Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) -
Commenting on second quarter results, Allan Markin, Chairman of
Canadian Natural stated, "This is an exciting time for Canadian
Natural. Phase 1 of our Horizon Project is approaching completion.
This is a complex project which involves moving raw oil sands
materials through a complex process to yield raw bitumen crude oil
and then upgrading it to 34 degrees API, light sweet synthetic
crude oil. The hard work of everyone involved on the Horizon
Project has produced a world class asset that will provide steady
cash flow for years to come. Strong results from our conventional
operations reflect the strength and depth of our existing asset
base. It is a credit to our team and assets that we managed our
growth profile for conventional crude oil and natural gas growth
opportunities to build the Horizon Project."
John Langille, Vice-Chairman of Canadian Natural stated, "The
second quarter of 2008 saw continuing strength in both crude oil
and natural gas pricing. Narrow heavy crude oil differentials
combined with higher realized pricing for the quarter resulted in
Q2/08 cash flow of nearly $1.86 billion. As cash flow from the
Horizon Project is added to existing conventional cash flow, we
will focus on further strengthening our balance sheet as well as
opportunities available in our diverse asset base. Capital
discipline and allocation remain priorities to ensure returns are
optimized, even in a high commodity price environment."
Steve Laut, President and Chief Operating Officer of Canadian
Natural commented, "Q2/08 was a very strong quarter for us. In
Q2/08 both crude oil and natural gas production in Canada exceeded
the top end of our guidance, reflecting the strength of our
conventional asset base. Canadian Natural has achieved a
significant milestone as we proceed with the final construction,
commissioning and staged start-up of the Horizon Project and begin
to realize the benefits of the largest single capital project in
Canadian Natural's history. Our current schedule will see us
producing first bitumen crude oil in early September, first
partially upgraded crude oil by the end of September, and first 34
degrees API, light sweet synthetic crude oil in Q4/08.
We have experienced a slippage in our targeted start-up in the
production of synthetic crude oil as we have experienced delays in
the completion of the primary and secondary upgrading processes.
This has also resulted in increased project costs as manpower
requirements have been extended longer than our planning schedule
anticipated. Our current cost estimate has increased by 8% above
our previous estimate bringing the total cost to 36% above our
original 2004 estimate of $6.8 billion. The start-up of the Horizon
Project is a major step for Canadian Natural. We continue to evolve
and diversify our asset base and look forward to the continuous
stream of cash flow for years to come. The result is an even
stronger and more sustainable company.
As part of our three phase heavy crude oil marketing strategy,
Canadian Natural has made a significant step in the second phase to
secure additional markets. Canadian Natural has committed 120,000
bbl/d for 20 years to the Keystone Pipeline US Gulf Coast expansion
from Hardisty, Alberta to Port Arthur, Texas, which is subject to
regulatory approval. Canadian Natural has also secured an option to
acquire an equity interest in the Keystone Project.
Also fulfilling our defined heavy crude oil marketing plan is a
20 year 100,000 bbl/d supply arrangement with a major US refiner to
supply refineries in the Gulf Coast at market prices.
The completion of both of these agreements allows Canadian
Natural to proceed with increased confidence the development of
Canadian Natural's vast heavy oil assets and to deliver in a
methodical staged manner an incremental 325,000 bbl/d of heavy
crude oil. These agreements facilitate the unlocking of the value
in our vast heavy oil resource base and will create tremendous
value for Canadian Natural shareholders.
We remain focused on the costs we are able to control and manage
those that are outside our influence. We continue to direct our
investment - of time, energy and capital - towards those projects
and activities that provide the greatest return."
HIGHLIGHTS
Three Months Ended Six Months Ended
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Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions, except as noted) 2008 2008 2007 2008 2007
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Net earnings (loss) $ (347) $ 727 $ 841 $ 380 $ 1,110
per common share,
basic and diluted $ (0.65) $ 1.35 $ 1.56 $ 0.70 $ 2.06
Adjusted net earnings from
operations (1) $ 960 $ 872 $ 595 $1,832 $ 1,216
per common share,
basic and diluted $ 1.78 $ 1.61 $ 1.10 $ 3.39 $ 2.25
Cash flow from
operations (2) $ 1,859 $1,725 $1,513 $3,584 $ 3,135
per common share,
basic and diluted $ 3.44 $ 3.19 $ 2.81 $ 6.63 $ 5.82
Capital expenditures,
net of dispositions $ 2,127 $1,753 $1,460 $3,880 $ 3,469
Daily production,
before royalties
Natural gas (mmcf/d) 1,526 1,538 1,722 1,532 1,719
Crude oil and NGLs (bbl/d) 319,077 327,217 327,494 323,147 327,249
Equivalent production
(boe/d) 573,437 583,488 614,461 578,461 613,790
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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
measure is discussed in the Management's Discussion and Analysis
("MD&A").
(2) Cash flow from operations is a non-GAAP measure that the Company
considers key as it demonstrates the Company's ability to fund capital
reinvestment and repay debt. The derivation of this measure is
discussed in the MD&A.
- Natural gas production volumes for the second quarter
represented 44% of the Company's total production. Natural gas
production for Q2/08 averaged 1,526 mmcf/d, down slightly from
1,538 mmcf/d for Q1/08 and down 11% from 1,722 mmcf/d for Q2/07.
Q2/08 saw a very successful drilling program with North America
volumes exceeding corporate guidance. The decrease in volumes for
Q2/08 from Q2/07 reflected continued reallocation of capital
towards higher return projects in crude oil.
- Total crude oil and NGLs production for Q2/08 was 319,077
bbl/d. Q2/08 crude oil production volumes decreased 2% from Q1/08
of 327,217 bbl/d, and decreased 3% from Q2/07 of 327,494 bbl/d.
Volumes in Q2/08 reflect the transition between steam and
production cycles for Primrose thermal wells, continued conversion
of production wells to polymer injection wells at Pelican Lake,
along with turnarounds in the North Sea.
- Quarterly cash flow from operations was nearly $1.86 billion,
an 8% increase from Q1/08 and an increase of 23% from Q2/07. The
increase from Q2/07 primarily reflected higher crude oil and
natural gas realizations, partially offset by realized risk
management losses.
- Quarterly net loss for Q2/08 was $347 million primarily as a
result of risk management losses. Quarterly adjusted net earnings
from operations for Q2/08 were $960 million primarily due to higher
product prices.
- Maintained a strong undeveloped conventional core land base in
Canada of 11.4 million net acres - a key asset for continued value
growth.
- Improvements at the Pelican Lake Field continue with the
conversion of water flood wells to polymer flood wells, with a
daily average of approximately 37,000 bbl/d.
- The Primrose East Expansion, which is targeted to add 40,000
bbl/d of capacity, has made significant progress. First steam is
scheduled for September, coming in ahead of schedule, with first
production targeted for Q4/08 versus a previous target of
Q1/09.
- Drilling has started at Baobab in Offshore Cote d'Ivoire. The
equipment was mobilized in early Q2/08, enabling work to begin on
the restoration of shut-in production. It is targeted that a
minimum 3 of the 5 Baobab wells will come on stream over the course
of 2008 and 2009.
- The Olowi Project in Offshore Gabon continues on schedule with
first crude oil production targeted for late 2008.
- Construction and commissioning of the Horizon Oil Sands
Project ("Horizon Project") continued in Q2/08 with first bitumen
crude oil production targeted for early September, partially
upgraded crude oil production targeted for the end of September,
and first 34 degrees API, light sweet synthetic crude oil
production ("SCO") in Q4/08.
- Committed to ship 120,000 bbl/d of heavy crude oil for 20
years on the proposed Keystone pipeline US Gulf Coast expansion
from Hardisty, Alberta to Port Arthur, Texas.
- Committed to a 100,000 bbl/d heavy crude oil supply agreement
with a major US refiner to supply refineries in the Gulf Coast at
market prices for 20 years.
- Declared a quarterly cash dividend on common shares of C$0.10
per common share, payable October 1, 2008.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural
focuses its activities in core regions where it can dominate the
land base and infrastructure. Undeveloped land is critical to the
Company's ongoing growth and development within these core regions.
Land inventories are maintained to enable continuous exploitation
of play types and geological trends, greatly reducing overall
exploration risk. By dominating infrastructure, the Company is able
to maximize utilization of its production facilities, thereby
increasing control over production costs. Further, the Company
maintains large project inventories and production diversification
among each of the commodities it produces; namely natural gas,
light/medium crude oil, heavy crude oil and NGLs. A large
diversified project portfolio enables the effective allocation of
capital to higher return opportunities.
OPERATIONS REVIEW
Activity by core region
------------------------------------------------
Net undeveloped land Drilling activity
as at six months ended
Jun 30, 2008 Jun 30, 2008
(thousands of net acres) (net wells) (1)
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Canadian conventional
Northeast British Columbia 2,318 21.8
Northwest Alberta 1,428 53.9
Northern Plains 6,635 252.1
Southern Plains 863 68.8
Southeast Saskatchewan 123 19.4
In-situ Oil Sands 483 53.0
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11,850 469.0
Horizon Oil Sands Project 115 -
United Kingdom North Sea 268 4.1
Offshore West Africa 206 1.5
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12,439 474.6
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(1) Drilling activity includes stratigraphic test and service wells
Drilling activity (number of wells)
Six Months Ended Jun 30
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2008 2007
Gross Net Gross Net
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Crude oil 284 266 290 271
Natural gas 202 166 254 207
Dry 20 17 74 64
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Subtotal 506 449 618 542
Stratigraphic test / service wells 26 26 241 241
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Total 532 475 859 783
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Success rate (excluding
stratigraphic test / service wells) 96% 88%
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North America Conventional
North America natural gas
Three Months Ended Six Months Ended
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Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
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Natural gas production
(mmcf/d) 1,501 1,513 1,696 1,507 1,694
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Net wells targeting natural gas 8 167 7 175 252
Net successful wells drilled 5 161 6 166 207
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Success rate 63% 96% 86% 95% 82%
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- Q2/08 North America natural gas production decreased
marginally from Q1/08 and decreased 11% from Q2/07. The year over
year decrease reflected natural declines in base production and the
Company's strategic decision to reduce spending on natural gas
drilling. However, it was a very successful quarter with volumes
exceeding quarterly guidance targets.
- Canadian Natural targeted 8 net natural gas wells in Q2/08. In
Northeast British Columbia, 2 net wells were drilled, while in
Northwest Alberta, 1 net well was drilled. In the Northern Plains,
4 net wells were drilled, with 1 net well drilled in the Southern
Plains.
- Planned drilling activity for Q3/08 includes 81 natural gas
wells compared to drilling activity for Q3/07 of 106 natural gas
wells.
- Inflationary pressure continues to affect capital and service
costs for natural gas drilling. Cost control and maximizing
shareholder value remain priorities within this business
environment.
North America crude oil and NGLs
Three Months Ended Six Months Ended
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Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
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Crude oil and NGLs
production (bbl/d) 245,616 248,960 240,420 247,288 238,962
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Net wells targeting crude oil 94 176 78 270 285
Net successful wells drilled 92 171 75 263 266
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Success rate 98% 97% 96% 97% 93%
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- Q2/08 North America crude oil and NGLs production decreased
marginally from Q1/08 and increased 2% from Q2/07 levels. The
majority of the incremental production volume from Q2/07 was
contributed by thermal crude oil. The decrease from Q1/08 is a
reflection of transitioning off the production cycle peaks at
Primrose pads.
- 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. Drilling
is complete and facility construction is ahead of schedule, with
production targeted to commence in late 2008 versus the previous
production target of Q1/09. Primrose East is the second phase of
the 325,000 bbl/d thermal growth expansion plan identified to
unlock the value from Canadian Natural's thermal crude oil resource
base.
- 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 Q2/08. In
Q2/08, the Company drilled 32 horizontal wells with plans to drill
an additional 57 horizontal wells and 1 vertical service well
throughout the remainder of 2008. Pelican Lake production averaged
approximately 37,000 bbl/d for Q2/08 compared to approximately
34,000 bbl/d for Q2/07 and approximately 37,000 bbl/d for Q1/08.
The response from the polymer flood project continues to be
positive and the Company is moving forward on converting regions
currently under waterflood to polymer flood and expanding the
polymer flood to new areas.
- Conventional heavy crude oil production volumes remained
constant in Q2/08 compared to Q1/08, with volumes as expected.
- During Q2/08, drilling activity targeted 94 net wells
including 40 wells targeting heavy crude oil, 32 wells targeting
Pelican Lake crude oil, 14 wells targeting thermal crude oil and 8
wells targeting light crude oil.
- Planned drilling activity for Q3/08 includes 256 net crude oil
wells, excluding stratigraphic test and service wells.
- Inflationary pressure continues to affect capital and service
costs for crude oil drilling. Cost control and maximizing
shareholder value remain priorities within this business
environment.
International
Three Months Ended Six Months Ended
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Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
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Crude oil production (bbl/d)
North Sea 45,830 49,568 57,286 47,699 59,565
Offshore West Africa 27,631 28,689 29,788 28,160 28,722
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Natural gas production (mmcf/d)
North Sea 10 11 15 11 15
Offshore West Africa 15 14 11 14 10
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Net wells targeting crude oil 1.6 2.2 3.1 3.8 5.1
Net successful wells drilled 0.8 2.2 3.1 3.0 5.1
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Success rate 50% 100% 100% 79% 100%
North Sea
- During Q2/08, 2.4 net wells were drilled including 0.8 net
injection wells. At the end of the quarter 0.9 net crude oil wells
were in progress. Crude oil production was down 8% in Q2/08 to
45,830 bbl/d from 49,568 bbl/d in Q1/08 as a result of a planned
shutdown for maintenance at Ninian.
- Focus on waterflood optimization at Ninian continued with one
new water injection well being completed in Q2/08, increasing water
injection capacity. Compared to the first six months of last year
the Company has increased water injection by 25%.
- At Murchison, the second of two production wells planned for
2008 was completed in the quarter.
- During the quarter, an unsuccessful exploration well was
drilled on the Anning prospect which lies in proximity of the
Murchison Field.
Offshore West Africa
- Offshore West Africa's crude oil production was down 4% in
Q2/08 to 27,631 bbl/d from 28,689 bbl/d in Q1/08 with stable
production at Espoir and Baobab during the quarter.
- Progress on the Facility Upgrade Project at Espoir to increase
capacity of the Floating, Production, Storage and Offtake Vessel
("FPSO") continues to progress ahead of schedule and is still
expected to be completed in Q3/09, an acceleration of 3 to 6 months
from the original estimate.
- The deep water drilling rig for Baobab was mobilized early in
Q2/08, enabling work to begin on the restoration of shut-in
production. It is targeted that a minimum 3 of the 5 shut-in Baobab
wells be on stream over the course of 2008 and 2009.
- At the Olowi project in Offshore Gabon, a drilling rig was
mobilized and drilling commenced in early May of this year with
first crude oil production targeted for late 2008.
- Capital spending in Offshore West Africa is expected to
increase $250 million in 2008 primarily due to early delivery of
the second wellhead tower and minor scope changes for pipeline
heating at Olowi.
Horizon Project
- Canadian Natural has achieved a significant milestone,
entering the final construction, commissioning and staged start-up
of the Horizon Project. There are seven stages to the start-up and
the associated targeted start-up dates are as follows:
-- Stage 1 - Mining. The mining operation has been ready for
operation since May, and continues to move overburden. The mining
team awaits the call for first oil sands delivery.
-- Stage 2 - Steam Supply. Utility plants have been supplying
low, medium and high pressure steam in stages, with the last steam
(high pressure) delivered in the third week of July for testing and
commissioning purposes.
-- Stage 3 - Bitumen Crude Oil Production. Bitumen crude oil
production operations are in the final stages of commissioning with
first bitumen crude oil production targeted for early
September.
-- Stage 4 - Electricity Generation. The Co-generation Plant is
targeted to deliver full load electricity in the second half of
September.
-- Stage 5 - Sulphur Plant/Sour Gas Treating. The Sulphur Plant
is targeted to be ready to receive sour gas feed mid-August and
circulate amine, awaiting the first delivery of sour gas.
-- Stage 6 - Partially Upgraded Crude Oil Production. The
Delayed Coker/Diluent Recovery Unit Plants are in the commissioning
stage concurrent with the completion of final task lists (i.e.
punch-lists), and are targeted to deliver partially upgraded crude
oil to intermediate tanks by the end of September.
-- Stage 7 - 34 degrees API, Light Sweet SCO Production. The
Naphtha Hydrotreating Plant (Unit 41) is completing loop checks and
insulation concurrent with commissioning. First product output is
currently targeted for October. The Gas Oil Hydrotreating Plant
(Unit 43) is completing punch-lists, loop checks, electrical heat
tracing and insulation concurrent with commissioning with first
product output currently targeted for Q4/08. First, 34 degrees API,
light sweet SCO in the sales pipeline is currently targeted for
Q4/08. Capacity is targeted to be 70,000 bbl/d, meeting scheduled
product ramp-up. The Distillate Hydrotreating Plant (Unit 42) is
finishing mechanical completion, and completing electrical heat
tracing, insulation and loop checks, and currently targeted first
product output is for the latter part of Q4/08. Facility capacity
will be targeted to be 110,000 bbl/d of 34 degrees API, light sweet
SCO upon Plant 42 completion, ramping up production to facility
capacity and maintaining the previous production ramp-up
schedule.
- During the second quarter, Canadian Natural completed a
majority of the pre-commissioning activity, commissioned another
shovel and 12 more trucks in the mine, brought on Utilities (air,
water, steam, power and natural gas), and commenced operating
several of the bitumen crude oil production plants on water as a
"wet run" before the introduction of oil sands.
- Pre start-up safety reviews are taking longer to complete than
originally anticipated, however, the Company is remaining
disciplined and will not put the facilities and personnel at
risk.
- Significant progress was made but the Company has found that
testing and closing of all safety and operations punch-lists are
taking longer than expected. 42% of the over 800 plant systems were
turned over to operations at the end of the quarter. Progress by
major plant facility shows:
-- Mining - Completed, ready to mine oil sands and continues to
move overburden
-- Ore Preparation Plant - Completed, targeted to receive first
oil sands in August
-- Hydrotransport - Completed, ready to accept slurry
-- Piperack - Completed, live and operational
-- Extraction - Completed, ready for operation
-- Froth Treatment - Targeted to be complete by August
-- Delayed Coker/Diluent Recovery Unit - Commissioning well
underway
-- Hydrogen Plant - Completed, turned over to operations
-- Hydrotreaters - Plant 41 and 43 completing loop checks, Plant
42 encountering some scheduling issues
-- Co-generation - Completed, producing steam
-- Sulphur Plant - Completed, turned over to operations
-- Tankage - Completed, ready for first oil
-- Main Control Room - Completed, live and fully operational
-- Utilities & Services - Completed, live and fully
operational
-- SCO Pipeline(third party owned and operated) - Completed,
ready to accept product, with terminaling facilities in Edmonton
arranged
- Many challenges continue to be faced, with the critical path
item being the completion and turnover of all three Hydrotreaters
in a small window. The Distillate and Gas Oil Hydrotreater units
have encountered delays and schedule slippage resulting in
commissioning beyond the third quarter. The operations team has
developed an overall start-up scenario for initial operation at
approximately 60% of the design rate until the Distillate
Hydrotreater is commissioned to mitigate any impact to overall
production ramp-up.
- After the thorough monthly review in the second half of July
2008, it was determined that there was schedule slippage in
Upgrading/Hydrotreating Plants and it is taking longer to complete
testing, reinstatement and pre-commissioning activities of these
plants.
- A detailed review of the current cost estimate indicates that
the Horizon Project targeted final cost will increase by
approximately 8% or approximately $525 million above the previous
construction cost estimates bringing the total cost estimate of the
Horizon Project to approximately 36% above our original 2004 $6.8
billion estimate, or approximately $9.27 billion (up from the
previous total cost estimate of $8.74 billion). This increase will
result in a targeted on-stream cost of $84,000 bbl/d of capacity,
including the benefits of the significant pre-build capital
invested for Phase 2/3.
- With primary focus on completing Phase 1 and producing SCO,
Canadian Natural has a team working on future expansions. Several
long lead items for Phase 2/3 expansions are on site, including the
coke drums and hydrotreating reactors. The reactors have been
assembled on site and hydrotested. The Company has awarded nearly
all the Engineering (detailed design) and Procurement contracts for
the Tranche 2 scope and have held kick-off meetings with the
majority of the contractors.
- Canadian Natural is managing its commitment to safety and
celebrated over 20 million manhours without a lost time incident -
more than 1 year. Along with systems and start-up training for a
significant number of staff, the Company has completed its 'Going
Live' safety orientation for all Horizon Project employees and
contractors. The Pre Start-Up Safety Reviews have been initiated in
all plants and the learnings from earlier system turnovers are
being applied.
- For further details, refer to the Horizon Oil Sands Project
update from August 6, 2008.
MARKETING
Three Months Ended Six Months Ended
-----------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
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Crude oil and NGLs pricing
WTI(1) benchmark price
(US$/bbl) $ 124.00 $ 97.96 $ 65.02 $ 110.98 $ 61.64
Western Canadian Select
blend differential(2)
from WTI (%) 17% 22% 29% 19% 28%
Corporate average pricing
before risk management
(C$/bbl) $ 103.73 $ 78.99 $ 53.74 $ 91.11 $ 52.72
Natural gas pricing
AECO benchmark price
(C$/GJ) $ 8.86 $ 6.76 $ 6.99 $ 7.81 $ 7.03
Corporate average pricing
before risk management
(C$/mcf) $ 9.89 $ 7.77 $ 7.44 $ 8.83 $ 7.59
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(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
(2) Beginning in Q1 2008, the Company has quantified the Heavy Differential
using the Western Canadian Select ("WCS") blend as the heavy crude oil
marker. Prior period amounts have been reclassified.
- In Q2/08, the WCS heavy crude oil differential as a percent of
WTI was 17%, compared to 22% in Q1/08. Heavy crude oil
differentials improved in Q2/08 due to a strong worldwide demand
for diesel and low crack spreads, with overall high demand for
crude oil products. Combined with declining heavy crude oil
production in Mexico, and increased Venezuelan supply shipments to
the Asian markets, demand has been strong for Canadian heavy crude
oil.
- The Company continues its efforts with other industry players
to find new markets and to ease the logistical constraints in
getting Western Canadian heavy crude oil to new markets, such as
the US Gulf Coast. Plans were recently announced to expand the
Keystone crude oil pipeline system providing additional capacity to
the US Gulf Coast by 2012. Canadian Natural sees this as an
important step in its marketing strategy by allowing Canadian heavy
crude oil into the US Gulf Coast market and as such has committed
120,000 bbl/d to the Keystone Pipeline US Gulf Coast Expansion,
which is subject to regulatory approval, for a 20 year period. The
agreement also includes an option for Canadian Natural to acquire
an equity interest of the Keystone Pipeline.
- Canadian Natural has also entered into a 20 year supply
agreement with a major US refiner for 100,000 bbl/d of heavy crude
oil to US Gulf Coast refineries. These agreements represent a step
forward in the defined marketing plan of Canadian Natural to
improve the margins on the Company's heavy crude oil production and
to reduce the volatility historically experienced in the heavy
crude oil market. With the Keystone agreement, Canadian Natural
will retain full ownership of the resource while gaining access to
a key market for Canadian heavy crude oil. The refining capacity in
the US Gulf Coast area is approximately 7.5 million bbl/d. The long
term supply agreement with a US refiner, which is contingent on the
completion of the Keystone Pipeline US Gulf Coast Expansion,
ensures a customer at the end of the Keystone Pipeline for a large
portion of Canadian Natural's heavy crude oil that is shipped at
prevailing US Gulf Coast heavy oil market prices at the points of
delivery.
- The Company sees this as a strategic component to its heavy
crude oil development which targets an increase to heavy crude oil
production capacity from just over 200,000 bbl/d today, to over
500,000 bbl/d over the course of the next 15 years. Canadian heavy
crude oil is very competitive against other international grades
available in the US Gulf Coast. For Q2/08, the differential for the
heavy crude oil marker, Mayan grade, was US$21.00/bbl or 17%.
- During Q2/08, the Company contributed approximately 158,000
bbl/d of its heavy crude oil streams to the WCS blend as market
conditions resulted in this strategy offering the optimal pricing
for bitumen
crude oil.
- Natural gas pricing for Q2/08 was strong as demand for natural
gas increased more than expected during the quarter. The quarter
also saw fewer imports of liquefied natural gas to North America as
a result of stronger pricing in Europe and Asia, again resulting in
decreased supply to North America.
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 the Company's strengths are:
-- A diverse asset base geographically and by product - produced
in excess of 573,000 boe/d in Q2/08, 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 $1.86 billion for Q2/08, available unused bank lines of $2.7
billion at June 30, 2008 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
targeted ranges.
- Commencing January 1, 2009, the Company's commodity hedging
program has been revised by its Board of Directors to allow for the
hedging of up to 50% of the near 12 months budgeted production and
up to 25% of the following 13 to 24 months estimated production.
The purchase of put options will continue to be in addition to the
above parameters. The current program allows for hedging of 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 the expected
production in months 25 to 48. The Company continues to believe
that its risk management program meets its objective of securing
funding for its capital projects.
- In 2007 and 2008, the Province of Alberta issued certain
details of its proposed changes to the Alberta crude oil and
natural gas royalty regime, effective January 1, 2009. The Company
is currently awaiting finalization and government approval of the
royalty regulations, however it expects that its 2009 and future
Alberta royalty payments will increase as a result of the proposed
royalty changes and that its level of activity in Alberta in
aggregate will be reduced from what it otherwise would have been in
the absence of such royalty changes.
- Declared a quarterly cash dividend on common shares of C$0.10
per common share, payable October 1, 2008.
OUTLOOK
The Company forecasts 2008 production levels before royalties to
average between 1,482 and 1,511 mmcf/d of natural gas and between
308,000 and 350,000 bbl/d of crude oil and NGLs. Q3/08 production
guidance before royalties is forecast to average between 1,466 and
1,490 mmcf/d of natural gas and between 299,000 and 316,000 bbl/d
of crude oil and NGLs. Detailed guidance on production levels,
capital allocation and operating costs can be found on the
Company's website at
http://www.cnrl.com/investor_info/corporate_guidance/.
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 dependent 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 six and three months ended June 30, 2008 and the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2007.
All dollar amounts are referenced in millions of Canadian
dollars, except where noted otherwise. The financial statements
have been prepared in accordance with Canadian generally accepted
accounting principles ("GAAP"). This MD&A includes references
to financial measures commonly used in the crude oil and natural
gas industry, such as adjusted net earnings from operations and
cash flow from operations. These financial measures are not defined
by GAAP and therefore are referred to as non-GAAP measures. The
non-GAAP measures used by the Company may not be comparable to
similar measures presented by other companies. The Company uses
these non-GAAP measures to evaluate its performance. The non-GAAP
measures should not be considered an alternative to or more
meaningful than net earnings, as determined in accordance with
GAAP, as an indication of the Company's performance. The measures
adjusted net earnings from operations and cash flow from operations
are reconciled to net earnings in the "Financial Highlights"
section of this MD&A. The Company also presents certain
non-GAAP financial ratios and their derivation in the "Liquidity
and Capital Resources" section of this MD&A.
The calculation of barrels of oil equivalent ("boe") is based on
a conversion ratio of six thousand cubic feet ("mcf") of natural
gas to one barrel ("bbl") of crude oil to estimate relative energy
content. This conversion may be misleading, particularly when used
in isolation, since the 6 mcf:1 bbl ratio is based on an energy
equivalency at the burner tip and does not represent the value
equivalency at the wellhead.
Production volumes are presented throughout this MD&A on a
"before royalty" or "gross" basis, and realized prices exclude the
effect of risk management activities and transportation and
blending costs, except where noted otherwise. Production on an
"after royalty" or "net" basis is also presented for information
purposes only.
The following discussion refers primarily to the Company's
financial results for the six and three months ended June 30, 2008
in relation to the comparable periods in 2007 and the first quarter
of 2008. The accompanying tables form an integral part of this
MD&A. This MD&A is dated August 6, 2008. Additional
information relating to the Company, including its Annual
Information Form for the year ended December 31, 2007, is available
on SEDAR at www.sedar.com.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Six Months Ended
-----------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue, before royalties $ 5,112 $ 3,967 $ 3,152 $ 9,079 $ 6,270
Net earnings (loss) $ (347) $ 727 $ 841 $ 380 $ 1,110
Per common share
- basic and diluted $ (0.65) $ 1.35 $ 1.56 $ 0.70 $ 2.06
Adjusted net earnings
from operations (1) $ 960 $ 872 $ 595 $ 1,832 $ 1,216
Per common share
- basic and diluted $ 1.78 $ 1.61 $ 1.10 $ 3.39 $ 2.25
Cash flow from
operations (2) $ 1,859 $ 1,725 $ 1,513 $ 3,584 $ 3,135
Per common share
- basic and diluted $ 3.44 $ 3.19 $ 2.81 $ 6.63 $ 5.82
Capital expenditures,
net of dispositions $ 2,127 $ 1,753 $ 1,460 $ 3,880 $ 3,469
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted net earnings from operations is a non-GAAP measure that
represents net earnings adjusted for certain items of a non-operational
nature. The Company evaluates its performance based on adjusted net
earnings from operations. The reconciliation "Adjusted Net Earnings from
Operations" presented below lists the after-tax effects of certain items
of a non-operational nature that are included in the Company's financial
results. Adjusted net earnings from operations may not be comparable to
similar measures presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that represents net
earnings adjusted for non-cash items before working capital adjustments.
The Company evaluates its performance based on cash flow from
operations. The Company considers cash flow from operations a key
measure as it demonstrates the Company's ability to generate the cash
flow necessary to fund future growth through capital investment and to
repay debt. The reconciliation "Cash Flow from Operations" presented
below lists certain non-cash items that are included in the Company's
financial results. Cash flow from operations may not be comparable to
similar measures presented by other companies.
Adjusted Net Earnings from Operations
Three Months Ended Six Months Ended
-----------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Net earnings (loss)
as reported $ (347) $ 727 $ 841 $ 380 $ 1,110
Stock-based compensation
expense, net of tax (a) 328 - 74 328 91
Unrealized risk management
loss (gain), net of tax (b) 997 76 (35) 1,073 327
Unrealized foreign exchange
(gain) loss, net of tax (c) (18) 110 (214) 92 (241)
Effect of statutory tax rate
and other legislative
changes on future income tax
liabilities (d) - (41) (71) (41) (71)
----------------------------------------------------------------------------
Adjusted net earnings from
operations $ 960 $ 872 $ 595 $ 1,832 $ 1,216
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) The Company's employee stock option plan provides for a cash payment
option. Accordingly, the intrinsic value of outstanding vested options
is recorded as a liability on the Company's balance sheet and periodic
changes in the intrinsic value are recognized in net earnings or are
capitalized as part of the Horizon Oil Sands Project during the
construction period.
(b) Derivative financial instruments are recorded at fair value on the
balance sheet, with changes in fair value of non-designated hedges
recognized in net earnings. The amounts ultimately realized may be
materially different than reflected in the financial statements due to
changes in prices of the underlying items hedged, primarily crude oil
and natural gas.
(c) Unrealized foreign exchange gains and losses result primarily from the
translation of US dollar denominated long-term debt to period-end
exchange rates, offset by the impact of cross currency swaps, and are
recognized in net earnings.
(d) All substantively enacted adjustments in applicable income tax rates
and other legislative changes are applied to underlying assets and
liabilities on the Company's consolidated balance sheet in determining
future income tax assets and liabilities. The impact of these tax rate
and other legislative changes is recorded in net earnings during the
period the legislation is substantively enacted. Income tax rate changes
in the first quarter of 2008 resulted in a reduction of future income
tax liabilities of approximately $19 million in North America and $22
million in Cote d'Ivoire, Offshore West Africa. Income tax rate changes
in the second quarter of 2007 resulted in a reduction of future income
tax liabilities of approximately $71 million in North America.
Cash Flow from Operations
Three Months Ended Six Months Ended
-----------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Net earnings (loss) $ (347) $ 727 $ 841 $ 380 $ 1,110
Non-cash items:
Depletion, depreciation
and amortization 670 688 720 1,358 1,429
Asset retirement obligation
accretion 17 17 17 34 35
Stock-based compensation
expense 459 - 106 459 131
Unrealized risk management
loss (gain) 1,415 108 (57) 1,523 479
Unrealized foreign exchange
(gain) loss (20) 126 (250) 106 (282)
Deferred petroleum revenue
tax (recovery) expense (34) (21) 20 (55) 17
Future income tax (recovery)
expense (301) 80 116 (221) 216
----------------------------------------------------------------------------
Cash flow from operations $ 1,859 $ 1,725 $ 1,513 $ 3,584 $ 3,135
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the six months ended June 30, 2008 were $380
million compared to $1,110 million for the six months ended June
30, 2007. Net earnings for the six months ended June 30, 2008
included net unrealized after-tax expenses of $1,452 million
related to the effects of risk management activities, fluctuations
in foreign exchange rates, fluctuations in stock-based compensation
expense and the impact of statutory tax rate changes on future
income tax liabilities, compared to net unrealized after-tax
expenses of $106 million for the six months ended June 30, 2007.
Excluding these items, adjusted net earnings from operations for
the six months ended June 30, 2008 increased to a record $1,832
million compared to $1,216 million for the six months ended June
30, 2007. The increase in adjusted net earnings from the comparable
period in 2007 was primarily due to the impact of higher realized
pricing, lower depletion, depreciation and amortization expense,
lower interest expense, and lower administration expense. These
factors were partially offset by higher realized risk management
losses, higher royalty and production expense, lower sales volumes
and the impact of the stronger Canadian dollar relative to the US
dollar.
The net loss for the second quarter of 2008 was $347 million
compared to net earnings of $841 million for the second quarter of
2007 and net earnings of $727 million for the prior quarter. The
net loss for the second quarter of 2008 included net unrealized
after-tax expenses of $1,307 million related to the effects of risk
management activities, fluctuations in foreign exchange rates, and
fluctuations in stock-based compensation expense, compared to net
unrealized after-tax income of $246 million for the second quarter
of 2007 and net unrealized after-tax expenses of $145 million for
the prior quarter, which also included the impact of statutory tax
rate changes on future income tax liabilities. Excluding these
items, adjusted net earnings from operations for the second quarter
of 2008 increased to a record $960 million compared to $595 million
for the second quarter of 2007 and $872 million for the prior
quarter. The increase in adjusted net earnings from the second
quarter of 2007 and the prior quarter was primarily due to the
impact of higher realized pricing, lower depletion, depreciation
and amortization expense, lower interest expense, and lower
administration expense. These factors were partially offset by
higher realized risk management losses, higher royalty and
production expense, and lower sales volumes. The increase in
adjusted net earnings from the second quarter of 2007 was also
partially offset by the impact of the stronger Canadian dollar
relative to the US dollar.
The impacts of risk management activities, stock-based
compensation expense and fluctuations in foreign exchange rates are
expected to continue to contribute to significant quarterly
volatility in consolidated net earnings.
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
currently 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 put
options is in addition to the above parameters. In accordance with
the policy, approximately 57% of budgeted crude oil volumes are
hedged for the remainder of 2008, approximately 18% of budgeted
natural gas volumes are hedged for the third quarter of 2008 and
approximately 6% of estimated crude oil volumes are hedged for
2009. In addition, 50,000 bbl/d of crude oil volumes are protected
by put options for the remainder of 2008 at a strike price of
US$55.00 per bbl, 50,000 bbl/d of crude oil volumes are protected
by put options for 2009 at a strike price of US$80.00 per bbl, and
42,000 bbl/d of crude oil volumes are protected by put options for
2009 at a strike price of US$100.00 per bbl. Subsequent to June 30,
2008, the Company unwound 50,000 bbl/d of US$80.00 WTI put options
and entered into 50,000 bbl/d of US$100.00 WTI put options for the
period January to December 2009.
Commencing January 1, 2009, following the planned completion of
Phase 1 of the Horizon Project, the Company's commodity hedging
program has been revised by its Board of Directors to allow for the
hedging of up to 50% of the near 12 months budgeted production and
up to 25% of the following 13 to 24 months estimated production.
The purchase of put options will continue to be in addition to the
above parameters.
The Company's outstanding commodity related financial
derivatives as at June 30, 2008 are detailed in the "Liquidity and
Capital Resources" section of this MD&A.
The commodity derivative financial instruments currently
outstanding have not been designated as hedges for accounting
purposes (the "non-designated hedges"). The fair value of these
non-designated hedges is based on prevailing forward commodity
prices in effect at the end of each reporting period and is
reflected in risk management activities in consolidated net
earnings. The cash settlement amount of the risk management
derivative financial instruments may vary materially depending upon
the underlying crude oil and natural gas prices at the time of
final settlement of the derivative financial instruments, as
compared to their mark-to-market value at June 30, 2008.
Due to changes in crude oil and natural gas forward pricing and
the reversal of prior period unrealized gains and losses, the
Company recorded a net unrealized loss of $1,523 million ($1,073
million after-tax) on its commodity risk management activities for
the six months ended June 30, 2008, including a $1,415 million
($997 million after-tax) unrealized loss for the three months ended
June 30, 2008. 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. For further details, refer to the "Risk
Management Activities" section of this MD&A.
Subsequent to June 30, 2008, prevailing forward commodity prices
declined. Based on forward pricing as at July 31, 2008 and
including the effects of July 2008 settlements, unrealized risk
management losses as at June 30, 2008 would have decreased by
approximately $680 million ($480 million after-tax).
The Company recorded a $459 million ($328 million after-tax)
stock-based compensation expense for the six and three months ended
June 30, 2008 as a result of the increase in the Company's share
price (Company's share price as at: June 30, 2008 - C$100.84; March
31, 2008 - C$70.27; December 31, 2007 - C$72.58; June 30, 2007 -
C$70.78). 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 June 30, 2008 reflected the Company's
potential cash liability should vested options be surrendered for a
cash payout at the market price on June 30, 2008. In periods when
substantial share price changes occur, the Company's net earnings
are subject to significant volatility. The Company utilizes its
stock-based compensation plan to attract and retain employees in a
competitive environment. All employees participate in this
plan.
Cash flow from operations for the six months ended June 30, 2008
increased to a record $3,584 million compared to $3,135 million for
the six months ended June 30, 2007. The increase from the
comparable period in 2007 was primarily due to the impact of higher
realized pricing, partially offset by higher realized risk
management losses, higher royalty and production expense, higher
current income tax expense, lower sales volumes and the impact of
the stronger Canadian dollar relative to the US dollar.
Cash flow from operations for the second quarter of 2008
increased to a record $1,859 million compared to $1,513 million for
the second quarter of 2007 and $1,725 million for the prior
quarter. The increase from the second quarter of 2007 was primarily
due to the impact of higher realized pricing, partially offset by
higher realized risk management losses, higher royalty and
production expense, higher current income tax expense, lower sales
volumes and the impact of the stronger Canadian dollar relative to
the US dollar. The increase from the prior quarter was primarily
due to the impact of higher realized pricing, partially offset by
higher realized risk management losses, and higher royalty and
production expense.
Total production before royalties for the six months ended June
30, 2008 decreased 6% to average 578,461 boe/d from 613,790 boe/d
for the six months ended June 30, 2007. Production for the second
quarter of 2008 decreased 7% to 573,437 boe/d from 614,461 boe/d
for the second quarter of 2007 and 2% from 583,488 boe/d for the
prior quarter. Total production for the second quarter of 2008 was
at the high end of the Company's previously issued guidance.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results
for the eight most recently completed quarters:
----------------------------------------------------------------------------
($ millions, except per common share Jun 30 Mar 31 Dec 31 Sep 30
amounts) 2008 2008 2007 2007
----------------------------------------------------------------------------
Revenue, before royalties $ 5,112 $ 3,967 $ 3,200 $ 3,073
Net earnings (loss) $ (347) $ 727 $ 798 $ 700
Net earnings (loss) per common share
- Basic and diluted $ (0.65) $ 1.35 $ 1.48 $ 1.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common share Jun 30 Mar 31 Dec 31 Sep 30
amounts) 2007 2007 2006 2006
----------------------------------------------------------------------------
Revenue, before royalties $ 3,152 $ 3,118 $ 2,826 $ 3,108
Net earnings $ 841 $ 269 $ 313 $ 1,116
Net earnings per common share
- Basic and diluted $ 1.56 $ 0.50 $ 0.58 $ 2.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings (loss) over the eight most recently completed
quarters generally reflected fluctuations in realized crude oil and
natural gas prices, fluctuations in sales volumes, the impact of
mark-to-market accounting of financial instruments and stock-based
compensation, fluctuations in depletion, depreciation and
amortization charges, fluctuations in foreign exchange rates, and
adjustments to future income tax liabilities due to statutory tax
rate and other legislative changes. More specifically, volatility
in quarterly net earnings was primarily due to:
- 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 seasonal fluctuations in
both the demand for natural gas and inventory storage levels and
fluctuations in liquefied natural gas imports into the US.
- 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 Espoir, and additional sales volumes from the
Anadarko Canada Corporation ("ACC") acquisition completed in the
fourth quarter of 2006. Crude oil and NGLs sales volumes also
reflected fluctuations in production from the North Sea due to
timing of maintenance activities and liftings and the impact of
shut-in Baobab production in Offshore West Africa.
- 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, partially offset
by the impact of cross currency swaps.
- Risk management
Net earnings have fluctuated due to the recognition of realized
and unrealized gains and losses from the mark-to-market of the
Company's risk management activities.
- Changes in income tax expense
Income tax expense fluctuations include statutory tax rate and
other legislative changes enacted or substantively enacted in the
various periods.
- Stock-based compensation
Net earnings have fluctuated due to the mark-to-market movements
of the Company's stock-based compensation liability. Stock-based
compensation expense (recovery) reflected fluctuations in the
Company's share price over the eight most recently completed
quarters.
- Production expense
Production expense has fluctuated company wide primarily due to
the impact for the demand for services, industry-wide inflationary
cost pressures experienced in prior years in all segments,
fluctuations in product mix, and the impact of seasonal costs that
are dependent on weather.
- Depletion, depreciation and amortization
Depletion, depreciation and amortization expense has fluctuated
due to changes in sales volumes, finding and development costs
associated with crude oil and natural gas exploration, estimated
future costs to develop the Company's proved undeveloped reserves,
and a higher depletion base in North America related to the ACC
acquisition.
OPERATING HIGHLIGHTS
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
Sales price (2) $ 103.73 $ 78.99 $ 53.74 $ 91.11 $ 52.72
Royalties 14.82 8.70 5.46 11.70 5.19
Production expense 16.39 14.81 15.01 15.58 14.40
----------------------------------------------------------------------------
Netback $ 72.52 $ 55.48 $ 33.27 $ 63.83 $ 33.13
----------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 9.89 $ 7.77 $ 7.44 $ 8.83 $ 7.59
Royalties 1.86 1.35 1.10 1.60 1.29
Production expense 0.94 1.03 0.89 0.98 0.93
----------------------------------------------------------------------------
Netback $ 7.09 $ 5.39 $ 5.45 $ 6.25 $ 5.37
----------------------------------------------------------------------------
Barrels of oil equivalent
($/boe) (1)
Sales price (2) $ 84.88 $ 65.09 $ 49.70 $ 74.86 $ 49.50
Royalties 13.26 8.43 5.99 10.82 6.37
Production expense 11.60 11.02 10.44 11.31 10.27
----------------------------------------------------------------------------
Netback $ 60.02 $ 45.64 $ 33.27 $ 52.73 $ 32.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
WTI benchmark price
(US$/bbl) $ 124.00 $ 97.96 $ 65.02 $ 110.98 $ 61.64
Dated Brent benchmark
price (US$/bbl) $ 121.39 $ 96.94 $ 68.74 $ 109.17 $ 63.28
WCS blend differential
from WTI (US$/bbl) (1) $ 21.62 $ 21.41 $ 19.17 $ 21.51 $ 17.33
WCS blend differential
from WTI (%) (1) 17% 22% 29% 19% 28%
Condensate benchmark price
(US$/bbl) $ 124.64 $ 98.40 $ 65.66 $ 111.52 $ 62.28
NYMEX benchmark price
(US$/mmbtu) $ 10.80 $ 8.07 $ 7.56 $ 9.44 $ 7.26
AECO benchmark price
(C$/GJ) $ 8.86 $ 6.76 $ 6.99 $ 7.81 $ 7.03
US / Canadian dollar
average exchange rate $ 0.9900 $ 0.9958 $ 0.9112 $ 0.9929 $ 0.8812
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Beginning in the first quarter of 2008, the Company has quantified the
Heavy Differential using the Western Canadian Select ("WCS") blend as
the heavy crude oil marker. Prior period amounts have been reclassified.
Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$110.98
per bbl for the six months ended June 30, 2008, an increase of 80%
from US$61.64 per bbl for the six months ended June 30, 2007. WTI
averaged US$124.00 per bbl for the second quarter of 2008, an
increase of 91% from US$65.02 per bbl for the second quarter of
2007, and an increase of 27% from US$97.96 per bbl for the prior
quarter. WTI pricing during the second quarter of 2008 generally
reflected continued strong demand for crude oil and continued
geopolitical events resulting in increased market uncertainty and
limited supply.
Crude oil sales contracts for the Company's North Sea and
Offshore West Africa segments are typically based on Dated Brent
("Brent") pricing, which generally continued to benefit from strong
European and Asian demand. Brent averaged US$109.17 per bbl for the
six months ended June 30, 2008, an increase of 73% compared to
US$63.28 per bbl for the six months ended June 30, 2007. In the
second quarter of 2008, Brent averaged US$121.39 per bbl, an
increase of 77% compared to US$68.74 per bbl for the second quarter
of 2007, and an increase of 25% from US$96.94 per bbl for the prior
quarter.
The Company's realized crude oil prices increased from the six
months ended June 30, 2007 primarily as a result of increased WTI
and Brent pricing and a narrower Heavy Differential, offset by the
impact of a strong Canadian dollar. The Heavy Differential averaged
19% for the six months ended June 30, 2008 compared to 28% for the
six months ended June 30, 2007. For the second quarter of 2008, the
Heavy Differential averaged 17% compared to 29% for the second
quarter of 2007, and 22% for the prior quarter. The narrowing of
the Heavy Differential from the prior period was primarily due to
increased demand for heavy crude oil due to reduced refinery
cracking margins and increased demand for diesel, as well as an
industry wide reduction in Canadian production of heavy crude oil.
Realized prices continued to be adversely impacted by the strong
Canadian dollar.
The Company anticipates continued volatility in the crude oil
pricing benchmarks due to the unpredictable nature of ongoing
supply and demand factors and geopolitical events. The Heavy
Differential is expected to continue to reflect seasonal demand
fluctuations and refinery cracking margins.
NYMEX natural gas prices averaged US$9.44 per mmbtu for the six
months ended June 30, 2008, an increase of 30% from US$7.26 per
mmbtu for the six months ended June 30, 2007. For the second
quarter of 2008, NYMEX natural gas prices averaged US$10.80 per
mmbtu, an increase of 43% from US$7.56 per mmbtu for the second
quarter of 2007, and 34% from US$8.07 per mmbtu for the prior
quarter. AECO natural gas prices for the six months ended June 30,
2008 increased 11% to average $7.81 per GJ from $7.03 per GJ for
the six months ended June 30, 2007. For the second quarter of 2008,
AECO natural gas prices averaged $8.86 per GJ, an increase of 27%
from $6.99 per GJ in the second quarter of 2007 and 31% from $6.76
per GJ for the prior quarter. Increased natural gas prices from the
comparable periods were primarily related to higher overall demand
and lower storage levels, resulting from increased industrial
consumption, colder weather experienced late in the first quarter
of 2008, and lower liquefied natural gas imports into the US during
the first half of 2008.
Operating, Royalty and Capital Costs
Strong commodity prices in recent years have resulted in
increased demand and costs for oilfield services worldwide. This
has led to inflationary operating and capital cost pressures
throughout the 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 CO2e annually. Two
of the Company's facilities, the Primrose/Wolf Lake in-situ heavy
crude oil facilities and the Hays sour natural gas plant, are
captured under the regulations. In the UK, GHG regulations have
been in effect since 2005. During Phase 1 (2005 - 2007) of the UK
National Allocation Plan the Company operated below its CO2
allocation. For Phase 2 (2008 - 2012) the Company's CO2 allocation
has been decreased below the Company's estimated current operations
emissions. The Company continues to focus on implementing reduction
programs based on efficiency audits to reduce CO2 emissions at its
major facilities and on trading mechanisms to ensure compliance
with any requirement in effect from time to time.
During the first quarter of 2008, British Columbia announced a
carbon tax on fuel consumed in the province. Commencing July 1,
2008, the carbon tax will be assessed at $10/tonne of CO2e,
increasing to $30/tonne by July 1, 2012.
Continued cost pressures and the final outcome of changes to
environmental regulations may adversely impact the Company's future
net earnings, cash flow and capital projects.
In 2007 and 2008, the Province of Alberta issued certain details
of its proposed changes to the Alberta crude oil and natural gas
royalty regime, effective January 1, 2009. These proposed changes
include:
- The implementation of a new bitumen valuation methodology and
a sliding scale for oil sands royalties ranging from 1% to 9% on a
gross revenue basis pre-payout and 25% to 40% on a net revenue
basis post-payout depending on benchmark crude oil pricing; and
- New royalty formulas for conventional crude oil and natural
gas that are to operate on sliding scales ranging up to 50%
determined by commodity prices and well productivity.
The Company is currently awaiting finalization and government
approval of the royalty regulations, however it expects that its
2009 and future Alberta royalty payments will increase as a result
of the proposed royalty changes and that its level of activity in
Alberta in aggregate will be reduced from what it otherwise would
have been in the absence of such royalty changes.
PRODUCT PRICES
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1) (2)
North America $ 97.94 $ 72.86 $ 47.20 $ 85.31 $ 46.66
North Sea $ 129.57 $ 99.01 $ 73.18 $ 112.75 $ 70.84
Offshore West Africa $ 114.56 $ 96.31 $ 72.84 $ 105.51 $ 65.34
Company average $ 103.73 $ 78.99 $ 53.74 $ 91.11 $ 52.72
Natural gas
($/mcf) (1) (2)
North America $ 9.94 $ 7.80 $ 7.47 $ 8.87 $ 7.62
North Sea $ 4.27 $ 3.30 $ 3.92 $ 3.77 $ 4.21
Offshore West Africa $ 8.97 $ 7.89 $ 6.22 $ 8.44 $ 6.11
Company average $ 9.89 $ 7.77 $ 7.44 $ 8.83 $ 7.59
Company average
($/boe) (1) (2) $ 84.88 $ 65.09 $ 49.70 $ 74.86 $ 49.50
Percentage of gross
revenue (2)
(excluding midstream
revenue)
Crude oil and NGLs 68% 68% 57% 68% 57%
Natural gas 32% 32% 43% 32% 43%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 73% to average
$91.11 per bbl for the six months ended June 30, 2008 from $52.72
per bbl for the six months ended June 30, 2007. Realized crude oil
prices for the second quarter of 2008 increased 93% to average
$103.73 per bbl from $53.74 per bbl for the second quarter of 2007,
and increased 31% from $78.99 per bbl for the prior quarter. The
Company's realized crude oil prices increased from the comparable
periods in 2007 and the prior quarter primarily as a result of an
increased WTI and Brent benchmark prices and a narrower Heavy
Differential, partially offset by a strong Canadian dollar relative
to the US dollar.
The Company's realized natural gas price increased 16% to
average $8.83 per mcf for the six months ended June 30, 2008 from
$7.59 per mcf for the six months ended June 30, 2007. Realized
natural gas price for the second quarter of 2008 increased 33% to
average $9.89 per mcf from $7.44 per mcf for the second quarter of
2007, and increased 27% from $7.77 per mcf for the prior quarter.
The increase in realized natural gas prices from the comparable
periods primarily reflected increased benchmark prices due to
increased industrial consumption, colder weather experienced late
in the first quarter of 2008, and lower liquefied natural gas
imports into the US in the first half of 2008.
North America
North America realized crude oil prices increased 83% to average
$85.31 per bbl for the six months ended June 30, 2008 from $46.66
per bbl for the six months ended June 30, 2007. Realized crude oil
prices increased 108% to average $97.94 per bbl for the second
quarter of 2008 from $47.20 per bbl for the second quarter of 2007,
and increased 34% from $72.86 per bbl for the prior quarter. The
increase from the comparable periods was due to the increase in WTI
benchmark pricing and a narrower Heavy Differential.
In North America, the Company continues to focus on its crude
oil marketing strategy, including the development of a blending
strategy that expands markets within current pipeline
infrastructure, supporting pipeline projects that will provide
capacity to transport crude oil to new markets, and working with
refiners to add incremental heavy crude oil conversion capacity.
During the second quarter, the Company contributed approximately
158,000 bbl/d of heavy crude oil blends to the WCS stream.
Subsequent to June 30, 2008, the Company entered into a 20 year
transportation agreement to commit to ship 120,000 bbl/d of heavy
sour crude oil on the proposed 500,000 bbl/d Keystone Pipeline US
Gulf Coast expansion from Hardisty, Alberta to the US Gulf Coast.
Contemporaneously, the Company also entered into a 20 year crude
oil purchase and sales agreement to sell 100,000 bbl/d of heavy
sour crude oil to a major US refiner. Deliveries under the
agreements are expected to commence in 2012 and are subject to
Keystone's receipt of regulatory approval of the pipeline expansion
as well as minimum levels of shipper commitments.
North America realized natural gas prices increased 16% to
average $8.87 per mcf for the six months ended June 30, 2008 from
$7.62 per mcf for the six months ended June 30, 2007. Realized
North America natural gas prices increased 33% to average $9.94 per
mcf for the second quarter of 2008 from $7.47 per mcf for the
second quarter of 2007, and increased 27% from $7.80 per mcf for
the prior quarter. The increase in natural gas prices from the
comparable periods was primarily related to the increase in
benchmark prices.
Comparisons of the prices received for the Company's North
America production by product type were as follows:
Jun 30 Mar 31 Jun 30
2008 2008 2007
----------------------------------------------------------------------------
Wellhead Price (1) (2)
Light/medium crude oil and NGLs (C$/bbl) $ 113.92 $ 88.78 $ 63.09
Pelican Lake crude oil (C$/bbl) $ 98.28 $ 72.77 $ 44.49
Primary heavy crude oil (C$/bbl) $ 95.39 $ 68.61 $ 42.30
Thermal heavy crude oil (C$/bbl) $ 88.72 $ 65.97 $ 41.09
Natural gas (C$/mcf) $ 9.94 $ 7.80 $ 7.47
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North Sea
North Sea realized crude oil prices increased 59% to average
$112.75 per bbl for the six months ended June 30, 2008 from $70.84
per bbl for the six months ended June 30, 2007. Realized North Sea
crude oil prices increased 77% to average $129.57 per bbl for the
second quarter of 2008 from $73.18 per bbl for the second quarter
of 2007, and by 31% from $99.01 per bbl for the prior quarter. As
revenue in the North Sea is currently recognized on a liftings
basis, realized crude oil prices per bbl in any particular quarter
are dependant on the frequency and timing of liftings of each
field. Realized crude oil prices in the North Sea during the second
quarter continued to benefit from the impact of strong European and
Asian demand, partially offset by the impact of the strong Canadian
dollar.
Offshore West Africa
Offshore West Africa realized crude oil prices increased 61% to
average $105.51 per bbl for the six months ended June 30, 2008 from
$65.34 per bbl for the six months ended June 30, 2007. Realized
Offshore West Africa crude oil prices increased 57% to average
$114.56 per bbl for the second quarter of 2008 from $72.84 per bbl
for the second quarter of 2007, and increased 19% from $96.31 per
bbl for the prior quarter. As revenue in Offshore West Africa is
recognized on a liftings basis, realized crude oil prices per bbl
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 second quarter continued to benefit from the impact of
strong European and Asian demand, offset by the impact of the
strong Canadian dollar.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when
title transfers to the customer and delivery has taken place. The
related crude oil volumes by segment, which have not been
recognized in revenue, were as follows:
Jun 30 Mar 31 Dec 31
(bbl) 2008 2008 2007
----------------------------------------------------------------------------
North America, related to pipeline fill 1,097,526 1,097,526 1,097,526
North Sea, related to timing of liftings 802,576 637,755 1,032,723
Offshore West Africa, related to timing of
liftings 377,741 260,649 8,578
----------------------------------------------------------------------------
2,277,843 1,995,930 2,138,827
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the second quarter of 2008, an additional 282,000 barrels of
crude oil produced in the Company's international operations was
deferred and included in inventory at June 30, 2008, reducing cash
flow from operations by approximately $42 million.
DAILY PRODUCTION, before royalties
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America 245,616 248,960 240,420 247,288 238,962
North Sea 45,830 49,568 57,286 47,699 59,565
Offshore West Africa 27,631 28,689 29,788 28,160 28,722
----------------------------------------------------------------------------
319,077 327,217 327,494 323,147 327,249
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,501 1,513 1,696 1,507 1,694
North Sea 10 11 15 11 15
Offshore West Africa 15 14 11 14 10
----------------------------------------------------------------------------
1,526 1,538 1,722 1,532 1,719
----------------------------------------------------------------------------
Total barrels of oil
equivalent (boe/d) 573,437 583,488 614,461 578,461 613,790
----------------------------------------------------------------------------
Product mix
Light/medium crude oil and
NGLs 22% 23% 23% 22% 24%
Pelican Lake crude oil 6% 6% 6% 6% 5%
Primary heavy crude oil 16% 15% 15% 16% 15%
Thermal heavy crude oil 12% 12% 9% 12% 9%
Natural gas 44% 44% 47% 44% 47%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
DAILY PRODUCTION, net of royalties
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America 202,264 216,585 206,927 209,424 205,671
North Sea 45,734 49,473 57,185 47,603 59,457
Offshore West Africa 24,136 23,496 26,876 23,816 26,389
----------------------------------------------------------------------------
272,134 289,554 290,988 280,843 291,517
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,227 1,260 1,444 1,243 1,406
North Sea 10 11 15 11 15
Offshore West Africa 13 11 10 12 9
----------------------------------------------------------------------------
1,250 1,282 1,469 1,266 1,430
----------------------------------------------------------------------------
Total barrels of oil
equivalent (boe/d) 480,418 503,250 535,789 491,835 529,793
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Daily production and per bbl statistics are presented throughout
this MD&A on a "before royalty" or "gross" basis. Production on
an "after royalty" or "net" basis is also presented.
The Company's business approach is to maintain large project
inventories and production diversification among each of the
commodities it produces; namely natural gas, light/medium crude oil
and NGLs, Pelican Lake crude oil, primary heavy crude oil and
thermal heavy crude oil.
Total production averaged 578,461 boe/d for the six months ended
June 30, 2008, a 6% decrease from 613,790 boe/d for the six months
ended June 30, 2007. Production for the second quarter of 2008
decreased 7% to average 573,437 boe/d, from 614,461 boe/d for the
second quarter of 2007, and a 2% decrease from 583,488 boe/d for
the prior quarter.
Total crude oil and NGLs production for the six months ended
June 30, 2008 decreased 1% to 323,147 bbl/d from 327,249 bbl/d for
the six months ended June 30, 2007. Second quarter total crude oil
and NGLs production decreased 3% to 319,077 bbl/d from 327,494
bbl/d for the second quarter of 2007, and decreased 2% from 327,217
bbl/d for the prior quarter. The decrease from the comparable
periods was primarily due to lower production in the North Sea.
Crude oil and NGLs production in the second quarter of 2008 was at
the high end of the Company's previously issued guidance of 306,000
to 323,000 bbl/d.
Natural gas production continued to represent the Company's
largest product offering, accounting for 44% of the Company's total
production. Natural gas production for the six months ended June
30, 2008 averaged 1,532 mmcf/d compared to 1,719 mmcf/d for the six
months ended June 30, 2007. Second quarter natural gas production
averaged 1,526 mmcf/d compared to 1,722 mmcf/d for the second
quarter of 2007 and 1,538 mmcf/d for the prior quarter. The
decrease in natural gas production from the comparable periods
primarily reflected production declines due to the Company's
strategic reduction in natural gas drilling activity. Second
quarter natural gas production exceeded the Company's previously
issued guidance of 1,479 to 1,513 mmcf/d.
For 2008, annual production guidance is targeted to average
between 308,000 and 350,000 bbl/d of crude oil and NGLs and between
1,482 and 1,511 mmcf/d of natural gas. Third quarter 2008
production guidance is targeted to average between 299,000 and
316,000 bbl/d of crude oil and NGLs and between 1,466 and 1,490
mmcf/d of natural gas.
North America
North America crude oil and NGLs production for the six months
ended June 30, 2008 increased 3% to average 247,288 bbl/d from
238,962 bbl/d for the six months ended June 30, 2007. Second
quarter North America crude oil and NGLs production increased 2% to
average 245,616 bbl/d from 240,420 bbl/d for the second quarter of
2007, and decreased 1% from 248,960 bbl/d for the prior quarter.
The fluctuations in crude oil and NGLs production from the prior
periods was primarily due to the cyclic nature of the Company's
thermal production.
For the six months ended June 30, 2008, natural gas production
decreased 11% to 1,507 mmcf/d from 1,694 mmcf/d for the six months
ended June 30, 2007. For the second quarter of 2008, natural gas
production decreased 11% to 1,501 mmcf/d from 1,696 mmcf/d for the
second quarter of 2007, and decreased marginally from 1,513 mmcf/d
for the prior quarter. The decrease in natural gas production from
the prior periods reflected production declines due to the
Company's strategic decision to reduce natural gas drilling
activity.
North Sea
North Sea crude oil production for the six months ended June 30,
2008 decreased 20% to 47,699 bbl/d from 59,565 bbl/d for the six
months ended June 30, 2007. Second quarter North Sea crude oil
production decreased 20% to 45,830 bbl/d from 57,286 bbl/d for the
second quarter of 2007 and by 8% from 49,568 bbl/d for the prior
quarter. Second quarter production was in line with expectations,
with the decrease from the prior quarter due to a planned
maintenance shutdown at Ninian. Further maintenance shutdowns are
planned at T-Block, Banff, and Murchison in the third quarter and
at Ninian in the fourth quarter.
Offshore West Africa
Offshore West Africa crude oil production decreased 2% to 28,160
bbl/d for the six months ended June 30, 2008 from 28,722 bbl/d for
the six months ended June 30, 2007. As expected, second quarter
Offshore West Africa crude oil production decreased 7% to 27,631
bbl/d from 29,788 bbl/d for the second quarter of 2007, and by 4%
from 28,689 bbl/d for the prior quarter. A deepwater rig commenced
operations at Baobab in April 2008, which should enable the Company
to execute its plan to restore certain of its shut-in production
over the course of 2008 and 2009.
ROYALTIES
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
North America $ 17.46 $ 9.63 $ 6.58 $ 13.52 $ 6.50
North Sea $ 0.27 $ 0.19 $ 0.13 $ 0.23 $ 0.13
Offshore West Africa $ 14.49 $ 17.43 $ 7.12 $ 15.95 $ 5.32
Company average $ 14.82 $ 8.70 $ 5.46 $ 11.70 $ 5.19
Natural gas ($/mcf) (1)
North America $ 1.88 $ 1.36 $ 1.11 $ 1.62 $ 1.30
Offshore West Africa $ 1.13 $ 1.43 $ 0.59 $ 1.28 $ 0.50
Company average $ 1.86 $ 1.35 $ 1.10 $ 1.60 $ 1.29
Company average ($/boe) (1) $ 13.26 $ 8.43 $ 5.99 $ 10.82 $ 6.37
Percentage of revenue (2)
Crude oil and NGLs 14% 11% 10% 13% 10%
Natural gas 19% 17% 15% 18% 17%
Boe 16% 13% 12% 14% 13%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk
management activities.
North America
North America crude oil and NGLs royalties per bbl for the six
months ended June 30, 2008 continue to reflect strong realized
crude oil prices. Crude oil and NGLs royalties averaged
approximately 18% of revenues for the second quarter of 2008,
compared to 14% for the second quarter in 2007 and 13% in the prior
quarter. Crude oil and NGLs royalties per bbl are anticipated to
average 16% to 18% of gross revenue for 2008.
Natural gas royalties per mcf generally fluctuate with natural
gas prices. Natural gas royalties averaged approximately 19% of
revenues for the second quarter of 2008 compared to 15% for the
second quarter of 2007 and 17% for the prior quarter. Natural gas
royalties are anticipated to average 17% to 20% of gross revenue
for 2008.
North Sea
North Sea government royalties on crude oil were eliminated
effective January 1, 2003. The remaining royalty is a gross
overriding royalty on the Ninian Field.
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
13% for the second quarter of 2008 compared to 10% for the second
quarter of 2007 and 18% for the prior quarter. Royalty expense in
the second quarter reflected a relatively low proportion of Espoir
sales in the period, which have higher royalty rates, offset by the
increase in allocation of the Government's share to royalties due
to the reduction in the Cote d'Ivoire corporate income tax rate
enacted in the first quarter of 2008. Offshore West Africa royalty
rates are anticipated to average 14% to 17% of gross revenue for
2008.
PRODUCTION EXPENSE
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
North America $ 15.44 $ 13.88 $ 13.98 $ 14.65 $ 13.50
North Sea $ 25.61 $ 22.35 $ 22.11 $ 23.81 $ 20.21
Offshore West Africa $ 9.79 $ 8.03 $ 7.98 $ 8.92 $ 8.48
Company average $ 16.39 $ 14.81 $ 15.01 $ 15.58 $ 14.40
Natural gas ($/mcf) (1)
North America $ 0.93 $ 1.01 $ 0.87 $ 0.97 $ 0.91
North Sea $ 2.68 $ 2.33 $ 2.26 $ 2.50 $ 2.42
Offshore West Africa $ 1.27 $ 1.25 $ 1.10 $ 1.26 $ 1.26
Company average $ 0.94 $ 1.03 $ 0.89 $ 0.98 $ 0.93
Company average
($/boe) (1) $ 11.60 $ 11.02 $ 10.44 $ 11.31 $ 10.27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America
North America crude oil and NGLs production expense for the six
months ended June 30, 2008 increased 9% to $14.65 per bbl from
$13.50 per bbl for the six months ended June 30, 2007. Second
quarter North America crude oil and NGLs production expense
increased 10% to $15.44 per bbl from $13.98 per bbl for the second
quarter of 2007 and increased 11% from $13.88 per bbl for the prior
quarter. The increase in production expense per bbl for the second
quarter of 2008 was primarily a result of the higher cost of
natural gas for fuel for the Company's thermal operations and
increased property tax and power costs.
North America natural gas production expense for the six months
ended June 30, 2008 increased 7% to $0.97 per mcf from $0.91 per
mcf for the six months ended June 30, 2007. Second quarter North
America natural gas production expense increased 7% to $0.93 per
mcf from $0.87 per mcf for the second quarter of 2007 and decreased
8% from $1.01 per mcf for the prior quarter. The increase in
production expense per mcf from the comparable periods in 2007 was
a result of lower sales volumes on the fixed cost portion of
production costs. The decrease from the prior period was a result
of normal seasonal activity.
North Sea
North Sea crude oil production expense increased on a per bbl
basis from the comparable periods in 2007 and the prior quarter due
to lower production volumes on a relatively fixed cost base and the
timing of liftings and maintenance activities on various fields.
The Company is experiencing pressure from rising fuel costs and
industry wide higher service and environmental costs.
Offshore West Africa
Offshore West Africa crude oil production expense increased on a
per bbl basis from the comparable periods in 2007 and the prior
quarter primarily due to the impact of the timing of liftings at
the Baobab and Espoir Fields, resulting in a greater proportion of
relatively higher fixed cost Baobab sales in the quarter.
MIDSTREAM
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue $ 20 $ 20 $ 17 $ 40 $ 36
Production expense 8 5 5 13 11
----------------------------------------------------------------------------
Midstream cash flow 12 15 12 27 25
Depreciation 2 2 2 4 4
----------------------------------------------------------------------------
Segment earnings before
taxes $ 10 $ 13 $ 10 $ 23 $ 21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's midstream assets consist of three crude oil
pipeline systems and a 50% working interest in an 84-megawatt
cogeneration plant at Primrose. Approximately 80% of the Company's
heavy crude oil production is transported to international mainline
liquid pipelines via the 100% owned and operated ECHO Pipeline, the
62% owned and operated Pelican Lake Pipeline and the 15% owned Cold
Lake Pipeline. The midstream pipeline assets allow the Company to
control the transport of its own production volumes as well as earn
third party revenue. This transportation control enhances the
Company's ability to manage the full range of costs associated with
the development and marketing of its heavier crude oil.
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Expense ($ millions) $ 668 $ 686 $ 718 $ 1,354 $ 1,425
$/boe (2) $ 12.88 $ 12.87 $ 12.95 $ 12.88 $ 12.84
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) DD&A excludes depreciation on midstream assets.
(2) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, Depreciation and Amortization ("DD&A") for the
six months ended June 30, 2008 and the second quarter decreased in
total from the comparable periods in 2007 and the prior quarter.
The decrease in DD&A expense from the prior periods was
primarily due to the impact of lower sales volumes.
ASSET RETIREMENT OBLIGATION ACCRETION
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Expense ($ millions) $ 17 $ 17 $ 17 $ 34 $ 35
$/boe (1) $ 0.33 $ 0.31 $ 0.30 $ 0.32 $ 0.31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 six months
ended June 30, 2008 and the second quarter was consistent with the
comparable periods.
ADMINISTRATION EXPENSE
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Expense ($ millions) $ 45 $ 43 $ 53 $ 88 $ 113
$/boe (1) $ 0.87 $ 0.80 $ 0.96 $ 0.83 $ 1.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the six months ended June 30, 2008
and the second quarter decreased in total and on a boe basis from
the comparable periods in 2007 primarily due to decreased staffing
costs, including costs related to the Company's share bonus
program, as well as decreased office lease costs.
STOCK-BASED COMPENSATION EXPENSE
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Expense $ 459 $ - $ 106 $ 459 $ 131
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $459 million ($328 million after-tax)
stock-based compensation expense for the six and three months ended
June 30, 2008 as a result of the increase in the Company's share
price (Company's share price as at: June 30, 2008 - C$100.84; March
31, 2008 - C$70.27; December 31, 2007 - C$72.58; June 30, 2007 -
C$70.78). As required by GAAP, the Company's outstanding stock
options are valued each reporting period based on the difference
between the exercise price of the stock options and the market
price of the Company's common shares, pursuant to a graded vesting
schedule. The liability is revalued quarterly to reflect changes in
the market price of the Company's common shares and the options
exercised or surrendered in the period, with the net change
recognized in net earnings, or capitalized during the construction
period in the case of the Horizon Project. For the six months ended
June 30, 2008, the Company capitalized $132 million in stock-based
compensation on the Horizon Project (June 30, 2007 - $39 million).
The stock-based compensation liability reflected the Company's
potential cash liability should all the vested options be
surrendered for a cash payout at the market price on June 30, 2008.
In periods when substantial stock price changes occur, the Company
is subject to significant earnings volatility.
For the six months ended June 30, 2008, the Company paid $184
million for stock options surrendered for cash settlement (June 30,
2007 - $221 million).
INTEREST EXPENSE
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions, except per boe
amounts) 2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Expense, gross $ 141 $ 160 $ 158 $ 301 $ 312
Less: capitalized interest,
Horizon Project 110 111 81 221 152
----------------------------------------------------------------------------
Expense, net $ 31 $ 49 $ 77 $ 80 $ 160
$/boe (1) $ 0.60 $ 0.92 $ 1.40 $ 0.76 $ 1.44
Average effective interest
rate 4.8% 5.5% 5.4% 5.2% 5.4%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest expense and the Company's average effective
interest rate decreased from the comparable periods in 2007 and the
prior quarter primarily due to decreased short term borrowing rates
in the six months ended June 30, 2008 and the impact of the strong
Canadian dollar, offset by an increased proportion of higher cost
US dollar denominated debt.
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.
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments $ 944 $ 463 $ 100 $ 1,407 $ 95
Natural gas financial
instruments 10 (47) (8) (37) (91)
----------------------------------------------------------------------------
Realized loss $ 954 $ 416 $ 92 $ 1,370 $ 4
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments $ 1,380 $ 51 $ 64 $ 1,431 $ 394
Natural gas financial
instruments 38 59 (121) 97 85
Foreign currency swaps (3) (2) - (5) -
----------------------------------------------------------------------------
Unrealized loss (gain) $ 1,415 $ 108 $ (57) $ 1,523 $ 479
----------------------------------------------------------------------------
Net loss $ 2,369 $ 524 $ 35 $ 2,893 $ 483
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The net realized loss (gain) from crude oil and natural gas
financial instruments would have decreased (increased) the
Company's average realized prices as follows:
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1) $ 32.84 $ 15.47 $ 3.41 $ 23.98 $ 1.61
Natural gas ($/mcf) (1) $ 0.07 $ (0.33) $ (0.05) $ (0.13) $ (0.29)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Complete details related to outstanding derivative financial
instruments at June 30, 2008 are disclosed in note 10 to the
Company's unaudited interim consolidated financial statements.
The commodity derivative financial instruments currently
outstanding have not been designated as hedges for accounting
purposes (the "non-designated hedges"). The fair value of these
non-designated hedges is based on prevailing forward commodity
prices in effect at the end of each reporting period and is
reflected in risk management activities in consolidated net
earnings. The cash settlement amount of the risk management
derivative financial instruments may vary materially depending upon
the underlying crude oil and natural gas prices at the time of
final settlement of the derivative financial instruments, as
compared to their mark-to-market value at June 30, 2008. Due to
changes in crude oil and natural gas forward pricing and the
reversal of prior period unrealized gains and losses, the Company
recorded a net unrealized loss of $1,523 million ($1,073 million
after-tax) on its commodity risk management activities for the six
months ended June 30, 2008, including a $1,415 million ($997
million after-tax) net unrealized loss for the second quarter of
2008 (March 31, 2008 - unrealized loss of $108 million, $76 million
after-tax; June 30, 2007 -unrealized gain of $57 million, $35
million after-tax).
FOREIGN EXCHANGE
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Net realized (gain) loss $ (11) $ (12) $ 26 $ (23) $ 31
Net unrealized (gain) loss(1) (20) 126 (250) 106 (282)
----------------------------------------------------------------------------
Net (gain) loss $ (31) $ 114 $ (224) $ 83 $ (251)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps
as described in Risk Management Activities.
The Company's operating results are affected by fluctuations in
the exchange rates between the Canadian dollar, US dollar, and UK
pound sterling. A majority of the Company's revenue is based on
reference to US dollar benchmark prices. An increase in the value
of the Canadian dollar in relation to the US dollar results in
decreased revenue from the sale of the Company's production.
Conversely, a decrease in the value of the Canadian dollar in
relation to the US dollar results in increased revenue from the
sale of the Company's production. Production expenses in the North
Sea are subject to foreign currency fluctuations due to changes in
the exchange rate of the UK pound sterling to the US dollar, while
production expenses in Offshore West Africa are subject to foreign
currency fluctuations due to changes in the exchange rate of the
Canadian dollar to the US dollar. The value of the Company's US
dollar denominated debt is also impacted by the value of the
Canadian dollar in relation to the US dollar.
The net unrealized foreign exchange loss for the six months
ended June 30, 2008 was primarily related to the weakening of the
Canadian dollar in relation to the US dollar with respect to the US
dollar debt, together with the impact of the re-measurement of
North Sea future income tax liabilities denominated in UK pounds
sterling to US dollars. Included in the net unrealized loss for the
six months ended June 30, 2008 was an unrealized gain of $58
million (six months ended June 30, 2007 - unrealized loss of $207
million) related to the impact of the cross currency swaps. The net
realized foreign exchange gain for the six months ended June 30,
2008 was primarily due to the result of foreign exchange rate
fluctuations on settlement of working capital items denominated in
US dollars or UK pounds sterling and the repayment of US dollar
denominated debt. The Canadian dollar ended the second quarter at
US$0.9817 compared to US$0.9729 at March 31, 2008 (December 31,
2007 - US$1.0120, June 30, 2007 - US$0.9404).
TAXES
Three Months Ended Six Months Ended
--------------------------------------------------
($ millions, except income Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
tax rates) 2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Current $ 96 $ 70 $ 9 $ 166 $ 75
Deferred (34) (21) 20 (55) 17
----------------------------------------------------------------------------
Taxes other than income
tax $ 62 $ 49 $ 29 $ 111 $ 92
----------------------------------------------------------------------------
North America $ 6 $ 21 $ 12 $ 27 $ 37
North Sea 111 96 54 207 89
Offshore West Africa 34 38 16 72 26
----------------------------------------------------------------------------
Current income tax 151 155 82 306 152
Future income tax (301) 80 116 (221) 216
----------------------------------------------------------------------------
(150) 235 198 85 368
Income tax rate and other
legislative changes (1)(2) - 41 71 41 71
----------------------------------------------------------------------------
$ (150) $ 276 $ 269 $ 126 $ 439
----------------------------------------------------------------------------
Effective income tax rate
before non-recurring
benefits 30.2% 28.7% 25.9% 27.1% 29.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the effect of a one time recovery of $19 million due to
British Columbia corporate income tax rate reductions and $22 million
due to Cote d'Ivoire corporate income tax rate reductions enacted or
substantively enacted during the first quarter of 2008.
(2) Includes the effect of a one time recovery of $71 million due to
Canadian Federal income tax rate reductions enacted during the second
quarter of 2007.
Taxes other than income tax primarily includes current and
deferred petroleum revenue tax ("PRT"). PRT is charged on certain
fields in the North Sea at the rate of 50% of net operating income,
after allowing for certain deductions including abandonment
expenditures.
Taxable income from the conventional crude oil and natural gas
business in Canada is primarily generated through partnerships,
with the related income taxes payable in a future period. North
America current income taxes have been provided on the basis of the
corporate structure and available income tax deductions and will
vary depending upon the nature, timing and amount of capital
expenditures incurred in Canada in any particular year.
CAPITAL EXPENDITURES (1)
Three Months Ended Six Months Ended
------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Expenditures on property,
plant and equipment
Net property acquisitions
(dispositions) $ 263 $ (8) $ 15 $ 255 $ 61
Land acquisition and
retention 24 12 22 36 51
Seismic evaluations 18 27 34 45 84
Well drilling, completion
and equipping 286 452 288 738 1,002
Production and related
facilities 270 319 243 589 577
----------------------------------------------------------------------------
Total net reserve
replacement expenditures 861 802 602 1,663 1,775
----------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 875 665 704 1,540 1,378
Phase 1 operating and
capital inventory 14 41 - 55 -
Phase 1 commissioning costs 34 49 - 83 -
Phases 2/3 costs 82 77 19 159 63
Capitalized interest,
stock-based compensation
and other 247 109 118 356 209
----------------------------------------------------------------------------
Total Horizon Project 1,252 941 841 2,193 1,650
----------------------------------------------------------------------------
Midstream 3 1 - 4 2
Abandonments (2) 7 6 13 13 33
Head office 4 3 4 7 9
----------------------------------------------------------------------------
Total net capital
expenditures $ 2,127 $ 1,753 $ 1,460 $ 3,880 $ 3,469
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 617 $ 663 $ 419 $ 1,280 $ 1,417
North Sea 79 45 136 124 274
Offshore West Africa 164 94 46 258 82
Other 1 - 1 1 2
Horizon Project 1,252 941 841 2,193 1,650
Midstream 3 1 - 4 2
Abandonments (2) 7 6 13 13 33
Head office 4 3 4 7 9
----------------------------------------------------------------------------
Total $ 2,127 $ 1,753 $ 1,460 $ 3,880 $ 3,469
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The net capital expenditures exclude adjustments related to differences
between carrying value and tax value, and other fair value adjustments.
(2) Abandonments represent expenditures to settle asset retirement
obligations and have been reflected as capital expenditures in this table.
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 six months ended June 30, 2008
were $3,880 million compared to $3,469 million for the six months
ended June 30, 2007. Net capital expenditures for the second
quarter of 2008 were $2,127 million compared to $1,460 million for
the second quarter of 2007 and $1,753 million for the prior
quarter. The capital expenditures primarily reflected the continued
progress on the Company's larger, future growth projects, most
notably the Horizon Project, offset by the effects of an overall
strategic reduction in the North America natural gas drilling
program. Capital expenditures in the second quarter of 2008 also
included the acquisition of producing properties in the Company's
Northern Plains region.
For the six months ended June 30, 2008, the Company drilled a
total of 475 net wells consisting of 166 natural gas wells, 266
crude oil wells, 26 stratigraphic test and service wells and 17
wells that were dry. This compared to 783 net wells drilled for the
six months ended June 30, 2007. The Company achieved an overall
success rate of 96% for the six months ended June 30, 2008,
excluding stratigraphic test and service wells, compared to 88% for
the six months ended June 30, 2007.
For the second quarter of 2008, the Company drilled a total of
115 net wells consisting of 5 natural gas wells, 93 crude oil
wells, 11 stratigraphic test and service wells and 6 wells that
were dry. This compared to 95 net wells drilled for the second
quarter of 2007 and 360 net wells for the prior quarter. The
Company achieved an overall success rate of 94% for the second
quarter of 2008, excluding stratigraphic test and service wells,
compared to 95% for the second quarter of 2007 and 97% for the
prior quarter.
North America
North America, including the Horizon Project, accounted for
approximately 90% of the total capital expenditures for the six
months ended June 30, 2008 and June 30, 2007.
During the six months ended June 30, 2008, the Company targeted
175 net natural gas wells, including 22 wells in Northeast British
Columbia, 48 wells in the Northern Plains region, 51 wells in
Northwest Alberta, and 54 wells in the Southern Plains region. The
Company also targeted 270 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 136 heavy crude
oil wells, 57 Pelican Lake crude oil wells, 36 thermal crude oil
wells and 4 light crude oil wells were drilled. Another 37 wells
targeting light crude oil were drilled outside the Northern Plains
region.
Due to significant differences in relative commodity prices
between crude oil and natural gas during the six months ended June
30, 2008, the Company continued to access its large crude oil
drilling inventory to maximize value in both the short and long
term. Due to the Company's focus on drilling crude oil wells in
2007 and 2008, natural gas drilling activities have been reduced to
manage overall capital spending. Deferred natural gas well
locations have been retained in the Company's prospect
inventory.
As part of the phased expansion of its In-Situ Oil Sands Assets,
the Company is continuing to develop its Primrose thermal projects.
Overall Primrose thermal production averaged approximately 67,000
bbl/d for the second quarter of 2008 compared to 56,000 bbl/d for
the second quarter of 2007 and approximately 69,000 bbl/d for the
prior quarter.
The Primrose East Expansion, a new facility located 15
kilometers from the existing Primrose South steam plant and 25
kilometers from the Wolf Lake central processing facility, is
anticipated to add approximately 40,000 bbl/d when complete.
Drilling is complete and construction of facilities is ongoing.
First steaming is scheduled for September 2008 and first production
is now targeted to commence in late 2008.
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 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
second quarter of 2008. Drilling consisted of 32 horizontal wells
and 5 vertical service wells in the second quarter. The response
from the water and polymer flood projects continues to be positive.
Pelican Lake production averaged approximately 37,000 bbl/d for the
second quarter of 2008 compared to 34,000 bbl/d for the second
quarter of 2007 and approximately 37,000 bbl/d for the prior
quarter.
For the third quarter of 2008, the Company's overall drilling
activity in North America is expected to be comprised of 81 natural
gas wells and 256 crude oil wells, excluding stratigraphic and
service wells.
Horizon Project
First production of synthetic crude oil is now currently
targeted to commence in the fourth quarter of 2008. The project
status as at June 30, 2008 was as follows:
- Overall construction progress is 96.5% complete;
- Mine overburden removal has moved 67.6 million bank cubic
meters, which represents approximately 97% of the total required to
be moved prior to start-up;
- In Mining, 4 of 5 large excavators, 16 of 23 heavy haul trucks
and all support equipment are operational;
- Completed flow through Dyke Construction in Mining;
- Main Control Room turned over to Operations;
- Completed all hydrotests, blows and flushes in Gas Treating
and Sulphur Recovery;
- Introduced water to the Extraction plant;
- Completed piping in Delayed Coker/Diluent Recovery Unit
area;
- Completed Piping, Electrical and Insulation in Piperacks;
- Produced first steam in Co-generation Plant; and
- Completed construction of Tank 2 and began filling with
distillate for start-up.
Major activities for the third quarter of 2008 include:
- Mining of first oil sands;
- Complete remainder of Ore Preparation Plant and start-up;
- Complete commissioning of Extraction and Froth Treatment and
produce first bitumen crude oil;
- Complete and commission Flares and Hydrogen Plant; and
- Complete construction and start commissioning Delayed
Coker/Diluent Recovery Unit and Sulphur Plant.
The Company has budgeted revised construction costs of
approximately $970 million for the remainder of 2008 related to the
planned completion of Phase 1 of the Horizon Project.
North Sea
In the second quarter of 2008, the Company continued with its
planned program of infill drilling, recompletions, workovers and
waterflood optimizations. During the quarter, 2.4 net wells were
drilled, including 0.8 net injection wells, with an additional 0.9
net wells drilling at the end of the quarter.
At Ninian, the Company continued with its planned investment in
its long-term facilities and infrastructure strategy. One water
injection well was drilled during the quarter and 1 production well
was being drilled at quarter end and is due for completion in the
third quarter. The Company completed a planned turnaround at Ninian
during the quarter with activities including tie in of a new export
pipeline from the Lyell Field. At the Murchison Platform, the
second of 2 production wells planned for 2008 was completed. At
Columba E, the Company successfully maintained water injection
rates, thereby increasing reservoir pressure with the goal of
increasing production.
Offshore West Africa
During the second quarter of 2008, 0.9 net wells were drilled,
with an additional 1.5 net wells drilling at the end of the
quarter.
At the 90% owned and operated Olowi Field in offshore Gabon, all
major construction contracts have been awarded and construction
activity on the wellhead towers, subsea facilities and the floating
production storage and offtake vessel ("FPSO") are progressing as
planned. Drilling commenced early in the second quarter of 2008 and
first crude oil is targeted for late 2008. Olowi production is
targeted to plateau at approximately 20,000 bbl/d net to the
Company.
LIQUIDITY AND CAPITAL RESOURCES
----------------------------------------
Jun 30 Mar 31 Dec 31 Jun 30
($ millions, except ratios) 2008 2008 2007 2007
----------------------------------------------------------------------------
Working capital deficit (1) $ 3,180 $ 1,572 $ 1,382 $ 860
Long-term debt (2) $ 11,040 $ 11,230 $ 10,940 $ 10,958
Share capital $ 2,754 $ 2,725 $ 2,674 $ 2,649
Retained earnings 10,847 11,248 10,575 9,169
Accumulated other comprehensive
income 6 95 72 62
----------------------------------------------------------------------------
Shareholders' equity $ 13,607 $ 14,068 $ 13,321 $ 11,880
Debt to book capitalization (2)(3) 45% 44% 45% 48%
Debt to market capitalization (2)(4) 17% 23% 22% 22%
After tax return on average common
shareholders' equity (5) 14% 24% 22% 24%
After tax return on average capital
employed (2) (6) 8% 14% 12% 14%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated as current assets less current liabilities.
(2) Long-term debt is stated at its carrying value, net of fair value
adjustments, original issue discounts and transaction costs.
(3) Calculated as long-term debt; divided by the book value of common
shareholders' equity plus long-term debt.
(4) Calculated as long-term debt; divided by the market value of common
shareholders' equity plus long-term debt.
(5) Calculated as net earnings for the twelve month trailing period; as a
percentage of average common shareholders' equity for the period.
(6) Calculated as net earnings plus after-tax interest expense for the
twelve month trailing period; as a percentage of average capital
employed for the period. Average capital employed is the average
shareholders' equity and long-term debt for the period, including
$8,781 million in average capital employed related to the Horizon
Project (March 31, 2008 - $7,876 million; December 31, 2007 - $7,001
million; June 30, 2007 - $5,319 million).
The Company's capital resources at June 30, 2008 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, 2007 annual MD&A. The
Company's ability to renew existing credit facilities and raise new
debt is also dependent upon these factors, as well as maintaining
an investment grade debt rating and the condition of capital and
credit markets. 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 June 30, 2008, the Company had undrawn bank lines of credit
of $2,705 million. Details related to the Company's long-term debt
at June 30, 2008 are disclosed in note 3 to the Company's unaudited
interim consolidated financial statements.
At June 30, 2008, the Company's working capital deficit was
$3,180 million and included the current portion of the stock-based
compensation liability of $755 million and the current portion of
the net mark-to-market liability for risk management derivative
financial instruments of $2,606 million. The settlement of the
stock-based compensation liability is dependent upon both the
surrender of vested stock options for cash settlement by employees
and the value of the Company's share price at the time of
surrender. The cash settlement amount of the risk management
derivative financial instruments may vary materially depending upon
the underlying crude oil and natural gas prices at the time of
final settlement of the derivative financial instruments, as
compared to their mark-to-market value at June 30, 2008.
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 $11,040 million at June 30, 2008, resulting
in a debt to book capitalization ratio of 45% (March 31, 2008 -
44%; December 31, 2007 - 45%; June 30, 2007 - 48%). 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 currently 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 put options is in addition to the
above parameters. In accordance with the policy, approximately 57%
of budgeted crude oil volumes are hedged for the remainder of 2008,
approximately 18% of budgeted natural gas volumes are hedged for
the third quarter of 2008 and approximately 6% of estimated crude
oil volumes are hedged for 2009. In addition, 50,000 bbl/d of crude
oil volumes are protected by put options for the remainder of 2008
at a strike price of US$55.00 per bbl, 50,000 bbl/d of crude oil
volumes are protected by put options for 2009 at a strike price of
US$80.00 per bbl, and 42,000 bbl/d of crude oil volumes are
protected by put options for 2009 at a strike price of US$100.00
per bbl. Subsequent to June 30, 2008, the Company unwound 50,000
bbl/d of US$80.00 WTI put options and entered into 50,000 bbl/d of
US$100.00 WTI put options for the period January to December
2009.
Commencing January 1, 2009, following the planned completion of
Phase 1 of the Horizon Project, the Company's commodity hedging
program has been revised by its Board of Directors to allow for the
hedging of up to 50% of the near 12 months budgeted production and
up to 25% of the following 13 to 24 months estimated production.
The purchase of put options will continue to be in addition to the
above parameters.
The Company has the following commodity related net financial
derivatives outstanding at June 30, 2008:
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Crude oil
Crude oil price Jul 2008 - Sep 2008 25,000 bbl/d US$60.00- US$80.46 WTI
collars Jul 2008 - Sep 2008 25,000 bbl/d US$70.00-US$123.75 WTI
Mayan
Jul 2008 - Dec 2008 20,000 bbl/d US$50.00-US$65.53 Heavy
Jul 2008 - Dec 2008 50,000 bbl/d US$60.00-US$75.22 WTI
Jul 2008 - Dec 2008 50,000 bbl/d US$60.00-US$76.05 WTI
Jul 2008 - Dec 2008 50,000 bbl/d US$60.00-US$76.98 WTI
Oct 2008 - Dec 2008 25,000 bbl/d US$70.00-US$112.63 WTI
Jan 2009 - Dec 2009 25,000 bbl/d US$70.00-US$111.56 WTI
Crude oil puts
(1) Jul 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
Jan 2009 - Dec 2009 50,000 bbl/d US$80.00 WTI
Jan 2009 - Dec 2009 42,000 bbl/d US$100.00 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to June 30, 2008, the Company unwound 50,000 bbl/d of
US$80.00 WTI put options and entered into 50,000 bbl/d of US$100.00 WTI
put options for the period January to December 2009, for a net cost of
US$89 million.
Natural gas
AECO price
collars Jul 2008 - Sep 2008 290,000 GJ/d C$7.50 - C$8.69 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 June 30, 2008, the Company had in place unsecured bank
credit facilities of $6,235 million, comprised of:
- a $125 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.
The revolving syndicated credit facilities are extendible
annually for one year periods at the mutual agreement of the
Company and the lenders. If the facilities are not extended, the
full amount of the outstanding principal would be repayable on the
maturity date.
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $367 million, including $300
million related to the Horizon Project, were outstanding at June
30, 2008.
Medium-term notes
The Company has $2,600 million remaining on its outstanding
$3,000 million base shelf prospectus filed in September 2007 that
allows for the issue of medium-term notes in Canada until October
2009. If issued, these securities will bear interest as determined
at the date of issuance.
Senior unsecured notes
During the second quarter of 2008, US$31 million of the senior
unsecured notes were repaid.
US dollar debt securities
In January 2008, the Company issued US$1,200 million of
unsecured notes under a US base shelf prospectus, comprised of
US$400 million of 5.15% unsecured notes due February 2013, US$400
million of 5.90% unsecured notes due February 2018, and US$400
million of 6.75% unsecured notes due February 2039. Proceeds from
the securities issued were used to repay bankers' acceptances under
the Company's bank credit facilities. After issuing these
securities, the Company has US$1,800 million remaining on its
outstanding US$3,000 million base shelf prospectus filed in
September 2007 that allows for the issue of US dollar debt
securities in the United States until October 2009. If issued,
these securities will bear interest as determined at the date of
issuance.
Share capital
As at June 30, 2008, there were 540,773,000 common shares
outstanding and 25,148,000 stock options outstanding. As at August
5, 2008, the Company had 540,810,000 common shares outstanding and
25,647,000 stock options outstanding.
In February 2008, the Company's Board of Directors approved an
increase in the annual dividend paid by the Company to $0.40 per
common share for 2008. The increase represents an 18% increase from
2007, recognizes the stability of the Company's cash flow, and
provides a return to Shareholders. This is the eighth consecutive
year in which the Company has paid dividends and the seventh
consecutive year of an increase in the distribution paid to its
Shareholders. The dividend policy undergoes a periodic review by
the Board of Directors and is subject to change.
Commitments and off balance sheet arrangements
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. These commitments primarily relate to debt
repayments; operating leases relating to offshore FPSOs, drilling
rigs and office space; firm commitments for gathering, processing
and transmission services; as well as expenditures relating to
asset retirement obligations. As at June 30, 2008, no entities were
consolidated under the Canadian Institute of Chartered Accountants
Handbook Accounting Guideline 15, "Consolidation of Variable
Interest Entities". The following table summarizes the Company's
commitments as at June 30, 2008:
Remaining
($ millions) 2008 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Product
transportation
and pipeline $ 121 $ 172 $ 156 $ 130 $ 113 $ 1,097
Offshore equipment
operating lease(1) $ 76 $ 129 $ 117 $ 115 $ 93 $ 403
Offshore drilling
(2)(3) $ 189 $ 211 $ 52 $ - $ - $ -
Asset retirement
obligations (4) $ 20 $ 4 $ 5 $ 4 $ 4 $ 4,534
Long-term debt (5) $ 8 $ 2,377 $ 400 $ 407 $ 357 $ 6,453
Interest expense
(6) $ 339 $ 552 $ 492 $ 470 $ 408 $ 5,363
Office lease $ 12 $ 26 $ 29 $ 22 $ 2 $ -
Other $ 86 $ 288 $ 182 $ 24 $ 20 $ 53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 commenced in the second quarter of 2008, on
delivery of the rig. Estimated total remaining payments of US$81
million, after joint venture recoveries, have been included in this
table for the period 2008 - 2009.
(3) During 2007, the Company awarded contracts for a drilling rig and for
the construction of wellhead towers in connection with the planned
offshore development in Gabon, Offshore West Africa. Estimated total
remaining payments of US$359 million have been included in this table
for the period 2008 - 2010.
(4) Amounts represent management's estimate of the future undiscounted
payments to settle asset retirement obligations related to resource
properties, facilities, and production platforms, based on current
legislation and industry operating practices. Amounts disclosed for the
period 2008 - 2012 represent the minimum required expenditures to meet
these obligations. Actual expenditures in any particular year may exceed
these minimum amounts.
(5) The long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or transaction
costs. No debt repayments are reflected for $1,111 million of revolving
bank credit facilities due to the extendable nature of the facilities.
(6) Interest expense amounts represent the scheduled fixed-rate and
variable-rate cash payments related to long-term debt. Interest on
variable-rate long-term debt was estimated based upon prevailing
interest rates as at June 30, 2008.
In addition to the amounts disclosed above, the Company has
budgeted revised construction costs of approximately $970 million
for the remainder of 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, 2007.
For the impact of new accounting standards related to capital
disclosures, inventory and financial instruments, refer to note 2
of the unaudited interim consolidated financial statements as at
June 30, 2008.
International Financial Reporting Standards
In February 2008, the Canadian Institute of Chartered
Accountants confirmed that effective January 1, 2011, Canadian GAAP
for publicly accountable entities will be replaced in full with
International Financial Reporting Standards ("IFRS") as promulgated
by the International Accounting Standards Board. The Company is
currently assessing the impact of adopting IFRS and is developing a
plan to achieve convergence to IFRS by January 1, 2011.
SENSITIVITY ANALYSIS
The following table is indicative of the annualized
sensitivities of cash flow from operations and net earnings from
changes in certain key variables. The analysis is based on business
conditions and sales volumes during the second quarter of 2008,
excluding mark-to-market gains (losses) on risk management
activities and capitalized interest, and is not necessarily
indicative of future results. Each separate line item in the
sensitivity analysis shows the effect of a change in that variable
only with all other variables being held constant.
Cash flow
Cash flow from
from operations Net 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 $ 88 $ 0.16 $ 65 $ 0.12
Including financial
derivatives $ 44 - 46 $ 0.08 - 0.09 $ 33 - 35 $ 0.06
Natural gas - AECO
C$0.10/mcf (1)
Excluding financial
derivatives $ 40 $ 0.07 $ 28 $ 0.05
Including financial
derivatives $ 37 $ 0.07 $ 26 $ 0.05
Volume changes
Crude oil - 10,000
bbl/d $ 233 $ 0.43 $ 147 $ 0.27
Natural gas - 10
mmcf/d $ 26 $ 0.05 $ 13 $ 0.02
Foreign currency
rate change
$0.01 change in
US$ (1)
Including financial
derivatives $ 92 - 94 $ 0.17 $ 35 $ 0.06 - 0.07
Interest rate change
- 1% $ 29 $ 0.05 $ 29 $ 0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Six Months Ended
---------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($/boe) (1) 2008 2008 2007 2008 2007
----------------------------------------------------------------------------
Sales price (2) $ 84.88 $ 65.09 $ 49.70 $ 74.86 $ 49.50
Royalties 13.26 8.43 5.99 10.82 6.37
Production expense (3) 11.60 11.02 10.44 11.31 10.27
----------------------------------------------------------------------------
Netback 60.02 45.64 33.27 52.73 32.86
Midstream contribution (3) (0.24) (0.27) (0.20) (0.26) (0.22)
Administration 0.87 0.80 0.96 0.83 1.02
Interest, net 0.60 0.92 1.40 0.76 1.44
Realized risk management
loss 18.38 7.82 1.66 13.03 0.04
Realized foreign exchange
(gain) loss (0.20) (0.22) 0.47 (0.21) 0.28
Taxes other than income
tax - current 1.84 1.32 0.16 1.58 0.67
Current income tax
- North America 0.11 0.40 0.21 0.26 0.33
Current income tax
- North Sea 2.15 1.79 0.99 1.97 0.81
Current income tax
- Offshore West Africa 0.65 0.71 0.29 0.68 0.23
----------------------------------------------------------------------------
Cash flow $ 35.86 $ 32.37 $ 27.33 $ 34.09 $ 28.26
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
(3) Excluding intersegment elimination.
FINANCIAL STATEMENTS
Consolidated Balance Sheets
Jun 30 Dec 31
(millions of Canadian dollars, unaudited) 2008 2007
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 22 $ 21
Accounts receivable and other 2,340 1,662
Future income tax 992 480
Current portion of other long-term assets - 18
----------------------------------------------------------------------------
3,354 2,181
Property, plant and equipment (note 12) 36,482 33,902
Other long-term assets 31 31
----------------------------------------------------------------------------
$ 39,867 $ 36,114
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 489 $ 379
Accrued liabilities 2,634 1,567
Current portion of other long-term
liabilities (note 4) 3,411 1,617
----------------------------------------------------------------------------
6,534 3,563
Long-term debt (note 3) 11,040 10,940
Other long-term liabilities (note 4) 1,722 1,561
Future income tax 6,964 6,729
----------------------------------------------------------------------------
26,260 22,793
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 6) 2,754 2,674
Retained earnings 10,847 10,575
Accumulated other comprehensive income (note 7) 6 72
----------------------------------------------------------------------------
13,607 13,321
----------------------------------------------------------------------------
$ 39,867 $ 36,114
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (note 11)
Consolidated Statements of Earnings (Loss)
Three Months Ended Six Months Ended
(millions of Canadian dollars, ----------------------------------------
except per common share amounts, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue $ 5,112 $ 3,152 $ 9,079 $ 6,270
Less: royalties (688) (331) (1,137) (707)
----------------------------------------------------------------------------
Revenue, net of royalties 4,424 2,821 7,942 5,563
----------------------------------------------------------------------------
Expenses
Production 610 584 1,197 1,149
Transportation and blending 689 385 1,174 744
Depletion, depreciation and
amortization 670 720 1,358 1,429
Asset retirement obligation
accretion (note 4) 17 17 34 35
Administration 45 53 88 113
Stock-based compensation (note 4) 459 106 459 131
Interest, net 31 77 80 160
Risk management activities (note 10) 2,369 35 2,893 483
Foreign exchange (gain) loss (31) (224) 83 (251)
----------------------------------------------------------------------------
4,859 1,753 7,366 3,993
----------------------------------------------------------------------------
Earnings (loss) before taxes (435) 1,068 576 1,570
Taxes other than income tax 62 29 111 92
Current income tax expense (note 5) 151 82 306 152
Future income tax (recovery) expense
(note 5) (301) 116 (221) 216
----------------------------------------------------------------------------
Net earnings (loss) $ (347) $ 841 $ 380 $ 1,110
----------------------------------------------------------------------------
Net earnings (loss) per common share
(note 9)
Basic and diluted $ (0.65) $ 1.56 $ 0.70 $ 2.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Shareholders' Equity
Six Months Ended
-------------------------
Jun 30 Jun 30
(millions of Canadian dollars, unaudited) 2008 2007
----------------------------------------------------------------------------
Share capital (note 6)
Balance - beginning of period $ 2,674 $ 2,562
Issued upon exercise of stock options 14 16
Previously recognized liability on stock options
exercised for common shares 66 71
----------------------------------------------------------------------------
Balance - end of period 2,754 2,649
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period 10,575 8,151
Net earnings 380 1,110
Dividends on common shares (note 6) (108) (92)
----------------------------------------------------------------------------
Balance - end of period 10,847 9,169
----------------------------------------------------------------------------
Accumulated other comprehensive income (note 7)
Balance - beginning of period 72 146
Other comprehensive loss, net of taxes (66) (84)
----------------------------------------------------------------------------
Balance - end of period 6 62
----------------------------------------------------------------------------
Shareholders' equity $ 13,607 $ 11,880
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income (Loss)
Three Months Ended Six Months Ended
----------------------------------------
(millions of Canadian dollars, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net earnings (loss) $ (347) $ 841 $ 380 $ 1,110
----------------------------------------------------------------------------
Net change in derivative financial
instruments designated as cash flow
hedges
Unrealized income (loss) during the
period, net of taxes of $13 million
(2007 - $47 million) - three months
ended; $15 million (2007 - $8
million) - six months ended (89) 112 (65) (4)
Reclassification to net earnings (loss),
net of taxes of $1 million (2007 -
$nil) - three months ended; $7
million (2007 - $35 million) -
six months ended 3 (1) (14) (75)
----------------------------------------------------------------------------
(86) 111 (79) (79)
Foreign currency translation adjustment
Translation of net investment (3) (4) 13 (5)
----------------------------------------------------------------------------
Other comprehensive income (loss),
net of taxes (89) 107 (66) (84)
----------------------------------------------------------------------------
Comprehensive income (loss) $ (436) $ 948 $ 314 $ 1,026
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months Ended Six Months Ended
----------------------------------------
(millions of Canadian dollars, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) 2008 2007 2008 2007
----------------------------------------------------------------------------
Operating activities
Net earnings (loss) $ (347) $ 841 $ 380 $ 1,110
Non-cash items
Depletion, depreciation and
amortization 670 720 1,358 1,429
Asset retirement obligation
accretion 17 17 34 35
Stock-based compensation 459 106 459 131
Unrealized risk management
loss (gain) 1,415 (57) 1,523 479
Unrealized foreign exchange
(gain) loss (20) (250) 106 (282)
Deferred petroleum revenue tax
(recovery) expense (34) 20 (55) 17
Future income tax (recovery)
expense (301) 116 (221) 216
Other 6 8 19 (5)
Abandonment expenditures (7) (13) (13) (33)
Net change in non-cash working
capital 314 131 148 12
----------------------------------------------------------------------------
2,172 1,639 3,738 3,109
----------------------------------------------------------------------------
Financing activities
(Repayment) issue of bank credit
facilities, net (68) 167 (1,240) (1,846)
Repayment of medium-term notes - - - (125)
Repayment of senior unsecured notes (31) (33) (31) (33)
Issue of US dollar debt securities - - 1,223 2,553
Issue of common shares on exercise
of stock options 5 3 14 16
Dividends on common shares (54) (46) (100) (86)
Net change in non-cash working
capital 25 45 30 23
----------------------------------------------------------------------------
(123) 136 (104) 502
----------------------------------------------------------------------------
Investing activities
Expenditures on property, plant and
equipment (2,121) (1,447) (3,877) (3,440)
Net proceeds on sale of property,
plant and equipment 1 - 10 4
----------------------------------------------------------------------------
Net expenditures on property, plant
and equipment (2,120) (1,447) (3,867) (3,436)
Net change in non-cash working
capital 66 (331) 234 (187)
----------------------------------------------------------------------------
(2,054) (1,778) (3,633) (3,623)
----------------------------------------------------------------------------
(Decrease) increase in cash and cash
equivalents (5) (3) 1 (12)
Cash and cash equivalents
- beginning of period 27 14 21 23
----------------------------------------------------------------------------
Cash and cash equivalents
- end of period $ 22 $ 11 $ 22 $ 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 132 $ 87 $ 278 $ 245
Taxes paid (recovered)
Taxes other than income tax $ 24 $ 39 $ 55 $ 74
Current income tax $ (108) $ 1 $ (55) $ 72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes to the consolidated financial statements
(tabular amounts in millions of Canadian dollars, unless otherwise stated,
unaudited)
1. ACCOUNTING POLICIES
The interim consolidated financial statements of Canadian
Natural Resources Limited (the "Company") include the Company and
all of its subsidiaries and partnerships, and have been prepared
following the same accounting policies as the audited consolidated
financial statements of the Company as at December 31, 2007, except
as described in note 2. The interim consolidated financial
statements contain disclosures that are supplemental to the
Company's annual audited consolidated financial statements. Certain
disclosures that are normally required to be included in the notes
to the annual audited consolidated financial statements have been
condensed. These interim financial statements should be read in
conjunction with the Company's audited consolidated financial
statements and notes thereto for the year ended December 31,
2007.
Comparative Figures
Certain prior period figures have been reclassified to conform
to the presentation adopted in 2008.
2. CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2008 the Company adopted the following
accounting and disclosure standards issued by the Canadian
Institute of Chartered Accountants:
- Capital Disclosures - Section 1535 - "Capital Disclosures"
requires entities to disclose their objectives, policies and
processes for managing capital, as well as quantitative data about
capital. The standard also requires the disclosure of any
externally imposed capital requirements and compliance with those
requirements. The standard does not define capital. This standard
affects disclosure only and did not impact the Company's accounting
for capital (note 8).
- Inventories - Section 3031 - "Inventories" replaces Section
3030 - "Inventories" and establishes new standards for the
measurement of cost of inventories and expands disclosure
requirements for inventories. Adoption of this standard did not
have a material impact on the Company's financial statements.
- Financial Instruments - Section 3862 - "Financial Instruments
- Disclosure" and Section 3863 - "Financial Instruments -
Presentation" replace Section 3861 - "Financial Instruments -
Disclosure and Presentation". Section 3862 enhances disclosure
requirements concerning risks and requires quantitative and
qualitative disclosures about exposures to risks arising from
financial instruments. Section 3863 carries forward the
presentation requirements from Section 3861 unchanged. These
standards affect disclosures only and do not impact the Company's
accounting for financial instruments (note 10).
3. LONG--TERM DEBT
-------------------------
Jun 30 Dec 31
2008 2007
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities (bankers' acceptances) $ 3,456 $ 4,696
Medium-term notes 1,200 1,200
----------------------------------------------------------------------------
4,656 5,896
----------------------------------------------------------------------------
US dollar denominated debt
Senior unsecured notes (2008 - US$31 million; 2007
- US$62 million) 32 61
US dollar debt securities (2008 - US$6,308 million;
2007 - US$5,108 million) 6,425 5,048
Less - original issue discount on senior unsecured
notes and US dollar debt securities (1) (24) (23)
----------------------------------------------------------------------------
6,433 5,086
Fair value of interest rate swaps on US dollar debt
securities (2) 9 9
----------------------------------------------------------------------------
6,442 5,095
----------------------------------------------------------------------------
Long-term debt before transaction costs 11,098 10,991
Less - transaction costs (1) (3) (58) (51)
----------------------------------------------------------------------------
$ 11,040 $ 10,940
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has included unamortized original issue discounts and
directly attributable transaction costs in the carrying value of the
outstanding debt.
(2) The carrying values of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $9 million (2007 - $9 million) to reflect the fair value impact of
hedge accounting.
(3) Transaction costs primarily represent underwriting commissions charged
as a percentage of the related debt offerings, as well as legal, rating
agency and other professional fees.
Bank credit facilities
As at June 30, 2008, the Company had in place unsecured bank
credit facilities of $6,235 million, comprised of:
- a $125 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.
The revolving syndicated credit facilities are extendible
annually for one year periods at the mutual agreement of the
Company and the lenders. If the facilities are not extended, the
full amount of the outstanding principal would be repayable on the
maturity date.
The weighted average interest rate of the bank credit facilities
outstanding at June 30, 2008, was 3.6% (December 31, 2007 -
5.2%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $367 million, including $300
million related to the Horizon Oil Sands Project ("Horizon
Project"), were outstanding at June 30, 2008.
Medium-term notes
The Company has $2,600 million remaining on its outstanding
$3,000 million base shelf prospectus filed in September 2007 that
allows for the issue of medium-term notes in Canada until October
2009. If issued, these securities will bear interest as determined
at the date of issuance.
Senior unsecured notes
During the second quarter of 2008, US$31 million of the senior
unsecured notes were repaid.
US dollar debt securities
In January 2008, the Company issued US$1,200 million of
unsecured notes under a US base shelf prospectus, comprised of
US$400 million of 5.15% unsecured notes due February 2013, US$400
million of 5.90% unsecured notes due February 2018, and US$400
million of 6.75% unsecured notes due February 2039. Proceeds from
the securities issued were used to repay bankers' acceptances under
the Company's bank credit facilities. After issuing these
securities, the Company has US$1,800 million remaining on its
outstanding US$3,000 million base shelf prospectus filed in
September 2007 that allows for the issue of US dollar debt
securities in the United States until October 2009. If issued,
these securities will bear interest as determined at the date of
issuance.
4. OTHER LONG-TERM LIABILITIES
-------------------------
Jun 30 Dec 31
2008 2007
----------------------------------------------------------------------------
Asset retirement obligations $ 1,120 $ 1,074
Stock-based compensation 870 529
Risk management (note 10) 3,042 1,474
Other 101 101
----------------------------------------------------------------------------
5,133 3,178
Less: current portion 3,411 1,617
----------------------------------------------------------------------------
$ 1,722 $ 1,561
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset retirement obligations
At June 30, 2008, the Company's total estimated undiscounted
costs to settle its asset retirement obligations were approximately
$4,571 million (December 31, 2007 - $4,426 million). These costs
will be incurred over the lives of the operating assets and have
been discounted using a weighted average credit-adjusted risk free
rate of 6.6% (December 31, 2007 - 6.6%). A reconciliation of the
discounted asset retirement obligations is as follows:
-----------------------------
Six Months Year
Ended Ended
Jun 30, 2008 Dec 31, 2007
----------------------------------------------------------------------------
Balance - beginning of period $ 1,074 $ 1,166
Liabilities incurred 10 21
Liabilities acquired (disposed) 2 (65)
Liabilities settled (13) (71)
Asset retirement obligation accretion 34 70
Revision of estimates - 35
Foreign exchange 13 (82)
----------------------------------------------------------------------------
Balance - end of period $ 1,120 $ 1,074
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock-based compensation
The Company recognizes a liability for the potential cash
settlements under its Stock Option Plan. The current portion
represents the maximum amount of the liability payable within the
next twelve month period if all vested options are surrendered for
cash settlement.
-----------------------------
Six Months Year
Ended Ended
Jun 30, 2008 Dec 31, 2007
----------------------------------------------------------------------------
Balance - beginning of period $ 529 $ 744
Stock-based compensation 459 193
Payments for options surrendered (184) (375)
Transferred to common shares (66) (91)
Capitalized to Horizon Project 132 58
----------------------------------------------------------------------------
Balance - end of period 870 529
Less: current portion 755 390
----------------------------------------------------------------------------
$ 115 $ 139
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Six Months Ended
----------------------------------------
Jun 30 Jun 30 Jun 30 Jun 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Current income tax - North America $ 6 $ 12 $ 27 $ 37
Current income tax - North Sea 111 54 207 89
Current income tax - Offshore West
Africa 34 16 72 26
----------------------------------------------------------------------------
Current income tax expense 151 82 306 152
Future income tax (recovery) expense (301) 116 (221) 216
----------------------------------------------------------------------------
Income tax (recovery) expense $ (150) $ 198 $ 85 $ 368
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Taxable income from the conventional crude oil and natural gas
business in Canada is primarily generated through partnerships,
with the related income taxes payable in a future period. North
America current income taxes have been provided on the basis of the
corporate structure and available income tax deductions and will
vary depending upon the nature, timing and amount of capital
expenditures incurred in Canada in any particular year.
During the first quarter of 2008, enacted or substantively
enacted income tax rate changes resulted in a reduction of future
income tax liabilities of approximately $19 million in British
Columbia and $22 million in Cote d'Ivoire, Offshore West
Africa.
During the second quarter of 2007, the Canadian Federal
Government enacted income tax rate changes, resulting in a
reduction of future income tax liabilities of approximately $71
million.
6. SHARE CAPITAL
---------------------------------
Six Months Ended Jun 30, 2008
Issued Number of shares
Common shares (thousands) Amount
----------------------------------------------------------------------------
Balance - beginning of period 539,729 $ 2,674
Issued upon exercise of stock options 1,044 14
Previously recognized liability on stock
options exercised for common shares - 66
----------------------------------------------------------------------------
Balance - end of period 540,773 $ 2,754
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dividend policy
In February 2008, the Board of Directors set the regular
quarterly dividend at $0.10 per common share. The Company has paid
regular quarterly dividends in January, April, July, and October of
each year since 2001. The dividend policy undergoes a periodic
review by the Board of Directors and is subject to change.
Stock options
-------------------------------
Six Months Ended Jun 30, 2008
Weighted
average
Stock options exercise
(thousands) price
----------------------------------------------------------------------------
Outstanding - beginning of period 30,659 $ 47.23
Granted 346 $ 72.14
Surrendered for cash settlement (3,253) $ 25.42
Exercised for common shares (1,044) $ 14.00
Forfeited (1,560) $ 54.74
----------------------------------------------------------------------------
Outstanding - end of period 25,148 $ 51.30
----------------------------------------------------------------------------
Exercisable - end of period 6,572 $ 36.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of accumulated other comprehensive income, net of taxes, were
as follows:
-----------------------------
Jun 30 Jun 30
2008 2007
----------------------------------------------------------------------------
Derivative financial instruments designated as
cash flow hedges $ 22 $ 80
Foreign currency translation adjustment (16) (18)
----------------------------------------------------------------------------
$ 6 $ 62
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. CAPITAL DISCLOSURES
As required by Canadian generally accepted accounting principles
("GAAP"), effective January 1, 2008, the Company must provide
certain disclosures regarding its objectives, policies and
processes for managing capital, as well as provide certain
quantitative data about capital. As the Company does not have any
externally imposed capital requirements, for the purposes of this
disclosure, the Company has defined its capital to mean its
long-term debt and consolidated shareholders' equity, as determined
each reporting date.
The Company's objectives when managing its capital structure are
to maintain financial flexibility and balance to enable the Company
to access capital markets to sustain its on-going operations and to
support its growth strategies. The Company primarily monitors
capital on the basis of an internally derived non-GAAP financial
measure referred to as its "debt to book capitalization ratio",
which is the arithmetic ratio of long-term debt divided by the sum
of the carrying value of shareholders' equity plus long-term debt.
The Company aims over time to maintain its debt to book
capitalization ratio in the range of 35% to 45%. However, the
Company may exceed the high end of such target range if it is
investing in capital projects, undertaking acquisitions, or in
periods of lower commodity prices. The Company may be below the low
end of the target range when cash flow from operating activities is
greater than current investment activities. The ratio is currently
at the high end of the target range due to the debt financing of a
business acquisition in 2006 and the construction of the Horizon
Project.
Readers are cautioned that as the debt to book capitalization
ratio has no defined meaning under GAAP, this financial measure may
not be comparable to similar measures provided by other reporting
entities. Further, there can be no assurances that the Company will
continue to use this measure to monitor capital or will not alter
the method of calculation of this measure at some point in the
future.
-----------------------------
Jun 30 Dec 31
2008 2007
----------------------------------------------------------------------------
Long-term debt $ 11,040 $ 10,940
Total shareholders' equity $ 13,607 $ 13,321
Debt to book capitalization 45% 45%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. NET EARNINGS (LOSS) PER COMMON SHARE
Three Months Ended Six Months Ended
----------------------------------------
Jun 30 Jun 30 Jun 30 Jun 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Weighted average common shares
outstanding (thousands)
basic and diluted 540,632 539,296 540,425 539,094
----------------------------------------------------------------------------
Net earnings (loss) - basic and
diluted $ (347) $ 841 $ 380 $ 1,110
----------------------------------------------------------------------------
Net earnings (loss) per common
share - basic and diluted $ (0.65) $ 1.56 $ 0.70 $ 2.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. FINANCIAL INSTRUMENTS
The carrying values of the Company's financial instruments by category are
as follows:
--------------------------------------------------
Jun 30, 2008
--------------------------------------------------
Loans and Held for Other financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized cost
----------------------------------------------------------------------------
Cash and cash
equivalents $ - $ 22 $ -
Accounts receivable 1,786 - -
Accounts payable - - (489)
Accrued liabilities - - (2,634)
Risk management - (3,042) -
Long-term debt - - (11,040)
----------------------------------------------------------------------------
$ 1,786 $ (3,020) $ (14,163)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
--------------------------------------------------
Dec 31, 2007
--------------------------------------------------
Loans and Held for Other financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized cost
----------------------------------------------------------------------------
Cash and cash
equivalents $ - $ 21 $ -
Accounts receivable 1,143 - -
Accounts payable - - (379)
Accrued liabilities - - (1,567)
Risk management - (1,474) -
Long-term debt - - (10,940)
----------------------------------------------------------------------------
$ 1,143 $ (1,453) $ (12,886)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The carrying value of the Company's financial instruments approximates their
fair value, except for fixed-rate long-term debt as noted below:
----------------------------------------
Jun 30, 2008 Dec 31, 2007
----------------------------------------------------------------------------
Carrying Fair Carrying Fair
value value value value
----------------------------------------------------------------------------
Fixed-rate long-term debt (1) $ 7,584 $ 7,535 $ 6,244 $ 6,259
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The carrying values of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $9 million (2007 - $9 million) to reflect the fair value impact of
hedge accounting.
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.
The estimated fair value of derivative financial instruments has
been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values
determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows and discount
rates. In determining these assumptions, the Company has relied
primarily on external readily observable market inputs including
quoted commodity prices and volatility, interest rate yield curves,
and foreign exchange rates. The resulting fair value estimates may
not necessarily be indicative of the amounts that could be realized
or settled in a current market transaction and these differences
may be material.
The changes in estimated fair values of derivative financial
instruments included in the risk management asset (liability) were
recognized in the financial statements as follows:
-----------------------------------
Six Months Ended Year Ended
Jun 30, 2008 Dec 31, 2007
----------------------------------------------------------------------------
Risk management Risk management
Asset (liability) mark-to-market mark-to-market
----------------------------------------------------------------------------
Balance -- beginning of period $ (1,474) $ 128
Retained earnings effect of adoption of
financial instrument standards - 14
Net cost of outstanding put options 186 58
Net change in fair value of outstanding
derivative financial instruments
attributable to:
- Risk management activities (1,523) (1,400)
- Interest expense (1) 9
- Foreign exchange 58 (350)
- Other comprehensive income (102) 125
----------------------------------------------------------------------------
(2,856) (1,416)
Add: Put premium financing
obligations (1) (186) (58)
----------------------------------------------------------------------------
Balance - end of period (3,042) (1,474)
Less: current portion (2,606) (1,227)
----------------------------------------------------------------------------
$ (436) $ (247)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has negotiated payment of put option premiums with various
counterparties at the time of actual settlement of the respective
options. These obligations have been reflected in the net risk
management asset (liability).
Net losses (gains) from risk management activities were as follows:
Three Months Ended Six Months Ended
----------------------------------------
Jun 30 Jun 30 Jun 30 Jun 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Net realized risk management loss $ 954 $ 92 $ 1,370 $ 4
Net unrealized risk management
loss (gain) 1,415 (57) 1,523 479
----------------------------------------------------------------------------
$ 2,369 $ 35 $ 2,893 $ 483
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial risk factors
a) Market risk
Market risk is the risk that the fair value or future cash flows
of a financial instrument will fluctuate because of changes in
market prices. The Company's market risk is comprised of commodity
price risk, interest rate risk, and foreign currency exchange
risk.
Commodity price risk
The Company uses commodity price financial derivatives to manage
its exposure to commodity price risk associated with the sale of
its future crude oil and natural gas production. At June 30, 2008,
the Company had the following net financial derivatives outstanding
to manage its commodity price exposures:
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Crude oil
Crude oil
price
collars Jul 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
Mayan
Jul 2008 - Dec 2008 20,000 bbl/d US$50.00 - US$65.53 Heavy
Jul 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$75.22 WTI
Jul 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.05 WTI
Jul 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.98 WTI
Oct 2008 - Dec 2008 25,000 bbl/d US$70.00 - US$112.63 WTI
Jan 2009 - Dec 2009 25,000 bbl/d US$70.00 - US$111.56 WTI
Crude oil
puts (1) Jul 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
Jan 2009 - Dec 2009 50,000 bbl/d US$80.00 WTI
Jan 2009 - Dec 2009 42,000 bbl/d US$100.00 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to June 30, 2008, the Company unwound 50,000 bbl/d of
US$80.00 WTI put options and entered into 50,000 bbl/d of US$100.00 WTI
put options for the period January to December 2009, for a net cost of
US$89 million.
At June 30, 2008, the net cost of outstanding put options and their
respective periods of settlement was as follows:
Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009 Q4 2009
----------------------------------------------------------------------------
Cost ($ millions) US$15 US$15 US$38 US$38 US$38 US$38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Natural gas
AECO price
collars Jul 2008 - Sep 2008 290,000 GJ/d C$7.50 - C$8.69 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's outstanding commodity financial derivatives are
expected to be settled monthly based on the applicable index
pricing for the respective contract month.
Interest rate risk
The Company is exposed to interest rate risk on its fixed and
floating rate long-term debt. The Company enters into interest rate
swap agreements to manage its fixed to floating interest rate mix
on long-term debt. The interest rate swap contracts require the
periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At June 30,
2008, the Company had the following interest rate swap contracts
outstanding:
Amount Fixed
Remaining term ($ millions) rate Floating rate
----------------------------------------------------------------------------
Interest rate
Swaps - fixed
to floating Jul 2008 - Oct 2012 US$350 5.45% LIBOR (1) + 0.81%
Jul 2008 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) London Interbank Offered Rate
All interest rate related derivative financial instruments
designated as hedges at June 30, 2008 were classified as fair value
hedges.
Foreign currency exchange rate risk
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated debt. The
Company is also exposed to foreign currency exchange rate risk on
transactions conducted in foreign currencies in its foreign
subsidiaries and in the carrying value of its self-sustaining
foreign subsidiaries. The Company enters into cross currency swap
agreements to manage currency exposure on US dollar denominated
long-term debt. The cross currency swap contracts require the
periodic exchange of payments with the exchange at maturity of
notional principal amounts on which the payments are based. At June
30, 2008, the Company had the following cross currency swap
contracts outstanding:
Exchange Interest Interest
Amount rate rate rate
Remaining term ($ millions) (US$/C$) (US$) (C$)
----------------------------------------------------------------------------
Cross
currency
Swaps Jul 2008 - Aug 2016 US$250 1.116 6.00% 5.40%
Jul 2008 - May 2017 US$1,100 1.170 5.70% 5.10%
Jul 2008 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency related derivative financial instruments
designated as hedges at June 30, 2008 were classified as cash flow
hedges.
Financial instrument sensitivities
The following table summarizes the annualized sensitivities of
the Company's net earnings and other comprehensive income to
changes in the fair value of financial instruments outstanding as
at June 30, 2008 resulting from changes in the specified variable,
with all other variables held constant. These sensitivities are
limited to the impact of changes in a specified variable applied to
financial instruments only and do not represent the impact of a
change in the variable on the operating results of the Company
taken as a whole. Further, these sensitivities are theoretical, as
changes in one variable may contribute to changes in another
variable, which may magnify or counteract the sensitivities. In
addition, changes in fair value generally can not be extrapolated
because the relationship of a change in an assumption to the change
in fair value may not be linear.
------------------------------------
Impact on other
Impact on net comprehensive
earnings income
----------------------------------------------------------------------------
Commodity price risk
Increase WTI US$1.00/bbl $ (34) $ -
Decrease WTI US$1.00/bbl $ 34 $ -
Increase AECO C$0.10/mcf $ (2) $ -
Decrease AECO C$0.10/mcf $ 2 $ -
Interest rate risk
Increase interest rate 1% $ (21) $ 26
Decrease interest rate 1% $ 21 $ (32)
Foreign currency exchange rate risk
Increase exchange rate by US$0.01 $ (33) $ -
Decrease exchange rate by US$0.01 $ 33 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) Credit risk
Credit risk is the risk that a party to a financial instrument
will cause a financial loss for the Company by failing to discharge
an obligation.
The Company's accounts receivable are mainly with customers in
the crude oil and natural gas industry and are subject to normal
industry credit risks. The Company manages these risks by reviewing
its exposure to individual companies on a regular basis and where
appropriate, ensures that parental guarantees or letters of credit
are in place to minimize the impact in the event of default.
Substantially all of the Company's accounts receivables are due
within normal trade terms.
The Company is also exposed to possible losses in the event of
nonperformance by counterparties to derivative financial
instruments; however, the Company manages this credit risk by
entering into agreements with substantially all investment grade
financial institutions and other entities. At June 30, 2008, the
Company had net risk management assets of $3 million with specific
counterparties related to derivative financial instruments
(December 31, 2007 - $20 million).
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter
difficulty in meeting obligations associated with financial
liabilities.
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating
activities, available credit facilities, and access to debt capital
markets, to meet obligations as they become due. Due to
fluctuations in the timing of the receipt and/or disbursement of
operating cash flows, the Company maintains adequate bank credit
facilities to provide liquidity.
The maturity dates for financial liabilities are as follows:
1 to 2 to
Less than less than less than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 489 $ - $ - $ -
Accrued liabilities $ 2,634 $ - $ - $ -
Risk management $ 2,606 $ 182 $ (35) $ 289
Long-term debt (1) $ 40 $ 2,345 $ 1,971 $ 5,646
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or transaction
costs. No debt repayments are reflected for $1,111 million of revolving
bank credit facilities due to the extendable nature of the facilities.
11. COMMITMENTS
As at June 30, 2008, the Company had committed to certain payments as
follows:
Remaining
2008 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 121 $ 172 $ 156 $ 130 $ 113 $ 1,097
Offshore equipment
operating leases (1) $ 76 $ 129 $ 117 $ 115 $ 93 $ 403
Offshore drilling (2) (3) $ 189 $ 211 $ 52 $ - $ - $ -
Asset retirement
obligations (4) $ 20 $ 4 $ 5 $ 4 $ 4 $ 4,534
Office leases $ 12 $ 26 $ 29 $ 22 $ 2 $ -
Other $ 86 $ 288 $ 182 $ 24 $ 20 $ 53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 commenced in the second quarter of 2008, on
delivery of the rig. Estimated total remaining payments of US$81
million, after joint venture recoveries, have been included in this
table for the period 2008 - 2009.
(3) During 2007, the Company awarded contracts for a drilling rig and for
the construction of wellhead towers in connection with the planned
offshore development in Gabon, Offshore West Africa. Estimated total
remaining payments of US$359 million have been included in this table
for the period 2008 - 2010.
(4) Amounts represent management's estimate of the future undiscounted
payments to settle asset retirement obligations related to resource
properties, facilities, and production platforms, based on current
legislation and industry operating practices. Amounts disclosed for the
period 2008 - 2012 represent the minimum required expenditures to meet
these obligations. Actual expenditures in any particular year may exceed
these minimum amounts.
In addition to the amounts disclosed above, the Company has
budgeted revised construction costs of approximately $970 million
to for the remainder of 2008 related to the planned completion of
Phase 1 of the Horizon Project.
12. SEGMENTED INFORMATION
North America North Sea
Three Six Three Six
Months Months Months Months
(millions of Canadian Ended Ended Ended Ended
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
Segmented revenue 4,282 2,584 7,497 5,119 537 402 1,045 833
Less: royalties (651) (315) (1,056) (681) (1) - (2) (1)
----------------------------------------------------------------------------
Segmented revenue, net of
royalties 3,631 2,269 6,441 4,438 536 402 1,043 832
----------------------------------------------------------------------------
Segmented expenses
Production 475 442 926 864 105 120 217 236
Transportation and
blending 698 391 1,191 756 2 4 5 8
Depletion, depreciation
and amortization 562 595 1,128 1,155 72 87 158 194
Asset retirement
obligation accretion 9 10 20 19 7 7 13 15
Realized risk management
loss (gain) 954 67 1,371 (25) - 25 (1) 29
----------------------------------------------------------------------------
Total segmented expenses 2,698 1,505 4,636 2,769 186 243 392 482
----------------------------------------------------------------------------
Segmented earnings before
the following 933 764 1,805 1,669 350 159 651 350
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Stock-based compensation
expense
Interest, net
Unrealized risk management
loss (gain)
Foreign exchange (gain) loss
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings (loss) before taxes
Taxes other than income tax
Current income tax expense
Future income tax (recovery)
expense
----------------------------------------------------------------------------
Net earnings (loss)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore West Africa Midstream
Three Six Three Six
Months Months Months Months
(millions of Canadian Ended Ended Ended Ended
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
Segmented revenue 287 161 524 305 20 17 40 36
Less: royalties (36) (16) (79) (25) - - - -
----------------------------------------------------------------------------
Segmented revenue, net of
royalties 251 145 445 280 20 17 40 36
----------------------------------------------------------------------------
Segmented expenses
Production 25 18 46 40 8 5 13 11
Transportation and blending - - - - - - - -
Depletion, depreciation and
amortization 34 36 68 76 2 2 4 4
Asset retirement obligation
accretion 1 - 1 1 - - - -
Realized risk management
loss (gain) - - - - - - - -
----------------------------------------------------------------------------
Total segmented expenses 60 54 115 117 10 7 17 15
----------------------------------------------------------------------------
Segmented earnings before
the following 191 91 330 163 10 10 23 21
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Stock-based compensation
expense
Interest, net
Unrealized risk management
loss (gain)
Foreign exchange (gain) loss
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings (loss) before taxes
Taxes other than income tax
Current income tax expense
Future income tax (recovery)
expense
----------------------------------------------------------------------------
Net earnings (loss)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment
elimination
and other Total
Three Six Three Six
Months Months Months Months
(millions of Canadian Ended Ended Ended Ended
unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
Segmented revenue (14) (12) (27) (23) 5,112 3,152 9,079 6,270
Less: royalties - - - - (688) (331) (1,137) (707)
----------------------------------------------------------------------------
Segmented revenue, net
of royalties (14) (12) (27) (23) 4,424 2,821 7,942 5,563
----------------------------------------------------------------------------
Segmented expenses
Production (3) (1) (5) (2) 610 584 1,197 1,149
Transportation and
blending (11) (10) (22) (20) 689 385 1,174 744
Depletion, depreciation
and amortization - - - - 670 720 1,358 1,429
Asset retirement obligation
accretion - - - - 17 17 34 35
Realized risk management
loss (gain) - - - - 954 92 1,370 4
----------------------------------------------------------------------------
Total segmented
expenses (14) (11) (27) (22) 2,940 1,798 5,133 3,361
----------------------------------------------------------------------------
Segmented earnings before
the following - (1) - (1) 1,484 1,023 2,809 2,202
----------------------------------------------------------------------------
Non-segmented expenses
Administration 45 53 88 113
Stock-based compensation
expense 459 106 459 131
Interest, net 31 77 80 160
Unrealized risk management
loss (gain) 1,415 (57) 1,523 479
Foreign exchange (gain) loss (31) (224) 83 (251)
----------------------------------------------------------------------------
Total non-segmented
expenses 1,919 (45) 2,233 632
----------------------------------------------------------------------------
Earnings (loss) before taxes (435)1,068 576 1,570
Taxes other than income tax 62 29 111 92
Current income tax expense 151 82 306 152
Future income tax (recovery) expense (301) 116 (221) 216
----------------------------------------------------------------------------
Net earnings (loss) (347) 841 380 1,110
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net additions to property, plant and equipment
Six Months Ended
Jun 30, 2008
------------------------------------------
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 1,280 $ 12 $ 1,292
North Sea 124 - 124
Offshore West Africa 258 (2) 256
Other 1 - 1
Horizon Project (2) 2,193 - 2,193
Midstream 4 - 4
Head office 7 - 7
----------------------------------------------------------------------------
$ 3,867 $ 10 $ 3,877
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six Months Ended
Jun 30, 2007
------------------------------------------
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 1,417 $ 8 $ 1,425
North Sea 274 - 274
Offshore West Africa 82 - 82
Other 2 - 2
Horizon Project (2) 1,650 - 1,650
Midstream 2 - 2
Head office 9 - 9
----------------------------------------------------------------------------
$ 3,436 $ 8 $ 3,444
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
----------------------------------------
Jun 30 Dec 31 Jun 30 Dec 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Segmented assets
North America $ 22,205 $ 22,033 $ 24,922 $ 23,617
North Sea 1,761 1,728 2,121 1,957
Offshore West Africa 1,373 1,188 1,445 1,354
Other 26 25 38 41
Horizon Project 10,844 8,651 10,943 8,740
Midstream 205 205 330 333
Head office 68 72 68 72
----------------------------------------------------------------------------
$ 36,482 $ 33,902 $ 39,867 $ 36,114
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 six
months ended June 30, 2008, pre-tax interest of $221 million was
capitalized to the Horizon Project (June 30, 2007 - $152
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 June 30, 2008:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 2.8x
Cash flow from operations (2) 11.9x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 7:00 a.m. Mountain Time, 9:00
a.m. Eastern Time on Thursday,
August 7, 2008. The North American conference call number is
1-877-461-2816 and the outside North American conference call
number is 001-416-695-9761. 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 August 14, 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 3262068.
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 THIRD QUARTER RESULTS
2008 third quarter results are scheduled for release prior to
market opening on Thursday, November 6, 2008. A conference call
will be held on that day 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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