Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) -
Commenting on first quarter results, Canadian Natural's
Chairman, Allan Markin, stated, "It has been an exciting and
productive beginning of the year for Canadian Natural with the
first successful SCO production at Horizon on February 28th, 2009
and first crude oil production achieved April 28th, 2009 at the
Olowi Field in Offshore Gabon. Conventional operations have also
performed well with North America and International volumes coming
in as targeted."
John Langille, Vice-Chairman of Canadian Natural continued,
"Cash flow remained strong in Q1/09. We benefited from favorable
heavy oil differentials and our substantial hedging program.
Strengthening our balance sheet remains a priority. We have the
ability to continually review capital allocation decisions, thus
providing flexibility in our budget throughout the year."
Steve Laut, President and Chief Operating Officer for Canadian
Natural stated, "The major capital requirements for our four major
growth projects have been met. We are focused on capital and
operating cost efficiencies in all areas of our business, while
executing our development plans including the ramping up of
production at both Olowi and Horizon. We have strong assets, all of
which generate free cash flow in this environment, and a committed
and dedicated team of people working together to create value for
our shareholders."
HIGHLIGHTS
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions, except as noted) 2009 2008 2008
----------------------------------------------------------------------------
Net earnings $ 305 $ 1,770 $ 727
Per common share, basic and
diluted $ 0.56 $ 3.27 $ 1.35
Adjusted net earnings from
operations (1) $ 727 $ 697 $ 872
Per common share, basic and
diluted $ 1.34 $ 1.29 $ 1.61
Cash flow from operations (2) $ 1,516 $ 1,570 $ 1,725
Per common share, basic and
diluted $ 2.80 $ 2.90 $ 3.19
Capital expenditures, net of
dispositions $ 1,256 $ 1,827 $ 1,753
Daily production, before
royalties
Natural gas (mmcf/d) 1,369 1,427 1,538
Crude oil and NGLs (bbl/d) 330,017 309,570 327,217
Equivalent production (boe/d) 558,142 547,399 583,488
(1) Adjusted net earnings from operations is a non-GAAP measure that the
Company utilizes to evaluate its performance. The derivation of this
measure is discussed in the Management's Discussion and Analysis
("MD&A").
(2) Cash flow from operations is a non-GAAP measure that the Company
considers key as it demonstrates the Company's ability to fund capital
reinvestment and debt repayment. The derivation of this measure is
discussed in the MD&A.
HIGHLIGHTS
- Total crude oil and NGLs production for Q1/09 was 330,017
bbl/d, an increase of 7% from the previous quarter. Volumes in
Q1/09 reflect the transition between steam and production cycles
for Primrose thermal wells, the early production from the Primrose
East expansion, continued conversion of production wells to polymer
injection wells at Pelican Lake, increased production from Baobab,
and initial Horizon production.
- Natural gas production for Q1/09 averaged 1,369 mmcf/d, down
4% from the previous quarter as expected. The decrease in volumes
for Q1/09 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 3% from the previous quarter. The decrease from Q4/08
reflects lower crude oil and natural gas price realizations and
lower natural gas sales volumes, partially offset by the impact of
higher crude oil sales volumes and realized risk management
gains.
- Quarterly net earnings for Q1/09 of $305 million included the
effects of unrealized risk management activities, stock-based
compensation and fluctuations in foreign exchange rates. Excluding
these items, quarterly adjusted net earnings from operations for
Q1/09 were $727 million, a increase of 4% from the previous
quarter.
- The drilling program at Baobab in Offshore Cï¿1/2te d'Ivoire
was completed in Q1/09. The fourth well was brought on production
in early Q2/09. The four wells restored production of approximately
11,000 bbl/d net to Canadian Natural.
- First crude oil production was achieved at the Olowi Field in
Offshore Gabon on April 28, 2009.
- First synthetic crude oil ("SCO") production was achieved at
Horizon on February 28, 2009. First shipment of SCO into the sales
pipeline was achieved on March 18, 2009.
- Declared a quarterly cash dividend on common shares of $0.105
per common share payable July 1, 2009.
OPERATIONS REVIEW
Activity by core region
-----------------------------------------------
Net undeveloped land Drilling activity
as at three months ended
Mar 31, 2009 Mar 31, 2009
(thousands of net acres) (net wells) (1)
----------------------------------------------------------------------------
North America conventional
Northeast British Columbia 2,188 15.0
Northwest Alberta 1,289 33.2
Northern Plains 6,318 96.1
Southern Plains 887 8.3
Southeast Saskatchewan 132 3.0
Thermal In-situ Oil Sands 491 207.0
----------------------------------------------------------------------------
11,305 362.6
Oil Sands Mining and Upgrading 115 42.0
North Sea 182 0.9
Offshore West Africa 188 2.3
----------------------------------------------------------------------------
11,790 407.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Drilling activity includes stratigraphic test and service wells
Drilling activity (number of wells)
Three Months Ended Mar 31
--------------------------------------
2009 2008
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 94 93 184 173
Natural gas 87 64 191 161
Dry 16 15 13 11
----------------------------------------------------------------------------
Subtotal 197 172 388 345
Stratigraphic test / service wells 236 236 15 15
----------------------------------------------------------------------------
Total 433 408 403 360
----------------------------------------------------------------------------
Success rate (excluding
stratigraphic test / service wells) 91% 97%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America Conventional
North America natural gas
Quarterly Results
----------------------------------------
Q1/09 Q4/08 Q1/08
----------------------------------------------------------------------------
Natural gas production (mmcf/d) 1,347 1,405 1,513
----------------------------------------------------------------------------
Net wells targeting natural gas 72 43 167
Net successful wells drilled 64 41 161
----------------------------------------------------------------------------
Success rate 89% 95% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Q1/09 North America natural gas production decreased 11% as
expected from Q1/08 and decreased 4% from Q4/08, reflecting natural
declines in base production and the Company's strategic decision to
reduce spending on natural gas drilling. The Company had a limited
but highly successful winter drilling program with all planned
wells drilled and all planned tie-ins completed prior to spring
break-up.
- Canadian Natural successfully completed 64 net natural gas
wells in Q1/09 with an active program across the Company's core
regions. In Northeast British Columbia, 15 net wells were drilled,
while in Northwest Alberta, 29 net wells were drilled. In the
Northern Plains, 20 net wells were drilled, with eight net wells
drilled in the Southern Plains.
- Planned drilling activity for Q2/09 includes one natural gas
well compared to drilling activity for Q2/08 of eight natural gas
wells.
North America crude oil and NGLs
Quarterly Results
Q1/09 Q4/08 Q1/08
----------------------------------------
----------------------------------------------------------------------------
Crude oil and NGLs production
(bbl/d) 253,833 240,831 248,960
----------------------------------------------------------------------------
Net wells targeting crude oil 97 190 176
Net successful wells drilled 90 181 171
----------------------------------------------------------------------------
Success rate 93% 95% 97%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Q1/09 North America crude oil and NGLs production increased 2%
from Q1/08 and increased 5% from Q4/08 levels. The majority of the
incremental production volume was contributed by thermal crude oil
and Pelican Lake crude oil.
- In Q1/09 after initial steaming, Canadian Natural discovered
oil seepage at the surface on one of the new multi-well pads at
Primrose East. A significant amount of diagnostic work has been
done and the Company believes it has identified the issue and the
remedial action required. Canadian Natural has submitted a detailed
analysis and provided a recommendation on how to proceed to the
regulators. The Company will proactively work with the regulators
on resolving the issue and returning Primrose East to normal
operations.
- Canadian Natural is continuing its proposed third phase of the
thermal growth plan with a development plan for the 45,000 bbl/d
Kirby In-Situ Oil Sands Project located approximately 85 km
northeast of Lac La Biche in the Regional Municipality of Wood
Buffalo. The Company has filed its formal regulatory application
documents for this project and is awaiting regulatory approval.
Canadian Natural will decide in late 2009 or early 2010 when to
proceed with the project.
- Development of new pads and secondary recovery conversion
projects at Pelican Lake continued as expected throughout Q1/09. In
Q1/09, the Company drilled three horizontal wells with plans to
drill one vertical service well and an additional 46 horizontal
wells throughout the remainder of 2009. Pelican Lake production
averaged approximately 37,000 bbl/d for Q1/09.
- Conventional heavy crude oil production volumes decreased
slightly in Q1/09 compared to Q4/08, reflecting expected declines
in certain older fields and higher than forecast downtime due to
cold weather.
- During Q1/09, drilling activity targeted 97 net wells
including 72 wells targeting heavy crude oil, three wells targeting
Pelican Lake crude oil, 14 wells targeting thermal crude oil and
eight wells targeting light crude oil.
- Planned drilling activity for Q2/09 includes 63 net crude oil
wells, excluding stratigraphic test and service wells.
International
Quarterly Results
----------------------------------------
Q1/09 Q4/08 Q1/08
----------------------------------------------------------------------------
Crude oil production (bbl/d)
North Sea 42,369 42,991 49,568
Offshore West Africa 30,431 25,748 28,689
----------------------------------------------------------------------------
Natural gas production (mmcf/d)
North Sea 10 10 11
Offshore West Africa 12 12 14
----------------------------------------------------------------------------
Net wells targeting crude oil 3.2 1.1 2.2
Net successful wells drilled 3.2 1.1 2.2
----------------------------------------------------------------------------
Success rate 100% 100% 100%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
- North Sea production for Q1/09 was 42,369 bbl/d. During the
first quarter, 0.9 net wells were drilled, with 0.4 net wells in
progress at the end of the quarter with focus continuing to be on
lowering costs, high grading inventory and infill drilling
opportunities.
- During the quarter, drilling commenced on Deep Banff, a high
temperature, high pressure, natural gas well. Canadian Natural's
initial net paying interest in the well is 18%. Results are
expected in the second quarter.
Offshore West Africa
- Offshore West Africa's crude oil production for the quarter
increased by 18% from Q4/08. This was largely due to a full quarter
of production from the first three wells delivered in the Baobab
drilling program. A fourth and final well was completed in the
quarter and was brought on production early in the second
quarter.
- Progress on the Facility Upgrade Project at Espoir to increase
capacity of the Floating Production Storage and Offtake Vessel
("FPSO") continues ahead of schedule and is targeted to be complete
in late Q3/09.
- At the Olowi Project in Offshore Gabon, two further production
wells were completed. The FPSO and Conductor Supported Platform
were commissioned and first production of crude oil was achieved on
April 28, 2009. Further drilling and development activity is
continuing.
Oil Sands Mining and Upgrading
- Canadian Natural substantially completed the construction at
Horizon with first production of SCO from Phase 1 achieved February
28, 2009, representing a major milestone achieved by the Company.
First shipment of SCO into the sales pipeline was achieved on March
18, 2009.
- Construction and commissioning of the final unit, Plant 42 -
the Distillate Hydrotreater - was completed in late March.
- During April 2009, production was shut down for a period of
time to facilitate equipment maintenance and ensure product
quality. All major components of the plant have been tested and so
far have shown no issues with design or capacity limitations.
- Horizon production was 304,544 barrels for Q1/09, as the
Company worked through the commissioning of the plant, averaging
daily production volumes of 3,384 bbl/d. These volumes went to
pipeline fill and on-site tank inventory.
- Since first SCO production, Horizon has produced approximately
1.1 million barrels of SCO of which approximately 766,000 barrels
filled the sales pipeline to Edmonton. The SCO inventory on site at
the end of April was just over 327,000 barrels.
- As expected during the initial stages of commissioning,
production volumes continue to fluctuate on a weekly basis. Nearing
the end of Q2/09, the Company targets production volumes to
stabilize with a steady ramp up to full production by the end of
2009. The Company will work towards full capacity throughout 2009
as the plant continues to be fine tuned to design rates with a
focus on safety, reliability, and cost control.
- Tranche 2 of the expansion Phase 2/3, engineering and
procurement is underway and focuses on increasing reliability and
uptime. Tranches 3 and 4 of Phase 2/3 continue to be
re-profiled.
MARKETING Quarterly Results
----------------------------------------
Q1/09 Q4/08 Q1/08
----------------------------------------------------------------------------
Crude oil and NGLs pricing
WTI(1) benchmark price
(US$/bbl) $ 43.21 $ 58.75 $ 97.96
Western Canadian Select blend
differential from WTI (%) 21% 33% 22%
Corporate average pricing
before risk management (C$/bbl) $ 41.25 $ 45.81 $ 78.99
Natural gas pricing
AECO benchmark price (C$/GJ) $ 5.34 $ 6.43 $ 6.76
Corporate average pricing
before risk management (C$/mcf) $ 5.46 $ 7.03 $ 7.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
- In Q1/09, the Western Canadian Select ("WCS") heavy crude oil
differential as a percent of WTI was 21%, compared to 33% in Q4/08.
Heavy crude oil differentials narrowed in Q1/09 due to a stronger
demand from the US for heavy crude oil.
- The marketing strategy for Horizon SCO remains flexible. There
is an active market for the product and the Company will be selling
the SCO to refiners throughout North America.
- During Q1/09, the Company contributed approximately 156,000
bbl/d of its heavy crude oil streams to the WCS blend as market
conditions resulted in this strategy offering the optimal pricing
for bitumen crude oil.
- Natural gas pricing for Q1/09 weakened compared to prior
periods primarily due to supply/demand imbalances. North America
natural gas inventory levels remained high during the first quarter
due to lower industrial consumption.
FINANCIAL REVIEW
- The Company continues to believe that its internally generated
cash flow from operations supported by the implementation of its
commodity hedge policy, the flexibility of its capital expenditure
programs supported by its multi-year financial plans, its existing
credit facilities and its ability to raise new debt on commercially
acceptable terms, will provide sufficient liquidity to sustain its
operations in the short, medium and long-term and support its
growth strategy. A brief summary of the Company's strengths
are:
-- A diverse asset base geographically and by product - produced
in excess of 558,000 boe/d in Q1/09, comprised of approximately 41%
natural gas and 59% crude oil - with 94% of production located in
G8 countries.
-- Financial stability and liquidity - cash flow from operations
of $1,516 million for Q1/09, with available unused bank lines of
$1,769 million at March 31, 2009.
-- Reduced volatility of commodity prices - a proactive
commodity hedging program to reduce the downside risk of volatility
in commodity prices supporting cash flow for its capital
expenditure program.
-- In Q1/09 the Company repaid $420 million on the non-revolving
syndicated acquisition credit facility maturing in October 2009. An
additional $285 million has been repaid thus far in Q2/09.
-- A strengthening balance sheet with debt to book
capitalization of 41% and debt to EBITDA of 1.8 times, both within
targeted ranges.
- Declared a quarterly cash dividend on common shares of C$0.105
per common share, payable July 1, 2009.
OUTLOOK
- The Company forecasts 2009 production levels before royalties
to average between 1,274 and 1,330 mmcf/d of natural gas and
between 326,000 and 389,000 bbl/d of crude oil and NGLs. Q2/09
production guidance before royalties is forecast to average between
1,318 and 1,353 mmcf/d of natural gas and between 321,000 and
359,000 bbl/d of crude oil and NGLs. Detailed guidance on
production levels, capital allocation and operating costs can be
found on the Company's website at
http://www.cnrl.com/investor_info/corporate_guidance/.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements 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,
Gabon Offshore West Africa, and the Kirby 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 and the reader should not place undue
reliance on these forward-looking statements as there can be no
assurances that the plans, initiatives or expectations upon which
they are based will occur.
In addition, statements relating to "reserves" are deemed to be
forward-looking statements as they involve the implied assessment
based on certain estimates and assumptions that the reserves
described can be profitably produced in the future. There are
numerous uncertainties inherent in estimating quantities of proved
crude oil and natural gas reserves and in projecting future rates
of production and the timing of development expenditures. The total
amount or timing of actual future production may vary significantly
from reserve and production estimates.
The forward-looking statements are based on current
expectations, estimates and projections about the Company and the
industry in which the Company operates, which speak only as of the
date such statements were made or as of the date of the report or
document in which they are contained, and are subject to known and
unknown risks and uncertainties that could cause the actual
results, performance or achievements of the Company to be
materially different from any future results, performance or
achievements expressed or implied by such forward-looking
statements. Such risks and uncertainties include, among others:
general economic and business conditions which will, among other
things, impact demand for and market prices of the Company's
products; volatility of and assumptions regarding crude oil and
natural gas prices; fluctuations in currency and interest rates;
assumptions on which the Company's current guidance is based;
economic conditions in the countries and regions in which the
Company conducts business; political uncertainty, including actions
of or against terrorists, insurgent groups or other conflict
including conflict between states; industry capacity; ability of
the Company to implement its business strategy, including
exploration and development activities; impact of competition; the
Company's defense of lawsuits; availability and cost of seismic,
drilling and other equipment; ability of the Company and its
subsidiaries to complete capital programs; the Company's and its
subsidiaries' ability to secure adequate transportation for its
products; unexpected difficulties in mining, extracting or
upgrading the Company's bitumen products; potential delays or
changes in plans with respect to exploration or development
projects or capital expenditures; ability of the Company to attract
the necessary labour required to build its thermal and oil sands
mining projects; operating hazards and other difficulties inherent
in the exploration for and production and sale of crude oil and
natural gas; availability and cost of financing; the Company's and
its subsidiaries' success of exploration and development activities
and their ability to replace and expand crude oil and natural gas
reserves; timing and success of integrating the business and
operations of acquired companies; production levels; imprecision of
reserve estimates and estimates of recoverable quantities of crude
oil, bitumen, natural gas and liquids not currently classified as
proved; actions by governmental authorities; government regulations
and the expenditures required to comply with them (especially
safety and environmental laws and regulations and the impact of
climate change initiatives on capital and operating costs); asset
retirement obligations; the adequacy of the Company's provision for
taxes; and other circumstances affecting revenues and expenses.
The Company's operations have been, and in the future may be,
affected by political developments and by federal, provincial and
local laws and regulations such as restrictions on production,
changes in taxes, royalties and other amounts payable to
governments or governmental agencies, price or gathering rate
controls and environmental protection regulations. Should one or
more of these risks or uncertainties materialize, or should any of
the Company's assumptions prove incorrect, actual results may vary
in material respects from those projected in the forward-looking
statements. The impact of any one factor on a particular
forward-looking statement is not determinable with certainty as
such factors are dependent upon other factors, and the Company's
course of action would depend upon its assessment of the future
considering all information then available.
Readers are cautioned that the foregoing list of factors is not
exhaustive. Unpredictable or unknown factors not discussed in this
report could also have material adverse effects on forward-looking
statements. Although the Company believes that the expectations
conveyed by the forward-looking statements are reasonable based on
information available to it on the date such forward-looking
statements are made, no assurances can be given as to future
results, levels of activity and achievements. All subsequent
forward-looking statements, whether written or oral, attributable
to the Company or persons acting on its behalf are expressly
qualified in their entirety by these cautionary statements. Except
as required by law, the Company assumes no obligation to update
forward-looking statements should circumstances or Management's
estimates or opinions change.
Management's Discussion and Analysis
Management's Discussion and Analysis of the financial condition
and results of operations of the Company should be read in
conjunction with the unaudited interim consolidated financial
statements for the three months ended March 31, 2009 and the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2008.
All dollar amounts are referenced in millions of Canadian
dollars, except where noted otherwise. The financial statements
have been prepared in accordance with generally accepted accounting
principles in Canada ("GAAP"). This MD&A includes references to
financial measures commonly used in the crude oil and natural gas
industry, such as adjusted net earnings from operations and cash
flow from operations. These financial measures are not defined by
GAAP and therefore are referred to as non-GAAP measures. The
non-GAAP measures used by the Company may not be comparable to
similar measures presented by other companies. The Company uses
these non-GAAP measures to evaluate its performance. The non-GAAP
measures should not be considered an alternative to or more
meaningful than net earnings, as determined in accordance with
GAAP, as an indication of the Company's performance. The non-GAAP
measures adjusted net earnings from operations and cash flow from
operations are reconciled to net earnings, as determined in
accordance with GAAP, in the "Financial Highlights" section of this
MD&A. The Company also presents certain non-GAAP financial
ratios and their derivation in the "Liquidity and Capital
Resources" section of this MD&A.
The calculation of barrels of oil equivalent ("boe") is based on
a conversion ratio of six thousand cubic feet ("mcf") of natural
gas to one barrel ("bbl") of crude oil to estimate relative energy
content. This conversion may be misleading, particularly when used
in isolation, since the 6 mcf:1 bbl ratio is based on an energy
equivalency at the burner tip and does not represent the value
equivalency at the wellhead.
Production volumes 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, 2009 in
relation to the comparable period in 2008 and the fourth quarter of
2008. The accompanying tables form an integral part of this
MD&A. This MD&A is dated May 7, 2009. Additional
information relating to the Company, including its Annual
Information Form for the year ended December 31, 2008, is available
on SEDAR at www.sedar.com.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Revenue, before royalties $ 2,186 $ 2,511 $ 3,967
Net earnings $ 305 $ 1,770 $ 727
Per common share - basic and
diluted $ 0.56 $ 3.27 $ 1.35
Adjusted net earnings from
operations (1) $ 727 $ 697 $ 872
Per common share - basic and
diluted $ 1.34 $ 1.29 $ 1.61
Cash flow from operations (2) $ 1,516 $ 1,570 $ 1,725
Per common share - basic and
diluted $ 2.80 $ 2.90 $ 3.19
Capital expenditures, net of
dispositions $ 1,256 $ 1,827 $ 1,753
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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) 2009 2008 2008
----------------------------------------------------------------------------
Net earnings as reported $ 305 $ 1,770 $ 727
Stock-based compensation
expense (recovery), net of tax (a) 3 (145) -
Unrealized risk management
loss (gain), net of tax (b) 320 (1,435) 76
Unrealized foreign exchange
loss, net of tax (c) 118 507 110
Effect of statutory tax rate
and other legislative changes
on future income tax
liabilities (d) (19) - (41)
----------------------------------------------------------------------------
Adjusted net earnings from
operations $ 727 $ 697 $ 872
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 during the
construction period.
(b) Derivative financial instruments are recorded at fair value on the
balance sheet, with changes in fair value of non-designated hedges
recognized in net earnings. The amounts ultimately realized may be
materially different than reflected in the financial statements due to
changes in prices of the underlying items hedged, primarily crude oil
and natural gas.
(c) Unrealized foreign exchange gains and losses result primarily from the
translation of US dollar denominated long-term debt to period-end
exchange rates, offset by the impact of cross currency swaps, and are
recognized in net earnings.
(d) All substantively enacted or enacted adjustments in applicable income
tax rates and other legislative changes are applied to underlying assets
and liabilities on the Company's consolidated balance sheet in
determining future income tax assets and liabilities. The impact of
these tax rate and other legislative changes is recorded in net earnings
during the period the legislation is substantively enacted or enacted.
Income tax rate changes in the first quarter of 2009 resulted in a
reduction of future income tax liabilities of approximately $19 million
in North America. Income tax rate changes in the first quarter of 2008
resulted in a reduction of future income tax liabilities of
approximately $19 million in North America and $22 million in Cote
d'Ivoire, Offshore West Africa.
Cash Flow from Operations
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2009 2008 2008
----------------------------------------------------------------------------
Net earnings $ 305 $ 1,770 $ 727
Non-cash items:
Depletion, depreciation and
amortization 646 666 688
Asset retirement obligation
accretion 19 19 17
Stock-based compensation
expense (recovery) 4 (203) -
Unrealized risk management
loss (gain) 463 (2,107) 108
Unrealized foreign exchange
loss 138 613 126
Deferred petroleum revenue
tax recovery (3) (5) (21)
Future income tax (recovery)
expense (56) 817 80
----------------------------------------------------------------------------
Cash flow from operations $ 1,516 $ 1,570 $ 1,725
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the first quarter of 2009 were $305 million
compared to $727 million for the first quarter of 2008 and $1,770
million for the prior quarter. Net earnings for the first quarter
of 2009 included net unrealized after-tax expenses of $422 million
related to the effects of risk management activities, fluctuations
in foreign exchange rates, fluctuations in stock-based compensation
expense, and the impact of statutory tax rate changes on future
income tax liabilities, compared to net unrealized after-tax
expenses of $145 million for the first quarter of 2008 and net
unrealized after-tax income of $1,073 million for the prior
quarter. Excluding these items, adjusted net earnings from
operations for the first quarter of 2009 was $727 million compared
to $872 million for the first quarter of 2008 and $697 million for
the prior quarter. The decrease in adjusted net earnings from the
first quarter of 2008 was primarily due to the impact of lower
realized pricing and lower sales volumes, partially offset by the
impact of higher realized risk management gains, lower depletion,
depreciation and amortization expense, lower royalty and production
expense, and the impact of the weaker Canadian dollar relative to
the US dollar. The increase in adjusted net earnings from the prior
quarter was primarily due to the impact of higher crude oil sales
volumes related to Primrose East production, higher realized risk
management gains, lower depletion, depreciation and amortization
expense, and lower royalty expense, partially offset by the impact
of lower realized pricing, lower natural gas sales volumes, and
higher interest expense.
The impacts of unrealized risk management activities,
stock-based compensation, and changes in foreign exchange rates are
expected to continue to contribute to significant quarterly
volatility in consolidated net earnings and are discussed in detail
in the relevant sections of this MD&A.
Cash flow from operations for the first quarter of 2009
decreased to $1,516 million compared to $1,725 million for the
first quarter of 2008 and $1,570 million for the prior quarter. The
decrease in cash flow from operations from the comparable quarters
was primarily due to the impact of lower realized pricing, lower
natural gas sales volumes, and higher interest expense, partially
offset by the impact of higher crude oil sales volumes, higher
realized risk management gains, lower royalty and production
expense, and the impact of the weaker Canadian dollar relative to
the US dollar. The decrease from the prior quarter was also due to
higher current income tax expense and lower realized foreign
exchange gains.
During the first quarter of 2009, the Company achieved first
production of synthetic crude oil at Horizon Oil Sands ("Horizon").
The Company is currently focusing on completing final
commissioning, stabilizing and ramping up production, and
continuing to ensure the plant is fine tuned to design rates with a
focus on safety, reliability, and cost control.
Total production before royalties for the first quarter of 2009
decreased 4% to 558,142 boe/d from 583,488 boe/d for the first
quarter of 2008 and increased 2% from 547,399 boe/d for the prior
quarter. Total production for the first quarter of 2009 was within
the Company's previously issued guidance.
For a discussion of the impact of current worldwide financial
and economic events, please refer to the "Liquidity and Capital
Resources" section of this MD&A.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the eight
most recently completed quarters:
($ millions, except per common 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)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common share Mar 31 Dec 31 Sep 30 Jun 30
amounts) 2008 2007 2007 2007
----------------------------------------------------------------------------
Revenue, before royalties $ 3,967 $ 3,200 $ 3,073 $ 3,152
Net earnings $ 727 $ 798 $ 700 $ 841
Net earnings per common share
- Basic and diluted $ 1.35 $ 1.48 $ 1.30 $ 1.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 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 - Increased production from
the Company's Primrose thermal projects, the results from the
Pelican Lake water and polymer flood projects, and development of
the Espoir Field. Sales volumes also reflected fluctuations due to
timing of liftings and maintenance activities in the North Sea and
Offshore West Africa and the impact of the shut in, and subsequent
restoration, of some of the Baobab Field production.
- Natural gas sales volumes - Production declines due to the
Company's strategic decision to reduce natural gas drilling
activity in North America due to the allocation of capital to
higher return crude oil projects, as well as natural decline
rates.
- Production expense - Fluctuations company wide, primarily due
to the impact of the demand for services, industry-wide
inflationary cost pressures experienced in prior quarters in all
segments, fluctuations in product mix, and the impact of seasonal
costs that are dependent on weather.
- Depletion, depreciation and amortization - Fluctuations due to
changes in sales volumes, finding and development costs associated
with crude oil and natural gas exploration, and estimated future
costs to develop the Company's proved undeveloped reserves.
- 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 over the eight most
recently completed quarters.
- Risk management - Fluctuations due to the recognition of
realized and unrealized gains and losses from the mark-to-market
and subsequent settlement of the Company's risk management
activities.
- Foreign exchange rates - Fluctuations in the Canadian dollar
relative to the US dollar impacted the realized price the Company
received for its crude oil and natural gas sales, as sales prices
are based predominately on US dollar denominated benchmarks.
Similarly, unrealized foreign exchange gains and losses were
recorded with respect to US dollar denominated debt and the
re-measurement of North Sea future income tax liabilities
denominated in UK pounds sterling to US dollars, partially offset
by the impact of cross currency swap hedges.
- Changes in 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
2009 2008 2008
----------------------------------------------------------------------------
WTI benchmark price (US$/bbl) $ 43.21 $ 58.75 $ 97.96
Dated Brent benchmark price
(US$/bbl) $ 44.45 $ 54.93 $ 96.94
WCS blend differential from
WTI (US$/bbl) $ 8.98 $ 19.13 $ 21.41
WCS blend differential from
WTI (%) 21% 33% 22%
Condensate benchmark price
(US$/bbl) $ 43.44 $ 59.01 $ 98.40
NYMEX benchmark price
(US$/mmbtu) $ 4.87 $ 6.82 $ 8.07
AECO benchmark price (C$/GJ) $ 5.34 $ 6.43 $ 6.76
US / Canadian dollar average
exchange rate $ 0.8028 $ 0.8252 $ 0.9958
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$43.21 per
bbl for the first quarter of 2009, a decrease of 56% from US$97.96
per bbl for the first quarter of 2008, and 26% from US$58.75 for
the prior quarter. WTI pricing during the first quarter of 2009
continued to be impacted by a significant decrease in demand as a
result of worldwide financial and economic events and ongoing
geopolitical uncertainty resulting in increased market
volatility.
Crude oil sales contracts for the Company's North Sea and
Offshore West Africa segments are typically based on Dated Brent
("Brent") pricing, which also continued to be impacted by worldwide
financial and economic events during the first quarter of 2009.
Brent averaged US$44.45 per bbl for the first quarter of 2009, a
decrease of 54% compared to US$96.94 per bbl for the first quarter
of 2008, and 19% from US$54.93 per bbl for the prior quarter.
The Heavy Differential averaged 21% for the first quarter of
2009 compared to 22% for the first quarter of 2008, and 33% for the
prior quarter. The narrowing of the Heavy Differential from the
prior periods was primarily due to continued worldwide demand
favoring distillates over gasolines and relatively weak refinery
margins.
The Company anticipates continued volatility in the crude oil
pricing benchmarks due to the unpredictable nature of supply and
demand factors, geopolitical events and the global economic
slowdown resulting from worldwide financial and economic events.
The Heavy Differential is expected to reflect seasonal demand
fluctuations and refinery margins.
NYMEX natural gas prices averaged US$4.87 per mmbtu for the
first quarter of 2009, a decrease of 40% from US$8.07 per mmbtu for
the first quarter of 2008, and a decrease of 29% from US$6.82 per
mmbtu for the prior quarter. AECO natural gas prices for the first
quarter of 2009 decreased 21% to average $5.34 per GJ from $6.76
per GJ in the first quarter of 2008, and decreased 17% from $6.43
per GJ for the prior quarter. Decreases in natural gas prices from
the comparable periods were primarily related to lower demand as a
result of the worldwide financial and economic events. In addition,
successful production from shale gas reservoirs contributed to the
supply imbalance and high storage levels in North America.
Update to Alberta Royalty Framework
Effective January 1, 2009, changes to the Alberta royalty regime
under the Alberta Royalty Framework ("ARF") include the
implementation of a sliding scale for oil sands royalties ranging
from 1% to 9% on a gross revenue basis pre-payout and 25% - 40% on
a net revenue basis post-payout, depending on benchmark crude oil
pricing.
In addition, effective January 1, 2009, new royalty formulas
under the ARF for conventional crude oil and natural gas are to
operate on sliding scales ranging up to 50%, determined by
commodity prices and well productivity.
In March 2009, the Government of Alberta announced new incentive
programs to stimulate activity in Alberta. These programs provide
for:
- A royalty credit of $200 per metre on new conventional crude
oil and natural gas wells drilled between April 1, 2009 and March
31, 2010.
- Reduced royalty rates that set the maximum royalty at 5% for
the first 12 months of production, up to a maximum of 50,000 bbl or
500 mmcf, for new conventional crude oil and natural gas wells that
commence production between April 1, 2009 and March 31, 2010.
OPERATING HIGHLIGHTS - CONVENTIONAL
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
Sales price (2) $ 41.25 $ 45.81 $ 78.99
Royalties 3.98 4.49 8.70
Production expense 15.02 16.33 14.81
----------------------------------------------------------------------------
Netback $ 22.25 $ 24.99 $ 55.48
----------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 5.46 $ 7.03 $ 7.77
Royalties 0.72 1.08 1.35
Production expense 1.18 1.06 1.03
----------------------------------------------------------------------------
Netback $ 3.56 $ 4.89 $ 5.39
----------------------------------------------------------------------------
Barrels of oil equivalent
($/boe) (1)
Sales price (2) $ 37.87 $ 43.84 $ 65.09
Royalties 4.14 5.37 8.43
Production expense 11.77 12.05 11.02
----------------------------------------------------------------------------
Netback $ 21.96 $ 26.42 $ 45.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
DAILY PRODUCTION, before royalties
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America - Conventional 253,833 240,831 248,960
North America - Oil Sands
Mining and Upgrading 3,384 - -
North Sea 42,369 42,991 49,568
Offshore West Africa 30,431 25,748 28,689
----------------------------------------------------------------------------
330,017 309,570 327,217
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,347 1,405 1,513
North Sea 10 10 11
Offshore West Africa 12 12 14
----------------------------------------------------------------------------
1,369 1,427 1,538
----------------------------------------------------------------------------
Total barrels of oil
equivalent (boe/d) 558,142 547,399 583,488
----------------------------------------------------------------------------
Product mix
Light/medium crude oil and
NGLs 22% 22% 23%
Pelican Lake crude oil 6% 7% 6%
Primary heavy crude oil 15% 16% 15%
Thermal heavy crude oil 15% 12% 12%
Oil Sands Mining and Upgrading
synthetic crude oil 1% - -
Natural gas 41% 43% 44%
----------------------------------------------------------------------------
Percentage of gross revenue (1)
(excluding midstream revenue)
Crude oil and NGLs 64% 60% 68%
Natural gas 36% 40% 32%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
2009 2008 2008
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America - Conventional 224,506 210,496 216,585
North America - Oil Sands
Mining and Upgrading 3,362 - -
North Sea 42,265 42,910 49,473
Offshore West Africa 28,341 23,907 23,496
----------------------------------------------------------------------------
298,474 277,313 289,554
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,180 1,198 1,260
North Sea 10 10 11
Offshore West Africa 11 10 11
----------------------------------------------------------------------------
1,201 1,218 1,282
----------------------------------------------------------------------------
Total barrels of oil
equivalent (boe/d) 498,740 480,409 503,250
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 synthetic crude oil.
Total crude oil and NGLs production for the first quarter of
2009 of 330,017 bbl/d was comparable to 327,217 bbl/d for the first
quarter of 2008, and increased 7% from 309,570 bbl/d for the prior
quarter. The increase from the prior quarter was primarily due to
increased thermal production in North America, increased production
as a result of the drilling program in the Baobab Field in Offshore
West Africa, and first production from Horizon. Crude oil and NGLs
production in the first quarter of 2009 was within the Company's
previously issued guidance of 320,000 to 344,000 bbl/d.
Natural gas production continued to represent the Company's
largest product offering, accounting for 41% of the Company's total
production. Natural gas production for the first quarter of 2009
averaged 1,369 mmcf/d compared to 1,538 mmcf/d for the first
quarter of 2008 and 1,427 mmcf/d for the prior quarter. The
decrease in natural gas production from the comparable periods
primarily reflected production declines due to the Company's
strategic reduction in natural gas drilling activity. First quarter
natural gas production was at the low end of the Company's
previously issued guidance of 1,365 to 1,394 mmcf/d.
For 2009, revised annual production guidance is targeted to
average between 326,000 and 389,000 bbl/d of crude oil and NGLs and
between 1,274 and 1,330 mmcf/d of natural gas. Second quarter 2009
production guidance is targeted to average between 321,000 and
359,000 bbl/d of crude oil and NGLs and between 1,318 and 1,353
mmcf/d of natural gas.
North America - Conventional
North America conventional crude oil and NGLs production for the
first quarter of 2009 increased 2% to average 253,833 bbl/d from
248,960 bbl/d for the first quarter of 2008, and increased 5% from
240,831 bbl/d for the prior quarter. The increase in crude oil and
NGLs production from the prior periods was primarily due to the
cyclic nature of the Company's thermal production and new
production capacity from the Primrose East development.
For the first quarter of 2009, natural gas production decreased
11% to 1,347 mmcf/d from 1,513 mmcf/d for the first quarter of
2008, and decreased 4% from 1,405 mmcf/d for the prior quarter,
consistent with the Company's strategic decision to reduce natural
gas drilling activity.
North America - Oil Sands Mining and Upgrading
Horizon Phase 1 achieved first production of synthetic crude oil
during the first quarter of 2009, with production averaging 3,384
bbl/d.
North Sea
North Sea crude oil production for the first quarter of 2009
decreased 15% to 42,369 bbl/d from 49,568 bbl/d for the first
quarter of 2008 and 1% from 42,991 bbl/d for the prior quarter.
First quarter production was in line with the prior quarter and
expectations.
Offshore West Africa
Offshore West Africa crude oil production increased 6% to 30,431
bbl/d for the first quarter of 2009 from 28,689 bbl/d for the first
quarter of 2008, and 18% from 25,748 bbl/d for the prior quarter.
In the first quarter of 2009 there was a full quarter of production
from three of the wells drilled in the Baobab Field, and the fourth
and final well was completed and came on stream early in the second
quarter of 2009.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when
title transfers to the customer and delivery has taken place. The
related crude oil volumes by segment, which have not been
recognized in revenue, were as follows:
----------------------------------------
Mar 31 Dec 31 Mar 31
(bbl) 2009 2008 2008
----------------------------------------------------------------------------
North America - Conventional,
related to pipeline fill 761,351 761,351 1,097,526
North America - Oil Sands
Mining and Upgrading, primarily
related to pipeline fill 304,544 - -
North Sea, related to timing
of liftings 1,305,169 558,904 637,755
Offshore West Africa, related
to timing of liftings (231,042) 609,444 260,649
----------------------------------------------------------------------------
2,140,022 1,929,699 1,995,930
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the first quarter of 2009, an additional 94,000 barrels
of crude oil produced in the Company's international operations,
which were deferred and included in inventory at December 31, 2008,
were sold, increasing cash flow from operations by approximately
$11 million.
PRODUCT PRICES - CONVENTIONAL
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) (2)
North America $ 37.40 $ 40.39 $ 72.86
North Sea $ 54.67 $ 63.07 $ 99.01
Offshore West Africa $ 54.27 $ 65.80 $ 96.31
Company average $ 41.25 $ 45.81 $ 78.99
Natural gas ($/mcf) (1) (2)
North America $ 5.46 $ 7.00 $ 7.80
North Sea $ 4.28 $ 5.19 $ 3.30
Offshore West Africa $ 6.68 $ 12.54 $ 7.89
Company average $ 5.46 $ 7.03 $ 7.77
Company average ($/boe) (1) (2) $ 37.87 $ 43.84 $ 65.09
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North America
North America realized crude oil prices decreased 49% to average
$37.40 per bbl for the first quarter of 2009 from $72.86 per bbl
for the first quarter of 2008, and 7% from $40.39 per bbl for the
prior quarter. The decrease from the comparable periods was
primarily a result of decreased WTI benchmark pricing, partially
offset by a narrower Heavy Differential and the impact of the
weaker Canadian dollar relative to the US dollar.
During the first quarter of 2009, the Company continued to focus
on its crude oil marketing strategy, and contributed approximately
156,000 bbl/d of heavy crude oil blends to the Western Canadian
Select stream.
Realized North America natural gas prices decreased 30% to
average $5.46 per mcf for the first quarter of 2009 from $7.80 per
mcf for the first quarter of 2008, and 22% from $7.00 per mcf for
the prior quarter. The decreases in natural gas prices from the
comparable periods were primarily related to lower benchmark prices
due to lower demand and high storage levels in the first quarter of
2009.
Comparisons of the prices received for the Company's North
America production by product type were as follows:
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Wellhead Price (1) (2)
Light/medium crude oil and NGLs
(C$/bbl) $ 45.97 $ 46.58 $ 88.78
Pelican Lake crude oil (C$/bbl) $ 37.50 $ 40.91 $ 72.77
Primary heavy crude oil (C$/bbl) $ 37.99 $ 37.85 $ 68.61
Thermal heavy crude oil (C$/bbl) $ 31.53 $ 38.68 $ 65.97
Natural gas (C$/mcf) $ 5.46 $ 7.00 $ 7.80
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 decreased 45% to average
$54.67 per bbl for the first quarter of 2009 from $99.01 per bbl
for the first quarter of 2008, and 13% from $63.07 per bbl for the
prior quarter. Realized crude oil prices in the North Sea during
the first quarter were impacted by the declining Brent benchmark
pricing, partially offset by the impact of the weakening of the
Canadian dollar.
Offshore West Africa
Offshore West Africa realized crude oil prices decreased 44% to
average $54.27 per bbl for the first quarter of 2009 from $96.31
per bbl for the first quarter of 2008, and 18% from $65.80 per bbl
for the prior quarter. Realized crude oil prices in Offshore West
Africa during the first quarter were impacted by the declining
Brent benchmark pricing, partially offset by the impact of the
weakening of the Canadian dollar. Realized crude oil prices in
Offshore West Africa were also impacted by the timing of liftings
from each field.
ROYALTIES - CONVENTIONAL
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
North America $ 4.54 $ 5.25 $ 9.63
North Sea $ 0.13 $ 0.12 $ 0.19
Offshore West Africa $ 3.73 $ 4.71 $ 17.43
Company average $ 3.98 $ 4.49 $ 8.70
Natural gas ($/mcf) (1)
North America $ 0.73 $ 1.09 $ 1.36
Offshore West Africa $ 0.46 $ 1.26 $ 1.43
Company average $ 0.72 $ 1.08 $ 1.35
Company average ($/boe) (1) $ 4.14 $ 5.37 $ 8.43
Percentage of revenue (2)
Crude oil and NGLs 10% 10% 11%
Natural gas 13% 15% 17%
Boe 11% 12% 13%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North America
North America royalties for the first quarter of 2009 reflect
the impact of the change in the ARF and weaker realized commodity
prices.
Crude oil and NGLs royalties averaged approximately 12% of
revenues for the first quarter of 2009, compared to 13% for the
first quarter in 2008 and 13% in the prior quarter. Crude oil and
NGLs royalties per bbl are anticipated to average 10% to 15% of
gross revenue for 2009.
Natural gas royalties averaged approximately 13% of revenues for
the first quarter of 2009 compared to 17% for the first quarter of
2008 and 16% for the prior quarter. Natural gas royalties are
anticipated to average 12% to 15% of gross revenue for 2009.
Offshore West Africa
Under the terms of the Production Sharing Contracts, royalty
rates fluctuate based on realized commodity pricing and capital
costs. Royalty rates as a percentage of revenue averaged
approximately 7% for the first quarter of 2009 compared to 18% for
the first quarter of 2008 and 7% for the prior quarter. Offshore
West Africa royalty rates are anticipated to average 6% to 9% of
gross revenue for 2009.
PRODUCTION EXPENSE - CONVENTIONAL
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
North America $ 14.60 $ 14.31 $ 13.88
North Sea $ 22.39 $ 28.77 $ 22.35
Offshore West Africa $ 11.39 $ 14.47 $ 8.03
Company average $ 15.02 $ 16.33 $ 14.81
Natural gas ($/mcf) (1)
North America $ 1.17 $ 1.04 $ 1.01
North Sea $ 1.86 $ 1.96 $ 2.33
Offshore West Africa $ 1.70 $ 2.51 $ 1.25
Company average $ 1.18 $ 1.06 $ 1.03
Company average ($/boe) (1) $ 11.77 $ 12.05 $ 11.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 2009 increased 5% to $14.60 per bbl from $13.88
per bbl for the first quarter of 2008 and 2% from $14.31 per bbl
for the prior quarter. The increase in production expense per
barrel for the first quarter of 2009 was a result of the timing of
steam cycles, increased property tax, and increased seasonal costs
related to cold weather, partially offset by the lower cost of
natural gas for fuel for the Company's thermal operations. North
America crude oil and NGLs production expense is anticipated to
average $15.00 to $15.65 per bbl for 2009.
North America natural gas production expense for the first
quarter of 2009 increased 16% to $1.17 per mcf from $1.01 per mcf
for the first quarter of 2008 and 13% from $1.04 per mcf for the
prior quarter. The increase in production expense per mcf was
primarily a result of lower production volumes on the fixed cost
portion of production costs and increased seasonal costs related to
winter access areas and cold weather. North America natural gas
production expense is anticipated to average $1.05 to $1.15 per mcf
for 2009.
North Sea
North Sea crude oil production expense decreased on a per barrel
basis from the prior quarter due to lower maintenance costs and the
timing of liftings from various fields. Production expense is
anticipated to average $27.50 to $29.50 per bbl for 2009.
Offshore West Africa
Offshore West Africa crude oil production expense decreased on a
per barrel basis from the prior quarter due to higher production
volumes and lower maintenance costs. Production expense is also
impacted by the timing of liftings of each field. Production
expense is anticipated to average $13.00 to $15.00 per bbl for
2009.
MIDSTREAM
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2009 2008 2008
----------------------------------------------------------------------------
Revenue $ 19 $ 17 $ 20
Production expense 5 6 5
----------------------------------------------------------------------------
Midstream cash flow 14 11 15
Depreciation 2 2 2
----------------------------------------------------------------------------
Segment earnings before taxes $ 12 $ 9 $ 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable periods.
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Expense ($ millions) $ 642 $ 664 $ 686
$/boe (2) $ 13.21 $ 13.20 $ 12.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes DD&A on midstream and Oil Sands Mining and
Upgrading assets.
(2) Amounts expressed on a per unit basis are based on sales volumes.
The decrease in Depletion, Depreciation and Amortization expense from the
prior periods was primarily due to the impact of lower sales volumes.
ASSET RETIREMENT OBLIGATION ACCRETION (1)
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Expense ($ millions) $ 17 $ 19 $ 17
$/boe (2) $ 0.35 $ 0.38 $ 0.31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes accretion on Oil Sands Mining and Upgrading assets.
(2) 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.
ADMINISTRATION EXPENSE
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Expense ($ millions) $ 47 $ 46 $ 43
$/boe (1) $ 0.95 $ 0.91 $ 0.80
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the first quarter of 2009 was comparable to the
prior periods.
STOCK-BASED COMPENSATION EXPENSE (RECOVERY)
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2009 2008 2008
----------------------------------------------------------------------------
Expense (recovery) $ 4 $ (203) $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company recorded a $4 million ($3 million after-tax)
stock-based compensation expense for the three months ended March
31, 2009 primarily as a result of normal course graded vesting of
options granted in prior periods, the impact of vested options
exercised or surrendered during the period and the change in the
Company's share price (Company's share price as at: March 31, 2009
- C$48.91; December 31, 2008 - C$48.75; March 31, 2008 - C$70.27;
December 31, 2007 - C$72.58). For the three months ended March 31,
2009, the Company recorded a $9 million recovery on previously
capitalized stock-based compensation to Oil Sands Mining and
Upgrading (March 31, 2008 - $5 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, 2009.
For the three months ended March 31, 2009, the Company paid $28
million for stock options surrendered for cash settlement (March
31, 2008 - $80 million).
INTEREST EXPENSE
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions, except per boe amounts) 2009 2008 2008
----------------------------------------------------------------------------
Expense, gross $ 143 $ 158 $ 160
Less: capitalized interest, Oil
Sands Mining and Upgrading 86 135 111
----------------------------------------------------------------------------
Expense, net $ 57 $ 23 $ 49
$/boe (1) $ 1.14 $ 0.45 $ 0.92
Average effective interest rate 4.4% 5.0% 5.5%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest expense and the Company's average effective
interest rate decreased from the comparable quarters in 2008
primarily due to decreasing short-term borrowing rates, offset by
the impact of the weaker Canadian dollar relative to the US dollar
on US dollar borrowings during the first quarter of 2009.
During the first quarter of 2009, interest capitalization ceased
on Horizon Phase 1, 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) 2009 2008 2008
----------------------------------------------------------------------------
Crude oil and NGLs financial
instruments $ (585) $ (179) $ 463
Natural gas financial instruments (32) - (47)
Foreign currency contracts (24) (122) -
----------------------------------------------------------------------------
Realized (gain) loss $ (641) $ (301) $ 416
----------------------------------------------------------------------------
Crude oil and NGLs financial
instruments $ 483 $ (2,112) $ 51
Natural gas financial instruments (24) (13) 59
Foreign currency contracts and
interest rate swaps 4 18 (2)
----------------------------------------------------------------------------
Unrealized loss (gain) $ 463 $ (2,107) $ 108
----------------------------------------------------------------------------
Net (gain) loss $ (178) $ (2,408) $ 524
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The net realized (gain) loss from crude oil and natural gas
derivative financial instruments would have (increased) decreased
the Company's average realized prices as follows:
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) $ (19.84) $ (6.16) $ 15.47
Natural gas ($/mcf) (1) $ (0.26) $ - $ (0.33)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Complete details related to outstanding derivative financial
instruments at March 31, 2009 are disclosed in note 11 to the
Company's unaudited interim consolidated financial statements.
Due to changes in crude oil and natural gas forward pricing and
the reversal of prior period unrealized gains and losses, the
Company recorded a net unrealized loss of $463 million ($320
million after-tax) on its risk management activities for the three
months ended March 31, 2009 (December 31, 2008 - unrealized gain of
$2,107 million, $1,435 million after-tax; March 31, 2008 -
unrealized loss of $108 million, $76 million after-tax).
FOREIGN EXCHANGE
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2009 2008 2008
----------------------------------------------------------------------------
Net realized gain $ (15) $ (51) $ (12)
Net unrealized loss (1) 138 613 126
----------------------------------------------------------------------------
Net loss $ 123 $ 562 $ 114
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net unrealized foreign exchange loss for the first quarter
of 2009 was primarily due to the weakening of the Canadian dollar
with respect to the US dollar debt, together with the impact of the
re-measurement of North Sea future income tax liabilities
denominated in UK pounds sterling. Also included in net unrealized
loss for the respective periods was the impact of cross currency
swaps (March 31, 2009 - unrealized gain of $68 million; December
31, 2008 - unrealized gain of $313 million; March 31, 2008 -
unrealized gain of $75 million). The net realized foreign exchange
gain for the three months ended March 31, 2009 was primarily due to
the result of foreign exchange rate fluctuations on settlement of
working capital items denominated in US dollars or UK pounds
sterling. The Canadian dollar ended the first quarter at US$0.7935
(December 31, 2008 - US$0.8166; March 31, 2008 - US$0.9729).
TAXES
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions, except income tax rates) 2009 2008 2008
----------------------------------------------------------------------------
Current $ 7 $ 27 $ 70
Deferred (3) (5) (21)
----------------------------------------------------------------------------
Taxes other than income tax $ 4 $ 22 $ 49
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America $ 5 $ - $ 21
North Sea 98 12 96
Offshore West Africa 14 12 38
----------------------------------------------------------------------------
Current income tax 117 24 155
Future income tax (recovery) expense (56) 817 80
----------------------------------------------------------------------------
61 841 235
Income tax rate and other
legislative changes (1) (2) 19 - 41
----------------------------------------------------------------------------
$ 80 $ 841 $ 276
----------------------------------------------------------------------------
Effective income tax rate before
non-recurring benefits 21.9% 32.2% 28.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the effect of a one time recovery of $19 million due to British
Columbia corporate income tax rate reductions substantively enacted or
enacted during the first quarter of 2009.
(2) Includes the effect of a one time recovery of $19 million due to British
Columbia corporate income tax rate reductions and $22 million due to
Cote d'Ivoire corporate income tax rate reductions substantively enacted
or enacted during the first quarter of 2008.
CAPITAL EXPENDITURES (1)
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2009 2008 2008
----------------------------------------------------------------------------
Expenditures on property, plant and
equipment
Net property acquisitions
(dispositions) $ 27 $ 34 $ (8)
Land acquisition and retention 13 18 12
Seismic evaluations 28 22 27
Well drilling, completion and
equipping 498 505 452
Production and related facilities 290 382 319
----------------------------------------------------------------------------
Total net reserve replacement
expenditures 856 961 802
----------------------------------------------------------------------------
Oil Sands Mining and Upgrading:
Horizon Phase 1 construction costs 128 557 665
Horizon Phase 1 commissioning costs
and other 156 115 90
Horizon Phases 2/3 construction
costs 19 94 77
Capitalized interest, stock-based
compensation and other 79 78 109
----------------------------------------------------------------------------
Total Oil Sands Mining and
Upgrading (2) 382 844 941
----------------------------------------------------------------------------
Midstream 5 3 1
Abandonments (3) 9 15 6
Head office 4 4 3
----------------------------------------------------------------------------
Total net capital expenditures $ 1,256 $ 1,827 $ 1,753
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 599 $ 486 $ 663
North Sea 42 117 45
Offshore West Africa 215 358 94
Oil Sands Mining and Upgrading 382 844 941
Midstream 5 3 1
Abandonments (3) 9 15 6
Head office 4 4 3
----------------------------------------------------------------------------
Total $ 1,256 $ 1,827 $ 1,753
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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,
2009 were $1,256 million compared to $1,753 million for the three
months ended March 31, 2008 and $1,827 million for the three months
ended December 31, 2008. Capital expenditures in the first quarter
of 2009 primarily reflect growth projects, most notably the
substantial completion of Horizon Phase 1 construction, offset by
the effects of an overall strategic reduction in the North America
natural gas drilling programs.
Drilling Activity (number of wells)
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2009 2008 2008
----------------------------------------------------------------------------
Net successful natural gas wells 64 41 161
Net successful crude oil wells 93 182 173
Dry natural gas and crude oil wells 15 11 11
Stratigraphic test / service wells 236 97 15
----------------------------------------------------------------------------
Total 408 331 360
Success rate (excluding stratigraphic
test / service wells) 91% 95% 97%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America
North America, excluding Oil Sands Mining and Upgrading,
accounted for approximately 49% of the total capital expenditures
for the three months ended March 31, 2009 compared to approximately
38% for the first quarter of 2008 and 28% for the prior
quarter.
During the first quarter of 2009, the Company targeted 72 net
natural gas wells, including 15 wells in Northeast British
Columbia, 20 wells in the Northern Plains region, 29 wells in
Northwest Alberta, and 8 wells in the Southern Plains region. The
Company also targeted 97 net crude oil wells during the same
period. The majority of these wells were concentrated in the
Company's crude oil Northern Plains region where 72 heavy crude oil
wells, 3 Pelican Lake crude oil wells, and 14 thermal crude oil
wells were drilled. Another 8 wells targeting light crude oil were
drilled outside the Northern Plains region.
The Company continued to access its large crude oil drilling
inventory to maximize value in both the short and long term. Due to
the Company's focus on drilling crude oil wells in recent years and
as a result of royalty changes under the ARF, natural gas drilling
activities have been reduced to manage overall capital spending.
Deferred natural gas well locations have been retained in the
Company's prospect inventory.
As part of the phased expansion of its In-Situ Oil Sands Assets,
the Company is continuing to develop its Primrose thermal projects.
Overall Primrose thermal production for the first quarter of 2009
averaged approximately 82,000 bbl/d compared to approximately
69,000 bbl/d for the first quarter of 2008 and approximately 64,000
bbl/d for the prior quarter.
The Primrose East expansion was completed and first steaming
commenced in September 2008, with first production achieved in the
fourth quarter of 2008. During the first quarter of 2009,
operational issues on one of the pads has caused steaming to cease
on all well pads in the Primrose East project area and the Company
is continuing to work on resolving the issues.
Development of new pads and secondary recovery conversion
projects at Pelican Lake continued as expected throughout the first
quarter of 2009. Drilling consisted of 3 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 2009,
consistent with the comparable periods in 2008.
For the second quarter of 2009, the Company's overall planned
drilling activity in North America is expected to be comprised of 1
natural gas well and 63 crude oil wells, excluding stratigraphic
and service wells.
Oil Sands Mining and Upgrading
During the first quarter of 2009, construction of Horizon Phase
1 was substantially complete, subject to final commissioning
efforts. In addition, the Company has recognized additional asset
retirement obligations related to oil sands mining operations and
tailings ponds.
North Sea
In the first quarter of 2009, the Company completed its program
of infill drilling, continued to focus on waterflood optimizations,
and continued drilling the Deep Banff exploration well. The Company
continues to focus on lowering costs and high grading inventory in
preparation for restart when economics are more favorable. During
the first quarter, 0.9 net wells were drilled, with 0.4 net wells
in progress at the end of the quarter.
Offshore West Africa
During the first quarter of 2009, 2.3 net crude oil wells were
drilled, with an injection well in progress at the Olowi Field, in
Offshore Gabon at the end of the quarter.
At Baobab, the fourth and final well in the drilling program was
completed in the quarter and the drilling rig was released early in
the second quarter. At the Olowi Field, the floating production
storage and offtake vessel ("FPSO") and the Conductor Supported
Platform were commissioned in readiness for first crude oil
production, which was achieved during April 2009. Construction also
continued on the wellhead towers during the quarter, with
installation expected in the third quarter of 2009.
LIQUIDITY AND CAPITAL RESOURCES
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions, except ratios) 2009 2008 2008
----------------------------------------------------------------------------
Working capital (deficit) (1) $ 237 $ 392 $ (1,572)
Long-term debt (2) (3) $ 13,132 $ 13,016 $ 11,230
Share capital $ 2,809 $ 2,768 $ 2,725
Retained earnings 15,592 15,344 11,248
Accumulated other comprehensive
income 315 262 95
----------------------------------------------------------------------------
Shareholders' equity $ 18,716 $ 18,374 $ 14,068
Debt to book capitalization (3) (4) 41% 41% 44%
Debt to market capitalization (3)
(5) 33% 33% 23%
After tax return on average common
shareholders' equity (6) 28% 33% 24%
After tax return on average capital
employed (3) (7) 17% 19% 14%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2009 - $205
million, December 31, 2008 - $420 million, March 31, 2008 - $nil).
(3) Long-term debt is stated at its carrying value, net of fair value
adjustments, original issue discounts and transaction costs.
(4) Calculated as current and long-term debt; divided by the book value of
common shareholders' equity plus current and long-term debt.
(5) Calculated as current and long-term debt; divided by the market value of
common shareholders' equity plus current and long-term debt.
(6) Calculated as net earnings for the twelve month trailing period; as a
percentage of average common shareholders' equity for the period.
(7) Calculated as net earnings plus after-tax interest expense for the
twelve month trailing period; as a percentage of average capital
employed for the period. Average capital employed is the average
shareholders' equity and current and long-term debt for the period,
including $11,537 million in average capital employed related to the
Oil Sands Mining and Upgrading assets (December 31, 2008 -
$10,678 million; March 31, 2008 - $7,876 million).
At March 31, 2009, the Company's capital resources consisted
primarily of cash flow from operations, available bank credit
facilities and access to debt capital markets. Cash flow from
operations is dependent on factors discussed in the "Risks and
Uncertainties" section of the Company's December 31, 2008 annual
MD&A. The Company's ability to renew existing bank credit
facilities and raise new debt is also dependent upon these factors,
as well as maintaining an investment grade debt rating and the
condition of capital and credit markets.
The ongoing worldwide financial and economic events continued to
result in a significant tightening of the availability and cost of
new sources of liquidity including bank credit facilities and funds
derived from debt capital markets. In light of these credit
challenges, the Company continues to review its liquidity sources
as well as its exposure to counterparties on a regular basis and
has concluded that its capital resources are sufficient to meet
ongoing short-, medium- and long-term commitments. Specifically,
the Company continues to believe that its internally generated cash
flow from operations supported by the implementation of its hedge
policy, the flexibility of its capital expenditure programs
supported by its multi-year financial plans, its existing 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. Further, the Company believes that its
counterparties currently have the financial capacity to settle
outstanding obligations in the normal course of business.
At March 31, 2009, the Company had $1,769 million of available
credit under its bank credit facilities, which together with cash
flow from operating activities to be generated in 2009 supported by
its commodity risk management program and the ability to actively
manage the capital expenditure programs, is forecasted to be
sufficient to repay the non-revolving bank credit facility maturing
October 2009. The Company's current debt ratings are BBB (high)
with a negative trend by DBRS Limited, Baa2 with a stable outlook
by Moody's Investors Service and BBB with a stable outlook by
Standard & Poor's.
Further details related to the Company's long-term debt at March
31, 2009 are discussed in note 4 to the Company's unaudited interim
consolidated financial statements.
Long-term debt was $13,132 million at March 31, 2009, resulting
in a debt to book capitalization ratio of 41% (December 31, 2008 -
41%; March 31, 2008 - 44%). This ratio is near the midpoint of the
35% to 45% range targeted by management, including the impact of
capital spending on Horizon Phase 1. 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 2009 and 2010 at prices that protect
investment returns to ensure ongoing balance sheet strength and the
completion of its capital expenditure programs. In the future, the
Company may also consider the divestiture of certain non-strategic
and non-core properties to gain additional balance sheet
flexibility.
The Company's commodity hedging program reduces the risk of
volatility in commodity prices and supports the Company's cash flow
for its capital expenditures 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,
2009, in accordance with the policy, approximately 6% of budgeted
crude oil volumes were hedged using collars for 2009 and
approximately 17% of budgeted natural gas volumes were hedged using
collars for 2010. In addition, 92,000 bbl/d of crude oil volumes
are protected by put options for the remainder of 2009 at a strike
price of US$100.00 per bbl.
Further details related to the Company's commodity related
derivative financial instruments outstanding at March 31, 2009 are
discussed in note 11 to the Company's unaudited interim
consolidated financial statements.
Share capital
As at March 31, 2009, there were 541,934,000 common shares
outstanding and 28,663,000 stock options outstanding. As at May 5,
2009, the Company had 541,972,000 common shares outstanding and
28,434,000 stock options outstanding.
In March 2009, the Company's Board of Directors approved an
increase in the annual dividend paid by the Company to $0.42 per
common share for 2009. The increase represented a 5% increase from
2008, recognizes the stability of the Company's cash flow, and
provides a return to Shareholders. The dividend policy undergoes a
periodic review by the Board of Directors and is subject to
change.
Commitments and off balance sheet arrangements
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. As at March 31, 2009, no entities were
consolidated under the Canadian Institute of Chartered Accountants
Handbook Accounting Guideline 15, "Consolidation of Variable
Interest Entities". The following table summarizes the Company's
commitments as at March 31, 2009:
Remaining
($ millions) 2009 2010 2011 2012 2013 Thereafter
----------------------------------------------------------------------------
Product transportation and
pipeline $ 163 $ 193 $ 160 $ 135 $ 125 $ 1,177
Offshore equipment
operating lease $ 151 $ 149 $ 148 $ 119 $ 121 $ 409
Offshore drilling $ 178 $ 64 $ - $ - $ - $ -
Asset retirement
obligations (1) $ 13 $ 11 $ 16 $ 17 $ 26 $ 5,763
Long-term debt (2) $ 1,968 $ 400 $ 504 $ 441 $ 904 $ 6,891
Interest expense (3) $ 400 $ 560 $ 538 $ 489 $ 439 $ 6,167
Office lease $ 19 $ 29 $ 23 $ 2 $ 2 $ 2
Other $ 259 $ 186 $ 17 $ 11 $ 8 $ 21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 2009 - 2013 represent the minimum required expenditures to meet
these obligations. Actual expenditures in any particular year may exceed
these minimum amounts.
(2) The long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or transaction
costs. No debt repayments are reflected for $2,035 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 as at
March 31, 2009.
Legal proceedings
The Company is defendant and plaintiff in a number of legal
actions. In addition, the Company is subject to certain contractor
construction claims related to Horizon. The Company believes that
any liabilities that might arise pertaining to any such matters
would not have a material effect on its consolidated financial
position.
Critical accounting estimates and change in accounting
policies
The preparation of financial statements requires the Company to
make judgements, assumptions and estimates in the application of
generally accepted accounting principles that have a significant
impact on the financial results of the Company. Actual results
could differ from those estimates. A comprehensive discussion of
the Company's significant accounting policies is contained in the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2008.
For the impact of new accounting standards related to goodwill
and intangible assets, refer to note 2 of the unaudited interim
consolidated financial statements as at March 31, 2009.
International Financial Reporting Standards
In February 2008, the CICA's Accounting Standards Board
confirmed that Canadian publicly accountable enterprises will be
required to adopt International Financial Reporting Standards
("IFRS") as promulgated by the International Accounting Standards
Board ("IASB") in place of Canadian GAAP effective January 1,
2011.
The Company commenced its IFRS conversion project in 2008 and
has established a formal 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 Senior 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.
Significant differences were identified in accounting for Property,
Plant & Equipment ("PP&E"), including exploration costs,
depletion and depreciation, impairment testing, capitalized
interest and asset retirement obligations. Other significant
differences were noted in accounting for stock-based compensation,
risk management activities, and income taxes. The Company is
currently performing the necessary research to develop and document
IFRS policies to address the major differences noted. At this time,
the impact on the Company's future financial position and results
of operations is not reasonably determinable. In addition, IFRS is
expected to change prior to adoption in 2011, and the impact of
these potential changes is not known. Included in the potential
IFRS changes is an exposure draft issued in September 2008 by the
IASB that proposes transition rules for oil and gas companies
following full cost accounting. The proposed transition rule would
allow 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. The
Company intends to adopt the transition rule if it is approved.
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 2009,
excluding mark-to-market gains (losses) on risk management
activities, and is not necessarily indicative of future results.
Each separate line item in the sensitivity analysis shows the
effect of a change in that variable only with all other variables
being held constant.
Cash flow Cash flow from Net
from operations Net earnings
operations (per common earnings (per common
($ millions) share, basic) ($ millions) share, basic)
----------------------------------------------------------------------------
Price changes
Crude oil -
WTI
US$1.00/bbl (1)
Excluding
financial
derivatives $ 123 $ 0.23 $ 93 $ 0.17
Including
financial
derivatives $ 86 $ 0.16 $ 64 $ 0.12
Natural gas
- AECO
C$0.10/mcf (1)
Excluding
financial
derivatives $ 26 $ 0.05 $ 19 $ 0.03
Including
financial
derivatives $ 24 $ 0.05 $ 17 $ 0.03
Volume changes
Crude oil -
10,000 bbl/d $ 78 $ 0.14 $ 30 $ 0.06
Natural gas
- 10 mmcf/d $ 13 $ 0.02 $ 4 $ 0.01
Foreign
currency rate
change
$0.01 change
in US$ (1)
Including
financial
derivatives $ 97 - 100 $ 0.18 $ 4 $ 0.01
Interest rate
change - 1% $ 28 $ 0.05 $ 28 $ 0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) For details of outstanding financial instruments in place, refer to note
11 of the Company's unaudited interim consolidated financial statements.
OTHER OPERATING HIGHLIGHTS
NETBACK ANALYSIS
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($/boe) (1) 2009 2008 2008
----------------------------------------------------------------------------
Sales price (2) $ 37.87 $ 43.84 $ 65.09
Royalties 4.14 5.37 8.43
Production expense (3) 11.77 12.05 11.02
----------------------------------------------------------------------------
Netback 21.96 26.42 45.64
Midstream contribution (3) (0.28) (0.23) (0.27)
Administration 0.95 0.91 0.80
Interest, net 1.14 0.45 0.92
Realized risk management (gain) loss (12.81) (5.90) 7.82
Realized foreign exchange gain (0.31) (0.99) (0.22)
Taxes other than income tax -
current 0.15 0.53 1.32
Current income tax - North America 0.10 - 0.40
Current income tax - North Sea 1.96 0.22 1.79
Current income tax - Offshore West
Africa 0.28 0.26 0.71
----------------------------------------------------------------------------
Cash flow $ 30.78 $ 31.17 $ 32.37
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
(3) Excluding intersegment elimination.
FINANCIAL STATEMENTS
Consolidated Balance Sheets
-------------------------
Mar 31 Dec 31
(millions of Canadian dollars, unaudited) 2009 2008
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 10 $ 27
Accounts receivable 1,142 1,059
Inventory, prepaids and other 525 455
Current portion of other long-term assets
(note 3) 1,383 1,851
----------------------------------------------------------------------------
3,060 3,392
Property, plant and equipment (note 13) 39,916 38,966
Other long-term assets (note 3) 368 292
----------------------------------------------------------------------------
$ 43,344 $ 42,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 347 $ 383
Accrued liabilities 1,909 1,802
Future income tax 383 585
Current portion of long-term debt (note 4) 205 420
Current portion of other long-term
liabilities (note 5) 184 230
----------------------------------------------------------------------------
3,028 3,420
Long-term debt (note 4) 12,927 12,596
Other long-term liabilities (note 5) 1,382 1,124
Future income tax 7,291 7,136
----------------------------------------------------------------------------
24,628 24,276
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 7) 2,809 2,768
Retained earnings 15,592 15,344
Accumulated other comprehensive income (note 8) 315 262
----------------------------------------------------------------------------
18,716 18,374
----------------------------------------------------------------------------
$ 43,344 $ 42,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (note 12)
Consolidated Statements of Earnings
Three Months Ended
-------------------------
(millions of Canadian dollars, except per Mar 31 Mar 31
common share amounts, unaudited) 2009 2008
----------------------------------------------------------------------------
Revenues $ 2,186 $ 3,967
Less: royalties (199) (449)
----------------------------------------------------------------------------
Revenues, net of royalties 1,987 3,518
----------------------------------------------------------------------------
Expenses
Production 582 587
Transportation and blending 317 485
Depletion, depreciation and amortization 646 688
Asset retirement obligation accretion (note 5) 19 17
Administration 47 43
Stock-based compensation expense (note 5) 4 -
Interest, net 57 49
Risk management activities (note 11) (178) 524
Foreign exchange loss 123 114
----------------------------------------------------------------------------
1,617 2,507
----------------------------------------------------------------------------
Earnings before taxes 370 1,011
Taxes other than income tax 4 49
Current income tax expense (note 6) 117 155
Future income tax (recovery) expense (note 6) (56) 80
----------------------------------------------------------------------------
Net earnings $ 305 $ 727
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common share (note 10)
Basic and diluted $ 0.56 $ 1.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Shareholders' Equity
Three Months Ended
-------------------------
Mar 31 Mar 31
(millions of Canadian dollars, unaudited) 2009 2008
----------------------------------------------------------------------------
Share capital (note 7)
Balance - beginning of period $ 2,768 $ 2,674
Issued upon exercise of stock options 16 9
Previously recognized liability on stock
options exercised for common shares 25 42
----------------------------------------------------------------------------
Balance - end of period 2,809 2,725
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period 15,344 10,575
Net earnings 305 727
Dividends on common shares (note 7) (57) (54)
----------------------------------------------------------------------------
Balance - end of period 15,592 11,248
----------------------------------------------------------------------------
Accumulated other comprehensive income (note 8)
Balance - beginning of period 262 72
Other comprehensive income, net of taxes 53 23
----------------------------------------------------------------------------
Balance - end of period 315 95
----------------------------------------------------------------------------
Shareholders' equity $ 18,716 $ 14,068
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income
Three Months Ended
-------------------------
Mar 31 Mar 31
(millions of Canadian dollars, unaudited) 2009 2008
----------------------------------------------------------------------------
Net earnings $ 305 $ 727
----------------------------------------------------------------------------
Net change in derivative financial
instruments designated as cash flow hedges
Unrealized (loss) income during the period,
net of taxes of $2 million (2008 - $2 million) (17) 24
Reclassification to net earnings, net of
taxes of $1 million (2008 - $8 million) (3) (17)
----------------------------------------------------------------------------
(20) 7
Foreign currency translation adjustment
Translation of net investment 73 16
----------------------------------------------------------------------------
Other comprehensive income, net of taxes 53 23
----------------------------------------------------------------------------
Comprehensive income $ 358 $ 750
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months Ended
-------------------------
Mar 31 Mar 31
(millions of Canadian dollars, unaudited) 2009 2008
----------------------------------------------------------------------------
Operating activities
Net earnings $ 305 $ 727
Non-cash items
Depletion, depreciation and amortization 646 688
Asset retirement obligation accretion 19 17
Stock-based compensation expense 4 -
Unrealized risk management loss 463 108
Unrealized foreign exchange loss 138 126
Deferred petroleum revenue tax recovery (3) (21)
Future income tax (recovery) expense (56) 80
Other (13) 13
Abandonment expenditures (9) (6)
Net change in non-cash working capital (3) (166)
----------------------------------------------------------------------------
1,491 1,566
----------------------------------------------------------------------------
Financing activities
Repayment of bank credit facilities, net (108) (1,172)
Issue of US dollar debt securities - 1,223
Issue of common shares on exercise of stock
options 16 9
Dividends on common shares (54) (46)
Net change in non-cash working capital (36) 5
----------------------------------------------------------------------------
(182) 19
----------------------------------------------------------------------------
Investing activities
Expenditures on property, plant and equipment (1,247) (1,756)
Net proceeds on sale of property, plant and
equipment - 9
----------------------------------------------------------------------------
Net expenditures on property, plant and
equipment (1,247) (1,747)
Net change in non-cash working capital (79) 168
----------------------------------------------------------------------------
(1,326) (1,579)
----------------------------------------------------------------------------
(Decrease) increase in cash and cash
equivalents (17) 6
Cash and cash equivalents - beginning of
period 27 21
----------------------------------------------------------------------------
Cash and cash equivalents - end of period $ 10 $ 27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 184 $ 146
Taxes paid (recovered)
Taxes other than income tax $ (25) $ 31
Current income tax $ 43 $ 53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes to the consolidated financial statements
(tabular amounts in millions of Canadian dollars, unless otherwise stated,
unaudited)
1. ACCOUNTING POLICIES
The interim consolidated financial statements of Canadian
Natural Resources Limited (the "Company") include the Company and
all of its subsidiaries and partnerships, and have been prepared
following the same accounting policies as the audited consolidated
financial statements of the Company as at December 31, 2008, except
as described in note 2. The interim consolidated financial
statements contain disclosures that are supplemental to the
Company's annual audited consolidated financial statements. Certain
disclosures that are normally required to be included in the notes
to the annual audited consolidated financial statements have been
condensed. These interim financial statements should be read in
conjunction with the Company's audited consolidated financial
statements and notes thereto for the year ended December 31,
2008.
Comparative Figures
Certain prior period figures have been reclassified to conform
to the presentation adopted in 2009.
2. CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2009 the Company adopted the following new
accounting standard issued by the Canadian Institute of Chartered
Accountants ("CICA"):
- Goodwill and Intangible Assets - Section 3064 - "Goodwill and
Intangible Assets" replaces Section 3062 - "Goodwill and Other
Intangible Assets" and Section 3450 - "Research and Development
Costs". In addition, EIC-27 - "Revenue and Expenditures during the
Pre-Operating Period" has been withdrawn. The new standard
addresses when an internally generated intangible asset meets the
definition of an asset. The adoption of this standard, which was
adopted retroactively without restatement, did not have an impact
on the Company's financial statements.
In February 2008, the CICA's Accounting Standards Board
confirmed that Canadian publicly accountable entities will be
required to adopt International Financial Reporting Standards
("IFRS") as promulgated by the International Accounting Standards
Board in place of generally accepted accounting principles in
Canada ("GAAP") effective January 1, 2011. The Company is currently
assessing which accounting policies will be affected by the change
to IFRS and the potential impact of these changes on its financial
position and results of operations.
3. OTHER LONG-TERM ASSETS
-------------------------
Mar 31 Dec 31
2009 2008
----------------------------------------------------------------------------
Risk management (note 11) $ 1,714 $ 2,119
Other 37 24
----------------------------------------------------------------------------
1,751 2,143
Less: current portion 1,383 1,851
----------------------------------------------------------------------------
$ 368 $ 292
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. LONG-TERM DEBT
-------------------------
Mar 31 Dec 31
2009 2008
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities (bankers' acceptances) $ 3,020 $ 4,073
Medium-term notes 1,200 1,200
----------------------------------------------------------------------------
4,220 5,273
----------------------------------------------------------------------------
US dollar denominated debt
US dollar bank credit facilities (bankers'
acceptances)
(2009 - US$750 million; 2008 - US$nil) 945 -
Senior unsecured notes (2009 - US$31 million;
2008 - US$31 million) 39 38
US dollar debt securities (2009 - US$6,300
million; 2008 - US$6,300 million) 7,939 7,715
Less - original issue discount on senior
unsecured notes and US dollar
debt securities (1) (23) (23)
----------------------------------------------------------------------------
8,900 7,730
Fair value of interest rate swaps on US
dollar debt securities (2) 65 68
----------------------------------------------------------------------------
8,965 7,798
----------------------------------------------------------------------------
Long-term debt before transaction costs 13,185 13,071
Less - transaction costs (1) (3) (53) (55)
----------------------------------------------------------------------------
13,132 13,016
Less: current portion 205 420
----------------------------------------------------------------------------
$ 12,927 $ 12,596
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has included unamortized original issue discounts and
directly attributable transaction costs in the carrying value of the
outstanding debt.
(2) The carrying values of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $65 million (2008 - $68 million) to reflect the fair value impact of
hedge accounting.
(3) Transaction costs primarily represent underwriting commissions charged
as a percentage of the related debt offerings, as well as legal, rating
agency and other professional fees.
Bank credit facilities
As at March 31, 2009, the Company had in place unsecured bank
credit facilities of $5,812 million, comprised of:
- a $125 million demand credit facility;
- a non-revolving syndicated credit facility of $1,930 million
maturing October 2009;
- a revolving syndicated credit facility of $2,230 million
maturing June 2012;
- a revolving syndicated credit facility of $1,500 million
maturing June 2012; and
- a Pounds Sterling 15 million demand credit facility related to
the Company's North Sea operations.
The revolving syndicated credit facilities are extendible
annually for one year periods at the mutual agreement of the
Company and the lenders. If the facilities are not extended, the
full amount of the outstanding principal would be repayable on the
maturity date. 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 has $1,930 million remaining on the non-revolving
syndicated credit facility maturing October 2009 related to the
acquisition of Anadarko Canada Corporation. During 2009, the
Company plans to fully retire this facility from its existing
borrowing capacity under its other long-term bank credit facilities
of $1,725 million supported by cash flow from operating activities,
including the commodity risk management activities. Subsequent to
March 31, 2009, $285 million was repaid on this facility.
Subsequent to March 31, 2009, the Company renegotiated its
demand credit facility, increasing it to $200 million.
The weighted average interest rate of the bank credit facilities
outstanding at March 31, 2009, was 1.0% (December 31, 2008 -
2.2%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $378 million, including $300
million related to Horizon Oil Sands ("Horizon"), were outstanding
at March 31, 2009.
Medium-term notes
The Company has $2,600 million remaining on its outstanding
$3,000 million base shelf prospectus filed in September 2007 that
allows for the issue of medium-term notes in Canada until October
2009. If issued, these securities will bear interest as determined
at the date of issuance.
US dollar debt securities
The Company has US$1,800 million remaining on its outstanding
US$3,000 million base shelf prospectus filed in September 2007 that
allows for the issue of US dollar debt securities in the United
States until October 2009. If issued, these securities will bear
interest as determined at the date of issuance.
5. OTHER LONG-TERM LIABILITIES
-------------------------
Mar 31 Dec 31
2009 2008
----------------------------------------------------------------------------
Asset retirement obligations $ 1,336 $ 1,064
Stock-based compensation 113 171
Other 117 119
----------------------------------------------------------------------------
1,566 1,354
Less: current portion 184 230
----------------------------------------------------------------------------
$ 1,382 $ 1,124
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset retirement obligations
At March 31, 2009, the Company's total estimated undiscounted
costs to settle its asset retirement obligations were approximately
$5,846 million (December 31, 2008 - $4,474 million). These costs
will be incurred over the lives of the operating assets and have
been discounted using a weighted average credit-adjusted risk-free
rate of 7.0% (December 31, 2008 - 6.7%). A reconciliation of the
discounted asset retirement obligations is as follows:
-----------------------------
Three Months Year
Ended Ended
Mar 31, 2009 Dec 31, 2008
----------------------------------------------------------------------------
Balance - beginning of period $ 1,064 $ 1,074
Liabilities incurred (1) 249 18
Liabilities acquired - 3
Liabilities settled (9) (38)
Asset retirement obligation accretion 19 71
Revision of estimates - (156)
Foreign exchange 13 92
----------------------------------------------------------------------------
Balance - end of period $ 1,336 $ 1,064
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) During the first quarter of 2009, the Company recognized additional
asset retirement obligations related to Horizon.
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, 2009 Dec 31, 2008
----------------------------------------------------------------------------
Balance - beginning of period $ 171 $ 529
Stock-based compensation expense (recovery) 4 (52)
Cash payments for options surrendered (28) (207)
Transferred to common shares (25) (76)
Recovery to Oil Sands Mining and Upgrading (9) (23)
----------------------------------------------------------------------------
Balance - end of period 113 171
Less: current portion 113 159
----------------------------------------------------------------------------
$ - $ 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended
-------------------------
Mar 31 Mar 31
2009 2008
----------------------------------------------------------------------------
Current income tax - North America $ 5 $ 21
Current income tax - North Sea 98 96
Current income tax - Offshore West Africa 14 38
----------------------------------------------------------------------------
Current income tax expense 117 155
Future income tax (recovery) expense (56) 80
----------------------------------------------------------------------------
Income tax expense $ 61 $ 235
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, North America and North Sea
current income taxes will vary depending upon available income tax
deductions related to the nature, timing and amount of capital
expenditures incurred in any particular year.
During the first quarter of 2009, substantively enacted income
tax rate changes resulted in a reduction of future income tax
liabilities of $19 million in British Columbia (2008 - $19 million
reduction in British Columbia, $22 million reduction in Cote
d'Ivoire).
7. SHARE CAPITAL
---------------------------------
Three Months Ended Mar 31, 2009
Issued Number of shares
Common shares (thousands) Amount
----------------------------------------------------------------------------
Balance - beginning of period 540,991 $ 2,768
Issued upon exercise of stock options 943 16
Previously recognized liability on stock
options exercised - 25
----------------------------------------------------------------------------
Balance - end of period 541,934 $ 2,809
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dividend policy
In March 2009, the Board of Directors set the regular quarterly
dividend at $0.105 per common share. The Company has paid regular
quarterly dividends in January, April, July, and October of each
year since 2001. The dividend policy undergoes a periodic review by
the Board of Directors and is subject to change.
Stock options
---------------------------------
Three Months Ended Mar 31, 2009
Weighted
average
Stock options exercise
(thousands) price
----------------------------------------------------------------------------
Outstanding - beginning of period 30,962 $ 51.94
Granted 176 $ 47.74
Surrendered for cash settlement (1,041) $ 17.74
Exercised for common shares (943) $ 16.91
Forfeited (491) $ 58.45
----------------------------------------------------------------------------
Outstanding - end of period 28,663 $ 54.20
----------------------------------------------------------------------------
Exercisable - end of period 9,297 $ 47.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of accumulated other comprehensive income, net of taxes,
were as follows:
Three Months Ended
-------------------------
Mar 31 Mar 31
2009 2008
----------------------------------------------------------------------------
Derivative financial instruments designated
as cash flow hedges $ 99 $ 108
Foreign currency translation adjustment 216 (13)
----------------------------------------------------------------------------
$ 315 $ 95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. CAPITAL DISCLOSURES
As required by Canadian GAAP, the Company must provide certain
disclosures regarding its objectives, policies and processes for
managing capital, as well as provide certain quantitative data
about capital. As the Company does not have any externally imposed
regulatory capital requirements, for the purposes of this
disclosure, the Company has defined its capital to mean its
long-term debt and consolidated shareholders' equity, as determined
each reporting date.
The Company's objectives when managing its capital structure are
to maintain financial flexibility and balance to enable the Company
to access capital markets to sustain its on-going operations and to
support its growth strategies. The Company primarily monitors
capital on the basis of an internally derived non-GAAP financial
measure referred to as its "debt to book capitalization ratio",
which is the arithmetic ratio of 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 near the midpoint of the target range at 41% including
the impact of capital spending on Horizon Phase 1.
Readers are cautioned that as the debt to book capitalization
ratio has no defined meaning under GAAP, this financial measure may
not be comparable to similar measures provided by other reporting
entities. Further, there can be no assurances that the Company will
continue to use this measure to monitor capital or will not alter
the method of calculation of this measure at some point in the
future.
-------------------------
Mar 31 Dec 31
2009 2008
----------------------------------------------------------------------------
Long-term debt (1) $ 13,132 $ 13,016
Total shareholders' equity $ 18,716 $ 18,374
Debt to book capitalization 41% 41%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of the long-term debt.
10. NET EARNINGS PER COMMON SHARE
Three Months Ended
-------------------------
Mar 31 Mar 31
2009 2008
----------------------------------------------------------------------------
Weighted average common shares outstanding
(thousands) - basic and diluted 541,251 540,218
----------------------------------------------------------------------------
Net earnings - basic and diluted $ 305 $ 727
----------------------------------------------------------------------------
Net earnings per common share - basic and
diluted $ 0.56 $ 1.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. FINANCIAL INSTRUMENTS
The carrying values of the Company's financial instruments by category are
as follows:
----------------------------------------------
Mar 31, 2009
----------------------------------------------------------------------------
Other
Loans and Held for financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized cost
----------------------------------------------------------------------------
Cash and cash equivalents $ - $ 10 $ -
Accounts receivable 1,142 - -
Risk management - 1,714 -
Accounts payable - - (347)
Accrued liabilities - - (1,909)
Other long-term liabilities - - (103)
Long-term debt (1) - - (13,132)
----------------------------------------------------------------------------
$ 1,142 $ 1,724 $ (15,491)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of the long-term debt.
Dec 31, 2008
----------------------------------------------------------------------------
Other
Loans and Held for financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized cost
----------------------------------------------------------------------------
Cash and cash equivalents $ - $ 27 $ -
Accounts receivable 1,059 - -
Risk management - 2,119 -
Accounts payable - - (383)
Accrued liabilities - - (1,802)
Other long-term liabilities - - (105)
Long-term debt (1) - - (13,016)
----------------------------------------------------------------------------
$ 1,059 $ 2,146 $ (15,306)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of the long-term debt.
The carrying value of the Company's financial instruments approximates their
fair value, except for fixed-rate long-term debt as noted below:
Mar 31, 2009 Dec 31, 2008
-----------------------------------------
Carrying Fair Carrying Fair
value value value value
----------------------------------------------------------------------------
Fixed-rate long-term debt (1) $ 9,167 $ 7,990 $ 8,943 $ 7,649
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The carrying values of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $65 million (2008 - $68 million) to reflect the fair value impact of
hedge accounting.
Risk management
The Company uses derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures.
These financial instruments are entered into solely for hedging
purposes and are not used for speculative purposes.
The estimated fair value of derivative financial instruments has
been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values
determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows and discount
rates. In determining these assumptions, the Company has relied
primarily on external, readily-observable market inputs including
quoted commodity prices and volatility, interest rate yield curves,
and foreign exchange rates. The resulting fair value estimates may
not necessarily be indicative of the amounts that could be realized
or settled in a current market transaction and these differences
may be material.
The changes in estimated fair values of derivative financial
instruments included in the risk management asset (liability) were
recognized in the financial statements as follows:
------------------------------------
Three Months Ended Year Ended
Mar 31, 2009 Dec 31, 2008
----------------------------------------------------------------------------
Risk Risk
management management
Asset (liability) mark-to-market mark-to-market
----------------------------------------------------------------------------
Balance - beginning of period $ 2,119 $ (1,474)
Net cost of outstanding put options 230 297
Net change in fair value of outstanding
derivative financial instruments
attributable to:
- Risk management activities (463) 3,090
- Interest expense (2) 60
- Foreign exchange 68 449
- Other comprehensive income (8) 18
- Settlement of interest rate swaps and
other 3 (20)
----------------------------------------------------------------------------
1,947 2,420
Add: put premium financing obligations (1) (233) (301)
----------------------------------------------------------------------------
Balance - end of period 1,714 2,119
Less: current portion 1,383 1,851
----------------------------------------------------------------------------
$ 331 $ 268
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has negotiated payment of put option premiums with various
counterparties at the time of actual settlement of the respective
options. These obligations have been reflected in the net risk
management asset (liability).
Net (gains) losses from risk management activities were as follows:
Three Months Ended
-------------------------
Mar 31 Mar 31
2009 2008
----------------------------------------------------------------------------
Net realized risk management (gain) loss $ (641) $ 416
Net unrealized risk management loss 463 108
----------------------------------------------------------------------------
$ (178) $ 524
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial risk factors
a) Market risk
Market risk is the risk that the fair value or future cash flows
of a financial instrument will fluctuate because of changes in
market prices. The Company's market risk is comprised of commodity
price risk, interest rate risk, and foreign currency exchange
risk.
Commodity price risk
The Company uses commodity 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, 2009, the Company had the following net derivative financial
instruments outstanding to manage its commodity price
exposures:
Weighted average
Remaining term Volume price Index
----------------------------------------------------------------------------
Crude oil
Crude oil price Apr 2009 -
collars Dec 2009 25,000 bbl/d US$70.00 - US$111.56 WTI
Apr 2009 -
Jun 2009 4,000 bbl/d US$70.00 - US$90.00 WTI
Apr 2009 -
Crude oil puts Dec 2009 92,000 bbl/d US$100.00 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At March 31, 2009, the net cost of outstanding put options and their
respective periods of settlement was as follows:
Q2 2009 Q3 2009 Q4 2009
----------------------------------------------------------------------------
Cost ($ millions) US$60 US$61 US$61
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Remaining term Volume Weighted average Index
price
----------------------------------------------------------------------------
Natural gas
Natural gas
price collars Jan 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, 2009.
In addition to the derivative financial instruments noted above,
the Company entered into natural gas physical sales contracts for
400,000 GJ/d at an average fixed price of C$5.29 per GJ at AECO for
the period April to December 2009.
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed
rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company enters into interest rate
swap contracts to manage its fixed to floating interest rate mix on
long-term debt. The interest rate swap contracts require the
periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At March 31,
2009, the Company had the following interest rate swap contracts
outstanding:
Amount
Remaining term ($ millions) Fixed rate Floating rate
----------------------------------------------------------------------------
Interest
rate
Swaps -
fixed to
floating Apr 2009 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
Swaps -
floating to
fixed Apr 2009 - Feb 2011 C$300 1.0680% 3 month CDOR (2)
Apr 2009 - Feb 2012 C$200 1.4475% 3 month CDOR (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) London Interbank Offered Rate
(2) Canadian Dealer Offered Rate
All interest rate related derivative financial instruments
designated as hedges at March 31, 2009 were classified as fair
value hedges.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated long-term
debt and working capital. The Company is also exposed to foreign
currency exchange rate risk on transactions conducted in other
currencies in its subsidiaries and in the carrying value of its
self-sustaining foreign subsidiaries. The Company periodically
enters into cross currency swap contracts and foreign currency
forward contracts to manage known currency exposure on US dollar
denominated long-term debt and working capital. The cross currency
swap contracts require the periodic exchange of payments with the
exchange at maturity of notional principal amounts on which the
payments are based. At March 31, 2009, the Company had the
following cross currency swap contracts outstanding:
Exchange Interest Interest
Amount rate rate rate
Remaining term ($ millions) (US$/C$) (US$) (C$)
----------------------------------------------------------------------------
Cross currency
Swaps Apr 2009 - Aug 2016 US$250 1.116 6.00% 5.40%
Apr 2009 - May 2017 US$1,100 1.170 5.70% 5.10%
Apr 2009 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency swap derivative financial instruments
designated as hedges at March 31, 2009 were classified as cash flow
hedges.
In addition to the cross currency swap contracts noted above,
the Company periodically utilizes foreign currency forward
contracts to manage certain foreign currency cash management needs.
At March 31, 2009, the Company had US$1,244 million of these
contracts outstanding, with terms of approximately 30 days or
less.
Financial instrument sensitivities
As required by Canadian GAAP, the Company must provide certain
quantitative sensitivities related to its financial instruments,
which are prepared on a different basis than those sensitivities
currently disclosed in the Company's other continuous disclosure
documents. 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, 2009 resulting from changes in the
specified variable, with all other variables held constant. These
sensitivities are limited to the impact of changes in a specified
variable applied to financial instruments only and do not represent
the impact of a change in the variable on the operating results of
the Company taken as a whole. Further, these sensitivities are
theoretical, as changes in one variable may contribute to changes
in another variable, which may magnify or counteract the
sensitivities. In addition, changes in fair value generally can not
be extrapolated because the relationship of a change in an
assumption to the change in fair value may not be linear.
----------------------------------------
Impact on
other
Impact on net comprehensive
earnings income
----------------------------------------------------------------------------
Commodity price risk
Increase WTI US$1.00/bbl $ (26) $ -
Decrease WTI US$1.00/bbl $ 26 $ -
Increase AECO C$0.10/mcf $ (4) $ -
Decrease AECO C$0.10/mcf $ 4 $ -
Interest rate risk
Increase interest rate 1% $ (26) $ (28)
Decrease interest rate 1% $ 26 $ 34
Foreign currency exchange rate risk
Increase exchange rate by US$0.01 $ (35) $ -
Decrease exchange rate by US$0.01 $ 35 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, 2009, substantially all of the Company's accounts
receivable were due within normal trade terms.
The Company is also exposed to possible losses in the event of
nonperformance 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, 2009, the Company had net risk management assets of
$1,714 million with specific counterparties related to derivative
financial instruments (December 31, 2008 - $2,119 million). The
Company believes that its counterparties currently have the
financial capacity to settle outstanding obligations in the normal
course of business.
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter
difficulty in meeting obligations associated with financial
liabilities.
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating
activities, available credit facilities, and access to debt capital
markets, to meet obligations as they become due. Due to
fluctuations in the timing of the receipt and/or disbursement of
operating cash flows, the Company believes it has adequate bank
credit facilities to provide liquidity.
The maturity dates for financial liabilities are as follows:
1 to less 2 to less
Less than than than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 347 $ - $ - $ -
Accrued liabilities $ 1,909 $ - $ - $ -
Other long-term liabilities $ 86 $ 17 $ - $ -
Long-term debt (1) $ 1,968 $ 400 $ 1,850 $ 6,890
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $2,035 million of revolving
bank credit facilities due to the extendable nature of the facilities.
12. COMMITMENTS
As at March 31, 2009, the Company had committed to certain payments as
follows:
2009 2010 2011 2012 2013 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 163 $ 193 $ 160 $ 135 $ 125 $ 1,177
Offshore equipment
operating leases $ 151 $ 149 $ 148 $ 119 $ 121 $ 409
Offshore drilling $ 178 $ 64 $ - $ - $ - $ -
Asset retirement
obligations (1) $ 13 $ 11 $ 16 $ 17 $ 26 $ 5,763
Office leases $ 19 $ 29 $ 23 $ 2 $ 2 $ 2
Other $ 259 $ 186 $ 17 $ 11 $ 8 $ 21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 2009 - 2013 represent the minimum required expenditures to meet
these obligations. Actual expenditures in any particular year may exceed
these minimum amounts.
13. SEGMENTED INFORMATION
North America North Sea Offshore West Africa
(millions of
Canadian Three Months Ended Three Months Ended Three Months Ended
dollars, Mar 31 Mar 31 Mar 31
unaudited) -------------------------------------------------------------
2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
Segmented
revenues 1,847 3,215 175 508 201 237
Less: royalties (193) (405) - (1) (14) (43)
----------------------------------------------------------------------------
Segmented
revenue, net of
royalties 1,654 2,810 175 507 187 194
----------------------------------------------------------------------------
Segmented
expenses
Production 476 451 70 112 43 21
Transportation
and blending 326 493 3 3 - -
Depletion,
depreciation
and
amortization 547 566 64 86 50 34
Asset
retirement
obligation
accretion 9 11 7 6 1 -
Realized risk
management
activities (484) 417 (157) (1) - -
----------------------------------------------------------------------------
Total segmented
expenses 874 1,938 (13) 206 94 55
----------------------------------------------------------------------------
Segmented
earnings (loss)
before
the following 780 872 188 301 93 139
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Stock-based
compensation
expense
Interest, net
Unrealized risk
management
activities
Foreign
exchange loss
----------------------------------------------------------------------------
Total
non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Taxes other
than income tax
Current income
tax expense
Future income
tax (recovery)
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment
elimination
Midstream and other Total
(millions of
Canadian Three Months Ended Three Months Ended Three Months Ended
dollars, Mar 31 Mar 31 Mar 31
unaudited) -------------------------------------------------------------
2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
Segmented revenues 19 20 (56) (13) 2,186 3,967
Less: royalties - - 8 - (199) (449)
----------------------------------------------------------------------------
Segmented revenue,
net of royalties 19 20 (48) (13) 1,987 3,518
----------------------------------------------------------------------------
Segmented expenses
Production 5 5 (12) (2) 582 587
Transportation
and blending - - (12) (11) 317 485
Depletion,
depreciation and
amortization 2 2 (17) - 646 688
Asset retirement
obligation
accretion - - 2 - 19 17
Realized risk
management
activities - - - - (641) 416
----------------------------------------------------------------------------
Total segmented
expenses 7 7 (39) (13) 923 2,193
----------------------------------------------------------------------------
Segmented earnings
(loss) before
the following 12 13 (9) - 1,064 1,325
----------------------------------------------------------------------------
Non-segmented
expenses
Administration 47 43
Stock-based compensation
expense 4 -
Interest, net 57 49
Unrealized risk
management activities 463 108
Foreign exchange loss 123 114
----------------------------------------------------------------------------
Total non-segmented
expenses 694 314
----------------------------------------------------------------------------
Earnings before taxes 370 1,011
Taxes other than
income tax 4 49
Current income
tax expense 117 155
Future income tax
(recovery) expense (56) 80
----------------------------------------------------------------------------
Net earnings 305 727
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net additions to property, plant and equipment
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended
Mar 31, 2008
--------------------------------------------
Non Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 663 $ 9 $ 672
North Sea 45 - 45
Offshore West Africa 94 (1) 93
Oil Sands Mining
and Upgrading (2) 941 - 941
Midstream 1 - 1
Head office 3 - 3
----------------------------------------------------------------------------
$ 1,747 $ 8 $ 1,755
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Asset retirement obligations, future income tax adjustments
related to
differences between carrying value and tax value, and other fair
value
adjustments.
(2) Net expenditures for the Oil Sands Mining and Upgrading
assets also
include capitalized interest, stock-based compensation, and
the impact of intersegment eliminations.
Property, plant and
equipment Total assets
-----------------------------------------
Mar 31 Dec 31 Mar 31 Dec 31
2009 2008 2009 2008
----------------------------------------------------------------------------
Segmented assets
North America $ 22,200 $ 22,151 $ 24,681 $ 24,875
North Sea 2,066 2,048 2,603 2,638
Offshore West Africa 2,127 1,894 2,253 2,013
Other 26 26 70 64
Oil Sands Mining and Upgrading 13,220 12,573 13,357 12,677
Midstream 209 206 312 315
Head office 68 68 68 68
----------------------------------------------------------------------------
$ 39,916 $ 38,966 $ 43,344 $ 42,650
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capitalized interest
The Company capitalizes construction period interest to Oil
Sands Mining and Upgrading based on Horizon 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, 2009,
pre-tax interest of $86 million was capitalized to Oil Sands Mining
and Upgrading (March 31, 2008 - $111 million).
SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with
the Company's continuous offering of medium-term notes pursuant to
the short form prospectus dated September 2007. These ratios are
based on the Company's interim consolidated financial statements
that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended March 31, 2009:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 11.2x
Cash flow from operations (2) 12.4x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 8, 2009. The North American
conference call number is 1-866-226-1793 and the outside North
American conference call number is 001-416-641-6128. Please call in
about 10 minutes before the starting time in order to be patched
into the call. The conference call will also be broadcast live on
the internet and may be accessed through the Canadian Natural
website at www.cnrl.com.
A taped rebroadcast will be available until 6:00 p.m. Mountain
Time, Friday, May 15, 2009. 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 8634752.
WEBCAST
This call is being webcast and can be accessed on Canadian
Natural's website at www.cnrl.com/investor_info/calendar.html.
2009 SECOND QUARTER RESULTS
2009 second quarter results are scheduled for release prior to
market opening on Thursday, August 6, 2009.
Contacts: Canadian Natural Resources Limited Allan P. Markin
Chairman (403) 514-7777 (403) 514-7888 (FAX) Canadian Natural
Resources Limited John G. Langille Vice-Chairman (403) 514-7777
(403) 514-7888 (FAX) Canadian Natural Resources Limited Steve W.
Laut President and Chief Operating Officer (403) 514-7777 (403)
514-7888 (FAX) Canadian Natural Resources Limited Douglas A. Proll
Chief Financial Officer and Senior Vice-President, Finance (403)
514-7777 (403) 514-7888 (FAX) Canadian Natural Resources Limited
Corey B. Bieber Vice-President, Finance & Investor Relations
(403) 514-7777 (403) 514-7888 (FAX) Canadian Natural Resources
Limited 2500, 855 - 2nd Street S.W. Calgary, Alberta T2P 4J8 Email:
ir@cnrl.com Website: www.cnrl.com
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