2006. North America grew 5%, offset
by a decrease in production from the International operations.
- Cash flow from operations increased 26% to $6.2 billion in
2007 from $4.9 billion in 2006, and net earnings increased 3% in
2007 to $2.6 billion from $2.5 billion in 2006. Cash flow was
primarily impacted due to increased sales volumes, higher realized
pricing, and lower realized risk management losses, offset by
increased production expense, higher interest costs, higher current
taxes, and the impact of the stronger Canadian dollar relative to
the US dollar.
Fourth Quarter
- Natural gas production for Q4/07 averaged 1,589 mmcf/d, down
2% from 1,620 mmcf/d for Q4/06 and down 4% from 1,647 mmcf/d for
Q3/07. Volumes in Q4/07 reflected the continued reallocation of
capital towards higher return projects in crude oil.
- Total crude oil and NGLs production for Q4/07 was 337,240
bbl/d. Q4/07 production was 2% lower than Q4/06 volumes of 343,705
bbl/d, and increased from Q3/07 volumes of 333,062 bbl/d. Volumes
in Q4/07 reflect the transition from steam cycles to production
cycles for a number of thermal wells and continued conversion of
production wells to polymer injection wells at Pelican Lake.
- Quarterly cash flow from operations was $1.5 billion, an
increase of 15% from Q4/06 and a decrease of 6% from Q3/07. The
increase from Q4/06 primarily reflected higher crude oil
realizations and the impact of higher sales volumes. The decrease
from Q3/07 represented lower natural gas sales volumes in Q4/07 and
higher risk management losses. Cash flow in Q4/07 continued to be
negatively impacted by the strengthening of the Canadian dollar
compared to the US dollar. The average exchange rate for Q4/07 was
US$0.9810 per C$1.00 compared with US$1.0455 per C$1.00 for Q3/07
and US$1.1388 per C$1.00 for Q4/06.
- Q4/07 quarterly net earnings were $798 million, a 155%
increase from Q4/06 and a 14% increase from Q3/07. Quarterly
adjusted net earnings from operations for Q4/07 were $546 million,
a 33% increase from Q4/06 and a decrease of 15% from Q3/07
results.
- Completed the Q4/07 North America drilling program targeting
172 net crude oil wells and 92 net natural gas wells with a 94%
success rate in the quarter, excluding stratigraphic test and
service wells. The success rate is a reflection of Canadian
Natural's strong, predictable, low-risk asset base.
Operational and Financial
- Maintained a strong undeveloped conventional core land base in
Canada of 12 million net acres - a key asset for continued value
growth.
- Continued production improvements at the Pelican Lake Field
were realized from new drilling activity and the expansion of the
enhanced crude oil recovery program. Pelican Lake crude oil
production averaged approximately 36,000 bbl/d during the quarter,
up 24% or approximately 7,000 bbl/d from Q4/06.
- The Primrose East expansion, which is targeted to add 40,000
bbl/d of capacity, made significant progress and is targeted for
first steaming in Q4/08 and production in 2009.
- Secured a deep water drilling rig for the Baobab Field. The
equipment is targeted to be mobilized in mid-year 2008, enabling
work to begin on the restoration of shut-in production. It is
forecasted that a minimum 3 of the 5 shut-in Baobab wells should
come back on stream over the course of 2008 and 2009.
- The Olowi project in Offshore Gabon continues on track.
Drilling is targeted to commence in Q2/08 and first crude oil is
targeted for late 2008.
- Work progress on the Horizon Oil Sands Project ("Horizon
Project") exited Q4/07 at 90% complete and remains on track for
first oil targeted for Q3/08.
- Independent qualified reserve evaluators evaluated 100% of the
Company's conventional crude oil and natural gas reserves under
constant prices and costs as at December 31, 2007:
-- Total net proved reserves from conventional operations at the
end of 2007 amounted to 1.4 billion barrels of crude oil and NGLs
and 3.7 trillion cubic feet of natural gas. Total net proved
conventional reserves increased modestly from 2006 to 2007.
-- Net proved reserve additions from conventional operations
equaled 110% of 2007 net production, at a finding and on-stream
cost of $14.28 per barrel of oil equivalent. The Company's
three-year average proved finding and on-stream costs were $15.07
per barrel of oil equivalent.
-- Total net proved and probable reserves from conventional
operations at the end of 2007 amounted to 2.1 billion barrels of
crude oil and NGLs and 4.8 trillion cubic feet of natural gas.
Total proved and probable net conventional reserves remained
relatively unchanged from the prior year.
-- Net proved and probable reserve additions from conventional
operations equaled 87% of 2007 net production, at a finding and
on-stream cost of $18.02 per barrel of oil equivalent. The
Company's three-year average net proved and probable finding and
on-stream costs were $11.03 per barrel of oil equivalent. As
anticipated, the significantly reduced drilling program in 2007
resulted in less proved and probable reserves being booked.
-- Using net proved finding and on-stream costs, the Company
achieved an overall recycle ratio of 2.3x during 2007.
- Independent qualified reserve evaluators evaluated 100% of the
Company's Phase 1 to Phase 3 oil sands mining reserves for the
Horizon Project under constant prices as at December 31, 2007,
which resulted in 2.4 billion barrels of gross lease proved bitumen
reserves and 3.5 billion barrels of gross lease proved and probable
bitumen reserves. The gross lease proved synthetic crude oil
reserves increased by 90 million barrels in 2007 to 2.0 billion
barrels. The gross lease proved and probable synthetic crude oil
reserves were 3.0 billion barrels.
- On October 25, 2007 the Province of Alberta issued the
framework of its proposed changes to the Alberta crude oil and
natural gas royalty regime, effective January 1, 2009. The Company
is currently awaiting finalization of the royalty implementation
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.
- In December 2007, the Company issued $400 million of unsecured
notes under a Canadian base shelf prospectus maturing December
2010, bearing interest at 5.50%. 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 which have been sold to investors in the United
States. Net proceeds from the issue of these notes were used to
repay bankers' acceptances.
- For the eighth consecutive year the Company's dividend was
increased. The 2008 quarterly cash dividend on common shares has
been increased to C$0.10 per common share, payable April 1, 2008,
an 18% increase over the 2007 quarterly dividend.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural
focuses its activities in core regions where it can dominate the
land base and infrastructure. Undeveloped land is critical to the
Company's ongoing growth and development within these core regions.
Land inventories are maintained to enable continuous exploitation
of play types and geological trends, greatly reducing overall
exploration risk. By dominating infrastructure, the Company is able
to maximize utilization of its production facilities, thereby
increasing control over production costs. Further, the Company
maintains large project inventories and production diversification
among each of the commodities it produces; namely natural gas,
light/medium and heavy crude oil and NGLs. A large diversified
project portfolio enables the effective allocation of capital to
higher return opportunities.
OPERATIONS REVIEW
Activity by core region
--------------------------------------------
Net undeveloped land Drilling activity
as at year ended
Dec 31, 2007 Dec 31, 2007
(thousands of net acres) (net wells) (1)
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Canadian conventional
Northeast British Columbia 2,401 61
Northwest Alberta 1,489 126
Northern Plains 6,626 636
Southern Plains 925 169
Southeast Saskatchewan 121 28
In-situ Oil Sands 483 192
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12,045 1,212
Horizon Oil Sands Project 115 98
United Kingdom North Sea 287 7
Offshore West Africa 206 5
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12,653 1,322
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(1) Drilling activity includes stratigraphic test and service wells
Drilling activity (number of wells)
Year Ended Dec 31
-----------------------------------
2007 2006
Gross Net Gross Net
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Crude oil 655 592 666 603
Natural gas 478 383 855 641
Dry 107 93 133 119
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Subtotal 1,240 1,068 1,654 1,363
Stratigraphic test / service wells 256 254 376 375
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Total 1,496 1,322 2,030 1,738
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Success rate (excluding stratigraphic
test / service wells) 91% 91%
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North America Conventional
North America natural gas
Quarterly Results Year End Results
-------------------------------------------------
Q4/07 Q3/07 Q4/06 2007 2006
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Natural gas production
(mmcf/d) 1,562 1,622 1,594 1,643 1,468
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Net wells targeting
natural gas 92 106 74 450 732
Net successful wells drilled 80 96 60 383 641
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Success rate 87% 91% 81% 85% 88%
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- Natural gas annual average production increased 12% in 2007 as
compared to 2006 primarily due to a full year of production from
the Anadarko Canada Corporation acquisition in November of
2006.
- Natural gas drilling in 2007 was down 39% from 2006. This
reflects the strategic decision to reduce the natural gas
development due to a high cost environment and the reallocation of
capital to stronger return crude oil projects.
- As anticipated, Q4/07 North America natural gas production
decreased slightly by 2% from Q4/06 and decreased by 4% from Q3/07.
The decrease reflected the Company's strategic decision to scale
back the 2007 drilling program due to reallocating capital to
higher return crude oil projects and natural decline rates.
- Canadian Natural targeted 92 net natural gas wells in Q4/07
including 7 wells in the Northern Plains region, 20 wells in the
Northwest Alberta region, 59 wells in the Southern Plains region
and 6 wells in the Northeast British Columbia region, with an
overall success rate of 87%.
- Planned drilling activity for Q1/08 includes 173 targeted
natural gas wells compared to 245 in Q1/07.
North America crude oil and NGLs
Quarterly Results Year End Results
-------------------------------------------------
Q4/07 Q3/07 Q4/06 2007 2006
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Crude oil and NGLs
production (bbl/d) 256,843 252,095 249,565 246,779 235,253
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Net wells targeting
crude oil 172 153 188 610 619
Net successful wells drilled 168 150 174 584 591
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Success rate 98% 98% 93% 96% 95%
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- 2007 production increased 5% from 2006 to 246,779 bbl/d due to
increased production from Pelican Lake, conventional heavy crude
oil, and light crude oil.
- Q4/07 North America crude oil and NGLs production increased 3%
from Q4/06 and increased 2% over Q3/07 levels. The majority of the
incremental production volume was contributed by thermal crude oil
and Pelican Lake crude oil. The issues in Q3/07 at Primrose as a
result of lightning strikes and water treatment have been resolved
and thermal production recovered as expected in Q4/07.
- 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 approximately 40,000 bbl/d of crude oil. The
Primrose East Expansion received Board of Directors' sanction in
2006 and the Alberta Energy and Utilities Board regulatory approval
in the first quarter of 2007. Drilling and construction are
currently underway, and production is targeted to commence in 2009.
Primrose East is the second phase of the 300,000 bbl/d conventional
expansion plan identified to unlock the value from Canadian
Natural's thermal crude oil resource base.
- In early 2007, Canadian Natural announced its proposed third
phase of the thermal growth plan with a development plan for the
45,000 bbl/d Kirby In-Situ Oil Sands Project located approximately
85 km northeast of Lac La Biche in the Regional Municipality of
Wood Buffalo. The Company has filed its formal regulatory
application documents for this project as part of the Company's
normal course of business.
- Development of new pads and secondary recovery conversion
projects at Pelican Lake continued as expected throughout Q4/07.
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. Pelican Lake production averaged
approximately 36,000 bbl/d for Q4/07 compared to approximately
29,000 bbl/d for Q4/06.
- Conventional heavy crude oil production volumes decreased
slightly in Q4/07 compared to Q3/07, reflecting earlier than
expected declines in certain older fields.
- During Q4/07, drilling activity targeted 172 net wells
including 102 wells targeting heavy crude oil, 18 wells targeting
Pelican Lake crude oil, 11 wells targeting thermal crude oil and 41
wells targeting light crude oil.
- Planned drilling activity for Q1/08 includes 175 net crude oil
wells, excluding stratigraphic test and service wells.
International
Quarterly Results Year End Results
-------------------------------------------------
Q4/07 Q3/07 Q4/06 2007 2006
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Crude oil production (bbl/d)
North Sea 52,709 52,013 61,786 55,933 60,056
Offshore West Africa 27,688 28,954 32,354 28,520 36,689
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Natural gas production (mmcf/d)
North Sea 13 10 16 13 15
Offshore West Africa 14 15 10 12 9
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Net wells targeting crude oil 0.6 2.2 2.3 7.8 11.5
Net successful wells drilled 0.6 2.2 2.3 7.8 11.5
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Success rate 100% 100% 100% 100% 100%
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North Sea
- Crude oil production was down 7% in 2007 to 55,933 bbl/d from
2006 production of 60,056 bbl/d primarily due to lower than
expected performance from the development of the Lyell and Columbia
Fields and water injection challenges encountered at the Ninian
Field.
- During Q4/07 no new wells were completed, however 1.6 net
wells were drilling at quarter end. Production levels during the
quarter were in line with expectations following the successful
completion of planned maintenance in Q3/07 that addressed water
injection challenges experienced at Ninian Field earlier in the
year.
- In December 2007, the Company completed the sale of its entire
working interest in the B-Block, in line with its strategy of
focusing on its core producing areas. The B-Block comprises the
Balmoral, Stirling and Glamis Fields. In 2007, it produced
approximately 1,600 bbl/d net to Canadian Natural, representing
less than 0.5% of Canadian Natural's total crude oil and NGLs
production for the year.
Offshore West Africa
- Offshore West Africa's 2007 crude oil production was 28,520
bbl/d, a 22% decline from 2006 production of 36,689 bbl/d,
primarily from the sanding issues experienced at Baobab.
- During Q4/07, 1.2 net crude oil and injection wells were
drilled with an additional 0.6 net wells drilling at quarter
end.
- The development of West Espoir was successfully completed in
early 2008, with the addition of 5 production wells and 2 water
injection wells during 2007.
- During 2007, the Company awarded a contract for the upgrade of
the Espoir floating production, storage and offtake vessel
("FPSO"), in order to increase the throughput handling capability
of the vessel. Design and procurement work commenced during the
year. Production volumes will not be significantly impacted during
the installation work, scheduled to be completed in late 2009.
- A deep water drilling rig has been secured for the Baobab
Field. Due to the rig's ongoing prior commitments, it is now
targeted to be mobilized mid-year 2008. The Company is targeting to
bring a minimum 3 of 5 of the shut-in Baobab wells back into
production over the course of 2008 and 2009.
- At the 90% owned and operated Olowi Field in offshore Gabon,
all major construction contracts have been awarded. Platform
construction and FPSO conversion are under way. The project is on
schedule with drilling targeted to commence in Q2/08 and first
crude oil production targeted for late 2008.
Horizon Project
- Canadian Natural achieved 90% completion of the Horizon
Project at year end 2007, and remains on track for first oil in the
third quarter of 2008. The remaining 10%, however, is the most
labour intensive portion of the Horizon Project. Unfortunately, mid
to late January and early February saw a significant deterioration
in labour productivity on the construction site as much colder than
normal weather seriously curtailed activity. The weather also
affected the commissioning schedule of certain plants; however, at
present this is not expected to have any impact on the targeted
completion of Phase 1.
- As of December 31, 2007, the forecasted total costs of the
Horizon Project were at 13.4% over the $6.8 billion the Board of
Directors authorized as project sanction. After a thorough review
of the productivity that has recently been experienced at the
Horizon Project construction site, it has been determined that
should no improvements in productivity be achieved through the
remainder of construction, then the cost estimate for Phase 1 of
the Horizon Project would need to be increased to 28% above the
original $6.8 billion Board authorization. If the Horizon Project
regains targeted labour efficiencies and productivity, this overage
could be reduced to approximately 25% above the original $6.8
billion Board authorization. This range of outcomes will result in
an on-stream cost of less than $80,000 bbl/d of capacity, including
the benefits of the significant pre-build capital invested for
Phase 2/3.
- In the fourth quarter of 2007, many significant milestones
were achieved including completion of the tailings pond, filling of
the raw water pond and preparing two tanks to receive start-up
diluent in January 2008. There was some minor slippage in certain
non-critical path plants where mechanical completion has moved from
the end of the second quarter to early in the third quarter - with
no expected impact however on targeted Project completion. The
critical path plants, the Delayed Coker / Diluent Recovery Unit and
Hydrotreater, remain on track for first oil in the third quarter of
2008.
- In parallel with completing major systems, the Horizon Project
is getting ready for operations and has gained significant
momentum. Also, all of the maintenance contracts have been awarded,
with these contractors immediately mobilizing to site in the last
part of the fourth quarter of 2007.
- Canadian Natural remains focused on timely completion of Phase
1, while getting ready to operate the new facilities. Meanwhile,
with Tranche 2 of the next expansion, the Company was immediately
able to award a contract for an additional Ore Preparation Plant to
an existing contractor that is performing well. In addition, other
long lead equipment (Coke Drums and Reactors) for Phase 2/3 will be
delivered to site during Q1/08.
Project Summary
Status Q3/07 Q4/07 Q1/08
Q4/07 Original Q1/08 Original
Actual Actual Forecast Plan Forecast Plan
-------- -------- --------- --------- --------- --------
Phase 1 - Work
progress
(cumulative) 84% 90% 90% 94% 95% 97%
Phase 1 -
Construction
capital spending
(1) (cumulative) 89% 99% 99% 92% 110% 97%
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(1) Relative to overall Phase 1 project capital of $6.8 billion
Accomplished to the end of the Fourth Quarter of 2007
Detailed Engineering
- Overall detailed engineering 98.5% complete and substantially
complete in most areas.
Procurement
- Overall procurement progress is 99% complete.
- Awarded over $5.6 billion in purchase orders and contracts to
date.
- Only one significant contract remains to be awarded for Phase
1 - mechanical for Sulphur Blocking.
- Commenced receipt and site assembly of Mine Operations
Equipment (Shovels and Heavy Haul Trucks).
- Operations and maintenance service and supply agreements have
been awarded.
Modularization
- Delivered an additional 54 oversized loads to site for a total
of 1,560 loads, representing approximately 94% of the total
requirement. Remaining deliveries consist primarily of the balance
of required Mine Operations Equipment (Shovels and Heavy Haul
Trucks).
Construction
- Overall construction progress is 85% complete.
- Mine overburden removal has moved 49.9 million bank cubic
meters, which represents approximately 72% of the total to be moved
and is 0.6 million bank cubic meters ahead of schedule.
- Main Control Room Distributed Control Systems equipment
powered and tested.
- Commissioned 260kV Transmission line and turned over to
operations.
- Commissioned Raw Water Pumphouse and turned over to
operations.
- Completed reformer erection in Hydrogen Plant.
- Completed installation and pre-commissioning of CPI Separator
Building.
- Completed the closure of Dyke 10 (external tailings pond) in
Mining.
- Completed erection of Crushing Plants and conveyors in Ore
Preparation Area.
- Completed Primary Separation Cells in Extraction.
- Completed construction of Main Laboratory.
Milestones for the First Quarter of 2008
- Mechanically complete Extraction Plant.
- Mechanically complete Froth Treatment Plant.
- Mechanically complete Amine Plant.
- Complete Auxiliary Boiler installation in Cogeneration.
- Complete Piping in Heat Integration.
MARKETING Quarterly Results Year End Results
-------------------------------------------------
Q4/07 Q3/07 Q4/06 2007 2006
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Crude oil and NGLs pricing
WTI(1) benchmark price
(US$/bbl) $ 90.63 $ 75.33 $ 60.21 $ 72.40 $ 66.25
Lloyd Blend Heavy oil
differential from
WTI (%) 38% 30% 35% 32% 33%
Corporate average pricing
before risk management
(C$/bbl) $ 58.03 $ 58.10 $ 47.27 $ 55.45 $ 53.65
Natural gas pricing
AECO benchmark price
(C$/GJ) $ 5.69 $ 5.32 $ 6.03 $ 6.26 $ 6.62
Corporate average
pricing before risk
management (C$/mcf) $ 6.28 $ 5.87 $ 6.66 $ 6.85 $ 6.72
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(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
- In Q4/07, the Lloyd Blend heavy crude oil differential as a
percent of WTI was 38%, compared to 30% in Q3/07. The Lloyd Blend
heavy oil differential increased in Q4/07 due to seasonal demand
fluctuations, refinery outages and turn arounds, refiners reducing
their inventory levels decreasing demand, and the common carrier
pipeline disruption in November 2007. Heavy oil differentials in
Q1/08 have improved to approximately 27% of WTI.
- The Company continues efforts towards working with various
industry groups to find new markets, such as the U.S. Gulf Coast
for Western Canadian heavy crude oil and to ease the logistical
constraints in getting crude oil to that area. The heavy crude oil
sold to the Gulf Coast receives Mayan index equivalent pricing, a
premium to the Lloyd Blend price. For Q4/07, the Mayan differential
to WTI averaged US$12.30/bbl or 16%.
- During Q4/07, the Company contributed approximately 155,000
bbl/d of its heavy crude oil streams to the Western Canadian Select
blend as market conditions resulted in this strategy offering the
optimal pricing for bitumen.
- Natural gas inventories in North America continue to remain
high in Q4/07 due to a lack of demand for natural gas and higher
storage levels, resulting from the milder weather, and significant
increases in liquefied natural gas (LNG) imports to the United
States at the beginning of 2007, along with growing production
levels in the United States. These factors contributed to depressed
pricing for natural gas for North America relative to WTI.
FINANCIAL REVIEW
- Canadian Natural has structured its financial position to
profitably grow its conventional crude oil and natural gas
operations over the next several years and to build the financial
capacity to complete the Horizon Project and other major projects.
A brief summary of its strengths are:
-- A diverse asset base geographically and by product - produced
in excess of 601,900 boe/d in Q4/07, comprised of approximately 44%
natural gas and 56% crude oil - with 95% of production located in
G8 countries with stable and secure economies.
-- Financial stability and liquidity - cash flow from operations
of $6.2 billion for the fiscal year 2007, available unused bank
lines of $1.4 billion at December 31, 2007 and access to capital
debt markets supported by strong credit ratings.
-- Reduced volatility of commodity prices - a proactive
commodity hedging program to reduce the downside risk of volatility
in commodity prices supporting cash flow for its capital
expenditure program throughout the Horizon Project.
-- A strengthening balance sheet with debt to book
capitalization of 45% and debt to EBITDA of 1.6 times, both within
our targeted ranges.
- In December 2007, the Company issued $400 million of unsecured
notes maturing December 2010, bearing interest at 5.50%. Subsequent
to December 31, 2007, the Company issued US$1,200 million of
unsecured notes under its 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. Net proceeds
from the issue of these notes were used to repay bankers'
acceptances.
- During 2007, the Company did not purchase any common shares
for cancellation pursuant to the Normal Course Issuer Bid
previously filed for the 12-month period beginning January 24, 2007
and ending January 23, 2008. The Company has decided not to renew
the Normal Course Issuer Bid until subsequent to the completion of
Phase 1 of the Horizon Project.
- Eighth consecutive year of dividend increases. The 2008
quarterly dividend will increase 18% from $0.085 per common share
to $0.10 per common share, effective with the April 1, 2008
payment.
OUTLOOK
The Company forecasts 2008 production levels before royalties to
average between 1,429 and 1,513 mmcf/d of natural gas and between
316,000 and 366,000 bbl/d of crude oil and NGLs. Q1/08 production
guidance before royalties is forecast to average between 1,522 and
1,557 mmcf/d of natural gas and between 315,000 and 331,000 bbl/d
of crude oil and NGLs. Detailed guidance on revised production
levels, capital allocation and operating costs can be found on the
Company's website at
http://www.cnrl.com/investor_info/corporate_guidance/.
YEAR-END RESERVES
Determination of reserves
- For the year ended December 31, 2007, Canadian Natural
retained qualified independent reserve evaluators, Sproule
Associates Limited ("Sproule"), and Ryder Scott Company ("Ryder
Scott"), to evaluate 100% of the Company's conventional proved and
proved and probable crude oil and natural gas reserves and prepare
Evaluation Reports on the Company's total reserves. Sproule
evaluated the Company's North America assets and Ryder Scott
evaluated its international assets. Canadian Natural has been
granted an exemption from National Instrument 51-101 - Standards of
Disclosure for Oil and Gas Activities ("NI 51-101") which
prescribes the standards for the preparation and disclosure of
reserves and related information for companies listed in Canada.
This exemption allows the Company to substitute United States
Securities and Exchange Commission ("SEC") requirements for certain
disclosures required under NI 51-101. There are three principal
differences between the two standards. The first is the requirement
under NI 51-101 to disclose both proved and proved and probable
reserves, as well as the related net present value of future net
revenues using forecast prices and costs. The second is in the
definition of proved reserves; however, as discussed in the
Canadian Oil and Gas Evaluation Handbook ("COGEH"), the standards
that NI 51-101 employs, the difference in estimated proved reserves
based on constant pricing and costs between the two standards is
not material. The third is the requirement to disclose a gross
reserve reconciliation (before the consideration of royalties).
Canadian Natural discloses its reserve reconciliation net of
royalties in adherence to SEC requirements.
- The Company has disclosed proved reserves using constant
prices and costs as mandated by the SEC and has also provided
proved and probable reserves under the same parameters as voluntary
additional information.
- The SEC requires that oil sands mining reserves be disclosed
separately from conventional oil and gas disclosure. Canadian
Natural retained a qualified independent reserve evaluator, GLJ
Petroleum Consultants Ltd. ("GLJ"), to evaluate Phase 1 to Phase 3
of the Company's Horizon Project under SEC Industry Guide 7
requirements.
- The Reserves Committee of the Company's Board of Directors has
met with and carried out independent due diligence procedures with
each of Sproule, Ryder Scott and GLJ as to the Company's
reserves.
Corporate Conventional Net Reserves
- Crude oil, natural gas and NGLs proved reserves increased by
1% replacing 110% of production. This was accomplished at all-in
finding and on-stream cost of $14.28 per barrel of oil equivalent
for proved reserves and $18.02 per barrel of oil equivalent for
proved and probable reserves.
- In the Evaluation Reports, 46% of crude oil and NGLs proved
reserves were assigned to the proved undeveloped category, a 1
percentage point decrease from the 47% recorded in 2006.
- In the Evaluation Reports, 22% of natural gas proved reserves
were assigned to the proved undeveloped category reflecting the
generally shorter lead times required for natural gas developments
in Canada.
- In the Evaluation Reports, total proved and probable reserves
decreased by 1%.
North America Conventional Net Reserves
- Crude oil and NGLs proved reserves increased by 4% replacing
143% of -production. Natural gas proved reserves decreased by 5%
replacing 63% of 2007 production and reflected the Company's
decision to reduce capital spending on natural gas.
International Conventional Net Reserves
- North Sea proved reserves grew by 18 million barrels to 324
million barrels of oil equivalent or 16% of the total proved
Company reserves.
- In Offshore West Africa proved reserves were unchanged at 139
million barrels. This is largely the result of increases in the
year end crude oil price which, in the Cote d'Ivoire evaluation,
accelerates project payout and increases the government royalties
payable.
Horizon Oil Sands Mining Gross Lease Reserves
- The gross lease proved bitumen reserves increased by 110
million barrels to 2.385 billion barrels largely as a result of
Tranche 2 capital spending commitments. The gross lease proved and
probable bitumen reserves decreased 5 million barrels to 3.525
billion barrels.
- The gross lease proved synthetic crude oil reserves increased
by 90 million barrels to 1.956 billion barrels. The gross leased
proved and probable synthetic crude oil reserves decreased 4
million barrels to 2.958 billion barrels.
RESERVES OF CONVENTIONAL CRUDE OIL AND NATURAL GAS, NET OF ROYALTIES(1)
December 31, 2007
Proved Proved Proved Proved and
Developed(2) Undeveloped(2) Total(2) Probable(3)
----------------------------------------------------------------------------
Crude oil and NGLs (mmbbl)
North America 426 494 920 1,545
North Sea 240 70 310 405
Offshore West Africa 70 58 128 186
----------------------------------------------------------------------------
736 622 1,358 2,136
----------------------------------------------------------------------------
Natural gas (bcf)
North America 2,731 790 3,521 4,602
North Sea 58 23 81 113
Offshore West Africa 53 11 64 88
----------------------------------------------------------------------------
2,842 824 3,666 4,803
----------------------------------------------------------------------------
Total reserves (mmboe) 1,210 759 1,969 2,937
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reserve replacement
ratio(4) (%) 110% 87%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cost to develop(5) ($/boe)
10% discount $1.25 $6.73 $3.36 $3.20
15% discount $1.09 $6.43 $3.15 $2.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Present value of
conventional reserves(6)
($ millions)
10% discount $25,767 $8,810 $34,577 $44,286
15% discount $21,924 6,082 $28,006 $34,604
----------------------------------------------------------------------------
----------------------------------------------------------------------------
RESERVES OF CONVENTIONAL CRUDE OIL AND NATURAL GAS, NET OF ROYALTIES(1)
December 31, 2006
Proved Proved Proved Proved and
Developed(2) Undeveloped(2) Total(2) Probable(3)
----------------------------------------------------------------------------
Crude oil and NGLs (mmbbl)
North America 420 467 887 1,502
North Sea 214 85 299 422
Offshore West Africa 63 67 130 195
----------------------------------------------------------------------------
697 619 1,316 2,119
----------------------------------------------------------------------------
Natural gas (bcf)
North America 2,934 771 3,705 4,857
North Sea 17 20 37 93
Offshore West Africa 12 44 56 99
----------------------------------------------------------------------------
2,963 835 3,798 5,049
----------------------------------------------------------------------------
Total reserves (mmboe) 1,191 758 1,949 2,961
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reserve replacement
ratio(4) (%) 295% 472%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cost to develop(5) ($/boe)
10% discount $1.33 $6.46 $3.32 $3.08
15% discount $1.12 $5.80 $2.94 $2.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Present value of
conventional reserves(6)
($ millions)
10% discount $20,028 $7,469 $27,497 $37,291
15% discount $17,296 $5,247 $22,543 $29,350
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OIL SANDS MINING RESERVES(1)(7)
The following table sets out Canadian Natural's reserves of bitumen and
synthetic crude oil from the Horizon Project Oil Sands leases.
As at Dec 31, 2007 As at Dec 31, 2006
Proved Proved and Proved Proved and
Total Probable Total Probable
----------------------------------------------------------------------------
Gross reserves(i) , before
royalties (mmbbl)
Bitumen 2,385 3,525 2,275 3,530
Synthetic crude oil 1,956 2,958 1,866 2,962
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) Represents gross lease reserves.
Synthetic crude oil reserves are based upon upgrading of the bitumen
reserves.
The reserves shown for bitumen and Synthetic crude oil are not additive.
CONVENTIONAL CRUDE OIL AND NGLs RESERVES RECONCILIATION, NET OF ROYALTIES(1)
North North Offshore
America Sea West Africa Total
Proved reserves (mmbbl)
----------------------------------------------------------------------------
Reserves, December 31, 2005 694 290 134 1,118
----------------------------------------------------------------------------
Extensions and discoveries 53 3 - 56
Infill drilling 190 14 - 204
Improved recovery - 12 - 12
Property purchases 26 - - 26
Property disposals - - - -
Production (75) (22) (13) (110)
Revisions of prior estimates (1) 2 9 10
----------------------------------------------------------------------------
Reserves, December 31, 2006 887 299 130 1,316
----------------------------------------------------------------------------
Extensions and discoveries 30 - - 30
Infill drilling 10 6 - 16
Improved recovery 3 - - 3
Property purchases 1 - - 1
Property disposals - (3) - (3)
Production (77) (20) (10) (107)
Revisions of prior estimates 66 28 8 102
----------------------------------------------------------------------------
Reserves, December 31, 2007 920 310 128 1,358
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved and probable reserves (mmbbl)
----------------------------------------------------------------------------
Reserves, December 31, 2005 1,035 417 206 1,658
----------------------------------------------------------------------------
Extensions and discoveries 128 3 - 131
Infill drilling 384 17 - 401
Improved recovery - 12 - 12
Property purchases 34 - - 34
Property disposals - - - -
Production (75) (22) (13) (110)
Revisions of prior estimates (4) (5) 2 (7)
----------------------------------------------------------------------------
Reserves, December 31, 2006 1,502 422 195 2,119
----------------------------------------------------------------------------
Extensions and discoveries 41 - - 41
Infill drilling 52 6 - 58
Improved recovery 4 - - 4
Property purchases 2 6 - 8
Property disposals - (3) - (3)
Production (77) (20) (10) (107)
Revisions of prior estimates 21 (6) 1 16
----------------------------------------------------------------------------
Reserves, December 31, 2007 1,545 405 186 2,136
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CONVENTIONAL NATURAL GAS RESERVES RECONCILIATION, NET OF ROYALTIES(1)
North North Offshore
America Sea West Africa Total
Proved reserves (bcf)
----------------------------------------------------------------------------
Reserves, December 31, 2005 2,741 29 72 2,842
----------------------------------------------------------------------------
Extensions and discoveries 250 - - 250
Infill drilling 71 - - 71
Improved recovery 3 - - 3
Property purchases 1,111 - - 1,111
Property disposals (1) - - (1)
Production (433) (5) (3) (441)
Revisions of prior estimates (37) 13 (13) (37)
----------------------------------------------------------------------------
Reserves, December 31, 2006 3,705 37 56 3,798
----------------------------------------------------------------------------
Extensions and discoveries 134 - - 134
Infill drilling 124 3 - 127
Improved recovery 8 - - 8
Property purchases 12 - - 12
Property disposals - - - -
Production (503) (5) (4) (512)
Revisions of prior estimates 41 46 12 99
----------------------------------------------------------------------------
Reserves, December 31, 2007 3,521 81 64 3,666
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved and probable reserves (bcf)
----------------------------------------------------------------------------
Reserves, December 31, 2005 3,548 69 110 3,727
----------------------------------------------------------------------------
Extensions and discoveries 307 - - 307
Infill drilling 95 - - 95
Improved recovery 4 - - 4
Property purchases 1,466 - - 1,466
Property disposals (1) - - (1)
Production (433) (5) (3) (441)
Revisions of prior estimates (129) 29 (8) (108)
----------------------------------------------------------------------------
Reserves, December 31, 2006 4,857 93 99 5,049
----------------------------------------------------------------------------
Extensions and discoveries 177 - - 177
Infill drilling 163 3 - 166
Improved recovery 8 - - 8
Property purchases 17 1 - 18
Property disposals (1) - - (1)
Production (503) (5) (4) (512)
Revisions of prior estimates (116) 21 (7) (102)
----------------------------------------------------------------------------
Reserves, December 31, 2007 4,602 113 88 4,803
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following information for reserves before royalties is provided for
comparative purposes:
CONVENTIONAL RESERVES, BEFORE ROYALTIES(1)
December 31, 2007
Proved Proved Proved Proved and
Developed(2) Undeveloped(2) Total(2) Probable(3)
----------------------------------------------------------------------------
Crude oil and NGLs (mmbbl)
North America 505 579 1,084 1,806
North Sea 242 69 311 406
Offshore West Africa 81 67 148 218
----------------------------------------------------------------------------
828 715 1,543 2,430
----------------------------------------------------------------------------
Natural gas (bcf)
North America 3,330 945 4,275 5,582
North Sea 58 23 81 113
Offshore West Africa 66 13 79 109
----------------------------------------------------------------------------
3,454 981 4,435 5,804
----------------------------------------------------------------------------
Total reserves (mmboe) 1,404 879 2,282 3,397
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, 2006
Proved Proved Proved Proved and
Developed(2) Undeveloped(2) Total(2) Probable(3)
----------------------------------------------------------------------------
Crude oil and NGLs (mmbbl)
North America 495 548 1,043 1,753
North Sea 214 85 299 421
Offshore West Africa 70 75 145 223
----------------------------------------------------------------------------
779 708 1,487 2,397
----------------------------------------------------------------------------
Natural gas (bcf)
North America 3,587 920 4,507 5,898
North Sea 17 20 37 93
Offshore West Africa 15 54 69 121
----------------------------------------------------------------------------
3,619 994 4,613 6,112
----------------------------------------------------------------------------
Total reserves (mmboe) 1,382 874 2,256 3,416
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CONVENTIONAL FINDING AND ON-STREAM COSTS
Three Year
2007 2006 2005 Total
----------------------------------------------------------------------------
Net reserve replacement expenditures $3,027 $8,727 $3,361 $15,115
($ millions)
Net reserve additions (mmboe) (8)
Proved 212 540 251 1,003
Proved and probable 168 865 337 1,370
Finding and on-stream costs ($/boe)(9)
Proved $14.28 $16.16 $13.41 $15.07
Proved and probable $18.02 $10.09 $9.97 $11.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Reserve estimates and present value calculations are based upon year
end constant reference price assumptions as detailed below as well as
constant year-end costs.
Company WTI @ Hardisty North
Average Cushing Heavy Sea
Price Oklahoma 12 API Brent
Crude oil and NGLs (C$/bbl) (US$/bbl) (C$/bbl) (US$/bbl)
----------------------------------------------------------------------------
2007 $62.87 $96.00 $41.70 $96.02
2006 $51.11 $61.05 $41.94 $58.93
2005 $46.12 $61.04 $32.64 $58.21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Company British Columbia
Average Henry Hub Alberta Huntingdon
Price Louisiana AECO C Sumas
Natural gas (C$/mcf) (US$/mmbtu) (C$/mmbtu) (C$/mmbtu)
----------------------------------------------------------------------------
2007 $6.48 $6.80 $6.52 $6.96
2006 $6.07 $5.52 $6.13 $6.52
2005 $9.45 $10.08 $9.99 $9.53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
A foreign exchange rate of US$1.01/C$1.00 was used in the 2007 evaluation;
US$0.86/C$1.00 was used in the 2006 and 2005 evaluation.
(2) Proved reserve estimates and values were evaluated in accordance with
the SEC requirements. The stated
reserves have a reasonable certainty of being economically recoverable
using year-end prices and costs held constant throughout the productive
life of the properties.
(3) Proved and probable reserve estimates and values were evaluated in
accordance with the standards of the COGEH and as mandated by NI 51-101.
The stated reserves have a 50% probability of equaling or exceeding the
indicated quantities and were evaluated using year-end costs and prices
held constant throughout the productive life of the properties.
(4) Reserve replacement ratios were calculated using annual net reserve
additions comprised of all change categories divided by the net
production for that year.
(5) Cost to develop represents total discounted future capital for each
reserves category excluding abandonment capital divided by the reserves
associated with that category.
(6) Present value of reserves are based upon discounted cash flows
associated with prices and operating expenses held constant into the
future, before income taxes. Future development costs and associated
material well abandonment costs have been applied against future
net revenues.
(7) Synthetic crude oil reserves are based on upgrading of the bitumen
reserves using technologies implemented at the Horizon Project. The
reserve values shown for bitumen and synthetic crude oil are not
additive.
(8) Reserves additions are comprised of all categories of reserves changes,
exclusive of production.
(9) Reserves finding and on-stream costs are determined by dividing total
capital cash expenditures for each year by net reserves additions for
that year. It excludes costs associated with head office, abandonments,
midstream and the Horizon Project.
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 2008 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 interdependent upon other factors,
and the Company's course of action would depend upon its assessment
of the future considering all information then available.
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 year ended December 31, 2007 and the MD&A
and the audited consolidated financial statements for the year
ended December 31, 2006.
All dollar amounts are referenced in millions of Canadian
dollars, except where noted otherwise. The financial statements
have been prepared in accordance with Canadian generally accepted
accounting principles ("GAAP"). This MD&A includes references
to financial measures commonly used in the crude oil and natural
gas industry, such as adjusted net earnings from operations and
cash flow from operations. These financial measures are not defined
by GAAP and therefore are referred to as non-GAAP measures. The
non-GAAP measures used by the Company may not be comparable to
similar measures presented by other companies. The Company uses
these non-GAAP measures to evaluate its performance. The non-GAAP
measures should not be considered an alternative to or more
meaningful than net earnings, as determined in accordance with
GAAP, as an indication of the Company's performance. The measures
adjusted net earnings from operations and cash flow from operations
are reconciled to net earnings in the "Financial Highlights"
section.
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 year and three months ended December 31,
2007 in relation to the comparable periods in 2006 and the third
quarter of 2007. The accompanying tables form an integral part of
this MD&A. This MD&A is dated February 26, 2008. Additional
information relating to the Company, including its Annual
Information Form for the year ended December 31, 2006, is available
on SEDAR at www.sedar.com.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue, before royalties $ 3,200 $ 3,073 $ 2,826 $ 12,543 $ 11,643
Net earnings $ 798 $ 700 $ 313 $ 2,608 $ 2,524
Per common share -
basic and diluted $ 1.48 $ 1.30 $ 0.58 $ 4.84 $ 4.70
Adjusted net earnings
from operations (1) $ 546 $ 644 $ 412 $ 2,406 $ 1,664
Per common share -
basic and diluted $ 1.02 $ 1.19 $ 0.77 $ 4.46 $ 3.10
Cash flow from
operations (2) $ 1,486 $ 1,577 $ 1,293 $ 6,198 $ 4,932
Per common share -
basic and diluted $ 2.75 $ 2.92 $ 2.41 $ 11.49 $ 9.18
Capital expenditures, net
of dispositions $ 1,514 $ 1,442 $ 6,497 $ 6,425 $ 12,025
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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" 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"
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 Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Net earnings as reported $ 798 $ 700 $ 313 $ 2,608 $ 2,524
Stock-based compensation
(recovery) expense, net
of tax(a) (11) 54 120 134 95
Unrealized risk management
loss (gain), net of tax(b) 593 57 (166) 977 (674)
Unrealized foreign exchange
(gain) loss, net of tax(c) (41) (167) 145 (449) 114
Effect of statutory tax
rate and other legislative
changes on future income
tax liabilities(d) (793) - - (864) (395)
----------------------------------------------------------------------------
Adjusted net earnings from
operations $ 546 $ 644 $ 412 $ 2,406 $ 1,664
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) The Company's employee stock option plan provides for a cash payment
option. Accordingly, the intrinsic value of the outstanding vested
options is recorded as a liability on the Company's balance sheet and
periodic changes in the intrinsic value 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 the fair value of non-designated hedges
flowing through net earnings. The amounts ultimately realized may be
materially different than reflected in the financial statements due to
changes in prices of the underlying items hedged, primarily crude oil
and natural gas.
(c) Unrealized foreign exchange gains and losses result primarily from the
translation of US dollar denominated long-term debt to period-end
exchange rates, offset by the impact of cross currency swaps, and are
immediately recognized in net earnings.
(d) All substantively enacted adjustments in applicable income tax rates
and other legislative changes are applied to underlying assets and
liabilities on the Company's balance sheet in determining future income
tax assets and liabilities. The impact of these tax rate changes is
recorded in net earnings during the period the legislation is
substantively enacted. Income tax rate and other legislative changes in
the fourth quarter of 2007 resulted in a reduction of future income tax
liabilities of approximately $793 million in North America. Income tax
rate changes in the second quarter of 2007 resulted in a reduction of
future income tax liabilities of approximately $71 million in North
America. Income tax rate changes in the first quarter of 2006 resulted
in an increase of future income tax liabilities of approximately $110
million in the UK North Sea. Income tax rate changes in the second
quarter of 2006 resulted in a reduction of future income tax
liabilities of approximately $438 million in North America. Income tax
rate changes in the third quarter of 2006 resulted in a reduction of
future income liabilities of approximately $67 million in Cote
d'Ivoire, Offshore West Africa.
Cash Flow from Operations
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Net earnings $ 798 $ 700 $ 313 $ 2,608 $ 2,524
Non-cash items:
Depletion, depreciation
and amortization 719 715 724 2,863 2,391
Asset retirement
obligation accretion 17 18 18 70 68
Stock-based compensation
(recovery) expense (16) 78 176 193 139
Unrealized risk
management loss (gain) 845 76 (241) 1,400 (1,013)
Unrealized foreign
exchange (gain) loss (47) (195) 171 (524) 134
Deferred petroleum
revenue tax expense
(recovery) 17 10 (3) 44 37
Future income tax
(recovery) expense (847) 175 135 (456) 652
----------------------------------------------------------------------------
Cash flow from operations $ 1,486 $ 1,577 $ 1,293 $ 6,198 $ 4,932
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
For the year ended December 31, 2007, the Company reported net
earnings of $2,608 million compared to net earnings of $2,524
million for the year ended December 31, 2006. Net earnings for the
year ended December 31, 2007 included net unrealized after-tax
income of $202 million related to the effects of risk management
activities, fluctuations in foreign exchange rates, stock-based
compensation expense and the impact of statutory tax rate and other
legislative changes on future income tax liabilities, compared to
net unrealized after-tax income of $860 million for the year ended
December 31, 2006. Excluding these items, adjusted net earnings
from operations for the year ended December 31, 2007 increased to
$2,406 million from $1,664 million for the year ended December 31,
2006. The increase from the prior year was primarily due to
increased sales volumes, higher realized pricing, lower realized
risk management losses, and lower income tax expense. These factors
were partially offset by increased production expense, higher
depletion, depreciation and amortization expense, higher interest
expense, and the impact of the stronger Canadian dollar relative to
the US dollar.
Net earnings for the fourth quarter of 2007 were $798 million
compared to net earnings of $313 million for the fourth quarter of
2006 and net earnings of $700 million for the prior quarter. Net
earnings for the fourth quarter of 2007 included net unrealized
after-tax income of $252 million related to the effects of risk
management activities, fluctuations in foreign exchange rates,
stock-based compensation (recovery) expense and the impact of
statutory tax rate and other legislative changes on future income
tax liabilities, compared to net unrealized after-tax expenses of
$99 million for the fourth quarter of 2006 and net unrealized
after-tax income of $56 million for the prior quarter. Excluding
these items, adjusted net earnings from operations for the fourth
quarter of 2007 increased to $546 million from $412 million for the
fourth quarter of 2006 and decreased from $644 million for the
prior quarter. The increase in adjusted net earnings from the
fourth quarter of 2006 was primarily due to the impact of higher
realized pricing and decreased production expense. These factors
were partially offset by higher realized risk management losses and
the impact of the stronger Canadian dollar relative to the US
dollar. The decrease from the prior quarter was primarily due to
increased realized risk management losses on crude oil and the
impact of the stronger Canadian dollar relative to the US dollar,
partially offset by higher realized pricing and decreased
production costs.
The Company expects that consolidated net earnings will continue
to reflect significant quarterly volatility due to the impact of
risk management activities, stock-based compensation (recovery)
expense and fluctuations in foreign exchange rates.
The Company's commodity hedging program reduces the risk of
volatility in commodity price markets and supports the Company's
cash flow for its capital expenditures throughout the Horizon Oil
Sands Project ("Horizon Project") construction period. This program
allows for the hedging of up to 75% of the near 12 months budgeted
production, up to 50% of the following 13 to 24 months estimated
production and up to 25% of production expected in months 25 to 48.
For the purpose of this program, the purchase of crude oil put
options is in addition to the above parameters. In accordance with
the policy, approximately 65% of expected crude oil volumes are
hedged for 2008 and approximately 53% of expected natural gas
volumes are hedged for the first quarter of 2008. Subsequent to
December 31, 2007, the Company hedged 25,000 bbl/d of crude oil
volumes for 2009 using WTI collars with a US$70.00 floor.
The Company's outstanding commodity related financial
derivatives as at December 31, 2007 are detailed on page 48 of this
MD&A.
As disclosed in note 2 to the Company's unaudited interim
consolidated financial statements, commencing January 1, 2007 all
derivative financial instruments are recognized at fair value on
the consolidated balance sheet at each balance sheet date. As
effective as the Company's hedges are against reference commodity
prices, a substantial portion of the derivative financial
instruments entered into by the Company have not been formally
designated as hedges for accounting purposes or do not meet the
requirements for hedge accounting under GAAP due to currency,
product quality and location differentials (the "non-designated
hedges"). The change in the fair value of the non-designated hedges
is based on prevailing forward commodity prices in effect at the
end of each reporting period and is reflected in risk management
activities in consolidated net earnings. The cash settlement amount
of the risk management derivative financial instruments may vary
materially depending upon the underlying crude oil and natural gas
prices at the time of final settlement of the derivative financial
instruments, as compared to their mark-to-market value at December
31, 2007.
Due to the changes in crude oil and natural gas forward pricing
and the reversal of prior-period unrealized gains and losses, the
Company recorded a net unrealized loss of $1,400 million ($977
million after-tax) on its commodity risk management activities for
the year ended December 31, 2007, including an $845 million ($593
million after-tax) unrealized loss for the three months ended
December 31, 2007. Mark-to-market unrealized gains and losses do
not impact the Company's current cash flow or its ability to
finance ongoing capital programs. The Company continues to believe
that its risk management program meets its objective of securing
funding for its capital projects and does not intend to alter its
current strategy of obtaining price certainty for its crude oil and
natural gas sales. For further details, refer to Risk Management
Activities on page 38 of this MD&A.
The Company also recorded a $193 million ($134 million
after-tax) stock-based compensation expense as a result of the 17%
increase in the Company's share price for the year ended December
31, 2007, and a $16 million ($11 million after-tax) stock-based
compensation recovery as a result of the 4% decrease in the
Company's share price for the three months ended December 31, 2007
(Company's share price as at: December 31, 2007 - C$72.58;
September 30, 2007 - C$75.56; December 31, 2006 - C$62.15). 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 the changes in the market price of
the Company's common shares and the options exercised or
surrendered in the period, with the net change recognized in net
earnings, or capitalized as part of the Horizon Project during the
construction period. The stock-based compensation liability at
December 31, 2007 reflected the Company's potential cash liability
assuming all the vested options had been surrendered for a cash
payout at the market price on December 31, 2007. In periods when
substantial share price changes occur, the Company's net earnings
are subject to significant volatility. The Company utilizes its
stock-based compensation plan to attract and retain employees in a
competitive environment. All employees participate in this
plan.
Cash flow from operations for the year ended December 31, 2007
increased to $6,198 million from $4,932 million for the year ended
December 31, 2006. The increase from the comparable period in 2006
was primarily due to increased sales volumes, higher realized
pricing, and lower realized risk management losses, offset by
increased production expense, higher interest costs, higher current
taxes, and the impact of the stronger Canadian dollar relative to
the US dollar.
Cash flow from operations for the fourth quarter of 2007
increased to $1,486 million from $1,293 million for the fourth
quarter of 2006, and decreased from $1,577 million for the prior
quarter. The increase from the fourth quarter of 2006 was primarily
due to the impact of higher realized pricing and lower production
expense, partially offset by increased realized risk management
losses and the impact of the stronger Canadian dollar relative to
the US dollar. The decrease from the prior quarter was primarily
due to lower natural gas production, increased realized risk
management losses on crude oil, higher current taxes, and the
impact of the stronger Canadian dollar relative to the US dollar,
partially offset by increased crude oil production and lower
production costs.
Total production before royalties increased 5% to average
609,206 boe/d for the year ended December 31, 2007 from 580,724
boe/d for the year ended December 31, 2006. Production for the
fourth quarter of 2007 decreased 2% to 601,908 boe/d from 613,764
boe/d for the fourth quarter of 2006 and 1% from 607,484 boe/d for
the prior quarter.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results
for the eight most recently completed quarters:
($ millions, except per common share Dec 31 Sep 30 Jun 30 Mar 31
amounts) 2007 2007 2007 2007
----------------------------------------------------------------------------
Revenue, before royalties $ 3,200 $ 3,073 $ 3,152 $ 3,118
Net earnings $ 798 $ 700 $ 841 $ 269
Net earnings per common share
- Basic and diluted $ 1.48 $ 1.30 $ 1.56 $ 0.50
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common share Dec 31 Sep 30 Jun 30 Mar 31
amounts) 2006 2006 2006 2006
----------------------------------------------------------------------------
Revenue, before royalties (1) $ 2,826 $ 3,108 $ 3,041 $ 2,668
Net earnings $ 313 $ 1,116 $ 1,038 $ 57
Net earnings per common share
- Basic and diluted $ 0.58 $ 2.08 $ 1.93 $ 0.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Blending costs that were netted against gross revenues in prior periods
have been reclassified to transportation expense to conform to the
presentation adopted in the fourth quarter of 2006.
Net earnings over the eight most recently completed quarters
generally reflected fluctuations in realized crude oil and natural
gas prices, fluctuations in sales volumes, the impact of
mark-to-market accounting of financial instruments, increased
depletion, depreciation and amortization charges, 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:
- Crude oil pricing
Crude oil prices reflected demand growth, continued geopolitical
uncertainties and fluctuations in the Heavy Crude Oil Differential
from WTI ("Heavy Differential") in North America.
- Natural gas pricing
Natural gas prices primarily reflected fluctuations in demand
for natural gas and high inventory storage levels as a result of
seasonality, milder overall weather experienced during 2007 and
2006, and increased liquefied natural gas imports into the US
during the first half of 2007.
- 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,
development of West and East Espoir, and additional sales volumes
from the Anadarko Canada Corporation ("ACC") acquisition completed
in the fourth quarter of 2006.
- Natural gas sales volumes
Natural gas sales volumes primarily reflected additional natural
gas volumes as a result of the ACC acquisition and internally
generated growth. The increases were partially offset by production
declines due to the Company's strategic reduction in natural gas
drilling activity.
- 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, offset by the
impact of cross currency swaps.
- Commodity hedges
Net earnings have fluctuated due to the recognition of realized
and unrealized gains and losses from the mark-to-market of the
Company's commodity hedges.
- Changes in income tax expense
Income tax expense and recovery fluctuations include statutory
tax rate and other legislative changes enacted or substantively
enacted in the various periods.
- Stock-based compensation
Net earnings have fluctuated due to the recognition of realized
and unrealized expenses and recoveries from the mark-to-market of
the Company's stock-based compensation liability. Stock-based
compensation expense reflected fluctuations in the Company's share
price over the eight most recently completed quarters.
- Production expense
Production expense has fluctuated company-wide primarily due to
production growth and industry-wide inflationary cost pressures in
all segments.
- Depletion, depreciation and amortization
Depletion, depreciation and amortization expense has increased
primarily due to overall increases in finding and development costs
associated with crude oil and natural gas exploration, increased
estimated future costs to develop the Company's proved undeveloped
reserves, and a higher depletion base in North America related to
the ACC acquisition, together with the impact of higher sales
volumes.
OPERATING HIGHLIGHTS
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
Sales price (2) $ 58.03 $ 58.10 $ 47.27 $ 55.45 $ 53.65
Royalties 6.66 6.65 4.10 5.94 4.48
Production expense 11.53 13.13 12.32 13.34 12.29
----------------------------------------------------------------------------
Netback $ 39.84 $ 38.32 $ 30.85 $ 36.17 $ 36.88
----------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 6.28 $ 5.87 $ 6.66 $ 6.85 $ 6.72
Royalties 0.94 0.89 1.26 1.11 1.29
Production expense 0.91 0.88 0.86 0.91 0.82
----------------------------------------------------------------------------
Netback $ 4.43 $ 4.10 $ 4.54 $ 4.83 $ 4.61
----------------------------------------------------------------------------
Barrels of oil equivalent
($/boe) (1)
Sales price (2) $ 49.23 $ 47.96 $ 43.91 $ 49.05 $ 47.92
Royalties 6.21 6.07 5.62 6.26 5.89
Production expense 8.85 9.62 9.16 9.75 9.14
----------------------------------------------------------------------------
Netback $ 34.17 $ 32.27 $ 29.13 $ 33.04 $ 32.89
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
BUSINESS ENVIRONMENT
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
WTI benchmark price
(US$/bbl) $ 90.63 $ 75.33 $ 60.21 $ 72.40 $ 66.25
Dated Brent benchmark
price (US$/bbl) $ 88.65 $ 74.85 $ 59.68 $ 72.59 $ 65.18
Differential to LLB
blend (US$/bbl) $ 34.07 $ 22.69 $ 21.31 $ 23.05 $ 21.69
LLB blend differential
from WTI (%) 38% 30% 35% 32% 33%
Condensate benchmark
price (US$/bbl) $ 90.89 $ 75.93 $ 59.59 $ 72.88 $ 66.24
NYMEX benchmark price
(US$/mmbtu) $ 7.03 $ 6.13 $ 6.61 $ 6.92 $ 7.26
AECO benchmark price
(C$/GJ) $ 5.69 $ 5.32 $ 6.03 $ 6.26 $ 6.62
US / Cdn dollar average
exchange rate $ 1.0193 $ 0.9565 $ 0.8781 $ 0.9304 $ 0.8818
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$72.40 per
bbl for the year ended December 31, 2007, an increase of 9% from
US$66.25 per bbl for the year ended December 31, 2006. For the
fourth quarter of 2007, WTI averaged US$90.63 per bbl, an increase
of 51% from US$60.21 per bbl for the fourth quarter of 2006, and an
increase of 20% from US$75.33 per bbl for the prior quarter.
Increases in WTI pricing in the fourth quarter reflected continued
strong demand for crude oil and continued geopolitical events
resulting in increased market uncertainty and price volatility. The
WTI reference price, in relation to other world benchmark crude
oils, also benefited from the easing of logistical constraints
experienced during the second quarter, particularly at Cushing,
Oklahoma.
Crude oil sales contracts for the Company's North Sea and
Offshore West Africa segments are typically based on Brent pricing,
which continued to benefit from strong European and Asian demand in
2007. Dated Brent ("Brent") averaged US$72.59 per bbl for the year
ended December 31, 2007, an increase of 11% from US$65.18 per bbl
for the year ended December 31, 2006. For the fourth quarter of
2007, Brent averaged US$88.65 per bbl, an increase of 49% compared
to US$59.68 per bbl for the fourth quarter of 2006, and an increase
of 18% from US$74.85 per bbl for the prior quarter. During the
fourth quarter, the differential between Brent and WTI returned to
more historical levels as logistical constraints at Cushing,
Oklahoma were resolved.
Company-wide, realized crude oil prices for the year ended
December 31, 2007 increased slightly as a result of higher
benchmark WTI pricing and a narrower Heavy Differential in North
America. The Heavy Differential averaged 32% for the year ended
December 31, 2007 compared to 33% for the year ended December 31,
2006. For the fourth quarter of 2007, the Heavy Differential
averaged 38% compared to 35% for the fourth quarter of 2006. The
widening of the Heavy Differential from the comparable period in
2006 was primarily due to increased heavy crude oil production from
Western Canada and reduced demand from US Midwest refineries due to
plant maintenance and unplanned outages. In 2007, realized prices
continued to be adversely impacted by the stronger Canadian
dollar.
The Company anticipates continued volatility in the crude oil
pricing benchmarks due to the unpredictable nature of geopolitical
events and potential unplanned refinery outages. The Heavy
Differential is expected to continue to reflect seasonal demand
fluctuations and refinery cracking margins.
NYMEX natural gas prices averaged US$6.92 per mmbtu for the year
ended December 31, 2007, a decrease of 5% from US$7.26 per mmbtu
for the year ended December 31, 2006. For the fourth quarter of
2007, the NYMEX natural gas price averaged US$7.03 per mmbtu, an
increase of 6% from US$6.61 per mmbtu for the fourth quarter of
2006, and an increase of 15% from US$6.13 per mmbtu for the prior
quarter. AECO natural gas prices decreased 5% to average $6.26 per
GJ for the year ended December 31, 2007, compared to $6.62 per GJ
for the year ended December 31, 2006. For the fourth quarter of
2007 AECO natural gas prices averaged $5.69 per GJ, a decrease of
6% from $6.03 per GJ for the fourth quarter of 2006, and an
increase of 7% from $5.32 per GJ for the prior quarter.
Fluctuations in natural gas prices from the comparable periods in
2006 were primarily related to lower overall demand and higher
storage levels, resulting from the milder weather, reduced economic
activity in the US, and higher liquefied natural gas imports into
the US in the first half of 2007. Natural gas inventory levels in
North America continued to remain high throughout 2007 due to
stable production levels in the US, offset by production declines
in Canada due to reduced drilling activity.
Operating, Royalty and Capital Costs
Strong commodity prices in recent years have resulted in
increased demand and costs for oilfield services worldwide. This
has lead to inflationary operating and capital cost pressures
throughout the North America crude oil and natural gas industry,
particularly related to drilling activities and oil sands
developments. The strong commodity price environment has also
impacted costs in international basins, due in large part to the
high demand for offshore drilling rigs.
The crude oil and natural gas industry is also experiencing cost
pressures related to environmental regulations, both in North
America and internationally. In Canada, the Federal government 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 CO2 annually. In
the UK, GHG regulations have been in effect since 2005. The Company
has strategies in place to ensure compliance with any requirements
now in effect. The additional requirements of enacted and proposed
GHG legislation will add to the cost of executing projects
company-wide.
Continued cost pressures and the final outcome of changes to
environmental regulations may adversely impact the Company's future
net earnings, cash flow and capital projects.
Further, on October 25, 2007, the Province of Alberta issued
certain details of its proposed changes to the Alberta crude oil
and natural gas royalty regime, effective January 1, 2009. These
proposed changes include:
- The implementation of 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
- 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 of the royalty
implementation 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.
PRODUCT PRICES
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)(2)
North America $ 50.49 $ 52.47 $ 40.27 $ 49.16 $ 46.52
North Sea $ 83.44 $ 77.55 $ 67.72 $ 74.99 $ 72.62
Offshore West Africa $ 81.89 $ 70.52 $ 63.50 $ 71.68 $ 67.99
Company average $ 58.03 $ 58.10 $ 47.27 $ 55.45 $ 53.65
Natural gas
($/mcf) (1)(2)
North America $ 6.31 $ 5.88 $ 6.70 $ 6.87 $ 6.77
North Sea $ 3.62 $ 5.26 $ 3.48 $ 4.26 $ 2.66
Offshore West Africa $ 5.49 $ 5.31 $ 5.72 $ 5.68 $ 5.37
Company average $ 6.28 $ 5.87 $ 6.66 $ 6.85 $ 6.72
Company average
($/boe) (1)(2) $ 49.23 $ 47.96 $ 43.91 $ 49.05 $ 47.92
Percentage of gross revenue
(excluding midstream
revenue)(2)
Crude oil and NGLs 66% 67% 60% 62% 64%
Natural gas 34% 33% 40% 38% 36%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 3% to average
$55.45 per bbl for the year ended December 31, 2007 from $53.65 per
bbl for the year ended December 31, 2006. Realized crude oil prices
for the fourth quarter of 2007 increased 23% to average $58.03 per
bbl from $47.27 per bbl for the fourth quarter of 2006, and
decreased marginally from $58.10 per bbl for the prior quarter. The
Company's realized crude oil prices increased from the comparable
periods in 2006 as a result of higher benchmark WTI pricing,
largely offset by the impact of the stronger Canadian dollar. The
decrease from the prior quarter primarily reflected the widening of
the Heavy Differential and the impact of the stronger Canadian
dollar, partially offset by higher benchmark WTI pricing.
The Company's realized natural gas price increased 2% to average
$6.85 per mcf for the year ended December 31, 2007 from $6.72 per
mcf for the year ended December 31, 2006. In the fourth quarter of
2007, the Company's realized natural gas price decreased 6% to
average $6.28 per mcf from $6.66 per mcf in the fourth quarter of
2006, and increased 7% from $5.87 per mcf for the prior quarter.
Fluctuations in natural gas prices from the comparable periods in
2006 and the third quarter of 2007 were primarily related to the
impact of both weather and storage levels.
North America
North America realized crude oil prices increased 6% to average
$49.16 per bbl for the year ended December 31, 2007 from $46.52 per
bbl for the year ended December 31, 2006. Realized crude oil prices
for the fourth quarter of 2007 averaged $50.49 per bbl, a 25%
increase from $40.27 per bbl for the fourth quarter of 2006, and
decreased 4% from $52.47 per bbl for the prior quarter. The
increase in realized crude oil prices from the fourth quarter of
2006 was due to the increase in WTI benchmark pricing, largely
offset by the impact of the stronger Canadian dollar and the
widening of the Heavy Differential, while the decrease from the
prior quarter was due to the widening Heavy Differential and the
impact of the stronger Canadian dollar relative to the US dollar,
partially offset by the increase in 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 fourth quarter, the Company contributed approximately
155,000 bbl/d of heavy crude oil blends to the Western Canadian
Select stream.
North America realized natural gas prices increased 1% to
average $6.87 per mcf for the year ended December 31, 2007 from
$6.77 per mcf for the year ended December 31, 2006. The realized
natural gas price for the fourth quarter of 2007 averaged $6.31 per
mcf, a 6% decrease from $6.70 per mcf for the fourth quarter of
2006, and a 7% increase from $5.88 per mcf for the prior quarter.
Fluctuations in natural gas prices from the comparable periods in
2006 and the third quarter of 2007 were primarily related to the
impact of weather and storage levels.
A comparison of the price received for the Company's North
America production by product type is as follows:
Dec 31 Sep 30 Dec 31
2007 2007 2006
----------------------------------------------------------------------------
Wellhead Price (1) (2)
Light / medium crude oil and NGLs (C$/bbl) $ 74.96 $ 67.55 $ 54.11
Pelican Lake crude oil (C$/bbl) $ 47.01 $ 48.91 $ 37.89
Primary heavy crude oil (C$/bbl) $ 43.30 $ 47.47 $ 36.16
Thermal heavy crude oil (C$/bbl) $ 42.76 $ 48.99 $ 36.06
Natural gas (C$/mcf) $ 6.31 $ 5.88 $ 6.70
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation and blending costs and excluding risk management
activities.
(2) Amounts expressed on a per unit basis are based on sales volumes.
North Sea
North Sea realized crude oil prices increased 3% to average
$74.99 per bbl for the year ended December 31, 2007 from $72.62 per
bbl for the year ended December 31, 2006. Realized crude oil prices
for the fourth quarter of 2007 averaged $83.44 per bbl, a 23%
increase from $67.72 per bbl for the fourth quarter of 2006, and an
8% increase from $77.55 per bbl for the prior quarter. Realized
crude oil prices in the North Sea during the fourth quarter
continued to benefit from the impact of strong European and Asian
demand, partially offset by the impact of the stronger Canadian
dollar relative to the US dollar.
Offshore West Africa
Offshore West Africa realized crude oil prices increased 5% to
average $71.68 per bbl for the year ended December 31, 2007 from
$67.99 per bbl for the year ended December 31, 2006. Realized crude
oil prices for the fourth quarter of 2007 averaged $81.89 per bbl,
a 29% increase from $63.50 per bbl for the fourth quarter of 2006,
and a 16% increase from $70.52 per bbl for the prior quarter. As
all revenue in Offshore West Africa is currently recognized on a
liftings basis, realized crude oil prices per barrel in any
particular quarter are dependant on the frequency and timing of
liftings of each field, as well as the terms of the related sales
contracts. Realized crude oil prices in Offshore West Africa during
the fourth quarter continued to benefit from the impact of strong
European and Asian demand, offset by the impact of the stronger
Canadian dollar relative to the US dollar.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when
title transfers to the customer and delivery has taken place. The
related crude oil inventory volumes by segment, which have not been
recognized in revenue, were as follows:
Dec 31 Sep 30 Dec 31
(bbl) 2007 2007 2006
----------------------------------------------------------------------------
North America, related to pipeline fill 1,097,526 1,097,526 1,097,526
North Sea, related to timing of liftings 1,032,723 260,648 910,796
Offshore West Africa, related to timing
of liftings 8,578 587,486 113,774
----------------------------------------------------------------------------
2,138,827 1,945,660 2,122,096
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the fourth quarter of 2007, net production of approximately
193,000 barrels of crude oil produced in the Company's
international operations was deferred and included in inventory at
December 31, 2007. Notwithstanding the increase in inventory, cash
flow from operations increased by approximately $8 million in the
fourth quarter of 2007 as increased cash flow derived from
additional sales volumes in Offshore West Africa more than offset
the decrease in cash flows due to lower sales volumes in the North
Sea.
DAILY PRODUCTION, before royalties
Three Months Ended Year Ended
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America 256,843 252,095 249,565 246,779 235,253
North Sea 52,709 52,013 61,786 55,933 60,056
Offshore West Africa 27,688 28,954 32,354 28,520 36,689
----------------------------------------------------------------------------
337,240 333,062 343,705 331,232 331,998
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,562 1,622 1,594 1,643 1,468
North Sea 13 10 16 13 15
Offshore West Africa 14 15 10 12 9
----------------------------------------------------------------------------
1,589 1,647 1,620 1,668 1,492
----------------------------------------------------------------------------
Total barrel of oil
equivalent (boe/d) 601,908 607,484 613,764 609,206 580,724
----------------------------------------------------------------------------
Product mix
Light/medium crude oil and
NGLs 23% 22% 24% 23% 26%
Pelican Lake crude oil 6% 6% 5% 6% 5%
Primary heavy crude oil 15% 16% 15% 15% 16%
Thermal heavy crude oil 12% 11% 12% 11% 11%
Natural gas 44% 45% 44% 45% 42%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
DAILY PRODUCTION, net of royalties
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America 217,886 213,680 217,751 210,769 205,382
North Sea 52,586 51,917 61,658 55,825 59,940
Offshore West Africa 25,123 26,158 30,817 26,012 35,212
----------------------------------------------------------------------------
295,595 291,755 310,226 292,606 300,534
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,327 1,373 1,291 1,378 1,185
North Sea 13 10 16 13 15
Offshore West Africa 12 14 9 11 9
----------------------------------------------------------------------------
1,352 1,397 1,316 1,402 1,209
----------------------------------------------------------------------------
Total barrel of oil
equivalent (boe/d) 520,887 524,417 529,515 526,193 502,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Daily production and per barrel statistics are presented
throughout this MD&A on a "before royalty" or "gross" basis.
Production on an "after royalty" or "net" basis is also
presented.
The Company's business approach is to maintain large project
inventories and production diversification among each of the
commodities it produces; namely natural gas, light/medium crude oil
and NGLs, Pelican Lake crude oil, primary heavy crude oil and
thermal heavy crude oil.
Total production averaged 609,206 boe/d for the year ended
December 31, 2007, a 5% increase from the year ended December 31,
2006. Fourth quarter total production in 2007 averaged 601,908
boe/d, a decrease of 2% from 613,764 boe/d for the fourth quarter
of 2006, and a decrease of 1% from 607,484 boe/d for the prior
quarter.
Total crude oil and NGLs production for the year ended December
31, 2007 decreased marginally to 331,232 bbl/d from 331,998 bbl/d
for the year ended December 31, 2006. For the fourth quarter of
2007, production decreased 2% to 337,240 bbl/d from 343,705 bbl/d
for the fourth quarter of 2006 and increased 1% from 333,062 bbl/d
for the prior quarter. The decrease from the comparable periods of
2006 was primarily due to lower production in the North Sea due to
the timing of planned maintenance activities and reduced production
from the Baobab Field in Offshore West Africa, offset by increased
production in North America. Crude oil and NGLs production in the
fourth quarter of 2007 was within the Company's previously issued
guidance of 321,000 to 344,000 bbl/d.
Natural gas production continued to represent the Company's
largest product offering in 2007, accounting for 45% of the
Company's total production. Natural gas production for the year
ended December 31, 2007 averaged 1,668 mmcf/d compared to 1,492
mmcf/d for the year ended December 31, 2006. For the fourth quarter
of 2007, natural gas production averaged 1,589 mmcf/d compared to
1,620 mmcf/d for the fourth quarter of 2006 and 1,647 mmcf/d for
the prior quarter. Natural gas production generally reflects peak
production levels in the spring of each year due to the higher
proportion of wells drilled during the winter months, followed by
natural production declines throughout the remainder of the year.
The decrease in natural gas production from the fourth quarter of
2006 and the prior quarter primarily reflected production declines
due to the Company's strategic reduction in natural gas drilling
activity. Fourth quarter natural gas production was within the
Company's previously issued guidance of 1,577 to 1,616 mmcf/d.
For 2008, annual production guidance is targeted to average
between 316,000 and 366,000 bbl/d of crude oil and NGLs and between
1,429 and 1,513 mmcf/d of natural gas. First quarter 2008
production guidance is targeted to average between 315,000 and
331,000 bbl/d of crude oil and NGLs and between 1,522 and 1,557
mmcf/d of natural gas.
North America
North America crude oil and NGLs production for the year ended
December 31, 2007 increased 5% to average 246,779 bbl/d, up from
235,253 bbl/d for the year ended December 31, 2006. Production for
the fourth quarter of 2007 increased 3% to average 256,843 bbl/d
from 249,565 bbl/d for the fourth quarter of 2006, and increased 2%
from 252,095 bbl/d for the prior quarter. The increase in crude oil
and NGLs production from the prior periods was primarily due to the
results from the Pelican Lake project and the cyclic nature of the
Company's thermal production.
North America natural gas production increased 12% to average
1,643 mmcf/d for the year ended December 31, 2007, up from 1,468
mmcf/d for the year ended December 31, 2006. For the fourth quarter
of 2007, natural gas production decreased 2% to 1,562 mmcf/d from
1,594 mmcf/d for the fourth quarter of 2006, and decreased 4% from
1,622 mmcf/d for the prior quarter. The increase in natural gas
production from the year ended December 31, 2006 reflected the full
year impact of the ACC acquisition, partially offset by production
declines throughout 2007 due to the Company's strategic decision to
reduce natural gas drilling activity.
North Sea
North Sea crude oil production averaged 55,933 bbl/d for the
year ended December 31, 2007, a decrease of 7% from 60,056 bbl/d
for the year ended December 31, 2006. Crude oil production for the
fourth quarter of 2007 decreased 15% to 52,709 bbl/d from 61,786
bbl/d for the fourth quarter of 2006 and increased marginally from
52,013 bbl/d for the prior quarter. Production levels for the
fourth quarter of 2007 were in line with expectations, with the
increase from the prior quarter primarily related to the planned
maintenance shutdowns carried out in the third quarter and the
successful resolution of water injection problems previously
experienced at Ninian.
Offshore West Africa
Offshore West Africa crude oil production decreased 22% to
average 28,520 bbl/d for the year ended December 31, 2007 from
36,689 bbl/d for the year ended December 31, 2006. Fourth quarter
2007 production decreased 14% to 27,688 bbl/d from 32,354 bbl/d for
the fourth quarter of 2006, and was marginally down from 28,954
bbl/d for the prior quarter. Production decreased from the
comparable periods in 2006 due to continued challenges with sand
production at the Baobab Field where 5 of 10 production wells
remain shut in. The Company has secured a deepwater rig, expected
in mid-year 2008, that should enable the Company to execute its
plan to return certain of the shut in wells to production over the
course of 2008 and 2009.
ROYALTIES
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
North America $ 7.66 $ 8.00 $ 5.13 $ 7.19 $ 5.86
North Sea $ 0.19 $ 0.14 $ 0.14 $ 0.14 $ 0.13
Offshore West Africa $ 7.59 $ 6.81 $ 3.02 $ 6.40 $ 2.81
Company average $ 6.66 $ 6.65 $ 4.10 $ 5.94 $ 4.48
Natural gas ($/mcf) (1)
North America $ 0.95 $ 0.90 $ 1.29 $ 1.12 $ 1.31
North Sea $ - $ - $ - $ - $ -
Offshore West Africa $ 0.52 $ 0.51 $ 0.27 $ 0.51 $ 0.22
Company average $ 0.94 $ 0.89 $ 1.26 $ 1.11 $ 1.29
Company average
($/boe) (1) $ 6.21 $ 6.07 $ 5.62 $ 6.26 $ 5.89
Percentage of revenue (2)
Crude oil and NGLs 11% 11% 9% 11% 8%
Natural gas 15% 15% 19% 16% 19%
Boe 13% 13% 13% 13% 12%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North America
North America crude oil and NGLs royalties per bbl for the year
ended December 31, 2007 continue to reflect strong realized crude
oil prices and the impact of the full recovery of the Company's
capital investments in the Primrose North and South Fields in the
fourth quarter of 2006. Upon full recovery, Crown royalty rates on
the Primrose North and South Fields increased from 1% of revenue to
25% of revenue less operating, capital and abandonment costs. Crude
oil and NGLs royalties averaged approximately 15% of revenues for
the year ended December 31, 2007, compared to 13% for 2006. Crude
oil and NGLs royalties per bbl are anticipated to average 14% to
16% of gross revenue for 2008.
Natural gas royalties per mcf generally fluctuate with natural
gas prices. Natural gas royalties averaged approximately 15% of
revenues for the fourth quarter of 2007 compared to 19% for the
fourth quarter of 2006 and 15% for the prior quarter. Natural gas
royalties decreased in the third and fourth quarter of 2007
compared to prior periods in 2006 due to the impact of certain
adjustments, and 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.
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
9% for the fourth quarter of 2007 compared to 5% for fourth quarter
of 2006 and 10% for the prior quarter. The increase in royalty
rates from the comparable period for 2006 was due to the Company's
full recovery of its capital investment in the Espoir Field in 2007
and the resulting increase in profit oil on which the Government's
entitlement is based. Offshore West Africa royalty rates are
anticipated to average 12% to 17% of gross revenue for 2008.
PRODUCTION EXPENSE
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
North America $ 10.54 $ 11.69 $ 12.13 $ 12.26 $ 11.73
North Sea $ 18.95 $ 23.61 $ 14.76 $ 20.78 $ 17.57
Offshore West Africa $ 9.32 $ 7.00 $ 10.05 $ 8.32 $ 7.45
Company average $ 11.53 $ 13.13 $ 12.32 $ 13.34 $ 12.29
Natural gas ($/mcf) (1)
North America $ 0.90 $ 0.87 $ 0.84 $ 0.90 $ 0.81
North Sea $ 1.50 $ 2.29 $ 1.54 $ 2.17 $ 1.40
Offshore West Africa $ 1.89 $ 1.39 $ 2.01 $ 1.48 $ 1.19
Company average $ 0.91 $ 0.88 $ 0.86 $ 0.91 $ 0.82
Company average
($/boe) (1) $ 8.85 $ 9.62 $ 9.16 $ 9.75 $ 9.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America
North America crude oil and NGLs production expense for the year
ended December 31, 2007 increased 5% to $12.26 per bbl from $11.73
per bbl for the year ended December 31, 2006. For the fourth
quarter of 2007 production expense decreased 13% to $10.54 per bbl
from $12.13 per bbl for the fourth quarter of 2006 and decreased
10% from $11.69 per bbl for the prior quarter. The decrease in
production expense per barrel for the fourth quarter of 2007 was a
result of the timing of primary steam cycles, lower cost of natural
gas for fuel for the Company's thermal operations, and higher
production volumes in Pelican Lake and thermal production areas,
where a large portion of costs are fixed in nature.
North America natural gas production expense for the year ended
December 31, 2007 increased 11% to $0.90 per mcf from $0.81 per mcf
for the year ended December 31, 2006. For the fourth quarter of
2007 production expense increased 7% to $0.90 per mcf from $0.84
per mcf for the fourth quarter of 2006 and was up slightly from
$0.87 per mcf for the prior quarter. The increase in production
expense per mcf is a result of lower sales volumes on the fixed
cost portion of production costs, partially offset by the
stabilization of natural gas well servicing costs in the last half
of 2007.
North Sea
North Sea crude oil production expense varied on a per barrel
basis from the prior quarter due to the completion of planned
maintenance shutdowns in the third quarter of 2007, varying
production volumes on a relatively fixed cost base, the timing of
liftings from various fields, and the impact of the stronger
Canadian dollar.
Offshore West Africa
Offshore West Africa crude oil production expense on a per
barrel basis varied from the prior quarter primarily due to the
impact of the timing of liftings at Baobab and Espoir, resulting in
a greater proportion of relatively higher fixed cost Baobab sourced
liftings in the quarter. Production expense was positively impacted
by the impact of the stronger Canadian dollar.
MIDSTREAM
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue $ 19 $ 19 $ 18 $ 74 $ 72
Production expense 6 5 6 22 23
----------------------------------------------------------------------------
Midstream cash flow 13 14 12 52 49
Depreciation 2 2 2 8 8
----------------------------------------------------------------------------
Segment earnings
before taxes $ 11 $ 12 $ 10 $ 44 $ 41
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's midstream assets consist of three crude oil
pipeline systems and a 50% working interest in an 84-megawatt
cogeneration plant at Primrose. Approximately 80% of the Company's
heavy crude oil production is transported to international mainline
liquid pipelines via the 100% owned and operated ECHO Pipeline, the
62% owned and operated Pelican Lake Pipeline and the 15% owned Cold
Lake Pipeline. The midstream pipeline assets allow the Company to
control the transport of its own production volumes as well as earn
third party revenue. This transportation control enhances the
Company's ability to manage the full range of costs associated with
the development and marketing of its heavier crude oil.
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Expense ($ millions) $ 717 $ 713 $ 722 $ 2,855 $ 2,383
$/boe (2) $ 12.99 $ 12.68 $ 12.80 $ 12.84 $ 11.27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) DD&A excludes depreciation on midstream assets.
(2) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, Depreciation and Amortization ("DD&A") for the
year ended December 31, 2007 increased in total and on a boe basis
from the year ended December 31, 2006. DD&A for the fourth
quarter of 2007 was consistent with the prior quarter and the
fourth quarter of 2006. The increase in DD&A expense from the
prior year was primarily due to overall increases in finding and
development costs associated with crude oil and natural gas
exploration, increased estimated future costs to develop the
Company's proved undeveloped reserves, and a higher depletion base
in North America related to the ACC acquisition, together with the
impact of higher sales volumes.
ASSET RETIREMENT OBLIGATION ACCRETION
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Expense ($ millions) $ 17 $ 18 $ 18 $ 70 $ 68
$/boe (1) $ 0.31 $ 0.32 $ 0.32 $ 0.32 $ 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 year and
quarter ended December 31, 2007 was consistent with the comparable
periods.
ADMINISTRATION EXPENSE
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Net expense ($ millions) $ 42 $ 53 $ 57 $ 208 $ 180
$/boe (1) $ 0.76 $ 0.94 $ 1.01 $ 0.93 $ 0.85
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the year ended December 31, 2007
increased in total and on a boe basis from the year ended December
31, 2006 primarily due to increased staffing costs, including costs
related to the Company's share bonus program. The decrease in
administration expense from the prior quarter in 2007 was primarily
due to decreased insurance costs and lower costs associated with
employee bonus programs.
STOCK-BASED COMPENSATION (RECOVERY) EXPENSE
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Stock-based compensation
(recovery) expense $ (16) $ 78 $ 176 $ 193 $ 139
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's Stock Option Plan (the "Option Plan") provides
current employees (the "option holders") with the right to elect to
receive common shares or a direct cash payment in exchange for
options surrendered. The design of the Option Plan balances the
need for a long-term compensation program to retain employees with
the benefits of reducing the impact of dilution on current
Shareholders and the reporting of the obligations associated with
stock options. Transparency of the cost of the Option Plan is
increased since changes in the intrinsic value of outstanding stock
options are recognized each period. The cash payment feature
provides option holders with substantially the same benefits and
allows them to realize the value of their options through a
simplified administration process.
The Company recorded a $193 million ($134 million after-tax)
stock-based compensation expense as a result of the 17% increase in
the Company's share price for the year ended December 31, 2007, and
a $16 million ($11 million after-tax) stock-based compensation
recovery as a result of the 4% decrease in the Company's share
price for the three months ended December 31, 2007 (Company's share
price as at: December 31, 2007 - C$72.58; September 30, 2007 -
C$75.56; December 31, 2006 - C$62.15;). As required by GAAP, the
Company's outstanding stock options are valued each reporting
period based on the difference between the exercise price of the
stock options and the market price of the Company's common shares,
pursuant to a graded vesting schedule. The liability is revalued
quarterly to reflect changes in the market price of the Company's
common shares and the options exercised or surrendered in the
period, with the net change recognized in net earnings, or
capitalized during the construction period in the case of the
Horizon Project. For the year ended December 31, 2007, the Company
capitalized $58 million in stock-based compensation on the Horizon
Project (December 31, 2006 - $79 million). The stock-based
compensation liability reflected the Company's potential cash
liability should all the vested options be surrendered for a cash
payout at the market price on December 31, 2007. In periods when
substantial stock price changes occur, the Company is subject to
significant earnings volatility.
For the year ended December 31, 2007, the Company paid $375
million for stock options surrendered for cash settlement (December
31, 2006 - $264 million).
INTEREST EXPENSE
Three Months Ended Year Ended
-------------------------------------------------
($ millions, except Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
per boe amounts) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Interest expense, gross $ 160 $ 160 $ 128 $ 632 $ 336
Less: capitalized interest,
Horizon Project 109 95 66 356 196
----------------------------------------------------------------------------
Interest expense, net $ 51 $ 65 $ 62 $ 276 $ 140
$/boe (1) $ 0.92 $ 1.15 $ 1.08 $ 1.24 $ 0.66
Average effective
interest rate 5.5% 5.7% 5.6% 5.5% 5.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest expense increased from the comparable periods in
2006 substantially due to increased debt levels associated with the
ACC acquisition in the fourth quarter of 2006 and the ongoing
financing of Horizon Project capital expenditures.
The Company's average effective interest rate for the periods
ended December 31, 2007 reflected the impact of the stronger
Canadian dollar, offset by higher cost US dollar denominated debt
issued in March 2007 and the impact of higher short-term lending
rates on the Company's floating rate debt due to credit market
uncertainty.
In 2008, 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.
These derivative financial instruments are not intended for trading
or speculative purposes.
As disclosed in note 2 to the Company's unaudited interim
consolidated financial statements, commencing January 1, 2007 the
Company adopted new accounting standards issued by the Canadian
Institute of Chartered Accountants relating to the accounting for
and disclosure of financial instruments and comprehensive
income.
Adoption of these standards required the Company to record all
of its derivative financial instruments on the balance sheet at
estimated fair value as at January 1, 2007, including those
designated as hedges. Designated hedges, other than cross currency
swaps, were previously not recognized on the balance sheet but were
disclosed in the notes to the financial statements. The adjustment
to recognize the designated hedges on the balance sheet was
recorded as an adjustment to the opening balance of retained
earnings or accumulated other comprehensive income, as
appropriate.
With the exception of the foreign currency translation
adjustment, these standards were adopted prospectively;
accordingly, comparative amounts for prior periods have not been
restated. The reclassification of the foreign currency translation
adjustment to other comprehensive income was applied retroactively
with prior period restatement.
The effects of adopting these standards on the opening balance
sheet were as follows:
($ millions) Jan 1, 2007
----------------------------------------------------------------------------
Increased current portion of other long-term assets (1) $ 193
Decreased other long-term assets (2) $ (16)
Decreased long-term debt (3) $ (72)
Increased retained earnings (4) $ 10
Increased foreign currency translation adjustment (5) $ 13
Increased accumulated other comprehensive income (6) $ 146
Decreased current portion of future income tax asset (7) $ (62)
Increased future income tax liability (7) $ 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Relates to the recognition of the current portion of the fair value of
derivative financial instruments designated as cash flow hedges.
(2) Relates to the recognition of the long-term portion of the fair value of
derivative financial instruments designated as cash flow and fair value
hedges, as well as the reclassification of transaction costs and
original issue discounts from deferred charges to long-term debt.
(3) Relates to the fair value impact of derivative financial instruments
designated as fair value hedges, as well as the reclassification of
transaction costs and original issue discounts.
(4) Relates to the impact on adoption of the measurement of ineffectiveness
on derivative financial instruments designated as cash flow hedges.
(5) Relates to the retroactive restatement of foreign currency translation
adjustment to accumulated other comprehensive income.
(6) Relates to the recognition of accumulated other comprehensive income
arising from the measurement of effectiveness on derivative financial
instruments designated as cash flow hedges.
(7) Relates to the future income tax impacts of the above noted adjustments.
Effective January 1, 2007, the Company's accounting policies for
financial instruments and comprehensive income are as follows:
All derivative financial instruments are recognized at estimated
fair value on the consolidated balance sheet at each balance sheet
date. The estimated fair value of derivative financial instruments
has been determined based on appropriate internal valuation
methodologies and/or third party indications. However, these
estimates may not necessarily be indicative of the amounts that
could be realized or settled in a current market transaction and
these differences may be material.
The Company formally documents all derivative financial
instruments that are designated as hedging transactions at the
inception of the hedging relationship, in accordance with the
Company's risk management policies. The effectiveness of the
hedging relationship is evaluated, both at inception of the hedge
and on an ongoing basis.
The Company periodically enters into commodity price contracts
to manage anticipated sales of crude oil and natural gas production
in order to protect cash flow for capital expenditure programs. The
effective portion of changes in the fair value of derivative
commodity price contracts designated as cash flow hedges is
initially recognized in other comprehensive income and is
reclassified to risk management activities in consolidated net
earnings in the same period or periods in which the crude oil or
natural gas is sold. The ineffective portion of changes in the fair
value of these designated contracts is immediately recognized in
risk management activities in consolidated net earnings. All
changes in the fair value of non-designated crude oil and natural
gas commodity price contracts are recognized in risk management
activities in consolidated net earnings.
The Company enters into interest rate swap contracts to manage
its fixed to floating interest rate mix on certain of its long-term
debt. The interest rate swap contracts require the periodic
exchange of payments without the exchange of the notional principal
amounts on which the payments are based. Changes in the fair value
of interest rate swap contracts designated as fair value hedges and
corresponding changes in the fair value of the hedged long-term
debt are included in interest expense in consolidated net earnings.
Changes in the fair value of non-designated interest rate swap
contracts are included in risk management activities in
consolidated net earnings.
Cross currency swap contracts are periodically used to manage
currency exposure on US dollar denominated long-term debt. The
cross currency swap contracts require the periodic exchange of
payments with the exchange at maturity of notional principal
amounts on which the payments are based. Changes in the fair value
of the foreign exchange component of cross currency swap contracts
designated as cash flow hedges are included in foreign exchange in
consolidated net earnings. The effective portion of changes in the
fair value of the interest rate component of cross currency swap
contracts designated as cash flow hedges is initially included in
other comprehensive income and is reclassified to interest expense
when realized, with the ineffective portion immediately recognized
in risk management activities in consolidated net earnings. Changes
in the fair value of non-designated cross currency swap contracts
are included in risk management activities in consolidated net
earnings.
Gains or losses on the termination of financial instruments that
have been designated as cash flow hedges are deferred under
accumulated other comprehensive income on the consolidated balance
sheets and amortized into consolidated net earnings in the period
in which the underlying hedged item is recognized. In the event a
designated hedged item is sold, extinguished or matures prior to
the termination of the related derivative instrument, any
unrealized derivative gain or loss is recognized immediately in
consolidated net earnings. Gains or losses on the termination of
financial instruments that have not been designated as hedges are
recognized in consolidated net earnings immediately.
Embedded derivatives are derivatives that are included in a
non-derivative host contract. Embedded derivatives are recorded at
fair value separately from the host contract when their economic
characteristics and risks are not clearly and closely related to
the host contract.
Transaction costs that are directly attributable to the
acquisition or issue of a financial asset or financial liability
and original issue discounts on long-term debt have been included
in the carrying value of the financial asset or liability and are
amortized to consolidated net earnings over the life of the
financial instrument using the effective interest method.
RISK MANAGEMENT
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Realized loss (gain)
Crude oil and NGLs
financial instruments $ 308 $ 102 $ 223 $ 505 $ 1,395
Natural gas financial
instruments (127) (125) (97) (343) (70)
----------------------------------------------------------------------------
$ 181 $ (23) $ 126 $ 162 $ 1,325
----------------------------------------------------------------------------
Unrealized loss (gain)
Crude oil and NGLs
financial instruments $ 770 $ 80 $ (239) $ 1,244 $ (736)
Natural gas financial
instruments 75 (4) 8 156 (260)
Interest rate swaps - - (10) - (17)
----------------------------------------------------------------------------
$ 845 $ 76 $ (241) $ 1,400 $ (1,013)
----------------------------------------------------------------------------
Total $ 1,026 $ 53 $ (115) $ 1,562 $ 312
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The net realized losses (gains) from crude oil and NGLs and natural gas
financial instruments decreased (increased) the Company's average realized
prices as follows:
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1) $ 9.99 $ 3.30 $ 7.09 $ 4.18 $ 11.57
Natural gas ($/mcf) (1) $ (0.87) $ (0.83) $ (0.65) $ (0.56) $ (0.13)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Complete details related to outstanding derivative financial
instruments at December 31, 2007 are disclosed in note 10 to the
Company's unaudited interim consolidated financial statements. As
at December 31, 2006, the net unrecognized asset related to the
estimated fair values of derivative financial instruments
designated as hedges was $222 million.
As effective as the Company's hedges are against reference
commodity prices, a substantial portion of the commodity derivative
financial instruments entered into by the Company have not been
formally designated as hedges for accounting purposes or do not
meet the requirements for hedge accounting under GAAP due to
currency, product quality and location differentials (the
"non-designated hedges"). The change in the fair value of the
non-designated hedges is based on prevailing forward commodity
prices in effect at the end of each reporting period and is
reflected in risk management activities in consolidated net
earnings. The cash settlement amount of the risk management
derivative financial instruments may vary materially depending upon
the underlying crude oil and natural gas prices at the time of
final settlement of the derivative financial instruments, as
compared to their mark-to-market value at December 31, 2007. Due to
changes in the crude oil and natural gas forward pricing, and the
reversal of prior period unrealized gains and losses, the Company
recorded a net unrealized loss of $1,400 million ($977 million
after-tax) on its commodity risk management activities for the year
ended December 31, 2007, including an $845 million ($593 million
after-tax) unrealized loss for the three months ended December 31,
2007 (September 30, 2007 - unrealized loss of $76 million, $57
million after-tax; December 31, 2006 - unrealized gain of $241
million, $166 million after-tax).
FOREIGN EXCHANGE
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Net realized foreign
exchange loss (gain) $ - $ 22 $ (20) $ 53 $ (12)
Net unrealized foreign
exchange (gain) loss (1) (47) (195) 171 (524) 134
----------------------------------------------------------------------------
$ (47) $ (173) $ 151 $ (471) $ 122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency
interest rate swaps as described in Risk Management Activities.
The Company's operating results are affected by fluctuations in
the exchange rates between the Canadian dollar, US dollar, and UK
pound sterling. A majority of the Company's revenue is based on
reference to US dollar benchmark prices. An increase in the value
of the Canadian dollar in relation to the US dollar results in
decreased revenue from the sale of the Company's production.
Conversely, a decrease in the value of the Canadian dollar in
relation to the US dollar results in increased revenue from the
sale of the Company's production. Production expenses 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 gain for the three months
and year ended December 31, 2007 was primarily related to the
strengthening of the Canadian dollar in relation to the US dollar
with respect to the US dollar debt. The net unrealized foreign
exchange gain for the three months ended December 31, 2007 was also
impacted by the re-measurement of North Sea future income tax
liabilities denominated in UK pounds sterling to US dollars.
Included in the net unrealized gain for the year ended December 31,
2007 was an unrealized loss of $350 million (nine months ended
September 30, 2007 - unrealized loss of $335 million) related to
the impact of the cross currency interest rate swaps. The net
realized foreign exchange gain for the year ended December 31, 2007
was primarily due to the result of foreign exchange rate
fluctuations on settlement of working capital items denominated in
US dollars or UK pounds sterling. The Canadian dollar ended the
fourth quarter above parity, at US$1.0120 compared to US$1.0037 at
September 30, 2007 (December 31, 2006 - US$0.8581).
During the first quarter of 2007, the Company de-designated the
portion of the US dollar denominated debt previously hedged against
its net investment in US dollar based self-sustaining foreign
operations. Accordingly, all foreign exchange (gains) losses
arising each period on US dollar denominated long-term debt are now
recognized in the consolidated statement of earnings.
TAXES
Three Months Ended Year Ended
-------------------------------------------------
($ millions, except Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
income tax rates) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Taxes other than income tax
Current $ 16 $ 30 $ 44 $ 121 $ 219
Deferred 17 10 (3) 44 37
----------------------------------------------------------------------------
$ 33 $ 40 $ 41 $ 165 $ 256
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current income tax
North America $ 31 $ 28 $ 51 $ 96 $ 143
North Sea 65 56 30 210 30
Offshore West Africa 27 21 14 74 49
----------------------------------------------------------------------------
123 105 95 380 222
Future income tax (recovery)
expense (847) 175 135 (456) 652
----------------------------------------------------------------------------
(724) 280 230 (76) 874
Income tax rate and other
legislative changes
(1)(2)(3) 793 - - 864 395
----------------------------------------------------------------------------
Total income tax expense $ 69 $ 280 $ 230 $ 788 $ 1,269
----------------------------------------------------------------------------
Effective income tax rate
before non-recurring
benefits 93.2% 28.6% 42.4% 31.1% 37.3%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the effect of a one time recovery of $793 million due to
Canadian Federal income tax rate reductions and other legislative
changes enacted or substantively enacted during the fourth quarter of
2007.
(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.
(3) Includes the effect of the following:
- a one time expense of $110 million related to the increased
supplementary charge on oil and gas profits in the UK North Sea,
substantively enacted during the first quarter of 2006.
- a one time recovery of $438 million due to Canadian Federal, Alberta
and Saskatchewan tax rate reductions enacted during the second
quarter of 2006.
- a one time recovery of $67 million due to Cote d'Ivoire corporate
income tax rate reductions enacted during the third quarter of 2006.
Taxes other than income tax primarily includes current and
deferred petroleum revenue tax ("PRT"). PRT is charged on certain
fields in the North Sea at the rate of 50% of net operating income,
after allowing for certain deductions including abandonment
expenditures.
Taxable income from the conventional crude oil and natural gas
business in Canada is primarily generated through partnerships,
with the related income taxes payable in a future period. North
America current income taxes have been provided on the basis of the
corporate structure and available income tax deductions and will
vary depending upon the nature, timing and amount of capital
expenditures incurred in Canada in any particular year. In
particular, current taxes in a specific year are sensitive to the
timing of when the Horizon Project capital expenditures are
deductible for Canadian income tax purposes.
During the year ended December 31, 2007, the Company's
consolidated effective income tax rate was reduced primarily due to
income tax rate reductions enacted in Canada during the second and
fourth quarters of 2007, the effects of the non-taxable portion of
unrealized foreign exchange gains on US dollar debt, net of
unrealized losses on cross currency swaps, and adjustments to
future tax expense in Canada related to the final phase-in of
deductibility of crown royalties and the elimination of the
resource allowance deduction in 2007.
CAPITAL EXPENDITURES (1)
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Expenditures on property,
plant and equipment
Net property (dispositions)
acquisitions $ (107) $ 7 $ 4,720 $ (39) $ 4,733
Land acquisition and
retention 15 29 28 95 210
Seismic evaluations 17 23 17 124 130
Well drilling, completion
and equipping 341 299 462 1,642 2,340
Production and related
facilities 390 238 311 1,205 1,314
----------------------------------------------------------------------------
Total net reserve replacement
expenditures 656 596 5,538 3,027 8,727
----------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 691 671 745 2,740 2,768
Phases 2/3 costs 33 28 54 124 79
Capitalized interest,
stock-based
compensation and other 108 120 134 437 338
----------------------------------------------------------------------------
Total Horizon Project 832 819 933 3,301 3,185
----------------------------------------------------------------------------
Midstream 2 2 1 6 12
Abandonments (2) 16 22 19 71 75
Head office 8 3 6 20 26
----------------------------------------------------------------------------
Total net capital
expenditures $ 1,514 $ 1,442 $ 6,497 $ 6,425 $ 12,025
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 570 $ 441 $ 5,296 $ 2,428 $ 7,936
North Sea 44 121 211 439 646
Offshore West Africa 43 34 30 159 134
Other (1) - 1 1 11
Horizon Project 832 819 933 3,301 3,185
Midstream 2 2 1 6 12
Abandonments (2) 16 22 19 71 75
Head office 8 3 6 20 26
----------------------------------------------------------------------------
Total $ 1,514 $ 1,442 $ 6,497 $ 6,425 $ 12,025
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The net capital expenditures exclude adjustments related to
differences between carrying value and tax value.
(2) Abandonments represent expenditures to settle asset retirement
obligations and have been reflected as capital expenditures in this
table.
The Company's strategy is focused on building a diversified
asset base that is balanced among various products. In order to
facilitate efficient operations, the Company concentrates its
activities in core regions where it can dominate the land base and
infrastructure. The Company focuses on maintaining its land
inventories to enable the continuous exploitation of play types and
geological trends, greatly reducing overall exploration risk. By
dominating infrastructure, the Company is able to maximize
utilization of its production facilities, thereby increasing
control over production costs.
Net capital expenditures for the year ended December 31, 2007
were $6,425 million compared to $12,025 million for the year ended
December 31, 2006. Excluding the ACC acquisition, net capital
expenditures were $7,270 million for 2006. Capital expenditures in
2007 reflected the continued progress on the Company's larger,
future growth projects, most notably the Horizon Project, as well
as continued industry-wide inflationary pressures, offset by the
effects of an overall strategic reduction in the North America
natural gas drilling program.
For the year ended December 31, 2007, the Company drilled a
total of 1,322 net wells consisting of 383 natural gas wells, 592
crude oil wells, 254 stratigraphic test and service wells and 93
wells that were dry. This compared to 1,738 net wells drilled for
the year ended December 31, 2006. The Company achieved an overall
success rate of 91% for the year ended December 31, 2007, excluding
stratigraphic test and service wells, consistent with the year
ended December 31, 2006.
Net capital expenditures for the fourth quarter of 2007 were
$1,514 million compared to $6,497 million for the fourth quarter of
2006 and $1,442 million for the prior quarter. Excluding the ACC
acquisition, net capital expenditures were $1,742 million for the
fourth quarter of 2006. Fourth quarter 2007 capital expenditures
decreased from the comparable period in 2006 due to the Company's
strategic reduction in natural gas drilling activity, and increased
slightly from the third quarter of 2007 due to normal drilling
seasonality.
For the fourth quarter of 2007, the Company drilled a total of
271 net wells consisting of 80 natural gas wells, 169 crude oil
wells, 6 stratigraphic test and service wells and 16 wells that
were dry. This compared to 331 net wells for the fourth quarter of
2006 and 268 net wells for the prior quarter. The Company achieved
an overall success rate of 94% for the fourth quarter of 2007,
excluding stratigraphic test and service wells, compared to 89% for
the fourth quarter of 2006 and 95% for the third quarter of
2007.
North America
North America, including the Horizon Project, accounted for
approximately 91% of the total capital expenditures for the year
ended December 31, 2007 compared to approximately 93% for the year
ended December 31, 2006.
During the year ended December 31, 2007, the Company targeted
450 net natural gas wells, including 58 wells in Northeast British
Columbia, 133 wells in the Northern Plains region, 110 wells in
Northwest Alberta, and 149 wells in the Southern Plains region. The
Company also targeted 610 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 362 heavy crude
oil wells, 127 Pelican Lake crude oil wells, 55 thermal crude oil
wells and 6 light crude oil wells were drilled. Another 60 wells
targeting light crude oil were drilled outside the Northern Plains
region.
Due to significant changes in relative commodity prices between
crude oil and natural gas, the Company continues to access its
large crude oil drilling inventory to maximize value in both the
short and long term. Due to the Company's focus on drilling crude
oil wells in 2007, natural gas drilling activities were reduced to
manage overall capital spending. Deferred natural gas well
locations have been retained in the Company's prospect inventory.
Drilling on ACC acquired lands was optimized as part of the overall
capital program.
In November of 2005, the Company announced a phased expansion of
its In-Situ Oil Sands Assets. As part of the development, the
Company is continuing to develop its Primrose thermal projects.
During 2007, the Company drilled 135 stratigraphic test wells and
observation wells, 2 water source wells and 55 thermal oil wells.
Overall Primrose thermal production for each of the years ended
December 31, 2007 and 2006 was approximately 64,000 bbl/d.
The Primrose East Expansion, a new facility located 15
kilometers from the existing Primrose South steam plant and 25
kilometers from the Wolf Lake central processing facility, is
anticipated to add approximately 40,000 bbl/d when complete. The
Primrose East Expansion received Board of Directors' sanction in
2006 and the Alberta Energy and Utilities Board regulatory approval
in the first quarter of 2007. Drilling and construction are
currently underway, and production is targeted to commence in
2009.
The next phase of the Company's In-Situ Oil Sands Assets
expansion is the Kirby project located 120 kilometers north of the
existing Primrose facilities. The Kirby project is anticipated to
add approximately 45,000 bbl/d of production growth. During
September 2007, the Company filed a combined application and
Environmental Impact Assessment for this project with Alberta
Environment and the Alberta Energy and Utilities Board. Final
corporate sanction 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
fourth quarter of 2007. Drilling consisted of 18 horizontal wells
in the fourth quarter and 125 horizontal wells for the year ended
December 31, 2007. The response from the water and polymer flood
projects continues to be positive. Pelican Lake production averaged
approximately 36,000 bbl/d for the fourth quarter of 2007 compared
to 29,000 bbl/d for the fourth quarter of 2006.
Due to growing concerns relating to increased environmental
costs for upgraders located in Canada, inflationary capital cost
pressures and narrowing heavy oil differentials in North America,
the Company has, at this point in time, deferred the Design Basis
Memorandum and Engineering Design Specification of the Canadian
Natural Upgrader, outside of the Horizon Project, pending
clarification on the cost of future environmental legislation and a
more stable cost environment.
For the first quarter of 2008, the Company's overall drilling
activity in North America is expected to be comprised of 173
natural gas wells and 175 crude oil wells excluding stratigraphic
and service wells.
Horizon Project
Work progress on the Horizon Project was 90% complete at the end
of the fourth quarter. First production continues to be targeted to
commence in the third quarter of 2008. The project status as at
December 31, 2007 was as follows:
- Overall detailed engineering 98.5% complete and substantially
complete in most areas;
- Overall procurement 99% complete with over $5.6 billion in
purchase orders and contracts awarded;
- Commenced receipt and site assembly of Mine Operations
equipment (Shovels and Heavy Haul Trucks);
- Overall construction progress 85% complete;
- Mine overburden removal approximately 72% complete and 0.6
million bank cubic meters ahead of schedule;
- Main Control Room Distributed Control Systems equipment
powered and tested;
- Commissioned 260kV Transmission Line and turned over to
operations;
- Commissioned Raw Water Pumphouse and turned over to
operations;
- Completed reformer erection in Hydrogen Plant;
- Completed installation and pre-commissioning of CPI Separator
Building;
- Completed the closure of Dyke 10 (external tailings pond) in
Mining;
- Completed erection of Crushing Plants and conveyors in Ore
Preparation Area;
- Completed Primary Separation Cells in Extraction; and
- Completed construction of Main Laboratory.
Major activities for the first quarter of 2008 include:
- Mechanically complete Extraction Plant;
- Mechanically complete Froth Treatment Plant;
- Mechanically complete Amine Plant;
- Complete Auxiliary Boiler installation in Cogeneration;
and
- Complete Piping in Heat Integration.
The Company has budgeted construction costs of approximately
$1.7 billion to $1.9 billion for 2008 related to the planned
completion of Phase 1 of the Horizon Project.
North Sea
In the fourth quarter of 2007, the Company continued with its
planned program of infill drilling, recompletions, workovers and
waterflood optimizations. During the quarter, no wells were
drilled, with 1.6 net wells drilling at the end of the quarter.
At Ninian, the Company continued with its planned investment in
its long-term facilities and infrastructure strategy, as well as
completing workover activity to address water injection performance
issues. Upon completion of this activity, the drilling crew was
mobilized to the Murchison Platform to commence the first of 2
wells planned for 2008.
In December 2007, the Company completed the sale of its entire
working interest in the B-Block, comprising the Balmoral, Stirling,
and Glamis Fields.
Offshore West Africa
During the fourth quarter of 2007, 1.2 net wells were drilled
with 0.6 net wells drilling at the end of the quarter.
First crude oil from West Espoir commenced production in mid
2006 with 1 additional production well and 1 additional injector
well added during the fourth quarter of 2007. West Espoir
development drilling was completed in early 2008, on budget and on
schedule.
At the 90% owned and operated Olowi Field in offshore Gabon, all
major construction contracts have been awarded and construction
activity on the wellhead towers and the floating production storage
and offtake vessel ("FPSO") are ongoing. The project is on schedule
with drilling targeted to commence in the second quarter of 2008
and first crude oil targeted in late 2008. Olowi production is
targeted to plateau at approximately 20,000 bbl/d net to the
Company.
LIQUIDITY AND CAPITAL RESOURCES
Dec 31 Sep 30 Dec 31
($ millions, except ratios) 2007 2007 2006
----------------------------------------------------------------------------
Working capital deficit (1) $ 1,382 $ 824 $ 832
Long-term debt (2) $ 10,940 $ 10,686 $ 11,043
Shareholders' equity
Share capital $ 2,674 $ 2,663 $ 2,562
Retained earnings 10,575 9,824 8,141
Accumulated other comprehensive income (loss) 72 85 (13)
----------------------------------------------------------------------------
Total $ 13,321 $ 12,572 $ 10,690
Debt to book capitalization (2)(3) 45% 46% 51%
Debt to market capitalization (2)(4) 22% 21% 25%
After tax return on average common
shareholders' equity (5) 22% 19% 27%
After tax return on average capital
employed (2)(6) 12% 11% 17%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated as current assets less current liabilities.
(2) Long-term debt at December 31, 2007 is stated at its carrying value, net
of fair value adjustments, original issue discounts and transactions
costs. Amounts for periods prior to January 1, 2007 were not adjusted
for these items.
(3) Calculated as 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 $7,001
million in average capital employed related to the Horizon Project
(2006 - $3,760 million; 2005 - $1,421 million).
The Company's capital resources at December 31, 2007 consisted
primarily of cash flow from operations, available credit facilities
and access to debt capital markets. Cash flow from operations is
dependent on factors discussed in the Risks and Uncertainties
section of the Company's December 31, 2006 annual MD&A. The
Company's ability to renew existing credit facilities and raise new
debt is also dependent upon these factors, as well as maintaining
an investment grade debt rating and the condition of capital and
credit markets. Management believes internally generated cash flows
supported by the implementation of the Company's hedge policy, the
flexibility of its capital expenditure programs supported by its
multi-year financial plans, the Company's existing credit
facilities and the Company's ability to raise new debt on
commercially acceptable terms, will be sufficient to sustain its
operations and support its growth strategy. The Company's current
debt ratings are BBB (high) with a negative trend by DBRS Limited,
Baa2 with a stable outlook by Moody's Investors Service and BBB
with a stable outlook by Standard & Poor's. The Company does
not have any direct exposure to asset-backed commercial paper.
At December 31, 2007, the Company had undrawn bank lines of
credit of $1,442 million. Details related to the Company's
long-term debt at December 31, 2007 are disclosed in note 4 to the
Company's unaudited interim consolidated financial statements.
Subsequent to December 31, 2007, the Company issued an aggregate
US$1,200 million of unsecured notes. Proceeds from the securities
issued were used to repay the Company's bankers' acceptances.
At December 31, 2007, the Company's working capital deficit was
$1,382 million and included the current portion of the stock-based
compensation liability of $390 million and the current portion of
the net mark-to-market liability for risk management derivative
financial instruments of $1,227 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 December 31, 2007.
The Company believes it has the necessary financial capacity to
complete the Horizon Project, while at the same time not
compromising conventional crude oil and natural gas growth
opportunities. The financing of Phase 1 of the Horizon Project
development is guided by the competing principles of retaining as
much direct ownership interest as possible while maintaining a
strong balance sheet.
Long-term debt was $10,940 million at December 31, 2007,
resulting in a debt to book capitalization level of 45% (September
30, 2007 - 46%; December 31, 2006 - 51%). While this ratio is at
the high end of the 35% to 45% range targeted by management, the
Company remains committed to maintaining a strong balance sheet and
flexible capital structure, and expects its debt to book
capitalization ratio to be near the midpoint of the range in late
2008. While the Company believes that it has the balance sheet
strength and flexibility to complete Phase 1 of the Horizon
Project, as well as its other planned capital expenditure programs,
the Company has hedged a significant portion of its crude oil and
natural gas production for 2008 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 price markets and supports the Company's
cash flow for its capital expenditures throughout the Horizon
Project construction period. This program allows for the hedging of
up to 75% of the near 12 months budgeted production, up to 50% of
the following 13 to 24 months estimated production and up to 25% of
production expected in months 25 to 48. For the purpose of this
program, the purchase of crude oil put options is in addition to
the above parameters. In accordance with the policy, approximately
65% of expected crude oil volumes are hedged for 2008 and
approximately 53% of expected natural gas volumes are hedged for
the first quarter of 2008. Subsequent to December 31, 2007, the
Company hedged 25,000 bbl/d of crude oil volumes for 2009 using WTI
collars with a US$70.00 floor.
The Company has the following commodity related net financial
derivatives outstanding as at December 31, 2007:
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Crude oil
Crude oil price
collars (1) Jan 2008-Mar 2008 50,000 bbl/d US$60.00-US$80.06 WTI
Jan 2008-Jun 2008 25,000 bbl/d US$60.00-US$80.44 WTI
Apr 2008-Sep 2008 25,000 bbl/d US$60.00-US$80.46 WTI
Jul 2008-Sep 2008 25,000 bbl/d US$70.00-US$123.75 WTI
Oct 2008-Dec 2008 25,000 bbl/d US$70.00-US$112.63 WTI
Mayan
Jan 2008-Dec 2008 20,000 bbl/d US$50.00-US$65.53 Heavy
Jan 2008-Dec 2008 50,000 bbl/d US$60.00-US$75.22 WTI
Jan 2008-Dec 2008 50,000 bbl/d US$60.00-US$76.05 WTI
Jan 2008-Dec 2008 50,000 bbl/d US$60.00-US$76.98 WTI
Crude oil puts Jan 2008-Dec 2008 50,000 bbl/d US$55.00 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to December 31, 2007, the Company entered into 25,000 bbl/d
of US$70.00-US$111.56 WTI collars for the period January to December
2009.
----------------------------------------------------------------------------
Natural gas
AECO price
collars Jan 2008-Mar 2008 400,000 GJ/d C$7.00-C$14.08 AECO
Jan 2008-Mar 2008 500,000 GJ/d C$7.50-C$10.81 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's outstanding commodity financial derivatives are
expected to be settled monthly based on the applicable index
pricing for the respective contract month.
Long-term debt
As at December 31, 2007, the Company had in place unsecured bank
credit facilities of $6,209 million, comprised of:
- a $100 million demand credit facility;
- a non-revolving syndicated credit facility of $2,350 million
maturing October 2009;
- a revolving syndicated credit facility of $2,230 million
maturing June 2012;
- a revolving syndicated credit facility of $1,500 million
maturing June 2012; and
- a Pounds Sterling 15 million demand credit facility related to
the Company's North Sea operations.
During the second quarter of 2007, one of the revolving
syndicated credit facilities was increased from $1,825 million to
$2,230 million and a $500 million demand credit facility was
terminated. The revolving syndicated credit facilities were
extended and now mature June 2012. Both facilities are extendible
annually for one year periods at the mutual agreement of the
Company and the lenders. If the facilities are not extended, the
full amount of the outstanding principal would be repayable on the
maturity date.
In conjunction with the closing of the acquisition of ACC in
November 2006, the Company executed a $3,850 million, non-revolving
syndicated credit facility maturing in October 2009. In March 2007,
$1,500 million was repaid, reducing the facility to $2,350
million.
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $345 million, including $300
million related to the Horizon Project, were outstanding at
December 31, 2007.
Medium-term notes
In December 2007, the Company issued $400 million of unsecured
notes maturing December 2010, bearing interest at 5.50%. Proceeds
from the securities issued were used to repay bankers' acceptances
under the Company's bank credit facilities. After issuing these
securities, the Company has $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.
During the first quarter of 2007, $125 million of 7.40%
unsecured debentures due March 1, 2007 were repaid.
Senior unsecured notes
During the second quarter of 2007, US$31 million of the senior
unsecured notes were repaid.
US dollar debt securities
In March 2007, the Company issued US$2,200 million of unsecured
notes, comprised of US$1,100 million of unsecured notes maturing
May 2017 and US$1,100 million of unsecured notes maturing March
2038, bearing interest at 5.70% and 6.25%, respectively.
Concurrently, the Company entered into cross currency interest rate
swaps to fix the Canadian dollar interest and principal repayment
amounts on the entire US$1,100 million of unsecured notes due May
2017 at 5.10% and C$1,287 million. The Company also entered into a
cross currency interest rate swap to fix the Canadian dollar
interest and principal repayment amounts on US$550 million of
unsecured notes due March 2038 at 5.76% and C$644 million. Proceeds
from the securities issued were used to repay bankers' acceptances
under the Company's bank credit facilities.
During the first quarter of 2007, the Company de-designated the
portion of its US dollar denominated debt previously hedged against
its net investment in US dollar based self-sustaining foreign
operations. Accordingly, all foreign exchange (gains) losses
arising each period on U.S. dollar denominated long-term debt are
now recognized in the consolidated statement of earnings.
In September 2007, the Company filed a base shelf prospectus
that allows for the issue of up to US$3,000 million of debt
securities in the United States until October 2009.
Subsequent to December 31, 2007, the Company issued US$1,200
million of unsecured notes under this 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. If issued, these securities will bear interest as
determined at the date of issuance.
Share capital
As at December 31, 2007, there were 539,729,000 common shares
outstanding and 30,649,000 stock options outstanding. As at
February 26, 2008, the Company had 540,252,000 common shares
outstanding and 29,173,000 stock options outstanding.
During 2007, the Company did not purchase any common shares for
cancellation pursuant to the Normal Course Issuer Bid previously
filed for the 12-month period beginning January 24, 2007 and ending
January 23, 2008. The Company has decided not to renew the Normal
Course Issuer Bid until subsequent to the completion of Phase 1 of
the Horizon Project.
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 a 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. In March 2007, an
increase in the annual dividend paid by the Company was approved to
$0.34 per common share for 2007. The increase represented a 13%
increase from 2006.
Commitments and off balance sheet arrangements
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. These commitments primarily relate to debt
repayments, operating leases relating to offshore FPSOs, drilling
rigs and office space, and firm commitments for gathering,
processing and transmission services, as well as expenditures
relating to asset retirement obligations. As at December 31, 2007,
no entities were consolidated under the Canadian Institute of
Chartered Accountants Handbook Accounting Guideline 15,
"Consolidation of Variable Interest Entities". The following table
summarizes the Company's commitments as at December 31, 2007:
($ millions) 2008 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Product transportation and
pipeline $ 232 $ 151 $ 137 $ 109 $ 91 $ 972
Offshore equipment
operating lease (1) $ 114 $ 129 $ 113 $ 111 $ 90 $ 387
Offshore drilling (2)(3) $ 267 $ 185 $ 39 $ - $ - $ -
Asset retirement
obligations (4) $ 33 $ 4 $ 5 $ 4 $ 4 $ 4,376
Long-term debt (5) $ 39 $ 2,361 $ 400 $ 395 $ 346 $ 5,098
Interest expense (6) $ 612 $ 590 $ 487 $ 465 $ 374 $ 4,338
Office lease $ 26 $ 28 $ 28 $ 22 $ 3 $ -
Electricity and other $ 166 $ 173 $ 25 $ 4 $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Offshore equipment operating leases are primarily comprised of
obligations related to FPSOs. During 2006, the Company entered into an
agreement to lease an additional FPSO commencing in 2008, in connection
with the planned offshore development in Gabon, Offshore West Africa.
During the initial term, the total annual payments for the Gabon FPSO
are estimated to be US$50 million.
(2) During 2007, the Company entered into a one-year agreement for offshore
drilling services related to the Baobab Field in Cote d'Ivoire, Offshore
West Africa. The agreement is scheduled to commence in 2008, subject to
rig availability. Estimated total payments of US$100 million, after
joint venture recoveries, have been included in this table for the
period 2008 - 2009.
(3) During 2007, the Company awarded contracts for a drilling rig and for
the construction of wellhead towers in connection with the planned
offshore development in Gabon, Offshore West Africa. Estimated total
payments of US$393 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 $2,366 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 of December 31, 2007.
In addition to the amounts disclosed above, the Company has
budgeted construction costs of approximately $1.7 billion to $1.9
billion for 2008 related to the planned completion of Phase 1 of
the Horizon Project.
Legal proceedings
The Company is defendant and plaintiff in a number of legal
actions that arise in the normal course of business. In addition,
the Company is subject to certain contractor construction claims
related to the Horizon Project. The Company believes that any
liabilities that might arise pertaining to any such matters would
not have a material effect on its consolidated financial
position.
Critical accounting estimates and change in accounting
policies
The preparation of financial statements requires the Company to
make judgements, assumptions and estimates in the application of
generally accepted accounting principles that have a significant
impact on the financial results of the Company. Actual results
could differ from those estimates. A comprehensive discussion of
the Company's significant accounting policies is contained in the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2006.
For the impact of new accounting standards related to financial
instruments and comprehensive income, please refer to Risk
Management Activities on page 38 of this MD&A and note 2 of the
unaudited interim consolidated financial statements as at December
31, 2007.
SENSITIVITY ANALYSIS
The following table is indicative of the annualized
sensitivities of cash flow from operations and net earnings from
changes in certain key variables. The analysis is based on business
conditions and sales volumes during the fourth quarter of 2007,
excluding mark-to-market gains (losses) on risk management
activities, and is not necessarily indicative of future results.
Each separate line item in the sensitivity analysis shows the
effect of a change in that variable only; all other variables are
held constant.
Cash flow
Cash flow from Net
from operations Net earnings
operations (per common earnings (per common
($ millions) share, basic) ($ millions) share, basic)
----------------------------------------------------------------------------
Price changes
Crude oil - WTI
US$1.00/bbl (1)
Excluding financial
derivatives $ 96 $ 0.18 $ 70 $ 0.13
Including financial
derivatives $ 21 $ 0.04 $ 17 $ 0.03
Natural gas - AECO
C$0.10/mcf (1)
Excluding financial
derivatives $ 41 $ 0.08 $ 29 $ 0.05
Including financial
derivatives $ 33 $ 0.06 $ 23 $ 0.04
Volume changes
Crude oil - 10,000
bbl/d $ 132 $ 0.25 $ 70 $ 0.13
Natural gas - 10
mmcf/d $ 16 $ 0.03 $ 6 $ 0.01
Foreign currency rate
change
$0.01 change in US$ (1)
Including financial
derivatives $ 73-74 $0.13-0.14 $ 31-32 $ 0.06
Interest rate change
- 1% $ 38 $ 0.07 $ 38 $ 0.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) For details of outstanding financial instruments in place, refer to
note 10 of the Company's unaudited interim consolidated financial
statements.
OTHER OPERATING HIGHLIGHTS
NETBACK ANALYSIS
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($/boe) (1) 2007 2007 2006 2007 2006
----------------------------------------------------------------------------
Sales price (2) $ 49.23 $ 47.96 $ 43.91 $ 49.05 $ 47.92
Royalties 6.21 6.07 5.62 6.26 5.89
Production expense (3) 8.85 9.62 9.16 9.75 9.14
----------------------------------------------------------------------------
Netback 34.17 32.27 29.13 33.04 32.89
Midstream contribution (3) (0.24) (0.26) (0.22) (0.23) (0.23)
Administration 0.76 0.94 1.01 0.93 0.85
Interest, net 0.92 1.15 1.08 1.24 0.66
Realized risk management
loss (gain) 3.27 (0.41) 2.25 0.73 6.27
Realized foreign exchange
(gain) loss - 0.38 (0.34) 0.24 (0.06)
Taxes other than income
tax - current 0.30 0.54 0.78 0.54 1.04
Current income tax - North
America 0.56 0.49 0.91 0.43 0.68
Current income
tax - North Sea 1.18 0.99 0.54 0.95 0.14
Current income
tax - Offshore West Africa 0.50 0.37 0.24 0.33 0.23
----------------------------------------------------------------------------
Cash flow $ 26.92 $ 28.08 $ 22.88 $ 27.88 $ 23.31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
FINANCIAL STATEMENTS
Consolidated balance sheets
Dec 31 Dec 31
(millions of Canadian dollars, unaudited) 2007 2006
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 21 $ 23
Accounts receivable and other 1,662 1,947
Future income tax 480 163
Current portion of other long-term assets
(note 3) 18 106
----------------------------------------------------------------------------
2,181 2,239
Property, plant and equipment (note 12) 33,902 30,767
Other long-term assets (note 3) 31 154
----------------------------------------------------------------------------
$ 36,114 $ 33,160
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 379 $ 842
Accrued liabilities 1,567 1,618
Current portion of other long-term
liabilities (note 5) 1,617 611
----------------------------------------------------------------------------
3,563 3,071
Long-term debt (note 4) 10,940 11,043
Other long-term liabilities (note 5) 1,561 1,393
Future income tax 6,729 6,963
----------------------------------------------------------------------------
22,793 22,470
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 7) 2,674 2,562
Retained earnings 10,575 8,141
Accumulated other comprehensive income (loss)
(note 8) 72 (13)
----------------------------------------------------------------------------
13,321 10,690
----------------------------------------------------------------------------
$ 36,114 $ 33,160
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (note 11)
Consolidated statements of earnings
Three Months Ended Year Ended
(millions of Canadian dollars,
except per common share Dec 31 Dec 31 Dec 31 Dec 31
amounts, unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue $ 3,200 $ 2,826 $ 12,543 $ 11,643
Less: royalties (343) (317) (1,391) (1,245)
----------------------------------------------------------------------------
Revenue, net of royalties 2,857 2,509 11,152 10,398
----------------------------------------------------------------------------
Expenses
Production 491 519 2,184 1,949
Transportation and blending 467 333 1,570 1,443
Depletion, depreciation and
amortization 719 724 2,863 2,391
Asset retirement obligation
accretion (note 5) 17 18 70 68
Administration 42 57 208 180
Stock-based compensation
(recovery) expense (note 5) (16) 176 193 139
Interest, net 51 62 276 140
Risk management activities (note 10) 1,026 (115) 1,562 312
Foreign exchange (gain) loss (47) 151 (471) 122
----------------------------------------------------------------------------
2,750 1,925 8,455 6,744
----------------------------------------------------------------------------
Earnings before taxes 107 584 2,697 3,654
Taxes other than income tax 33 41 165 256
Current income tax expense (note 6) 123 95 380 222
Future income tax (recovery)
expense (note 6) (847) 135 (456) 652
----------------------------------------------------------------------------
Net earnings $ 798 $ 313 $ 2,608 $ 2,524
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common share
(note 9)
Basic and diluted $ 1.48 $ 0.58 $ 4.84 $ 4.70
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated statements of shareholders' equity
Year Ended
Dec 31 Dec 31
(millions of Canadian dollars, unaudited) 2007 2006
----------------------------------------------------------------------------
Share capital
Balance - beginning of year $ 2,562 $ 2,442
Issued upon exercise of stock options 21 21
Previously recognized liability on stock
options exercised for common shares 91 101
Purchase of common shares under Normal
Course Issuer Bid - (2)
----------------------------------------------------------------------------
Balance - end of year 2,674 2,562
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of year, as originally reported 8,141 5,804
Transition adjustment on adoption of financial
instruments standards (note 2) 10 -
----------------------------------------------------------------------------
Balance - beginning of year, as restated 8,151 5,804
Net earnings 2,608 2,524
Dividends on common shares (note 7) (184) (161)
Purchase of common shares under Normal
Course Issuer Bid - (26)
----------------------------------------------------------------------------
Balance - end of year 10,575 8,141
----------------------------------------------------------------------------
Accumulated other comprehensive income (loss) (note 2)
Balance - beginning of year (13) (9)
Transition adjustment on adoption of
financial instruments standards 159 -
----------------------------------------------------------------------------
Balance - beginning of year, after effect of
transition adjustment 146 (9)
Other comprehensive loss, net of taxes (74) (4)
----------------------------------------------------------------------------
Balance - end of year 72 (13)
----------------------------------------------------------------------------
Shareholders' equity $ 13,321 $ 10,690
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated statements of comprehensive income
Three Months Ended Year Ended
(millions of Canadian dollars, Dec 31 Dec 31 Dec 31 Dec 31
unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net earnings $ 798 $ 313 $ 2,608 $ 2,524
----------------------------------------------------------------------------
Net change in derivative
financial instruments designated
as cash flow hedges
Unrealized income during the
period (net of taxes of $3
million - three months ended;
$6 million - year ended) 32 - 38 -
Reclassification to net
earnings (net of taxes of $21
million - three months ended;
$45 million - year ended) (45) - (96) -
----------------------------------------------------------------------------
(13) - (58) -
----------------------------------------------------------------------------
Foreign currency translation
adjustment
Translation of net investment - 2 (16) (4)
Hedge of net investment, net
of tax - (3) - -
----------------------------------------------------------------------------
- (1) (16) (4)
----------------------------------------------------------------------------
Other comprehensive loss, net
of taxes (13) (1) (74) (4)
----------------------------------------------------------------------------
Comprehensive income $ 785 $ 312 $ 2,534 $ 2,520
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated statements of cash flows
Three Months Ended Year Ended
(millions of Canadian dollars, Dec 31 Dec 31 Dec 31 Dec 31
unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Operating activities
Net earnings $ 798 $ 313 $ 2,608 $ 2,524
Non-cash items
Depletion, depreciation and
amortization 719 724 2,863 2,391
Asset retirement obligation
accretion 17 18 70 68
Stock-based compensation
(recovery) expense (16) 176 193 139
Unrealized risk management
activities 845 (241) 1,400 (1,013)
Unrealized foreign exchange
(gain) loss (47) 171 (524) 134
Deferred petroleum revenue tax
expense (recovery) 17 (3) 44 37
Future income tax (recovery)
expense (847) 135 (456) 652
Deferred charges and other 31 6 38 (2)
Abandonment expenditures (16) (19) (71) (75)
Net change in non-cash working
capital (264) (317) (346) (679)
----------------------------------------------------------------------------
1,237 963 5,819 4,176
----------------------------------------------------------------------------
Financing activities
(Repayment) issue of bank credit
facilities, net (128) 5,384 (1,925) 6,499
Issue of medium-term notes 398 - 273 400
Repayment of senior unsecured
notes - - (33) -
Issue of US dollar debt
securities - - 2,553 788
Issue of common shares on
exercise of stock options 2 4 21 21
Dividends on common shares (46) (40) (178) (153)
Purchase of common shares - - - (28)
Net change in non-cash working
capital 2 29 8 37
----------------------------------------------------------------------------
228 5,377 719 7,564
----------------------------------------------------------------------------
Investing activities
Expenditures on property, plant
and equipment (1,603) (1,791) (6,464) (7,266)
Net proceeds on sale of property,
plant and equipment 105 68 110 71
----------------------------------------------------------------------------
Net expenditures on property,
plant and equipment (1,498) (1,723) (6,354) (7,195)
Acquisition of Anadarko Canada
Corporation - (4,641) - (4,641)
Net change in non-cash working
capital 33 35 (186) 101
----------------------------------------------------------------------------
(1,465) (6,329) (6,540) (11,735)
----------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents - 11 (2) 5
Cash and cash equivalents -
beginning of period 21 12 23 18
----------------------------------------------------------------------------
Cash and cash equivalents - end
of period $ 21 $ 23 $ 21 $ 23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 153 $ 83 $ 556 $ 262
Taxes paid
Taxes other than income tax $ 13 $ 52 $ 116 $ 291
Current income tax $ 145 $ 108 $ 302 $ 412
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes to the consolidated financial statements (tabular amounts
in millions of Canadian dollars, unaudited)
1. ACCOUNTING POLICIES
The interim consolidated financial statements of Canadian
Natural Resources Limited (the "Company") include the Company and
all of its subsidiaries and partnerships, and have been prepared
following the same accounting policies as the audited consolidated
financial statements of the Company as at December 31, 2006, except
as described in note 2. The interim consolidated financial
statements contain disclosures that are supplemental to the
Company's annual audited consolidated financial statements. Certain
disclosures that are normally required to be included in the notes
to the annual audited consolidated financial statements have been
condensed. These interim financial statements should be read in
conjunction with the Company's audited consolidated financial
statements and notes thereto for the year ended December 31,
2006.
2. CHANGE IN ACCOUNTING POLICY
Financial Instruments and Comprehensive Income
Effective January 1, 2007, the Company adopted the following new
accounting standards issued by the Canadian Institute of Chartered
Accountants relating to the accounting for and disclosure of
financial instruments and comprehensive income:
- Section 1530 - "Comprehensive Income" introduces the concept
of comprehensive income to Canadian GAAP. Comprehensive income is
the change in equity (net assets) of the Company during a reporting
period from transactions and other events and circumstances from
non-owner sources. It includes all changes in equity during a
period except transactions with owners. The foreign currency
translation adjustment, which was previously a separate component
of shareholders' equity, is now recorded as part of accumulated
other comprehensive income.
- Section 3251 - "Equity" replaces Section 3250 - "Surplus" and
establishes standards for the presentation of equity and changes in
equity during a reporting period.
- Section 3855 - "Financial Instruments - Recognition and
Measurement" prescribes when a financial asset, financial
liability, or non-financial derivative should be recognized on the
balance sheet as well as its measurement amount.
- Section 3865 - "Hedges" replaces Accounting Guideline 13 -
"Hedging Relationships" and EIC 128 - "Accounting for Trading,
Speculative or Non-Hedging Derivative Financial Instruments" and
specifies how hedge accounting is to be applied and what
disclosures are necessary when hedge accounting is applied.
Adoption of these standards required the Company to record all
of its derivative financial instruments on the balance sheet at
estimated fair value as at January 1, 2007, including those
designated as hedges. Designated hedges, other than cross currency
swaps, were previously not recognized on the balance sheet but were
disclosed in the notes to the financial statements. The adjustment
to recognize all designated hedges on the balance sheet was
recorded as an adjustment to the opening balance of retained
earnings or accumulated other comprehensive income, as
appropriate.
With the exception of the foreign currency translation
adjustment, these standards were adopted prospectively;
accordingly, comparative amounts for prior periods have not been
restated. The reclassification of the foreign currency translation
adjustment to other comprehensive income was applied retroactively
with prior period restatement.
Effective January 1, 2007, the Company's accounting policies for
financial instruments and comprehensive income are as follows:
Risk Management Activities
The Company utilizes various derivative financial instruments to
manage its commodity price, currency and interest rate exposures.
These derivative financial instruments are not intended for trading
or speculative purposes.
All derivative financial instruments are recognized at estimated
fair value on the consolidated balance sheet at each balance sheet
date. The estimated fair value of derivative instruments has been
determined based on appropriate internal valuation methodologies
and/or third party indications. However, these estimates may not
necessarily be indicative of the amounts that could be realized or
settled in a current market transaction and these differences may
be material.
The Company formally documents all derivative financial
instruments that are designated as hedging transactions at the
inception of the hedging relationship, in accordance with the
Company's risk management policies. The effectiveness of the
hedging relationship is evaluated, both at inception of the hedge
and on an ongoing basis.
The Company periodically enters into commodity price contracts
to manage anticipated sales of crude oil and natural gas production
in order to protect cash flow for capital expenditure programs. The
effective portion of changes in the fair value of derivative
commodity price contracts designated as cash flow hedges is
initially recognized in other comprehensive income and is
reclassified to risk management activities in consolidated net
earnings in the same period or periods in which the crude oil or
natural gas is sold. The ineffective portion of changes in the fair
value of these designated contracts is immediately recognized in
risk management activities in consolidated net earnings. All
changes in the fair value of non-designated crude oil and natural
gas commodity price contracts are recognized in risk management
activities in consolidated net earnings.
The Company enters into interest rate swap contracts to manage
its fixed to floating interest rate mix on certain of its long-term
debt. The interest rate swap contracts require the periodic
exchange of payments without the exchange of the notional principal
amounts on which the payments are based. Changes in the fair value
of interest rate swap contracts designated as fair value hedges and
corresponding changes in the fair value of the hedged long-term
debt are included in interest expense in consolidated net earnings.
Changes in the fair value of non-designated interest rate swap
contracts are included in risk management activities in
consolidated net earnings.
Cross currency swap contracts are periodically used to manage
currency exposure on US dollar denominated long-term debt. The
cross currency swap contracts require the periodic exchange of
payments with the exchange at maturity of notional principal
amounts on which the payments are based. Changes in the fair value
of the foreign exchange component of cross currency swap contracts
designated as cash flow hedges are included in foreign exchange in
consolidated net earnings. The effective portion of changes in the
fair value of the interest rate component of cross currency swap
contracts designated as cash flow hedges is initially included in
other comprehensive income and is reclassified to interest expense
when realized, with the ineffective portion recognized in risk
management activities in consolidated net earnings. Changes in the
fair value of non-designated cross currency swap contracts are
included in risk management activities in consolidated net
earnings.
Gains or losses on the termination of financial instruments that
have been designated as cash flow hedges are deferred under
accumulated other comprehensive income on the consolidated balance
sheets and amortized into consolidated net earnings in the period
in which the underlying hedged item is recognized. In the event a
designated hedged item is sold, extinguished or matures prior to
the termination of the related derivative instrument, any
unrealized derivative gain or loss is recognized immediately in
consolidated net earnings. Gains or losses on the termination of
financial instruments that have not been designated as hedges are
recognized in consolidated net earnings immediately.
Embedded derivatives are derivatives that are included in a
non-derivative host contract. Embedded derivatives are recorded at
fair value separately from the host contract when their economic
characteristics and risks are not clearly and closely related to
the host contract.
Transaction costs that are directly attributable to the
acquisition or issue of a financial asset or financial liability
and original issue discounts on long-term debt have been included
in the carrying value of the related financial asset or liability
and are amortized to consolidated net earnings over the life of the
financial instrument using the effective interest method.
Comprehensive Income
Comprehensive income is comprised of the Company's net earnings
and other comprehensive income. Other comprehensive income includes
the effective portion of changes in the fair value of derivative
financial instruments designated as cash flow hedges and foreign
currency translation gains and losses on the net investment in
self-sustaining foreign operations. Other comprehensive income is
shown net of related income taxes.
The effects of adopting these standards on the opening balance
sheet were as follows:
--------------
Jan 1, 2007
----------------------------------------------------------------------------
Increased current portion of other long-term assets (1) $ 193
Decreased other long-term assets (2) $ (16)
Decreased long-term debt (3) $ (72)
Increased retained earnings (4) $ 10
Increased foreign currency translation adjustment (5) $ 13
Increased accumulated other comprehensive income (6) $ 146
Decreased current portion of future income tax asset (7) $ (62)
Increased future income tax liability (7) $ 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Relates to the recognition of the current portion of the fair value of
derivative financial instruments designated as cash flow hedges.
(2) Relates to the recognition of the long-term portion of the fair value of
derivative financial instruments designated as cash flow and fair value
hedges, as well as the reclassification of transaction costs and
original issue discounts from deferred charges to long-term debt.
(3) Relates to the fair value impact of derivative financial instruments
designated as fair value hedges, as well as the reclassification of
transaction costs and original issue discounts.
(4) Relates to the impact on adoption of the measurement of ineffectiveness
on derivative financial instruments designated as cash flow hedges.
(5) Relates to the retroactive restatement of foreign currency translation
adjustment to accumulated other comprehensive income.
(6) Relates to the recognition of accumulated other comprehensive income
arising from the measurement of effectiveness on derivative financial
instruments designated as cash flow hedges.
(7) Relates to the future income tax impacts of the above noted adjustments.
3. OTHER LONG-TERM ASSETS
--------------------------
Dec 31 Dec 31
2007 2006
----------------------------------------------------------------------------
Deferred charges (note 2) $ 28 $ 109
Risk management (note 10) - 128
Other 21 23
----------------------------------------------------------------------------
49 260
Less: current portion 18 106
----------------------------------------------------------------------------
$ 31 $ 154
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. LONG-TERM DEBT
---------------------------------------
Pro forma
Dec 31 Dec 31 Dec 31
2007(4) 2007 2006
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities (bankers'
acceptances) $ 3,510 $ 4,696 $ 6,621
Medium-term notes 1,200 1,200 925
----------------------------------------------------------------------------
4,710 5,896 7,546
----------------------------------------------------------------------------
US dollar denominated debt
Senior unsecured notes (2007 - US$62
million; and 2006 - US$93 million) 61 61 108
US dollar debt securities (2007 -
US$5,108 million; and 2006 - US$2,908
million) 6,244 5,048 3,389
Less - original issue discount on
senior unsecured notes and US dollar
debt securities (1) (24) (23) -
----------------------------------------------------------------------------
6,281 5,086 3,497
Change in fair value of interest rate
swaps on US dollar debt securities (2) 9 9 -
----------------------------------------------------------------------------
6,290 5,095 3,497
----------------------------------------------------------------------------
Long-term debt before transaction costs 11,000 10,991 11,043
Less - transaction costs (1) (3) (60) (51) -
----------------------------------------------------------------------------
$ 10,940 $ 10,940 $ 11,043
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) As described in note 2, effective January 1, 2007, the Company has
included unamortized original issue discounts and directly attributable
transaction costs in the carrying value of the outstanding debt.
(2) The carrying values of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $9 million to reflect the fair value impact of hedge accounting
(note 2).
(3) Transaction costs primarily represent underwriting commissions charged
as a percentage of the related debt offerings, as well as legal, rating
agency and other professional fees.
(4) On January 10, 2008, the Company issued US$1,200 million of debt
securities. The pro forma gives effect to the proceeds and their initial
use.
Bank credit facilities
As at December 31, 2007, the Company had in place unsecured bank
credit facilities of $6,209 million, comprised of:
- a $100 million demand credit facility;
- a non-revolving syndicated credit facility of $2,350 million
maturing October 2009;
- a revolving syndicated credit facility of $2,230 million
maturing June 2012;
- a revolving syndicated credit facility of $1,500 million
maturing June 2012; and
- a Pounds Sterling 15 million demand credit facility related to
the Company's North Sea operations.
During the second quarter of 2007, one of the revolving
syndicated credit facilities was increased from $1,825 million to
$2,230 million and a $500 million demand credit facility was
terminated. The revolving syndicated credit facilities were also
extended and now mature June 2012. Both facilities are extendible
annually for one year periods at the mutual agreement of the
Company and the lenders. If the facilities are not extended, the
full amount of the outstanding principal would be repayable on the
maturity date.
In conjunction with the closing of the acquisition of Anadarko
Canada Corporation in November 2006, the Company executed a $3,850
million, non-revolving syndicated credit facility maturing in
October 2009. In March 2007, $1,500 million was repaid, reducing
the facility to $2,350 million.
The weighted average interest rate of the bank credit facilities
outstanding at December 31, 2007, was 5.2% (December 31, 2006 -
4.8%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $345 million, including $300
million related to the Horizon Oil Sands Project ("Horizon
Project"), were outstanding at December 31, 2007.
Medium-term notes
In December 2007, the Company issued $400 million of unsecured
notes maturing December 2010, bearing interest at 5.50%. Proceeds
from the securities issued were used to repay bankers' acceptances
under the Company's bank credit facilities. After issuing these
securities, the Company has $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.
During the first quarter of 2007, $125 million of 7.40%
unsecured debentures due March 1, 2007 were repaid.
Senior unsecured notes
During the second quarter of 2007, US$31 million of the senior
unsecured notes were repaid.
US dollar debt securities
In March 2007, the Company issued US$2,200 million of unsecured
notes, comprised of US$1,100 million of unsecured notes maturing
May 2017 and US$1,100 million of unsecured notes maturing March
2038, bearing interest at 5.70% and 6.25%, respectively.
Concurrently, the Company entered into cross currency interest rate
swaps to fix the Canadian dollar interest and principal repayment
amounts on the entire US$1,100 million of unsecured notes due May
2017 at 5.10% and C$1,287 million (note 10). The Company also
entered into a cross currency interest rate swap to fix the
Canadian dollar interest and principal repayment amounts on US$550
million of unsecured notes due March 2038 at 5.76% and C$644
million (note 10). Proceeds from the securities issued were used to
repay bankers' acceptances under the Company's bank credit
facilities.
During the first quarter of 2007, the Company de-designated the
portion of the US dollar denominated debt previously hedged against
its net investment in US dollar based self-sustaining foreign
operations. Accordingly, all foreign exchange (gains) losses
arising each period on U.S. dollar denominated long-term debt are
now recognized in the consolidated statement of earnings.
In September 2007, the Company filed a base shelf prospectus
that allows for the issue of up to US$3,000 million of debt
securities in the United States until October 2009.
Subsequent to December 31, 2007, the Company issued US$1,200
million of unsecured notes under this 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. If issued, these securities will bear interest as
determined at the date of issuance.
5. OTHER LONG-TERM LIABILITIES
--------------------------
Dec 31 Dec 31
2007 2006
----------------------------------------------------------------------------
Asset retirement obligations $ 1,074 $ 1,166
Stock-based compensation 529 744
Risk management (note 10) 1,474 -
Other 101 94
----------------------------------------------------------------------------
3,178 2,004
Less: current portion 1,617 611
----------------------------------------------------------------------------
$ 1,561 $ 1,393
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset retirement obligations
At December 31, 2007, the Company's total estimated costs to
settle its asset retirement obligations were approximately $4,426
million (December 31, 2006 - $4,497 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%. A reconciliation of the discounted asset retirement
obligations is as follows:
-----------------------------
Year Year
Ended Ended
Dec 31, 2007 Dec 31, 2006
---------------------------------------------------------------------------
Balance - beginning of year $ 1,166 $ 1,112
Liabilities incurred 21 26
Liabilities (disposed) acquired (65) 56
Liabilities settled (71) (75)
Asset retirement obligation accretion 70 68
Revision of estimates 35 (21)
Foreign exchange (82) -
---------------------------------------------------------------------------
Balance - end of year $ 1,074 $ 1,166
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Stock-based compensation
The Company recognizes a liability for the potential cash
settlements under its Stock Option Plan. The current portion
represents the maximum amount of the liability payable within the
next 12-month period if all vested options are surrendered for cash
settlement.
-----------------------------
Year Year
Ended Ended
Dec 31, 2007 Dec 31, 2006
---------------------------------------------------------------------------
Balance - beginning of year $ 744 $ 891
Stock-based compensation 193 139
Payments for options surrendered (375) (264)
Transferred to common shares (91) (101)
Capitalized to Horizon Project 58 79
---------------------------------------------------------------------------
Balance - end of year 529 744
Less: current portion of stock-based compensation 390 611
---------------------------------------------------------------------------
$ 139 $ 133
---------------------------------------------------------------------------
---------------------------------------------------------------------------
6. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Year Ended
----------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Current income tax - North America $ 31 $ 51 $ 96 $ 143
Current income tax - North Sea 65 30 210 30
Current income tax - Offshore West
Africa 27 14 74 49
----------------------------------------------------------------------------
Current income tax expense 123 95 380 222
Future income tax (recovery) expense (847) 135 (456) 652
----------------------------------------------------------------------------
Income tax (recovery) expense $ (724) $ 230 $ (76) $ 874
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 fourth quarter of 2007, the Canadian Federal
Government enacted or substantively enacted income tax rate and
other legislative changes, resulting in a reduction of future
income tax liabilities of approximately $793 million.
During the second quarter of 2007, the Canadian Federal
Government enacted income tax rate changes, resulting in a
reduction of future income tax liabilities of approximately $71
million.
During the first quarter of 2006, enacted income tax rate
changes resulted in an increase of future income tax liabilities of
approximately $110 million in the UK North Sea.
During the second quarter of 2006, enacted income tax rate
changes resulted in a reduction of future income tax liabilities of
approximately $438 million in North America.
During the third quarter of 2006, enacted income tax rate
changes resulted in a reduction of future income tax liabilities of
approximately $67 million in Cote d'Ivoire, Offshore West
Africa.
7. SHARE CAPITAL
------------------------------
Year Ended Dec 31, 2007
Issued Number of shares
Common shares (thousands) Amount
---------------------------------------------------------------------------
Balance - beginning of year 537,903 $ 2,562
Issued upon exercise of stock options 1,826 21
Previously recognized liability on stock
options exercised for common shares - 91
---------------------------------------------------------------------------
Balance - end of year 539,729 $ 2,674
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Normal Course Issuer Bid
During 2007, the Company did not purchase any common shares for
cancellation pursuant to the Normal Course Issuer Bid previously
filed for the 12-month period beginning January 24, 2007 and ending
January 23, 2008. The Company has not renewed the Normal Course
Issuer Bid in 2008.
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.
In March 2007, the Board of Directors set the regular quarterly
dividend at $0.085 per common share (2006 - $0.075 per common
share).
Stock options
------------------------------
Year Ended Dec 31, 2007
Stock options Weighted average
(thousands) exercise price
---------------------------------------------------------------------------
Outstanding - beginning of year 34,425 $ 33.77
Granted 7,498 $ 70.03
Surrendered for cash settlement (7,249) $ 16.10
Exercised for common shares (1,826) $ 11.71
Forfeited (2,199) $ 46.46
---------------------------------------------------------------------------
Outstanding - end of year 30,649 $ 47.23
---------------------------------------------------------------------------
Exercisable - end of year 7,640 $ 30.00
---------------------------------------------------------------------------
---------------------------------------------------------------------------
8. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income (loss), net of
taxes, were as follows:
--------------------------
Dec 31 Dec 31
2007 2006
---------------------------------------------------------------------------
Derivative financial instruments
designated as cash flow hedges $ 101 $ -
Foreign currency translation adjustment (29) (13)
---------------------------------------------------------------------------
Accumulated other comprehensive income (loss) $ 72 $ (13)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
9. NET EARNINGS PER COMMON SHARE
Three Months Ended Year Ended
----------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Weighted average common shares
outstanding (thousands) -
basic and diluted 539,652 537,616 539,336 537,339
----------------------------------------------------------------------------
Net earnings - basic and diluted $ 798 $ 313 $2,608 $2,524
----------------------------------------------------------------------------
Net earnings per common share -
basic and diluted $ 1.48 $ 0.58 $ 4.84 $ 4.70
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. FINANCIAL INSTRUMENTS
Risk management
The Company uses derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures.
These financial instruments are entered into solely for hedging
purposes and are not intended for trading or other speculative
purposes.
As described in note 2, commencing January 1, 2007, the Company
recorded all of its derivative financial instruments on the balance
sheet at fair value, including those designated as hedges. As at
December 31, 2006, the net unrecognized asset related to the
estimated fair values of derivative financial instruments
designated as hedges was $222 million.
The estimated fair values of derivative financial instruments
recognized in the risk management asset (liability) were comprised
as follows:
----------------------------------------------
Year Ended Year Ended
Dec 31, 2007 Dec 31, 2006
---------------------------------------------------------------------------
Risk management Risk management Deferred
Asset (liability) mark-to-market mark-to-market revenue
---------------------------------------------------------------------------
Balance - beginning of year $ 128 $ (877) $ (8)
Retained earnings effect of
adoption of financial
instrument standards (note 2) 14 - -
Net cost of outstanding put options 58 455 -
Net change in fair value of
outstanding derivative
financial instruments attributable
to:
- Risk management activities (1,400) 1,005 -
- Interest expense 9 - -
- Foreign exchange (350) - -
- Other comprehensive income 125 - -
Amortization of deferred revenue - - 8
---------------------------------------------------------------------------
(1,416) 583 -
Add: Put premium financing
obligations (1) (58) (455) -
---------------------------------------------------------------------------
Balance - end of year (1,474) 128 -
Less: current portion (1,227) 88 -
---------------------------------------------------------------------------
$ (247) $ 40 $ -
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) The Company has negotiated payment of put option premiums with various
counter-parties at the time of actual settlement of the respective
options. These obligations have been reflected in the net risk
management asset (liability).
Net losses (gains) from risk management activities were as follows:
Three Months Ended Year Ended
----------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Net realized risk management loss $ 181 $ 126 $ 162 $ 1,325
Net unrealized risk management
mark-to-market loss (gain) 845 (241) 1,400 (1,013)
----------------------------------------------------------------------------
$ 1,026 $ (115) $ 1,562 $ 312
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company had the following net financial derivatives outstanding as at
December 31, 2007:
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Crude oil
Crude oil
price
collars (1) Jan 2008 - Mar 2008 50,000 bbl/d US$60.00 - US$80.06 WTI
Jan 2008 - Jun 2008 25,000 bbl/d US$60.00 - US$80.44 WTI
Apr 2008 - Sep 2008 25,000 bbl/d US$60.00 - US$80.46 WTI
Jul 2008 - Sep 2008 25,000 bbl/d US$70.00 - US$123.75 WTI
Oct 2008 - Dec 2008 25,000 bbl/d US$70.00 - US$112.63 WTI
Mayan
Jan 2008 - Dec 2008 20,000 bbl/d US$50.00 - US$65.53 Heavy
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$75.22 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.05 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.98 WTI
Crude oil
puts Jan 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to December 31, 2007, the Company entered into 25,000 bbl/d
of US$70.00 - US$111.56 WTI collars for the period January to December
2009.
The net cost of outstanding put options and their respective periods of
settlement are as follows:
Q1 2008 Q2 2008 Q3 2008 Q4 2008
----------------------------------------------------------------------------
Cost ($ millions) US$14 US$15 US$15 US$15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Natural gas
AECO price
collars Jan 2008 - Mar 2008 400,000 GJ/d C$7.00 - C$14.08 AECO
Jan 2008 - Mar 2008 500,000 GJ/d C$7.50 - C$10.81 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's outstanding commodity financial derivatives are expected to be
settled monthly based on the applicable index pricing for the respective
contract month.
Amount Fixed
Remaining term ($ millions) rate Floating rate
----------------------------------------------------------------------------
Interest rate
Swaps - fixed
to floating Jan 2008 - Oct 2012 US$350 5.45% LIBOR (1) + 0.81%
Jan 2008 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) London Interbank Offered Rate
Exchange Interest Interest
Amount rate rate rate
Remaining term ($ millions) (US$/C$) (US$) (C$)
----------------------------------------------------------------------------
Cross currency
Swaps Jan 2008 - Aug 2016 US$250 1.116 6.00% 5.40%
Jan 2008 - May 2017 US$1,100 1.170 5.70% 5.10%
Jan 2008 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. COMMITMENTS
The Company has committed to certain payments as follows:
2008 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 232 $ 151 $ 137 $ 109 $ 91 $ 972
Offshore equipment
operating leases (1) $ 114 $ 129 $ 113 $ 111 $ 90 $ 387
Offshore drilling (2) (3) $ 267 $ 185 $ 39 $ - $ - $ -
Asset retirement
obligations (4) $ 33 $ 4 $ 5 $ 4 $ 4 $ 4,376
Office leases $ 26 $ 28 $ 28 $ 22 $ 3 $ -
Electricity and other $ 166 $ 173 $ 25 $ 4 $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 2008, in connection with the planned
offshore development in Gabon, Offshore West Africa. During the initial
term, the total annual payments for the Gabon FPSO are estimated to be
US$50 million.
(2) During 2007, the Company entered into a one-year agreement for offshore
drilling services related to the Baobab Field in Cote d'Ivoire, Offshore
West Africa. The agreement is scheduled to commence in 2008, subject to
rig availability. Estimated total payments of US$100 million, after
joint venture recoveries, have been included in this table for the
period 2008 - 2009.
(3) During 2007, the Company awarded contracts for a drilling rig and for
the construction of wellhead towers in connection with the planned
offshore development in Gabon, Offshore West Africa. Estimated total
payments of US$393 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 construction costs of approximately $1.7 billion to $1.9
billion for 2008 related to the planned completion of Phase 1 of
the Horizon Project.
12. SEGMENTED INFORMATION
North America North Sea
Three Months Year Ended Three Months Year Ended
(millions of Ended Dec 31 Dec 31 Ended Dec 31 Dec 31
Canadian dollars, ---------------------------------------------------------
unaudited) 2007 2006 2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
Segmented revenue 2,571 2,243 10,149 9,066 367 352 1,597 1,616
Less: royalties (317) (305) (1,318)(1,203) (1) (1) (3) (3)
----------------------------------------------------------------------------
Segmented revenue,
net of royalties 2,254 1,938 8,831 7,863 366 351 1,594 1,613
----------------------------------------------------------------------------
Segmented expenses
Production 377 400 1,642 1,436 79 77 432 390
Transportation and
blending 473 337 1,595 1,465 4 4 16 15
Depletion,
depreciation and
amortization 602 580 2,350 1,897 69 85 340 297
Asset retirement
obligation
accretion 10 9 38 35 7 9 30 31
Realized risk
management
activities 182 76 129 1,022 (1) 50 33 303
----------------------------------------------------------------------------
Total segmented
expenses 1,644 1,402 5,754 5,855 158 225 851 1,036
----------------------------------------------------------------------------
Segmented earnings
(loss) before
the following 610 536 3,077 2,008 208 126 743 577
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Stock-based compensation
(recovery) expense
Interest, net
Unrealized risk management
activities
Foreign exchange (gain) loss
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before taxes
Taxes other than income tax
Current income tax expense
Future income tax (recovery)
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore West Africa Midstream
Three Months Year Ended Three Months Year Ended
(millions of Ended Dec 31 Dec 31 Ended Dec 31 Dec 31
Canadian dollars, ---------------------------------------------------------
unaudited) 2007 2006 2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
Segmented revenue 260 232 776 950 19 18 74 72
Less: royalties (25) (11) (70) (39) - - - -
----------------------------------------------------------------------------
Segmented revenue,
net of royalties 235 221 706 911 19 18 74 72
----------------------------------------------------------------------------
Segmented expenses
Production 31 38 94 106 6 6 22 23
Transportation and
blending 1 1 1 1 - - - -
Depletion,
depreciation and
amortization 46 57 165 189 2 2 8 8
Asset retirement
obligation accretion - - 2 2 - - - -
Realized risk
management
activities - - - - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 78 96 262 298 8 8 30 31
----------------------------------------------------------------------------
Segmented earnings
(loss) before
the following 157 125 444 613 11 10 44 41
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Stock-based compensation
(recovery) expense
Interest, net
Unrealized risk management
activities
Foreign exchange (gain) loss
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before taxes
Taxes other than income tax
Current income tax expense
Future income tax (recovery)
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment
elimination and other Total
Three Months Year Ended Three Months Year Ended
(millions of Ended Dec 31 Dec 31 Ended Dec 31 Dec 31
Canadian dollars, ---------------------------------------------------------
unaudited) 2007 2006 2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
Segmented revenue (17) (19) (53) (61) 3,200 2,826 12,543 11,643
Less: royalties - - - - (343) (317) (1,391)(1,245)
----------------------------------------------------------------------------
Segmented revenue,
net of royalties (17) (19) (53) (61) 2,857 2,509 11,152 10,398
----------------------------------------------------------------------------
Segmented expenses
Production (2) (2) (6) (6) 491 519 2,184 1,949
Transportation and
blending (11) (9) (42) (38) 467 333 1,570 1,443
Depletion,
depreciation and
amortization - - - - 719 724 2,863 2,391
Asset retirement
obligation accretion - - - - 17 18 70 68
Realized risk
management
activities - - - - 181 126 162 1,325
----------------------------------------------------------------------------
Total segmented
expenses (13) (11) (48) (44) 1,875 1,720 6,849 7,176
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following (4) (8) (5) (17) 982 789 4,303 3,222
----------------------------------------------------------------------------
Non-segmented expenses
Administration 42 57 208 180
Stock-based compensation
(recovery) expense (16) 176 193 139
Interest, net 51 62 276 140
Unrealized risk management
activities 845 (241) 1,400 (1,013)
Foreign exchange (gain) loss (47) 151 (471) 122
----------------------------------------------------------------------------
Total non-segmented
expenses 875 205 1,606 (432)
----------------------------------------------------------------------------
Earnings before taxes 107 584 2,697 3,654
Taxes other than income tax 33 41 165 256
Current income tax expense 123 95 380 222
Future income tax (recovery)
expense (847) 135 (456) 652
----------------------------------------------------------------------------
Net earnings 798 313 2,608 2,524
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net additions to property, plant and equipment
Year Ended Dec 31, 2007
-----------------------------------------
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 2,428 $ 52 $ 2,480
North Sea 439 (77) 362
Offshore West Africa 159 (11) 148
Other 1 - 1
Horizon Project (2) 3,301 - 3,301
Midstream 6 - 6
Head office 20 - 20
----------------------------------------------------------------------------
$ 6,354 $ (36) $ 6,318
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year Ended Dec 31, 2006
----------------------------------------
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 7,936 $ 1,521 $ 9,457
North Sea 646 (14) 632
Offshore West Africa 134 1 135
Other 11 - 11
Horizon Project (2) 3,185 - 3,185
Midstream 12 - 12
Head office 26 - 26
----------------------------------------------------------------------------
$ 11,950 $ 1,508 $ 13,458
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
---------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Segmented assets
North America $ 22,033 $ 21,879 $ 23,617 $ 23,670
North Sea 1,728 2,029 1,957 2,248
Offshore West Africa 1,188 1,204 1,354 1,323
Other 25 24 41 46
Horizon Project 8,651 5,350 8,740 5,444
Midstream 205 207 333 355
Head office 72 74 72 74
----------------------------------------------------------------------------
$ 33,902 $ 30,767 $ 36,114 $ 33,160
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capitalized interest
The Company capitalizes construction period interest based on
Horizon Project costs incurred and the Company's cost of borrowing.
Interest capitalization on 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 year
ended December 31, 2007, pre-tax interest of $356 million was
capitalized to the Horizon Project (December 31, 2006 - $196
million).
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
December 31, 2007:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 4.4x
Cash flow from operations (2) 10.8x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net earnings plus income taxes and interest expense; divided by the sum
of interest expense and capitalized interest.
(2) Cash flow from operations plus current income taxes and interest
expense; divided by the sum of interest expense and capitalized
interest.
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Time, 11:00
a.m. Eastern Time on Thursday, February 28, 2008. The North
American conference call number is 1-866-540-8136 and the outside
North American conference call number is 001-416-340-8010. 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, March 6, 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 3243753.
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 FIRST QUARTER RESULTS
2008 first quarter results are scheduled for release after
market close on Thursday, May 8, 2008. A conference call will be
held on Friday, May 9, 2008 at 9:00 a.m. Mountain Time, 11:00 a.m.
Eastern Time.
Contacts: Canadian Natural Resources Limited Allan P. Markin
Chairman (403) 514-7777 (403) 514-7888 (FAX) Canadian Natural
Resources Limited John G. Langille Vice-Chairman (403) 514-7777
(403) 514-7888 (FAX) Canadian Natural Resources Limited Steve W.
Laut President and Chief Operating Officer (403) 514-7777 (403)
514-7888 (FAX) Canadian Natural Resources Limited Douglas A. Proll
Chief Financial Officer and Senior Vice-President, Finance (403)
514-7777 (403) 514-7888 (FAX) Canadian Natural Resources Limited
Corey B. Bieber Vice-President, Finance & Investor Relations
(403) 514-7777 (403) 514-7888 (FAX) Canadian Natural Resources
Limited 2500, 855 - 2nd Street S.W. Calgary, Alberta T2P 4J8 Email:
ir@cnrl.com Website: www.cnrl.com
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