Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on first quarter results, Canadian Natural's
Chairman, Allan Markin stated, "Overall it has been an excellent
start to the year for Canadian Natural as production in North
America and in our International operations are doing as or better
than expected. We continue to focus on optimizing operational
performance in all parts of the Company. Ramp up at Horizon
continues with production at the high end of expectations as our
team continues to work towards production at levels near targeted
capacity of 110,000 barrels per day."
John Langille, Vice-Chairman of Canadian Natural continued, "Our
financial position exiting the first quarter shows continued
strengthening as the Company benefited from an increase in
production and favorable heavy oil differentials. This has resulted
in a reduction in outstanding debt and an improvement in our debt
to book capital to 31%. Throughout 2010, we anticipate solid cash
flow and earnings as we remain focused on our operational and
financial discipline."
Steve Laut, President for Canadian Natural stated, "The Company
continues to focus on short-, mid- and long-term strategies for the
development of our product types to allocate capital effectively.
The efforts of our committed and dedicated team of people to
promote operational efficiencies have resulted in strong production
volumes and a reduction in our conventional operating costs."
HIGHLIGHTS
Three Months Ended
Mar 31 Dec 31 Mar 31
($ millions, except as noted) 2010 2009 2009
----------------------------------------------------------------------------
Net earnings $ 866 $ 455 $ 305
Per common share, basic and diluted $ 1.60 $ 0.85 $ 0.56
Adjusted net earnings from operations (1) $ 658 $ 667 $ 727
Per common share, basic and diluted $ 1.21 $ 1.23 $ 1.34
Cash flow from operations (2) $ 1,505 $ 1,703 $ 1,516
Per common share, basic and diluted $ 2.77 $ 3.14 $ 2.80
Capital expenditures, net of dispositions $ 1,072 $ 694 $ 1,256
Daily production, before royalties
Natural gas (mmcf/d) 1,226 1,250 1,369
Crude oil and NGLs (bbl/d) 406,266 366,451 330,017
Equivalent production (boe/d) 610,556 574,857 558,142
----------------------------------------------------------------------------
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(1) Adjusted net earnings from operations is a non-GAAP measure that the
Company utilizes to evaluate its performance. The derivation of this
measure is discussed in 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.
HIGHLIGHTS
- Total crude oil and NGLs production for Q1/10 was 406,266
bbl/d, an increase of 11% from the previous quarter. Volumes in
Q1/10 were at the high end of the Company's guidance of 372,000 to
409,000 bbl/d and reflect the cyclic nature of Primrose production
and an increase in production at Horizon Oil Sands ("Horizon") from
the last quarter.
- Natural gas production for Q1/10 averaged 1,226 mmcf/d,
slightly above the Company's guidance of 1,197 to 1,221 mmcf/d due
to continued operational optimization and good drilling results.
Natural gas production for Q1/10 was down 2% from the previous
quarter. The decrease in volumes for Q1/10 from previous quarters
reflects the continuing reallocation of capital towards higher
return crude oil projects.
- Quarterly cash flow from operations was $1.5 billion, a
decrease of 12% from the previous quarter, and relatively flat from
Q1/09. The decrease from Q4/09 reflects the impact of lower natural
gas sales volumes, higher realized risk management expense, higher
cash tax expense and the stronger Canadian dollar relative to the
US dollar, partially offset by the impact of higher crude oil sales
volumes, and higher realized pricing.
- Quarterly net earnings for Q1/10 of $866 million included the
effects of unrealized risk management activities, fluctuations in
foreign exchange rates, stock-based compensation and the impact of
statutory tax rate and other legislative changes on future income
tax liabilities. Excluding these items, quarterly adjusted net
earnings from operations for Q1/10 were $658 million.
- Strong quarterly free cash flow and strengthening foreign
exchange rates contributed to a reduction in long-term debt of over
$700 million.
- Reliability at Horizon continues to improve. In both March and
April 2010, synthetic crude oil ("SCO") production was in excess of
100,000 barrels per day.
- In the first quarter, Canadian Natural drilled 150 primary
heavy crude oil wells as part of the planned record drilling
program for 2010.
- Platform B of the Olowi Project was commissioned in Q1/10.
Production at three wells commenced in early Q2/10.
- During the first quarter of 2010 and into the second quarter
of 2010 Canadian Natural entered into a number of agreements to
purchase crude oil and natural gas properties in its core regions
in Western Canada aggregating approximately $1 billion. Subject to
receipt of any required regulatory approvals and any applicable
rights of first refusal, the majority of these acquisitions are
expected to close in late Q2/10 and corporate guidance has been
revised accordingly.
- In March 2010, the Government of Alberta modified the
conventional crude oil and natural gas royalty rates. These changes
will be effective on January 1, 2011. Additional changes to the
Alberta Royalty Framework, including potential further changes to
conventional crude oil and natural gas royalty curves are expected
to be finalized and announced by May 31, 2010.
- Declared a quarterly cash dividend on common shares of $0.15
per common share payable July 1, 2010. The dividend will be
adjusted to reflect the proposed split in the Company's shares.
- 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 to be held on
May 6, 2010.
OPERATIONS REVIEW
Activity by core region
Net undeveloped land Drilling activity
as at Three Months Ended
Mar 31, 2010 Mar 31, 2010
(thousands of net acres) (net wells)(1)
----------------------------------------------------------------------------
North America conventional
Northeast British Columbia 1,972 14.1
Northwest Alberta 1,335 23.8
Northern Plains 5,869 256.3
Southern Plains 818 7.1
Southeast Saskatchewan 142 9.9
Thermal In-situ Oil Sands 488 173.0
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10,624 484.2
Oil Sands Mining and Upgrading 115 112.0
North Sea 150 -
Offshore West Africa 4,193 2.8
----------------------------------------------------------------------------
15,082 599.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Drilling activity includes stratigraphic test and service wells.
Drilling activity (number of wells)
Three Months Ended Mar 31
2010 2009
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 256 243 94 93
Natural gas 52 45 87 64
Dry 15 14 16 15
----------------------------------------------------------------------------
Subtotal 323 302 197 172
Stratigraphic test / service wells 298 297 236 236
----------------------------------------------------------------------------
Total 621 599 433 408
----------------------------------------------------------------------------
Success rate (excluding stratigraphic
test / service wells) 95% 91%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America Conventional
North America natural gas
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Natural gas production (mmcf/d) 1,193 1,218 1,347
----------------------------------------------------------------------------
Net wells targeting natural gas 49 28 72
Net successful wells drilled 45 28 64
----------------------------------------------------------------------------
Success rate 92% 100% 89%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Q1/10 North America natural gas production decreased, as
expected, 11% from Q1/09 and 2% from Q4/09, reflecting the
Company's strategic decision to reduce spending on natural gas
drilling. Although natural gas production volumes have decreased
from Q1/09, the Company has been able to maintain its unit of
production operating costs as a result of the Company's continued
focus on optimization.
- Canadian Natural targeted 49 net natural gas wells in Q1/10
with a prudent program across the Company's core regions. In
Northeast British Columbia, 14 net natural gas wells were drilled,
while in Northwest Alberta, 19 net natural gas wells were drilled.
In the Northern Plains, 15 net natural gas wells were drilled, with
1 net natural gas well drilled in the Southern Plains
- Planned drilling activity for Q2/10 includes 11 net natural
gas wells.
North America crude oil and NGLs
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Crude oil and NGLs production (bbl/d) 252,450 229,206 253,833
----------------------------------------------------------------------------
Net wells targeting crude oil 250 212 97
Net successful wells drilled 240 195 90
----------------------------------------------------------------------------
Success rate 96% 92% 93%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Q1/10 North America crude oil and NGLs production decreased 1%
from Q1/09 and increased 10% from Q4/09 levels. The increase in
production volume from Q4 was largely due to cyclic thermal crude
oil at Primrose.
- At Primrose East, Canadian Natural continues to work with
regulators and has commenced surveillance steaming with average
production targeted to be between 16,000 bbl/d and 20,000 bbl/d in
2010. Canadian Natural plans to slowly return to normal steaming
activities by late 2010 or early 2011.
- Canadian Natural is continuing its proposed third phase of the
thermal growth plan with a development plan for the Kirby In-Situ
Oil Sands Project. The Company has filed its formal regulatory
application documents for this project and is awaiting regulatory
approval. Final project scope and corporate sanction is targeted
for late 2010.
- Improvements at Pelican Lake continue with conversion to
polymer flooding. Pelican Lake production averaged approximately
37,000 bbl/d for Q1/10.
- Conventional heavy crude oil production volumes increased 5%
in Q1/10 compared to Q4/09, reflecting the Company's record
drilling program planned for 2010.
- During Q1/10, drilling activity targeted 250 net wells
including 150 wells targeting heavy crude oil, 74 wells targeting
Pelican Lake crude oil, and 26 wells targeting light crude oil.
- Planned drilling activity for Q2/10 includes 113 net crude oil
wells, excluding stratigraphic test and service wells, compared to
drilling activity for Q2/09 of 97 net crude oil wells, excluding
stratigraphic test and service wells.
International
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Crude oil production (bbl/d)
North Sea 36,879 34,408 42,369
Offshore West Africa 29,942 32,643 30,431
----------------------------------------------------------------------------
Natural gas production (mmcf/d)
North Sea 15 12 10
Offshore West Africa 18 20 12
----------------------------------------------------------------------------
Net wells targeting crude oil 2.8 - 3.2
Net successful wells drilled 2.8 - 3.2
----------------------------------------------------------------------------
Success rate 100% - 100%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
- North Sea crude oil production for the quarter increased by 7%
from Q4/09. Production was at the high end of guidance and
reflected strong well performance in the Ninian Field during the
quarter.
- The Company recommenced platform drilling operations at the
beginning of the second quarter and continues to focus on maturing
and high grading its inventory of future drilling locations. The
Company maintains focus on lowering costs.
Offshore West Africa
- Offshore West Africa's crude oil production decreased by 8%
from Q4/09, reflecting a planned shutdown at Espoir associated with
the facilities modules upgrade on the Espoir FPSO with ongoing
construction targeted for completion in Q3/10.
- The Company is currently drilling the second platform
(Platform B) at the Olowi Field, Offshore Gabon with 4 gross wells
drilled and completed and first Platform B crude oil achieved in
April 2010. Initial production performance from the first 3 wells
is encouraging. The fourth well is scheduled to be brought on
production in May 2010. Two additional wells are planned to be
drilled on Platform B with Platform A drilling to follow.
Oil Sands Mining and Upgrading
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Synthetic crude oil production (bbl/d) 86,995 70,194 3,384
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- The Company continues to move closer to sustainable production
as SCO production was 86,995 bbl/d in Q1/10, an increase of 24%
from Q4/09. Monthly average production for Horizon is now provided
on a monthly basis on the Company's website.
- Plant challenges in Q4/09 such as downtime relating to a coker
furnace were largely resolved in March 2010.
- Enhancement of operational procedures and plant reliability
continues to remain a focus.
- Operational costs in the quarter averaged $43.12 per barrel of
SCO primarily due to slightly lower production volumes in January,
unplanned maintenance expenditures such as costs associated with
the coker furnace repairs, higher property tax and the impact of
changes in product inventory carrying costs in the quarter. The
Company continues to target reduced operating costs between $31.00
to $37.00 per barrel of SCO for 2010. March 2010 actual operating
costs were approximately $32.50 per barrel (including approximately
$3.40 per barrel of natural gas input costs), in line with full
year guidance.
- The Company continues to target stable production levels with
annual production guidance for 2010 remaining at 90,000 to 105,000
barrels per day of SCO at Horizon. May 2010 production is expected
to be between 75,000 to 80,000 barrels per day of SCO due to
planned reductions in production levels for the month due to a
planned maintenance outage which will slightly reduce May's volumes
but are forecast to limit future operational issues and help reach
and maintain sustained production levels.
- Engineering and procurement for Tranche 2 of the Phase 2/3
expansion is progressing with a focus on increasing reliability and
uptime. Tranches 3 and 4 of Phase 2/3 continue to be re-profiled.
The Company continues to work on completing its lessons learned
from the construction of Phase 1 and implementing these into the
development of future expansions.
MARKETING Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Crude oil and NGLs pricing
WTI (1) benchmark price (US$/bbl) $ 78.79 $ 76.17 $ 43.21
Western Canadian Select blend
differential from WTI (%) 12% 16% 21%
SCO price (US$/bbl) $ 79.37 $ 75.07 $ 44.97
Corporate average pricing before
risk management (2) (C$/bbl) $ 68.76 $ 68.00 $ 41.25
Natural gas pricing
AECO benchmark price (C$/GJ) $ 5.07 $ 4.01 $ 5.34
Corporate average pricing before
risk management (C$/mcf) $ 5.19 $ 4.75 $ 5.46
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
(2) Excludes SCO.
- In Q1/10, the Western Canadian Select ("WCS") heavy crude oil
differential as a percent of WTI was 12%, compared to 16% in Q4/09.
Heavy crude oil differentials were narrow in Q1/10 as strong demand
from the US continued for heavy crude oil.
- There is an active market for Horizon SCO and the Company has
had success in selling the SCO to refiners in Edmonton and
throughout North America.
- During Q1/10, the Company contributed approximately 161,000
bbl/d of its heavy crude oil streams to the WCS blend as market
conditions resulted in optimal pricing for heavy crude oil.
FINANCIAL REVIEW
- The financial position of the Company remains robust and the
Company continually examines its liquidity position and targets a
low risk approach to finance. The implementation of its commodity
hedging policy, its existing credit facilities and capital
expenditure programs all support a flexible financial position:
-- A diverse asset base spread over various commodity types -
produced in excess of 610,000 boe/d in Q1/10, with 95% of
production located in G8 countries.
-- Financial stability and liquidity - cash flow from operations
of $1.5 billion and free cash flow, net of capital expenditures, of
over $400 million for Q1/10, with available unused bank lines of
$2.5 billion at March 31, 2010.
-- Flexibility in asset base allowing for disciplined capital
allocations.
- A strengthening balance sheet with debt to book capitalization
of 31% and debt to EBITDA of 1.3 times, both below targeted
ranges.
- Declared a quarterly cash dividend on common shares of C$0.15
per common share, payable July 1, 2010. The dividend will be
adjusted to reflect the proposed split in the Company's shares.
- Implemented a normal course issuer bid for the period from
April 6, 2010 to April 5, 2011 to purchase up to 13,581,970 common
shares (2.5%) of the common shares outstanding at March 17, 2010.
As at May 6, 2010, no common shares had been purchased for
cancellation.
- 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 to be held on
May 6, 2010. If the special resolution is passed and all regulatory
approvals are obtained, the record date for determining
shareholders entitled to participate in the subdivision is expected
to be on or about May 21, 2010 and it is expected that the common
shares will begin to trade on a subdivided basis on Toronto Stock
Exchange on or about May 19, 2010 and on the New York Stock
Exchange on or about May 28, 2010.
OUTLOOK
- The Company forecasts 2010 production levels before royalties
to average between 1,202 and 1,269 mmcf/d of natural gas and
between 405,000 and 450,000 bbl/d of crude oil and NGLs. Q2/10
production guidance before royalties is forecast to average between
1,207 and 1,232 mmcf/d of natural gas and between 394,000 and
426,000 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 www.cnrl.com.
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, 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 NGLs 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 three months ended March 31, 2010 and the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2009.
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 three months ended March 31, 2010 in
relation to the comparable period in 2009 and the fourth quarter of
2009. The accompanying tables form an integral part of this
MD&A. This MD&A is dated May 6, 2010. Additional
information relating to the Company, including its amended Annual
Information Form for the year ended December 31, 2009, 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
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Revenue, before royalties $ 3,580 $ 3,319 $ 2,186
Net earnings $ 866 $ 455 $ 305
Per common share - basic and diluted $ 1.60 $ 0.85 $ 0.56
Adjusted net earnings from operations (1) $ 658 $ 667 $ 727
Per common share - basic and diluted $ 1.21 $ 1.23 $ 1.34
Cash flow from operations (2) $ 1,505 $ 1,703 $ 1,516
Per common share - basic and diluted $ 2.77 $ 3.14 $ 2.80
Capital expenditures, net of dispositions $ 1,072 $ 694 $ 1,256
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
Mar 31 Dec 31 Mar 31
($ millions) 2010 2009 2009
----------------------------------------------------------------------------
Net earnings as reported $ 866 $ 455 $ 305
Stock-based compensation (recovery)
expense, net of tax (a)(d) (2) 65 3
Unrealized risk management (gain) loss,
net of tax (b) (154) 224 320
Unrealized foreign exchange (gain) loss,
net of tax (c) (135) (77) 118
Effect of statutory tax rate and other
legislative changes on future income
tax liabilities (d) 83 - (19)
----------------------------------------------------------------------------
Adjusted net earnings from operations $ 658 $ 667 $ 727
----------------------------------------------------------------------------
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(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. During the first quarter of 2010, the Canadian Federal budget
proposed changes to the taxation of stock options surrendered by
employees for cash payments. As a result of the proposed changes, the
Company anticipates that Canadian based employees will no longer
surrender their options for cash payments, resulting in a loss of income
tax deductions for the Company. The impact of this change was an $83
million charge to future income tax expense during the quarter. Income
tax rate changes in the first quarter of 2009 resulted in a reduction of
future income tax liabilities of approximately $19 million in North
America.
Cash Flow from Operations
Three Months Ended
Mar 31 Dec 31 Mar 31
($ millions) 2010 2009 2009
----------------------------------------------------------------------------
Net earnings $ 866 $ 455 $ 305
Non-cash items:
Depletion, depreciation and amortization 771 836 646
Asset retirement obligation accretion 26 23 19
Stock-based compensation (recovery) expense (2) 87 4
Unrealized risk management (gain) loss (208) 308 463
Unrealized foreign exchange (gain) loss (150) (88) 138
Deferred petroleum revenue tax expense
(recovery) 7 7 (3)
Future income tax expense (recovery) 195 75 (56)
----------------------------------------------------------------------------
Cash flow from operations $ 1,505 $ 1,703 $ 1,516
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the first quarter of 2010 were $866 million
compared to $305 million for the first quarter of 2009 and $455
million for the prior quarter. Net earnings for the first quarter
of 2010 included net unrealized after-tax income of $208 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 and other legislative changes on
future income tax liabilities, compared to net unrealized after-tax
expenses of $422 million for the first quarter of 2009 and net
unrealized after-tax expenses of $212 million for the prior
quarter. Excluding these items, adjusted net earnings from
operations for the first quarter of 2010 were $658 million compared
to $727 million for the first quarter of 2009 and $667 million for
the prior quarter. The decrease in adjusted net earnings from the
first quarter of 2009 was primarily due to the impact of lower
natural gas sales volumes and realized pricing, higher royalty
expense, and fluctuations in the effects of realized risk
management activities, partially offset by the impact of higher
crude oil sales volumes associated with Horizon and higher realized
crude oil pricing.
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 first quarter of 2010 was
$1,505 million compared to $1,516 million for the first quarter of
2009 and $1,703 million for the prior quarter. The decrease in cash
flow from operations from the prior quarter was primarily due to
the impact of lower natural gas sales volumes, higher royalty
expense, higher production expense related to Horizon, higher cash
taxes and the impact of realized risk management activities,
partially offset by the impact of higher crude oil sales volumes
associated with Horizon and higher realized pricing.
Total production before royalties for the first quarter of 2010
increased 9% to 610,556 boe/d from 558,142 boe/d for the first
quarter of 2009 and 6% from 574,857 boe/d for the prior quarter.
Total production for the first quarter of 2010 was within the
Company's previously issued guidance.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results
for the eight most recently completed quarters:
($ millions, except per common Mar 31 Dec 31 Sep 30 Jun 30
share amounts) 2010 2009 2009 2009
----------------------------------------------------------------------------
Revenue, before royalties $ 3,580 $ 3,319 $ 2,823 $ 2,750
Net earnings $ 866 $ 455 $ 658 $ 162
Net earnings per common share
- Basic and diluted $ 1.60 $ 0.85 $ 1.21 $ 0.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common Mar 31 Dec 31 Sep 30 Jun 30
share amounts) 2009 2008 2008 2008
----------------------------------------------------------------------------
Revenue, before royalties $ 2,186 $ 2,511 $ 4,583 $ 5,112
Net earnings (loss) $ 305 $ 1,770 $ 2,835 $ (347)
Net earnings (loss) per common share
- Basic and diluted $ 0.56 $ 3.27 $ 5.25 $ (0.65)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
and ramp up 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.
- Natural gas sales volumes - Declines in production 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, proved reserves, 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 an 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 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. The
impact of unrealized foreign exchange gains and losses are 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
Mar 31 Dec 31 Mar 31
(Quarterly Average) 2010 2009 2009
----------------------------------------------------------------------------
WTI benchmark price (US$/bbl) $ 78.79 $ 76.17 $ 43.21
Dated Brent benchmark price (US$/bbl) $ 76.32 $ 74.54 $ 44.45
WCS blend differential from WTI (US$/bbl) $ 9.06 $ 12.08 $ 8.98
WCS blend differential from WTI (%) 12% 16% 21%
SCO price (US$/bbl) (1) $ 79.37 $ 75.07 $ 44.97
Condensate benchmark price (US$/bbl) $ 84.82 $ 74.46 $ 43.44
NYMEX benchmark price (US$/mmbtu) $ 5.38 $ 4.27 $ 4.87
AECO benchmark price (C$/GJ) $ 5.07 $ 4.01 $ 5.34
US / Canadian dollar average exchange rate $ 0.9615 $ 0.9468 $ 0.8028
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Synthetic Crude Oil ("SCO")
Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$78.79 per
bbl for the first quarter of 2010, an increase of 82% from US$43.21
per bbl for the first quarter of 2009, and 3% from US$76.17 per bbl
for the prior quarter. WTI pricing was reflective of the overall
balanced supply and demand environment, with strong Asian demand
offsetting the demand decline related to the Organization of
Economic Co-operation and Development (OECD).
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. Brent averaged US$76.32
per bbl for the first quarter of 2010, an increase of 72% compared
to US$44.45 per bbl for the first quarter of 2009, and 2% from
US$74.54 per bbl for the prior quarter.
The Western Canadian Select ("WCS") Heavy Differential averaged
12% for the first quarter of 2010, compared to 21% for the first
quarter of 2009 and 16% 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
the near term economic recovery. The Heavy Differential is expected
to continue to reflect seasonal demand fluctuations and refinery
margins.
NYMEX natural gas prices averaged US$5.38 per mmbtu for the
first quarter of 2010, an increase of 10% from US$4.87 per mmbtu
for the first quarter of 2009, and 26% from US$4.27 per mmbtu for
the prior quarter. AECO natural gas prices for the first quarter of
2010 decreased 5% to average $5.07 per GJ from $5.34 per GJ in the
first quarter of 2009, and increased 26% from $4.01 per GJ for the
prior quarter. The weather patterns in the first quarter of 2010
resulted in stronger demand in the Northeast part of the United
States and weaker demand in the Western part of North America,
supporting a relatively higher pricing level over the last quarter.
The stronger Canadian dollar negatively impacted the realized price
at AECO in the first quarter of 2010 compared to the first quarter
of 2009.
Update to Alberta Royalty Framework
On January 1, 2009, changes to the Alberta royalty regime under
the Alberta Royalty Framework ("ARF") came into effect, including
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, on January 1, 2009, new royalty formulas under the
ARF for conventional crude oil and natural gas, specifying
royalties on sliding scales ranging up to 50%, depending on
commodity prices and well productivity, came into effect.
In March 2010, the Government of Alberta modified the
conventional crude oil and natural gas royalty rates. These
changes, effective January 1, 2011, include:
- A reduction in the maximum royalty rate to 5% on new natural
gas and conventional crude oil wells for the first 12 months after
the start of production, subject to volume limits of 500 mmcfe and
50,000 boe respectively.
- A reduction in the maximum royalty rate for conventional crude
oil from 50% to 40% and a reduction in the maximum royalty rate for
conventional and unconventional natural gas from 50% to 36%.
Additional changes to the ARF, including potential further
changes to conventional crude oil and natural gas royalty curves,
are expected to be finalized and announced by May 31, 2010.
DAILY PRODUCTION, before royalties
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America - Conventional 252,450 229,206 253,833
North America - Oil Sands Mining
and Upgrading 86,995 70,194 3,384
North Sea 36,879 34,408 42,369
Offshore West Africa 29,942 32,643 30,431
----------------------------------------------------------------------------
406,266 366,451 330,017
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,193 1,218 1,347
North Sea 15 12 10
Offshore West Africa 18 20 12
----------------------------------------------------------------------------
1,226 1,250 1,369
----------------------------------------------------------------------------
Total barrels of oil equivalent (boe/d) 610,556 574,857 558,142
----------------------------------------------------------------------------
Product mix
Light/medium crude oil and NGLs 19% 20% 22%
Pelican Lake crude oil 6% 7% 6%
Primary heavy crude oil 15% 15% 15%
Thermal heavy crude oil 12% 10% 15%
Synthetic crude oil 14% 12% 1%
Natural gas 34% 36% 41%
----------------------------------------------------------------------------
Percentage of gross revenue (1)
(excluding midstream revenue)
Crude oil and NGLs 82% 82% 64%
Natural gas 18% 18% 36%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation and blending costs and excluding risk management
activities.
DAILY PRODUCTION, net of royalties
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America - Conventional 206,094 195,070 224,506
North America - Oil Sands Mining
and Upgrading 83,918 67,806 3,362
North Sea 36,803 34,341 42,265
Offshore West Africa 28,927 30,296 28,341
----------------------------------------------------------------------------
355,742 327,513 298,474
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,101 1,135 1,180
North Sea 15 12 10
Offshore West Africa 17 19 11
----------------------------------------------------------------------------
1,133 1,166 1,201
----------------------------------------------------------------------------
Total barrels of oil equivalent (boe/d) 544,553 521,894 498,740
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 first quarter of
2010 increased 23% to 406,266 bbl/d from 330,017 bbl/d for the
first quarter of 2009, and 11% from 366,451 bbl/d for the prior
quarter. The increase from the first quarter in 2009 was primarily
due to the commencement of production from Horizon. The increase
from the prior quarter was in line with expectations and primarily
related to the cyclic nature of the Company's thermal production
and increased Horizon production. Crude oil and NGLs production in
the first quarter of 2010 was at the high end of the Company's
previously issued guidance of 372,000 to 409,000 bbl/d.
Natural gas production for the first quarter of 2010 decreased
10% to 1,226 mmcf/d compared to 1,369 mmcf/d for the first quarter
of 2009 and 2% from 1,250 mmcf/d for the prior quarter. The
decrease in natural gas production from the comparable periods
reflects the expected production declines due to the allocation of
capital to higher return crude oil projects resulting in a
strategic reduction of natural gas drilling activity. Natural gas
production in the first quarter of 2010 exceeded the Company's
previously issued guidance of 1,197 to 1,221 mmcf/d.
For 2010, annual production guidance is targeted to average
between 405,000 and 450,000 bbl/d of crude oil and NGLs and between
1,202 and 1,269 mmcf/d of natural gas. Second quarter 2010
production guidance is targeted to average between 394,000 and
426,000 bbl/d of crude oil and NGLs and between 1,207 and 1,232
mmcf/d of natural gas.
North America - Conventional
First quarter North America conventional crude oil and NGLs
production averaged 252,450 bbl/d, comparable to 253,833 bbl/d for
the first quarter of 2009, and increased 10% from 229,206 bbl/d for
the prior quarter. The fluctuations in crude oil and NGLs
production 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 exceeded the Company's previously
issued guidance of 240,000 bbl/d to 250,000 bbl/d for the first
quarter of 2010.
For the first quarter of 2010, natural gas production decreased
11% to 1,193 mmcf/d from 1,347 mmcf/d for the first quarter of
2009, and 2% from 1,218 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 and
allocate capital to higher return projects. Production of natural
gas exceeded the Company's previously issued guidance of 1,165
mmcf/d to 1,185 mmcf/d for the first quarter of 2010.
North America - Oil Sands Mining and Upgrading
Horizon Phase 1 commenced production of synthetic crude oil
during 2009. Production averaged 86,995 bbl/d for the first quarter
of 2010, up 24% from 70,194 bbl/d in the prior quarter. Production
volumes fluctuated throughout the quarter as the Company continued
to focus on stabilizing and ramping up production. First quarter
production for 2010 was at the high end of the Company's previously
issued guidance of 70,000 bbl/d to 90,000 bbl/d.
North Sea
First quarter 2010 North Sea crude oil production decreased 13%
to 36,879 bbl/d from 42,369 bbl/d for the first quarter of 2009 and
increased 7% from 34,408 bbl/d for the prior quarter. Production in
the first quarter of 2010 was at the high end of the Company's
previously issued guidance of 34,000 bbl/d to 37,000 bbl/d
primarily due to improved uptime and well performance from the
Ninian Platforms.
Offshore West Africa
First quarter 2010 Offshore West Africa crude oil production
decreased 2% to 29,942 bbl/d from 30,431 bbl/d for the first
quarter of 2009, and 8% from 32,643 bbl/d for the prior quarter.
Production in the first quarter was within the Company's previously
issued guidance of 28,000 bbl/d to 32,000 bbl/d and was impacted by
a planned shutdown at Espoir for installation of facilities
upgrades.
The Company is currently drilling the second platform (Platform
B) at the Olowi Field, Offshore Gabon with 3 gross wells drilled
and completed and first Platform B crude oil achieved in April
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:
Mar 31 Dec 31 Mar 31
(bbl) 2010 2009 2009
----------------------------------------------------------------------------
North America - Conventional 761,351 1,131,372 761,351
North America - Oil Sands Mining and
Upgrading (SCO) 1,021,028 1,224,481 304,544
North Sea 642,457 713,112 1,305,169
Offshore West Africa(1) 898,233 51,103 373,103
----------------------------------------------------------------------------
3,323,069 3,120,068 2,744,167
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) March 31, 2009 inventory volumes include a one-time adjustment to sales
volumes for MD&A reporting purposes only.
OPERATING HIGHLIGHTS - CONVENTIONAL
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
Sales price (2) $ 68.76 $ 68.00 $ 41.25
Royalties 10.08 7.96 3.98
Production expense 14.56 15.45 15.02
----------------------------------------------------------------------------
Netback $ 44.12 $ 44.59 $ 22.25
----------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 5.19 $ 4.75 $ 5.46
Royalties (3) 0.41 0.35 0.72
Production expense 1.20 1.03 1.18
----------------------------------------------------------------------------
Netback $ 3.58 $ 3.37 $ 3.56
----------------------------------------------------------------------------
Barrels of oil equivalent ($/boe) (1)
Sales price (2) $ 53.88 $ 51.95 $ 37.87
Royalties 7.07 5.60 4.14
Production expense 11.67 11.72 11.77
----------------------------------------------------------------------------
Netback $ 35.14 $ 34.63 $ 21.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) (2)
North America $ 66.18 $ 65.12 $ 37.40
North Sea $ 80.53 $ 78.89 $ 54.67
Offshore West Africa $ 79.30 $ 72.88 $ 54.27
Company average $ 68.76 $ 68.00 $ 41.25
Natural gas ($/mcf) (1) (2)
North America $ 5.20 $ 4.75 $ 5.46
North Sea $ 4.30 $ 4.94 $ 4.28
Offshore West Africa $ 5.56 $ 5.04 $ 6.68
Company average $ 5.19 $ 4.75 $ 5.46
Company average ($/boe) (1) (2) $ 53.88 $ 51.95 $ 37.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 increased 77% to average
$66.18 per bbl for the first quarter of 2010 from $37.40 per bbl
for the first quarter of 2009, and 2% from $65.12 per bbl for the
prior quarter. The increase from the comparable quarters was
primarily a result of increased WTI benchmark pricing and the
impact of the narrow Heavy Differential, 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 first quarter of 2010 contributed
approximately 161,000 bbl/d of heavy crude oil blends to the WCS
stream.
In the first quarter of 2010, the Company 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. The Alberta
Government is expected to announce the successful bid later in
2010.
North America realized natural gas prices decreased 5% to
average $5.20 per mcf for the first quarter of 2010 from $5.46 per
mcf for the first quarter of 2009, and increased 9% from $4.75 per
mcf for the prior quarter. The decrease in natural gas prices from
the first quarter of 2009 was primarily related to lower benchmark
prices due to lower demand and high storage levels, and the impact
of the stronger Canadian dollar relative to the US dollar. The
increase in natural gas prices from the prior quarter was primarily
related to seasonality of demand.
Comparisons of the prices received for the Company's North
America conventional production by product type were as
follows:
Mar 31 Dec 31 Mar 31
(Quarterly Average) 2010 2009 2009
----------------------------------------------------------------------------
Wellhead Price (1) (2)
Light/medium crude oil and NGLs ($/bbl) $ 72.15 $ 67.30 $ 45.97
Pelican Lake crude oil ($/bbl) $ 66.04 $ 63.75 $ 37.50
Primary heavy crude oil ($/bbl) $ 66.45 $ 65.46 $ 37.99
Thermal heavy crude oil ($/bbl) $ 62.08 $ 63.62 $ 31.53
Natural gas ($/mcf) $ 5.20 $ 4.75 $ 5.46
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North Sea
North Sea realized crude oil prices increased 47% to average
$80.53 per bbl for the first quarter of 2010 from $54.67 per bbl
for the first quarter of 2009, and 2% from $78.89 per bbl for the
prior quarter. The increase in realized crude oil prices in the
North Sea from the prior periods 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 increased 46% to
average $79.30 per bbl for the first quarter of 2010 from $54.27
per bbl for the first quarter of 2009, and 9% from $72.88 per bbl
for the prior quarter. The increase in realized crude oil prices in
Offshore West Africa from the prior periods was primarily the
result of increased Brent benchmark pricing, partially offset by
the impact of the stronger Canadian dollar. Realized crude oil
prices in Offshore West Africa were also impacted by the timing of
liftings from each field.
ROYALTIES - CONVENTIONAL
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
North America $ 12.13 $ 9.88 $ 4.54
North Sea $ 0.17 $ 0.15 $ 0.13
Offshore West Africa $ 2.69 $ 5.24 $ 3.73
Company average $ 10.08 $ 7.96 $ 3.98
Natural gas ($/mcf) (1)
North America (2) $ 0.41 $ 0.35 $ 0.73
Offshore West Africa $ 0.19 $ 0.27 $ 0.46
Company average $ 0.41 $ 0.35 $ 0.72
Company average ($/boe) (1) $ 7.07 $ 5.60 $ 4.14
Percentage of revenue (3)
Crude oil and NGLs 15% 12% 10%
Natural gas (2) 8% 7% 13%
Boe 13% 11% 11%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 three months ended March 31,
2010 compared to 2009 reflect stronger realized commodity prices
and the impact of the changes under the ARF.
Crude oil and NGLs royalties averaged approximately 18% of
revenues for the first quarter of 2010, compared to 12% for the
first quarter in 2009 and 15% for 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 8% of revenues for
the first quarter of 2010 compared to 13% for the first quarter of
2009 and 7% for the prior quarter. The decrease in natural gas
royalty rates for the first quarter of 2010 compared to the prior
year was due to the impact of low natural gas benchmark pricing.
Natural gas royalties are anticipated to average 6% to 8% 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 3% for the first
quarter of 2010 compared to 7% for the first quarter of 2009 and
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
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
North America $ 13.09 $ 13.44 $ 14.60
North Sea $ 25.15 $ 27.03 $ 22.39
Offshore West Africa $ 13.49 $ 15.26 $ 11.39
Company average $ 14.56 $ 15.45 $ 15.02
Natural gas ($/mcf) (1)
North America $ 1.17 $ 1.01 $ 1.17
North Sea $ 3.54 $ 3.23 $ 1.86
Offshore West Africa $ 1.63 $ 0.70 $ 1.70
Company average $ 1.20 $ 1.03 $ 1.18
Company average ($/boe) (1) $ 11.67 $ 11.72 $ 11.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
first quarter of 2010 decreased 10% to $13.09 per bbl from $14.60
per bbl for the first quarter of 2009 and 3% from $13.44 per bbl
for the prior quarter. The decrease in production expense per
barrel for the first quarter of 2010 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 first
quarter of 2010 averaged $1.17 per mcf and was comparable to the
first quarter of 2009 and increased 16% from $1.01 per mcf for the
prior quarter. The increase in production expense per mcf from the
prior quarter was primarily a result of the impact of normal
seasonal costs associated with winter access and colder weather and
lower production volumes on fixed costs. The Company continues to
focus on optimizing service costs. 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 lower maintenance activities and improved
performance from the Ninian Platforms. Production expense for the
first quarter of 2010 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 on a per barrel basis due to the timing of liftings
of each field, and higher operating costs associated with Gabon
coming on stream in 2009. Offshore West Africa crude oil production
expense decreased from the prior quarter on a per barrel basis due
to the timing of liftings of each field. Production expense is
anticipated to average $14.00 to $17.00 per bbl for 2010.
DEPLETION, DEPRECIATION AND AMORTIZATION - CONVENTIONAL
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Expense ($ millions) $ 679 $ 754 $ 661
$/boe (1) $ 14.52 $ 15.68 $ 13.21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
The increase in Depletion, Depreciation and Amortization expense
from the previous year was due to the increase in the estimated
future costs to develop the Company's proved undeveloped reserves
in the North Sea. The decrease in Conventional Depletion,
Depreciation and Amortization expense from the prior quarter was
primarily due to the impact of an impairment related to Gabon,
Offshore West Africa recorded in the fourth quarter of 2009, offset
by the impact of higher production.
ASSET RETIREMENT OBLIGATION ACCRETION - CONVENTIONAL
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Expense ($ millions) $ 20 $ 17 $ 17
$/boe (1) $ 0.43 $ 0.36 $ 0.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
Mar 31 Dec 31 Mar 31
($/bbl) (1) 2010 2009 2009
----------------------------------------------------------------------------
SCO sales price (2) $ 78.76 $ 76.33 $ -
Bitumen value for royalty purposes (3) $ 61.33 $ 58.90 $ -
Bitumen royalties (4) $ 2.83 $ 3.06 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation.
(3) Calculated as the simple average of the monthly bitumen
valuation methodology price.
(4) 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
throughout North America.
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
Mar 31 Dec 31 Mar 31
($ millions) 2010 2009 2009
----------------------------------------------------------------------------
Cash costs, excluding natural gas costs $ 299 $ 228 $ -
Natural gas costs 47 31 -
----------------------------------------------------------------------------
Total cash production costs $ 346 $ 259 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended
Mar 31 Dec 31 Mar 31
($/bbl) (1) 2010 2009 2009
----------------------------------------------------------------------------
Cash costs, excluding natural gas costs $ 37.29 $ 36.23 $ -
Natural gas costs 5.83 4.98 -
----------------------------------------------------------------------------
Total cash production costs $ 43.12 $ 41.21 $ -
----------------------------------------------------------------------------
Sales (bbl/d) 89,256 68,140 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $43.12 per bbl in the first
quarter of 2010 compared to $41.21 per bbl for the fourth quarter
of 2009. The increase in cash production costs was primarily due to
unplanned maintenance activities including costs associated with
the coker furnace repairs, increased property taxes and the impact
of changes in product inventory carrying costs in the quarter. As
production volumes are targeted to stabilize throughout 2010, cash
production costs are expected to decrease in line with the
previously issued annual guidance of $31.00 to $37.00 per bbl for
2010.
Three Months Ended
Mar 31 Dec 31 Mar 31
($ millions) 2010 2009 2009
----------------------------------------------------------------------------
Depreciation, depletion and amortization $ 90 $ 83 $ 2
Asset retirement obligation accretion 6 6 2
----------------------------------------------------------------------------
Total $ 96 $ 89 $ 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended
Mar 31 Dec 31 Mar 31
($/bbl) (1) 2010 2009 2009
----------------------------------------------------------------------------
Depreciation, depletion and amortization $ 11.22 $ 13.28 $ -
Asset retirement obligation accretion 0.69 1.00 -
----------------------------------------------------------------------------
Total $ 11.91 $ 14.28 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, depreciation and amortization per barrel decreased in
the first quarter of 2010, due to the impact of increased
production on the component of depreciation determined on a
straight-line basis.
MIDSTREAM
Three Months Ended
Mar 31 Dec 31 Mar 31
($ millions) 2010 2009 2009
----------------------------------------------------------------------------
Revenue $ 19 $ 18 $ 19
Production expense 5 5 5
----------------------------------------------------------------------------
Midstream cash flow 14 13 14
Depreciation 2 3 2
----------------------------------------------------------------------------
Segment earnings before taxes $ 12 $ 10 $ 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable periods.
ADMINISTRATION EXPENSE
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Expense ($ millions) $ 54 $ 49 $ 47
$/boe (1) $ 0.99 $ 0.92 $ 0.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the first quarter of 2010 increased from the
comparative quarters due to higher staffing related costs.
STOCK-BASED COMPENSATION EXPENSE
Three Months Ended
Mar 31 Dec 31 Mar 31
($ millions) 2010 2009 2009
----------------------------------------------------------------------------
(Recovery) expense $ (2) $ 87 $ 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company recorded a $2 million ($2 million after-tax)
stock-based compensation recovery for the three months ended March
31, 2010 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 a 1% decrease in
the Company's share price (Company's share price as at: March 31,
2010 - $75.17; December 31, 2009 - $76.00; March 31, 2009 - $48.91;
December 31, 2008 - $48.75). For the three months ended March 31,
2010, the Company capitalized $2 million in stock-based
compensation to Oil Sands Mining and Upgrading (March 31, 2009 - $9
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
March 31, 2010.
The Company's Stock Option Plan (the "Option Plan") provides
current employees with the right to receive common shares or a
direct cash payment in exchange for options surrendered. As a
result of recently proposed changes to Canadian income tax
legislation related to the cash surrender of options, the Company
anticipates that Canadian based employees will now choose to
exercise their options to receive newly issued common shares rather
than surrender their options for cash payment.
For the three months ended March 31, 2010, the Company paid $36
million for stock options surrendered for cash settlement (March
31, 2009 - $28 million).
INTEREST EXPENSE
Three Months Ended
Mar 31 Dec 31 Mar 31
($ millions, except per boe amounts) 2010 2009 2009
----------------------------------------------------------------------------
Expense, gross $ 118 $ 119 $ 143
Less: capitalized interest, Oil Sands
Mining and Upgrading 7 8 86
----------------------------------------------------------------------------
Expense, net $ 111 $ 111 $ 57
$/boe (1) $ 2.02 $ 2.06 $ 1.14
Average effective interest rate 4.7% 4.5% 4.4%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest expense decreased from the comparable periods in
2009 primarily due to lower variable interest rates and debt
levels, and reflected the impact of fluctuations in foreign
exchange rates on US dollar denominated debt. The Company's average
effective interest rate increased from the comparable periods in
2009 primarily due to increased weighting of fixed versus floating
rate debt, partially offset by 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
Mar 31 Dec 31 Mar 31
($ millions) 2010 2009 2009
----------------------------------------------------------------------------
Crude oil and NGLs financial instruments $ 17 $ (148) $ (585)
Natural gas financial instruments (18) - (32)
Foreign currency contracts and interest
rate swaps 40 26 (24)
----------------------------------------------------------------------------
Realized loss (gain) $ 39 $ (122) $ (641)
----------------------------------------------------------------------------
Crude oil and NGLs financial instruments $ (73) $ 328 $ 483
Natural gas financial instruments (130) (17) (24)
Foreign currency contracts and interest
rate swaps (5) (3) 4
----------------------------------------------------------------------------
Unrealized (gain) loss $ (208) $ 308 $ 463
----------------------------------------------------------------------------
Net (gain) loss $ (169) $ 186 $ (178)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Complete details related to outstanding derivative financial
instruments at March 31, 2010 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 gain of $208 million ($154
million after-tax) on its risk management activities for the three
months ended March 31, 2010 (December 31, 2009 - unrealized loss of
$308 million, $224 million after-tax; March 31, 2009 - unrealized
loss of $463 million, $320 million after-tax).
FOREIGN EXCHANGE
Three Months Ended
Mar 31 Dec 31 Mar 31
($ millions) 2010 2009 2009
----------------------------------------------------------------------------
Net realized (gain) loss $ (10) $ 4 $ (15)
Net unrealized (gain) loss (1) (150) (88) 138
----------------------------------------------------------------------------
Net (gain) loss $ (160) $ (84) $ 123
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net unrealized foreign exchange gain for the three months
ended March 31, 2010 was primarily due to the strengthening
Canadian dollar with respect to the US dollar debt, and 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 partially offset by the cross
currency swaps (three months ended March 31, 2010 - unrealized loss
of $59 million; December 31, 2009 - unrealized loss of $48 million,
three months ended March 31, 2009 - unrealized gain of $68
million). The net realized foreign exchange gain for the three
months ended March 31, 2010 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 first quarter at US$0.9846 (December 31, 2009 -
US$0.9555; March 31, 2009 - US$0.7935).
TAXES
Three Months Ended
Mar 31 Dec 31 Mar 31
($ millions, except income tax rates) 2010 2009 2009
----------------------------------------------------------------------------
Current $ 32 $ 25 $ 7
Deferred 7 7 (3)
----------------------------------------------------------------------------
Taxes other than income tax $ 39 $ 32 $ 4
----------------------------------------------------------------------------
North America (1) $ 129 $ 11 $ 5
North Sea 53 60 98
Offshore West Africa 6 23 14
----------------------------------------------------------------------------
Current income tax 188 94 117
Future income tax expense (recovery) 195 75 (56)
----------------------------------------------------------------------------
383 169 61
Income tax rate and other legislative
changes (2) (83) - 19
----------------------------------------------------------------------------
$ 300 $ 169 $ 80
----------------------------------------------------------------------------
Effective income tax rate on adjusted net
earnings from operations 26.0% 28.4% 25.1%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Conventional Crude Oil and Natural Gas,
Midstream, and Oil Sands Mining and Upgrading segments.
(2) During the first quarter of 2010, the Canadian Federal budget proposed
changes to the taxation of stock options surrendered by employees for
cash payments. As a result of the proposed changes, the Company
anticipates that Canadian based employees will no longer surrender their
options for cash payments, resulting in a loss of income tax deductions
for the Company. The impact of this change was an $83 million charge to
future income tax expense during the quarter. Income tax rate changes in
the first quarter of 2009 include the effect of a recovery of $19
million due to British Columbia corporate income tax rate reductions
substantively enacted or enacted.
Taxes other than income tax primarily includes current and
deferred Petroleum Revenue Tax ("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 and Offshore West Africa of $220 million to $260 million.
NET CAPITAL EXPENDITURES (1)
Three Months Ended
Mar 31 Dec 31 Mar 31
($ millions) 2010 2009 2009
----------------------------------------------------------------------------
Expenditures on property, plant and
equipment
Net property acquisitions (dispositions) $ 36 $ 11 $ 27
Land acquisition and retention 38 28 13
Seismic evaluations 33 13 28
Well drilling, completion and equipping 442 291 498
Production and related facilities 382 222 290
----------------------------------------------------------------------------
Total net reserve replacement expenditures 931 565 856
----------------------------------------------------------------------------
Oil Sands Mining and Upgrading:
Horizon Phase 1 construction costs - - 128
Horizon Phase 1 commissioning and other
costs - - 156
Horizon Phases 2/3 construction costs 71 42 19
Capitalized interest, stock-based
compensation and other 9 12 79
Sustaining capital 18 53 -
----------------------------------------------------------------------------
Total Oil Sands Mining and Upgrading (2) 98 107 382
----------------------------------------------------------------------------
Midstream - 1 5
Abandonments (3) 39 17 9
Head office 4 4 4
----------------------------------------------------------------------------
Total net capital expenditures $ 1,072 $ 694 $ 1,256
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 809 $ 436 $ 599
North Sea 23 48 42
Offshore West Africa 99 80 215
Other - 1 -
Oil Sands Mining and Upgrading 98 107 382
Midstream - 1 5
Abandonments (3) 39 17 9
Head office 4 4 4
----------------------------------------------------------------------------
Total $ 1,072 $ 694 $ 1,256
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 three months ended March 31,
2010 were $1,072 million compared to $1,256 million for the three
months ended March 31, 2009. The decrease in capital expenditures
from the prior year reflects the completion of Horizon Phase 1
construction in 2009.
Drilling Activity (number of wells)
Three Months Ended
Mar 31 Dec 31 Mar 31
2010 2009 2009
----------------------------------------------------------------------------
Net successful natural gas wells 45 28 64
Net successful crude oil wells 243 195 93
Dry wells 14 17 15
Stratigraphic test / service wells 297 80 236
----------------------------------------------------------------------------
Total 599 320 408
Success rate
(excluding stratigraphic test / service
wells) 95% 93% 91%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America
North America, excluding Oil Sands Mining and Upgrading,
accounted for approximately 79% of the total capital expenditures
for the three months ended March 31, 2010 compared to approximately
49% for the three months ended March 31, 2009.
During the first quarter of 2010, the Company targeted 49 net
natural gas wells, including 14 wells in Northeast British
Columbia, 15 wells in the Northern Plains region, 19 wells in
Northwest Alberta, and 1 well in the Southern Plains region. The
Company also targeted 250 net crude oil wells. The majority of
these wells were concentrated in the Company's crude oil Northern
Plains region where 150 heavy crude oil wells, 74 Pelican Lake
crude oil wells, and 7 light crude oil wells were drilled. Another
19 wells targeting light crude oil were drilled outside the
Northern Plains region.
The Company has entered into a number of agreements to purchase
crude oil and natural gas properties in its core regions in Western
Canada aggregating approximately $1 billion. Subject to receipt of
any required regulatory approvals and any applicable rights of
first refusal, the majority of these acquisitions are expected to
close late in the second quarter of 2010, and corporate guidance
has been revised accordingly.
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 first quarter of 2010
averaged approximately 76,000 bbl/d, compared to approximately
82,000 bbl/d for the first quarter of 2009 and approximately 57,000
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 first quarter of 2009. 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. The Company is continuing to work with regulators to commence
normal steaming.
The next planned phase of the Company's In-Situ Oil Sands Assets
expansion is the Kirby Project. Final project scope and corporate
sanction 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 first
quarter of 2010. Drilling included 28 horizontal wells in the first
quarter. The response from the water and polymer flood projects
continues to be positive. Pelican Lake production averaged
approximately 37,000 bbl/d for the first quarter of 2010,
consistent with the first quarter of 2009 and 38,000 bbl/day for
the prior quarter.
For the second quarter of 2010, the Company's overall planned
drilling activity in North America is expected to be comprised of
11 natural gas wells and 113 crude oil wells, excluding
stratigraphic and service wells.
Oil Sands Mining and Upgrading
Limited Phase 2/3 spending during the quarter was focused on the
construction of the third Ore Preparation Plant, the Mine
Maintenance Shop and additional product tankage.
North Sea
In the first quarter of 2010, the Company continued preparation
for platform drilling, which commenced as planned in April. The
Company continues to focus on developing and high grading its
inventory of drilling locations for future execution.
Offshore West Africa
During the first quarter of 2010, 2.8 net crude oil wells were
drilled on Platform B at Olowi. Final commissioning of Platform B
was completed and first crude oil production was achieved in April
2010. Drilling continues on Platform B and development activities
are proceeding on the third platform (Platform A).
At Espoir the lift of the facilities upgrade modules onto the
FPSO was completed on schedule and work continues towards
completion of the upgrade in the second quarter, with associated
production uplift anticipated in the third quarter of 2010. Also in
the second quarter of 2010, the Company will be conducting a
planned maintenance shutdown and the upgrade on the Espoir
FPSO.
LIQUIDITY AND CAPITAL RESOURCES
Mar 31 Dec 31 Mar 31
($ millions, except ratios) 2010 2009 2009
----------------------------------------------------------------------------
Working capital (deficit) (1) $ (534) $ (514) $ 237
Long-term debt (2) (3) $ 8,939 $ 9,658 $ 13,132
Share capital $ 2,939 $ 2,834 $ 2,809
Retained earnings 17,481 16,696 15,592
Accumulated other comprehensive (loss)
income (152) (104) 315
----------------------------------------------------------------------------
Shareholders' equity $ 20,268 $ 19,426 $ 18,716
Debt to book capitalization (3) (4) 31% 33% 41%
Debt to market capitalization (3) (5) 18% 19% 33%
After tax return on average common
shareholders' equity (6) 11% 8% 28%
After tax return on average capital
employed (3) (7) 8% 6% 17%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 (March 31, 2010 - $nil;
December 31, 2009 - $nil; March 31, 2009 - $205 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.
At March 31, 2010, 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, 2009 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 March 31, 2010, the Company had $2,516 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, Inc., and BBB
with a stable outlook by Standard & Poor's Corporation.
Further details related to the Company's long-term debt at March
31, 2010 are discussed in note 4 to the Company's unaudited interim
consolidated financial statements.
Long-term debt was $8,939 million at March 31, 2010, resulting
in a debt to book capitalization ratio of 31%
(December 31, 2009 - 33%; March 31, 2009 - 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.
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 March 31,
2010, in accordance with the policy, approximately 34% of budgeted
crude oil volumes and approximately 39% of budgeted natural gas
volumes were hedged using collars for the remainder of 2010.
Further details related to the Company's commodity related
derivative financial instruments outstanding at March 31, 2010 are
discussed in note 11 to the Company's unaudited interim
consolidated financial statements.
Share capital
As at March 31, 2010, there were 543,762,000 common shares
outstanding and 29,823,000 stock options outstanding. As at May 5,
2010, the Company had 544,350,000 common shares outstanding and
29,067,000 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 $0.60 per
common share for 2010. The increase represented a 43% increase from
2009, recognizes the stability of the Company's cash flow, and
provides a return to Shareholders. The dividend policy undergoes a
periodic review by the Board of Directors and is subject to
change.
In 2010, the Company announced a Normal Course Issuer Bid to
purchase, through the facilities of the Toronto Stock Exchange
("TSX") and the New York Stock Exchange ("NYSE"), during the 12
month period commencing April 6, 2010 and ending April 5, 2011, up
to 13,581,970 common shares or 2.5% of the common shares of the
Company outstanding at March 17, 2010. As at May 6, 2010, no common
shares had been purchased for cancellation.
Share split
On March 3, 2010, the Company's Board of Directors approved a
resolution to subdivide the Company's common shares on a two for
one basis, subject to shareholder approval. The proposal will be
voted on at the Company's Annual and Special Meeting of
Shareholders to be held on May 6, 2010. If the special resolution
is passed and all regulatory approvals are obtained, the record
date for determining shareholders entitled to participate in the
subdivision is expected to be on or about May 21, 2010, and it is
expected that the common shares will begin to trade on a subdivided
basis on the TSX on or about May 19, 2010 and on the NYSE on or
about May 28, 2010.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. As at March 31, 2010, no entities were
consolidated under the Canadian Institute of Chartered Accountants
Handbook Accounting Guideline 15, "Consolidation of Variable
Interest Entities". The following table summarizes the Company's
commitments as at March 31, 2010:
Remaining
($ millions) 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Product transportation and
pipeline $ 160 $ 172 $ 144 $ 134 $ 135 $ 1,060
Offshore equipment
operating leases $ 116 $ 121 $ 100 $ 98 $ 98 $ 254
Offshore drilling $ 34 $ - $ - $ - $ - $ -
Asset retirement
obligations (1) $ 12 $ 20 $ 21 $ 31 $ 39 $ 6,423
Long-term debt (2) $ 400 $ 406 $ 355 $ 806 $ 355 $ 5,276
Interest expense (3) $ 316 $ 435 $ 400 $ 360 $ 340 $ 4,627
Office leases $ 19 $ 19 $ 3 $ 2 $ 2 $ 2
Other $ 211 $ 65 $ 19 $ 14 $ 12 $ 33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 estimated minimum expenditures required
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 $1,369 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 March 31, 2010.
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, 2009.
For the impact of new accounting standards, refer to note 2 of
the unaudited interim consolidated financial statements as at March
31, 2010.
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 finalizing 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 system
processes and 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 March 31, 2010.
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 2009 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
not required.
- Impairment of PP&E will be tested at a cash generating
unit level (the lowest level at which cash inflows can be
separately 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. After initial adoption, future impairment charges may be
reversed.
Asset Retirement Obligations
Canadian GAAP accounting requirements for asset retirement
obligations ("ARO") are discussed in the "Critical Accounting
Estimates" section of the 2009 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 first quarter of 2010,
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 $ 112 $ 0.21 $ 91 $ 0.17
Including financial
derivatives $ 98 $ 0.18 $ 81 $ 0.15
Natural gas - AECO
C$0.10/mcf (1)
Excluding financial
derivatives $ 31 $ 0.06 $ 23 $ 0.04
Including financial
derivatives $ 26 $ 0.05 $ 19 $ 0.03
Volume changes
Crude oil - 10,000
bbl/d $ 161 $ 0.30 $ 104 $ 0.19
Natural gas - 10
mmcf/d $ 13 $ 0.02 $ 4 $ 0.01
Foreign currency rate
change
$0.01 change in US$ (1)
Including financial
derivatives $ 101 - 103 $ 0.19 $ 37 $ 0.07
Interest rate change
- 1% $ 9 $ 0.02 $ 9 $ 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
Mar 31 Dec 31
(millions of Canadian dollars, unaudited) 2010 2009
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 21 $ 13
Accounts receivable 1,324 1,148
Inventory, prepaids and other 640 584
Future income tax - 146
Current portion of other long-term assets
(note 3) 22 -
----------------------------------------------------------------------------
2,007 1,891
Property, plant and equipment (note 13) 39,252 39,115
Other long-term assets (note 3) 45 18
----------------------------------------------------------------------------
$ 41,304 $ 41,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 269 $ 240
Accrued liabilities 1,914 1,522
Future income tax 5 -
Current portion of other long-term
liabilities (note 5) 353 643
----------------------------------------------------------------------------
2,541 2,405
Long-term debt (note 4) 8,939 9,658
Other long-term liabilities (note 5) 1,878 1,848
Future income tax 7,678 7,687
----------------------------------------------------------------------------
21,036 21,598
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 7) 2,939 2,834
Retained earnings 17,481 16,696
Accumulated other comprehensive loss (note 8) (152) (104)
----------------------------------------------------------------------------
20,268 19,426
----------------------------------------------------------------------------
$ 41,304 $ 41,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (note 12)
Consolidated Statements of Earnings
Three Months Ended
(millions of Canadian dollars, except per Mar 31 Mar 31
common share amounts, unaudited) 2010 2009
----------------------------------------------------------------------------
Revenue $ 3,580 $ 2,186
Less: royalties (353) (199)
----------------------------------------------------------------------------
Revenue, net of royalties 3,227 1,987
----------------------------------------------------------------------------
Expenses
Production 894 582
Transportation and blending 414 317
Depletion, depreciation and amortization 771 646
Asset retirement obligation accretion (note 5) 26 19
Administration 54 47
Stock-based compensation (recovery) expense
(note 5) (2) 4
Interest, net 111 57
Risk management activities (note 11) (169) (178)
Foreign exchange (gain) loss (160) 123
----------------------------------------------------------------------------
1,939 1,617
----------------------------------------------------------------------------
Earnings before taxes 1,288 370
Taxes other than income tax 39 4
Current income tax expense (note 6) 188 117
Future income tax expense (recovery) (note 6) 195 (56)
----------------------------------------------------------------------------
Net earnings $ 866 $ 305
----------------------------------------------------------------------------
Net earnings per common share (note 10)
Basic and diluted $ 1.60 $ 0.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Shareholders' Equity
Three Months Ended
Mar 31 Mar 31
(millions of Canadian dollars, unaudited) 2010 2009
----------------------------------------------------------------------------
Share capital (note 7)
Balance - beginning of period $ 2,834 $ 2,768
Issued upon exercise of stock options 40 16
Previously recognized liability on stock
options exercised for common shares 65 25
----------------------------------------------------------------------------
Balance - end of period 2,939 2,809
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period 16,696 15,344
Net earnings 866 305
Dividends on common shares (note 7) (81) (57)
----------------------------------------------------------------------------
Balance - end of period 17,481 15,592
----------------------------------------------------------------------------
Accumulated other comprehensive (loss) income
(note 8)
Balance - beginning of period (104) 262
Other comprehensive (loss) income, net of
taxes (48) 53
----------------------------------------------------------------------------
Balance - end of period (152) 315
----------------------------------------------------------------------------
Shareholders' equity $ 20,268 $ 18,716
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income
Three Months Ended
Mar 31 Mar 31
(millions of Canadian dollars, unaudited) 2010 2009
----------------------------------------------------------------------------
Net earnings $ 866 $ 305
----------------------------------------------------------------------------
Net change in derivative financial instruments
designated as cash flow hedges
Unrealized loss during the period, net of
taxes of $1 million (2009 - $2 million) (5) (17)
Reclassification to net earnings, net of taxes
of $nil (2009 - $1 million) - (3)
----------------------------------------------------------------------------
(5) (20)
Foreign currency translation adjustment
Translation of net investment (43) 73
----------------------------------------------------------------------------
Other comprehensive (loss) income, net of
taxes (48) 53
----------------------------------------------------------------------------
Comprehensive income $ 818 $ 358
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months Ended
Mar 31 Mar 31
(millions of Canadian dollars, unaudited) 2010 2009
----------------------------------------------------------------------------
Operating activities
Net earnings $ 866 $ 305
Non-cash items
Depletion, depreciation and amortization 771 646
Asset retirement obligation accretion 26 19
Stock-based compensation (recovery) expense (2) 4
Unrealized risk management (gain) loss (208) 463
Unrealized foreign exchange (gain) loss (150) 138
Deferred petroleum revenue tax expense
(recovery) 7 (3)
Future income tax expense (recovery) 195 (56)
Other (26) (13)
Abandonment expenditures (39) (9)
Net change in non-cash working capital (79) (3)
----------------------------------------------------------------------------
1,361 1,491
----------------------------------------------------------------------------
Financing activities
Repayment of bank credit facilities, net (528) (108)
Issue of common shares on exercise of stock
options 40 16
Dividends on common shares (57) (54)
Net change in non-cash working capital (37) (36)
----------------------------------------------------------------------------
(582) (182)
----------------------------------------------------------------------------
Investing activities
Net expenditures on property, plant and
equipment (1,033) (1,247)
Net change in non-cash working capital 262 (79)
----------------------------------------------------------------------------
(771) (1,326)
----------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents 8 (17)
Cash and cash equivalents - beginning of
period 13 27
----------------------------------------------------------------------------
Cash and cash equivalents - end of period $ 21 $ 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 152 $ 184
Taxes (recovered) paid
Taxes other than income tax $ (6) $ (25)
Current income tax $ 52 $ 43
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, 2009. 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, 2009.
Comparative Figures
Certain prior period figures have been reclassified to conform
to the presentation adopted in 2010.
2. CHANGES IN ACCOUNTING POLICIES
International Financial Reporting Standards
In February 2008, the Canadian Institute of Chartered
Accountants' 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 those
accounting policies that 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". The new standards are the
Canadian equivalent of IFRS 3 "Business Combinations" and IAS 27
"Consolidated and Separate 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. 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. These new standards have no impact on
the Company's results of operations or financial position at this
time.
3. OTHER LONG-TERM ASSETS
Mar 31 Dec 31
2010 2009
----------------------------------------------------------------------------
Risk management (note 11) $ 22 $ -
Other 45 18
----------------------------------------------------------------------------
67 18
Less: current portion 22 -
----------------------------------------------------------------------------
$ 45 $ 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. LONG-TERM DEBT
Mar 31 Dec 31
2010 2009
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities (bankers' acceptances) $ 1,369 $ 1,897
Medium-term notes 1,200 1,200
----------------------------------------------------------------------------
2,569 3,097
----------------------------------------------------------------------------
US dollar denominated debt
US dollar debt securities (2010 and 2009 - US$6,300
million) 6,398 6,594
Less: original issue discount on US dollar debt
securities (1) (21) (22)
6,377 6,572
Fair value of interest rate swaps on US dollar debt
securities (2) 41 38
----------------------------------------------------------------------------
6,418 6,610
----------------------------------------------------------------------------
Long-term debt before transaction costs 8,987 9,707
Less: transaction costs (1) (3) (48) (49)
----------------------------------------------------------------------------
$ 8,939 $ 9,658
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $41 million (2009 - $38 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 March 31, 2010, the Company had in place unsecured bank
credit facilities of $3,953 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.
The Company's weighted average interest rate on bank credit
facilities outstanding as at March 31, 2010 was 0.8% (December 31,
2009 - 0.8%), and on total long-term debt outstanding as at March
31, 2010 was 4.7% (December 31, 2009 - 4.5%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $371 million, including $300
million related to Horizon, were outstanding at March 31, 2010.
Medium-term notes
The Company filed a $3,000 million base shelf prospectus in
October 2009 that allows for the issue of medium-term notes in
Canada until November 2011. If issued, these securities will bear
interest as determined at the date of issuance.
US dollar debt securities
The Company filed a US$3,000 million base shelf prospectus in
October 2009 that allows for the issue of US dollar debt securities
in the United States until November 2011. If issued, these
securities will bear interest as determined at the date of
issuance.
5. OTHER LONG-TERM LIABILITIES
Mar 31 Dec 31
2010 2009
----------------------------------------------------------------------------
Asset retirement obligations $ 1,581 $ 1,610
Stock-based compensation 291 392
Risk management (note 11) 185 309
Other 174 180
----------------------------------------------------------------------------
2,231 2,491
Less: current portion 353 643
----------------------------------------------------------------------------
$ 1,878 $ 1,848
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset retirement obligations
At March 31, 2010, the Company's total estimated undiscounted
costs to settle its asset retirement obligations were approximately
$6,546 million (December 31, 2009 - $6,606 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, 2009 - 6.9%). A reconciliation of the
discounted asset retirement obligations is as follows:
Three Months Year
Ended Ended
Mar 31, 2010 Dec 31, 2009
----------------------------------------------------------------------------
Balance - beginning of period $ 1,610 $ 1,064
Liabilities incurred (1) 3 299
Liabilities settled (39) (48)
Asset retirement obligation accretion 26 90
Revision of estimates - 276
Foreign exchange (19) (71)
----------------------------------------------------------------------------
Balance - end of period $ 1,581 $ 1,610
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) During 2009, the Company recognized additional asset retirement
obligations related to Oil Sands Mining and Upgrading 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.
Three Months Year
Ended Ended
Mar 31, 2010 Dec 31, 2009
----------------------------------------------------------------------------
Balance - beginning of period $ 392 $ 171
Stock-based compensation (recovery)
expense (2) 355
Cash payments for options surrendered (36) (94)
Transferred to common shares (65) (42)
Capitalized to Oil Sands Mining and
Upgrading 2 2
----------------------------------------------------------------------------
Balance - end of period 291 392
Less: current portion 258 365
----------------------------------------------------------------------------
$ 33 $ 27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended
Mar 31 Mar 31
2010 2009
----------------------------------------------------------------------------
Current income tax - North America (1) $ 129 $ 5
Current income tax - North Sea 53 98
Current income tax - Offshore West Africa 6 14
----------------------------------------------------------------------------
Current income tax expense 188 117
Future income tax expense (recovery) 195 (56)
----------------------------------------------------------------------------
Income tax expense $ 383 $ 61
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
The first quarter 2010 future income tax expense includes a
charge of $83 million related to the proposed change to the
taxation of stock options surrendered by employees for cash. During
the first quarter of 2009, substantively enacted or enacted income
tax rate changes resulted in a reduction of future income tax
liabilities of $19 million in British Columbia.
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
Three Months Ended Mar 31, 2010
Issued Number of shares
Common shares (thousands) Amount
----------------------------------------------------------------------------
Balance - beginning of period 542,327 $ 2,834
Issued upon exercise of stock options 1,435 40
Previously recognized liability on
stock options exercised - 65
----------------------------------------------------------------------------
Balance - end of period 543,762 $ 2,939
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
Normal Course Issuer Bid
In 2010, the Company announced a Normal Course Issuer Bid to
purchase, through the facilities of the Toronto Stock Exchange and
the New York Stock Exchange, during the 12 month period commencing
April 6, 2010 and ending April 5, 2011, up to 13,581,970 common
shares or 2.5% of the common shares of the Company outstanding at
March 17, 2010. As at May 6, 2010, no common shares had been
purchased for cancellation.
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
Three Months Ended Mar 31, 2010
Stock options Weighted average
(thousands) exercise price
----------------------------------------------------------------------------
Outstanding - beginning of period 32,106 $ 58.54
Granted 448 $ 74.73
Surrendered for cash settlement (993) $ 37.07
Exercised for common shares (1,435) $ 28.12
Forfeited (303) $ 63.91
----------------------------------------------------------------------------
Outstanding - end of period 29,823 $ 60.92
----------------------------------------------------------------------------
Exercisable - end of period 10,132 $ 57.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME
The components of accumulated other comprehensive (loss) income,
net of taxes, were as follows:
Mar 31 Mar 31
2010 2009
----------------------------------------------------------------------------
Derivative financial instruments designated as
cash flow hedges $ 71 $ 99
Foreign currency translation adjustment (223) 216
----------------------------------------------------------------------------
$ (152) $ 315
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 at 31%.
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 are 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 in the future.
Mar 31 Dec 31
2010 2009
----------------------------------------------------------------------------
Long-term debt $ 8,939 $ 9,658
Total shareholders' equity $ 20,268 $ 19,426
Debt to book capitalization 31% 33%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. NET EARNINGS PER COMMON SHARE
Three Months Ended
Mar 31 Mar 31
2010 2009
----------------------------------------------------------------------------
Weighted average common shares outstanding
(thousands) - basic and diluted 542,795 541,251
----------------------------------------------------------------------------
Net earnings - basic and diluted $ 866 $ 305
----------------------------------------------------------------------------
Net earnings per common share - basic and
diluted $ 1.60 $ 0.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. FINANCIAL INSTRUMENTS
The carrying values of the Company's financial instruments by
category are as follows:
Mar 31, 2010
----------------------------------------------------------------------------
Loans and Held for Other financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized cost
----------------------------------------------------------------------------
Cash and cash
equivalents $ - $ 21 $ -
Accounts receivable 1,324 - -
Other long-term assets - 22 -
Accounts payable - - (269)
Accrued liabilities - - (1,914)
Other long-term
liabilities - (185) (163)
Long-term debt - - (8,939)
----------------------------------------------------------------------------
$ 1,324 $ (142) $ (11,285)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2009
----------------------------------------------------------------------------
Loans and Held for Other financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized 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)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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:
Mar 31, 2010
----------------------------------------------------------------------------
Carrying value Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term assets $ 22 $ - $ 22
Other long-term liabilities (185) - (185)
Fixed-rate long-term
debt(2)(3) (7,570) (8,034) -
----------------------------------------------------------------------------
$ (7,733) $ (8,034) $ (163)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $41 million (2009 - $38 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:
Three Months Ended Year Ended
Mar 31, 2010 Dec 31, 2009
----------------------------------------------------------------------------
Risk management Risk management
Asset (liability) mark-to-market mark-to-market
----------------------------------------------------------------------------
Balance - beginning of period $ (309) $ 2,119
Net change in fair value of
outstanding derivative financial
instruments attributable to:
- Risk management activities 208 (1,991)
- Interest expense 3 (25)
- Foreign exchange (59) (338)
- Other comprehensive income (6) (78)
- Settlement of interest rate
swaps and other - 4
----------------------------------------------------------------------------
Balance - end of period (163) (309)
Less: current portion 22 (182)
----------------------------------------------------------------------------
$ (185) $ (127)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net (gains) losses from risk management activities were as follows:
Three Months Ended
Mar 31 Mar 31
2010 2009
----------------------------------------------------------------------------
Net realized risk management loss
(gain) $ 39 $ (641)
Net unrealized risk management
(gain) loss (208) 463
----------------------------------------------------------------------------
$ (169) $ (178)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 March
31, 2010, the Company had the following net derivative financial
instruments outstanding:
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Crude oil
Crude oil WTI
price
collars(1) Apr 2010 - Jun 2010 100,000 bbl/d US$60.00 - US$90.13
Apr 2010 - Sep 2010 50,000 bbl/d US$65.00 - US$105.49 WTI
Apr 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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to March 31, 2010, the Company entered into 50,000 bbl/d of
US$70 -US$105.81 crude oil WTI collars for the period October to
December 2010.
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Natural gas
Natural gas
price
collars Apr 2010 - Sep 2010 400,000 GJ/d C$4.50 - C$6.30 AECO
Apr 2010 - Dec 2010 220,000 GJ/d C$6.00 - C$8.00 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's outstanding commodity derivative financial
instruments are expected to be settled monthly based on the
applicable index pricing for the respective contract month.
There were no commodity derivative financial instruments
designated as hedges at March 31, 2010.
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed
rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company enters into interest rate
swap contracts to manage its fixed to floating interest rate mix on
long-term debt. The interest rate swap contracts require the
periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At March 31,
2010, the Company had the following interest rate swap contracts
outstanding:
Amount Fixed
Remaining term ($ millions) rate Floating rate
----------------------------------------------------------------------------
Interest rate
Swaps - fixed
to floating Apr 2010 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
Swaps - floating
to fixed Apr 2010 - Feb 2011 C$300 1.0680% 3 month CDOR (2)
Apr 2010 - Feb 2012 C$200 1.4475% 3 month CDOR (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) London Interbank Offered Rate
(2) Canadian Dealer Offered Rate
All fixed to floating interest rate related derivative financial
instruments designated as hedges at March 31, 2010 were classified
as fair value hedges.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated long-term
debt and working capital. The Company is also exposed to foreign
currency exchange rate risk on transactions conducted in other
currencies in its subsidiaries and in the carrying value of its
self-sustaining foreign subsidiaries. The Company periodically
enters into cross currency swap contracts and foreign currency
forward contracts to manage known currency exposure on US dollar
denominated long-term debt and working capital. The cross currency
swap contracts require the periodic exchange of payments with the
exchange at maturity of notional principal amounts on which the
payments are based. At March 31, 2010, the Company had the
following cross currency swap contracts outstanding:
Exchange Interest Interest
Amount rate rate rate
Remaining term ($ millions) (US$/C$) (US$) (C$)
----------------------------------------------------------------------------
Cross
currency
Swaps(1) Apr 2010 - Aug 2016 US$250 1.116 6.00% 5.40%
Apr 2010 - May 2017 US$1,100 1.170 5.70% 5.10%
Apr 2010 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to March 31, 2010, the Company entered into cross currency
swap contracts for US$100 million with an exchange rate of $0.999
(US$/C$) and average interest rates of 6.70% (US$) and 7.64% (C$) for
the period April 2010 to July 2011.
All cross currency swap derivative financial instruments
designated as hedges at March 31, 2010 were classified as cash flow
hedges.
In addition to the cross currency swap contracts noted above, at
March 31, 2010, the Company had US$1,184 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 March 31, 2010 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 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 $ (12) $ -
Decrease WTI US$1.00/bbl $ 13 $ -
Increase AECO C$0.10/mcf $ (8) $ -
Decrease AECO C$0.10/mcf $ 9 $ -
Interest rate risk
Increase interest rate 1% $ (8) $ 21
Decrease interest rate 1% $ 6 $ (26)
Foreign currency exchange rate risk
Increase exchange rate by US$0.01 $ (28) $ -
Decrease exchange rate by US$0.01 $ 28 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
March 31, 2010, 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
March 31, 2010, the Company had net risk management assets of $55
million with specific counterparties related to derivative
financial instruments (December 31, 2009 - $7 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:
Less than 1 to less than 2 to less than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 269 $ - $ - $ -
Accrued
liabilities $ 1,914 $ - $ - $ -
Risk management $ - $ 20 $ 66 $ 99
Other long-term
liabilities $ 95 $ 23 $ 26 $ 19
Long-term debt
(1) $ 400 $ 406 $ 1,516 $ 5,276
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $1,369 million of revolving
bank credit facilities due to the extendable nature of the facilities.
12. COMMITMENTS
As at March 31, 2010, the Company had committed to certain payments as
follows:
Remaining
2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 160 $ 172 $ 144 $ 134 $ 135 $ 1,060
Offshore equipment
operating leases $ 116 $ 121 $ 100 $ 98 $ 98 $ 254
Offshore drilling $ 34 $ - $ - $ - $ - $ -
Asset retirement
obligations (1) $ 12 $ 20 $ 21 $ 31 $ 39 $ 6,423
Office leases $ 19 $ 19 $ 3 $ 2 $ 2 $ 2
Other $ 211 $ 65 $ 19 $ 14 $ 12 $ 33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 estimated minimum expenditures required
to meet these obligations. Actual expenditures in any particular year
may exceed these minimum amounts.
13. SEGMENTED INFORMATION
Conventional Crude Oil and Natural Gas
Offshore West Total
(millions of North America North Sea Africa Conventional
Canadian Three Months Three Months Three Months Three Months
dollars, Ended Ended Ended Ended
unaudited) Mar 31 Mar 31 Mar 31 Mar 31
2010 2009 2010 2009 2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented
revenue 2,486 1,847 286 175 156 201 2,928 2,223
Less:
royalties (324) (193) (1) - (5) (14) (330) (207)
----------------------------------------------------------------------------
Segmented
revenue, net
of royalties 2,162 1,654 285 175 151 187 2,598 2,016
----------------------------------------------------------------------------
Segmented
expenses
Production 427 476 90 70 28 43 545 589
Transportation
and blending 407 326 3 3 - - 410 329
Depletion,
depreciation
and
amortization 557 547 83 64 39 50 679 661
Asset
retirement
obligation
accretion 11 9 8 7 1 1 20 17
Realized risk
management
activities 39 (484) - (157) - - 39 (641)
----------------------------------------------------------------------------
Total
segmented
expenses 1,441 874 184 (13) 68 94 1,693 955
----------------------------------------------------------------------------
Segmented
earnings
before the
following 721 780 101 188 83 93 905 1,061
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Stock-based
compensation
(recovery)
expense
Interest, net
Unrealized
risk
management
activities
Foreign
exchange
(gain) loss
----------------------------------------------------------------------------
Total
non-segmented
expenses
----------------------------------------------------------------------------
Earnings
before taxes
Taxes other
than income
tax
Current income
tax expense
Future income
tax expense
(recovery)
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment
Oil Sands Mining elimination and
(millions of and Upgrading Midstream other Total
Canadian Three Months Three Months Three Months Three Months
dollars, Ended Ended Ended Ended
unaudited) Mar 31 Mar 31 Mar 31 Mar 31
2010 2009 2010 2009 2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented
Revenue 647 - 19 19 (14) (56) 3,580 2,186
Less:
royalties (23) - - - - 8 (353) (199)
----------------------------------------------------------------------------
Segmented
revenue, net
of royalties 624 - 19 19 (14) (48) 3,227 1,987
----------------------------------------------------------------------------
Segmented
expenses
Production 346 - 5 5 (2) (12) 894 582
Transportation
and blending 15 - - - (11) (12) 414 317
Depletion,
depreciation
and
amortization 90 2 2 2 - (19) 771 646
Asset
retirement
obligation
accretion 6 2 - - - - 26 19
Realized risk
management
activities - - - - - - 39 (641)
----------------------------------------------------------------------------
Total
segmented
expenses 457 4 7 7 (13) (43) 2,144 923
----------------------------------------------------------------------------
Segmented
earnings
before the
following 167 (4) 12 12 (1) (5) 1,083 1,064
----------------------------------------------------------------------------
Non-segmented
expenses
Administration 54 47
Stock-based
compensation
(recovery)
expense (2) 4
Interest, net 111 57
Unrealized
risk
management
activities (208) 463
Foreign
exchange
(gain) loss (160) 123
----------------------------------------------------------------------------
Total
non-segmented
expenses (205) 694
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings
before taxes 1,288 370
Taxes other
than income
tax 39 4
Current income
tax expense 188 117
Future income
tax expense
(recovery) 195 (56)
----------------------------------------------------------------------------
Net earnings 866 305
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net additions to property, plant and equipment
Three Months Ended
Mar 31, 2010
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 809 $ 3 $ 812
North Sea 23 - 23
Offshore West Africa 99 1 100
Oil Sands Mining
and Upgrading (2) 98 - 98
Midstream - - -
Head office 4 - 4
----------------------------------------------------------------------------
$ 1,033 $ 4 $ 1,037
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended
Mar 31, 2009
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 599 $ (8) $ 591
North Sea 42 - 42
Offshore West Africa 215 - 215
Oil Sands Mining
and Upgrading (2) 382 270 652
Midstream 5 - 5
Head office 4 - 4
----------------------------------------------------------------------------
$ 1,247 $ 262 $ 1,509
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
Mar 31 Dec 31 Mar 31 Dec 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented assets
North America $ 22,097 $ 21,834 $ 23,253 $ 22,994
North Sea 1,699 1,812 1,829 1,968
Offshore West Africa 1,863 1,883 2,018 2,033
Other 29 28 64 42
Oil Sands Mining and Upgrading 13,303 13,295 13,753 13,621
Midstream 201 203 327 306
Head office 60 60 60 60
----------------------------------------------------------------------------
$ 39,252 $ 39,115 $ 41,304 $ 41,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capitalized interest
The Company capitalizes construction period interest to Oil
Sands Mining and Upgrading activities 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 three months ended March 31, 2010,
pre-tax interest of $7 million was capitalized to Oil Sands Mining
and Upgrading (March 31, 2009 - $86 million).
SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with
the Company's continuous offering of medium-term notes pursuant to
the short form prospectus dated 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 March 31, 2010:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 6.6 x
Cash flow from operations (2) 14.3 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 Friday,
May 7, 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, Friday, May 14, 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 6353533.
WEBCAST
This call is being webcast and can be accessed on Canadian
Natural's website at www.cnrl.com.
2010 SECOND QUARTER RESULTS
The 2010 second quarter results are scheduled for release on
Thursday, August 5, 2010. A conference call is scheduled to be held
the same day. Details can be found on our website www.cnrl.com.
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 & 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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