Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on second quarter results, Canadian Natural's
Chairman, Allan Markin stated, "We have reached the mid-point of
2010 and continue to deliver solid results. The Company had
excellent operating performance in all areas with production
volumes either meeting or exceeding guidance. We continue to focus
on efficient operations to provide value, which is evident across
our entire asset base."
John Langille, Vice-Chairman of Canadian Natural continued,
"Canadian Natural continues to deliver shareholder value with
excellent second quarter cash flow and earnings. We remain
committed to ensuring a strong financial position and will continue
to allocate capital to the highest return projects for the short-,
mid- and long-term. All operating divisions continue to execute the
plans for 2010 and provide significant free cash flow to the
Company."
Steve Laut, President for Canadian Natural stated, "The second
quarter results demonstrate the strength of our team. At Horizon,
we successfully completed planned maintenance in May and gained
another quarter of good operating experience. Strong thermal
execution resulted in significant production volume increases and
the ability of our natural gas team to optimize operations has led
to positive results in production and cost control."
Three Months Ended Six Months Ended
($ millions, Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
except as noted) 2010 2010(1) 2009(1) 2010 2009(1)
----------------------------------------------------------------------------
Net earnings $ 667 $ 866 $ 162 $ 1,533 $ 467
Per common share,
basic and diluted $ 0.61 $ 0.80 $ 0.15 $ 1.41 $ 0.43
Adjusted net earnings
from operations (2) $ 688 $ 658 $ 637 $ 1,346 $ 1,364
Per common share,
basic and diluted $ 0.63 $ 0.61 $ 0.59 $ 1.24 $ 1.26
Cash flow from
operations (3) $ 1,630 $ 1,505 $ 1,365 $ 3,135 $ 2,881
Per common share,
basic and diluted $ 1.49 $ 1.39 $ 1.26 $ 2.88 $ 2.66
Capital expenditures,
net of dispositions $ 1,573 $ 1,072 $ 473 $ 2,645 $ 1,729
Daily production,
before royalties
Natural gas (mmcf/d) 1,237 1,226 1,352 1,231 1,360
Crude oil and NGLs
(bbl/d) 443,045 406,266 365,672 424,757 347,943
Equivalent production
(boe/d) 649,195 610,556 590,984 629,982 574,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Per share amounts have been restated to reflect a two-for-one common
share split in May 2010.
(2) Adjusted net earnings from operations is a non-GAAP measure that the
Company utilizes to evaluate its performance. The derivation of this
measure is discussed in Management's Discussion and Analysis ("MD&A").
(3) 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
- Strong overall performance in the quarter is reflected by
increased overall Company production, lower per unit operating
costs, lower development capital costs, and significant free cash
flow.
- Record overall Company production for Q2/10 of 649,195 boe/d,
an increase of 10% from Q2/09 and 6% from Q1/10.
- Total crude oil and NGLs production for Q2/10 was 443,045
bbl/d, an increase of 21% and 9% from Q2/09 and Q1/10 respectively.
Volumes in Q2/10 exceeded the Company's guidance of 394,000 bbl/d
to 426,000 bbl/d due to excellent results at the Company's crude
oil properties, and reflect increased volumes due to the cyclic
nature of Primrose production, increased production from mining at
Horizon Oil Sands ("Horizon"), and a strong primary heavy crude oil
drilling program.
- Total natural gas production for Q2/10 averaged 1,237 mmcf/d,
slightly above the Company's guidance of 1,207 mmcf/d to 1,232
mmcf/d due to continued operational optimization and good drilling
results. Q2/10 natural gas production decreased 9% from Q2/09 and
increased 1% from the previous quarter. The increase from Q1/10 was
primarily due to the inclusion of acquisition volumes as previously
announced in the Company's corporate guidance.
- Quarterly operating expenses on a per unit basis across all
major product lines improved reflecting a concentration on
operating efficiencies, optimized production volumes and a lower
cost of natural gas used for fuel in North America. As a result,
annual midpoint operating cost guidance was reduced for North
America natural gas, and crude oil and NGLs in North America, North
Sea and Offshore West Africa while Oil Sands Mining has remained
unchanged.
- Quarterly cash flow from operations for Q2/10 exceeded $1.6
billion, an increase of 19% and 8% from Q2/09 and Q1/10
respectively. The increase from Q1/10 reflects the impact of higher
crude oil and NGL sales volumes, lower royalty and production
expense and higher realized risk management gains partially offset
by the impact of lower realized crude oil and natural gas
pricing.
- Quarterly net earnings for Q2/10 of $667 million, an increase
of 312% from Q2/09 and a decrease of 23% from Q1/10, included the
effects of unrealized risk management activities, fluctuations in
foreign exchange rates and stock-based compensation. Excluding
these items, quarterly adjusted net earnings from operations for
Q2/10 were $688 million.
- Record thermal heavy crude oil production of approximately
96,000 bbl/d was achieved in Q2/10. Thermal production levels
increased 53% from Q2/09 and 27% from Q1/10.
- In May 2010 planned plant maintenance at Horizon was
successfully completed. As a result, Horizon had exceptional
reliability and production volumes in June 2010 and Q2/10
production of 99,950 bbl/d. On July 30, 2010, while carrying out
previously announced maintenance to repair unexpected localized
pipe wall thinning in the amine unit, the Company determined that
the pipe wall thinning was more extensive than originally
estimated. Although this issue is limited to the amine unit only,
and is not technically difficult or a major expenditure to repair,
it has necessitated a plant wide shutdown that is targeted to be
complete by mid August. The Company's annual production guidance
for 2010 has been revised to 90,000 to 100,000 barrels per day of
SCO.
- In the second quarter, Canadian Natural drilled 38 primary
heavy crude oil wells as part of the planned record heavy crude oil
drilling program for 2010.
- At Platform B of the Olowi Project 3.7 net wells are on
production, and performance is in line with the Company's
expectations. The Company is targeting to commission and have
onstream a further 1.9 net wells in the third quarter and begin
drilling operations on Platform A.
- During Q2/10, the Espoir facilities upgrade on the Floating
Production, Storage and Offtake vessel ("FPSO") was completed.
- Canadian Natural is continuing its proposed third phase of the
thermal growth plan with a development plan for the Kirby In Situ
Oil Sands Project. The Company anticipates regulatory approval in
Q3/10. Final project scope and corporate sanction is targeted for
late 2010.
- Closed previously announced purchases of crude oil and natural
gas properties in its core regions in Western Canada. The Company's
previously issued guidance reflected production volumes associated
with the acquisitions.
- The Company's shareholders passed a Special Resolution
subdividing the common shares of the Company on a two-for-one basis
at the Company's Annual and Special Meeting held on May 6, 2010
with such subdivision taking effect on May 21, 2010. All common
share, per common share, and stock option amounts have been
restated to reflect the share split.
- Declared a quarterly cash dividend on common shares of $0.075
per common share payable October 1, 2010.
OPERATIONS REVIEW
Activity by core region
Net undeveloped land Drilling activity
as at six months ended
Jun 30, 2010 Jun 30, 2010
(thousands of net acres) (net wells)(1)
----------------------------------------------------------------------------
North America
Northeast British Columbia 2,093 23.0
Northwest Alberta 1,518 27.0
Northern Plains 5,776 339.1
Southern Plains 798 8.6
Southeast Saskatchewan 144 11.5
Thermal In Situ Oil Sands 486 179.0
----------------------------------------------------------------------------
10,815 588.2
Oil Sands Mining and Upgrading 115 119.0
North Sea 150 -
Offshore West Africa 4,193 4.7
----------------------------------------------------------------------------
15,273 711.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Drilling activity includes stratigraphic test and service wells.
Drilling activity (number of wells)
Six Months Ended Jun 30
2010 2009
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 356 335 192 187
Natural gas 63 55 87 64
Dry 17 16 20 19
----------------------------------------------------------------------------
Subtotal 436 406 299 270
Stratigraphic test / service wells 307 306 243 243
----------------------------------------------------------------------------
Total 743 712 542 513
----------------------------------------------------------------------------
Success rate (excluding stratigraphic
test / service wells) 96% 93%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America
North America natural gas
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Natural gas production (mmcf/d) 1,219 1,193 1,322 1,206 1,334
----------------------------------------------------------------------------
Net wells targeting natural gas 11 49 - 60 72
Net successful wells drilled 10 45 - 55 64
----------------------------------------------------------------------------
Success rate 91% 92% - 92% 89%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Production volumes were higher than anticipated despite the
Company's strategic decision to proactively limit the North America
natural gas drilling program for 2010. Excellent production volumes
reflect the Company's continued focus on optimizing performance.
Volumes decreased 8% from Q2/09. Production increased 2% from Q1/10
primarily due to inclusion of acquisition volumes as previously
announced.
- Operating costs for natural gas, compared to Q2/09, were $0.01
per mcf lower despite a production volume decrease of 8% from
Q2/09. This demonstrates the Company's focus on operating
efficiencies. Annual midpoint operating cost guidance has been
lowered accordingly.
- During Q2/10, the Company closed $949 million of property
acquisitions weighted approximately 75% to natural gas. These
acquisitions complement existing Canadian Natural operations in
core areas and have significant operated infrastructure that create
operational synergies benefiting both existing Canadian Natural
assets and the acquired assets. The assets have approximately
773,000 net acres of undeveloped land providing significant future
development opportunities.
- Canadian Natural targeted 11 net natural gas wells in Q2/10
with a prudent program across the Company's core regions. In
Northeast British Columbia, 7 net natural gas wells were drilled,
while in Northwest Alberta, 3 net natural gas wells were drilled.
In the Southern Plains, 1 net natural gas well was drilled.
- Planned drilling activity for Q3/10 includes 25 net natural
gas wells.
North America crude oil and NGLs
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs production
(bbl/d) 275,584 252,450 232,139 264,081 242,926
----------------------------------------------------------------------------
Net wells targeting crude oil 91 250 97 341 194
Net successful wells drilled 90 240 93 330 183
----------------------------------------------------------------------------
Success rate 99% 96% 96% 97% 94%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Q2/10 North America crude oil and NGLs production increased
19% from Q2/09 and increased 9% from Q1/10 levels. The increase in
production volume from Q1/10 was due to cyclic thermal crude oil at
Primrose and a strong primary heavy crude oil drilling program.
- Operating costs for crude oil and NGLs were 23% lower compared
to Q2/09 reflecting operating efficiencies, lower natural gas costs
and higher production volumes. Annual midpoint operating cost
guidance has been lowered accordingly.
- Surveillance steaming activities continue at Primrose East.
Performance has been better than expected and the Company now
targets average production to exceed 20,000 bbl/d in 2010. Canadian
Natural plans to return to normal steaming activities by late 2010
or early 2011.
- Canadian Natural is continuing its proposed third phase of the
thermal growth plan with the Kirby In Situ Oil Sands Project. The
Company anticipates regulatory approval in Q3/10. Final project
scope and corporate sanction is targeted for late 2010.
- Enhanced crude oil production continues with conversion to
polymer flooding at Pelican Lake. Production in this area averaged
approximately 37,000 bbl/d for Q2/10. Enhanced oil recovery ("EOR")
is targeted to accelerate production levels during the second half
of 2010.
- Primary heavy crude oil production volumes increased 10% in
Q2/10 compared to Q2/09 and increased 3% from Q1/10, reflecting the
Company's record drilling program planned for 2010.
- During Q2/10, drilling activity targeted 91 net wells
including 38 wells targeting heavy crude oil, 44 wells targeting
Pelican Lake crude oil, 6 wells targeting thermal crude oil, and 3
wells targeting light crude oil.
- Excluding stratigraphic test and service wells, planned
drilling activity for Q3/10 includes 330 net crude oil wells,
compared to drilling activity for Q3/09 of 270 net crude oil
wells.
International
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil production (bbl/d)
North Sea 37,669 36,879 40,362 37,276 41,360
Offshore West Africa 29,842 29,942 33,572 29,892 32,010
----------------------------------------------------------------------------
Natural gas production (mmcf/d)
North Sea 9 15 10 12 10
Offshore West Africa 9 18 20 13 16
----------------------------------------------------------------------------
Net wells targeting crude oil 1.9 2.8 1.0 4.7 4.2
Net successful wells drilled 1.9 2.8 1.0 4.7 4.2
----------------------------------------------------------------------------
Success rate 100% 100% 100% 100% 100%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
- Production exceeded guidance and reflected strong well
performance and uptimes in the Ninian Field during the quarter.
North Sea crude oil production for Q2/10 was down 7% from Q2/09 and
up 2% compared to Q1/10. Third quarter production guidance reflects
proactive planned maintenance.
- The Company's annual guidance for operating costs has been
lowered to reflect operational efficiencies, proactive maintenance
and certain one time items recorded in the second quarter.
- The Company recommenced platform drilling operations at the
beginning of the second quarter and continues to focus on maturing
and high grading its inventory of future drilling locations. The
Company maintains focus on maximizing efficiencies and operational
performance.
Offshore West Africa
- Offshore West Africa's crude oil production decreased 11% from
Q2/09 and was comparable to Q1/10. Production, which was impacted
by a planned shutdown at Espoir for the installation of facilities
upgrades, was at the high end of the Company's previously issued
guidance.
- Crude oil production expense increased from Q1/10 due to
increased liftings from the higher cost Olowi Field and the plant
shutdown at Espoir for facilities upgrades. Annual midpoint
operating cost guidance has been lowered to $14.00 to $16.00 per
barrel.
- At Platform B of the Olowi Project 3.7 net wells are on
production, and performance is in line with the Company's
expectations. The Company is targeting to commission and have
onstream a further 1.9 net wells in the third quarter and begin
drilling operations on Platform A.
Oil Sands Mining and Upgrading
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Synthetic crude oil production
(bbl/d) 99,950 86,995 59,599 93,508 31,647
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Horizon SCO production was 99,950 bbl/d in Q2/10, an increase
of 68% from Q2/09 and an increase of 15% from Q1/10. The planned
maintenance outage in May 2010 proved successful as June 2010
volumes increased to approximately 117,600 bbl/d. The Company will
continue strategic maintenance as required to target stable
production levels with annual production guidance for 2010 targeted
for 90,000 to 100,000 barrels per day of SCO at Horizon. Monthly
average production for Horizon is provided on the Company's
website.
- Operational costs in Q2/10 averaged $32.27 per barrel of SCO
(including approximately $3.18 per barrel of natural gas input
costs), primarily due to stabilized production volumes at levels
approaching plant capacity, and a focus on proactive maintenance
and operational optimization. The Company continues to target
operating costs between $31.00 to $37.00 per barrel of SCO for
2010.
- As provided in the Company's issued guidance, 2010 capital
expenditures at Horizon were decreased by $152 million due to
limited Phase 2/3 spending which remains focused on the
construction of the third Ore Preparation Plant, completion of the
Mine Maintenance Shop and additional product tankage.
- On July 30, 2010, while carrying out previously announced
maintenance to repair unexpected localized pipe wall thinning in
the amine unit, the Company determined that the pipe wall thinning
was more extensive than originally estimated. Although this issue
is limited to the amine unit only, and is not technically difficult
or a major expenditure to repair, it has necessitated a plant wide
shutdown that is targeted to be complete by mid August. As a result
planned maintenance originally targeted for late August and
September has been moved forward including furnace pigging cycles
and screen changes in the Ore Preparation Plant.
- Engineering and procurement for Tranche 2 of the Phase 2/3
expansion is progressing with a focus on increasing reliability and
uptime. Tranches 3 and 4 of Phase 2/3 continue to be re-profiled.
The Company continues to work on completing its lessons learned
from the construction of Phase 1 and implementing these into the
development of future expansions.
MARKETING
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs pricing
WTI(1) benchmark price
(US$/bbl) $ 77.99 $ 78.79 $ 59.61 $ 78.39 $ 51.46
Western Canadian Select blend
differential from WTI (%) 18% 12% 13% 15% 16%
SCO price (US$/bbl) $ 76.44 $ 79.37 $ 58.42 $ 77.90 $ 51.74
Average realized pricing
before risk management(2)
(C$/bbl) $ 63.62 $ 68.76 $ 59.56 $ 66.10 $ 50.12
Natural gas pricing
AECO benchmark price (C$/GJ) $ 3.66 $ 5.07 $ 3.46 $ 4.36 $ 4.40
Average realized pricing
before risk management
(C$/mcf) $ 3.86 $ 5.19 $ 4.11 $ 4.52 $ 4.78
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
(2) Excludes SCO.
- In Q2/10, the Western Canadian Select ("WCS") heavy crude oil
differential as a percent of WTI averaged 18%, compared to 12% in
Q1/10. Heavy crude oil differentials widened in Q2/10 reflecting
widening crude oil crack spreads.
- During Q2/10, the Company contributed approximately 165,000
bbl/d of its heavy crude oil streams to the WCS blend as market
conditions resulted in optimal pricing for heavy crude oil.
- In Q1/10, the Company announced, together with North West
Upgrading Inc., the submission of a joint proposal to the Alberta
Government to construct and operate a bitumen refinery near
Redwater, Alberta under the Alberta Royalty Framework's Bitumen
Royalty In Kind ("BRIK") program. In Q2/10, the Government of
Alberta announced that the proposal had been selected for exclusive
negotiations following a comprehensive review. Further project
development is dependent upon successful completion of these
negotiations on commercially acceptable terms and final project
sanction by the respective parties.
FINANCIAL REVIEW
- The financial position of the Company remains robust and the
Company continually examines its liquidity position and targets a
low risk approach to finance. The commodity hedging program, its
existing credit facilities and capital expenditure programs all
support a flexible financial position:
-- A large and diverse asset base spread over various commodity
types - produced in excess of 649,000 boe/d in Q2/10, with 95% of
production located in G8 countries.
-- Financial stability and liquidity - cash flow from operations
of $1.6 billion with available unused bank lines of $2.5 billion at
June 30, 2010.
-- Flexibility in asset base and positive free cash flow
produced from North America, Horizon, the North Sea and Offshore
West Africa allows for a disciplined capital allocation
program.
- A strong balance sheet with debt to book capitalization of 31%
and debt to EBITDA of 1.3 times.
- Declared a quarterly cash dividend on common shares of C$0.075
per common share, payable October 1, 2010.
OUTLOOK
The Company forecasts 2010 production levels before royalties to
average between 1,229 and 1,256 mmcf/d of natural gas and between
421,000 and 449,000 bbl/d of crude oil and NGLs. Q3/10 production
guidance before royalties is forecast to average between 1,247 and
1,271 mmcf/d of natural gas and between 414,000 and 445,000 bbl/d
of crude oil and NGLs. Detailed guidance on production levels,
capital allocation and operating costs can be found on the
Company's website at www.cnrl.com.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources
Limited (the "Company") in this document or documents incorporated
herein by reference constitute forward-looking statements or
information (collectively referred to herein as "forward-looking
statements") within the meaning of applicable securities
legislation. Forward-looking statements can be identified by the
words "believe", "anticipate", "expect", "plan", "estimate",
"target", "continue", "could", "intend", "may", "potential",
"predict", "should", "will", "objective", "project", "forecast",
"goal", "guidance", "outlook", "effort", "seeks", "schedule" or
expressions of a similar nature suggesting future outcome or
statements regarding an outlook. Disclosure related to expected
future commodity pricing, production volumes, royalties, operating
costs, capital expenditures and other guidance provided throughout
this Management's Discussion and Analysis ("MD&A"), constitute
forward-looking statements. Disclosure of plans relating to and
expected results of existing and future developments, including but
not limited to Horizon Oil Sands, Primrose East, Pelican Lake,
Olowi Field (Offshore Gabon), and the Kirby Thermal Oil Sands
Project also constitute forward-looking statements. This
forward-looking information is based on annual budgets and
multi-year forecasts, and is reviewed and revised throughout the
year if necessary in the context of targeted financial ratios,
project returns, product pricing expectations and balance in
project risk and time horizons. These statements are not guarantees
of future performance and are subject to certain risks. The reader
should not place undue reliance on these forward-looking statements
as there can be no assurances that the plans, initiatives or
expectations upon which they are based will occur.
In addition, statements relating to "reserves" are deemed to be
forward-looking statements as they involve the implied assessment
based on certain estimates and assumptions that the reserves
described can be profitably produced in the future. There are
numerous uncertainties inherent in estimating quantities of proved
crude oil and natural gas reserves and in projecting future rates
of production and the timing of development expenditures. The total
amount or timing of actual future production may vary significantly
from reserve and production estimates.
The forward-looking statements are based on current
expectations, estimates and projections about the Company and the
industry in which the Company operates, which speak only as of the
date such statements were made or as of the date of the report or
document in which they are contained, and are subject to known and
unknown risks and uncertainties that could cause the actual
results, performance or achievements of the Company to be
materially different from any future results, performance or
achievements expressed or implied by such forward-looking
statements. Such risks and uncertainties include, among others:
general economic and business conditions which will, among other
things, impact demand for and market prices of the Company's
products; volatility of and assumptions regarding crude oil and
natural gas prices; fluctuations in currency and interest rates;
assumptions on which the Company's current guidance is based;
economic conditions in the countries and regions in which the
Company conducts business; political uncertainty, including actions
of or against terrorists, insurgent groups or other conflict
including conflict between states; industry capacity; ability of
the Company to implement its business strategy, including
exploration and development activities; impact of competition; the
Company's defense of lawsuits; availability and cost of seismic,
drilling and other equipment; ability of the Company and its
subsidiaries to complete capital programs; the Company's and its
subsidiaries' ability to secure adequate transportation for its
products; unexpected difficulties in mining, extracting or
upgrading the Company's bitumen products; potential delays or
changes in plans with respect to exploration or development
projects or capital expenditures; ability of the Company to attract
the necessary labour required to build its thermal and oil sands
mining projects; operating hazards and other difficulties inherent
in the exploration for and production and sale of crude oil and
natural gas; availability and cost of financing; the Company's and
its subsidiaries' success of exploration and development activities
and their ability to replace and expand crude oil and natural gas
reserves; timing and success of integrating the business and
operations of acquired companies; production levels; imprecision of
reserve estimates and estimates of recoverable quantities of crude
oil, bitumen, natural gas and natural gas liquids ("NGLs") not
currently classified as proved; actions by governmental
authorities; government regulations and the expenditures required
to comply with them (especially safety and environmental laws and
regulations and the impact of climate change initiatives on capital
and operating costs); asset retirement obligations; the adequacy of
the Company's provision for taxes; and other circumstances
affecting revenues and expenses.
The Company's operations have been, and in the future may be,
affected by political developments and by federal, provincial and
local laws and regulations such as restrictions on production,
changes in taxes, royalties and other amounts payable to
governments or governmental agencies, price or gathering rate
controls and environmental protection regulations. Should one or
more of these risks or uncertainties materialize, or should any of
the Company's assumptions prove incorrect, actual results may vary
in material respects from those projected in the forward-looking
statements. The impact of any one factor on a particular
forward-looking statement is not determinable with certainty as
such factors are dependent upon other factors, and the Company's
course of action would depend upon its assessment of the future
considering all information then available.
Readers are cautioned that the foregoing list of factors is not
exhaustive. Unpredictable or unknown factors not discussed in this
report could also have material adverse effects on forward-looking
statements. Although the Company believes that the expectations
conveyed by the forward-looking statements are reasonable based on
information available to it on the date such forward-looking
statements are made, no assurances can be given as to future
results, levels of activity and achievements. All subsequent
forward-looking statements, whether written or oral, attributable
to the Company or persons acting on its behalf are expressly
qualified in their entirety by these cautionary statements. Except
as required by law, the Company assumes no obligation to update
forward-looking statements should circumstances or Management's
estimates or opinions change.
Management's Discussion and Analysis
Management's Discussion and Analysis of the financial condition
and results of operations of the Company should be read in
conjunction with the unaudited interim consolidated financial
statements for the six months ended June 30, 2010 and the MD&A
and the audited consolidated financial statements for the year
ended December 31, 2009.
All dollar amounts are referenced in millions of Canadian
dollars, except where noted otherwise. The financial statements
have been prepared in accordance with generally accepted accounting
principles in Canada ("GAAP"). This MD&A includes references to
financial measures commonly used in the crude oil and natural gas
industry, such as adjusted net earnings from operations, cash flow
from operations, and cash production costs. These financial
measures are not defined by GAAP and therefore are referred to as
non-GAAP measures. The non-GAAP measures used by the Company may
not be comparable to similar measures presented by other companies.
The Company uses these non-GAAP measures to evaluate its
performance. The non-GAAP measures should not be considered an
alternative to or more meaningful than net earnings, as determined
in accordance with GAAP, as an indication of the Company's
performance. The non-GAAP measures adjusted net earnings from
operations and cash flow from operations are reconciled to net
earnings, as determined in accordance with GAAP, in the "Financial
Highlights" section of this MD&A. The derivation of cash
production costs is included in the "Operating Highlights - Oil
Sands Mining and Upgrading" section of this MD&A. The Company
also presents certain non-GAAP financial ratios and their
derivation in the "Liquidity and Capital Resources" section of this
MD&A.
The calculation of barrels of oil equivalent ("boe") is based on
a conversion ratio of six thousand cubic feet ("mcf") of natural
gas to one barrel ("bbl") of crude oil to estimate relative energy
content. This conversion may be misleading, particularly when used
in isolation, since the 6 mcf:1 bbl ratio is based on an energy
equivalency at the burner tip and does not represent the value
equivalency at the wellhead.
Production volumes and per barrel statistics are presented
throughout this MD&A on a "before royalty" or "gross" basis,
and realized prices are net of transportation and blending costs
and exclude the effect of risk management activities. Production on
an "after royalty" or "net" basis is also presented for information
purposes only.
The following discussion refers primarily to the Company's
financial results for the six and three months ended June 30, 2010
in relation to the comparable periods in 2009 and the first quarter
of 2010. The accompanying tables form an integral part of this
MD&A. This MD&A is dated August 4, 2010. Additional
information relating to the Company, including its amended Annual
Information Form for the year ended December 31, 2009, is available
on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010(1) 2009(1) 2010 2009(1)
----------------------------------------------------------------------------
Revenue, before royalties $ 3,614 $ 3,580 $ 2,750 $ 7,194 $ 4,936
Net earnings $ 667 $ 866 $ 162 $ 1,533 $ 467
Per common share - basic
and diluted $ 0.61 $ 0.80 $ 0.15 $ 1.41 $ 0.43
Adjusted net earnings from
operations (2) $ 688 $ 658 $ 637 $ 1,346 $ 1,364
Per common share - basic
and diluted $ 0.63 $ 0.61 $ 0.59 $ 1.24 $ 1.26
Cash flow from operations (3) $ 1,630 $ 1,505 $ 1,365 $ 3,135 $ 2,881
Per common share - basic
and diluted $ 1.49 $ 1.39 $ 1.26 $ 2.88 $ 2.66
Capital expenditures, net of
dispositions $ 1,573 $ 1,072 $ 473 $ 2,645 $ 1,729
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Per share amounts have been restated to reflect a two-for-one common
share split in May 2010.
(2) 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.
(3) Cash flow from operations is a non-GAAP measure that represents net
earnings adjusted for non-cash items before working capital
adjustments. The Company evaluates its performance based on cash flow
from operations. The Company considers cash flow from operations a key
measure as it demonstrates the Company's ability to generate the cash
flow necessary to fund future growth through capital investment and to
repay debt. The reconciliation "Cash Flow from Operations" presented
below lists certain non-cash items that are included in the Company's
financial results. Cash flow from operations may not be comparable to
similar measures presented by other companies.
Adjusted Net Earnings from Operations
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Net earnings as reported $ 667 $ 866 $ 162 $ 1,533 $ 467
Stock-based compensation
(recovery) expense, net of
tax (a) (d) (58) (2) 67 (60) 70
Unrealized risk management
(gain) loss, net of tax (b) (64) (154) 676 (218) 996
Unrealized foreign exchange
loss (gain), net of tax (c) 143 (135) (268) 8 (150)
Effect of statutory tax rate and
other legislative changes on
future income tax
liabilities (d) - 83 - 83 (19)
----------------------------------------------------------------------------
Adjusted net earnings from
operations $ 688 $ 658 $ 637 $ 1,346 $ 1,364
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) The Company's employee stock option plan provides for a cash payment
option. Accordingly, the intrinsic value of the outstanding vested
options is recorded as a liability on the Company's balance sheet and
periodic changes in the intrinsic value are recognized in net earnings
or are capitalized to Oil Sands Mining and Upgrading construction costs.
(b) Derivative financial instruments are recorded at fair value on the
balance sheet, with changes in fair value of non-designated hedges
recognized in net earnings. The amounts ultimately realized may be
materially different than reflected in the financial statements due to
changes in prices of the underlying items hedged, primarily crude oil
and natural gas.
(c) Unrealized foreign exchange gains and losses result primarily from the
translation of US dollar denominated long-term debt to period-end
exchange rates, offset by the impact of cross currency swaps, and are
recognized in net earnings.
(d) All substantively enacted or enacted adjustments in applicable income
tax rates and other legislative changes are applied to underlying
assets and liabilities on the Company's consolidated balance sheet in
determining future income tax assets and liabilities. The impact of
these tax rate and other legislative changes is recorded in net
earnings during the period the legislation is substantively enacted or
enacted. During the first quarter of 2010, the Canadian Federal budget
proposed changes to the taxation of stock options surrendered by
employees for cash payments. As a result of the proposed changes,
the Company anticipates that Canadian based employees will no longer
surrender their options for cash payments, resulting in a loss of
future income tax deductions for the Company. The impact of this change
was an $83 million charge to future income tax expense during the first
quarter. Income tax rate changes in the first quarter of 2009 resulted
in a reduction of future income tax liabilities of approximately $19
million in North America.
Cash Flow from Operations
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Net earnings $ 667 $ 866 $ 162 $ 1,533 $ 467
Non-cash items:
Depletion, depreciation and
amortization 836 771 664 1,607 1,310
Asset retirement obligation
accretion 26 26 24 52 43
Stock-based compensation
(recovery) expense (58) (2) 92 (60) 96
Unrealized risk management
(gain) loss (82) (208) 946 (290) 1,409
Unrealized foreign exchange
loss (gain) 165 (150) (320) 15 (182)
Deferred petroleum revenue
tax expense (recovery) 5 7 (2) 12 (5)
Future income tax expense
(recovery) 71 195 (201) 266 (257)
----------------------------------------------------------------------------
Cash flow from operations $ 1,630 $ 1,505 $ 1,365 $ 3,135 $ 2,881
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the six months ended June 30, 2010 were $1,533
million compared to $467 million for the six months ended June 30,
2009. Net earnings for the six months ended June 30, 2010 included
net unrealized after-tax income of $187 million related to the
effects of risk management activities, fluctuations in foreign
exchange rates, fluctuations in stock-based compensation, and the
impact of statutory tax rate changes on future income tax
liabilities, compared to net unrealized after-tax expenses of $897
million for the six months ended June 30, 2009. Excluding these
items, adjusted net earnings from operations for the six months
ended June 30, 2010 were $1,346 million compared to $1,364 million
for the six months ended June 30, 2009.
Net earnings for the second quarter of 2010 were $667 million
compared to $162 million for the second quarter of 2009 and $866
million for the prior quarter. Net earnings for the second quarter
of 2010 included net unrealized after-tax expenses of $21 million
related to the effects of risk management activities, fluctuations
in foreign exchange rates and stock-based compensation, compared to
net unrealized after-tax expenses of $475 million for the second
quarter of 2009 and net unrealized after-tax income of $208 million
for the prior quarter. Excluding these items, adjusted net earnings
from operations for the second quarter of 2010 were $688 million
compared to $637 million for the second quarter of 2009 and $658
million for the prior quarter. The increase in adjusted net
earnings from the comparable periods in 2009 was primarily due to
the impact of higher realized crude oil pricing, higher crude oil
and NGL sales volumes including crude oil volumes associated with
Horizon, and realized foreign exchange gains, partially offset by
higher production expense, higher royalty expense, lower realized
risk management gains, higher depletion, depreciation and
amortization expense, and the impact of the stronger Canadian
dollar. The increase in adjusted net earnings from the prior
quarter was primarily due to the impact of higher crude oil and NGL
sales volumes including Horizon, lower production expense, lower
royalty expense, and realized risk management gains, partially
offset by the impact of lower realized crude oil and natural gas
pricing and higher depletion, depreciation and amortization
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 six months ended June 30, 2010
was $3,135 million compared to $2,881 million for the six months
ended June 30, 2009. Cash flow from operations for the second
quarter of 2010 was $1,630 million compared to $1,365 million for
the second quarter of 2009 and $1,505 million for the prior
quarter. The increase in cash flow from operations from the
comparable periods in 2009 was primarily due to the impact of
higher realized crude oil pricing, higher crude oil and NGL sales
volumes including crude oil volumes associated with Horizon, and
realized foreign exchange gains, partially offset by higher
production expense, higher royalty expense, lower realized risk
management gains, higher cash taxes and the impact of the stronger
Canadian dollar. The increase in cash flow from operations from the
prior quarter was primarily due to the impact of higher crude oil
and NGL sales volumes including Horizon, lower production expense,
lower royalty expense, and realized risk management gains partially
offset by the impact of lower realized crude oil and natural gas
pricing.
Total production before royalties for the six months ended June
30, 2010 increased 10% to 629,982 boe/d from 574,654 boe/d for the
six months ended June 30, 2009. Total production before royalties
for the second quarter of 2010 increased 10% to 649,195 boe/d from
590,984 boe/d for the second quarter of 2009 and 6% from 610,556
boe/d for the prior quarter. Production for the second quarter of
2010 exceeded the Company's previously issued guidance.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results
for the eight most recently completed quarters:
($ millions, except per Jun 30 Mar 31 Dec 31 Sep 30
common share amounts) 2010 2010(1) 2009(1) 2009(1)
----------------------------------------------------------------------------
Revenue, before royalties $ 3,614 $ 3,580 $ 3,319 $ 2,823
Net earnings $ 667 $ 866 $ 455 $ 658
Net earnings per common share
- Basic and diluted $ 0.61 $ 0.80 $ 0.42 $ 0.61
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per Jun 30 Mar 31 Dec 31 Sep 30
common share amounts) 2009(1) 2009(1) 2008(1) 2008(1)
----------------------------------------------------------------------------
Revenue, before royalties $ 2,750 $ 2,186 $ 2,511 $ 4,583
Net earnings $ 162 $ 305 $ 1,770 $ 2,835
Net earnings per common share
- Basic and diluted $ 0.15 $ 0.28 $ 1.64 $ 2.62
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Per share amounts have been restated to reflect a two-for-one common
share split in May 2010.
Volatility in quarterly net earnings over the eight most
recently completed quarters was primarily due to:
- Crude oil pricing - The impact of fluctuating demand,
inventory storage levels and geopolitical uncertainties on
worldwide benchmark pricing, and the fluctuations in the Heavy
Crude Oil Differential from WTI ("Heavy Differential") in North
America.
- Natural gas pricing - The impact of seasonal fluctuations in
both the demand for natural gas and inventory storage levels, and
the impact of increased shale gas production in the US, as well as
fluctuations in imports of liquefied natural gas into the US.
- Crude oil and NGLs sales volumes - Fluctuations in production
due to the cyclic nature of the Company's Primrose thermal
projects, the results from the Pelican Lake water and polymer flood
projects, and the commencement and ramp up of operations at
Horizon. Sales volumes also reflected fluctuations due to timing of
liftings and maintenance activities in the North Sea and Offshore
West Africa.
- Natural gas sales volumes - Fluctuations in production due to
the Company's strategic decision to reduce natural gas drilling
activity in North America and the allocation of capital to higher
return crude oil projects, as well as natural decline rates and the
impact of acquisitions.
- Production expense - Fluctuations primarily due to the impact
of the demand for services, industry-wide inflationary cost
pressures experienced in prior quarters, fluctuations in product
mix, the impact of seasonal costs that are dependent on weather,
production and cost optimizations in North America and the
commencement of operations at Horizon and the Olowi Field in
Offshore Gabon.
- Depletion, depreciation and amortization - Fluctuations due to
changes in sales volumes, proved reserves, finding and development
costs associated with crude oil and natural gas exploration,
estimated future costs to develop the Company's proved undeveloped
reserves, the commencement of operations at Horizon and the Olowi
Field in Offshore Gabon, and the impact of an impairment at the
Olowi Field at December 31, 2009.
- Stock-based compensation - Fluctuations due to the
mark-to-market movements of the Company's stock-based compensation
liability. Stock-based compensation expense (recovery) reflected
fluctuations in the Company's share price.
- Risk management - Fluctuations due to the recognition of gains
and losses from the mark-to-market and subsequent settlement of the
Company's risk management activities.
- Foreign exchange rates - Changes 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.
Fluctuations in unrealized foreign exchange gains and losses are
recorded with respect to US dollar denominated debt and the
re-measurement of North Sea future income tax liabilities
denominated in UK pounds sterling to US dollars, partially offset
by the impact of cross currency swap hedges.
- Income tax expense (recovery) - Fluctuations in income tax
expense (recovery) include statutory tax rate and other legislative
changes substantively enacted or enacted in the various
periods.
BUSINESS ENVIRONMENT
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
WTI benchmark price (US$/bbl) $ 77.99 $ 78.79 $ 59.61 $ 78.39 $ 51.46
Dated Brent benchmark price
(US$/bbl) $ 78.27 $ 76.32 $ 58.78 $ 77.30 $ 51.65
WCS blend differential from
WTI (US$/bbl) $ 14.12 $ 9.06 $ 7.43 $ 11.60 $ 8.20
WCS blend differential from
WTI (%) 18% 12% 13% 15% 16%
SCO price (US$/bbl) (1) $ 76.44 $ 79.37 $ 58.42 $ 77.90 $ 51.74
Condensate benchmark price
(US$/bbl) $ 82.81 $ 84.82 $ 58.30 $ 83.81 $ 50.91
NYMEX benchmark price
(US$/mmbtu) $ 4.08 $ 5.38 $ 3.59 $ 4.72 $ 4.23
AECO benchmark price (C$/GJ) $ 3.66 $ 5.07 $ 3.46 $ 4.36 $ 4.40
US / Canadian dollar average
exchange rate $ 0.9731 $ 0.9615 $ 0.8571 $ 0.9673 $ 0.8293
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Synthetic Crude Oil ("SCO")
Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$78.39 per
bbl for the six months ended June 30, 2010, an increase of 52% from
US$51.46 per bbl for the six months ended June 30, 2009. WTI
averaged US$77.99 per bbl for the second quarter of 2010, an
increase of 31% from US$59.61 per bbl for the second quarter of
2009, and was comparable to the prior quarter. WTI pricing was
reflective of the overall balanced supply and demand environment,
with strong Asian demand offsetting the demand decline related to
the Organization of Economic Co-operation and Development
("OECD").
Crude oil sales contracts for the Company's North Sea and
Offshore West Africa segments are typically based on Dated Brent
("Brent") pricing, which is more reflective of international
markets and overall supply and demand. Brent averaged US$77.30 per
bbl for the six months ended June 30, 2010, an increase of 50%
compared to US$51.65 per bbl for the six months ended June 30,
2009. Brent averaged US$78.27 per bbl for the second quarter of
2010, an increase of 33% compared to US$58.78 per bbl for the
second quarter of 2009, and 3% from US$76.32 per bbl for the prior
quarter. High inventory levels at Cushing during the second quarter
resulted in Brent prices exceeding WTI.
The Western Canadian Select ("WCS") Heavy Differential averaged
15% for the six months ended June 30, 2010 compared to 16% for the
six months ended June 30, 2009. The WCS Heavy Differential widened
in the second quarter of 2010, averaging 18% compared to 13% for
the second quarter of 2009 and 12% for the prior quarter due to
improved refinery utilizations.
The Company anticipates continued volatility in crude oil
pricing benchmarks due to the unpredictable nature of supply and
demand factors, geopolitical events, and the timing and extent of
the near term economic recovery. The Heavy Differential is expected
to continue to reflect seasonal demand fluctuations and refinery
margins.
NYMEX natural gas prices averaged US$4.72 per mmbtu for the six
months ended June 30, 2010, an increase of 12% from US$4.23 per
mmbtu for the six months ended June 30, 2009. NYMEX natural gas
prices averaged US$4.08 per mmbtu for the second quarter of 2010,
an increase of 14% from US$3.59 per mmbtu for the second quarter of
2009, and a decrease of 24% from US$5.38 per mmbtu for the prior
quarter. AECO natural gas prices for the six months ended June 30,
2010 averaged $4.36 per GJ, comparable to prices for the six months
ended June 30, 2009. AECO natural gas prices for the second quarter
of 2010 increased 6% to average $3.66 per GJ from $3.46 per GJ in
the second quarter of 2009, and decreased 28% from $5.07 per GJ for
the prior quarter. Natural gas prices reflected lower benchmark
pricing during the second quarter. Weather patterns in the
Northeast part of the United States and drilling shut-ins in the
Gulf of Mexico temporarily mitigated seasonal pricing declines.
Update to Alberta Royalty Framework
On January 1, 2009, changes to the Alberta royalty regime under
the Alberta Royalty Framework ("ARF") came into effect, including
the implementation of a sliding scale for oil sands royalties
ranging from 1% to 9% on a gross revenue basis pre-payout and 25%
to 40% on a net revenue basis post-payout, depending on benchmark
crude oil pricing.
In addition, on January 1, 2009, new royalty formulas under the
ARF for conventional crude oil and natural gas, specifying
royalties on sliding scales ranging up to 50%, depending on
commodity prices and well productivity, came into effect.
In March 2010, the Government of Alberta modified the
conventional crude oil and natural gas royalty rates. These
changes, effective January 1, 2011, include:
- A reduction in the maximum royalty rate to 5% on new natural
gas and conventional crude oil wells for the first 12 months after
the start of production, subject to volume limits of 500 mmcfe and
50,000 boe respectively.
- A reduction in the maximum royalty rate for conventional crude
oil from 50% to 40% and a reduction in the maximum royalty rate for
conventional and unconventional natural gas from 50% to 36%.
In May 2010, the Government of Alberta announced further changes
to conventional crude oil and natural gas royalty rates, effective
May 1, 2010, including:
- An extension of the period subject to the 5% maximum royalty
rate for coalbed methane and shale gas wells to the first 36 months
after start of production, subject to volume limits of 750 mmcfe
for coalbed methane and no volume limits for shale gas.
- An extension of the period subject to the 5% maximum royalty
rate for horizontal natural gas and conventional crude oil wells.
The period for horizontal natural gas wells is extended to the
first 18 months after start of production, and volumes of 500
mmcfe. Limits on production months and volumes for conventional
crude oil will be set according to the measured depth of the
wells.
Modifications were also made to the natural gas deep drilling
program, including changes to depth requirements. The government
also announced changes to the price components of oil and gas
royalty formulas to reduce the royalty rate at prices higher than
$85.00 per bbl and $5.25 per GJ respectively.
DAILY PRODUCTION, before royalties
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America - Conventional 275,584 252,450 232,139 264,081 242,926
North America -
Oil Sands Mining and Upgrading 99,950 86,995 59,599 93,508 31,647
North Sea 37,669 36,879 40,362 37,276 41,360
Offshore West Africa 29,842 29,942 33,572 29,892 32,010
----------------------------------------------------------------------------
443,045 406,266 365,672 424,757 347,943
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,219 1,193 1,322 1,206 1,334
North Sea 9 15 10 12 10
Offshore West Africa 9 18 20 13 16
----------------------------------------------------------------------------
1,237 1,226 1,352 1,231 1,360
----------------------------------------------------------------------------
Total barrels of oil
equivalent (boe/d) 649,195 610,556 590,984 629,982 574,654
----------------------------------------------------------------------------
Product mix
Light/medium crude oil and NGLs 18% 19% 21% 18% 21%
Pelican Lake crude oil 6% 6% 6% 6% 6%
Primary heavy crude oil 14% 15% 14% 15% 15%
Thermal heavy crude oil 15% 12% 11% 14% 13%
Synthetic crude oil 15% 14% 10% 15% 6%
Natural gas 32% 34% 38% 32% 39%
----------------------------------------------------------------------------
Percentage of gross revenue (1)
(excluding midstream revenue)
Crude oil and NGLs 86% 82% 79% 84% 73%
Natural gas 14% 18% 21% 16% 27%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation and blending costs and excluding risk management
activities.
DAILY PRODUCTION, net of royalties
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America - Conventional 228,781 206,094 197,281 217,501 210,819
North America -
Oil Sands Mining and Upgrading 96,543 83,918 58,467 90,266 31,067
North Sea 37,581 36,803 40,292 37,194 41,273
Offshore West Africa 28,225 28,927 30,470 28,574 29,411
----------------------------------------------------------------------------
391,130 355,742 326,510 373,535 312,570
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,149 1,101 1,313 1,125 1,247
North Sea 9 15 10 12 10
Offshore West Africa 8 17 18 13 15
----------------------------------------------------------------------------
1,166 1,133 1,341 1,150 1,272
----------------------------------------------------------------------------
Total barrels of oil
equivalent (boe/d) 585,556 544,553 550,053 565,170 524,538
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's business approach is to maintain large project
inventories and production diversification among each of the
commodities it produces; namely natural gas, light/medium crude oil
and NGLs, Pelican Lake crude oil, primary heavy crude oil, thermal
heavy crude oil, and SCO.
Total crude oil and NGLs production for the six months ended
June 30, 2010 increased 22% to 424,757 bbl/d from 347,943 bbl/d for
the six months ended June 30, 2009. The increase was primarily due
to the higher volumes from the Company's thermal and Horizon
operations.
Total crude oil and NGLs production for the second quarter of
2010 increased 21% to 443,045 bbl/d from 365,672 bbl/d for the
second quarter of 2009, and 9% from 406,266 bbl/d for the prior
quarter. The increases from the comparable periods were primarily
related to the cyclic nature of the Company's thermal operations
and increased Horizon production. Crude oil and NGLs production in
the second quarter of 2010 exceeded the Company's previously issued
guidance of 394,000 to 426,000 bbl/d.
Natural gas production for the six months ended June 30, 2010
averaged 1,231 mmcf/d compared to 1,360 mmcf/d for the six months
ended June 30, 2009. Natural gas production for the second quarter
of 2010 decreased 9% to 1,237 mmcf/d compared to 1,352 mmcf/d for
the second quarter of 2009 and was comparable to the prior quarter.
The decrease in natural gas production from the comparable periods
in 2009 reflects the expected production declines due to the
allocation of capital to higher return crude oil projects, which
resulted in a strategic reduction of natural gas drilling activity.
Natural gas production in the second quarter of 2010 exceeded the
Company's previously issued guidance of 1,207 to 1,232 mmcf/d.
For 2010, annual production guidance is targeted to average
between 421,000 and 449,000 bbl/d of crude oil and NGLs and between
1,229 and 1,256 mmcf/d of natural gas. Third quarter 2010
production guidance is targeted to average between 414,000 and
445,000 bbl/d of crude oil and NGLs and between 1,247 and 1,271
mmcf/d of natural gas.
North America - Conventional
North America conventional crude oil and NGLs production for the
six months ended June 30, 2010 increased 9% to average 264,081
bbl/d from 242,926 bbl/d for the six months ended June 30, 2009.
Second quarter North America conventional crude oil and NGLs
production increased 19% to average 275,584 bbl/d, compared to
232,139 bbl/d for the second quarter of 2009, and 9% from 252,450
bbl/d for the prior quarter. Increases in crude oil and NGLs
production were primarily due to the cyclic nature of the Company's
thermal production and a record heavy oil drilling program, and
exceeded expectations. Production of conventional crude oil and
NGLs exceeded the Company's previously issued guidance of 255,000
bbl/d to 265,000 bbl/d for the second quarter of 2010.
Natural gas production for the six months ended June 30, 2010
decreased 10% to 1,206 mmcf/d from 1,334 mmcf/d for the six months
ended June 30, 2009. For the second quarter of 2010, natural gas
production decreased 8% to 1,219 mmcf/d from 1,322 mmcf/d for the
second quarter of 2009, and increased 2% from 1,193 mmcf/d for the
prior quarter. The decreases in natural gas production from the
comparable periods in 2009 reflected the expected production
declines due to the allocation of capital to higher return crude
oil projects, which resulted in a strategic reduction of natural
gas drilling activity. The increase in natural gas production from
the prior quarter was primarily a result of the acquisition of
natural gas properties in certain of the Company's core regions.
Production of natural gas exceeded the Company's previously issued
guidance of 1,190 mmcf/d to 1,210 mmcf/d for the second quarter of
2010.
North America - Oil Sands Mining and Upgrading
Horizon Phase 1 commenced production of synthetic crude oil
during 2009. Production averaged 93,508 bbl/d for the six months
ended June 30, 2010, up 195% from 31,647 bbl/day for the six months
ended June 30, 2009. For the second quarter of 2010, production
increased 68% to 99,950 bbl/day, compared to 59,599 bbl/day in the
second quarter of 2009, and 15% from 86,995 bbl/d in the prior
quarter. Production volumes in the second quarter reflected the
Company's focus on operational optimization and ramping up of
production. Planned proactive maintenance during May 2010 was
successfully completed, leading to record production volumes of
117,600 bbl/day in June 2010. Second quarter production for 2010
exceeded the Company's previously issued guidance of 80,000 bbl/d
to 95,000 bbl/d.
North Sea
North Sea crude oil production for the six months ended June 30,
2010 decreased 10% to 37,276 bbl/d from 41,360 bbl/d for the six
months ended June 30, 2009. Production volumes for the six months
ended June 30, 2010 were lower than the comparable period in 2009
due to unplanned operational issues at Banff, Kyle and Murchison,
partially offset by improved performance on the Ninian and Lyell
Fields. Second quarter 2010 North Sea crude oil production
decreased 7% to 37,669 bbl/d from 40,362 bbl/d for the second
quarter of 2009 and was comparable to the prior quarter. Production
in the second quarter of 2010 exceeded the Company's previously
issued guidance of 33,000 bbl/d to 36,000 bbl/d primarily due to
strong performance from the Ninian Field.
Offshore West Africa
Offshore West Africa crude oil production decreased 7% to 29,892
bbl/d for the six months ended June 30, 2010 from 32,010 bbl/d for
the six months ended June 30, 2009. Second quarter crude oil
production decreased 11% to 29,842 bbl/d from 33,572 bbl/d for the
second quarter of 2009, and was comparable to the prior quarter.
During the second quarter of 2010, final commissioning of Platform
B at the Olowi Field was completed and first crude oil production
was achieved as planned in April. Production in the second quarter
was impacted by a planned shutdown at Espoir for installation of
facilities upgrades but was at the high end of the Company's
previously issued guidance.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when
title transfers to the customer and delivery has taken place.
Revenue has not been recognized on crude oil volumes that were
stored in various tanks, pipelines, or floating production, storage
and offtake vessels, as follows:
Jun 30 Mar 31 Dec 31
(bbl) 2010 2010 2009
----------------------------------------------------------------------------
North America - Conventional 761,351 761,351 1,131,372
North America - Oil Sands Mining
and Upgrading (SCO) 1,139,778 1,021,028 1,224,481
North Sea 1,018,357 642,457 713,112
Offshore West Africa 1,428,949 898,233 51,103
----------------------------------------------------------------------------
4,348,435 3,323,069 3,120,068
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS - CONVENTIONAL
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
Sales price (2) $ 63.62 $ 68.76 $ 59.56 $ 66.10 $ 50.12
Royalties 8.95 10.08 7.27 9.50 5.57
Production expense 13.19 14.56 16.59 13.85 15.78
----------------------------------------------------------------------------
Netback $ 41.48 $ 44.12 $ 35.70 $ 42.75 $ 28.77
----------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 3.86 $ 5.19 $ 4.11 $ 4.52 $ 4.78
Royalties (3) 0.25 0.41 0.06 0.33 0.39
Production expense 1.05 1.20 1.05 1.12 1.12
----------------------------------------------------------------------------
Netback $ 2.56 $ 3.58 $ 3.00 $ 3.07 $ 3.27
----------------------------------------------------------------------------
Barrels of oil equivalent
($/boe) (1)
Sales price (2) $ 47.97 $ 53.88 $ 44.52 $ 50.86 $ 41.13
Royalties 6.10 7.07 4.34 6.58 4.24
Production expense 10.55 11.67 12.21 11.09 11.98
----------------------------------------------------------------------------
Netback $ 31.32 $ 35.14 $ 27.97 $ 33.19 $ 24.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
(3) Natural gas royalties for 2009 reflect the impact of natural gas
physical sales contracts.
PRODUCT PRICES - CONVENTIONAL
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)(1)(2)
North America $ 60.35 $ 66.18 $ 57.97 $ 63.15 $ 47.25
North Sea $ 79.30 $ 80.53 $ 65.52 $ 79.95 $ 60.85
Offshore West Africa $ 79.21 $ 79.30 $ 63.00 $ 79.25 $ 58.00
Company average $ 63.62 $ 68.76 $ 59.56 $ 66.10 $ 50.12
Natural gas ($/mcf)(1)(2)
North America $ 3.85 $ 5.20 $ 4.06 $ 4.51 $ 4.76
North Sea $ 3.33 $ 4.30 $ 3.84 $ 3.93 $ 4.06
Offshore West Africa $ 5.14 $ 5.56 $ 7.34 $ 5.42 $ 7.09
Company average $ 3.86 $ 5.19 $ 4.11 $ 4.52 $ 4.78
Company average ($/boe)(1)(2) $ 47.97 $ 53.88 $ 44.52 $ 50.86 $ 41.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 realized crude oil prices increased 34% to average
$63.15 per bbl for the six months ended June 30, 2010 from $47.25
per bbl for the six months ended June 30, 2009. Realized crude oil
prices increased 4% to average $60.35 per bbl for the second
quarter of 2010 from $57.97 per bbl for the second quarter of 2009,
and decreased 9% from $66.18 per bbl for the prior quarter. The
increase from the comparable periods in 2009 was primarily a result
of increased WTI benchmark pricing and the impact of the narrow
Heavy Differential, partially offset by the impact of the stronger
Canadian dollar relative to the US dollar. The decrease in prices
from the prior quarter was a result of lower WTI benchmark pricing
and the widening heavy oil differential.
The Company continues to focus on its crude oil marketing
strategy, and in the second quarter of 2010 contributed
approximately 165,000 bbl/d of heavy crude oil blends to the WCS
stream.
In the first quarter of 2010, the Company announced, together
with North West Upgrading Inc., the submission of a joint proposal
to the Alberta Government to construct and operate a bitumen
refinery near Redwater, Alberta under the Alberta Royalty
Framework's Bitumen Royalty In Kind ("BRIK") program. In the second
quarter, the Government of Alberta announced that the proposal had
been selected for exclusive negotiations following a comprehensive
review. Further project development is dependent upon successful
completion of these negotiations on commercially acceptable terms
and final project sanction by the respective parties.
North America realized natural gas prices decreased 5% to
average $4.51 per mcf for the six months ended June 30, 2010 from
$4.76 per mcf for the six months ended June 30, 2009. Realized
natural gas prices decreased 5% to average $3.85 per mcf for the
second quarter of 2010 from $4.06 per mcf for the second quarter of
2009, and 26% from $5.20 per mcf for the prior quarter. The
decrease in natural gas prices from the second quarter of 2009 was
primarily related to lower benchmark prices due to lower demand and
high storage levels, and the impact of the stronger Canadian dollar
relative to the US dollar. The decrease in natural gas prices from
the prior quarter was primarily related to lower benchmark prices
due to high storage levels.
Comparisons of the prices received for the Company's North
America conventional production by product type were as
follows:
Jun 30 Mar 31 Jun 30
(Quarterly Average) 2010 2010 2009
----------------------------------------------------------------------------
Wellhead Price(1)(2)
Light/medium crude oil and NGLs ($/bbl) $ 68.13 $ 72.15 $ 56.00
Pelican Lake crude oil ($/bbl) $ 60.38 $ 66.04 $ 59.94
Primary heavy crude oil ($/bbl) $ 60.26 $ 66.45 $ 58.08
Thermal heavy crude oil ($/bbl) $ 56.53 $ 62.08 $ 58.22
Natural gas ($/mcf) $ 3.85 $ 5.20 $ 4.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North Sea
North Sea realized crude oil prices increased 31% to average
$79.95 per bbl for the six months ended June 30, 2010 from $60.85
per bbl for the six months ended June 30, 2009. Realized crude oil
prices increased 21% to average $79.30 per bbl for the second
quarter of 2010 from $65.52 per bbl for the second quarter of 2009,
and decreased 2% from $80.53 per bbl for the prior quarter. The
increase in realized crude oil prices in the North Sea from the
comparable periods in 2009 was primarily the result of increased
Brent benchmark pricing, partially offset by the impact of the
stronger Canadian dollar.
Offshore West Africa
Offshore West Africa realized crude oil prices increased 37% to
average $79.25 per bbl for the six months ended June 30, 2010 from
$58.00 per bbl for the six months ended June 30, 2009. Realized
crude oil prices increased 26% to average $79.21 per bbl for the
second quarter of 2010 from $63.00 per bbl for the second quarter
of 2009, and were comparable to the prior quarter. The increase in
realized crude oil prices in Offshore West Africa from the
comparable periods in 2009 was primarily the result of increased
Brent benchmark pricing, partially offset by the impact of the
stronger Canadian dollar. Realized crude oil prices in Offshore
West Africa were also impacted by the timing of liftings from each
field.
ROYALTIES - CONVENTIONAL
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)(1)
North America $ 10.42 $ 12.13 $ 8.83 $ 11.24 $ 6.59
North Sea $ 0.18 $ 0.17 $ 0.11 $ 0.17 $ 0.12
Offshore West Africa $ 4.29 $ 2.69 $ 5.82 $ 3.56 $ 4.62
Company average $ 8.95 $ 10.08 $ 7.27 $ 9.50 $ 5.57
Natural gas ($/mcf)(1)
North America (2) $ 0.25 $ 0.41 $ 0.05 $ 0.33 $ 0.39
Offshore West Africa $ 0.26 $ 0.19 $ 0.63 $ 0.21 $ 0.56
Company average $ 0.25 $ 0.41 $ 0.06 $ 0.33 $ 0.39
Company average ($/boe)(1) $ 6.10 $ 7.07 $ 4.34 $ 6.58 $ 4.24
Percentage of revenue(3)
Crude oil and NGLs 14% 15% 12% 14% 11%
Natural gas(2) 6% 8% 2% 7% 8%
Boe 13% 13% 10% 13% 10%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Natural gas royalties for 2009 reflect the impact of natural gas
physical sales contracts.
(3) Net of transportation and blending costs and excluding risk management
activities.
North America
North America royalties for the six months ended June 30, 2010
compared to 2009 reflect stronger realized commodity prices and the
impact of the changes under the ARF.
Crude oil and NGLs royalties averaged approximately 17% of
revenues for the second quarter of 2010, compared to 15% for the
second quarter in 2009 and 18% for the prior quarter. Crude oil and
NGLs royalties per bbl are anticipated to average 17% to 19% of
gross revenue for 2010.
Natural gas royalties averaged approximately 6% of revenues for
the second quarter of 2010 compared to 2% for the second quarter of
2009 and 8% for the prior quarter. The increase in natural gas
royalty rates for the second quarter of 2010 compared to the prior
year was primarily due to higher benchmark pricing and the impact
of fixed-price natural gas sales contracts in 2009. Natural gas
royalties are anticipated to average 6% to 8% of gross revenue for
2010.
Offshore West Africa
Under the terms of the Production Sharing Contracts, royalty
rates fluctuate based on realized commodity pricing, capital costs,
and the timing of liftings from each field. Royalty rates as a
percentage of revenue averaged approximately 5% for the second
quarter of 2010 compared to 9% for the second quarter of 2009 and
3% for the prior quarter. Offshore West Africa royalty rates are
anticipated to average 6% to 8% of gross revenue for 2010.
PRODUCTION EXPENSE - CONVENTIONAL
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)(1)
North America $ 11.75 $ 13.09 $ 15.29 $ 12.39 $ 14.93
North Sea $ 21.35 $ 25.15 $ 27.36 $ 23.35 $ 25.22
Offshore West Africa $ 18.33 $ 13.49 $ 10.45 $ 16.11 $ 10.99
Company average $ 13.19 $ 14.56 $ 16.59 $ 13.85 $ 15.78
Natural gas ($/mcf)(1)
North America $ 1.03 $ 1.17 $ 1.04 $ 1.10 $ 1.11
North Sea $ 2.53 $ 3.54 $ 1.62 $ 3.15 $ 1.73
Offshore West Africa $ 1.64 $ 1.63 $ 1.36 $ 1.63 $ 1.49
Company average $ 1.05 $ 1.20 $ 1.05 $ 1.12 $ 1.12
Company average ($/boe)(1) $ 10.55 $ 11.67 $ 12.21 $ 11.09 $ 11.98
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America
North America crude oil and NGLs production expense for the six
months ended June 30, 2010 decreased 17% to $12.39 per bbl from
$14.93 per bbl for the six months ended June 30, 2009. Production
expense for the second quarter of 2010 decreased 23% to $11.75 per
bbl from $15.29 per bbl for the second quarter of 2009 and 10% from
$13.09 per bbl for the prior quarter. The decrease in production
expense per barrel from the comparable periods was a result of
higher production volumes and the lower cost of natural gas used
for fuel. North America crude oil and NGLs production expense is
anticipated to average $12.00 to $13.00 per barrel for 2010.
North America natural gas production expense for the six months
ended June 30, 2010 averaged $1.10 per mcf and was comparable to
the six months ended June 30, 2009. Production expense for the
second quarter of 2010 averaged $1.03 per mcf and was comparable to
the second quarter of 2009 and decreased 12% from $1.17 per mcf for
the prior quarter. The decrease in production expense per mcf from
the prior quarter was primarily a result of the Company's focus on
optimizing production and service costs and improving efficiency.
North America natural gas production expense is anticipated to
average $1.10 to $1.20 per mcf for 2010.
North Sea
North Sea crude oil production expense for the six months ended
June 30, 2010 decreased 7% to $23.35 per bbl from $25.22 per bbl
for the six months ended June 30, 2009. Production expense for the
second quarter of 2010 decreased 22% to $21.35 per bbl from $27.36
per bbl for the second quarter of 2009 and 15% from $25.15 per bbl
for the prior quarter. Production expense decreased on a per barrel
basis from the comparable periods in 2009 due to lower maintenance
activities and improved performance from the Ninian Platforms.
Production expense decreased on a per barrel basis from the prior
quarter due to one-time third party cost recoveries. The Company
continues to focus on production costs, with guidance reduced to
$28.00 to $31.00 per barrel. Production expense is anticipated to
increase in the third quarter due to planned maintenance
activity.
Offshore West Africa
Offshore West Africa crude oil production expense increased 47%
to $16.11 per bbl from $10.99 per bbl for the six months ended June
30, 2009. Production expense for the second quarter of 2010
increased 75% to $18.33 per bbl from $10.45 per bbl for the second
quarter of 2009 and 36% from $13.49 per bbl for the prior quarter.
Production expense increased on a per barrel basis from the
comparable periods in the prior year due to the timing of liftings
for each field, including the impact of costs associated with the
Olowi Field which has higher production costs than Espoir and
Baobab. Production expense increased from the prior quarter due to
increased liftings from the Olowi Field, and the planned shutdown
at Espoir for facilities upgrades. Production expense is
anticipated to average $14.00 to $16.00 per bbl for 2010.
DEPLETION, DEPRECIATION AND AMORTIZATION - CONVENTIONAL
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expense ($ millions) $ 740 $ 679 $ 631 $ 1,419 $ 1,292
$/boe (1) $ 15.85 $ 14.52 $ 13.07 $ 14.81 $ 13.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
The increase in depletion, depreciation and amortization expense
from the comparable periods in the prior year was due to higher
production in North America, an increase in the estimated future
costs to develop the Company's proved undeveloped reserves in the
North Sea, and recognition of depletion, depreciation and
amortization expense due to increased liftings from the Olowi
Field. The increase in depletion, depreciation and amortization
expense from the prior quarter was primarily due to the impact of
higher production in North America and higher depletion,
depreciation and amortization expense due to increased liftings
from the Olowi Field.
ASSET RETIREMENT OBLIGATION ACCRETION - CONVENTIONAL
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expense ($ millions) $ 21 $ 20 $ 18 $ 41 $ 35
$/boe (1) $ 0.45 $ 0.43 $ 0.36 $ 0.43 $ 0.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the
increase in the carrying amount of the asset retirement obligation
due to the passage of time.
OPERATING HIGHLIGHTS - OIL SANDS MINING AND UPGRADING
FINANCIAL METRICS
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($/bbl)(1) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
SCO sales price (2) $ 75.97 $ 78.76 $ 65.40 $ 77.29 $ 65.40
Bitumen value for royalty
purposes (3) $ 52.67 $ 61.33 $ 54.00 $ 57.00 $ 54.00
Bitumen royalties (4) $ 2.69 $ 2.83 $ 0.76 $ 2.76 $ 0.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation.
(3) Calculated as the simple average of the monthly bitumen valuation
methodology price.
(4) Calculated based on actual bitumen royalties expensed during the
period; divided by the corresponding SCO sales volumes.
The increase in SCO prices from the comparative periods in 2009
was primarily due to the increase in the WTI benchmark price,
offset by the impact of the strengthening Canadian dollar. The
decrease in the SCO price for the second quarter of 2010 compared
to the prior quarter was primarily due to weakening in WTI pricing
and a widening of the SCO differential to WTI. There is an active
market for SCO throughout North America.
PRODUCTION COSTS
The following tables provide reconciliations of Oil Sands Mining
and Upgrading production costs to the Segmented Information
disclosed in note 13 to the Company's unaudited interim
consolidated financial statements.
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash costs, excluding natural
gas costs $ 262 $ 299 $ 159 $ 561 $ 159
Natural gas costs 28 47 23 75 23
----------------------------------------------------------------------------
Total cash production costs $ 290 $ 346 $ 182 $ 636 $ 182
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($/bbl)(1) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash costs, excluding natural
gas costs $ 29.09 $ 37.29 $ 37.15 $ 32.96 $ 37.15
Natural gas costs 3.18 5.83 5.50 4.43 5.50
----------------------------------------------------------------------------
Total cash production costs $ 32.27 $ 43.12 $ 42.65 $ 37.39 $ 42.65
----------------------------------------------------------------------------
Sales (bbl/d) 98,645 89,256 46,844 93,976 23,551
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
First sales from Horizon occurred in the second quarter of
2009.
Total cash production costs averaged $37.39 per bbl for the six
months ended June 30, 2010 compared to $42.65 per bbl for the six
months ended June 30, 2009. Total cash production costs averaged
$32.27 per bbl in the second quarter of 2010 compared to $42.65 per
bbl for the second quarter of 2009, and $43.12 in the prior
quarter. The decrease in cash production costs from the comparative
periods in 2009 and the prior quarter was primarily due to the
Company's focus on planned maintenance and operational
optimization, and the stabilizing of production volumes at levels
approaching plant capacity. As production volumes are targeted to
stabilize throughout 2010, cash production costs are expected to
decrease and be in line with the previously issued annual guidance
of $31.00 to $37.00 per bbl for 2010.
During the third quarter, unplanned maintenance to repair
localized pipe wall thinning in the amine unit resulted in a
plant-wide shutdown. Annual production guidance targets have been
revised to average between 90,000 and 100,000 bbl/d to reflect the
impact of this outage.
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Depreciation, depletion and
amortization $ 94 $ 90 $ 36 $ 184 $ 38
Asset retirement obligation
accretion 5 6 6 11 8
Total $ 99 $ 96 $ 42 $ 195 $ 46
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($/bbl)(1) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Depreciation, depletion and
amortization $ 10.47 $ 11.22 $ 8.51 $ 10.82 $ 9.02
Asset retirement obligation
accretion 0.62 0.69 1.47 0.65 1.96
----------------------------------------------------------------------------
Total $ 11.09 $ 11.91 $ 9.98 $ 11.47 $ 10.98
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, depreciation and amortization per barrel decreased in
the second quarter of 2010, compared to the prior quarter,
primarily due to the impact of increased production on the
component of depreciation determined on a straight-line basis.
MIDSTREAM
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue $ 21 $ 19 $ 17 $ 40 $ 36
Production expense 7 5 5 12 10
----------------------------------------------------------------------------
Midstream cash flow 14 14 12 28 26
Depreciation 2 2 2 4 4
----------------------------------------------------------------------------
Segment earnings before taxes $ 12 $ 12 $ 10 $ 24 $ 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable periods.
ADMINISTRATION EXPENSE
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expense ($ millions) $ 60 $ 54 $ 47 $ 114 $ 94
$/boe (1) $ 1.03 $ 0.99 $ 0.88 $ 1.01 $ 0.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the six and three months ended June
30, 2010 increased from the comparative periods in 2009 due to
higher staffing related costs. Administrative expense for the
second quarter of 2010, compared to the prior quarter, was impacted
by lower recoveries on a reduced capital program.
STOCK-BASED COMPENSATION EXPENSE
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
(Recovery) expense $ (58) $ (2) $ 92 $ (60) $ 96
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company recorded a $60 million ($60 million after-tax)
stock-based compensation recovery for the six months ended June 30,
2010 primarily as a result of normal course graded vesting of
options granted in prior periods, the impact of vested options
exercised or surrendered during the period, and a 7% decrease in
the Company's share price (Company's share price as at: June 30,
2010 - $35.33; March 31, 2010 - $37.59; December 31, 2009 - $38.00;
June 30, 2009 - $30.60). For the six months ended June 30, 2010,
the Company capitalized $1 million in stock-based compensation to
Oil Sands Mining and Upgrading (June 30, 2009 - $7 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 June 30,
2010.
The Company's stock option plan provides current employees with
the right to receive common shares or a direct cash payment in
exchange for options surrendered. As a result of recently proposed
changes to Canadian income tax legislation related to the cash
surrender of options, the Company anticipates that Canadian based
employees will now choose to exercise their options to receive
newly issued common shares rather than surrender their options for
cash payment.
For the six months ended June 30, 2010, the Company paid $38
million for stock options surrendered for cash settlement (June 30,
2009 - $43 million).
INTEREST EXPENSE
Three Months Ended Six Months Ended
($ millions, except Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
per boe amounts) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expense, gross $ 114 $ 118 $ 130 $ 232 $ 273
Less: capitalized interest,
Oil Sands Mining and
Upgrading 5 7 6 12 92
----------------------------------------------------------------------------
Expense, net $ 109 $ 111 $ 124 $ 220 $ 181
$/boe (1) $ 1.88 $ 2.02 $ 2.36 $ 1.95 $ 1.76
Average effective interest
rate 4.8% 4.7% 4.1% 4.8% 4.2%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest expense decreased from the comparable periods in
2009 primarily due to the impact of fluctuations in foreign
exchange rates on US dollar denominated debt and lower variable
interest rates and debt levels. The Company's average effective
interest rate increased from the comparable periods in 2009
primarily due to an increased weighting of fixed versus floating
rate debt, partially offset by lower variable interest rates.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to
manage its commodity price, currency and interest rate exposures.
These derivative financial instruments are not intended for trading
or speculative purposes.
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs financial
instruments $ 15 $ 17 $ (362) $ 32 $ (947)
Natural gas financial
instruments (78) (18) (1) (96) (33)
Foreign currency contracts
and interest rate swaps (28) 40 73 12 49
----------------------------------------------------------------------------
Realized (gain) loss $ (91)$ 39 $ (290) $ (52)$ (931)
----------------------------------------------------------------------------
Crude oil and NGLs financial
instruments $ (151)$ (73)$ 1,020 $ (224)$ 1,503
Natural gas financial
instruments 94 (130) (13) (36) (37)
Foreign currency contracts
and interest rate swaps (25) (5) (61) (30) (57)
----------------------------------------------------------------------------
Unrealized (gain) loss $ (82)$ (208)$ 946 $ (290)$ 1,409
----------------------------------------------------------------------------
Net (gain) loss $ (173)$ (169)$ 656 $ (342)$ 478
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Complete details related to outstanding derivative financial
instruments at June 30, 2010 are disclosed in note 11 to the
Company's unaudited interim consolidated financial statements.
Primarily due to changes in crude oil and natural gas forward
pricing and the reversal of prior period unrealized gains and
losses, the Company recorded a net unrealized gain of $290 million
($218 million after-tax) on its risk management activities for the
six months ended June 30, 2010, including an $82 million ($64
million after-tax) net unrealized gain for the second quarter of
2010 (March 31, 2010 - unrealized gain of $208 million, $154
million after-tax; June 30, 2009 - unrealized loss of $946 million,
$676 million after-tax).
FOREIGN EXCHANGE
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Net realized (gain) loss $ (9) $ (10) $ 74 $ (19) $ 59
Net unrealized loss (gain)(1) 165 (150) (320) 15 (182)
----------------------------------------------------------------------------
Net loss (gain) $ 156 $ (160) $ (246)$ (4) $ (123)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net unrealized foreign exchange loss for the six months
ended June 30, 2010 was primarily due to the weakening Canadian
dollar with respect to US dollar debt, and the impact of the
re-measurement of North Sea future income tax liabilities
denominated in UK pounds sterling. The net unrealized loss (gain)
for the respective periods was partially offset by cross currency
swaps (three months ended June 30, 2010 - unrealized gain of $91
million, March 31, 2010 - unrealized loss of $59 million, June 30,
2009 - unrealized loss of $186 million; six months ended June 30,
2010 - unrealized gain of $32 million, June 30, 2009 - unrealized
loss of $118 million). The net realized foreign exchange gain for
the six months ended June 30, 2010 was primarily due to foreign
exchange rate fluctuations on settlement of working capital items
denominated in US dollars or UK pounds sterling. The Canadian
dollar ended the second quarter at US$0.9429 (March 31, 2010 -
US$0.9846; December 31, 2009 - US$0.9555; June 30, 2009 -
US$0.8602).
TAXES
Three Months Ended Six Months Ended
($ millions, except Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
income tax rates) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Current $ 29 $ 32 $ 49 $ 61 $ 56
Deferred 5 7 (2) 12 (5)
----------------------------------------------------------------------------
Taxes other than
income tax $ 34 $ 39 $ 47 $ 73 $ 51
----------------------------------------------------------------------------
North America (1) $ 139 $ 129 $ 5 $ 268 $ 10
North Sea 43 53 65 96 163
Offshore West Africa 9 6 17 15 31
----------------------------------------------------------------------------
Current income tax 191 188 87 379 204
Future income tax
expense (recovery) 71 195 (201) 266 (257)
----------------------------------------------------------------------------
262 383 (114) 645 (53)
Income tax rate and
other legislative
changes (2) - (83) - (83) 19
----------------------------------------------------------------------------
$ 262 $ 300 $ (114) $ 562 $ (34)
----------------------------------------------------------------------------
Effective income tax
rate on adjusted
net earnings from
operations 27.9% 26.0% 16.8% 27.0% 21.5%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Conventional Crude Oil and Natural Gas,
Midstream, and Oil Sands Mining and Upgrading segments.
(2) During the first quarter of 2010, the Canadian Federal budget proposed
changes to the taxation of stock options surrendered by employees for
cash payments. As a result of the proposed changes, the Company
anticipates that Canadian based employees will no longer surrender
their options for cash payments, resulting in a loss of income tax
deductions for the Company. The impact of this change was an $83
million charge to future income tax expense during the first quarter.
Income tax rate changes in the first quarter of 2009 include the effect
of a recovery of $19 million due to British Columbia corporate income
tax rate reductions substantively enacted or enacted.
Taxes other than income tax primarily includes current and
deferred Petroleum Revenue Tax ("PRT"), which is charged on certain
fields in the North Sea at the rate of 50% of net operating income,
after allowing for certain deductions including related capital and
abandonment expenditures.
Taxable income from the conventional crude oil and natural gas
business in Canada is primarily generated through partnerships,
with the related income taxes payable in subsequent periods. North
America current income taxes have been provided on the basis of
this corporate structure. In addition, current income taxes in each
business segment will vary depending on available income tax
deductions related to the nature, timing and amount of capital
expenditures incurred in any particular year.
The Company is subject to income tax reassessments arising in
the normal course. The Company does not believe that any
liabilities ultimately arising from these reassessments will be
material.
For 2010, based on budgeted prices and the current availability
of tax pools, the Company expects to incur current income tax
expense in Canada of $525 million to $575 million and in the North
Sea and Offshore West Africa of $210 million to $250 million.
NET CAPITAL EXPENDITURES (1)
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expenditures on
property, plant and
equipment
Net property
acquisitions
(dispositions) $ 949 $ 36 $ (2) $ 985 $ 25
Land acquisition and
retention 37 38 18 75 31
Seismic evaluations 19 33 11 52 39
Well drilling,
completion and
equipping 249 442 194 691 692
Production and
related facilities 176 382 230 558 520
----------------------------------------------------------------------------
Total net reserve
replacement
expenditures 1,430 931 451 2,361 1,307
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading:
Horizon Phase 1
construction costs - - (59) - 69
Horizon Phase 1
commissioning and
other costs - - 46 - 202
Horizon Phases 2/3
construction costs 56 71 22 127 41
Capitalized
interest,
stock-based
compensation and
other 39 9 (4) 48 75
Sustaining capital 27 18 4 45 4
----------------------------------------------------------------------------
Total Oil Sands
Mining and
Upgrading (2) 122 98 9 220 391
----------------------------------------------------------------------------
Midstream 1 - - 1 5
Abandonments (3) 15 39 10 54 19
Head office 5 4 3 9 7
----------------------------------------------------------------------------
Total net capital
expenditures $ 1,573 $ 1,072 $ 473 $ 2,645 $ 1,729
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 1,350 $ 809 $ 270 $ 2,159 $ 869
North Sea 29 23 40 52 82
Offshore West Africa 50 99 141 149 356
Other 1 - - 1 -
Oil Sands Mining and
Upgrading 122 98 9 220 391
Midstream 1 - - 1 5
Abandonments (3) 15 39 10 54 19
Head office 5 4 3 9 7
----------------------------------------------------------------------------
Total $ 1,573 $ 1,072 $ 473 $ 2,645 $ 1,729
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 six months ended June 30, 2010
were $2,645 million compared to $1,729 million for the six months
ended June 30, 2009. Net capital expenditures for the second
quarter of 2010 were $1,573 million compared to $473 million for
the second quarter of 2009 and $1,072 million in the prior quarter.
The increase in capital expenditures reflects the purchase of crude
oil and natural gas producing properties and undeveloped land in
the Company's core regions in Western Canada.
Drilling Activity (number of wells)
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Net successful natural
gas wells 10 45 - 55 64
Net successful crude
oil wells 92 243 94 335 187
Dry wells 2 14 4 16 19
Stratigraphic test /
service wells 9 297 7 306 243
----------------------------------------------------------------------------
Total 113 599 105 712 513
Success rate
(excluding
stratigraphic test /
service wells) 98% 95% 96% 96% 93%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America
North America, excluding Oil Sands Mining and Upgrading,
accounted for approximately 84% of the total capital expenditures
for the six months ended June 30, 2010 compared to approximately
52% for the six months ended June 30, 2009.
During the second quarter of 2010, the Company targeted 11 net
natural gas wells, including 7 wells in Northeast British Columbia,
3 wells in Northwest Alberta and 1 well in the Southern Plains
region. The Company also targeted 91 net crude oil wells. The
majority of these wells were concentrated in the Company's crude
oil Northern Plains region where 38 heavy crude oil wells, 44
Pelican Lake crude oil wells, and 6 thermal crude oil wells were
drilled. Another 3 wells targeting light crude oil were drilled
outside the Northern Plains region.
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 second quarter of 2010
averaged approximately 96,000 bbl/d, compared to approximately
63,000 bbl/d for the second quarter of 2009 and approximately
76,000 bbl/d for the prior quarter. The Primrose East expansion was
completed and first steaming commenced in September 2008, with
first production achieved in the first quarter of 2009. During the
first quarter of 2009, operational issues on one of the pads caused
steaming to cease on all well pads in the Primrose East project
area. The Company is continuing to work with regulators to commence
normal steaming.
The next planned phase of the Company's In Situ Oil Sands Assets
expansion is the Kirby Project. Final project scope and corporate
sanction is targeted for late 2010. Currently the Company is
proceeding with the detailed engineering and design work.
Development of new pads and tertiary recovery conversion
projects at Pelican Lake continued as expected throughout the
second quarter of 2010. Drilling included 44 horizontal wells in
the second quarter. The response from the water and polymer flood
projects continues to be positive. Pelican Lake production averaged
approximately 37,000 bbl/d for the second and first quarter of
2010, compared to approximately 36,000 bbl/d for the second quarter
of 2009.
For the third quarter of 2010, the Company's overall planned
drilling activity in North America is expected to be comprised of
25 natural gas wells and 330 crude oil wells, excluding
stratigraphic and service wells.
Oil Sands Mining and Upgrading
Limited Phase 2/3 spending during the second quarter continued
to be focused on the construction of the third Ore Preparation
Plant, completion of the Mine Maintenance Shop and additional
product tankage.
North Sea
In the second quarter of 2010, the Company continued drilling on
the Ninian South Platform, with an injection well in progress at
quarter end. The Company continues to focus on developing and high
grading its inventory of drilling locations for future
execution.
Offshore West Africa
During the second quarter of 2010, final commissioning of
Platform B at the Olowi Field was completed and first crude oil
production was achieved as planned in April. Drilling continued
with 1.9 net crude oil wells completed during the quarter. By the
end of the second quarter a total of 3.7 net wells were on
production from Platform B. The Company is targeting to commission
and have onstream a further 1.9 net wells in the third quarter and
begin drilling operations on Platform A.
At Espoir the facilities upgrades were completed during the
second quarter. The associated production uplift from the upgrades
is anticipated in the third quarter of 2010.
LIQUIDITY AND CAPITAL RESOURCES
($ millions, except Jun 30 Mar 31 Dec 31 Jun 30
ratios) 2010 2010 2009 2009
----------------------------------------------------------------------------
Working capital (deficit)
(1) $ (245) $ (534) $ (514) $ (113)
Long-term debt (2) $ 9,335 $ 8,939 $ 9,658 $ 11,987
Share capital $ 3,006 $ 2,939 $ 2,834 $ 2,816
Retained earnings 18,066 17,481 16,696 15,697
Accumulated other
comprehensive (loss)
income (13) (152) (104) 75
----------------------------------------------------------------------------
Shareholders' equity $ 21,059 $ 20,268 $ 19,426 $ 18,588
Debt to book
capitalization (2) (3) 31% 31% 33% 39%
Debt to market
capitalization (2) (4) 20% 18% 19% 27%
After tax return on
average common
shareholders' equity (5) 13% 11% 8% 30%
After tax return on
average capital
employed (2) (6) 10% 8% 6% 18%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated as current assets less current liabilities, excluding the
current portion of long-term debt.
(2) Long-term debt is stated at its carrying value, net of fair value
adjustments, original issue discounts and transaction costs.
(3) Calculated as current and long-term debt; divided by the book value of
common shareholders' equity plus current and long-term debt.
(4) Calculated as current and long-term debt; divided by the market value
of common shareholders' equity plus current and long-term debt.
(5) Calculated as net earnings for the twelve month trailing period; as a
percentage of average common shareholders' equity for the period.
(6) Calculated as net earnings plus after-tax interest expense for the
twelve month trailing period; as a percentage of average capital
employed for the period.
At June 30, 2010, the Company's capital resources consist
primarily of cash flow from operations, available bank credit
facilities and access to debt capital markets. Cash flow from
operations is dependent on factors discussed in the "Risks and
Uncertainties" section of the Company's December 31, 2009 annual
MD&A. The Company's ability to renew existing bank credit
facilities and raise new debt is also dependent upon these factors,
as well as maintaining an investment grade debt rating and the
condition of capital and credit markets. The Company continues to
believe that its internally generated cash flow from operations
supported by the implementation of its on-going hedge policy, the
flexibility of its capital expenditure programs supported by its
multi-year financial plans, its existing bank credit facilities,
and its ability to raise new debt on commercially acceptable terms,
will provide sufficient liquidity to sustain its operations in the
short, medium and long term and support its growth strategy.
At June 30, 2010, the Company had $2,470 million of available
credit under its bank credit facilities. The Company's current debt
ratings are BBB (high) with a stable trend by DBRS Limited, Baa2
with a stable outlook by Moody's Investors Service, Inc., and BBB
with a positive outlook by Standard & Poor's Corporation.
Further details related to the Company's long-term debt at June
30, 2010 are discussed in note 4 to the Company's unaudited interim
consolidated financial statements.
Long-term debt was $9,335 million at June 30, 2010, resulting in
a debt to book capitalization ratio of 31% (March 31, 2010 - 31%;
December 31, 2009 - 33%; June 30, 2009 - 39%). This ratio is below
the 35% to 45% internal range utilized by management. This range
may be exceeded in periods when a combination of capital projects,
acquisitions, and lower commodity prices occur. The Company may be
below the low end of the targeted range when cash flow from
operating activities is greater than current investment activities.
The Company remains committed to maintaining a strong balance sheet
and flexible capital structure. The Company has hedged a portion of
its crude oil and natural gas production for 2010 at prices that
protect investment returns to ensure ongoing balance sheet strength
and the completion of its capital expenditure programs.
The Company's commodity hedging program reduces the risk of
volatility in commodity prices and supports the Company's cash flow
for its capital expenditures programs. This program currently
allows for the hedging of up to 60% of the near 12 months budgeted
production and up to 40% of the following 13 to 24 months estimated
production. For the purpose of this program, the purchase of put
options is in addition to the above parameters. As at June 30,
2010, in accordance with the policy, approximately 34% of budgeted
crude oil volumes and approximately 34% of budgeted natural gas
volumes were hedged using collars for the remainder of 2010.
Further details related to the Company's commodity related
derivative financial instruments outstanding at June 30, 2010 are
discussed in note 11 to the Company's unaudited interim
consolidated financial statements.
Share capital and share split
The Company's shareholders passed a Special Resolution
subdividing the common shares of the Company on a two-for-one basis
at the Company's Annual and Special Meeting held on May 6, 2010
with such subdivision taking effect on May 21, 2010. All common
share, per common share, and stock option amounts have been
restated to reflect the share split.
As at June 30, 2010, there were 1,089,238,000 common shares
outstanding and 57,754,000 stock options outstanding. As at August
4, 2010, the Company had 1,089,373,000 common shares outstanding
and 57,287,000 stock options outstanding.
On March 3, 2010, the Company's Board of Directors approved an
increase in the annual dividend paid by the Company to $0.30 per
common share for 2010. The increase represented a 43% increase from
2009, recognizes the stability of the Company's cash flow, and
provides a return to Shareholders. The dividend policy undergoes a
periodic review by the Board of Directors and is subject to
change.
In 2010, the Company announced a Normal Course Issuer Bid to
purchase, through the facilities of the Toronto Stock Exchange
("TSX") and the New York Stock Exchange ("NYSE"), during the 12
month period commencing April 6, 2010 and ending April 5, 2011, up
to 27,163,940 common shares or 2.5% of the common shares of the
Company outstanding at March 17, 2010. As at August 4, 2010, no
common shares had been purchased for cancellation.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. As at June 30, 2010, no entities were
consolidated under the Canadian Institute of Chartered Accountants
Handbook Accounting Guideline 15, "Consolidation of Variable
Interest Entities". The following table summarizes the Company's
commitments as at June 30, 2010:
Remaining
($ millions) 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Product
transportation
and pipeline $ 121 $ 207 $ 176 $ 150 $ 149 $ 1,088
Offshore
equipment
operating
leases $ 90 $ 127 $ 104 $ 103 $ 102 $ 265
Offshore
drilling $ 34 $ - $ - $ - $ - $ -
Asset
retirement
obligations (1) $ 8 $ 20 $ 21 $ 31 $ 39 $ 6,626
Long-term debt
(2) $ 400 $ 424 $ 371 $ 824 $ 371 $ 5,492
Interest
expense (3) $ 239 $ 456 $ 420 $ 374 $ 354 $ 4,844
Office leases $ 12 $ 20 $ 3 $ 3 $ 3 $ 4
Other $ 145 $ 66 $ 24 $ 14 $ 12 $ 36
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts represent management's estimate of the future undiscounted
payments to settle asset retirement obligations related to resource
properties, facilities, and production platforms, based on current
legislation and industry operating practices. Amounts disclosed for the
period 2010 - 2014 represent the estimated minimum expenditures
required to meet these obligations. Actual expenditures in any
particular year may exceed these minimum amounts.
(2) The long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or transaction
costs. No debt repayments are reflected for $1,472 million of revolving
bank credit facilities due to the extendable nature of the facilities.
(3) Interest expense amounts represent the scheduled fixed rate and
variable rate cash payments related to long-term debt. Interest on
variable rate long-term debt was estimated based upon prevailing
interest rates and foreign exchange rates as at June 30, 2010.
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is defendant and plaintiff in a number of legal
actions. In addition, the Company is subject to certain contractor
construction claims. The Company believes that any liabilities that
might arise pertaining to any such matters would not have a
material effect on its consolidated financial position.
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING
POLICIES
The preparation of financial statements requires the Company to
make judgments, assumptions and estimates in the application of
generally accepted accounting principles that have a significant
impact on the financial results of the Company. Actual results
could differ from those estimates. A comprehensive discussion of
the Company's significant accounting policies is contained in the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2009.
For the impact of new accounting standards, refer to note 2 of
the unaudited interim consolidated financial statements as at June
30, 2010.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
In February 2008, the CICA's Accounting Standards Board
confirmed that Canadian publicly accountable enterprises will be
required to adopt International Financial Reporting Standards
("IFRS") as promulgated by the International Accounting Standards
Board ("IASB") in place of Canadian GAAP effective January 1,
2011.
The Company has established a formal IFRS project governance
structure. The structure includes a Steering Committee, which
consists of senior levels of management from finance and
accounting, operations and information technology ("IT"). The
Steering Committee provides regular updates to the Company's
Management and the Audit Committee of the Board of Directors.
The Company's IFRS conversion project has been broken down into
the following phases:
- Phase 1 Diagnostic - identification of potential accounting
and reporting differences between Canadian GAAP and IFRS.
- Phase 2 Planning - establishment of project governance,
processes, resources, budget and timeline.
- Phase 3 Policy Delivery and Documentation - establishment of
accounting policies under IFRS.
- Phase 4 Policy Implementation - establishment of processes for
accounting and reporting, IT change requirements, and
education.
- Phase 5 Sustainment - ongoing compliance with IFRS after
implementation.
The Company has completed the Diagnostic and Planning phases
(Phases 1 and 2). Significant differences were identified in
accounting for Property, Plant & Equipment ("PP&E"),
including exploration costs, depletion and depreciation,
capitalized interest, impairment testing, and asset retirement
obligations. Other significant differences were noted in accounting
for stock-based compensation, risk management activities, and
income taxes. The Company is finalizing the necessary research to
develop and document IFRS policies to address the major differences
noted (Phase 3). A summary of the significant differences
identified is included below. At this time, the impact on the
Company's future financial position and results of operations is
not reasonably determinable. In addition, certain IFRS standards
are expected to change prior to adoption in 2011, and the impact of
these potential changes is not known.
The Company has identified, developed and tested system
processes and changes required to capture data required for IFRS
accounting and reporting (Phase 4), including 2010 requirements to
capture both Canadian GAAP and IFRS data. IT system changes are
substantially complete and implemented as at June 30, 2010.
Summary of Identified IFRS Accounting Policy Differences
Property, Plant & Equipment
Adoption of IFRS will significantly impact the Company's
accounting policies for PP&E. For Canadian GAAP purposes, the
Company follows the full cost method of accounting for its
conventional crude oil and natural gas properties and equipment as
prescribed by Accounting Guideline 16 ("AcG16"). Application of the
full cost method of accounting is discussed in the "Critical
Accounting Estimates" section of the 2009 annual MD&A.
Significant differences in accounting for PP&E under IFRS
include:
- Pre-exploration costs must be expensed. Under full cost
accounting, these costs are currently included in the country cost
centre.
- Exploration and evaluation costs will be initially capitalized
as exploration and evaluation assets. Once technical feasibility
and commercial viability of reserves is established for an area,
the costs will be transferred to PP&E. If technically feasible
and commercially viable reserves are not established for a new
area, the costs must be expensed. Under full cost accounting,
exploration and evaluation costs are currently disclosed as
PP&E but withheld from depletion. Costs are transferred to the
depletable assets when proved reserves are assigned or when it is
determined that the costs are impaired.
- PP&E for producing properties will be depreciated at an
asset level. Under full cost accounting, PP&E is depleted on a
country cost centre basis.
- Interest directly attributable to the acquisition or
construction of a qualifying asset must be capitalized to the cost
of the asset. Under Canadian GAAP, capitalization of interest is
not required.
- Impairment of PP&E will be tested at a cash generating
unit level (the lowest level at which cash inflows can be
separately identified). Under full cost accounting, impairment is
tested at the country cost centre level.
IFRS 1 "First-time Adoption of International Financial Reporting
Standards" issued by the IASB includes a transition exemption for
oil and gas companies following full cost accounting under their
previous GAAP. The transition exemption allows full cost companies
to allocate their existing full cost PP&E balances using
reserve values or volumes to IFRS compliant units of account
without requiring retroactive adjustment, subject to an initial
impairment test. The Company intends to adopt this transition
exemption. After initial adoption, future impairment charges may be
reversed.
Asset Retirement Obligations
Canadian GAAP accounting requirements for asset retirement
obligations ("ARO") are discussed in the "Critical Accounting
Estimates" section of the 2009 annual MD&A. A significant
difference in accounting for ARO under IFRS is that the liability
must be re-measured at each balance sheet date using the current
discount rates, whereas under Canadian GAAP the discount rates do
not change once the liability is recorded. On transition to IFRS,
the change in ARO liability on PP&E for which the full cost
exemption above is applied must be recorded in retained earnings.
For the change in ARO liability on other non-full cost PP&E,
the change will be adjusted to PP&E in accordance with the
general exemption for decommissioning liabilities included in IFRS
1. In future periods, the impact of changes in discount rates on
the ARO liability for all PP&E is adjusted to PP&E.
Stock-based Compensation
Under Canadian GAAP, the Company's stock option plan liability
is valued using the intrinsic value method, calculated as the
amount by which the market price of the Company's shares exceeds
the exercise price of the option for vested options. Under IFRS,
the stock option plan liability must be measured using a fair value
option pricing model such as the Black-Scholes model. The Company
intends to utilize the exemption in IFRS 1 under which options that
were settled prior to January 1, 2010 will not have to be
retrospectively restated. On transition to IFRS, the change in
stock-based compensation liability must be recorded in retained
earnings.
Petroleum Revenue Tax
Under Canadian GAAP, the liability for the UK PRT is estimated
using proved and probable reserves and future prices and costs, and
apportioned to accounting periods over the life of the field on the
basis of total estimated future operating income. Under IFRS, the
PRT liability will be estimated using the balance sheet method in
accordance with IAS 12 Income Taxes, where the liability is based
on temporary differences in balance sheet assets and liabilities
versus their tax basis. On transition to IFRS, the change in PRT
liability must be recorded in retained earnings.
Income Taxes
Both Canadian GAAP and IFRS follow the liability method of
accounting for income taxes, where tax liabilities and assets are
recognized on temporary differences. However, there are certain
exceptions to the treatment of temporary differences under IFRS
that may result in an adjustment to the Company's future tax
liability under IFRS. In addition, the Company's future tax
liability will be impacted by the tax effects of any changes noted
in the above areas. On transition to IFRS, the change in future
income tax liability must be recorded in retained earnings.
Other IFRS 1 Exemptions
The Company also intends to adopt the following IFRS 1
transition exemptions:
- The Company intends to elect to reset the foreign currency
translation adjustment to zero by transferring the Canadian GAAP
balance to retained earnings on January 1, 2010, rather than
retrospectively restating the balance.
- The Company intends to adopt the IFRS 1 election to not
restate business combinations entered into prior to January 1,
2010.
SENSITIVITY ANALYSIS
The following table is indicative of the annualized
sensitivities of cash flow from operations and net earnings from
changes in certain key variables. The analysis is based on business
conditions and sales volumes during the second quarter of 2010,
excluding mark-to-market gains (losses) on risk management
activities, and is not necessarily indicative of future results.
Each separate line item in the sensitivity analysis shows the
effect of a change in that variable only with all other variables
being held constant.
Cash flow
from Net
operations earnings
Cash flow (per (per
from common Net common
operations share, earnings share,
($ millions) basic) ($ millions) basic)
----------------------------------------------------------------------------
Price changes
Crude oil - WTI
US$1.00/bbl (1)
Excluding
financial
derivatives $ 137 $ 0.13 $ 105 $ 0.10
Including
financial
derivatives $ 128 $ 0.12 $ 98 $ 0.09
Natural gas -
AECO C$0.10/mcf
(1)
Excluding
financial
derivatives $ 31 $ 0.03 $ 23 $ 0.02
Including
financial
derivatives $ 26 $ 0.02 $ 19 $ 0.02
Volume changes
Crude oil -
10,000 bbl/d $ 171 $ 0.16 $ 98 $ 0.09
Natural gas -
10 mmcf/d $ 9 $ 0.01 $ 1 $ -
Foreign
currency rate
change
$0.01 change in
US$ (1)
Including
financial
derivatives $ 105 - 107 $ 0.10 $ 37 - 38 $0.03 - 0.04
Interest rate
change - 1% $ 10 $ 0.01 $ 10 $ 0.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) For details of outstanding financial instruments in place, refer to
note 11 of the Company's unaudited interim consolidated financial
statements.
FINANCIAL STATEMENTS
Consolidated Balance Sheets
Jun 30 Dec 31
(millions of Canadian dollars, unaudited) 2010 2009
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 19 $ 13
Accounts receivable 1,363 1,148
Inventory, prepaids and other 610 584
Future income tax - 146
Current portion of other long-term assets
(note 3) 108 -
----------------------------------------------------------------------------
2,100 1,891
Property, plant and equipment (note 13) 40,107 39,115
Other long-term assets (note 3) 48 18
----------------------------------------------------------------------------
$ 42,255 $ 41,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 295 $ 240
Accrued liabilities 1,842 1,522
Future income tax 22 -
Current portion of other long-term
liabilities (note 5) 186 643
----------------------------------------------------------------------------
2,345 2,405
Long-term debt (note 4) 9,335 9,658
Other long-term liabilities (note 5) 1,753 1,848
Future income tax 7,763 7,687
----------------------------------------------------------------------------
21,196 21,598
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 7) 3,006 2,834
Retained earnings 18,066 16,696
Accumulated other comprehensive loss (note 8) (13) (104)
----------------------------------------------------------------------------
21,059 19,426
----------------------------------------------------------------------------
$ 42,255 $ 41,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (note 12)
Consolidated Statements of Earnings
(millions of Canadian
dollars, except per Three Months Ended Six Months Ended
common share amounts, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue $ 3,614 $ 2,750 $ 7,194 $ 4,936
Less: royalties (324) (212) (677) (411)
----------------------------------------------------------------------------
Revenue, net of royalties 3,290 2,538 6,517 4,525
----------------------------------------------------------------------------
Expenses
Production 812 773 1,706 1,355
Transportation and
blending 559 309 973 626
Depletion, depreciation
and amortization 836 664 1,607 1,310
Asset retirement
obligation accretion
(note 5) 26 24 52 43
Administration 60 47 114 94
Stock-based compensation
(recovery) expense
(note 5) (58) 92 (60) 96
Interest, net 109 124 220 181
Risk management
activities (note 11) (173) 656 (342) 478
Foreign exchange loss
(gain) 156 (246) (4) (123)
----------------------------------------------------------------------------
2,327 2,443 4,266 4,060
----------------------------------------------------------------------------
Earnings before taxes 963 95 2,251 465
Taxes other than income
tax 34 47 73 51
Current income tax
expense (note 6) 191 87 379 204
Future income tax expense
(recovery) (note 6) 71 (201) 266 (257)
----------------------------------------------------------------------------
Net earnings $ 667 $ 162 $ 1,533 $ 467
----------------------------------------------------------------------------
Net earnings per common
share (note 10)
Basic and diluted $ 0.61 $ 0.15 $ 1.41 $ 0.43
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Shareholders' Equity
Six Months Ended
Jun 30 Jun 30
(millions of Canadian dollars, unaudited) 2010 2009
----------------------------------------------------------------------------
Share capital (note 7)
Balance - beginning of period $ 2,834 $ 2,768
Issued upon exercise of stock options 74 18
Previously recognized liability on stock options
exercised for common shares 98 30
----------------------------------------------------------------------------
Balance - end of period 3,006 2,816
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period 16,696 15,344
Net earnings 1,533 467
Dividends on common shares (note 7) (163) (114)
----------------------------------------------------------------------------
Balance - end of period 18,066 15,697
----------------------------------------------------------------------------
Accumulated other comprehensive (loss) income
(note 8)
Balance - beginning of period (104) 262
Other comprehensive income (loss), net of taxes 91 (187)
----------------------------------------------------------------------------
Balance - end of period (13) 75
----------------------------------------------------------------------------
Shareholders' equity $ 21,059 $ 18,588
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income (Loss)
Three Months Ended Six Months Ended
(millions of Canadian Jun 30 Jun 30 Jun 30 Jun 30
dollars, unaudited) 2010 2009 2010 2009
----------------------------------------------------------------------------
Net earnings $ 667 $ 162 $ 1,533 $ 467
----------------------------------------------------------------------------
Net change in derivative
financial instruments
designated as cash flow
hedges
Unrealized gain (loss)
during the period, net of
taxes of
$13 million (2009 - $2
million) - three months
ended;
$12 million (2009 - $4
million) - six months
ended 89 (13) 84 (30)
Reclassification to net
earnings, net of taxes of
$1 million (2009 - $nil) -
three months ended;
$1 million (2009 - $1
million) - six months
ended (3) (5) (3) (8)
----------------------------------------------------------------------------
86 (18) 81 (38)
Foreign currency translation
adjustment
Translation of net
investment 53 (222) 10 (149)
----------------------------------------------------------------------------
Other comprehensive income
(loss), net of taxes 139 (240) 91 (187)
----------------------------------------------------------------------------
Comprehensive income (loss) $ 806 $ (78) $ 1,624 $ 280
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months Ended Six Months Ended
(millions of Canadian Jun 30 Jun 30 Jun 30 Jun 30
dollars, unaudited) 2010 2009 2010 2009
----------------------------------------------------------------------------
Operating activities
Net earnings $ 667 $ 162 $ 1,533 $ 467
Non-cash items
Depletion, depreciation
and amortization 836 664 1,607 1,310
Asset retirement
obligation accretion 26 24 52 43
Stock-based compensation
(recovery) expense (58) 92 (60) 96
Unrealized risk
management (gain) loss (82) 946 (290) 1,409
Unrealized foreign
exchange loss (gain) 165 (320) 15 (182)
Deferred petroleum
revenue tax expense
(recovery) 5 (2) 12 (5)
Future income tax
expense (recovery) 71 (201) 266 (257)
Other 10 7 (16) (6)
Abandonment expenditures (15) (10) (54) (19)
Net change in non-cash
working capital 174 (110) 95 (113)
----------------------------------------------------------------------------
1,799 1,252 3,160 2,743
----------------------------------------------------------------------------
Financing activities
Issue (repayment) of bank
credit facilities, net 85 (398) (443) (506)
Repayment of senior
unsecured notes - (34) - (34)
Issue of common shares
on exercise of stock
options 34 2 74 18
Dividends on common
shares (81) (57) (138) (111)
Net change in non-cash
working capital 38 32 1 (4)
----------------------------------------------------------------------------
76 (455) (506) (637)
----------------------------------------------------------------------------
Investing activities
Expenditures on
property, plant, and
equipment (1,561) (470) (2,594) (1,717)
Net proceeds on sale of
property, plant and
equipment 3 7 3 7
----------------------------------------------------------------------------
Net expenditures on
property, plant and
equipment (1,558) (463) (2,591) (1,710)
Net change in non-cash
working capital (319) (319) (57) (398)
----------------------------------------------------------------------------
(1,877) (782) (2,648) (2,108)
----------------------------------------------------------------------------
(Decrease) increase in
cash and cash equivalents (2) 15 6 (2)
Cash and cash equivalents -
beginning of period 21 10 13 27
----------------------------------------------------------------------------
Cash and cash
equivalents - end of
period $ 19 $ 25 $ 19 $ 25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 80 $ 92 $ 232 $ 276
Taxes paid (recovered)
Taxes other than income
tax $ - $ 25 $ (6) $ -
Current income tax $ (40) $ (2) $ 12 $ 41
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes to the consolidated financial statements
(tabular amounts in millions of Canadian dollars, unless
otherwise stated, unaudited)
1. ACCOUNTING POLICIES
The interim consolidated financial statements of Canadian
Natural Resources Limited (the "Company") include the Company and
all of its subsidiaries and partnerships, and have been prepared
following the same accounting policies as the audited consolidated
financial statements of the Company as at December 31, 2009. The
interim consolidated financial statements contain disclosures that
are supplemental to the Company's annual audited consolidated
financial statements. Certain disclosures that are normally
required to be included in the notes to the annual audited
consolidated financial statements have been condensed. These
interim financial statements should be read in conjunction with the
Company's audited consolidated financial statements and notes
thereto for the year ended December 31, 2009.
Comparative Figures
Certain prior period figures have been reclassified to conform
to the presentation adopted in 2010.
Common share, per common share, and stock option data has been
restated to reflect the two-for-one share split in May 2010.
2. CHANGES IN ACCOUNTING POLICIES
International Financial Reporting Standards
In February 2008, the Canadian Institute of Chartered
Accountants' Accounting Standards Board confirmed that Canadian
publicly accountable entities will be required to adopt
International Financial Reporting Standards ("IFRS") as promulgated
by the International Accounting Standards Board in place of
generally accepted accounting principles in Canada ("GAAP")
effective January 1, 2011. The Company has assessed those
accounting policies that will be affected by the change to IFRS and
continues to assess the potential impact of these changes on its
financial position and results of operations.
Recently issued accounting standards under Canadian GAAP
The following standards will be effective for the Company's year
beginning on January 1, 2011:
Business Combinations, Consolidated Financial Statements and
Non-Controlling Interests
Section 1582 - "Business Combinations", 1601 - "Consolidated
Financial Statements", and 1602 - "Non-Controlling Interests"
replace Section 1581 - "Business Combinations", and 1600 -
"Consolidated Financial Statements". The new standards are the
Canadian equivalent of IFRS 3 "Business Combinations" and IAS 27
"Consolidated and Separate Financial Statements". Section 1582 is
effective for business combinations for acquisition dates on or
after January 1, 2011. Earlier adoption is permitted, provided all
three new standards are adopted simultaneously. Section 1582
requires equity instruments issued as part of the purchase
consideration to be measured at fair value at the acquisition date,
rather than the date when the acquisition was agreed to and
announced. In addition, most acquisition costs are expensed as
incurred, instead of being included in the purchase consideration.
The new standard also requires non-controlling interests to be
measured at fair value instead of carrying amounts. Section 1602
provides guidance on the treatment of non-controlling interests
after acquisition. Section 1601 carries forward existing guidance
on the preparation of consolidated financial statements, other than
non-controlling interests.
3. OTHER LONG-TERM ASSETS
Jun 30 Dec 31
2010 2009
----------------------------------------------------------------------------
Risk management (note 11) $ 122 $ -
Other 34 18
----------------------------------------------------------------------------
156 18
Less: current portion 108 -
----------------------------------------------------------------------------
$ 48 $ 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. LONG-TERM DEBT
Jun 30 Dec 31
2010 2009
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities (bankers' acceptances) $ 1,154 $ 1,897
Medium-term notes 1,200 1,200
----------------------------------------------------------------------------
2,354 3,097
----------------------------------------------------------------------------
US dollar denominated debt
US dollar bank credit facilities (bankers'
acceptances) (2010 - US$300 million; 2009
- US$nil) 318 -
US dollar debt securities (2010 and 2009 - US$6,300
million) 6,682 6,594
Less: original issue discount on US dollar debt
securities (1) (21) (22)
----------------------------------------------------------------------------
6,979 6,572
Fair value of interest rate swaps on US dollar debt
securities (2) 49 38
----------------------------------------------------------------------------
7,028 6,610
----------------------------------------------------------------------------
Long-term debt before transaction costs 9,382 9,707
Less: transaction costs (1) (3) (47) (49)
----------------------------------------------------------------------------
$ 9,335 $ 9,658
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has included unamortized original issue discounts and
directly attributable transaction costs in the carrying value of the
outstanding debt.
(2) The carrying values of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $49 million (2009 - $38 million) to reflect the fair value impact of
hedge accounting.
(3) Transaction costs primarily represent underwriting commissions charged
as a percentage of the related debt offerings, as well as legal, rating
agency and other professional fees.
Bank credit facilities
As at June 30, 2010, the Company had in place unsecured bank
credit facilities of $3,954 million, comprised of:
- a $200 million demand credit facility;
- a revolving syndicated credit facility of $2,230 million
maturing June 2012;
- a revolving syndicated credit facility of $1,500 million
maturing June 2012; and
- a Pounds Sterling 15 million demand credit facility related to
the Company's North Sea operations.
The revolving syndicated credit facilities are extendible
annually for one year periods at the mutual agreement of the
Company and the lenders. If the facilities are not extended, the
full amount of the outstanding principal would be repayable on the
maturity date. Borrowings under these facilities can be made by way
of Canadian dollar and US dollar bankers' acceptances, and LIBOR,
US base rate and Canadian prime loans.
The Company's weighted average interest rate on bank credit
facilities outstanding as at June 30, 2010 was 1.1% (December 31,
2009 - 0.8%), and on total long-term debt outstanding for the three
months ended June 30, 2010 was 4.8% (December 31, 2009 - 4.5%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $378 million, including $300
million related to Horizon, were outstanding at June 30, 2010.
Medium-term notes
The Company filed a $3,000 million base shelf prospectus in
October 2009 that allows for the issue of medium-term notes in
Canada until November 2011. If issued, these securities will bear
interest as determined at the date of issuance.
US dollar debt securities
The Company filed a US$3,000 million base shelf prospectus in
October 2009 that allows for the issue of US dollar debt securities
in the United States until November 2011. If issued, these
securities will bear interest as determined at the date of
issuance.
5. OTHER LONG-TERM LIABILITIES
Jun 30 Dec 31
2010 2009
----------------------------------------------------------------------------
Asset retirement obligations $ 1,631 $ 1,610
Stock-based compensation 197 392
Risk management (note 11) - 309
Other 111 180
----------------------------------------------------------------------------
1,939 2,491
Less: current portion 186 643
----------------------------------------------------------------------------
$ 1,753 $ 1,848
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset retirement obligations
At June 30, 2010, the Company's total estimated undiscounted
costs to settle its asset retirement obligations were approximately
$6,745 million (December 31, 2009 - $6,606 million). These costs
will be incurred over the lives of the operating assets and have
been discounted using a weighted average credit-adjusted risk-free
rate of 6.8% (December 31, 2009 - 6.9%). A reconciliation of the
discounted asset retirement obligations is as follows:
Six Months Year
Ended Ended
Jun 30, 2010 Dec 31, 2009
----------------------------------------------------------------------------
Balance - beginning of period $ 1,610 $ 1,064
Liabilities incurred (1) 6 299
Liabilities acquired 8 -
Liabilities settled (54) (48)
Asset retirement obligation accretion 52 90
Revision of estimates - 276
Foreign exchange 9 (71)
----------------------------------------------------------------------------
Balance - end of period $ 1,631 $ 1,610
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) During 2009, the Company recognized additional asset retirement
obligations related to Oil Sands Mining and Upgrading and Gabon,
Offshore West Africa.
Stock-based compensation
The Company recognizes a liability for the potential cash
settlements under its Stock Option Plan. The current portion
represents the maximum amount of the liability payable within the
next twelve-month period if all vested options are surrendered for
cash settlement.
Six Months Year
Ended Ended
Jun 30, 2010 Dec 31, 2009
----------------------------------------------------------------------------
Balance - beginning of period $ 392 $ 171
Stock-based compensation (recovery) expense (60) 355
Cash payments for options surrendered (38) (94)
Transferred to common shares (98) (42)
Capitalized to Oil Sands Mining and
Upgrading 1 2
----------------------------------------------------------------------------
Balance - end of period 197 392
Less: current portion 161 365
----------------------------------------------------------------------------
$ 36 $ 27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Six Months Ended
Jun 30 Jun 30 Jun 30 Jun 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Current income tax - North
America(1) $ 139 $ 5 $ 268 $ 10
Current income tax - North Sea 43 65 96 163
Current income tax - Offshore West
Africa 9 17 15 31
----------------------------------------------------------------------------
Current income tax expense 191 87 379 204
Future income tax expense (recovery) 71 (201) 266 (257)
----------------------------------------------------------------------------
Income tax expense (recovery) $ 262 $ (114) $ 645 $ (53)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Conventional Crude Oil and Natural Gas,
Midstream, and Oil Sands Mining and Upgrading segments.
Taxable income from the conventional crude oil and natural gas
business in Canada is primarily generated through partnerships,
with the related income taxes payable in subsequent periods. North
America current income taxes have been provided on the basis of
this corporate structure. In addition, current income taxes in each
business segment will vary depending upon available income tax
deductions related to the nature, timing and amount of capital
expenditures incurred in any particular year.
Future income tax expense in the first quarter of 2010 included
a charge of $83 million related to the proposed change in Canada to
the taxation of stock options surrendered by employees for cash.
During the first quarter of 2009, substantively enacted or enacted
income tax rate changes resulted in a reduction of future income
tax liabilities of $19 million in British Columbia.
The Company is subject to income tax reassessments arising in
the normal course. The Company does not believe that any
liabilities ultimately arising from these reassessments will be
material.
7. SHARE CAPITAL
Six Months Ended Jun 30, 2010
Issued Number of shares
Common shares (thousands) (1) Amount
----------------------------------------------------------------------------
Balance - beginning of period 1,084,654 $ 2,834
Issued upon exercise of stock options 4,598 74
Previously recognized liability on stock
options exercised - 98
Cancellation of common shares (14) -
----------------------------------------------------------------------------
Balance - end of period 1,089,238 $ 3,006
----------------------------------------------------------------------------
(1) Restated to reflect two-for-one common share split in May 2010.
Dividend policy
On March 3, 2010, the Board of Directors set the regular
quarterly dividend at $0.075 per common share. The Company has paid
regular quarterly dividends in January, April, July, and October of
each year since 2001. The dividend policy undergoes a periodic
review by the Board of Directors and is subject to change.
Normal Course Issuer Bid
In 2010, the Company announced a Normal Course Issuer Bid to
purchase, through the facilities of the Toronto Stock Exchange and
the New York Stock Exchange, during the 12 month period commencing
April 6, 2010 and ending April 5, 2011, up to 27,163,940 common
shares or 2.5% of the common shares of the Company outstanding at
March 17, 2010. As at June 30, 2010, no common shares had been
purchased for cancellation.
Share split
The Company's shareholders passed a Special Resolution
subdividing the common shares of the Company on a two-for-one basis
at the Company's Annual and Special Meeting held on May 6, 2010
with such subdivision taking effect on May 21, 2010. All common
share, per common share, and stock option amounts have been
restated to reflect the share split.
Six Months Ended Jun 30, 2010
Stock options Weighted average
Stock options (thousands) (1) exercise price (1)
----------------------------------------------------------------------------
Outstanding - beginning of period 64,211 $ 29.27
Granted 1,677 $ 37.15
Surrendered for cash settlement (2,162) $ 19.03
Exercised for common shares (4,598) $ 16.16
Forfeited (1,374) $ 32.33
----------------------------------------------------------------------------
Outstanding - end of period 57,754 $ 30.85
----------------------------------------------------------------------------
Exercisable - end of period 19,064 $ 29.89
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Restated to reflect two-for-one common share split in May 2010.
8. ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME
The components of accumulated other comprehensive (loss) income, net of
taxes, were as follows:
June 30 June 30
2010 2009
----------------------------------------------------------------------------
Derivative financial instruments designated as
cash flow hedges $ 157 $ 81
Foreign currency translation adjustment (170) (6)
----------------------------------------------------------------------------
$ (13) $ 75
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. CAPITAL DISCLOSURES
The Company does not have any externally imposed regulatory
capital requirements for managing capital. The Company has defined
its capital to mean its long-term debt and consolidated
shareholders' equity, as determined each reporting date.
The Company's objectives when managing its capital structure are
to maintain financial flexibility and balance to enable the Company
to access capital markets to sustain its on-going operations and to
support its growth strategies. The Company primarily monitors
capital on the basis of an internally derived non-GAAP financial
measure referred to as its "debt to book capitalization ratio",
which is the arithmetic ratio of current and long-term debt divided
by the sum of the carrying value of shareholders' equity plus
current and long-term debt. The Company's internal targeted range
for its debt to book capitalization ratio is 35% to 45%. This range
may be exceeded in periods when a combination of capital projects,
acquisitions, and lower commodity prices occurs. The Company may be
below the low end of the targeted range when cash flow from
operating activities is greater than current investment activities.
The ratio is currently at 31%.
Readers are cautioned that the debt to book capitalization ratio
is not defined by GAAP and this financial measure may not be
comparable to similar measures presented by other companies.
Further, there are no assurances that the Company will continue to
use this measure to monitor capital or will not alter the method of
calculation of this measure in the future.
June 30 Dec 31
2010 2009
----------------------------------------------------------------------------
Long-term debt $ 9,335 $ 9,658
Total shareholders' equity $ 21,059 $ 19,426
Debt to book capitalization 31% 33%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. NET EARNINGS PER COMMON SHARE
Three Months Ended Six Months Ended
Jun 30 Jun 30 Jun 30 Jun 30
2010 2009 (1) 2010 2009 (1)
----------------------------------------------------------------------------
Weighted average common shares
outstanding (thousands) -
basic and diluted 1,088,751 1,083,996 1,087,179 1,083,253
----------------------------------------------------------------------------
Net earnings - basic and
diluted $ 667 $ 162 $ 1,533 $ 467
----------------------------------------------------------------------------
Net earnings per common share -
basic and diluted $ 0.61 $ 0.15 $ 1.41 $ 0.43
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Restated to reflect two-for-one common share split in May 2010.
11. FINANCIAL INSTRUMENTS
The carrying values of the Company's financial instruments by category are
as follows:
---------------------------------------------------
Jun 30, 2010
----------------------------------------------------------------------------
Loans and Held for Other financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized cost
----------------------------------------------------------------------------
Cash and cash equivalents $ - $ 19 $ -
Accounts receivable 1,363 - -
Other long-term assets - 122 -
Accounts payable - - (295)
Accrued liabilities - - (1,842)
Other long-term
liabilities - - (100)
Long-term debt - - (9,335)
----------------------------------------------------------------------------
$ 1,363 $ 141 $ (11,572)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
-----------------------------------------------
Dec 31, 2009
----------------------------------------------------------------------------
Loans and Held for Other financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized cost
----------------------------------------------------------------------------
Cash and cash equivalents $ - $ 13 $ -
Accounts receivable 1,148 - -
Other long-term assets - - -
Accounts payable - - (240)
Accrued liabilities - - (1,522)
Other long-term
liabilities - (309) (167)
Long-term debt - - (9,658)
----------------------------------------------------------------------------
$ 1,148 $ (296) $ (11,587)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The carrying value of the Company's financial instruments
approximates their fair value, except for fixed-rate long-term debt
as noted below. The fair values of the Company's financial assets
and liabilities are outlined below:
Jun 30, 2010
---------------------------------------------
Carrying value Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term assets $ 122 $ - $ 122
Other long-term liabilities - - -
Fixed-rate long-term debt(2)(3) (7,863) (8,549) -
----------------------------------------------------------------------------
$ (7,741) $ (8,549) $ 122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2009
----------------------------------------------------------------------------
Carrying value Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term assets $ - $ - $ -
Other long-term liabilities (309) - (309)
Fixed-rate long-term debt(2)(3) (7,761) (8,212) -
----------------------------------------------------------------------------
$ (8,070) $ (8,212) $ (309)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes financial assets and liabilities where book value approximates
fair value due to the liquid nature of the asset or liability (cash and
cash equivalents, accounts receivable, accounts payable and accrued
liabilities).
(2) The carrying values of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $49 million (2009 - $38 million) to reflect the fair value impact of
hedge accounting.
(3) The fair value of fixed-rate long-term debt has been determined based on
quoted market prices.
Risk management
The Company uses derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures.
These financial instruments are entered into solely for hedging
purposes and are not used for speculative purposes.
The estimated fair value of derivative financial instruments has
been determined based on appropriate internal valuation
methodologies. Fair values determined using valuation models
require the use of assumptions concerning the amount and timing of
future cash flows and discount rates. In determining these
assumptions, the Company primarily relied on external,
readily-observable market inputs including quoted commodity prices
and volatility, interest rate yield curves, and foreign exchange
rates. The resulting fair value estimates may not necessarily be
indicative of the amounts that could be realized or settled in a
current market transaction and these differences may be
material.
The changes in estimated fair values of derivative financial
instruments included in the risk management asset (liability) were
recognized in the financial statements as follows:
Six Months Ended Year Ended
Jun 30, 2010 Dec 31, 2009
----------------------------------------------------------------------------
Risk Risk
management management
Asset (liability) mark-to-market mark-to-market
----------------------------------------------------------------------------
Balance - beginning of period $ (309) $ 2,119
Net change in fair value of outstanding
derivative financial
instruments attributable to:
- Risk management activities 290 (1,991)
- Interest expense 13 (25)
- Foreign exchange 36 (338)
- Other comprehensive income 92 (78)
- Settlement of interest rate swaps and
other - 4
----------------------------------------------------------------------------
Balance - end of period 122 (309)
Less: current portion 108 (182)
----------------------------------------------------------------------------
$ 14 $ (127)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net (gains) losses from risk management activities were as follows:
Three Months Ended Six Months Ended
Jun 30 Jun 30 Jun 30 Jun 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Net realized risk management gain $ (91) $ (290) $ (52) $ (931)
Net unrealized risk management
(gain) loss (82) 946 (290) 1,409
----------------------------------------------------------------------------
$ (173) $ 656 $ (342) $ 478
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial risk factors
a) Market risk
Market risk is the risk that the fair value or future cash flows
of a financial instrument will fluctuate because of changes in
market prices. The Company's market risk is comprised of commodity
price risk, interest rate risk, and foreign currency exchange
risk.
Commodity price risk management
The Company uses commodity derivative financial instruments to
manage its exposure to commodity price risk associated with the
sale of its future crude oil and natural gas production and with
natural gas purchases. At June 30, 2010, the Company had the
following net derivative financial instruments outstanding:
i) Sales Contracts
Remaining term Volume Weighted average price Index
----------------------------------------------------------------------------
Crude oil
Crude oil
price
collars Jul 2010 - Sep 2010 50,000 bbl/d US$65.00 - US$105.49 WTI
Jul 2010 - Dec 2010 50,000 bbl/d US$60.00 - US$75.08 WTI
Jul 2010 - Dec 2010 50,000 bbl/d US$65.00 - US$108.94 WTI
Oct 2010 - Dec 2010 50,000 bbl/d US$70.00 - US$105.81 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Remaining term Volume Weighted average price Index
----------------------------------------------------------------------------
Natural gas
Natural gas
price
collars Jul 2010 - Sep 2010 400,000 GJ/d C$4.50 - C$6.30 AECO
Jul 2010 - Dec 2010 220,000 GJ/d C$6.00 - C$8.00 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ii) Purchase Contracts
Weighted
average
Remaining term Volume fixed rate Floating index
----------------------------------------------------------------------------
Natural gas
Swaps - floating
to fixed Jan 2011 - Dec 2011 125,000 GJ/d C$4.87 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's outstanding commodity derivative financial
instruments are expected to be settled monthly based on the
applicable index pricing for the respective contract month.
All commodity derivative financial instruments designated as
hedges at June 30, 2010 were classified as cash flow hedges.
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed
rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company enters into interest rate
swap contracts to manage its fixed to floating interest rate mix on
long-term debt. The interest rate swap contracts require the
periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At June 30,
2010, the Company had the following interest rate swap contracts
outstanding:
Amount Fixed Floating
Remaining term ($ millions) rate rate
----------------------------------------------------------------------------
Interest rate
Swaps - fixed
to floating Jul 2010 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
Swaps -
floating to
fixed Jul 2010 - Feb 2011 C$300 1.0680% 3 month CDOR (2)
Jul 2010 - Feb 2012 C$200 1.4475% 3 month CDOR (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) London Interbank Offered Rate
(2) Canadian Dealer Offered Rate
All fixed to floating interest rate related derivative financial
instruments designated as hedges at June 30, 2010 were classified
as fair value hedges.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated long-term
debt and working capital. The Company is also exposed to foreign
currency exchange rate risk on transactions conducted in other
currencies in its subsidiaries and in the carrying value of its
self-sustaining foreign subsidiaries. The Company periodically
enters into cross currency swap contracts and foreign currency
forward contracts to manage known currency exposure on US dollar
denominated long-term debt and working capital. The cross currency
swap contracts require the periodic exchange of payments with the
exchange at maturity of notional principal amounts on which the
payments are based. At June 30, 2010, the Company had the following
cross currency swap contracts outstanding:
Exchange Interest Interest
Amount rate rate rate
Remaining term ($ millions) (US$/C$) (US$) (C$)
----------------------------------------------------------------------------
Cross currency
Swaps Jul 2010 - Jul 2011 US$100 0.999 6.70% 7.64%
Jul 2010 - Aug 2016 US$250 1.116 6.00% 5.40%
Jul 2010 - May 2017 US$1,100 1.170 5.70% 5.10%
Jul 2010 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency swap derivative financial instruments
designated as hedges at June 30, 2010 were classified as cash flow
hedges.
In addition to the cross currency swap contracts noted above, at
June 30, 2010, the Company had US$1,492 million of foreign currency
forward contracts outstanding, with original terms ranging from
approximately 30 days to 90 days.
Financial instrument sensitivities
The following table summarizes the annualized sensitivities of
the Company's net earnings and other comprehensive income to
changes in the fair value of financial instruments outstanding as
at June 30, 2010 resulting from changes in the specified variable,
with all other variables held constant. These sensitivities are
prepared on a different basis than those sensitivities disclosed in
the Company's other continuous disclosure documents and do not
represent the impact of a change in the variable on the operating
results of the Company taken as a whole. Further, these
sensitivities are theoretical, as changes in one variable may
contribute to changes in another variable, which may magnify or
counteract the sensitivities. In addition, changes in fair value
generally can not be extrapolated because the relationship of a
change in an assumption to the change in fair value may not be
linear.
Impact on other
Impact on net comprehensive
earnings income
----------------------------------------------------------------------------
Commodity price risk
Increase WTI US$1.00/bbl $ (7) $ -
Decrease WTI US$1.00/bbl $ 7 $ -
Increase AECO C$0.10/mcf $ (5) $ 3
Decrease AECO C$0.10/mcf $ 5 $ (3)
Interest rate risk
Increase interest rate 1% $ (9) $ (2)
Decrease interest rate 1% $ 8 $ 1
Foreign currency exchange rate risk
Increase exchange rate by US$0.01 $ (27) $ -
Decrease exchange rate by US$0.01 $ 27 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
June 30, 2010, substantially all of the Company's accounts
receivable were due within normal trade terms.
The Company is also exposed to possible losses in the event of
non-performance by counterparties to derivative financial
instruments; however, the Company manages this credit risk by
entering into agreements with counterparties that are substantially
all investment grade financial institutions and other entities. At
June 30, 2010, the Company had net risk management assets of $141
million with specific counterparties related to derivative
financial instruments (December 31, 2009 - $7 million).
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter
difficulty in meeting obligations associated with financial
liabilities.
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating
activities, available credit facilities, and access to debt capital
markets, to meet obligations as they become due. Due to
fluctuations in the timing of the receipt and/or disbursement of
operating cash flows, the Company believes it has adequate bank
credit facilities to provide liquidity.
The maturity dates for financial liabilities are as follows:
1 to less 2 to less
Less than than than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 295 $ - $ - $ -
Accrued liabilities $ 1,842 $ - $ - $ -
Other long-term
liabilities $ 26 $ 28 $ 46 $ -
Long-term debt (1) $ 400 $ 424 $ 1,967 $ 5,091
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or transaction
costs. No debt repayments are reflected for $1,472 million of revolving
bank credit facilities due to the extendable nature of the facilities.
12. COMMITMENTS
As at June 30, 2010, the Company had committed to certain payments as
follows:
Remaining
2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 121 $ 207 $ 176 $ 150 $ 149 $ 1,088
Offshore equipment
operating leases $ 90 $ 127 $ 104 $ 103 $ 102 $ 265
Offshore drilling $ 34 $ - $ - $ - $ - $ -
Asset retirement
obligations (1) $ 8 $ 20 $ 21 $ 31 $ 39 $ 6,626
Office leases $ 12 $ 20 $ 3 $ 3 $ 3 $ 4
Other $ 145 $ 66 $ 24 $ 14 $ 12 $ 36
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts represent management's estimate of the future undiscounted
payments to settle asset retirement obligations related to resource
properties, facilities, and production platforms, based on current
legislation and industry operating practices. Amounts disclosed for the
period 2010 - 2014 represent the estimated minimum expenditures required
to meet these obligations. Actual expenditures in any particular year
may exceed these minimum amounts.
13. SEGMENTED INFORMATION
Conventional Crude Oil and Natural Gas
North America North Sea
Three Six Three Six
Months Months Months Months
(millions of Canadian Ended Ended Ended Ended
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2010 2009 2010 2009 2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented revenue 2,490 2,000 4,976 3,847 245 271 531 446
Less: royalties (290) (192) (614) (385) - (1) (1) (1)
----------------------------------------------------------------------------
Segmented revenue, net
of royalties 2,200 1,808 4,362 3,462 245 270 530 445
----------------------------------------------------------------------------
Segmented expenses
Production 410 445 837 921 67 113 157 183
Transportation and
blending 554 304 961 630 2 2 5 5
Depletion, depreciation
and amortization 586 514 1,143 1,061 69 79 152 143
Asset retirement
obligation accretion 11 11 22 20 8 6 16 13
Realized risk management
activities (91) (188) (52) (672) - (102) - (259)
----------------------------------------------------------------------------
Total segmented
expenses 1,470 1,086 2,911 1,960 146 98 330 85
----------------------------------------------------------------------------
Segmented earnings
before the following 730 722 1,451 1,502 99 172 200 360
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Stock-based compensation
(recovery) expense
Interest, net
Unrealized risk
management activities
Foreign exchange loss
(gain)
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before taxes
Taxes other than income
tax
Current income tax expense
Future income tax expense
(recovery)
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore West Africa Total Conventional
Three Six Three Six
Months Months Months Months
(millions of Canadian Ended Ended Ended Ended
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2010 2009 2010 2009 2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented revenue 177 182 333 383 2,912 2,453 5,840 4,676
Less: royalties (10) (16) (15) (30) (300) (209) (630) (416)
----------------------------------------------------------------------------
Segmented revenue, net
of royalties 167 166 318 353 2,612 2,244 5,210 4,260
----------------------------------------------------------------------------
Segmented expenses
Production 41 30 69 73 518 588 1,063 1,177
Transportation and
blending - - - - 556 306 966 635
Depletion, depreciation
and amortization 85 38 124 88 740 631 1,419 1,292
Asset retirement
obligation accretion 2 1 3 2 21 18 41 35
Realized risk management
activities - - - - (91) (290) (52) (931)
----------------------------------------------------------------------------
Total segmented
expenses 128 69 196 163 1,744 1,253 3,437 2,208
----------------------------------------------------------------------------
Segmented earnings before
the following 39 97 122 190 868 991 1,773 2,052
Non-segmented expenses
Administration
Stock-based compensation
(recovery) expense
Interest, net
Unrealized risk management
activities
Foreign exchange loss
(gain)
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before taxes
Taxes other than income
tax
Current income tax
expense
Future income tax expense
(recovery)
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil Sands Mining and Upgrading Midstream
Three Six Three Six
Months Months Months Months
(millions of Canadian Ended Ended Ended Ended
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2010 2009 2010 2009 2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented revenue 698 292 1,345 292 21 17 40 36
Less: royalties (24) (3) (47) (3) - - - -
----------------------------------------------------------------------------
Segmented revenue, net
of royalties 674 289 1,298 289 21 17 40 36
----------------------------------------------------------------------------
Segmented expenses
Production 290 182 636 182 7 5 12 10
Transportation and
blending 16 14 31 14 - - - -
Depletion, depreciation
and amortization 94 36 184 38 2 2 4 4
Asset retirement
obligation accretion 5 6 11 8 - - - -
Realized risk management
activities - - - - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 405 238 862 242 9 7 16 14
----------------------------------------------------------------------------
Segmented earnings
before the following 269 51 436 47 12 10 24 22
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Stock-based compensation
(recovery) expense
Interest, net
Unrealized risk
management activities
Foreign exchange loss
(gain)
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before taxes
Taxes other than income
tax
Current income tax
expense
Future income tax
expense (recovery)
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment elimination and other Total
Three Six Three Six
Months Months Months Months
(millions of Canadian Ended Ended Ended Ended
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2010 2009 2010 2009 2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented revenue (17) (12) (31) (68) 3,614 2,750 7,194 4,936
Less: royalties - - - 8 (324) (212) (677) (411)
----------------------------------------------------------------------------
Segmented revenue, net
of royalties (17) (12) (31) (60) 3,290 2,538 6,517 4,525
----------------------------------------------------------------------------
Segmented expenses
Production (3) (2) (5) (14) 812 773 1,706 1,355
Transportation and
blending (13) (11) (24) (23) 559 309 973 626
Depletion, depreciation
and amortization - (5) - (24) 836 664 1,607 1,310
Asset retirement
obligation accretion - - - - 26 24 52 43
Realized risk management
activities - - - - (91) (290) (52) (931)
----------------------------------------------------------------------------
Total segmented
expenses (16) (18) (29) (61) 2,142 1,480 4,286 2,403
----------------------------------------------------------------------------
Segmented earnings
before the following (1) 6 (2) 1 1,148 1,058 2,231 2,122
----------------------------------------------------------------------------
Non-segmented expenses
Administration 60 47 114 94
Stock-based compensation
(recovery) expense (58) 92 (60) 96
Interest, net 109 124 220 181
Unrealized risk management
activities (82) 946 (290) 1,409
Foreign exchange loss (gain) 156 (246) (4) (123)
----------------------------------------------------------------------------
Total non-segmented
expenses 185 963 (20) 1,657
----------------------------------------------------------------------------
Earnings before taxes 963 95 2,251 465
Taxes other than income tax 34 47 73 51
Current income tax expense 191 87 379 204
Future income tax expense
(recovery) 71 (201) 266 (257)
----------------------------------------------------------------------------
Net earnings 667 162 1,533 467
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net additions to property, plant and equipment
Six Months Ended
Jun 30, 2010
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 2,159 $ 14 $ 2,173
North Sea 52 - 52
Offshore West Africa 149 (2) 147
Other 1 - 1
Oil Sands Mining
and Upgrading (2) 220 6 226
Midstream 1 - 1
Head office 9 - 9
----------------------------------------------------------------------------
$ 2,591 $ 18 $ 2,609
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six Months Ended
Jun 30, 2009
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 869 $ (4) $ 865
North Sea 82 - 82
Offshore West Africa 356 50 406
Other - - -
Oil Sands Mining
and Upgrading (2) 391 275 666
Midstream 5 - 5
Head office 7 - 7
----------------------------------------------------------------------------
$ 1,710 $ 321 $ 2,031
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Asset retirement obligations, future income tax adjustments related to
differences between carrying value and tax value, and other fair value
adjustments.
(2) Net expenditures for Oil Sands Mining and Upgrading assets also include
capitalized interest, stock-based compensation, and the impact of inter-
segment eliminations.
Property, plant
and equipment Total assets
Jun 30 Dec 31 Jun 30 Dec 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented assets
North America $ 22,876 $ 21,834 $ 24,078 $ 22,994
North Sea 1,708 1,812 1,850 1,968
Offshore West Africa 1,897 1,883 2,097 2,033
Other 29 28 56 42
Oil Sands Mining and Upgrading 13,337 13,295 13,794 13,621
Midstream 200 203 320 306
Head office 60 60 60 60
----------------------------------------------------------------------------
$ 40,107 $ 39,115 $ 42,255 $ 41,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capitalized interest
The Company capitalizes construction period interest to Oil
Sands Mining and Upgrading activities based on costs incurred and
the Company's cost of borrowing. Interest capitalization on a
particular development phase ceases once construction is
substantially complete. For the six months ended June 30, 2010,
pre-tax interest of $12 million was capitalized to Oil Sands Mining
and Upgrading (June 30, 2009 - $92 million).
SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with
the Company's continuous offering of medium-term notes pursuant to
the short form prospectus dated October 2009. These ratios are
based on the Company's interim consolidated financial statements
that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended June 30,
2010:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 8.6x
Cash flow from operations (2) 15.5x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net earnings plus income taxes and interest expense; divided by the sum
of interest expense and capitalized interest.
(2) Cash flow from operations plus current income taxes and interest
expense; divided by the sum of interest expense and capitalized
interest.
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Time, 11:00
a.m. Eastern Time on Thursday, August 5, 2010. The North American
conference call number is 1-800-769-8320 and the outside North
American conference call number is 001-416-695-6616. Please call in
about 10 minutes before the starting time in order to be patched
into the call. The conference call will also be broadcast live on
the internet and may be accessed through the Canadian Natural
website at www.cnrl.com.
A taped rebroadcast will be available until 6:00 p.m. Mountain
Time, Thursday, August 12, 2010. To access the postview in North
America, dial 1-800-408-3053. Those outside of North America, dial
001-416-695-5800. The passcode to use is 3858142.
WEBCAST
This call is being webcast and can be accessed on Canadian
Natural's website at www.cnrl.com.
2010 THIRD QUARTER RESULTS
The 2010 third quarter results are scheduled for release on
Thursday, November 4, 2010. A conference call is scheduled to be
held the same day. Details can be found on our website
www.cnrl.com.
Contacts: John G. Langille Vice-Chairman Steve W. Laut President
Corey B. Bieber Vice-President, Finance & Investor Relations
Canadian Natural Resources Limited 2500, 855 - 2nd Street S.W.
Calgary, Alberta T2P 4J8 (403) 514-7777 (403) 514-7888 (FAX)
ir@cnrl.com www.cnrl.com
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