Commenting on the fourth quarter 2009 and year end results, Allan
Markin, Chairman of Canadian Natural Resources Limited (TSX: CNQ)
(NYSE: CNQ) ("Canadian Natural" or the "Company") stated, "Canadian
Natural's strong quarterly and annual results reflect the focus of
management and all employees to deliver on the defined plan. We
were proactive in our approach to the low crude oil and natural gas
pricing environment by deferring capital in our original 2009
budget. Our capital discipline provides balance sheet strength
throughout all business cycles. Last year was noteworthy for
Canadian Natural as our diligent efforts were rewarded with the
achievement of first oil at Horizon, helping 2009 become a record
crude oil production year for the Company. We continue to strive to
develop our assets in the most cost effective way and are committed
to providing long-term shareholder value."
Canadian Natural's Vice-Chairman, John Langille, continued, "The
commodity price environment in 2009 was challenging, particular in
the first half of the year, as a result of economic concerns that
continued from 2008. By maintaining capital and operating
discipline in 2009, we were able to elevate the Company's financial
strength. Debt to book capitalization exited 2009 at 33%, below
current targeted ranges. We understand the importance of a strong
balance sheet as it enables the Company to withstand commodity
price cycles and provides the flexibility to take advantage of
current and future opportunities. As well, in recognition of our
strong financial position, large production base and sustainable
cash flow, the Company has approved a 43% dividend increase to
$0.15 per quarter per common share payable April 1, 2010."
Steve Laut, President of Canadian Natural concluded, "As always
we focus our capital on projects that provide the greatest value
and highest returns affording us the ability to generate
significant free cash flow. We continue to progress our thermal
crude oil growth plan and target to sanction the Kirby In-Situ Oil
Sands Project by the end of 2010. At Horizon, we continue to focus
on reaching sustainable production volumes, increasing reliability
and reducing operating costs. Additionally, we continue engineering
and procurement for Tranche 2 of the Phase 2/3 expansion. We are
committed to completing lessons learned from the construction of
Phase 1 to ensure an optimal strategy for the development of future
expansions.
The Company had another solid year of adding new reserves with
finding and on-stream costs (excluding Horizon SCO) of $19.81 per
barrel of oil equivalent for proved reserves and $22.64 per barrel
of oil equivalent for proved and probable reserves utilizing the
new SEC commodity pricing assumptions. The significant reduction in
natural gas pricing in 2009 resulted in the loss of late-life
reserves and certain reserves associated with undeveloped drilling
opportunities. The significant increase in crude oil prices
resulted in calculated higher royalties and accelerated project
payouts for oil sand projects, including Horizon and our thermal
projects. While this improves the economics of the projects it also
results in reduced net reserves. Excluding the impact of price
revisions, our finding and on-stream costs would have been $12.28
per barrel of oil equivalent for proved reserves and $7.74 per
barrel of oil equivalent for proved and probable reserves."
QUARTERLY HIGHLIGHTS
Quarterly Results Year End Results
--------------------------------------------------
($ millions, except as Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
noted) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Net earnings $ 455 $ 658 $ 1,770 $ 1,580 $ 4,985
per common share, basic
and diluted $ 0.85 $ 1.21 $ 3.27 $ 2.92 $ 9.22
Adjusted net earnings
from operations (1) $ 667 $ 658 $ 697 $ 2,689 $ 3,492
per common share, basic
and diluted $ 1.23 $ 1.21 $ 1.29 $ 4.96 $ 6.46
Cash flow from operations
(2) $ 1,703 $ 1,506 $ 1,570 $ 6,090 $ 6,969
per common share, basic
and diluted $ 3.14 $ 2.78 $ 2.90 $ 11.24 $ 12.89
Capital expenditures, net
of dispositions $ 694 $ 574 $ 1,827 $ 2,997 $ 7,451
Daily production, before
royalties
Natural gas (mmcf/d) 1,250 1,293 1,427 1,315 1,495
Crude oil and NGLs (bbl/d) 366,451 359,269 309,570 355,463 315,667
Equivalent production
(boe/d) 574,857 574,755 547,399 574,730 564,845
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 debt repayment. The derivation of this measure is
discussed in the MD&A.
Annual
- The Company's natural gas assets delivered as expected,
averaging 1,315 mmcf/d for 2009, a decrease of 12% from 2008. As
anticipated, 2009 natural gas production volumes declined due to
reduced capital re-investment and an associated 59% reduction in
natural gas net drilling activity.
- Total crude oil and NGLs production in 2009 averaged 355,463
bbl/d, a 13% increase from 2008. Crude oil volumes were higher due
to capital reallocation to crude oil drilling and the commencement
of production at Horizon Oil Sands ("Horizon"), slightly offset by
lower NGLs production and international light crude oil
declines.
- Cash flow from operations decreased 13% to $6.1 billion in
2009 from $7.0 billion in 2008, and net earnings decreased 68% in
2009 to $1.6 billion from $5.0 billion in 2008. The decrease in
cash flow and earnings was primarily due to a decrease in product
pricing, partially offset by the commencement of production at
Horizon.
Fourth Quarter
- Total crude oil and NGLs production for Q4/09 was 366,451
bbl/d. Q4/09 crude oil production volumes increased 2% from Q3/09
of 359,269 bbl/d, and increased 18% from Q4/08 of 309,570 bbl/d.
The increase in volumes in Q4/09 from the same quarter last year
was primarily due to production at Horizon. The increase from Q3/09
reflects increased production at Horizon and higher thermal volumes
relating to the cyclic nature of the Company's thermal
production.
- Natural gas production volumes for the fourth quarter
represented 36% of the Company's total production. Natural gas
production for Q4/09 averaged 1,250 mmcf/d, down 3% from 1,293
mmcf/d for Q3/09 and down 12% from 1,427 mmcf/d for Q4/08 as
expected. The decrease in volumes for Q4/09 from Q4/08 reflected
the reallocation of capital towards higher return crude oil
projects.
- Quarterly cash flow from operations was approximately $1.7
billion, a 13% increase from Q3/09 and an increase of 8% from
Q4/08. The increase from Q3/09 primarily reflected higher crude oil
and natural gas price realizations, partially offset by a lower
realized risk management gain for the quarter. The increase from
Q4/08 reflects the impact of higher realized crude oil pricing,
narrowing heavy oil differentials, and higher volumes primarily
associated with production at Horizon. These factors were partially
offset by the impact of lower natural gas volumes and pricing.
- Quarterly net earnings for Q4/09 of $455 million included the
effects of unrealized risk management activity, stock based
compensation and fluctuations in foreign exchange. Excluding these
items, quarterly adjusted net earnings from operations for Q4/09
were $667 million, a decrease of 4% from Q4/08.
Operational and Financial
- Maintained a strong undeveloped conventional core land base in
Canada of 10.5 million net acres - a key asset for continued value
growth.
- Completed the Q4/09 North America drilling program targeting
212 net crude oil wells and 28 net natural gas wells with a 93%
success rate in the quarter, excluding stratigraphic test and
service wells. The success rate is a reflection of Canadian
Natural's strong, predictable, low-risk asset base.
- Improvements at Pelican Lake continue with the conversion of
waterflood wells to polymer flood wells, with production averaging
approximately 38,000 bbl/d, a 2% increase over the previous
quarter.
- Q4/09 North America crude oil and NGLs production increased 3%
from Q3/09 levels, reflecting the transition between steam and
production cycles of Primrose wells.
- Diagnostic steaming is proceeding according to plan at
Primrose East and average production is targeted to be between
16,000 bbl/d and 20,000 bbl/d in 2010 as we cautiously return to
normal steaming activities.
- The Facility Upgrade Project at Espoir, which will increase
capacity of the Floating Production Storage and Offtake vessel
("FPSO"), is progressing and commissioning is targeted to be
complete in the second quarter of 2010.
- At the Olowi Project in Offshore Gabon production volumes from
the first platform continue to be below expectations and as a
result the Company recognized a ceiling test impairment of $115
million (pre-tax) at December 31, 2009. The Company continues
drilling at the next scheduled platform with production targeted
for second quarter of 2010.
- Independent qualified reserves evaluators evaluated and
reviewed all of the Company's crude oil and natural gas reserves
under twelve month average prices and current costs as at December
31, 2009:
-- Total corporate proved reserves were 3.03 billion barrels of
crude oil and NGLs and 3.18 trillion cubic feet of natural gas
equating to 3.56 billion barrels of oil equivalent. Total corporate
proved and probable reserves were 4.74 billion barrels of crude oil
and NGLs and 4.21 trillion cubic feet of natural gas equating to
5.44 billion barrels of oil equivalent.
-- As a result of the changes to United States Securities
Exchange Commission ("SEC") regulations, the synthetic crude oil
("SCO") produced at Horizon is now considered a crude oil and
natural gas producing activity and is therefore included with crude
oil and NGL reserves.
-- Horizon net proved SCO reserves decreased by 296 million
barrels to 1.65 billion barrels. The decrease included an economic
revision due to price of 307 million barrels. The net proved and
probable SCO reserves were 2.51 billion barrels. The significant
increase in crude oil prices resulted in calculated higher
royalties and accelerated project payout.
-- Total net proved reserves excluding Horizon SCO at the end of
2009 amounted to 1.38 billion barrels of crude oil and NGLs and
3.18 trillion cubic feet of natural gas equating to 1.91 billion
barrels of oil equivalent. Total net proved reserves excluding
Horizon SCO decreased by 53 million barrels of oil equivalent from
2008. As a direct result of lower natural gas prices, there was a
reduction of net proved natural gas reserves of 327 billion cubic
feet. There was also a decrease of 19 million barrels of proved
crude oil and NGLs as a result of economic revisions due to higher
royalties and accelerated project payouts resulting from higher
crude oil prices.
-- Total net proved reserve additions excluding Horizon SCO
equaled 69% of 2009 net production, at a finding and on-stream cost
of $19.81 per barrel of oil equivalent. The Company's three-year
average proved finding and on-stream cost was $17.76 per barrel of
oil equivalent.
-- Total net proved and probable reserves, excluding Horizon
SCO, at the end of 2009 amounted to 2.23 billion barrels of crude
oil and NGLs and 4.21 trillion cubic feet of natural gas equating
to 2.93 billion barrels of oil equivalent. Total proved and
probable net reserves, excluding Horizon SCO, decreased by 69
million barrels of oil equivalent from 2008 as a result of economic
revisions due to prices.
-- Total net proved and probable reserve additions, excluding
Horizon SCO, equaled 61% of 2009 net production, at a finding and
on-stream cost of $22.64 per barrel of oil equivalent. The
Company's three-year average net proved and probable finding and
on-stream cost was $17.41 per barrel of oil equivalent.
-- North America net proved reserve additions excluding economic
revisions due to prices and Horizon SCO equaled 176% of 2009
production at a finding and on-stream cost of $6.45 per barrel of
oil equivalent. Net proved and probable reserve additions excluding
economic revisions due to prices and Horizon SCO equaled 213% of
2009 production at a finding and on-stream cost of $5.32 per barrel
of oil equivalent.
-- Using the total net proved finding and on-stream costs,
excluding Horizon SCO, the Company achieved an overall recycle
ratio of 1.4x during 2009. By also excluding the revisions due to
prices, the recycle ratio would be 2.3x.
- Long-term debt was reduced by $3.3 billion to $9.7 billion in
2009 from $13.0 billion in 2008. As a result, 2009 debt to book
capitalization improved to 33% (2008 - 41%) and debt to EBITDA
improved to 1.4x (2008 - 1.7x).
- Tenth consecutive year of dividend increases. The 2010
quarterly dividend on common shares increased by 43% to C$0.15 from
C$0.105 per common share, payable April 1, 2010.
- On March 3, 2010 the Board of Directors approved a resolution
to file with the Toronto Stock Exchange a Notice of Intention to
purchase by way of normal course issuer bid up to 2.5% of its
issued and outstanding common shares. Subject to acceptance by the
Toronto Stock Exchange of the Notice of Intention, the purchases
would be made through the facilities of the Toronto Stock Exchange
and the New York Stock Exchange.
- On March 3, 2010, the Company's Board of Directors approved a
resolution to subdivide the Company's common shares on a two for
one basis, subject to shareholder approval. The proposal will be
voted on at the Company's Annual and Special Meeting of
Shareholders to be held on May 6, 2010.
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, synthetic crude oil and
NGLs. A large diversified project portfolio enables the effective
allocation of capital to higher return opportunities.
OPERATIONS REVIEW
Activity by core region
-------------------------------------------
Net undeveloped land Drilling activity
as at year ended
Dec 31, 2009 Dec 31, 2009
(thousands of net acres) (net wells) (1)
----------------------------------------------------------------------------
North America conventional
Northeast British Columbia 2,068 21.5
Northwest Alberta 1,154 53.5
Northern Plains 5,885 599.9
Southern Plains 804 19.0
Southeast Saskatchewan 139 22.5
Thermal In-situ Oil Sands 486 289.0
----------------------------------------------------------------------------
10,536 1,005.4
Oil Sands Mining and Upgrading 115 115.0
North Sea 150 1.2
Offshore West Africa 192 6.1
----------------------------------------------------------------------------
10,993 1,127.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Drilling activity includes stratigraphic test and service wells.
Drilling activity (number of wells)
Year Ended Dec 31
-------------------------------------
2009 2008
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 686 644 728 682
Natural gas 141 109 411 269
Dry 49 46 44 39
----------------------------------------------------------------------------
Subtotal 876 799 1,183 990
Stratigraphic test / service wells 329 329 133 131
----------------------------------------------------------------------------
Total 1,205 1,128 1,316 1,121
----------------------------------------------------------------------------
Success rate (excluding stratigraphic
test / service wells) 94% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America Conventional
North America natural gas
Three Months Ended Year Ended
------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas production
(mmcf/d) 1,218 1,264 1,405 1,287 1,472
----------------------------------------------------------------------------
Net wells targeting natural
gas 28 17 43 117 280
Net successful wells drilled 28 17 41 109 269
----------------------------------------------------------------------------
Success rate 100% 100% 95% 93% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Annual production for North America natural gas in 2009 was
1,287 mmcf/d, a decrease of 13% from 2008. Q4/09 North America
natural gas production decreased 4% from Q3/09 and decreased 13%
from Q4/08. The year over year decrease reflected natural declines
in production due to the Company's strategic decision to reduce
spending on natural gas drilling and focus on higher return crude
oil projects.
- Canadian Natural targeted 28 net natural gas wells in Q4/09.
In Northeast British Columbia, 4 net wells were drilled, while in
Northwest Alberta, 12 net wells were drilled. In the Northern
Plains, 11 net wells were drilled, with 1 net well drilled in the
Southern Plains.
- Planned drilling activity for Q1/10 includes 47 net natural
gas wells compared to drilling activity for Q1/09 of 72 net natural
gas wells.
North America crude oil and NGLs
Three Months Ended Year Ended
------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs
production (bbl/d) 229,206 223,307 240,831 234,523 243,826
----------------------------------------------------------------------------
Net wells targeting crude
oil 212 270 190 676 704
Net successful wells
drilled 195 260 181 638 677
----------------------------------------------------------------------------
Success rate 92% 96% 95% 94% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Annual production for North America crude oil and NGLs in 2009
was 234,523 bbl/d, a decrease of 4% from 2008 production. Q4/09
North America crude oil and NGLs production increased 3% from Q3/09
and decreased 5% from Q4/08 levels. The increase from the previous
quarter reflects higher thermal production volumes at Primrose.
- Diagnostic steaming is proceeding according to plan at
Primrose East and average production is targeted to be between
16,000 bbl/d and 20,000 bbl/d in 2010 as the Company cautiously
returns to normal steaming activities.
- In early 2007, Canadian Natural announced the Kirby In-Situ
Oil Sands Project, the proposed third phase of the thermal growth
plan which will target production capacity of 45,000 bbl/d. The
Company has filed its formal regulatory application documents for
this project, which is still proceeding, as part of the Company's
normal course of business. The Company continues with detailed
engineering and design work and targets to sanction the project by
the end of 2010.
- Development of new pads and tertiary recovery conversion
projects at Pelican Lake continued as expected throughout Q4/09.
The Company drilled 60 horizontal wells in 2009 with plans to drill
an additional 148 horizontal wells in 2010. Pelican Lake production
averaged approximately 38,000 bbl/d for Q4/09 compared to
approximately 37,000 bbl/d for Q3/09 and Q4/08. The response from
the polymer flood project continues to be positive and the Company
is converting regions currently under waterflood to polymer flood
and is also expanding the polymer flood to new areas.
- Conventional heavy crude oil production volumes were slightly
higher in Q4/09 compared to Q3/09 reflecting the expanded drilling
program in 2009.
- During Q4/09, drilling activity targeted 212 net crude oil
wells including 159 wells targeting heavy crude oil, 19 wells
targeting Pelican Lake crude oil, 14 wells targeting thermal crude
oil and 20 wells targeting light crude oil.
- Planned drilling activity for Q1/10 includes 253 net crude oil
wells, excluding stratigraphic test and service wells.
International
Three Months Ended Year Ended
------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil production
(bbl/d)
North Sea 34,408 34,034 42,991 37,761 45,274
Offshore West Africa 32,643 35,021 25,748 32,929 26,567
----------------------------------------------------------------------------
Natural gas production
(mmcf/d)
North Sea 12 8 10 10 10
Offshore West Africa 20 21 12 18 13
----------------------------------------------------------------------------
Net wells drilled - 2.2 1.1 6.4 5.5
Net successful wells
drilled - 1.9 1.1 6.1 4.7
----------------------------------------------------------------------------
Success rate - 86% 100% 95% 85%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
- North Sea production was 34,408 bbl/d during the quarter, in
line with expectations and quarterly guidance. Both Q3/09 and Q4/09
were impacted by planned maintenance shutdowns which were completed
within anticipated time frames. On an annual basis North Sea
production was 37,761 bbl/d, a 17% decrease from 2008 as expected,
reflecting reduced activity levels and natural declines.
Offshore West Africa
- In Q4/09, crude oil production at Offshore West Africa was at
the high end of guidance at 32,643 bbl/d despite a well failure at
Espoir late in Q4/09. Strategies to remediate the well failure are
currently under review. On an annual basis, Offshore West Africa
crude oil production increased by 24% from the prior year,
reflecting additional volumes from the Baobab drilling program and
Olowi, offsetting expected declines at Espoir.
- The Facility Upgrade Project at Espoir, which will increase
capacity of the FPSO, is progressing and commissioning is targeted
to be complete in the second quarter of 2010.
- At the Olowi Project in Offshore Gabon, production volumes
from the first platform continue to be below expectations and as a
result the Company recognized a ceiling test impairment of $115
million (pre-tax) at December 31, 2009. The Company continues
drilling at the next scheduled platform with production targeted
for the second quarter of 2010.
Oil Sands Mining and Upgrading
Three Months Ended Year Ended
------------------------------------------------
Dec 31 Sep 30 Dec 30 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Synthetic Crude Oil
Production (bbl/d) 70,194 66,907 - 50,250 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Equipment reliability challenges in the Hydrogen plant and
downtime relating to a Coker furnace caused an extended shut down
at the end of Q4/09. As a result, December production was
approximately 42,000 bbl/d SCO decreasing overall quarterly
production to the low end of guidance. Horizon's operational
ability at design capacity was proven in Q4/09 as a record monthly
average production was reached in November at approximately 97,000
bbl/d SCO. Monthly average production for Horizon will be provided
on a monthly basis on the Company's website.
Recent monthly production is as follows:
------------------------------------------------
Approximate monthly October November December January
production 2009 2009 2009 2010
----------------------------------------------------------------------------
(bbl/d SCO) 71,000 97,000 42,000 72,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- The Company continues to ramp up to sustainable production of
110,000 bbl/d which is targeted for mid-2010.
- The Company has been able to rectify the impact of clays
content through ore blending from three mine benches. Mitigating
strategies such as stockpiling the second bench allowed access to
the third bench much sooner than originally anticipated.
- Engineering and procurement for Tranche 2 of the Phase 2/3
expansion is progressing with a focus on increasing reliability and
uptime. Tranches 3 and 4 of Phase 2/3 continue to be re-profiled.
The Company continues to work on completing its lessons learned
from the construction of Phase 1 and implementing these into the
development of future expansions.
- In the 2009 start-up year and without the benefit of targeted
full production capacity, the annual operating cost averaged
approximately C$39.89 per barrel of SCO. With the stabilization of
production during 2010, the Company is targeting to reduce these
costs to C$31.00 to C$37.00 per barrel of SCO.
MARKETING
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs pricing
WTI (1) benchmark price
(US$/bbl) $ 76.17 $ 68.29 $ 58.75 $ 61.93 $ 99.65
Western Canadian Select
blend differential from
WTI (%) 16% 15% 33% 16% 20%
SCO price (US$/bbl) $ 75.07 $ 67.20 $ 58.64 $ 61.51 $ 102.48
Corporate average pricing
before risk
management (C$/bbl) $ 68.00 $ 62.90 $ 45.81 $ 57.68 $ 82.41
Natural gas pricing
AECO benchmark price
(C$/GJ) $ 4.01 $ 2.87 $ 6.43 $ 3.91 $ 7.71
Corporate average pricing
before risk
management (C$/mcf) $ 4.75 $ 3.80 $ 7.03 $ 4.53 $ 8.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
- In Q4/09, the Western Canadian Select ("WCS") heavy crude oil
differential as a percent of WTI was 16%, compared to 15% in Q3/09.
Heavy crude oil differentials remained narrow in Q4/09 due to
continuing demand from the US refineries for heavy crude oil.
- During Q4/09, the Company allocated approximately 140,000
bbl/d of its heavy crude oil blends to the WCS blend, optimizing
the pricing for heavy crude oil. WCS continues its advancement as
the recognized heavy crude oil benchmark for North America.
- Natural gas pricing for Q4/09 remained relatively weak
primarily due to supply/demand imbalances. North America natural
gas inventory levels remained high during the fourth quarter due to
an oversupply from US producers and lower industrial
consumption.
- In the first quarter of 2010, Canadian Natural announced,
together with North West Upgrading Inc., the submission of a joint
proposal to the Alberta Government to construct and operate a
bitumen refinery near Redwater, Alberta. This proposal was
submitted in response to a request for proposal under the Alberta
Royalty Framework's Bitumen Royalty In Kind (BRIK) program.
FINANCIAL REVIEW
- Although the negative worldwide economic conditions appear to
be subsiding, the potential for continued volatility in the market
and a long road to full economic recovery remain. The Company
continually examines its liquidity position and ensures a low risk
approach to finance. The Company understands the potential for
commodity price declines and positions itself to endure and succeed
in these times. The Company's financial strength continues to
improve as an increase in production and free cash flow are
expected in 2010. Financial strengths continue to be:
-- A diverse asset base spread over various commodity types with
94% of production located in G8 countries.
-- Financial stability and liquidity - cash flow from operations
of $1.7 billion for Q4/09, with available unused bank lines of $2.0
billion at December 31, 2009.
-- Flexibility in asset base allowing for disciplined capital
allocations.
- A strengthening balance sheet with debt to book capitalization
of 33% and debt to EBITDA of 1.4 times, both below targeted ranges.
Long-term debt was reduced to $9.7 billion as at December 31, 2009,
a reduction of $3.3 billion over the previous year.
- Tenth consecutive year of dividend increases. The 2010
quarterly dividend on common shares increased by 43% to C$0.15 from
C$0.105 per common share, payable April 1, 2010.
- On March 3, 2010 the Board of Directors approved a resolution
to file with the Toronto Stock Exchange a Notice of Intention to
purchase by way of normal course issuer bid up to 2.5% of its
issued and outstanding common shares. Subject to acceptance by the
Toronto Stock Exchange of the Notice of Intention, the purchases
would be made through the facilities of the Toronto Stock Exchange
and the New York Stock Exchange.
- On March 3, 2010, the Company's Board of Directors approved a
resolution to subdivide the Company's common shares on a two for
one basis, subject to shareholder approval. The proposal will be
voted on at the Company's Annual and Special Meeting of
Shareholders to be held on May 6, 2010.
OUTLOOK
- The Company forecasts 2010 production levels before royalties
to average between 1,117 and 1,185 mmcf/d of natural gas and
between 400,000 and 445,000 bbl/d of crude oil and NGLs. Q1/10
production guidance before royalties is forecast to average between
1,197 and 1,221 mmcf/d of natural gas and between 372,000 and
409,000 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/.
YEAR-END RESERVES
Determination of reserves
For the year ended December 31, 2009 the Company retained
qualified independent reserves evaluators, Sproule Associates
Limited ("Sproule"), and GLJ Petroleum Consultants Ltd. ("GLJ"), to
evaluate and review all of the Company's proved, as well as
probable crude oil, synthetic crude oil, NGLs and natural gas
reserves and prepare Evaluation Reports on these reserves. Sproule
evaluated and reviewed all of the Company's crude oil, bitumen,
natural gas, coal bed methane and NGLs reserves. GLJ evaluated all
of the synthetic crude oil reserves related to the Company's oil
sands mine. The Company has been granted an exemption from certain
provisions of National Instrument 51-101 - "Standards of Disclosure
for Oil and Gas Activities" ("NI 51-101"), which prescribes the
standards for the preparation and disclosure of reserves and
related information for companies listed in Canada. This exemption
allows the Company to substitute Securities Exchange Commission
("SEC") requirements under Regulation S-K and S-X for certain
disclosures required under NI 51-101. In February 2009 the SEC
released its final rules for the modernization of oil and gas
reporting ("Final Rule"). The material changes include the ability
to include oil sands mining as an oil and gas activity, ability to
use reliable technology to establish undeveloped reserves, the
optional ability to report probable reserves, the requirement to
track undeveloped locations, as well as the directive to use twelve
month average prices and current costs. These resulting changes are
more in line with the NI 51-101 however there are material
differences to the type of volumes disclosed and the basis from
which the volumes are determined. NI 51-101 requires gross reserves
and future net revenue under forecast pricing and costs, however,
the SEC, as discussed, requires disclosure of net reserves, after
royalties, under twelve month average prices and current costs.
Therefore the difference between the reported numbers under the two
disclosure standards can be material. The Company discloses its
synthetic crude oil, bitumen, crude oil and NGLs and natural gas
reserve reconciliations net of royalties in adherence to SEC
requirements.
The Reserves Committee of the Company's Board of Directors has
met with and carried out independent due diligence procedures with
Sproule and GLJ as to the Company's reserves.
Corporate net reserves
- Proved finding and on-stream costs, excluding Horizon SCO
reserves, were $19.81 per barrel of oil equivalent with total
reserve additions replacing 69% of production. On a three-year
basis, proved finding and on-stream costs were $17.76 per barrel of
oil equivalent. Using proved and probable reserves, finding and
on-stream costs were $22.64 per barrel of oil equivalent and
averaged $17.41 per barrel of oil equivalent over the past three
years.
- Economic price revisions on natural gas resulted in a
reduction of 327 billion cubic feet, 19 million barrels of crude
oil and NGLs and 307 million barrels of SCO proved reserves. Absent
these revisions and excluding Horizon SCO, proved finding and
on-stream costs would have been reported at $12.28 per barrel of
oil equivalent.
- Under revised SEC reporting guidelines, crude oil and natural
gas reserves now include Horizon SCO reserves. The net proved SCO
reserves, on a stand alone basis, have an associated cumulative
finding and on-stream cost of $5.82 per barrel of oil
equivalent.
North American net reserves
- Proved finding and on-stream costs for North American
operations, excluding the impact of Horizon SCO reserves, were
$12.78 per barrel of oil equivalent.
- Net proved reserve additions, excluding economic revisions due
to prices, replaced 176% of 2009 production at a finding and
on-stream cost of $6.45 per barrel of oil equivalent. Net proved
and probable reserve additions, excluding economic revisions due to
prices, replaced 213% of 2009 production at a finding and on-stream
cost of $5.32 per barrel of oil equivalent.
International
- North Sea net proved reserves were 16 million barrels of oil
equivalent less than 2008 as a result of technical revisions which
were largely offset by positive price revisions.
- In Offshore West Africa net proved reserves decreased by 21
million barrels of oil equivalent to 137 million barrels of oil
equivalent in 2009 due to production and negative price
revisions.
RESERVES OF CRUDE OIL AND NATURAL GAS, NET OF ROYALTIES(1)(2)
December 31, 2009
Proved Proved Proved Proved and
Developed Undeveloped Total Probable
----------------------------------------------------------------------------
Crude oil and NGLs (mmbbl)
North America - Synthetic
crude oil (3) 1,589 61 1,650 2,512
North America - Bitumen (4) 268 427 695 1,213
North America - Crude oil and
NGLs 204 115 319 447
North Sea 94 146 240 387
Offshore West Africa 106 17 123 179
----------------------------------------------------------------------------
2,261 766 3,027 4,738
----------------------------------------------------------------------------
Natural gas (bcf)
North America 2,333 694 3,027 3,992
North Sea 45 22 67 94
Offshore West Africa 81 4 85 124
----------------------------------------------------------------------------
2,459 720 3,179 4,210
----------------------------------------------------------------------------
Total reserves (mmboe) 2,671 886 3,557 5,440
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CRUDE OIL AND NGLs RESERVES RECONCILIATION, NET OF ROYALTIES(1)
North America International Total
----------------------------------------------------------------------------
Net Proved Synthetic Offshore
Reserves Crude Bitumen Crude Oil North West
(mmbbl)(2) Oil (3) (4) & NGLs Total Sea Africa
----------------------------------------------------------------------------
Reserves,
December 31,
2008 - 690 258 948 256 142 1,346
----------------------------------------------------------------------------
Extensions and
discoveries - 24 6 30 - - 30
Infill drilling - 8 1 9 - - 9
Improved recovery - - 74 74 - - 74
SEC Reliable
Technology (5) - 7 - 7 - - 7
SEC Rule
Transition (6) 1,650 - - 1,650 - - 1,650
Purchases of
reserves in
place - - 1 1 - - 1
Sales of reserves
in place - - - - - - -
Production - (49) (24) (73) (14) (11) (98)
Economic revisions
due to prices - (64) (8) (72) 57 (4) (19)
Revisions of prior
estimates - 79 11 90 (59) (4) 27
----------------------------------------------------------------------------
Reserves,
December 31,
2009 1,650 695 319 2,664 240 123 3,027
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America International Total
----------------------------------------------------------------------------
Net Proved and
Probable Synthetic Offshore
Reserves Crude Bitumen Crude Oil North West
(mmbbl)(7) Oil (3) (4) & NGLs Total Sea Africa
----------------------------------------------------------------------------
Reserves,
December 31,
2008 - 1,238 361 1,599 399 191 2,189
----------------------------------------------------------------------------
Extensions and
discoveries - 35 11 46 - - 46
Infill drilling - 12 2 14 - - 14
Improved recovery - - 110 110 - - 110
SEC Reliable
Technology (5) - 10 - 10 - - 10
SEC Rule
Transition (6) 2,512 - - 2,512 - - 2,512
Purchases of
reserves in
place - - 2 2 - - 2
Sales of reserves
in place - - - - - - -
Production - (49) (24) (73) (14) (11) (98)
Economic revisions
due to prices - (135) (3) (138) 13 (6) (131)
Revisions of prior
estimates - 102 (12) 90 (11) 5 84
Reserves,
December 31,
2009 2,512 1,213 447 4,172 387 179 4,738
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NATURAL GAS RESERVES RECONCILIATION, NET OF ROYALTIES(1)
Offshore
North North West
Net Proved Reserves (bcf) (2) America Sea Africa Total
----------------------------------------------------------------------------
Reserves, December 31, 2008 3,523 67 94 3,684
----------------------------------------------------------------------------
Extensions and discoveries 92 - - 92
Infill drilling 7 - - 7
Improved recovery 4 - - 4
SEC Reliable Technology (5) - - - -
Property purchases 15 - - 15
Property disposals (6) - - (6)
Production (443) (4) (6) (453)
Economic revisions due to prices (335) 12 (4) (327)
Revisions of prior estimates 170 (8) 1 163
----------------------------------------------------------------------------
Reserves, December 31, 2009 3,027 67 85 3,179
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Proved and Probable Reserves (bcf)(7)
----------------------------------------------------------------------------
Reserves, December 31, 2008 4,619 94 131 4,844
----------------------------------------------------------------------------
Extensions and discoveries 111 - - 111
Infill drilling 9 - - 9
Improved recovery 4 - - 4
SEC Reliable Technology (5) - - - -
Property purchases 19 - - 19
Property disposals (7) - - (7)
Production (443) (4) (6) (453)
Economic revisions due to prices (429) 7 (5) (427)
Revisions of prior estimates 109 (3) 4 110
----------------------------------------------------------------------------
Reserves, December 31, 2009 3,992 94 124 4,210
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FINDING AND ON-STREAM COSTS (excluding Horizon SCO reserves and capital)
Three
Year
2009 2008 2007 Total
----------------------------------------------------------------------------
Net reserve replacement expenditures
($ millions) $ 2,377 $ 3,475 $ 3,027 $ 8,879
Net reserve additions (mmboe) (8)
Proved 120 168 212 500
Proved and probable 105 237 168 510
Finding and on-stream costs ($/boe)(9)
Proved $ 19.81 $ 20.68 $ 14.28 $ 17.76
Proved and probable $ 22.64 $ 14.66 $ 18.02 $ 17.41
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) December 31, 2009 reserve estimates are based upon 2009 twelve month
average reference price assumptions, as detailed below, and current
costs. Twelve month average price, as defined by the SEC, is the
unweighted average price of the first day of the month within the twelve
month period prior to the end of the reporting period. Prior to December
31, 2009 year end prices and costs were used in the reserves estimates.
2009
12 Month 2008 2007
Average Year end Year end
Price Price Price
----------------------------------------------------------------------------
Crude oil and NGLs
----------------------------------------------------------------------------
WTI @ Cushing Oklahoma
(US$/bbl) $ 61.18 $ 44.60 $ 96.00
WCS (C$/bbl) $ 58.49 $ 33.07 $ n/a
North Sea Brent (US$/bbl) $ 59.91 $ 41.76 $ 96.02
Company Average Price (C$/bbl) $ 59.39 $ 34.51 $ 62.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2009
12 Month 2008 2007
Average Year end Year end
Price Price Price
----------------------------------------------------------------------------
Natural gas
----------------------------------------------------------------------------
Henry Hub Louisiana (US$/mmbtu) $ 3.87 $ 5.63 $ 6.80
Alberta AECO C (C$/mmbtu) $ 3.87 $ 6.34 $ 6.52
British Columbia Huntingdon
(C$/mmbtu) $ 3.92 $ 7.48 $ 6.96
Company Average Price (C$/mcf) $ 4.02 $ 6.51 $ 6.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------
A foreign exchange rate of US$0.87/C$1.00 was used in the 2009 evaluation;
US$0.82/C$1.00 was used in the 2008 evaluation; US$1.01/C$1.00 was used in
the 2007 evaluation.
(2) Proved reserve estimates were evaluated in accordance with the new SEC
requirements. The stated reserves have a reasonable certainty of being
economically recovered using twelve month average prices and current
costs held constant throughout the productive life of the properties.
(3) Prior to January 1, 2010 Horizon Oil Sands SCO reserves were reported
separately in accordance to the SEC's Industry Guide 7. With SEC's Final
Rule in effect January 1, 2010, this synthetic crude oil is now included
in the Company's crude oil and natural gas reserve totals.
(4) Bitumen as defined by the SEC, under the Final Rule, "is petroleum in a
solid or semi-solid state in natural deposits with a viscosity greater
than 10,000 centipoise measured at original temperature in the deposit
and atmospheric pressure, on a gas free basis." Under this definition,
all the Company's thermal and primary heavy crude oil reserves have been
classified as bitumen. Prior to January 1, 2010, these reserves would
have been classified within the Company's conventional crude oil and NGL
totals.
(5) SEC Reliable Technology accounts for reserves volumes added due to the
reserves rule changes to allow booking of undeveloped reserves beyond 1
spacing unit with supporting geoscience and engineering data.
(6) SEC Rule Transition accounts for the inclusion of synthetic crude oil
reserves volume additions as a result of oil sands mining reserves being
included as a crude oil and natural gas activity effective January 1,
2010. For continuity purposes, with respect to the transition from
Industry Guide 7 into the SEC's Final Rule, the following SCO table has
been provided to illustrate the changes in the Horizon Oil Sands SCO
reserves for the 2009 year.
-------------------------------------------------------------
-------------------------------------------------------------
North America Oil Sands Mining Reserves SCO (mmbbl)
-------------------------------------------------------------
Reserves, December 31, 2008 1,946
Production (18)
Economic revisions due to prices (307)
Revisions of prior estimates 29
-------------------------------------------------------------
Reserves, December 31, 2009 1,650
-------------------------------------------------------------
-------------------------------------------------------------
(7) The December 31, 2009 probable reserves have been evaluated in
accordance to the new SEC requirements. Probable reserves are less
certain to be recovered then proved but which when added with proved
are as likely as not to be recovered. Prior to December 31, 2009, proved
and probable reserve estimates and values were evaluated in accordance
with the standards of the COGEH and as mandated by NI 51-101.
(8) Reserves additions are comprised of all categories of reserves changes,
exclusive of production and SCO reserves.
(9) Reserves finding and on-stream costs are determined by dividing total
cash capital expenditures for each year by net reserves additions for
that year. It excludes costs associated with head office, abandonments,
midstream and the Horizon Oil Sands.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources
Limited (the "Company") in this document or documents incorporated
herein by reference constitute forward-looking statements or
information (collectively referred to herein as "forward-looking
statements") within the meaning of applicable securities
legislation. Forward-looking statements can be identified by the
words "believe", "anticipate", "expect", "plan", "estimate",
"target", "continue", "could", "intend", "may", "potential",
"predict", "should", "will", "objective", "project", "forecast",
"goal", "guidance", "outlook", "effort", "seeks", "schedule" or
expressions of a similar nature suggesting future outcome or
statements regarding an outlook. Disclosure related to expected
future commodity pricing, production volumes, royalties, operating
costs, capital expenditures and other guidance provided throughout
this Management's Discussion and Analysis ("MD&A"), constitute
forward-looking statements. Disclosure of plans relating to and
expected results of existing and future developments, including but
not limited to Horizon Oil Sands Mining and Upgrading operations,
Primrose East, Pelican Lake, Olowi Field (Offshore Gabon), and the
Kirby Thermal Oil Sands Project also constitute forward-looking
statements. This forward-looking information is based on annual
budgets and multi-year forecasts, and is reviewed and revised
throughout the year if necessary in the context of targeted
financial ratios, project returns, product pricing expectations and
balance in project risk and time horizons. These statements are not
guarantees of future performance and are subject to certain risks.
The reader should not place undue reliance on these forward-looking
statements as there can be no assurances that the plans,
initiatives or expectations upon which they are based will
occur.
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.
The forward-looking statements are based on current
expectations, estimates and projections about 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 and uncertainties 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 risks and uncertainties 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 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 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 factors is not
exhaustive. Unpredictable or unknown factors not discussed in this
report could also have material adverse effects on forward-looking
statements. Although the Company believes that the expectations
conveyed by the forward-looking statements are reasonable based on
information available to it on the date such forward-looking
statements are made, no assurances can be given as to future
results, levels of activity and achievements. All subsequent
forward-looking statements, whether written or oral, attributable
to the Company or persons acting on its behalf are expressly
qualified in their entirety by these cautionary statements. Except
as required by law, the Company assumes no obligation to update
forward-looking statements should circumstances or Management's
estimates or opinions change.
Management's Discussion and Analysis
Management's Discussion and Analysis of the financial condition
and results of operations of the Company should be read in
conjunction with the unaudited interim consolidated financial
statements for the year ended December 31, 2009 and the MD&A
and the audited consolidated financial statements for the year
ended December 31, 2008.
All dollar amounts are referenced in millions of Canadian
dollars, except where noted otherwise. The financial statements
have been prepared in accordance with generally accepted accounting
principles in Canada ("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, cash flow
from operations, and cash production costs. These financial
measures are not defined by GAAP and therefore are referred to as
non-GAAP measures. The non-GAAP measures used by the Company may
not be comparable to similar measures presented by other companies.
The Company uses these non-GAAP measures to evaluate its
performance. The non-GAAP measures should not be considered an
alternative to or more meaningful than net earnings, as determined
in accordance with GAAP, as an indication of the Company's
performance. The non-GAAP measures adjusted net earnings from
operations and cash flow from operations are reconciled to net
earnings, as determined in accordance with GAAP, in the "Financial
Highlights" section of this MD&A. The derivation of cash
production costs is included in the "Operating Highlights - Oil
Sands Mining and Upgrading" 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 and per barrel statistics are presented
throughout this MD&A on a "before royalty" or "gross" basis,
and realized prices are net of transportation and blending costs
and exclude the effect of risk management activities. 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 for the year and three months ended
December 31, 2009 in relation to the comparable periods in 2008 and
the third quarter of 2009. The accompanying tables form an integral
part of this MD&A. This MD&A is dated March 3, 2010.
Additional information relating to the Company, including its
Annual Information Form for the year ended December 31, 2008, is
available on SEDAR at www.sedar.com, and on EDGAR at
www.sec.gov.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue, before royalties $ 3,319 $ 2,823 $ 2,511 $ 11,078 $ 16,173
Net earnings $ 455 $ 658 $ 1,770 $ 1,580 $ 4,985
Per common share - basic
and diluted $ 0.85 $ 1.21 $ 3.27 $ 2.92 $ 9.22
Adjusted net earnings from
operations (1) $ 667 $ 658 $ 697 $ 2,689 $ 3,492
Per common share - basic
and diluted $ 1.23 $ 1.21 $ 1.29 $ 4.96 $ 6.46
Cash flow from operations
(2) $ 1,703 $ 1,506 $ 1,570 $ 6,090 $ 6,969
Per common share - basic
and diluted $ 3.14 $ 2.78 $ 2.90 $ 11.24 $ 12.89
Capital expenditures, net
of dispositions $ 694 $ 574 $ 1,827 $ 2,997 $ 7,451
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Net earnings as reported $ 455 $ 658 $ 1,770 $ 1,580 $ 4,985
Stock-based compensation
expense (recovery), net
of tax (a) 65 126 (145) 261 (38)
Unrealized risk
management loss (gain),
net of tax (b) 224 217 (1,435) 1,437 (2,112)
Unrealized foreign
exchange (gain) loss, net
of tax (c) (77) (343) 507 (570) 698
Effect of statutory tax
rate and other
legislative changes on
future income
tax liabilities (d) - - - (19) (41)
----------------------------------------------------------------------------
Adjusted net earnings
from operations $ 667 $ 658 $ 697 $ 2,689 $ 3,492
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) The Company's employee stock option plan provides for a cash payment
option. Accordingly, the intrinsic value of the outstanding vested
options is recorded as a liability on the Company's balance sheet and
periodic changes in the intrinsic value are recognized in net earnings
or are capitalized to Oil Sands Mining and Upgrading construction costs.
(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 or 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 or enacted.
Income tax rate changes in the first quarter of 2009 resulted in a
reduction of future income tax liabilities of approximately $19 million
in North America. 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 $22 million in Cote
d'Ivoire, Offshore West Africa.
Cash Flow from Operations
Three Months Ended Year Ended
---------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Net earnings $ 455 $ 658 $ 1,770 $ 1,580 $ 4,985
Non-cash items:
Depletion, depreciation
and amortization 836 673 666 2,819 2,683
Asset retirement
obligation accretion 23 24 19 90 71
Stock-based compensation
expense (recovery) 87 172 (203) 355 (52)
Unrealized risk
management loss (gain) 308 274 (2,107) 1,991 (3,090)
Unrealized foreign
exchange (gain) loss (88) (391) 613 (661) 832
Deferred petroleum
revenue tax expense
(recovery) 7 13 (5) 15 (67)
Future income tax
expense (recovery) 75 83 817 (99) 1,607
----------------------------------------------------------------------------
Cash flow from
operations $ 1,703 $ 1,506 $ 1,570 $ 6,090 $ 6,969
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the year ended December 31, 2009 were $1,580
million compared to $4,985 million for the year ended December 31,
2008. The 2009 operating results of the Company were significantly
impacted by lower benchmark crude oil and natural gas pricing,
partially offset by the impact of the commencement of production
from Horizon. Net earnings for the year ended December 31, 2009
included net unrealized after-tax expenses of $1,109 million
related to the effects of risk management activities, fluctuations
in foreign exchange rates and stock-based compensation, and the
impact of statutory tax rate changes on future income tax
liabilities, compared to net unrealized after-tax income of $1,493
million for the year ended December 31, 2008. Excluding these
items, adjusted net earnings from operations for the year ended
December 31, 2009 were $2,689 million compared to $3,492 million
for the year ended December 31, 2008. The decrease in adjusted net
earnings from the year ended December 31, 2008 was primarily due to
the impact of lower realized pricing, lower natural gas sales
volumes, higher production expenses, higher depletion,
depreciation, and amortization expense, including the impact of a
ceiling test impairment in Gabon, Offshore West Africa, higher
accretion expense, higher interest expense, and the impact of
realized foreign exchange loss, partially offset by the impact of
higher crude oil sales volumes, lower royalty expense, realized
risk management activities and the weaker Canadian dollar relative
to the US dollar.
Net earnings for the fourth quarter of 2009 were $455 million
compared to net earnings of $1,770 million for the fourth quarter
of 2008 and $658 million for the prior quarter. Net earnings for
the fourth quarter of 2009 included net unrealized after-tax
expenses of $212 million related to the effects of risk management
activities, and fluctuations in foreign exchange rates and
stock-based compensation, compared to net unrealized after-tax
income of $1,073 million for the fourth quarter of 2008. The
decrease in adjusted net earnings from the fourth quarter of 2008
was primarily due to the impact of lower natural gas sales volumes,
higher royalty and production expenses, higher depletion,
depreciation, and amortization expense, including the impact of a
ceiling test impairment in Gabon, Offshore West Africa, higher
interest expense, lower realized risk management gains, the impact
of realized foreign exchange loss, and the stronger Canadian dollar
relative to the US dollar partially offset by the impact of higher
realized pricing, and higher crude oil sales volumes. The increase
in adjusted net earnings from the prior quarter was primarily due
to the impact of higher crude oil sales volumes related to Horizon
and higher realized crude oil pricing offset by the impact of lower
natural gas sales volumes, lower realized risk management gains,
higher royalty expense, higher depletion, depreciation, and
amortization expense, and the impact of realized foreign exchange
loss and the stronger Canadian dollar relative to the US
dollar.
The impacts of unrealized risk management activities,
stock-based compensation, and changes in foreign exchange rates are
expected to continue to contribute to significant quarterly
volatility in consolidated net earnings and are discussed in detail
in the relevant sections of this MD&A.
Cash flow from operations for the year ended December 31, 2009
was $6,090 million compared to $6,969 million for the year ended
December 31, 2008. Cash flow from operations for the fourth quarter
of 2009 was $1,703 million compared to $1,570 million for the
fourth quarter of 2008 and $1,506 million for the prior quarter.
The decrease in cash flow from operations from the year ended 2008
was primarily due to the impact of lower realized pricing, lower
natural gas sales volumes, higher production expense, higher
interest expense, and the impact of realized foreign exchange,
partially offset by the impact of higher crude oil sales volumes,
realized risk management gains, lower royalty expense, lower
current income tax and Production Revenue Tax ("PRT") expense, and
the impact of the weaker Canadian dollar relative to the US dollar.
The increase in cash flow from operations from the fourth quarter
of 2008 was primarily due to the impact of higher crude oil sales
volumes and higher realized crude oil pricing, partially offset by
the impact of lower natural gas sales volumes, lower realized
natural gas pricing, lower realized risk management gains, higher
royalty and production expense, the impact of realized foreign
exchange losses and the stronger Canadian dollar relative to the US
dollar. The increase in cash flow from operations from the prior
quarter was primarily due to the impact of higher realized pricing,
partially offset by the impact of lower natural gas sales volumes,
lower realized risk management gains, the impact of realized
foreign exchange loss and the stronger Canadian dollar relative to
the US dollar.
During 2009, the Company achieved first production of synthetic
crude oil ("SCO") at Horizon in connection with the commencement of
operations. The Company continues to focus on stabilizing and
ramping up production as the plant is fine-tuned with a focus on
safety, reliability, and cost control. The results of operations
for Horizon are included in the "Oil Sands Mining and Upgrading"
segment.
Total production before royalties for the year ended December
31, 2009 increased 2% to 574,730 boe/d from 564,845 boe/d for the
year ended December 31, 2008. Total production before royalties for
the fourth quarter of 2009 increased 5% to 574,857 boe/d from
547,399 boe/d for the fourth quarter of 2008 and was comparable
with the prior quarter. Total production for the fourth quarter of
2009 was within 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 Dec 31 Sep 30 Jun 30 Mar 31
amounts) 2009 2009 2009 2009
----------------------------------------------------------------------------
Revenue, before royalties $ 3,319 $ 2,823 $ 2,750 $ 2,186
Net earnings $ 455 $ 658 $ 162 $ 305
Net earnings per common share
- Basic and diluted $ 0.85 $ 1.21 $ 0.30 $ 0.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common share Dec 31 Sep 30 Jun 30 Mar 31
amounts) 2008 2008 2008 2008
----------------------------------------------------------------------------
Revenue, before royalties $ 2,511 $ 4,583 $ 5,112 $ 3,967
Net earnings (loss) $ 1,770 $ 2,835 $ (347) $ 727
Net earnings (loss) per common share
- Basic and diluted $ 3.27 $ 5.25 $ (0.65) $ 1.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volatility in quarterly net earnings (loss) over the eight most
recently completed quarters was primarily due to:
- Crude oil pricing - The impact of fluctuating demand and
geopolitical uncertainties on worldwide benchmark pricing, and the
fluctuations in the Heavy Crude Oil Differential from WTI ("Heavy
Differential") in North America.
- Natural gas pricing - The impact of seasonal fluctuations in
both the demand for natural gas and inventory storage levels, and
the impact of increased shale gas production in the US, as well as
fluctuations in imports of liquefied natural gas into the US.
- Crude oil and NGLs sales volumes - Fluctuations in production
from the Company's Primrose thermal projects, the results from the
Pelican Lake water and polymer flood projects, and the commencement
of operations at Horizon. Sales volumes also reflected fluctuations
due to timing of liftings and maintenance activities in the North
Sea and Offshore West Africa and the impact of the shut in, and
subsequent restoration, of some of the production in the Baobab
Field.
- Natural gas sales volumes - Production declines due to the
Company's strategic decision to reduce natural gas drilling
activity in North America and the allocation of capital to higher
return crude oil projects, as well as natural decline rates.
- Production expense - Fluctuations primarily due to the impact
of the demand for services, industry-wide inflationary cost
pressures experienced in prior quarters, fluctuations in product
mix, the impact of seasonal costs that are dependent on weather,
and the commencement of operations at Horizon and the Olowi Field
in Offshore Gabon.
- Depletion, depreciation and amortization - Fluctuations 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, the
commencement of operations at Horizon and the Olowi Field in
Offshore Gabon, and the impact of a ceiling test impairment at the
Olowi Field at December 31, 2009.
- Stock-based compensation - Fluctuations 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.
- Risk management - Fluctuations due to the recognition of
realized and unrealized gains and losses from the mark-to-market
and subsequent settlement of the Company's risk management
activities.
- Foreign exchange rates - Fluctuations in the Canadian dollar
relative to the US dollar impacted the realized price the Company
received for its crude oil and natural gas sales, as sales prices
are based predominately on US dollar denominated benchmarks.
Similarly, unrealized foreign exchange gains and losses were
recorded with respect to US dollar denominated debt 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 swap hedges.
- Income tax expense (recovery) - Fluctuations in income tax
expense (recovery) include statutory tax rate and other legislative
changes substantively enacted or enacted in the various
periods.
BUSINESS ENVIRONMENT
Three Months Ended Year Ended
-------------------------------------------------
(Quarterly and Yearly Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
Average) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
WTI benchmark price
(US$/bbl) $ 76.17 $ 68.29 $ 58.75 $ 61.93 $ 99.65
Dated Brent benchmark
price (US$/bbl) $ 74.54 $ 68.28 $ 54.93 $ 61.61 $ 96.99
WCS blend differential
from WTI (US$/bbl) $ 12.08 $ 10.06 $ 19.13 $ 9.64 $ 20.03
WCS blend differential
from WTI (%) 16% 15% 33% 16% 20%
SCO price (US$/bbl) $ 75.07 $ 67.20 $ 58.64 $ 61.51 $ 102.48
Condensate benchmark price
(US$/bbl) $ 74.46 $ 65.80 $ 59.01 $ 60.60 $ 100.10
NYMEX benchmark price
(US$/mmbtu) $ 4.27 $ 3.42 $ 6.82 $ 4.03 $ 8.95
AECO benchmark price
(C$/GJ) $ 4.01 $ 2.87 $ 6.43 $ 3.91 $ 7.71
US / Canadian dollar
average exchange rate $ 0.9468 $ 0.9108 $ 0.8252 $ 0.8760 $ 0.9381
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$61.93 per
bbl for the year ended December 31, 2009, a decrease of 38% from
US$99.65 per bbl for the year ended December 31, 2008. WTI averaged
US$76.17 per bbl for the fourth quarter of 2009, an increase of 30%
from US$58.75 per bbl for the fourth quarter of 2008, and an
increase of 12% from US$68.29 per bbl for the prior quarter. WTI
pricing was impacted by strong Asian demand, partially offset by
declines in the European and North American markets due to weak
economic activity.
Crude oil sales contracts for the Company's North Sea and
Offshore West Africa segments are typically based on Dated Brent
("Brent") pricing, which is more reflective of international
markets and the overall supply and demand balance. Brent averaged
US$61.61 per bbl for the year ended December 31, 2009, a decrease
of 36% compared to US$96.99 per bbl for the year ended December 31,
2008. Brent averaged US$74.54 per bbl for the fourth quarter of
2009, an increase of 36% compared to US$54.93 per bbl for the
fourth quarter of 2008, and an increase of 9% from US$68.28 per bbl
for the prior quarter.
The Heavy Differential averaged 16% for the year ended December
31, 2009 compared to 20% for the year ended December 31, 2008. The
Heavy Differential averaged 16% for the fourth quarter of 2009,
compared to 33% for the fourth quarter of 2008 and 15% for the
prior quarter. The narrow Heavy Differential continued to reflect
the relatively weak refinery margins.
The Company anticipates continued volatility in crude oil
pricing benchmarks due to the unpredictable nature of supply and
demand factors, geopolitical events and the timing and extent of
recovery of the global economy. The Heavy Differential is expected
to continue to reflect seasonal demand fluctuations and refinery
margins.
NYMEX natural gas prices averaged US$4.03 per mmbtu for the year
ended December 31, 2009, a decrease of 55% from US$8.95 per mmbtu
for the year ended December 31, 2008. NYMEX natural gas prices
averaged US$4.27 per mmbtu for the fourth quarter of 2009, a
decrease of 37% from US$6.82 per mmbtu for the fourth quarter of
2008, and an increase of 25% from US$3.42 per mmbtu for the prior
quarter. AECO natural gas prices for the year ended December 31,
2009 decreased 49% to average $3.91 per GJ from $7.71 per GJ for
the year ended December 31, 2008. AECO natural gas prices for the
fourth quarter of 2009 decreased 38% to average $4.01 per GJ from
$6.43 per GJ in the fourth quarter of 2008, and increased 40% from
$2.87 per GJ for the prior quarter. Decreases in natural gas prices
from the comparable periods in the prior year were primarily
related to record storage levels in North America due to an
oversupply in the market. Natural gas pricing in the fourth quarter
improved due to seasonal demands and production shut ins by
producers.
Update to Alberta Royalty Framework
Effective January 1, 2009, changes to the Alberta royalty regime
under the Alberta Royalty Framework ("ARF") include the
implementation of a sliding scale for oil sands royalties ranging
from 1% to 9% on a gross revenue basis pre-payout and 25% to 40% on
a net revenue basis post-payout, depending on benchmark crude oil
pricing.
In addition, effective January 1, 2009, new royalty formulas
under the ARF for conventional crude oil and natural gas operate on
sliding scales ranging up to 50%, determined by commodity prices
and well productivity.
In March 2009, the Government of Alberta announced new incentive
programs to stimulate activity in Alberta. These programs provide
for:
- A royalty credit of $200 per meter on new conventional crude
oil and natural gas wells drilled between April 1, 2009 and March
31, 2010, to a maximum of 10% of conventional Crown royalties paid
in Alberta.
- Reduced royalty rates that set the maximum royalty at 5% for
the first 12 months of production, up to a maximum of 50,000 boe or
500 mmcfe, for new conventional crude oil and natural gas wells
that commence production between April 1, 2009 and March 31,
2010.
In June 2009, the Government of Alberta extended the two
incentive programs described above by one year, to
March 31, 2011.
Province of British Columbia Oil and Gas Stimulus Package
Effective September 1, 2009, the Province of British Columbia
announced an oil and gas stimulus package that includes:
- A one-year, 2% royalty rate for all natural gas wells drilled
between September 1, 2009 and June 30, 2010. Qualifying wells must
commence production before December 31, 2010.
- A permanent increase of 15% in the existing royalty holiday
credits for the Deep Royalty Program.
- Permanent qualification of horizontal wells drilled to a
vertical depth between 1,900 and 2,300 meters into the Deep Royalty
Program.
- An additional $50 million allocation for the Infrastructure
Royalty Credit Program to stimulate investment in oil and gas roads
and pipelines.
DAILY PRODUCTION, before royalties
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
Conventional 229,206 223,307 240,831 234,523 243,826
North America - Oil Sands
Mining and Upgrading 70,194 66,907 - 50,250 -
North Sea 34,408 34,034 42,991 37,761 45,274
Offshore West Africa 32,643 35,021 25,748 32,929 26,567
----------------------------------------------------------------------------
366,451 359,269 309,570 355,463 315,667
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,218 1,264 1,405 1,287 1,472
North Sea 12 8 10 10 10
Offshore West Africa 20 21 12 18 13
----------------------------------------------------------------------------
1,250 1,293 1,427 1,315 1,495
----------------------------------------------------------------------------
Total barrels of oil
equivalent (boe/d) 574,857 574,755 547,399 574,730 564,845
----------------------------------------------------------------------------
Product mix
Light/medium crude oil and
NGLs 20% 20% 22% 21% 22%
Pelican Lake crude oil 7% 6% 7% 6% 6%
Primary heavy crude oil 15% 15% 16% 15% 16%
Thermal heavy crude oil 10% 9% 12% 11% 12%
Synthetic crude oil 12% 12% - 9% -
Natural gas 36% 38% 43% 38% 44%
----------------------------------------------------------------------------
Percentage of gross revenue(1)
(excluding midstream revenue)
Crude oil and NGLs 78% 79% 60% 75% 68%
Natural gas 22% 21% 40% 25% 32%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation and blending costs and excluding risk management
activities.
DAILY PRODUCTION, net of royalties
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
Conventional 195,070 191,077 210,496 201,873 207,933
North America - Oil Sands
Mining and Upgrading 67,806 64,814 - 48,833 -
North Sea 34,341 33,961 42,910 37,683 45,182
Offshore West Africa 30,296 30,551 23,907 29,922 22,641
----------------------------------------------------------------------------
327,513 320,403 277,313 318,311 275,756
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,135 1,228 1,198 1,214 1,225
North Sea 12 8 10 10 10
Offshore West Africa 19 18 10 17 11
----------------------------------------------------------------------------
1,166 1,254 1,218 1,241 1,246
----------------------------------------------------------------------------
Total barrels of oil
equivalent (boe/d) 521,894 529,421 480,409 525,103 483,541
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, thermal
heavy crude oil, and SCO.
Total crude oil and NGLs production for the year ended December
31, 2009 increased 13% to 355,463 bbl/d from 315,667 bbl/d for the
year ended December 31, 2008. The increase from the comparable
period was primarily due to the commencement of production from
Horizon and the Olowi Field in Offshore Gabon and the restoration
of some of the production in the Baobab Field, in Offshore Cote
D'Ivoire.
Total crude oil and NGLs production for the fourth quarter of
2009 increased 18% to 366,451 bbl/d from 309,570 bbl/d for the
fourth quarter of 2008, and 2% from 359,269 bbl/d for the prior
quarter. The increase from the fourth quarter in 2008 was primarily
due to production from Horizon and the Olowi Field in Offshore
Gabon. The increase from the prior quarter was in line with
expectations and primarily due to the cyclic nature of the
Company's thermal production and the timing of planned maintenance
activities in the North Sea. Crude oil and NGLs production in the
fourth quarter of 2009 was within the Company's previously issued
guidance of 359,000 to 390,000 bbl/d.
Natural gas production continued to represent the Company's
largest product offering for the year ended December 31, 2009,
accounting for 38% of the Company's total production. Natural gas
production for the year ended December 31, 2009 decreased 12% to
1,315 mmcf/d compared to 1,495 mmcf/d for the year ended December
31, 2008. Natural gas production for the fourth quarter of 2009
decreased 12% to 1,250 mmcf/d compared to 1,427 mmcf/d for the
fourth quarter of 2008 and 3% from 1,293 mmcf/d for the prior
quarter. The decrease in natural gas production from the comparable
periods reflects the expected production declines due to the
Company's strategic reduction in natural gas drilling activity.
Natural gas production in the fourth quarter of 2009 exceeded the
Company's previously issued guidance of 1,213 to 1,243 mmcf/d.
For 2010, annual production guidance is targeted to average
between 400,000 and 445,000 bbl/d of crude oil and NGLs and between
1,117 and 1,185 mmcf/d of natural gas. First quarter 2010
production guidance is targeted to average between 372,000 and
409,000 bbl/d of crude oil and NGLs and between 1,197 and 1,221
mmcf/d of natural gas.
North America - Conventional
North America conventional crude oil and NGLs production for the
year ended December 31, 2009 decreased 4% to average 234,523 bbl/d
from 243,826 bbl/d for the year ended December 31, 2008. Fourth
quarter North America conventional crude oil and NGLs production
decreased 5% to average 229,206 bbl/d from 240,831 bbl/d for the
fourth quarter of 2008, and increased 3% from 223,307 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 and was in line with expectations.
Production of conventional crude oil and NGLs was within the
Company's previously issued guidance of 225,000 bbl/d to 235,000
bbl/d for the fourth quarter of 2009.
Natural gas production for the year ended December 31, 2009
decreased 13% to 1,287 mmcf/d from 1,472 mmcf/d for the year ended
December 31, 2008. For the fourth quarter of 2009, natural gas
production decreased 13% to 1,218 mmcf/d from 1,405 mmcf/d for the
fourth quarter of 2008, and decreased 4% from 1,264 mmcf/d for the
prior quarter. The decreases in natural gas production were
consistent with the Company's strategic decision to reduce natural
gas drilling activity. Production of natural gas exceeded the
Company's previously issued guidance of 1,185 mmcf/d to 1,210
mmcf/d for the fourth quarter of 2009.
North America - Oil Sands Mining and Upgrading
Horizon Phase 1 achieved first production of synthetic crude oil
during 2009. Production averaged 50,250 bbl/d for the year ended
December 31, 2009 and 70,194 bbl/d in the fourth quarter of 2009,
up 5% from 66,907 bbl/d in the prior quarter. Production volumes
fluctuated throughout the quarter as the Company continued to
stabilize and ramp up production. During December 2009, production
was impacted by an equipment failure in the hydrogen plant,
requiring the shutdown for an extended period of time, and issues
with one of the coker furnaces. As a consequence, fourth quarter
production was at the low end of the Company's previously issued
guidance of 70,000 bbl/d to 85,000 bbl/d for the fourth quarter of
2009. The Company has been able to resolve the impact of high clay
content much sooner than anticipated by blending the ore from three
benches.
North Sea
North Sea crude oil production for the year ended December 31,
2009 decreased 17% to 37,761 bbl/d from 45,274 bbl/d for the year
ended December 31, 2008. Fourth quarter North Sea crude oil
production decreased 20% to 34,408 bbl/d from 42,991 bbl/d for the
fourth quarter of 2008 and was comparable to the prior quarter.
Production in the fourth quarter of 2009 was at the low end of the
Company's previously issued guidance due to delays in restoring
certain production after the completion of maintenance
activities.
Offshore West Africa
Offshore West Africa crude oil production increased 24% to
32,929 bbl/d for the year ended December 31, 2009 from 26,567 bbl/d
for the year ended December 31, 2008. Fourth quarter Offshore West
Africa crude oil production increased 27% to 32,643 bbl/d from
25,748 bbl/d for the fourth quarter of 2008, and decreased 7% from
35,021 bbl/d for the prior quarter. Production in the fourth
quarter was at the high end of the Company's previously issued
guidance as a result of strong production performance from the
Baobab Field.
Production volumes from the first platform at the Olowi Field
continue to be below expectations and, as a result, the Company
recognized a ceiling test impairment of $115 million at December
31, 2009. Drilling results and production data is being reviewed in
order to develop appropriate remediation strategies and determine
the impact on future production from the Field, the impact on
recoverable reserves and the scope of the overall development plan.
The Company continues drilling at the next scheduled platform with
production targeted for second quarter of 2010.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when
title transfers to the customer and delivery has taken place.
Revenue has not been recognized on crude oil volumes that were
stored in various tanks, pipelines, or floating production, storage
and offtake vessels, as follows:
-----------------------------------------
Dec 31 Sep 30 Dec 31
(bbl) 2009 2009 2008
----------------------------------------------------------------------------
North America - Conventional 1,131,372 761,351 761,351
North America - Oil Sands Mining
and Upgrading (SCO) 1,224,481 1,035,573 -
North Sea 713,112 1,200,129 558,904
Offshore West Africa(1) 51,103 1,127,028 1,113,156
----------------------------------------------------------------------------
3,120,068 4,124,081 2,433,411
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Prior period inventory volumes include one-time adjustments to sales
volumes for MD&A reporting purposes only.
OPERATING HIGHLIGHTS - CONVENTIONAL
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
Sales price (2) $ 68.00 $ 62.90 $ 45.81 $ 57.68 $ 82.41
Royalties 7.96 7.89 4.49 6.73 10.48
Production expense 15.45 16.71 16.33 15.92 16.26
----------------------------------------------------------------------------
Netback $ 44.59 $ 38.30 $ 24.99 $ 35.03 $ 55.67
----------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 4.75 $ 3.80 $ 7.03 $ 4.53 $ 8.39
Royalties (3) 0.35 0.13 1.08 0.32 1.46
Production expense 1.03 1.05 1.06 1.08 1.02
----------------------------------------------------------------------------
Netback $ 3.37 $ 2.62 $ 4.89 $ 3.13 $ 5.91
----------------------------------------------------------------------------
Barrels of oil equivalent
($/boe) (1)
Sales price (2) $ 51.95 $ 45.52 $ 43.84 $ 44.87 $ 68.62
Royalties 5.60 4.85 5.37 4.72 9.78
Production expense 11.72 12.26 12.05 11.98 11.79
----------------------------------------------------------------------------
Netback $ 34.63 $ 28.41 $ 26.42 $ 28.17 $ 47.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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) Natural gas royalties for 2009 reflect the impact of natural gas
physical sales contracts.
PRODUCT PRICES - CONVENTIONAL
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)(2)
North America $ 65.12 $ 60.07 $ 40.39 $ 54.70 $ 77.42
North Sea $ 78.89 $ 75.91 $ 63.07 $ 68.84 $ 100.31
Offshore West Africa $ 72.88 $ 70.05 $ 65.80 $ 65.27 $ 97.96
Company average $ 68.00 $ 62.90 $ 45.81 $ 57.68 $ 82.41
Natural gas ($/mcf) (1)(2)
North America $ 4.75 $ 3.76 $ 7.00 $ 4.51 $ 8.41
North Sea $ 4.94 $ 5.70 $ 5.19 $ 4.66 $ 4.09
Offshore West Africa $ 5.04 $ 5.72 $ 12.54 $ 6.11 $ 10.03
Company average $ 4.75 $ 3.80 $ 7.03 $ 4.53 $ 8.39
Company average ($/boe)
(1)(2) $ 51.95 $ 45.52 $ 43.84 $ 44.87 $ 68.62
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North America
North America realized crude oil prices decreased 29% to average
$54.70 per bbl for the year ended December 31, 2009 from $77.42 per
bbl for the year ended December 31, 2008. Realized crude oil prices
increased 61% to average $65.12 per bbl for the fourth quarter of
2009 from $40.39 per bbl for the fourth quarter of 2008, and
increased 8% from $60.07 per bbl for the prior quarter. The
decrease from the year ended 2008 was primarily a result of
decreased WTI benchmark pricing, partially offset by the impact of
the narrowing of the Heavy Differential and the weaker Canadian
dollar relative to the US dollar. The increase from the prior
quarter and the fourth quarter of 2008 was primarily the result of
increased WTI benchmark pricing, partially offset by the impact of
the stronger Canadian dollar relative to the US dollar.
The Company continues to focus on its crude oil marketing
strategy, and in the fourth quarter of 2009 contributed
approximately 140,000 bbl/d of heavy crude oil blends to the
Western Canadian Select stream.
In the first quarter of 2010, Canadian Natural announced,
together with North West Upgrading Inc., the submission of a joint
proposal to the Alberta Government to construct and operate a
bitumen refinery near Redwater, Alberta. This proposal was
submitted in response to a request for proposal under the Alberta
Royalty Framework's Bitumen Royalty In Kind (BRIK) program.
North America realized natural gas prices decreased 46% to
average $4.51 per mcf for the year ended December 31, 2009 from
$8.41 per mcf for the year ended December 31, 2008. Realized
natural gas prices decreased 32% to average $4.75 per mcf for the
fourth quarter of 2009 from $7.00 per mcf for the fourth quarter of
2008, and increased 26% from $3.76 per mcf for the prior quarter.
The decrease in natural gas prices from the comparable periods of
2008 was primarily related to lower benchmark prices due to lower
demand and high storage levels in 2009. The increase in natural gas
prices from the prior quarter was primarily related to seasonality
of demand.
Comparisons of the prices received for the Company's North America
conventional production by product type were as follows:
----------------------------------------
Dec 31 Sep 30 Dec 31
(Quarterly Average) 2009 2009 2008
----------------------------------------------------------------------------
Wellhead Price (1) (2)
Light/medium crude oil and NGLs
($/bbl) (3) $ 67.30 $ 59.24 $ 46.58
Pelican Lake crude oil ($/bbl) $ 63.75 $ 61.11 $ 40.91
Primary heavy crude oil ($/bbl) $ 65.46 $ 60.42 $ 37.85
Thermal heavy crude oil ($/bbl) $ 63.62 $ 59.52 $ 38.68
Natural gas ($/mcf) $ 4.75 $ 3.76 $ 7.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
(3) Light/medium crude oil and NGLs wellhead pricing for the third quarter
of 2009 reflected the impact of significant price discounts for certain
types of NGLs, including propane and butane.
North Sea
North Sea realized crude oil prices decreased 31% to average
$68.84 per bbl for the year ended December 31, 2009 from $100.31
per bbl for the year ended December 31, 2008. Realized crude oil
prices increased 25% to average $78.89 per bbl for the fourth
quarter of 2009 from $63.07 per bbl for the fourth quarter of 2008,
and increased 4% from $75.91 per bbl for the prior quarter. The
decrease in realized crude oil prices in the North Sea from the
year ended 2008 was primarily the result of lower Brent benchmark
pricing, partially offset by the impact of the weaker Canadian
dollar. The increase from the prior quarter and the fourth quarter
2008 was primarily the result of increased Brent benchmark pricing,
partially offset by the impact of the stronger Canadian dollar.
Offshore West Africa
Offshore West Africa realized crude oil prices decreased 33% to
average $65.27 per bbl for the year ended December 31, 2009 from
$97.96 per bbl for the year ended December 31, 2008. Realized crude
oil prices increased 11% to average $72.88 per bbl for the fourth
quarter of 2009 from $65.80 per bbl for the fourth quarter of 2008,
and increased 4% from $70.05 per bbl for the prior quarter. The
decrease in realized crude oil prices in Offshore West Africa from
the year ended 2008 was primarily the result of lower Brent
benchmark pricing, partially offset by the impact of the weaker
Canadian dollar. The increase from the prior quarter and the fourth
quarter of 2008 was primarily the result of increased Brent
benchmark pricing, partially offset by the impact of the stronger
Canadian dollar. Realized crude oil prices in Offshore West Africa
were also impacted by the timing of liftings from each field.
ROYALTIES - CONVENTIONAL
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)(1)
North America $ 9.88 $ 8.80 $ 5.25 $ 7.93 $ 11.99
North Sea $ 0.15 $ 0.16 $ 0.12 $ 0.14 $ 0.21
Offshore West Africa $ 5.24 $ 8.94 $ 4.71 $ 5.79 $ 14.81
Company average $ 7.96 $ 7.89 $ 4.49 $ 6.73 $ 10.48
Natural gas ($/mcf) (1)
North America (2) $ 0.35 $ 0.12 $ 1.09 $ 0.32 $ 1.47
Offshore West Africa $ 0.27 $ 0.74 $ 1.26 $ 0.53 $ 1.52
Company average $ 0.35 $ 0.13 $ 1.08 $ 0.32 $ 1.46
Company average ($/boe)(1) $ 5.60 $ 4.85 $ 5.37 $ 4.72 $ 9.78
Percentage of revenue (3)
Crude oil and NGLs 12% 13% 10% 12% 13%
Natural gas (2) 7% 3% 15% 7% 17%
Boe 11% 11% 12% 11% 14%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Natural gas royalties for 2009 reflect the impact of natural gas
physical sales contracts.
(3) Net of transportation and blending costs and excluding risk management
activities.
North America
North America royalties for the year ended December 31, 2009
compared to 2008 reflect weaker realized commodity prices and the
impact of the change in the ARF.
Crude oil and NGLs royalties averaged approximately 15% of
revenues for the fourth quarter of 2009, compared to 13% for the
fourth quarter in 2008 and were consistent with the prior quarter.
Crude oil and NGLs royalties per bbl are anticipated to average 17%
to 19% of gross revenue for 2010.
Natural gas royalties averaged approximately 7% of revenues for
the fourth quarter of 2009 compared to 16% for the fourth quarter
of 2008 and 3% for the prior quarter. The decrease in natural gas
royalty rates for the fourth quarter of 2009 compared to the prior
year was due to the impact of low natural gas benchmark pricing.
Natural gas royalties are anticipated to average 11% to 13% of
gross revenue for 2010.
Offshore West Africa
Under the terms of the Production Sharing Contracts, royalty
rates fluctuate based on realized commodity pricing, capital costs,
and the timing of liftings from each field. Royalty rates as a
percentage of revenue averaged approximately 7% for the fourth
quarter of 2009 and 2008 and 13% for the prior quarter. Offshore
West Africa royalty rates are anticipated to average 7% to 9% of
gross revenue for 2010.
PRODUCTION EXPENSE - CONVENTIONAL
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)(1)
North America $ 13.44 $ 15.19 $ 14.31 $ 14.63 $ 14.96
North Sea $ 27.03 $ 31.30 $ 28.77 $ 26.98 $ 26.29
Offshore West Africa $ 15.26 $ 13.35 $ 14.47 $ 12.83 $ 10.29
Company average $ 15.45 $ 16.71 $ 16.33 $ 15.92 $ 16.26
Natural gas ($/mcf) (1)
North America $ 1.01 $ 1.04 $ 1.04 $ 1.07 $ 1.00
North Sea $ 3.23 $ 1.57 $ 1.96 $ 2.16 $ 2.51
Offshore West Africa $ 0.70 $ 1.37 $ 2.51 $ 1.23 $ 1.61
Company average $ 1.03 $ 1.05 $ 1.06 $ 1.08 $ 1.02
Company average ($/boe)(1) $ 11.72 $ 12.26 $ 12.05 $ 11.98 $ 11.79
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America
North America crude oil and NGLs production expense for the year
ended December 31, 2009 decreased 2% to $14.63 per bbl from $14.96
per bbl for the year ended December 31, 2008. Production expense
for the fourth quarter of 2009 decreased 6% to $13.44 per bbl from
$14.31 per bbl for the fourth quarter of 2008 and 12% from $15.19
per bbl for the prior quarter. The decrease in production expense
per barrel for the fourth quarter of 2009 was a result of the
Company's focus on optimizing service costs, together with lower
power prices and cost of natural gas used for fuel. North America
crude oil and NGLs production expense is anticipated to average
$13.00 to $14.00 per bbl for 2010.
North America natural gas production expense for the year ended
December 31, 2009 increased 7% to $1.07 per mcf from $1.00 per mcf
for the year ended December 31, 2008. Production expense for the
fourth quarter of 2009 decreased 3% to $1.01 per mcf from $1.04 per
mcf for the fourth quarter of 2008 and the prior quarter. The
increase in production expense per mcf from the prior year was
primarily a result of lower production volumes on fixed costs. The
decrease in production expense from the comparable quarters was due
to the Company's focus on optimizing service costs and lower power
prices. North America natural gas production expense is anticipated
to average $1.15 to $1.25 per mcf for 2010.
North Sea
North Sea crude oil production expense increased on a per barrel
basis from the prior year due to lower production volumes on a
relatively fixed operating cost base. North Sea crude oil
production expense decreased on a per barrel basis from the prior
quarter due to the timing of maintenance activities and liftings of
each field. Production expense for the year ended December 31, 2009
was below the Company's previously issued guidance and reflected
the Company's ongoing focus on lowering costs. Production expense
is anticipated to average $31.00 to $35.00 per bbl for 2010.
Offshore West Africa
Offshore West Africa crude oil production expense increased from
the prior year and prior quarters on a per barrel basis due to the
timing of liftings of each field and as a result of higher
operating costs associated with Gabon. Production expense for the
year ended December 31 2009 was in line with the Company's
previously issued guidance. Production expense is anticipated to
average $14.00 to $17.00 per bbl for 2010.
DEPLETION, DEPRECIATION AND AMORTIZATION - CONVENTIONAL
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Expense ($ millions) $ 754 $ 610 $ 674 $ 2,656 $ 2,685
$/boe (1) $ 15.68 $ 12.64 $ 13.20 $ 13.82 $ 12.97
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
The increase in Conventional Depletion, Depreciation and Amortization
expense from the previous periods was primarily due to the impact of a
ceiling test impairment related to Gabon, Offshore West Africa.
ASSET RETIREMENT OBLIGATION ACCRETION - CONVENTIONAL
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Expense ($ millions) $ 17 $ 17 $ 19 $ 69 $ 71
$/boe (1) $ 0.36 $ 0.36 $ 0.38 $ 0.36 $ 0.34
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
OPERATING HIGHLIGHTS - OIL SANDS MINING AND UPGRADING
FINANCIAL METRICS
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($/bbl) (1) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
SCO sales price (2) $ 76.33 $ 69.11 $ - $ 70.83 $ -
Bitumen value for royalty
purposes $ 58.90 $ 56.79 $ - $ 56.57 $ -
Bitumen royalties (3) $ 3.06 $ 2.19 $ - $ 2.15 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and excluding risk management activities.
(3) Calculated based on actual bitumen royalties expensed during the period;
divided by the corresponding SCO sales volumes.
The increase in SCO price from the previous quarter was due to
the increase in WTI price. There is an active market for SCO and it
has been well received by refiners. The marketing strategy
continues to remain flexible.
PRODUCTION COSTS
The following tables provide reconciliations of Oil Sands Mining
and Upgrading production costs to the Segmented Information
disclosed in note 13 to the Company's unaudited interim
consolidated financial statements.
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash costs, excluding
natural gas costs $ 228 $ 212 $ - $ 599 $ -
Natural gas costs 31 30 - 84 -
----------------------------------------------------------------------------
Total cash production
costs $ 259 $ 242 $ - $ 683 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($/bbl) (1) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash costs, excluding
natural gas costs $ 36.23 $ 32.36 $ - $ 34.97 $ -
Natural gas costs 4.98 4.49 - 4.92 -
----------------------------------------------------------------------------
Total cash production
costs $ 41.21 $ 36.85 $ - $ 39.89 $ -
----------------------------------------------------------------------------
Sales (bbl/d) 68,140 71,578 - 46,896 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
First sales from Horizon occurred in the second quarter of
2009.
Total cash production costs averaged $41.21 per bbl in the
fourth quarter of 2009 compared to $36.85 per bbl for the third
quarter due to higher operating costs associated with winter
operations, together with higher maintenance costs relating to an
equipment failure in the hydrogen plant requiring the shutdown for
an extended period of time in December, and issues with one of the
coker furnaces. Oil Sands Mining and Upgrading production expense
is anticipated to average $31.00 to $37.00 per bbl for 2010.
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Depreciation, depletion
and amortization $ 83 $ 66 $ - $ 187 $ -
Asset retirement
obligation accretion 6 7 - 21 -
----------------------------------------------------------------------------
Total $ 89 $ 73 $ - $ 208 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($/bbl) (1) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Depreciation, depletion
and amortization $ 13.28 $ 9.99 $ - $ 10.95 $ -
Asset retirement
obligation accretion 1.00 0.95 - 1.22 -
----------------------------------------------------------------------------
Total $ 14.28 $ 10.94 $ - $ 12.17 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
During 2009, Horizon Phase 1 assets were completed and available
for their intended use. Accordingly, capitalization of all
associated Phase 1 development costs, including capitalized
interest and stock-based compensation, and all directly
attributable Phase 1 administrative costs has ceased, and
depletion, depreciation and amortization of these assets has
commenced. Depletion, depreciation and amortization per barrel
increased in the fourth quarter of 2009 compared to the prior
quarter due to the disposal of a portion of the tailings line pipe
related to premature wear.
MIDSTREAM
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue $ 18 $ 18 $ 17 $ 72 $ 77
Production expense 5 4 6 19 25
----------------------------------------------------------------------------
Midstream cash flow 13 14 11 53 52
Depreciation 3 2 2 9 8
----------------------------------------------------------------------------
Segment earnings before
taxes $ 10 $ 12 $ 9 $ 44 $ 44
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable periods.
ADMINISTRATION EXPENSE
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Expense ($ millions) $ 49 $ 38 $ 46 $ 181 $ 180
$/boe (1) $ 0.92 $ 0.72 $ 0.91 $ 0.87 $ 0.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the fourth quarter of 2009 increased
from the prior quarter due to higher staffing related costs.
Administration expense on a boe basis in 2009 includes sales
volumes associated with the commencement of Horizon.
STOCK-BASED COMPENSATION EXPENSE
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Expense (recovery) $ 87 $ 172 $ (203) $ 355 $ (52)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company recorded a $355 million ($261 million after-tax)
stock-based compensation expense for the year ended December 31,
2009 primarily as a result of normal course graded vesting of
options granted in prior periods, the impact of vested options
exercised or surrendered during the period, and the 56% increase in
the Company's share price, including an $87 million ($65 million
after-tax) stock-based compensation expense for the three months
ended December 31, 2009 (Company's share price as at: December 31,
2009 - $76.00; September 30, 2009 - $72.30; December 31, 2008 -
$48.75). For the year ended December 31, 2009, the Company
capitalized $2 million in stock-based compensation to Oil Sands
Mining and Upgrading (December 31, 2008 - $23 million recovery).
The stock-based compensation liability reflected the Company's
potential cash liability should all the vested options be
surrendered for a cash payout at the market price on December 31,
2009.
For the year ended December 31, 2009, the Company paid $94
million for stock options surrendered for cash settlement (December
31, 2008 - $207 million).
INTEREST EXPENSE
Three Months Ended Year Ended
-------------------------------------------------
($ millions, except per Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
boe amounts) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Expense, gross $ 119 $ 124 $ 158 $ 516 $ 609
Less: capitalized
interest, Oil Sands
Mining and Upgrading 8 6 135 106 481
----------------------------------------------------------------------------
Expense, net $ 111 $ 118 $ 23 $ 410 $ 128
$/boe (1) $ 2.06 $ 2.23 $ 0.45 $ 1.96 $ 0.62
Average effective interest
rate 4.5% 4.3% 5.0% 4.3% 5.1%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest expense decreased from the comparable periods in
2008 primarily due to lower variable interest rates and debt
repayments, and reflected the impact of fluctuations in foreign
exchange rates on US dollar denominated debt. The Company's average
effective interest rate decreased from the comparable periods in
2008 primarily due to lower variable interest rates.
During the first quarter of 2009, interest capitalization ceased
on Horizon Phase 1 as the Phase 1 assets were completed and
available for their intended use, increasing net 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 Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments $ (148) $ (235) $ (179) $ (1,330) $ 2,020
Natural gas financial
instruments - - - (33) (21)
Foreign currency contracts
and interest
rate swaps 26 35 (122) 110 (139)
----------------------------------------------------------------------------
Realized (gain) loss $ (122) $ (200) $ (301) $ (1,253) $ 1,860
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments $ 328 $ 208 $ (2,112) $ 2,039 $ (3,104)
Natural gas financial
instruments (17) (4) (13) (58) 16
Foreign currency contracts
and interest rate swaps (3) 70 18 10 (2)
----------------------------------------------------------------------------
Unrealized loss (gain) $ 308 $ 274 $ (2,107) $ 1,991 $ (3,090)
----------------------------------------------------------------------------
Net loss (gain) $ 186 $ 74 $ (2,408) $ 738 $ (1,230)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Complete details related to outstanding derivative financial
instruments at December 31, 2009 are disclosed in note 11 to the
Company's unaudited interim consolidated financial statements.
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 $1,991 million ($1,437
million after-tax) on its risk management activities for the year
ended December 31, 2009, including a $308 million ($224 million
after-tax) net unrealized loss for the fourth quarter of 2009
(September 30, 2009 - unrealized loss of $274 million, $217 million
after-tax; December 31, 2008 - unrealized gain of $2,107 million,
$1,435 million after-tax).
FOREIGN EXCHANGE
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Net realized loss (gain) $ 4 $ (33) $ (51) $ 30 $ (114)
Net unrealized (gain) loss
(1) (88) (391) 613 (661) 832
----------------------------------------------------------------------------
Net (gain) loss $ (84) $ (424) $ 562 $ (631) $ 718
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net unrealized foreign exchange gain for the year ended
December 31, 2009 was primarily due to the strengthening Canadian
dollar with respect to the US dollar debt, offset by the impact of
the re-measurement of North Sea future income tax liabilities
denominated in UK pounds sterling. The net unrealized (gain) loss
for the respective periods was also impacted by the cross currency
swaps (three months ended December 31, 2009 - unrealized loss of
$48 million, September 30, 2009 - unrealized loss of $172 million,
December 31, 2008 - unrealized gain of $313 million; year ended
December 31, 2009 - unrealized loss of $338 million, December 31,
2008 - unrealized gain of $449 million). The net realized foreign
exchange loss for the year ended December 31, 2009 was primarily
due to the result of foreign exchange rate fluctuations on
settlement of working capital items denominated in US dollars or UK
pounds sterling. The Canadian dollar ended the fourth quarter at
US$0.9555 (September 30, 2009 - US$0.9327; December 31, 2008 -
US$0.8166).
TAXES
Three Months Ended Year Ended
-------------------------------------------------
($ millions, except income Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
tax rates) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Current $ 25 $ 10 $ 27 $ 91 $ 245
Deferred 7 13 (5) 15 (67)
----------------------------------------------------------------------------
Taxes other than income
tax $ 32 $ 23 $ 22 $ 106 $ 178
----------------------------------------------------------------------------
North America (1) $ 11 $ 7 $ - $ 28 $ 33
North Sea 60 55 12 278 340
Offshore West Africa 23 28 12 82 128
----------------------------------------------------------------------------
Current income tax 94 90 24 388 501
Future income tax expense
(recovery) 75 83 817 (99) 1,607
----------------------------------------------------------------------------
169 173 841 289 2,108
Income tax rate and other
legislative changes (2) - - - 19 41
----------------------------------------------------------------------------
$ 169 $ 173 $ 841 $ 308 $ 2,149
----------------------------------------------------------------------------
Effective income tax rate
on adjusted net earnings
from operations 28.4% 25.7% 23.7% 24.3% 27.8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Conventional Crude Oil and Natural Gas,
Midstream, and Oil Sands Mining and Upgrading segments.
(2) Includes the effect of a recovery of $19 million due to British Columbia
corporate income tax rate reductions substantively enacted or enacted
during the first quarter of 2009 and a 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 substantively
enacted or enacted during the first quarter of 2008.
Taxes other than income tax primarily includes current and
deferred PRT, which is charged on certain fields in the North Sea
at the rate of 50% of net operating income, after allowing for
certain deductions including related capital and abandonment
expenditures.
Taxable income from the conventional crude oil and natural gas
business in Canada is primarily generated through partnerships,
with the related income taxes payable in subsequent periods. North
America current income taxes have been provided on the basis of
this corporate structure. In addition, current income taxes in each
business segment will vary depending on available income tax
deductions related to the nature, timing and amount of capital
expenditures incurred in any particular year.
The Company is subject to income tax reassessments arising in
the normal course. The Company does not believe that any
liabilities ultimately arising from these reassessments will be
material.
For 2010, based on budgeted prices and the current availability
of tax pools, the Company expects to incur current income tax
expense in Canada of $450 million to $550 million and in the North
Sea of $220 million to $260 million.
NET CAPITAL EXPENDITURES(1)
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Expenditures on property,
plant and equipment
Net property acquisitions
(dispositions) $ 11 $ (30) $ 34 $ 6 $ 336
Land acquisition and
retention 28 18 18 77 86
Seismic evaluations 13 21 22 73 107
Well drilling, completion
and equipping 291 261 505 1,244 1,664
Production and related
facilities 222 235 382 977 1,282
----------------------------------------------------------------------------
Total net reserve
replacement expenditures 565 505 961 2,377 3,475
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading:
Horizon Phase 1
construction costs - - 557 69 2,732
Horizon Phase 1
commissioning and
other costs - - 115 202 364
Horizon Phases 2/3
construction costs 42 21 94 104 336
Capitalized interest,
stock-based
compensation and other 12 11 78 98 480
Sustaining capital 53 23 - 80 -
----------------------------------------------------------------------------
Total Oil Sands Mining and
Upgrading (2) 107 55 844 553 3,912
----------------------------------------------------------------------------
Midstream 1 - 3 6 9
Abandonments (3) 17 12 15 48 38
Head office 4 2 4 13 17
----------------------------------------------------------------------------
Total net capital
expenditures $ 694 $ 574 $ 1,827 $ 2,997 $ 7,451
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 436 $ 358 $ 486 $ 1,663 $ 2,344
North Sea 48 38 117 168 319
Offshore West Africa 80 108 358 544 811
Other 1 1 - 2 1
Oil Sands Mining and
Upgrading 107 55 844 553 3,912
Midstream 1 - 3 6 9
Abandonments (3) 17 12 15 48 38
Head office 4 2 4 13 17
----------------------------------------------------------------------------
Total $ 694 $ 574 $ 1,827 $ 2,997 $ 7,451
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The net capital expenditures exclude adjustments related to differences
between carrying value and tax value, and other fair value adjustments.
(2) Net expenditures for the Oil Sands Mining and Upgrading assets also
include the impact of intersegment eliminations.
(3) Abandonments represent expenditures to settle asset retirement
obligations and have been reflected as capital expenditures in this
table.
The Company's strategy is focused on building a diversified
asset base that is balanced among various products. In order to
facilitate efficient operations, the Company concentrates its
activities in core regions where it can dominate the land base and
infrastructure. The Company focuses on maintaining its land
inventories to enable the continuous exploitation of play types and
geological trends, greatly reducing overall exploration risk. By
dominating infrastructure, the Company is able to maximize
utilization of its production facilities, thereby increasing
control over production costs.
Net capital expenditures for the year ended December 31, 2009
were $2,997 million compared to $7,451 million for the year ended
December 31, 2008. Net capital expenditures for the fourth quarter
of 2009 were $694 million compared to $1,827 million for the fourth
quarter of 2008 and $574 million for the prior quarter. The
decrease in capital expenditures from the prior year reflects the
completion of Horizon Phase 1 construction. The increase in capital
expenditures from the prior quarter reflects increased drilling
activities in the fourth quarter of 2009. Capital expenditures
continue to be impacted by the effects of an overall strategic
reduction in the North America natural gas drilling program.
Drilling Activity (number of wells)
Three Months Ended Year Ended
-------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Net successful natural gas
wells 28 17 41 109 269
Net successful crude oil
wells 195 262 182 644 682
Dry wells 17 10 11 46 39
Stratigraphic test / service
wells 80 6 97 329 131
----------------------------------------------------------------------------
Total 320 295 331 1,128 1,121
Success rate
(excluding stratigraphic
test / service wells) 93% 97% 95% 94% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America
North America, excluding Oil Sands Mining and Upgrading,
accounted for approximately 58% of the total capital expenditures
for the year ended December 31, 2009 compared to approximately 32%
for the year ended December 31, 2008.
During the fourth quarter of 2009, the Company targeted 28 net
natural gas wells, including 4 wells in Northeast British Columbia,
11 wells in the Northern Plains region, 12 wells in Northwest
Alberta, and 1 well in the Southern Plains region. The Company also
targeted 212 net crude oil wells. The majority of these wells were
concentrated in the Company's crude oil Northern Plains region
where 159 heavy crude oil wells, 19 Pelican Lake crude oil wells,
14 thermal crude oil wells, and 2 light crude oil wells were
drilled. Another 18 wells targeting light crude oil were drilled
outside the Northern Plains region.
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 recent years, a
low natural gas price, and as a result of royalty changes under the
ARF, natural gas drilling activities have been reduced. 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 for the fourth quarter of 2009
averaged approximately 57,000 bbl/d, compared to approximately
64,000 bbl/d for the fourth quarter of 2008 and approximately
52,000 bbl/d for the prior quarter. The Primrose East expansion was
completed and first steaming commenced in September 2008, with
first production achieved in the fourth quarter of 2008. During the
first quarter of 2009, operational issues on one of the pads caused
steaming to cease on all well pads in the Primrose East project
area. During the fourth quarter of 2009, the Company continued
diagnostic steaming and is working with regulators to commence full
steaming.
The next planned phase of the Company's In-Situ Oil Sands Assets
expansion is the Kirby project. Final corporate sanction and
project scope is targeted for late 2010. Currently the Company is
proceeding with the detailed engineering and design work.
Development of new pads and tertiary recovery conversion
projects at Pelican Lake continued as expected throughout the
fourth quarter of 2009. Drilling consisted of 19 horizontal wells
in the fourth quarter. The response from the water and polymer
flood projects continues to be positive. Pelican Lake production
averaged approximately 38,000 bbl/d for the fourth quarter of 2009,
compared to 37,000 bbl/day for both the prior quarter and the
fourth quarter of 2008.
For the first quarter of 2010, the Company's overall planned
drilling activity in North America is expected to be comprised of
47 natural gas wells and 253 crude oil wells, excluding
stratigraphic and service wells.
Oil Sands Mining and Upgrading
With construction completed, Horizon Phase 1 assets are now
available for their intended use. Accordingly, capitalization of
all associated development costs, including capitalized interest
and stock-based compensation, and all directly attributable Phase 1
administrative costs have ceased, and depletion, depreciation and
amortization of these assets has commenced. Phase 2/3 spending was
focused on the construction of the third Ore Preparation Plant, the
Mine Maintenance Shop and additional tankage.
North Sea
In the fourth quarter of 2009, the Company completed a planned
maintenance shutdown at one of the Ninian Platforms on time and on
budget.
Offshore West Africa
At the Olowi Field, development activities related to
infrastructure tie-ins continued throughout the quarter. Drilling
commenced on the second platform with targeted production in the
second quarter of 2010.
LIQUIDITY AND CAPITAL RESOURCES
----------------------------------
Dec 31 Sep 30 Dec 31
($ millions, except ratios) 2009 2009 2008
----------------------------------------------------------------------------
Working capital (deficit) (1) $ (514) $ (396) $ 392
Long-term debt (2) (3) $ 9,658 $ 10,557 $ 13,016
Share capital $ 2,834 $ 2,827 $ 2,768
Retained earnings 16,696 16,299 15,344
Accumulated other comprehensive
(loss) income (104) (61) 262
----------------------------------------------------------------------------
Shareholders' equity $ 19,426 $ 19,065 $ 18,374
Debt to book capitalization (3) (4) 33% 36% 41%
Debt to market capitalization (3) (5) 19% 21% 33%
After tax return on average common
shareholders' equity (6) 8% 16% 33%
After tax return on average capital
employed (3) (7) 6% 10% 19%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated as current assets less current liabilities, excluding the
current portion of long-term debt.
(2) Includes the current portion of long-term debt (December 31,
2009 - $nil; September 30, 2009 - $nil; December 31, 2008 - $420
million).
(3) Long-term debt is stated at its carrying value, net of fair value
adjustments, original issue discounts and transaction costs.
(4) Calculated as current and long-term debt; divided by the book value of
common shareholders' equity plus current and long-term debt.
(5) Calculated as current and long-term debt; divided by the market value
of common shareholders' equity plus current and long-term debt.
(6) Calculated as net earnings for the twelve month trailing period; as a
percentage of average common shareholders' equity for the period.
(7) Calculated as net earnings plus after-tax interest expense for the
twelve month trailing period; as a percentage of average capital
employed for the period. Average capital employed is the average
shareholders' equity and current and long-term debt for the period,
including $12,855 million in average capital employed related to Oil
Sands Mining and Upgrading assets (September 30, 2009 - $12,642
million; December 31, 2008 - $10,678 million).
At December 31, 2009, the Company's capital resources consisted
primarily of cash flow from operations, available bank credit
facilities and access to debt capital markets. Cash flow from
operations is dependent on factors discussed in the "Risks and
Uncertainties" section of the Company's December 31, 2008 annual
MD&A. The Company's ability to renew existing bank credit
facilities and raise new debt is also dependent upon these factors,
as well as maintaining an investment grade debt rating and the
condition of capital and credit markets. The Company continues to
believe that its internally generated cash flow from operations
supported by the implementation of its on-going hedge policy, the
flexibility of its capital expenditure programs supported by its
multi-year financial plans, its existing bank credit facilities,
and its ability to raise new debt on commercially acceptable terms,
will provide sufficient liquidity to sustain its operations in the
short, medium and long term and support its growth strategy.
At December 31, 2009, the Company had $2,004 million of
available credit under its bank credit facilities. The Company's
current debt ratings are BBB (high) with a stable trend by DBRS
Limited, Baa2 with a stable outlook by Moody's Investors Service
and BBB with a stable outlook by Standard & Poor's.
Further details related to the Company's long-term debt at
December 31, 2009 are discussed in note 4 to the Company's
unaudited interim consolidated financial statements.
Long-term debt was $9,658 million at December 31, 2009,
resulting in a debt to book capitalization ratio of 33% (September
30, 2009 - 36%; December 31, 2008 - 41%). This ratio is below the
35% to 45% range targeted by management. The Company remains
committed to maintaining a strong balance sheet and flexible
capital structure. The Company has hedged a portion of its crude
oil and natural gas production for 2010 at prices that protect
investment returns to ensure ongoing balance sheet strength and the
completion of its capital expenditure programs.
During the fourth quarter of 2009, the Company filed new base
shelf prospectuses that allow for the issue of up to $3,000 million
of medium-term notes in Canada and US$3,000 million of debt
securities in the United States until November 2011. If issued,
these securities will bear interest as determined at the date of
issuance.
The Company's commodity hedging program reduces the risk of
volatility in commodity prices and supports the Company's cash flow
for its capital expenditures programs. This program currently
allows for the hedging of up to 60% of the near 12 months budgeted
production and up to 40% of the following 13 to 24 months estimated
production. For the purpose of this program, the purchase of put
options is in addition to the above parameters. As at December 31,
2009, in accordance with the policy, approximately 39% of budgeted
crude oil volumes and approximately 17% of budgeted natural gas
volumes were hedged using collars for 2010.
Further details related to the Company's commodity related
derivative financial instruments outstanding at December 31, 2009
are discussed in note 11 to the Company's unaudited interim
consolidated financial statements.
Share capital
As at December 31, 2009, there were 542,327,000 common shares
outstanding and 32,106,000 stock options outstanding. As at March
2, 2010, the Company had 542,655,000 common shares outstanding and
30,702,000 stock options outstanding.
On March 3, 2010, the Company's Board of Directors approved an
increase in the annual dividend paid by the Company to $0.60 per
common share for 2010. The increase represented a 43% increase from
2009, recognizes the stability of the Company's cash flow, and
provides a return to Shareholders. The dividend policy undergoes a
periodic review by the Board of Directors and is subject to
change.
On March 3, 2010 the Board of Directors approved a resolution to
file with the Toronto Stock Exchange a Notice of Intention to
purchase by way of normal course issuer bid up to 2.5% of its
issued and outstanding common shares. Subject to acceptance by the
Toronto Stock Exchange of the Notice of Intention, the purchases
would be made through the facilities of the Toronto Stock Exchange
and the New York Stock Exchange.
Share split
On March 3, 2010, the Company's Board of Directors approved a
resolution to subdivide the Company's common shares on a two for
one basis, subject to shareholder approval. The proposal will be
voted on at the Company's Annual and Special Meeting of
Shareholders to be held on May 6, 2010.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. As at December 31, 2009, no entities were
consolidated under the Canadian Institute of Chartered Accountants
Handbook Accounting Guideline 15, "Consolidation of Variable
Interest Entities". The following table summarizes the Company's
commitments as at December 31, 2009:
($ millions) 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 207 $ 162 $ 136 $ 125 $ 126 $ 1,051
Offshore equipment
Operating leases $ 155 $ 124 $ 103 $ 102 $ 101 $ 261
Offshore drilling $ 49 $ - $ - $ - $ - $ -
Asset retirement
obligations (1) $ 16 $ 20 $ 21 $ 31 $ 39 $ 6,479
Long-term debt (2) $ 400 $ 419 $ 366 $ 819 $ 366 $ 5,424
Interest expense (3) $ 473 $ 451 $ 415 $ 370 $ 350 $ 4,779
Office leases $ 25 $ 19 $ 3 $ 2 $ 2 $ -
Other $ 271 $ 67 $ 23 $ 15 $ 12 $ 34
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) 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 2010 - 2014 represent the minimum required expenditures to meet
these obligations. Actual expenditures in any particular year may
exceed these minimum amounts.
(2) 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 $1,897 million of revolving
bank credit facilities due to the extendable nature of the facilities.
(3) 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 and foreign exchange rates as at December 31, 2009.
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is defendant and plaintiff in a number of legal
actions. In addition, the Company is subject to certain contractor
construction claims. 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 judgments, 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, 2008.
For the impact of new accounting standards, refer to note 2 of
the unaudited interim consolidated financial statements as at
December 31, 2009.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
In February 2008, the CICA's Accounting Standards Board
confirmed that Canadian publicly accountable enterprises will be
required to adopt International Financial Reporting Standards
("IFRS") as promulgated by the International Accounting Standards
Board ("IASB") in place of Canadian GAAP effective January 1,
2011.
The Company has established a formal IFRS project governance
structure. The structure includes a Steering Committee, which
consists of senior levels of management from finance and
accounting, operations and information technology ("IT"). The
Steering Committee provides regular updates to the Company's
Management and the Audit Committee of the Board of Directors.
The Company's IFRS conversion project has been broken down into
the following phases:
- Phase 1 Diagnostic - identification of potential accounting
and reporting differences between Canadian GAAP and IFRS.
- Phase 2 Planning - establishment of project governance,
processes, resources, budget and timeline.
- Phase 3 Policy Delivery and Documentation - establishment of
accounting policies under IFRS.
- Phase 4 Policy Implementation - establishment of processes for
accounting and reporting, IT change requirements, and
education.
- Phase 5 Sustainment -ongoing compliance with IFRS after
implementation.
The Company has completed the Diagnostic and Planning phases
(Phases 1 and 2). Significant differences were identified in
accounting for Property, Plant & Equipment ("PP&E"),
including exploration costs, depletion and depreciation,
capitalized interest, impairment testing, and asset retirement
obligations. Other significant differences were noted in accounting
for stock-based compensation, risk management activities, and
income taxes. The Company is continuing to perform the necessary
research to develop and document IFRS policies to address the major
differences noted (Phase 3). A summary of the significant
differences identified is included below. At this time, the impact
on the Company's future financial position and results of
operations is not reasonably determinable. In addition, certain
IFRS standards are expected to change prior to adoption in 2011,
and the impact of these potential changes is not known.
The Company has identified, developed and tested process and
system changes required to capture data required for IFRS
accounting and reporting (Phase 4), including 2010 requirements to
capture both Canadian GAAP and IFRS data. IT system changes are
substantially complete and implemented as at December 31, 2009.
Summary of Identified IFRS Accounting Policy Differences
Property, Plant & Equipment
Adoption of IFRS will significantly impact the Company's
accounting policies for PP&E. For Canadian GAAP purposes, the
Company follows the full cost method of accounting for its
conventional crude oil and natural gas properties and equipment as
prescribed by Accounting Guideline 16 ("AcG16). Application of the
full cost method of accounting is discussed in the "Critical
Accounting Estimates" section of the 2008 annual MD&A.
Significant differences in accounting for PP&E under IFRS
include:
- Pre-exploration costs must be expensed. Under full cost
accounting, these costs are currently included in the country cost
centre.
- Exploration and evaluation costs will be initially capitalized
as exploration and evaluation assets. Once technical feasibility
and commercial viability of reserves is established for an area,
the costs will be transferred to PP&E. If technically feasible
and commercially viable reserves are not established for a new
area, the costs must be expensed. Under full cost accounting,
exploration and evaluation costs are currently disclosed as
PP&E but withheld from depletion. Costs are transferred to the
depletable assets when proved reserves are assigned or when it is
determined that the costs are impaired.
- PP&E for producing properties will be depreciated at an
asset level. Under full cost accounting, PP&E is depleted on a
country cost centre basis.
- Interest directly attributable to the acquisition or
construction of a qualifying asset must be capitalized to the cost
of the asset. Under Canadian GAAP, capitalization of interest is
discretionary.
- Impairment of PP&E will be tested at a cash generating
unit level (the lowest level at which cash inflows can be
identified). Under full cost accounting, impairment is tested at
the country cost centre level.
IFRS 1 "First-time Adoption of International Financial Reporting
Standards" issued by the IASB includes a transition exemption for
oil and gas companies following full cost accounting under their
previous GAAP. The transition exemption allows full cost companies
to allocate their existing full cost PP&E balances using
reserve values or volumes to IFRS compliant units of account
without requiring retroactive adjustment, subject to an initial
impairment test. The Company intends to adopt this transition
exemption.
Asset Retirement Obligations
Canadian GAAP accounting requirements for asset retirement
obligations ("ARO") are discussed in the "Critical Accounting
Estimates" section of the 2008 annual MD&A. A significant
difference in accounting for ARO under IFRS is that the liability
must be re-measured at each balance sheet date using the current
discount rates, whereas under Canadian GAAP the discount rates do
not change once the liability is recorded. On transition to IFRS,
the change in ARO liability on PP&E for which the full cost
exemption above is applied must be recorded in retained earnings.
For the change in ARO liability on other non-full cost PP&E,
the change will be adjusted to PP&E in accordance with the
general exemption for decommissioning liabilities included in IFRS
1. In future periods, the impact of changes in discount rates on
the ARO liability for all PP&E is adjusted to PP&E.
Stock-based Compensation
Under Canadian GAAP, the Company's stock option plan liability
is valued using the intrinsic value method, calculated as the
amount by which the market price of the Company's shares exceeds
the exercise price of the option for vested options. Under IFRS,
the stock option plan liability must be measured using a fair value
option pricing model such as the Black-Scholes model. The Company
intends to utilize the exemption in IFRS 1 under which options that
were settled prior to January 1, 2010 will not have to be
retrospectively restated.
Income Taxes
Both Canadian GAAP and IFRS follow the liability method of
accounting for income taxes, where tax liabilities and assets are
recognized on temporary differences. However, there are certain
exceptions to the treatment of temporary differences under IFRS
that may result in an adjustment to the Company's future tax
liability under IFRS. In addition, the Company's future tax
liability will be impacted by the tax effects of any changes noted
in the above areas.
Other IFRS 1 Exemptions
The Company also intends to adopt the following IFRS 1
transition exemptions:
- The Company intends to elect to reset the foreign currency
translation adjustment to zero by transferring the Canadian GAAP
balance to retained earnings on January 1, 2010, rather than
retrospectively restating the balance.
- The Company intends to adopt the IFRS 1 election to not
restate business combinations entered into prior to January 1,
2010.
SENSITIVITY ANALYSIS
The following table is indicative of the annualized
sensitivities of cash flow from operations and net earnings from
changes in certain key variables. The analysis is based on business
conditions and sales volumes during the fourth quarter of 2009,
excluding mark-to-market gains (losses) on risk management
activities, and is not necessarily indicative of future results.
Each separate line item in the sensitivity analysis shows the
effect of a change in that variable only with all other variables
being held constant.
Cash flow Cash flow from Net
from operations Net earnings
operations (per common earnings (per common
($ millions) share, basic) ($ millions) share, basic)
----------------------------------------------------------------------------
Price changes
Crude oil -
WTI US$1.00/bbl(1)
Excluding financial
derivatives $ 109 $ 0.20 $ 90 $ 0.17
Including financial
derivatives $ 91 $ 0.17 $ 76 $ 0.14
Natural gas -
AECO C$0.10/mcf(1)
Excluding financial
derivatives $ 33 $ 0.06 $ 24 $ 0.04
Including financial
derivatives $ 18 $ 0.03 $ 14 $ 0.03
Volume changes
Crude oil - 10,000 bbl/d $ 161 $ 0.30 $ 105 $ 0.19
Natural gas - 10 mmcf/d $ 12 $ 0.02 $ 4 $ 0.01
Foreign currency rate
change
$0.01 change in US$(1)
Including financial
derivatives $95-97 $0.17-0.18 $ 31-32 $ 0.06
Interest rate change - 1% $ 13 $ 0.02 $ 13 $ 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) For details of outstanding financial instruments in place, refer to
note 11 of the Company's unaudited interim consolidated financial
statements.
FINANCIAL STATEMENTS
Consolidated Balance Sheets
----------------------
Dec 31 Dec 31
(millions of Canadian dollars, unaudited) 2009 2008
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 13 $ 27
Accounts receivable 1,148 1,059
Inventory, prepaids and other 584 455
Future income tax 146 -
Current portion of other long-term assets (note 3) - 1,851
----------------------------------------------------------------------------
1,891 3,392
Property, plant and equipment (note 13) 39,115 38,966
Other long-term assets (note 3) 18 292
----------------------------------------------------------------------------
$ 41,024 $ 42,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 240 $ 383
Accrued liabilities 1,522 1,802
Future income tax - 585
Current portion of long-term debt (note 4) - 420
Current portion of other long-term
liabilities (note 5) 643 230
----------------------------------------------------------------------------
2,405 3,420
Long-term debt (note 4) 9,658 12,596
Other long-term liabilities (note 5) 1,848 1,124
Future income tax 7,687 7,136
----------------------------------------------------------------------------
21,598 24,276
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 7) 2,834 2,768
Retained earnings 16,696 15,344
Accumulated other comprehensive (loss) income (note 8) (104) 262
----------------------------------------------------------------------------
19,426 18,374
----------------------------------------------------------------------------
$ 41,024 $ 42,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (note 12)
Consolidated Statements of Earnings
Three Months Ended Year Ended
(millions of Canadian dollars, --------------------------------------
except per common Dec 31 Dec 31 Dec 31 Dec 31
share amounts, unaudited) 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue $ 3,319 $ 2,511 $ 11,078 $ 16,173
Less: royalties (285) (268) (936) (2,017)
----------------------------------------------------------------------------
Revenue, net of royalties 3,034 2,243 10,142 14,156
----------------------------------------------------------------------------
Expenses
Production 819 615 2,987 2,451
Transportation and blending 351 290 1,218 1,936
Depletion, depreciation and
amortization 836 666 2,819 2,683
Asset retirement obligation
accretion (note 5) 23 19 90 71
Administration 49 46 181 180
Stock-based compensation expense
(recovery) (note 5) 87 (203) 355 (52)
Interest, net 111 23 410 128
Risk management activities (note 11) 186 (2,408) 738 (1,230)
Foreign exchange (gain) loss (84) 562 (631) 718
----------------------------------------------------------------------------
2,378 (390) 8,167 6,885
----------------------------------------------------------------------------
Earnings before taxes 656 2,633 1,975 7,271
Taxes other than income tax 32 22 106 178
Current income tax expense (note 6) 94 24 388 501
Future income tax expense (recovery)
(note 6) 75 817 (99) 1,607
----------------------------------------------------------------------------
Net earnings $ 455 $ 1,770 $ 1,580 $ 4,985
----------------------------------------------------------------------------
Net earnings per common share (note 10)
Basic and diluted $ 0.85 $ 3.27 $ 2.92 $ 9.22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Shareholders' Equity
Year Ended
----------------------
Dec 31 Dec 31
(millions of Canadian dollars, unaudited) 2009 2008
----------------------------------------------------------------------------
Share capital (note 7)
Balance - beginning of year $ 2,768 $ 2,674
Issued upon exercise of stock options 24 18
Previously recognized liability on stock
options exercised for common shares 42 76
----------------------------------------------------------------------------
Balance - end of year 2,834 2,768
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of year 15,344 10,575
Net earnings 1,580 4,985
Dividends on common shares (note 7) (228) (216)
----------------------------------------------------------------------------
Balance - end of year 16,696 15,344
----------------------------------------------------------------------------
Accumulated other comprehensive (loss)
income (note 8)
Balance - beginning of year 262 72
Other comprehensive (loss) income, net of taxes (366) 190
----------------------------------------------------------------------------
Balance - end of year (104) 262
----------------------------------------------------------------------------
Shareholders' equity $ 19,426 $ 18,374
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income
--------------------------------------
Three Months Ended Year Ended
(millions of Canadian dollars, Dec 31 Dec 31 Dec 31 Dec 31
unaudited) 2009 2008 2009 2008
----------------------------------------------------------------------------
Net earnings $ 455 $ 1,770 $ 1,580 $ 4,985
----------------------------------------------------------------------------
Net change in derivative financial
Instruments designated as cash
flow hedges
Unrealized (loss) income during the
period, net of taxes of
$1 million (2008 - $1 million)
- three months ended;
$5 million (2008 - $1 million)
- year ended (9) 6 (33) 30
Reclassification to net earnings,
net of taxes of
$nil (2008 - $nil) - three months
ended;
$1 million (2008 - $6 million)
- year ended - (1) (10) (12)
----------------------------------------------------------------------------
(9) 5 (43) 18
Foreign currency translation adjustment
Translation of net investment (34) 141 (323) 172
----------------------------------------------------------------------------
Other comprehensive (loss) income,
net of taxes (43) 146 (366) 190
----------------------------------------------------------------------------
Comprehensive income $ 412 $ 1,916 $ 1,214 $ 5,175
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months Ended Year Ended
--------------------------------------
(millions of Canadian dollars, Dec 31 Dec 31 Dec 31 Dec 31
unaudited) 2009 2008 2009 2008
----------------------------------------------------------------------------
Operating activities
Net earnings $ 455 $ 1,770 $ 1,580 $ 4,985
Non-cash items
Depletion, depreciation and
amortization 836 666 2,819 2,683
Asset retirement obligation accretion 23 19 90 71
Stock-based compensation expense
(recovery) 87 (203) 355 (52)
Unrealized risk management loss (gain) 308 (2,107) 1,991 (3,090)
Unrealized foreign exchange (gain) loss (88) 613 (661) 832
Deferred petroleum revenue tax expense
(recovery) 7 (5) 15 (67)
Future income tax expense (recovery) 75 817 (99) 1,607
Other 3 2 5 25
Abandonment expenditures (17) (15) (48) (38)
Net change in non-cash working capital (180) (205) (235) (189)
----------------------------------------------------------------------------
1,509 1,352 5,812 6,767
----------------------------------------------------------------------------
Financing activities
(Repayment) issue of bank credit
facilities, net (717) 286 (2,021) (623)
Repayment of senior unsecured notes - - (34) (31)
Issue of US dollar debt securities - - - 1,215
Issue of common shares on exercise
of stock options 3 1 24 18
Dividends on common shares (57) (54) (225) (208)
Net change in non-cash working capital 36 48 (12) 46
----------------------------------------------------------------------------
(735) 281 (2,268) 417
----------------------------------------------------------------------------
Investing activities
Expenditures on property, plant and
equipment (680) (1,817) (2,985) (7,433)
Net proceeds on sale of property,
plant and equipment 3 5 36 20
----------------------------------------------------------------------------
Net expenditures on property, plant
and equipment (677) (1,812) (2,949) (7,413)
Net change in non-cash working capital (98) 192 (609) 235
----------------------------------------------------------------------------
(775) (1,620) (3,558) (7,178)
----------------------------------------------------------------------------
(Decrease) increase in cash and cash
equivalents (1) 13 (14) 6
Cash and cash equivalents - beginning
of period 14 14 27 21
----------------------------------------------------------------------------
Cash and cash equivalents - end of period $ 13 $ 27 $ 13 $ 27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 83 $ 112 516 574
Taxes paid
Taxes other than income tax $ 18 $ 83 $ 52 $ 300
Current income tax $ 88 $ 135 $ 216 $ 258
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, 2008, 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,
2008.
During 2009, Horizon Oil Sands ("Horizon") Phase 1 assets were
completed and available for their intended use. Accordingly,
capitalization of all associated Phase 1 development costs,
including capitalized interest and stock-based compensation, and
all directly attributable Phase 1 administrative costs ceased, and
depletion, depreciation and amortization of these assets commenced.
In addition, the Company recognized additional asset retirement
obligations related to its oil sands mining operations and tailings
ponds (note 5). All Horizon related financial results are included
in the "Oil Sands Mining and Upgrading" segment.
Comparative Figures
Certain prior period figures have been reclassified to conform
to the presentation adopted in 2009.
2. CHANGES IN ACCOUNTING POLICIES
During 2009, the Company adopted the following new accounting
standards issued by the Canadian Institute of Chartered Accountants
("CICA"):
- Goodwill and Intangible Assets - Effective January 1, 2009
Section 3064 - "Goodwill and Intangible Assets" replaced Section
3062 - "Goodwill and Other Intangible Assets" and Section 3450 -
"Research and Development Costs". In addition, EIC-27 - "Revenue
and Expenditures during the Pre-Operating Period" was withdrawn.
The new standard addresses when an internally generated intangible
asset meets the definition of an asset. The adoption of this
standard, which was adopted retroactively without restatement, did
not have an impact on the Company's financial statements.
- Credit Risk and the Fair Value of Financial Assets and
Liabilities - On January 20, 2009 the Emerging Issues Committee
("EIC") issued a new abstract EIC-173 "Credit Risk and the Fair
Value of Financial Assets and Financial Liabilities". This abstract
concludes that an entity's own credit risk and the credit risk of
the counterparty should be taken into account when determining the
fair value of financial assets and financial liabilities, including
derivative instruments. This abstract applies to all financial
assets and liabilities measured at fair value in interim and annual
financial statements for periods ending on or after January 20,
2009. The adoption of this abstract did not have a material impact
on the Company's results of operations or financial position.
- Financial Instruments - Disclosures - Effective October 1,
2009 Section 3862 - "Financial Instruments - Disclosures" was
amended to include additional disclosure requirements for fair
value measurements of financial instruments and to enhance
liquidity risk disclosure requirements. The amendment requires the
classification and disclosure of fair value using a three-level
hierarchy that reflects the significance of the inputs used in
making the fair value measurements. The fair values of assets and
liabilities included in Level 1 are determined by reference to
quoted prices in active markets for identical assets and
liabilities. Fair values of assets and liabilities in Level 2 are
based on inputs other than Level 1 quoted prices that are
observable for the asset or liability either directly (as prices)
or indirectly (derived from prices). The fair values of Level 3
assets and liabilities are not based on observable market data.
This amendment affected disclosure only and did not impact the
Company's accounting for financial instruments (note 11).
International Financial Reporting Standards
In February 2008, the CICA's Accounting Standards Board
confirmed that Canadian publicly accountable entities will be
required to adopt International Financial Reporting Standards
("IFRS") as promulgated by the International Accounting Standards
Board in place of generally accepted accounting principles in
Canada ("GAAP") effective January 1, 2011. The Company has assessed
which accounting policies will be affected by the change to IFRS
and continues to assess the potential impact of these changes on
its financial position and results of operations.
Recently issued accounting standards under Canadian GAAP
The following standards will be effective for the Company's year
beginning on January 1, 2011:
Business Combinations, Consolidated Financial Statements and
Non-Controlling Interests
Section 1582 - "Business Combinations", 1601 - "Consolidated
Financial Statements", and 1602 - "Non-Controlling Interests"
replace Section 1581 - "Business Combinations", and 1600 -
"Consolidated Financial Statements". Section 1582 is effective for
business combinations for acquisition dates on or after January 1,
2011. Earlier adoption is permitted, provided all three new
standards are adopted simultaneously. The new standards are the
Canadian equivalent of IFRS 3 "Business Combinations" and IAS 27
"Consolidated and Separate Financial Statements". Section 1582
requires equity instruments issued as part of the purchase
consideration to be measured at fair value at the acquisition date,
rather than the date when the acquisition was agreed to and
announced. In addition, most acquisition costs are expensed as
incurred, instead of being included in the purchase consideration.
The new standard also requires non-controlling interests to be
measured at fair value instead of carrying amounts. Section 1602
provides guidance on the treatment of non-controlling interests
after acquisition. Section 1601 carries forward existing guidance
on the preparation of consolidated financial statements, other than
non-controlling interests. There is no impact on the Company's
results of operations or financial position at this time.
3. OTHER LONG-TERM ASSETS
---------------------------
Dec 31 Dec 31
2009 2008
----------------------------------------------------------------------------
Risk management (note 11) $ - $ 2,119
Other 18 24
----------------------------------------------------------------------------
18 2,143
Less: current portion - 1,851
----------------------------------------------------------------------------
$ 18 $ 292
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. LONG-TERM DEBT
---------------------------
Dec 31 Dec 31
2009 2008
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities (bankers' acceptances) $ 1,897 $ 4,073
Medium-term notes 1,200 1,200
----------------------------------------------------------------------------
3,097 5,273
----------------------------------------------------------------------------
US dollar denominated debt
Senior unsecured notes (2009 - US$nil; 2008
- US$31 million) - 38
US dollar debt securities (2009 and 2008
- US$6,300 million) 6,594 7,715
Less: original issue discount on senior unsecured
notes and US dollar debt securities (1) (22) (23)
----------------------------------------------------------------------------
6,572 7,730
Fair value of interest rate swaps on US dollar
debt securities (2) 38 68
----------------------------------------------------------------------------
6,610 7,798
----------------------------------------------------------------------------
Long-term debt before transaction costs 9,707 13,071
Less: transaction costs (1) (3) (49) (55)
----------------------------------------------------------------------------
9,658 13,016
Less: current portion - 420
----------------------------------------------------------------------------
$ 9,658 $ 12,596
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $38 million (2008 - $68 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 December 31, 2009, the Company had in place unsecured bank
credit facilities of $3,955 million, comprised of:
- a $200 million demand credit facility;
- 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. Borrowings under these facilities can be made by way
of Canadian dollar and US dollar bankers' acceptances, and LIBOR,
US base rate and Canadian prime loans.
During 2009, the Company repaid the $2,350 million remaining on
the non-revolving syndicated credit facility related to the
acquisition of Anadarko Canada Corporation and cancelled the
facility.
During the second quarter of 2009, the Company renegotiated its
demand credit facility, increasing it to $200 million.
The Company's weighted average interest rate on bank credit
facilities outstanding as at December 31, 2009 was 0.8% (December
31, 2008 - 2.2%), and on long-term debt outstanding as at December
31, 2009 was 4.5% (December 31, 2008 - 4.6%)
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $358 million, including $300
million related to Horizon, were outstanding at December 31,
2009.
Medium-term notes
In October 2009, the Company filed a new base shelf prospectus
that allows for the issue of up to $3,000 million of medium-term
notes in Canada until November 2011. If issued, these securities
will bear interest as determined at the date of issuance. The
previous base shelf prospectus expired in October 2009.
Senior unsecured notes
During the second quarter of 2009, US$31 million of senior
unsecured notes were repaid.
US dollar debt securities
In October 2009, the Company filed a new base shelf prospectus
that allows for the issue of up to US$3,000 million of debt
securities in the United States until November 2011. If issued,
these securities will bear interest as determined at the date of
issuance. The previous base shelf prospectus expired in October
2009.
5. OTHER LONG-TERM LIABILITIES
---------------------------
Dec 31 Dec 31
2009 2008
----------------------------------------------------------------------------
Asset retirement obligations $ 1,610 $ 1,064
Stock-based compensation 392 171
Risk management (note 11) 309 -
Other 180 119
----------------------------------------------------------------------------
2,491 1,354
Less: current portion 643 230
----------------------------------------------------------------------------
$ 1,848 $ 1,124
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset retirement obligations
At December 31, 2009, the Company's total estimated undiscounted
costs to settle its asset retirement obligations were approximately
$6,606 million (December 31, 2008 - $4,474 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 6.9% (December 31, 2008 - 6.7%). A reconciliation of the
discounted asset retirement obligations is as follows:
-------------------------------
Year Ended Year Ended
Dec 31, 2009 Dec 31, 2008
----------------------------------------------------------------------------
Balance - beginning of year $ 1,064 $ 1,074
Liabilities incurred (1) 299 18
Liabilities acquired - 3
Liabilities settled (48) (38)
Asset retirement obligation accretion 90 71
Revision of estimates 276 (156)
Foreign exchange (71) 92
----------------------------------------------------------------------------
Balance - end of year $ 1,610 $ 1,064
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) During 2009, the Company recognized additional asset retirement
obligations related to Horizon and Gabon, Offshore West Africa.
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.
------------------------------
Year Ended Year Ended
Dec 31, 2009 Dec 31, 2008
----------------------------------------------------------------------------
Balance - beginning of year $ 171 $ 529
Stock-based compensation expense (recovery) 355 (52)
Cash payments for options surrendered (94) (207)
Transferred to common shares (42) (76)
Capitalized (recovery) to Oil Sands Mining and
Upgrading 2 (23)
----------------------------------------------------------------------------
Balance - end of year 392 171
Less: current portion 365 159
----------------------------------------------------------------------------
$ 27 $ 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Year Ended
----------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Current income tax - North
America (1) $ 11 $ - $ 28 $ 33
Current income tax - North Sea 60 12 278 340
Current income tax - Offshore West
Africa 23 12 82 128
----------------------------------------------------------------------------
Current income tax expense 94 24 388 501
Future income tax expense (recovery) 75 817 (99) 1,607
----------------------------------------------------------------------------
Income tax expense $ 169 $ 841 $ 289 $ 2,108
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Conventional Crude Oil and Natural Gas,
Midstream, and Oil Sands Mining and Upgrading segments.
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 subsequent periods. North
America current income taxes have been provided on the basis of
this corporate structure. In addition, current income taxes in each
business segment will vary depending upon available income tax
deductions related to the nature, timing and amount of capital
expenditures incurred in any particular year.
During the first quarter of 2009, substantively enacted income
tax rate changes resulted in a reduction of future income tax
liabilities of $19 million in British Columbia (2008 - $19 million
reduction in British Columbia, $22 million reduction in Cote
d'Ivoire).
The Company is subject to income tax reassessments arising in
the normal course. The Company does not believe that any
liabilities ultimately arising from these reassessments will be
material.
7. SHARE CAPITAL
---------------------------------
Year Ended Dec 31, 2009
Issued Number of shares
Common shares (thousands) Amount
----------------------------------------------------------------------------
Balance - beginning of year 540,991 $ 2,768
Issued upon exercise of stock options 1,336 24
Previously recognized liability on stock
options exercised - 42
----------------------------------------------------------------------------
Balance - end of year 542,327 $ 2,834
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dividend policy
On March 3, 2010, the Board of Directors set the regular
quarterly dividend at $0.15 per common share. The Company has paid
regular quarterly dividends in January, April, July, and October of
each year since 2001. The dividend policy undergoes a periodic
review by the Board of Directors and is subject to change.
In March 2009, the Board of Directors set the regular quarterly
dividend at $0.105 per common share (2008 - $0.10 per common
share).
Normal Course Issuer Bid
On March 3, 2010 the Board of Directors approved a resolution to
file with the Toronto Stock Exchange a Notice of Intention to
purchase by way of normal course issuer bid up to 2.5% of its
issued and outstanding common shares. Subject to acceptance by the
Toronto Stock Exchange of the Notice of Intention, the purchases
would be made through the facilities of the Toronto Stock Exchange
and the New York Stock Exchange.
Share split
On March 3, 2010, the Company's Board of Directors approved a
resolution to subdivide the Company's common shares on a two for
one basis, subject to shareholder approval. The proposal will be
voted on at the Company's Annual and Special Meeting of
Shareholders to be held on May 6, 2010.
Stock options
-----------------------------
Year Ended Dec 31, 2009
Weighted
average
Stock options exercise
(thousands) price
----------------------------------------------------------------------------
Outstanding - beginning of year 30,962 $ 51.94
Granted 6,736 $ 67.91
Surrendered for cash settlement (2,833) $ 27.31
Exercised for common shares (1,336) $ 17.99
Forfeited (1,423) $ 59.55
----------------------------------------------------------------------------
Outstanding - end of year 32,106 $ 58.54
----------------------------------------------------------------------------
Exercisable - end of year 10,969 $ 53.90
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME
The components of accumulated other comprehensive (loss) income, net of
taxes, were as follows:
-----------------------------
Dec 31 Dec 31
2009 2008
----------------------------------------------------------------------------
Derivative financial instruments designated
as cash flow hedges $ 76 $ 119
Foreign currency translation adjustment (180) 143
----------------------------------------------------------------------------
$ (104) $ 262
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9.CAPITAL DISCLOSURES
The Company does not have any externally imposed regulatory
capital requirements for managing capital. 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 current and long-term debt divided
by the sum of the carrying value of shareholders' equity plus
current and 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 below the target range at 33%.
Readers are cautioned that the debt to book capitalization ratio
is not defined by GAAP and this financial measure may not be
comparable to similar measures presented by other companies.
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.
-----------------------------
Dec 31 Dec 31
2009 2008
----------------------------------------------------------------------------
Long-term debt (1) $ 9,658 $ 13,016
Total shareholders' equity $ 19,426 $ 18,374
Debt to book capitalization 33% 41%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
10. NET EARNINGS PER COMMON SHARE
----------------------------------------
Three Months Ended Year Ended
Dec 31 Dec 31 Dec 31 Dec 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Weighted average common shares
outstanding (thousands)
- basic and diluted 542,300 540,914 541,925 540,647
----------------------------------------------------------------------------
Net earnings - basic and diluted $ 455 $ 1,770 $ 1,580 $ 4,985
----------------------------------------------------------------------------
Net earnings per common share -
basic and diluted $ 0.85 $ 3.27 $ 2.92 $ 9.22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. FINANCIAL INSTRUMENTS
The carrying values of the Company's financial instruments by category are
as follows:
-------------------------------------------------
Dec 31, 2009
----------------------------------------------------------------------------
Other
financial
Loans and Held for liabilities
receivables at trading at at amortized
Asset (liability) amortized cost fair value cost
----------------------------------------------------------------------------
Cash and cash equivalents $ - $ 13 $ -
Accounts receivable 1,148 - -
Other long-term assets - - -
Accounts payable - - (240)
Accrued liabilities - - (1,522)
Other long-term liabilities - (309) (167)
Long-term debt - - (9,658)
----------------------------------------------------------------------------
$ 1,148 $ (296) $ (11,587)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
-------------------------------------------------
Dec 31, 2008
----------------------------------------------------------------------------
Other
financial
Loans and Held for liabilities
receivables at trading at at amortized
Asset (liability) amortized cost fair value cost
----------------------------------------------------------------------------
Cash and cash equivalents $ - $ 27 $ -
Accounts receivable 1,059 - -
Other long-term assets - 2,119 -
Accounts payable - - (383)
Accrued liabilities - - (1,802)
Other long-term liabilities - - (105)
Long-term debt (1) - - (13,016)
----------------------------------------------------------------------------
$ 1,059 $ 2,146 $ (15,306)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
The carrying value of the Company's financial instruments
approximates their fair value, except for fixed-rate long-term debt
as noted below. The fair values of the Company's financial assets
and liabilities are outlined below:
---------------------------------------------
Dec 31, 2009
----------------------------------------------------------------------------
Carrying value Fair value
----------------------------------------------------------------------------
Asset (liability)(1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term assets $ - $ - $ -
Other long-term liabilities (309) - (309)
Fixed-rate long-term debt(2)(3) (7,761) (8,212) -
----------------------------------------------------------------------------
$ (8,070) $ (8,212) $ (309)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
---------------------------------------------
Dec 31, 2008
----------------------------------------------------------------------------
Carrying value Fair value
----------------------------------------------------------------------------
Asset (liability)(1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term assets $ 2,119 $ - $ 2,119
Other long-term liabilities - - -
Fixed-rate long-term debt(2)(3) (8,943) (7,649) -
----------------------------------------------------------------------------
$ (6,824) $ (7,649) $ 2,119
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes financial assets and liabilities where book value approximates
fair value due to the liquid nature of the asset or liability (cash and
cash equivalents, accounts receivable, accounts payable and accrued
liabilities).
(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 $38 million (2008 - $68 million) to reflect the fair value impact of
hedge accounting.
(3) The fair value of fixed-rate long-term debt has been determined based
on quoted market prices.
Risk management
The Company uses derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures.
These financial instruments are entered into solely for hedging
purposes and are not used for speculative purposes.
The estimated fair value of derivative financial instruments has
been determined based on appropriate internal valuation
methodologies. 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 primarily relied 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:
----------------------------------
Year Ended Year Ended
Dec 31, 2009 Dec 31, 2008
----------------------------------------------------------------------------
Risk management Risk management
Asset (liability) mark-to-market mark-to-market
----------------------------------------------------------------------------
Balance - beginning of year $ 2,119 $ (1,474)
Net cost of outstanding put options - 297
Net change in fair value of outstanding
derivative financial instruments
attributable to:
- Risk management activities (1,991) 3,090
- Interest expense (25) 60
- Foreign exchange (338) 449
- Other comprehensive income (78) 18
- Settlement of interest rate swaps and
other 4 (20)
----------------------------------------------------------------------------
(309) 2,420
Put premium financing obligations (1) - (301)
----------------------------------------------------------------------------
Balance - end of year (309) 2,119
Less: current portion (182) 1,851
----------------------------------------------------------------------------
$ (127) $ 268
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company negotiated payment of put option premiums with various
counterparties at the time of actual settlement of the respective
options. These obligations were reflected in the net risk management
asset (liability).
Net (gains) losses from risk management activities were as follows:
----------------------------------------
Three Months Ended Year Ended
Dec 31 Dec 31 Dec 31 Dec 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Net realized risk management
(gain) loss $ (122) $ (301) $ (1,253) $ 1,860
Net unrealized risk management
loss (gain) 308 (2,107) 1,991 (3,090)
----------------------------------------------------------------------------
$ 186 $ (2,408) $ 738 $ (1,230)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 management
The Company uses commodity derivative financial instruments to
manage its exposure to commodity price risk associated with the
sale of its future crude oil and natural gas production. At
December 31, 2009, the Company had the following net derivative
financial instruments outstanding to manage its commodity price
exposures:
Weighted average
Remaining term Volume price Index
----------------------------------------------------------------------------
Crude oil
Crude oil
price collars Jan 2010 - Mar 2010 6,000 bbl/d US$60.00 - US$105.15 WTI
Jan 2010 - Jun 2010 100,000 bbl/d US$60.00 - US$90.13 WTI
Jan 2010 - Sep 2010 50,000 bbl/d US$65.00 - US$105.49 WTI
Jan 2010 - Dec 2010 50,000 bbl/d US$60.00 - US$75.08 WTI
Jul 2010 - Dec 2010 50,000 bbl/d US$65.00 - US$108.94 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average
Remaining term Volume price Index
----------------------------------------------------------------------------
Natural gas
Natural gas
price
collars(1) Jan 2010 - Dec 2010 220,000 GJ/d C$6.00 - C$8.00 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to December 31, 2009, the Company entered into 400,000 GJ/d
of C$4.50 - C$6.30 natural gas AECO collars for the period April to
September 2010.
The Company's outstanding commodity derivative financial
instruments are expected to be settled monthly based on the
applicable index pricing for the respective contract month.
There were no commodity derivative financial instruments
designated as hedges at December 31, 2009.
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed
rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company enters into interest rate
swap contracts to manage its fixed to floating interest rate mix on
long-term debt. The interest rate swap contracts require the
periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At December 31,
2009, the Company had the following interest rate swap contracts
outstanding:
Amount Fixed
Remaining term ($ millions) rate Floating rate
----------------------------------------------------------------------------
Interest rate
Swaps - fixed
to floating Jan 2010 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
Swaps -
floating to
fixed Jan 2010 - Feb 2011 C$300 1.0680% 3 month CDOR (2)
Jan 2010 - Feb 2012 C$200 1.4475% 3 month CDOR (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) London Interbank Offered Rate
(2) Canadian Dealer Offered Rate
All fixed to floating interest rate related derivative financial
instruments designated as hedges at December 31, 2009 were
classified as fair value hedges.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated long-term
debt and working capital. The Company is also exposed to foreign
currency exchange rate risk on transactions conducted in other
currencies in its subsidiaries and in the carrying value of its
self-sustaining foreign subsidiaries. The Company periodically
enters into cross currency swap contracts and foreign currency
forward contracts to manage known currency exposure on US dollar
denominated long-term debt and working capital. The cross currency
swap contracts require the periodic exchange of payments with the
exchange at maturity of notional principal amounts on which the
payments are based. At December 31, 2009, the Company had the
following cross currency swap contracts outstanding:
Exchange Interest Interest
Amount rate rate rate
Remaining term ($ millions) (US$/C$) (US$) (C$)
----------------------------------------------------------------------------
Cross currency
Swaps Jan 2010 - Aug 2016 US$250 1.116 6.00% 5.40%
Jan 2010 - May 2017 US$1,100 1.170 5.70% 5.10%
Jan 2010 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency swap derivative financial instruments
designated as hedges at December 31, 2009 were classified as cash
flow hedges.
In addition to the cross currency swap contracts noted above, at
December 31, 2009, the Company had US$1,062 million of foreign
currency forward contracts outstanding, with terms of approximately
30 days or less.
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 December 31, 2009 resulting from changes in the specified
variable, with all other variables held constant. These
sensitivities are prepared on a different basis than those
sensitivities disclosed in the Company's other continuous
disclosure documents, 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 $ (21) $ -
Decrease WTI US$1.00/bbl $ 20 $ -
Increase AECO C$0.10/mcf $ (4) $ -
Decrease AECO C$0.10/mcf $ 4 $ -
Interest rate risk
Increase interest rate 1% $ (12) $ 14
Decrease interest rate 1% $ 8 $ (18)
Foreign currency exchange rate risk
Increase exchange rate by US$0.01 $ (29) $ -
Decrease exchange rate by US$0.01 $ 29 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) Credit risk
Credit risk is the risk that a party to a financial instrument
will cause a financial loss to the Company by failing to discharge
an obligation.
Counterparty credit risk management
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. At
December 31, 2009, substantially all of the Company's accounts
receivable were due within normal trade terms.
The Company is also exposed to possible losses in the event of
non-performance by counterparties to derivative financial
instruments; however, the Company manages this credit risk by
entering into agreements with counterparties that are substantially
all investment grade financial institutions and other entities. At
December 31, 2009, the Company had net risk management assets of $7
million with specific counterparties related to derivative
financial instruments (December 31, 2008 - $2,119 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 believes it has adequate bank
credit facilities to provide liquidity.
The maturity dates for financial liabilities are as follows:
1 to less 2 to less
Less than than than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 240 $ - $ - $ -
Accrued liabilities $ 1,522 $ - $ - $ -
Risk management $ 182 $ 15 $ 48 $ 64
Other long-term liabilities $ 96 $ 18 $ 32 $ 21
Long-term debt (1) $ 400 $ 419 $ 1,551 $ 5,424
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $1,897 million of revolving
bank credit facilities due to the extendable nature of the facilities.
12. COMMITMENTS
As at December 31, 2009, the Company had committed to certain payments as
follows:
2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 207 $ 162 $ 136 $ 125 $ 126 $ 1,051
Offshore equipment
operating leases $ 155 $ 124 $ 103 $ 102 $ 101 $ 261
Offshore drilling $ 49 $ - $ - $ - $ - $ -
Asset retirement
obligations (1) $ 16 $ 20 $ 21 $ 31 $ 39 $ 6,479
Office leases $ 25 $ 19 $ 3 $ 2 $ 2 $ -
Other $ 271 $ 67 $ 23 $ 15 $ 12 $ 34
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) 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 2010 - 2014 represent the minimum required expenditures to meet
these obligations. Actual expenditures in any particular year may exceed
these minimum amounts.
13. SEGMENTED INFORMATION
Conventional Crude Oil and Natural Gas
North America North Sea
(millions of
Canadian Three Months Three Months
dollars, Ended Year Ended Ended Year Ended
unaudited) Dec 31 Dec 31 Dec 31 Dec 31
----------------------------------------------------------------------------
2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
Segmented
revenue 2,220 2,116 7,973 13,496 295 262 961 1,769
Less:
royalties (244) (259) (825) (1,876) (1) (1) (2) (4)
----------------------------------------------------------------------------
Segmented
revenue, net
of royalties 1,976 1,857 7,148 11,620 294 261 959 1,765
----------------------------------------------------------------------------
Segmented
expenses
Production 391 457 1,748 1,881 103 117 376 457
Transportation
and blending 346 301 1,213 1,975 2 2 8 10
Depletion,
depreciation
and
amortization 487 552 2,060 2,236 65 84 261 317
Asset
retirement
obligation
accretion 11 10 41 42 5 8 24 27
Realized risk
management
activities (78) (301) (880) 1,861 (44) - (373) (1)
----------------------------------------------------------------------------
Total
segmented
expenses 1,157 1,019 4,182 7,995 131 211 296 810
----------------------------------------------------------------------------
Segmented
earnings
before
the following 819 838 2,966 3,625 163 50 663 955
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Stock-based
compensation
expense
(recovery)
Interest, net
Unrealized
risk
management
activities
Foreign
exchange
(gain) loss
----------------------------------------------------------------------------
Total
non-segmented
expenses
----------------------------------------------------------------------------
Earnings
before taxes
Taxes other
than income
tax
Current income
tax expense
Future income
tax expense
(recovery)
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore West Africa Total Conventional
(millions of
Canadian Three Months Three Months
dollars, Ended Year Ended Ended Year Ended
unaudited) Dec 31 Dec 31 Dec 31 Dec 31
----------------------------------------------------------------------------
2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
Segmented
revenue 307 186 913 944 2,822 2,564 9,847 16,209
Less:
royalties (22) (14) (81) (143) (267) (274) (908) (2,023)
----------------------------------------------------------------------------
Segmented
revenue, net
of royalties 285 172 832 801 2,555 2,290 8,939 14,186
----------------------------------------------------------------------------
Segmented
expenses
Production 63 41 179 102 557 615 2,303 2,440
Transportation
and blending - - 1 1 348 303 1,222 1,986
Depletion,
depreciation
and
amortization 202 38 335 132 754 674 2,656 2,685
Asset
retirement
obligation
accretion 1 1 4 2 17 19 69 71
Realized risk
management
activities - - - - (122) (301) (1,253) 1,860
----------------------------------------------------------------------------
Total
segmented
expenses 266 80 519 237 1,554 1,310 4,997 9,042
----------------------------------------------------------------------------
Segmented
earnings
before
the following 19 92 313 564 1,001 980 3,942 5,144
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Stock-based
compensation
expense
(recovery)
Interest, net
Unrealized
risk
management
activities
Foreign
exchange
(gain) loss
----------------------------------------------------------------------------
Total
non-segmented
expenses
----------------------------------------------------------------------------
Earnings
before taxes
Taxes other
than income
tax
Current income
tax expense
Future income
tax expense
(recovery)
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil Sands Mining and Midstream
Upgrading
(millions of
Canadian Three Months Three Months
dollars, Ended Year Ended Ended Year Ended
unaudited) Dec 31 Dec 31 Dec 31 Dec 31
----------------------------------------------------------------------------
2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
Segmented
revenue 492 - 1,253 - 18 17 72 77
Less:
royalties (18) - (36) - - - - -
----------------------------------------------------------------------------
Segmented
revenue, net
of royalties 474 - 1,217 - 18 17 72 77
----------------------------------------------------------------------------
Segmented
expenses
Production 259 - 683 - 5 6 19 25
Transportation
and blending 14 - 41 - - - - -
Depletion,
depreciation
and
amortization 83 - 187 - 3 2 9 8
Asset
retirement
obligation
accretion 6 - 21 - - - - -
Realized risk
management
activities - - - - - - - -
----------------------------------------------------------------------------
Total
segmented
expenses 362 - 932 - 8 8 28 33
----------------------------------------------------------------------------
Segmented
earnings
before
the following 112 - 285 - 10 9 44 44
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Stock-based
compensation
expense
(recovery)
Interest, net
Unrealized
risk
management
activities
Foreign
exchange
(gain) loss
----------------------------------------------------------------------------
Total
non-segmented
expenses
----------------------------------------------------------------------------
Earnings
before taxes
Taxes other
than income
tax
Current income
tax expense
Future income
tax expense
(recovery)
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment elimination Total
and other
(millions of
Canadian Three Months Three Months
dollars, Ended Year Ended Ended Year Ended
unaudited) Dec 31 Dec 31 Dec 31 Dec 31
----------------------------------------------------------------------------
2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
Segmented
revenue (13) (70) (94) (113) 3,319 2,511 11,078 16,173
Less:
royalties - 6 8 6 (285) (268) (936) (2,017)
----------------------------------------------------------------------------
Segmented
revenue, net
of
royalties (13) (64) (86) (107) 3,034 2,243 10,142 14,156
----------------------------------------------------------------------------
Segmented
expenses
Production (2) (6) (18) (14) 819 615 2,987 2,451
Transportation
and blending (11) (13) (45) (50) 351 290 1,218 1,936
Depletion,
depreciation
and
amortization (4) (10) (33) (10) 836 666 2,819 2,683
Asset
retirement
obligation
accretion - - - - 23 19 90 71
Realized risk
management
activities - - - - (122) (301) (1,253) 1,860
----------------------------------------------------------------------------
Total
segmented
expenses (17) (29) (96) (74) 1,907 1,289 5,861 9,001
----------------------------------------------------------------------------
Segmented
earnings
before
the following 4 (35) 10 (33) 1,127 954 4,281 5,155
----------------------------------------------------------------------------
Non-segmented
expenses
Administration 49 46 181 180
Stock-based
compensation
expense
(recovery) 87 (203) 355 (52)
Interest, net 111 23 410 128
Unrealized
risk
management
activities 308 (2,107) 1,991 (3,090)
Foreign
exchange
(gain) loss (84) 562 (631) 718
----------------------------------------------------------------------------
Total
non-segmented
expenses 471 (1,679) 2,306 (2,116)
----------------------------------------------------------------------------
Earnings
before taxes 656 2,633 1,975 7,271
Taxes other
than income
tax 32 22 106 178
Current income
tax expense 94 24 388 501
Future income
tax expense
(recovery) 75 817 (99) 1,607
----------------------------------------------------------------------------
Net earnings 455 1,770 1,580 4,985
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net additions to property, plant and equipment
Year Ended
Dec 31, 2009
--------------------------------------------
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 1,663 $ 65 $ 1,728
North Sea 168 146 314
Offshore West Africa 544 111 655
Other 2 - 2
Oil Sands Mining and Upgrading(2) 553 355 908
Midstream 6 - 6
Head office 13 - 13
----------------------------------------------------------------------------
$ 2,949 $ 677 $ 3,626
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year Ended
Dec 31, 2008
--------------------------------------------
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 2,344 $ (7) $ 2,337
North Sea 319 (127) 192
Offshore West Africa 811 6 817
Other 1 - 1
Oil Sands Mining and Upgrading(2) 3,912 10 3,922
Midstream 9 - 9
Head office 17 - 17
----------------------------------------------------------------------------
$ 7,413 $ (118) $ 7,295
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Oil Sands Mining and Upgrading assets also include
capitalized interest, stock-based compensation, and the impact of
inter-segment eliminations.
Property, plant and
equipment Total assets
-------------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Segmented assets
North America $ 21,834 $ 22,151 $ 22,994 $ 24,875
North Sea 1,812 2,048 1,968 2,638
Offshore West Africa(1) 1,883 1,894 2,033 2,013
Other 28 26 42 64
Oil Sands Mining and Upgrading 13,295 12,573 13,621 12,677
Midstream 203 206 306 315
Head office 60 68 60 68
----------------------------------------------------------------------------
$ 39,115 $ 38,966 $ 41,024 $ 42,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Offshore West Africa property, plant and equipment has been reduced by
$115 million to reflect the impact of a ceiling test impairment charge
as at December 31, 2009.
Capitalized interest
The Company capitalizes construction period interest to Oil
Sands Mining and Upgrading based on costs incurred and the
Company's cost of borrowing. Interest capitalization on a
particular development phase ceases once construction is
substantially complete. For the year ended December 31, 2009,
pre-tax interest of $106 million was capitalized to Oil Sands
Mining and Upgrading (December 31, 2008 - $481 million).
14. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES
Under Canadian full cost accounting guidelines, costs
capitalized in each country cost centre are limited to an amount
equal to the future net revenues from proved and probable reserves
using estimated future prices and costs discounted at the risk-free
rate, plus the carrying amount of unproved properties and major
development projects (the "ceiling test"). A ceiling test
impairment of $115 million was recognized in the Gabon, Offshore
West Africa country cost centre under Canadian GAAP at December 31,
2009, as capitalized costs exceeded future net revenues. No other
ceiling test impairments were recognized.
Under generally accepted accounting principles in the United
States ("US GAAP"), the Company is required to perform a ceiling
test calculation as at December 31, 2009, in accordance with the
full cost accounting method as set forth by the US Securities and
Exchange Commission. This ceiling test calculation limits the costs
capitalized in each country cost centre to an amount equal to the
future net revenues from proved reserves using the average
first-day-of-the-month price during the previous twelve-month
period and costs as at the balance sheet date, discounted at 10%,
plus the carrying amount of unproved properties and major
development projects, net of tax. Had the Company prepared its
financial statements in accordance with US GAAP, these differences
in applying the ceiling test would have resulted in the recognition
of additional ceiling test impairments in the Canada and Gabon,
Offshore West Africa country cost centres, reducing property, plant
and equipment by a further $993 million ($815 million net of tax)
in 2009.
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 October 2009. These ratios are
based on the Company's interim consolidated financial statements
that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended December 31,
2009:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 4.4 x
Cash flow from operations (2) 13.3 x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net earnings plus income taxes and interest expense; divided by the sum
of interest expense and capitalized interest.
(2) Cash flow from operations plus current income taxes and interest
expense; divided by the sum of interest expense and capitalized
interest.
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Time, 11:00
a.m. Eastern Time on Thursday, March 4, 2010. The North American
conference call number is 1-800-769-8320 and the outside North
American conference call number is 001-416-695-6616. Please call in
about 10 minutes before the starting time in order to be patched
into the call. The conference call will also be broadcast live on
the internet and may be accessed through the Canadian Natural
website at www.cnrl.com.
A taped rebroadcast will be available until 6:00 p.m. Mountain
Time, Thursday, March 11, 2010. 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 1207316.
WEBCAST
This call is being webcast and can be accessed on Canadian
Natural's website at www.cnrl.com/investor_info/calendar.html.
2010 FIRST QUARTER RESULTS
The 2010 first quarter results are scheduled for release on
Thursday, May 6, 2010. A conference call is scheduled to be held on
Friday, May 7, 2010 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 (403) 514-7777 (403) 514-7888 (FAX) Canadian Natural
Resources Limited Tim S. McKay 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 ir@cnrl.com www.cnrl.com
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