Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Canadian Natural's Chairman, Allan Markin stated, "We have
achieved good overall corporate performance across our assets
during the third quarter. Our people remain committed towards safe,
effective operations and cost optimization. At Horizon, we continue
to make operational adjustments to optimize a strong long-life
asset that adds to the diversity and cash flow generating capacity
of our portfolio."
John Langille, Vice-Chairman of Canadian Natural commented, "Our
strategy to steward capital to the highest return projects
continued to generate significant free cash flow in the third
quarter. We have increased our nine-month total production volumes
by over 9% from 2009 levels, and at the same time we have
effectively utilized our free cash flow to reduce debt, increase
dividend payments, and buy back common shares to reduce dilution
and complete acquisitions that support our corporate strategy."
Steve Laut, President for Canadian Natural concluded, "Canadian
Natural is in a strong position; our balanced asset base enables us
to allocate capital to maximize shareholder value. Our flexibility
allows us to adjust when commodity cycles change and currently this
means choosing crude oil projects over natural gas projects. We
remain disciplined in our approach to growing the Company, and this
strategy ensures we add value growth in the near, mid and long
term, while maintaining a solid balance sheet."
Three Months Ended Nine Months Ended
($ millions, Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
except as noted) 2010 2010 2009(1) 2010 2009(1)
----------------------------------------------------------------------------
Net earnings $ 580 $ 667 $ 658 $ 2,113 $ 1,125
Per common share,
basic and diluted $ 0.53 $ 0.61 $ 0.61 $ 1.94 $ 1.04
Adjusted net earnings
from operations (2) $ 606 $ 688 $ 658 $ 1,952 $ 2,022
Per common share,
basic and diluted $ 0.55 $ 0.63 $ 0.61 $ 1.79 $ 1.87
Cash flow from
operations (3) $ 1,545 $ 1,630 $ 1,506 $ 4,680 $ 4,387
Per common share,
basic and diluted $ 1.42 $ 1.49 $ 1.39 $ 4.30 $ 4.05
Capital expenditures,
net of dispositions $ 914 $ 1,573 $ 574 $ 3,559 $ 2,303
Daily production,
before royalties
Natural gas (mmcf/d) 1,258 1,237 1,293 1,240 1,338
Crude oil and NGLs
(bbl/d) 411,585 443,045 359,269 420,319 351,760
Equivalent production
(boe/d) 621,284 649,195 574,755 627,052 574,688
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Per common 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
- Total natural gas production for Q3/10 averaged 1,258 mmcf/d.
Q3/10 natural gas production decreased 3% from Q3/09, as expected,
and increased 2% from the previous quarter. The increase from Q2/10
reflects a full quarter of production volumes from acquisitions in
Q2/10 and the Company's high quality North American natural gas
assets.
- Total crude oil and NGLs production for Q3/10 averaged 411,585
bbl/d, a 15% increase from Q3/09 and a 7% decrease from Q2/10.
Lower production volumes in Q3/10 compared to Q2/10 mainly
reflected lower Horizon volumes as well as the optimization of
current steaming strategies at Primrose to maximize ultimate
recoveries. As a result, the production portion of the cycle was
delayed on new pads to capture this opportunity. Consequently,
thermal crude oil production volumes in Q3/10 are targeted to
increase in Q4/10 and Q1/11.
- Quarterly cash flow from operations for Q3/10 exceeded $1.5
billion, an increase of 3% from Q3/09 and decreased 5% from Q2/10.
The decrease from Q2/10 largely reflects the impact of lower crude
oil and NGL sales volumes.
- In Q3/10, Canadian Natural drilled 209 net primary heavy crude
oil wells as part of the ongoing record heavy crude oil drilling
program in 2010. The Company targets to drill approximately 650 net
primary heavy crude oil wells in 2010.
- Horizon SCO production averaged 83,809 bbl/d in Q3/10. The
maintenance required to address localized pipe wall thinning
limited to the amine unit, which required a plant wide shut down,
was successfully completed in mid August. This lowered August's
volumes to approximately 50,500 bbl/d while production increased to
approximately 108,600 bbl/d in September 2010.
- The last well on Platform B of the Olowi Project was completed
during Q3/10 and performance is in line with the Company's
expectations. The Company has commenced drilling operations on
Platform A and during October 2010, the first crude oil well came
on production as expected at 2,500 bbl/d.
- During Q3/10, Canadian Natural received regulatory approval
for the Kirby In Situ Oil Sands Project.
- In early October 2010, additional leases adjacent to Canadian
Natural's Kirby development were acquired, adding best estimate
contingent resources of 520 million barrels of bitumen. The Kirby
development will be expanded to include three phases; Kirby Phase 1
(with regulatory approval as noted above), Kirby Phase 2 and Kirby
Debottleneck Phase. Overall production capabilities are targeted to
range between 70,000 and 100,000 bbl/d for all three Phases. The
Company expects to gain significant operating synergies within the
Kirby development, which will create the potential to drive
exploitation opportunities similar to those seen at Primrose over
the last decade.
- Subsequent to Q3/10, the Board of Directors sanctioned Kirby
Phase 1. Canadian Natural targets to commence Kirby Phase 1
construction in Q4/10, first steam-in for 2013 and peak production
at 40,000 bbl/d. The overall cost of Kirby Phase 1 is targeted to
be $1.25 billion.
- The Company's balance sheet continues to strengthen with long
term debt reductions of approximately $1.2 billion in 2010, after
completing over $1.0 billion of acquisitions during the first nine
months of 2010.
- As a result of improving credit metrics, Moody's Investors
Service upgraded the Company's rating to Baa1 from Baa2. Standard
& Poor's reaffirmed its BBB rating, however changed its outlook
to positive. The DBRS Limited rating for Canadian Natural is BBB
(high) with a stable outlook.
-Repurchased two million common shares under the Company's
Normal Course Issuer Bid.
- Declared a quarterly cash dividend on common shares of $0.075
per common share payable January 1, 2011.
CORPORATE UPDATE
Canadian Natural is pleased to announce the appointments of
Timothy W. Faithfull, Christopher L. Fong and Wilfred A. Gobert to
the Board of Directors of the Company.
Mr. Faithfull had a 36 year career in various senior positions
with Royal Dutch/Shell, most recently as President and CEO of Shell
Canada Limited, retiring in 2003. He obtained his MA Philosophy,
Politics, and Economics from Keble College, Oxford and attended the
Senior Executive Programme at the London Business School. Mr.
Faithfull serves as a director on two other boards of senior
publicly traded Canadian corporations, a FTSE 100 UK public
company, sits on a number of not-for profit boards and is a
Distinguished Friend of the London Business School.
Mr. Fong, after 28 years with a Canadian chartered bank, retired
in 2009 as Global Head, Corporate Banking, Energy, with RBC Capital
Markets. In his energy career of over 35 years, he developed a
strategic and operational perspective of the energy industry, both
in Canada and abroad. Mr. Fong has a Bachelor degree in Chemical
Engineering and is a professional engineer in the Association of
Professional Engineers, Geologists and Geophysicists of Alberta
(APPEGA). He is a director of two other publicly traded companies
and sits on a number of not-for-profit boards.
Mr. Gobert, spent 33 years as a securities industry financial
analyst, primarily as an analyst on the petroleum industry with
Peters & Co. Limited where he was Director, Research before
becoming Vice-Chairman in 2002 serving on its Board of Directors
and Executive Committee until his retirement in May 2006. Mr.
Gobert holds a CFA designation and has an MBA and B. Sc (Honours)
degree. He currently serves on three other publicly traded company
boards and sits on a number of not-for-profit boards and is Senior
Fellow, Energy Studies, Centre for Energy Policy Studies with The
Fraser Institute.
OPERATIONS REVIEW
Activity by core region
Net undeveloped land Drilling activity
as at nine months ended
Sep 30, 2010 Sep 30, 2010
(thousands of net acres) (net wells) (1)
----------------------------------------------------------------------------
North America
Northeast British Columbia 2,040 30.9
Northwest Alberta 1,523 47.7
Northern Plains 5,436 593.9
Southern Plains 789 17.7
Southeast Saskatchewan 144 25.1
Thermal In Situ Oil Sands 675 192.0
----------------------------------------------------------------------------
10,607 907.3
Oil Sands Mining and Upgrading 115 121.0
North Sea 150 0.9
Offshore West Africa 4,193 5.6
----------------------------------------------------------------------------
15,065 1,034.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Drilling activity includes stratigraphic test and service wells.
Drilling activity (number of wells)
Nine Months Ended Sep 30
2010 2009
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 663 616 476 449
Natural gas 90 74 107 81
Dry 30 25 32 29
----------------------------------------------------------------------------
Subtotal 783 715 615 559
Stratigraphic test / service wells 321 320 249 249
----------------------------------------------------------------------------
Total 1,104 1,035 864 808
----------------------------------------------------------------------------
Success rate (excluding stratigraphic
test / service wells) 97% 95%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America
North America natural gas
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Natural gas production
(mmcf/d) 1,234 1,219 1,264 1,216 1,311
----------------------------------------------------------------------------
Net wells targeting
natural gas 19 11 17 79 89
Net successful wells drilled 19 10 17 74 81
----------------------------------------------------------------------------
Success rate 100% 91% 100% 94% 91%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- North America natural gas production volumes averaged 1,234
mmcf/d, in line with the Company's expectations for Q3/10. Volumes
decreased 2%, as expected, from Q3/09. The Company continues to
optimize performance on existing assets while implementing a
limited natural gas drilling program. Production increased 1% from
Q2/10 primarily due to a full quarter of production volumes from
acquisitions completed in Q2/10 and the high grading of natural gas
drilling inventory within the Company's portfolio.
- As at September 30, 2010, the Company has shut in
approximately 35 mmcf/d due to low natural gas pricing.
- Operating costs for natural gas in Q3/10 were comparable to
Q3/09 costs at $1.04 per mcf while production decreased by 2% from
Q3/09. This demonstrates the effectiveness of the Company's focus
on operating efficiencies and as a result, 2010 annual midpoint
operating cost guidance has been lowered to between $1.05 and $1.10
per mcf.
- Canadian Natural targeted 19 net natural gas wells in Q3/10
with a prudent program across the Company's core regions. In
Northeast British Columbia, 4 net natural gas wells were drilled,
while in Northwest Alberta, 12 net natural gas wells were drilled.
In the Northern Plains, 1 net natural gas well was drilled while in
the Southern Plains, 2 net natural gas wells were drilled.
- Planned drilling activity for Q4/10 includes 20 net natural
gas wells.
North America crude oil and NGLs
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs
production (bbl/d) 267,177 275,584 223,307 265,125 236,315
----------------------------------------------------------------------------
Net wells targeting
crude oil 289 91 270 630 464
Net successful wells
drilled 280 90 260 610 443
----------------------------------------------------------------------------
Success rate 97% 99% 96% 97% 95%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Q3/10 North America crude oil and NGLs production averaged
267,177 bbl/d, an increase of 20% from Q3/09, reflecting higher
thermal volumes and the implementation of a strong primary heavy
crude oil drilling program in 2010. Volumes decreased 3% from Q2/10
levels mainly reflecting the optimization of current steaming
strategies at Primrose to maximize ultimate recoveries. As a
result, the production portion of the cycle was delayed on new pads
to capture this opportunity. Thermal crude oil production volumes
from Q3/10 are targeted to increase in Q4/10 and Q1/11, and the
2010 annual midpoint production guidance for North America crude
oil and NGLs has been narrowed to between 270,000 and 272,000
bbl/d.
- Operating costs for crude oil and NGLs, compared to Q3/09,
decreased 18% and increased 6% from Q2/10. The decrease from Q3/09
was due to higher production volumes and the lower cost of natural
gas used as fuel. The increase from Q2/10 was a result of the
timing of thermal steaming cycles. Q3/10 operating costs remained
within expectations, demonstrating the Company's commitment to
effective operations and 2010 annual operating cost guidance
remains between $12.00 and $13.00 per bbl.
- During Q3/10, Canadian Natural received regulatory approval
for the Kirby In Situ Oil Sands Project.
- In early October 2010, additional leases adjacent to Canadian
Natural's Kirby development were acquired, adding best estimate
contingent resources of 520 million barrels of bitumen. The Kirby
development will be expanded to include three phases; Kirby Phase 1
(with regulatory approval as noted above), Kirby Phase 2 and Kirby
Debottleneck Phase. Overall production capabilities are targeted to
range between 70,000 and 100,000 bbl/d for all three Phases. The
Company expects to gain significant operating synergies within the
Kirby development, which will create the potential to drive
exploitation opportunities similar to those seen at Primrose over
the last decade.
- Subsequent to Q3/10, the Board of Directors sanctioned Kirby
Phase 1. Canadian Natural targets to commence Kirby Phase 1
construction in Q4/10, first steam-in for 2013 and peak production
at 40,000 bbl/d. The overall cost of Kirby Phase 1 is targeted to
be $1.25 billion.
- Production at Pelican Lake averaged approximately 38,000 bbl/d
for Q3/10 compared to 37,000 bbl/d for Q3/09 and Q2/10 reflecting
the effect of polymer flooding with further production increases
anticipated in Q4/10. Polymer flood production response is
typically seen 12 to 24 months after conversion to polymer flood
and production increases from the Company's 2010 program are
expected in late 2011/early 2012.
- Primary heavy crude oil production volumes increased 7% in
Q3/10 compared to Q3/09, reflecting the Company's ongoing drilling
program in 2010.
- During Q3/10, drilling activity targeted 289 net wells
including 209 net wells targeting heavy crude oil, 39 net wells
targeting Pelican Lake crude oil, 6 net wells targeting thermal
crude oil, and 35 net wells targeting light crude oil.
- Excluding stratigraphic test and service wells, planned
drilling activity for Q4/10 includes 351 net crude oil wells.
International
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil production (bbl/d)
North Sea 27,045 37,669 34,034 33,828 38,891
Offshore West Africa 33,554 29,842 35,021 31,126 33,025
----------------------------------------------------------------------------
Natural gas production
(mmcf/d)
North Sea 8 9 8 10 9
Offshore West Africa 16 9 21 14 18
----------------------------------------------------------------------------
Net wells targeting
crude oil 0.9 1.9 2.2 5.6 6.4
Net successful wells drilled 0.9 1.9 1.9 5.6 6.1
----------------------------------------------------------------------------
Success rate 100% 100% 86% 100% 95%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
- As expected, Q3/10 production decreased 21% from Q3/09 and 28%
from Q2/10 due to planned maintenance shut downs at all of the
production facilities. Production was further impacted due to an
unplanned shutdown on the Ninian Field to repair the flare gas
system. Production was reinstated within the quarter.
- Operating costs per barrel increased in Q3/10, which reflect
lower production volumes and increased maintenance costs due to
facility shutdowns. 2010 annual midpoint operating cost guidance
has been narrowed to between $30.00 and $31.00 per bbl.
- The Company recommenced platform drilling operations at the
beginning of Q3/10. One workover and an injector well were
completed, and the Company is currently drilling one gross
production well in the Ninian Field. Focus continues on maturing
and high grading future drilling locations to maximize efficiencies
and operational performance.
Offshore West Africa
- Offshore West Africa's crude oil production in Q3/10 decreased
4% from Q3/09 and increased 12% from Q2/10. As previously
announced, Q2/10 production was impacted by a shut down planned at
Espoir for installation of facilities upgrades. Q3/10 production
volumes were within the Company's previously issued guidance
range.
- Production at Olowi during Q3/10 was impacted by compressor
failures on the Floating Production Storage and Offtake vessel
limiting production capability.
- Crude oil production expense in Q3/10 decreased 25% from Q2/10
due to higher production volumes and a higher proportion of
liftings from the Espoir Field. 2010 annual midpoint operating cost
guidance has been narrowed to between $14.50 to $15.50 per bbl.
- The last well on Platform B of the Olowi Project was completed
during Q3/10 and performance is in line with the Company's
expectations. The Company has commenced drilling operations on
Platform A and during October 2010, the first crude oil well came
on production as expected at 2,500 bbl/d.
Oil Sands Mining and Upgrading
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Synthetic crude oil
production (bbl/d) 83,809 99,950 66,907 90,240 43,529
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Horizon SCO production averaged 83,809 bbl/d in Q3/10. The
maintenance required to address localized pipe wall thinning
limited to the amine unit, which required a plant wide shut down,
was successfully completed in mid August. This lowered August's
volumes to approximately 50,500 bbl/d while production increased to
approximately 108,600 bbl/d in September 2010.
- Operational costs in Q3/10 averaged $34.35 per barrel of SCO
(including approximately $3.15 per barrel of natural gas input
costs), primarily due to the plant wide shut down required during
August 2010. The Company has narrowed annual operating cost
guidance, which include natural gas input costs, to between $33.00
to $37.00 per bbl of SCO for 2010.
- Engineering and procurement for Tranche 2 of the Phase 2/3
expansion is progressing with a focus on increasing reliability and
uptime. Tranches 3 and 4 of Phase 2/3 continue to be re-profiled.
The Company continues to work on completing its lessons learned
from the construction of Phase 1 and implementing these into the
development of future expansions.
MARKETING
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs pricing
WTI(1) benchmark price
(US$/bbl) $ 76.21 $ 77.99 $ 68.29 $ 77.65 $ 57.13
Western Canadian Select
Blend differential from
WTI (%) 20% 18% 15% 17% 15%
SCO price (US$/bbl) $ 75.30 $ 76.44 $ 67.20 $ 77.02 $ 56.95
Average realized pricing
before risk management(2)
(C$/bbl) $ 63.21 $ 63.62 $ 62.90 $ 65.10 $ 54.17
Natural gas pricing
AECO benchmark price
(C$/GJ) $ 3.53 $ 3.66 $ 2.87 $ 4.08 $ 3.88
Average realized
pricing before risk
management (C$/mcf) $ 3.75 $ 3.86 $ 3.80 $ 4.26 $ 4.46
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
(2) Excludes SCO.
- In Q3/10, the Western Canadian Select ("WCS") heavy crude oil
differential as a percent of WTI averaged 20%, compared to 18% in
Q2/10. This widening of heavy crude oil differentials in Q3/10 and
early Q4/10 largely resulted from two pipeline disruptions in the
United States that occurred during Q3/10.
- During Q3/10, the Company contributed approximately 153,000
bbl/d of its heavy crude oil streams to the WCS blend.
- 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 is robust and the
Company continually examines its liquidity position and targets a
low risk approach to finance. The Company's 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 620,000 boe/d in Q3/10, with 94% of
production located in G8 countries.
-- Financial stability and liquidity - cash flow from operations
of $1.5 billion with available unused bank lines of $3.1 billion at
September 30, 2010.
-- Flexibility in asset base and positive free cash flow
produced from International and North America assets, and allows
for a disciplined capital allocation program.
- A strong balance sheet with debt to book capitalization of 28%
and debt to EBITDA of 1.1 times.
- The Company's balance sheet continues to strengthen with long
term debt reductions of approximately $1.2 billion in 2010, after
completing over $1.0 billion of acquisitions during the first nine
months of 2010.
- As a result of improving credit metrics, Moody's Investors
Service upgraded the Company's rating to Baa1 from Baa2. Standard
& Poor's reaffirmed its BBB rating, however changed its outlook
to positive. The DBRS Limited rating for Canadian Natural is BBB
(high) with a stable outlook.
- Repurchased two million common shares under the Company's
Normal Course Issuer Bid.
- Declared a quarterly cash dividend on common shares of $0.075
per common share payable January 1, 2011.
OUTLOOK
The Company forecasts 2010 production levels before royalties to
average between 1,242 and 1,250 mmcf/d of natural gas and between
423,000 and 430,000 bbl/d of crude oil and NGLs. Q4/10 production
guidance before royalties is forecast to average between 1,248 and
1,273 mmcf/d of natural gas and between 432,000 and 456,000 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 and costs, royalties,
operating costs, capital expenditures, income tax expenses 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 as 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 nine months ended September 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 nine and three months ended September 30,
2010 in relation to the comparable periods in 2009 and the second
quarter of 2010. The accompanying tables form an integral part of
this MD&A. This MD&A is dated November 2, 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 Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009(1) 2010 2009(1)
----------------------------------------------------------------------------
Revenue, before
royalties $ 3,341 $ 3,614 $ 2,823 $ 10,535 $ 7,759
Net earnings $ 580 $ 667 $ 658 $ 2,113 $ 1,125
Per common share
- basic and diluted $ 0.53 $ 0.61 $ 0.61 $ 1.94 $ 1.04
Adjusted net earnings
from operations (2) $ 606 $ 688 $ 658 $ 1,952 $ 2,022
Per common share
- basic and diluted $ 0.55 $ 0.63 $ 0.61 $ 1.79 $ 1.87
Cash flow from
operations (3) $ 1,545 $ 1,630 $ 1,506 $ 4,680 $ 4,387
Per common share
- basic and diluted $ 1.42 $ 1.49 $ 1.39 $ 4.30 $ 4.05
Capital expenditures,
net of dispositions $ 914 $ 1,573 $ 574 $ 3,559 $ 2,303
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Per common 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 Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Net earnings as reported $ 580 $ 667 $ 658 $ 2,113 $ 1,125
Stock-based compensation
expense (recovery),
net of tax (a) (d) 18 (58) 126 (42) 196
Unrealized risk management
loss (gain), net of tax (b) 71 (64) 217 (147) 1,213
Unrealized foreign exchange
(gain) loss, net of tax (c) (63) 143 (343) (55) (493)
Effect of statutory tax rate
and other legislative
changes on future income
tax liabilities (d) - - - 83 (19)
----------------------------------------------------------------------------
Adjusted net earnings from
operations $ 606 $ 688 $ 658 $ 1,952 $ 2,022
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $19 million in North
America.
Cash Flow from Operations
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Net earnings $ 580 $ 667 $ 658 $ 2,113 $ 1,125
Non-cash items:
Depletion, depreciation
and amortization 851 836 673 2,458 1,983
Asset retirement
obligation accretion 28 26 24 80 67
Stock-based compensation
expense (recovery) 18 (58) 172 (42) 268
Unrealized risk management
loss (gain) 92 (82) 274 (198) 1,683
Unrealized foreign exchange
(gain) loss (75) 165 (391) (60) (573)
Deferred petroleum revenue
tax expense 11 5 13 23 8
Future income tax expense
(recovery) 40 71 83 306 (174)
----------------------------------------------------------------------------
Cash flow from
operations $ 1,545 $ 1,630 $ 1,506 $ 4,680 $ 4,387
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the nine months ended September 30, 2010 were
$2,113 million compared to $1,125 million for the nine months ended
September 30, 2009. Net earnings for the nine months ended
September 30, 2010 included net unrealized after-tax income of $161
million related to the effects of risk management activities,
fluctuations in foreign exchange rates and stock-based
compensation, and the impact of statutory tax rate changes on
future income tax liabilities, compared to net unrealized after-tax
expenses of $897 million for the nine months ended September 30,
2009. Excluding these items, adjusted net earnings from operations
for the nine months ended September 30, 2010 were $1,952 million,
compared to $2,022 million for the nine months ended September 30,
2009. The decrease in adjusted net earnings from the nine months
ended September 30, 2009 was primarily due to 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, partially offset by
higher realized crude oil pricing, higher crude oil and NGL sales
volumes including crude oil volumes associated with Horizon and
realized foreign exchange gains.
Net earnings for the third quarter of 2010 were $580 million
compared to $658 million for the third quarter of 2009 and $667
million for the prior quarter. Net earnings for the third quarter
of 2010 included net unrealized after-tax expenses of $26 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 $21 million for the prior
quarter. Excluding these items, adjusted net earnings from
operations for the third quarter of 2010 were $606 million compared
to $658 million for the third quarter of 2009 and $688 million for
the prior quarter. The decrease in adjusted net earnings from the
third quarter of 2009 was primarily due to the impact of higher
production expense, higher royalty expense, higher depletion,
depreciation and amortization expense, lower realized risk
management gains and realized foreign exchange losses, partially
offset by higher sales volumes including crude oil volumes
associated with Horizon.
The decrease in adjusted net earnings from the prior quarter was
primarily due to the impact of lower crude oil and NGL sales
volumes, lower realized prices, higher production expense, higher
depletion, depreciation and amortization expense, lower realized
risk management gains and realized foreign exchange losses,
partially offset by lower royalty expense.
The impacts of unrealized risk management activities,
stock-based compensation, and changes in foreign exchange rates are
expected to continue to contribute to 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 nine months ended September
30, 2010 was $4,680 million compared to $4,387 million for the nine
months ended September 30, 2009. Cash flow from operations for the
third quarter of 2010 was $1,545 million compared to $1,506 million
for the third quarter of 2009 and $1,630 million for the prior
quarter. The increase in cash flow from operations from the
comparable periods in 2009 was primarily due to the impact of
higher realized crude oil and NGL pricing, higher crude oil and NGL
sales volumes including crude oil volumes associated with Horizon,
partially offset by higher production expense, higher royalty
expense, lower realized risk management gains, higher cash taxes
and realized foreign exchange gains and the impact of the stronger
Canadian dollar. The decrease in cash flow from operations from the
prior quarter was primarily due to the impact of lower crude oil
and NGL sales volumes, lower realized crude oil and natural gas
pricing, higher production expense and lower realized risk
management gains, partially offset by lower royalty expense and
lower cash taxes.
Total production before royalties for the nine months ended
September 30, 2010 increased 9% to 627,052 boe/d from 574,688 boe/d
for the nine months ended September 30, 2009. Total production
before royalties for the third quarter of 2010 increased 8% to
621,284 boe/d from 574,755 boe/d for the third quarter of 2009 and
decreased 4% from 649,195 boe/d for the prior quarter. Production
for the third quarter of 2010 was slightly below the Company's
previously issued guidance.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the eight
most recently completed quarters:
($ millions, except per Sep 30 Jun 30 Mar 31 Dec 31
common share amounts) 2010 2010 2010(1) 2009(1)
----------------------------------------------------------------------------
Revenue, before royalties $ 3,341 $ 3,614 $ 3,580 $ 3,319
Net earnings $ 580 $ 667 $ 866 $ 455
Net earnings per common share
- Basic and diluted $ 0.53 $ 0.61 $ 0.80 $ 0.42
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common Sep 30 Jun 30 Mar 31 Dec 31
share amounts) 2009(1) 2009(1) 2009(1) 2008(1)
----------------------------------------------------------------------------
Revenue, before royalties $ 2,823 $ 2,750 $ 2,186 $ 2,511
Net earnings $ 658 $ 162 $ 305 $ 1,770
Net earnings per common share
- Basic and diluted $ 0.61 $ 0.15 $ 0.28 $ 1.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Per common 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, 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 and the impact of the commencement of operations at
Horizon and the Olowi Field in Offshore Gabon.
- 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 - Fluctuations in income tax expense
include statutory tax rate and other legislative changes
substantively enacted or enacted in the various periods.
BUSINESS ENVIRONMENT
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
WTI benchmark price (1)
(US$/bbl) $ 76.21 $ 77.99 $ 68.29 $ 77.65 $ 57.13
Dated Brent benchmark
price (US$/bbl) $ 76.85 $ 78.27 $ 68.28 $ 77.15 $ 57.26
WCS blend differential
from WTI (US$/bbl) $ 15.60 $ 14.12 $ 10.06 $ 12.95 $ 8.83
WCS blend differential
from WTI (%) 20% 18% 15% 17% 15%
SCO price (US$/bbl) (2) $ 75.30 $ 76.44 $ 67.20 $ 77.02 $ 56.95
Condensate benchmark
price (US$/bbl) $ 74.52 $ 82.81 $ 65.80 $ 80.68 $ 55.93
NYMEX benchmark price
(US$/mmbtu) $ 4.42 $ 4.08 $ 3.42 $ 4.62 $ 3.96
AECO benchmark price
(C$/GJ) $ 3.53 $ 3.66 $ 2.87 $ 4.08 $ 3.88
US / Canadian dollar
average exchange rate $ 0.9624 $ 0.9731 $ 0.9108 $ 0.9656 $ 0.8549
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) West Texas Intermediate ("WTI")
(2) 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$77.65 per
bbl for the nine months ended September 30, 2010, an increase of
36% from US$57.13 per bbl for the nine months ended September 30,
2009. WTI averaged US$76.21 per bbl for the third quarter of 2010,
an increase of 12% from US$68.29 per bbl for the third quarter of
2009, and a decrease of 2% from US$77.99 per bbl in 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 economic downturn from the past
year.
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$77.15 per
bbl for the nine months ended September 30, 2010, an increase of
35% compared to US$57.26 per bbl for the nine months ended
September 30, 2009. Brent averaged US$76.85 per bbl for the third
quarter of 2010, an increase of 13% compared to US$68.28 per bbl
for the third quarter of 2009, and a decrease of 2% from US$78.27
per bbl for the prior quarter. High inventory levels of crude at
Cushing during the second and third quarters resulted in Brent
prices exceeding WTI.
The Western Canadian Select ("WCS") Heavy Differential averaged
17% for the nine months ended September 30, 2010 compared to 15%
for the nine months ended September 30, 2009. The WCS Heavy
Differential widened in the third quarter of 2010, averaging 20%
compared to 15% for the third quarter of 2009 and 18% for the prior
quarter, partially due to pipeline disruptions that forced the
shutdown of two major oil pipelines to Midwest refineries in the
United States.
The Company uses condensate as a blending diluent for heavy
crude oil pipeline shipments. During the third quarter of 2010,
condensate traded at a discount to WTI, compared to a premium in
the prior quarter, reflecting normal seasonality.
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 continuing economic recovery. The Heavy Differential is
expected to continue to reflect seasonal demand fluctuations and
refinery margins.
NYMEX natural gas prices averaged US$4.62 per mmbtu for the nine
months ended September 30, 2010, an increase of 17% from US$3.96
per mmbtu for the nine months ended September 30, 2009. NYMEX
natural gas prices averaged US$4.42 per mmbtu for the third quarter
of 2010, an increase of 29% from US$3.42 per mmbtu for the third
quarter of 2009, and an increase of 8% from US$4.08 per mmbtu for
the prior quarter. AECO natural gas prices for the nine months
ended September 30, 2010 averaged $4.08 per GJ, an increase of 5%
from $3.88 per GJ for the nine months ended September 30, 2009.
AECO natural gas prices for the third quarter of 2010 increased 23%
to average $3.53 per GJ from $2.87 per GJ in the third quarter of
2009, and decreased 4% from $3.66 per GJ for the prior quarter.
Demand from the price sensitive power and industrial sectors and
hot weather patterns in the Northeast part of the United States
temporarily offset the strong incremental production from shale gas
plays. Although natural gas prices have recovered compared to a
weak 2009 price environment, strong US natural gas production is
limiting the upside to natural gas price recovery.
DAILY PRODUCTION, before royalties
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America
- Conventional 267,177 275,584 223,307 265,125 236,315
North America -
Oil Sands Mining and
Upgrading 83,809 99,950 66,907 90,240 43,529
North Sea 27,045 37,669 34,034 33,828 38,891
Offshore West Africa 33,554 29,842 35,021 31,126 33,025
----------------------------------------------------------------------------
411,585 443,045 359,269 420,319 351,760
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,234 1,219 1,264 1,216 1,311
North Sea 8 9 8 10 9
Offshore West Africa 16 9 21 14 18
----------------------------------------------------------------------------
1,258 1,237 1,293 1,240 1,338
----------------------------------------------------------------------------
Total barrels of oil
equivalent (boe/d) 621,284 649,195 574,755 627,052 574,688
----------------------------------------------------------------------------
Product mix
Light/medium crude oil
and NGLs 18% 18% 20% 18% 21%
Pelican Lake crude oil 6% 6% 6% 6% 6%
Primary heavy crude oil 15% 14% 15% 15% 15%
Thermal heavy crude oil 14% 15% 9% 14% 11%
Synthetic crude oil 13% 15% 12% 14% 8%
Natural gas 34% 32% 38% 33% 39%
----------------------------------------------------------------------------
Percentage of gross revenue (1)
(excluding midstream revenue)
Crude oil and NGLs 86% 86% 83% 84% 77%
Natural gas 14% 14% 17% 16% 23%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation and blending costs and excluding risk management
activities.
DAILY PRODUCTION, net of royalties
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America
- Conventional 220,836 228,781 191,077 218,625 204,166
North America -
Oil Sands Mining and
Upgrading 81,077 96,543 64,814 87,168 42,439
North Sea 27,002 37,581 33,961 33,760 38,809
Offshore West Africa 30,724 28,225 30,551 29,299 29,795
----------------------------------------------------------------------------
359,639 391,130 320,403 368,852 315,209
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,213 1,149 1,228 1,155 1,241
North Sea 8 9 8 10 9
Offshore West Africa 15 8 18 13 16
----------------------------------------------------------------------------
1,236 1,166 1,254 1,178 1,266
----------------------------------------------------------------------------
Total barrels of oil
equivalent (boe/d) 565,595 585,556 529,421 565,313 526,184
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 nine months ended
September 30, 2010 increased 19% to 420,319 bbl/d from 351,760
bbl/d for the nine months ended September 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 third quarter of
2010 increased 15% to 411,585 bbl/d from 359,269 bbl/d for the
third quarter of 2009, and decreased 7% from 443,045 bbl/d for the
prior quarter. The increases from the comparable periods in 2009
were primarily related to the cyclic nature of the Company's
thermal operations and increased Horizon production. The decrease
from the prior quarter was related to an unplanned outage at
Horizon, planned turnaround activities in the North Sea and the
cyclic nature of the Company's thermal production. Crude oil and
NGLs production in the third quarter of 2010 was slightly below the
Company's previously issued guidance of 414,000 to 445,000
bbl/d.
Natural gas production for the nine months ended September 30,
2010 decreased 7% to 1,240 mmcf/d compared to 1,338 mmcf/d for the
nine months ended September 30, 2009. Natural gas production for
the third quarter of 2010 decreased 3% to 1,258 mmcf/d compared to
1,293 mmcf/d for the third quarter of 2009 and increased 2% from
1,237 mmcf/d for 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. The increase from the
prior quarter was primarily due to the inclusion of production
volumes from the acquisition of gas producing properties in the
second quarter. Natural gas production in the third quarter of 2010
was within the Company's previously issued guidance of 1,247 to
1,271 mmcf/d.
For 2010, annual production guidance is targeted to average
between 423,000 and 430,000 bbl/d of crude oil and NGLs and between
1,242 and 1,250 mmcf/d of natural gas. Fourth quarter 2010
production guidance is targeted to average between 432,000 and
456,000 bbl/d of crude oil and NGLs and between 1,248 and 1,273
mmcf/d of natural gas
North America - Conventional
North America conventional crude oil and NGLs production for the
nine months ended September 30, 2010 increased 12% to average
265,125 bbl/d from 236,315 bbl/d for the nine months ended
September 30, 2009. For the third quarter of 2010, crude oil and
NGLs production increased 20% to average 267,177 bbl/d, compared to
223,307 bbl/d for the third quarter of 2009, and decreased 3% from
275,584 bbl/d for the prior quarter. Increases in crude oil and
NGLs production from comparable periods in 2009 were primarily due
to the cyclic nature of the Company's thermal production and the
results of a record heavy oil drilling program. The decrease from
the prior quarter was related to the longer than anticipated
steaming cycle in the Company's thermal production which caused
volumes to be below target. Production of conventional crude oil
and NGLs was slightly below the Company's previously issued
guidance of 275,000 bbl/d to 285,000 bbl/d for the third quarter of
2010.
Natural gas production for the nine months ended September 30,
2010 decreased 7% to 1,216 mmcf/d from 1,311 mmcf/d for the nine
months ended September 30, 2009. For the third quarter of 2010,
natural gas production decreased 2% to 1,234 mmcf/d from 1,264
mmcf/d for the third quarter of 2009, and increased 1% from 1,219
mmcf/d in 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 from the
prior quarter was primarily due to the inclusion of production
volumes from the acquisition of gas producing properties in the
second quarter. Production of natural gas was within the Company's
previously issued guidance of 1,225 mmcf/d to 1,245 mmcf/d for the
third quarter of 2010.
North America - Oil Sands Mining and Upgrading
Horizon Phase 1 commenced production of synthetic crude oil
during 2009. Production averaged 90,240 bbl/d for the nine months
ended September 30, 2010, up 107% from 43,529 bbl/d for the nine
months ended September 30, 2009. For the third quarter of 2010,
production increased 25% to 83,809 bbl/d, compared to 66,907 bbl/d
in the third quarter of 2009, and decreased 16% from 99,950 bbl/d
in the prior quarter. Increases in production of synthetic crude
oil from comparable periods in 2009 reflected the Company's focus
on operational optimization and ramping up of production. The
decrease from the prior quarter was a result of a plant-wide
shutdown because of unplanned maintenance to repair localized pipe
wall thinning in the amine unit. Third quarter production for 2010
was within 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 nine months ended
September 30, 2010 decreased 13% to 33,828 bbl/d from 38,891 bbl/d
for the nine months ended September 30, 2009. Third quarter 2010
North Sea crude oil production decreased 21% to 27,045 bbl/d from
34,034 bbl/d for the third quarter of 2009 and decreased 28% from
37,669 bbl/d in the prior quarter. Decreases in production volumes
from the comparable periods in 2009 were due to natural field
declines and timing of scheduled maintenance shut downs. The
decrease in production volumes from the prior quarter was a result
of planned maintenance shut downs on all of the Company's North Sea
production facilities. Production in the third quarter of 2010 was
at the low end of the Company's previously issued guidance of
27,000 bbl/d to 30,000 bbl/d.
Offshore West Africa
Offshore West Africa crude oil production decreased 6% to 31,126
bbl/d for the nine months ended September 30, 2010 from 33,025
bbl/d for the nine months ended September 30, 2009. Third quarter
crude oil production decreased 4% to 33,554 bbl/d from 35,021 bbl/d
for the third quarter of 2009, and increased 12% from 29,842 bbl/d
in the prior quarter. Final commissioning of Platform B at the
Olowi Field was completed in the second quarter of 2010 and first
crude oil production was achieved as planned in April. The planned
shutdown at Espoir in the prior quarter for the completion of
installation of facilities upgrades resulted in increased volumes
in the current quarter. Production in the third quarter of 2010 was
within the Company's previously issued guidance of 32,000 bbl/d to
35,000 bbl/d.
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:
Sep 30 Jun 30 Dec 31
(bbl) 2010 2010 2009
----------------------------------------------------------------------------
North America - Conventional 761,351 761,351 1,131,372
North America - Oil Sands Mining and
Upgrading (SCO) 1,045,281 1,139,778 1,224,481
North Sea 793,582 1,018,357 713,112
Offshore West Africa 918,535 1,428,949 51,103
----------------------------------------------------------------------------
3,518,749 4,348,435 3,120,068
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS - CONVENTIONAL
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
Sales price (2) $ 63.21 $ 63.62 $ 62.90 $ 65.10 $ 54.17
Royalties 9.05 8.95 7.89 9.34 6.31
Production expense 15.37 13.19 16.71 14.38 16.08
----------------------------------------------------------------------------
Netback $ 38.79 $ 41.48 $ 38.30 $ 41.38 $ 31.78
----------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 3.75 $ 3.86 $ 3.80 $ 4.26 $ 4.46
Royalties (3) 0.11 0.25 0.13 0.25 0.31
Production expense 1.05 1.05 1.05 1.10 1.09
----------------------------------------------------------------------------
Netback $ 2.59 $ 2.56 $ 2.62 $ 2.91 $ 3.06
----------------------------------------------------------------------------
Barrels of oil equivalent
($/boe) (1)
Sales price (2) $ 47.44 $ 47.97 $ 45.52 $ 49.68 $ 42.54
Royalties 5.83 6.10 4.85 6.32 4.43
Production expense 11.89 10.55 12.26 11.37 12.07
----------------------------------------------------------------------------
Netback $ 29.72 $ 31.32 $ 28.41 $ 31.99 $ 26.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1) (2)
North America $ 59.13 $ 60.35 $ 60.07 $ 61.79 $ 51.36
North Sea $ 81.47 $ 79.30 $ 75.91 $ 80.40 $ 65.16
Offshore West Africa $ 77.32 $ 79.21 $ 70.05 $ 78.34 $ 61.92
Company average $ 63.21 $ 63.62 $ 62.90 $ 65.10 $ 54.17
Natural gas ($/mcf)
(1) (2)
North America $ 3.70 $ 3.85 $ 3.76 $ 4.23 $ 4.44
North Sea $ 4.52 $ 3.33 $ 5.70 $ 4.08 $ 4.53
Offshore West Africa $ 7.36 $ 5.14 $ 5.72 $ 6.17 $ 6.54
Company average $ 3.75 $ 3.86 $ 3.80 $ 4.26 $ 4.46
Company average ($/boe)
(1) (2) $ 47.44 $ 47.97 $ 45.52 $ 49.68 $ 42.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 20% to average
$61.79 per bbl for the nine months ended September 30, 2010 from
$51.36 per bbl for the nine months ended September 30, 2009.
Realized crude oil prices averaged $59.13 per bbl for the third
quarter of 2010 and decreased 2% compared to $60.07 per bbl for the
third quarter of 2009 and $60.35 per bbl for the prior quarter. The
increase from the comparable nine-month period in 2009 was
primarily a result of increased WTI benchmark pricing, partially
offset by the impact of the widening Heavy Differential and 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 differential.
The Company continues to focus on its crude oil marketing
strategy, and in the third quarter of 2010 contributed
approximately 153,000 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 Government of Alberta 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 $4.23 per mcf for the nine months ended September 30, 2010
from $4.44 per mcf for the nine months ended September 30, 2009.
The decrease in natural gas prices from the comparable period in
2009 was primarily related to the impact of the natural gas
physical sales contracts in 2009, the widening NYMEX and AECO
differential and the impact of a stronger Canadian dollar relative
to the US dollar. Realized natural gas prices averaged $3.70 per
mcf for the third quarter of 2010, a decrease of 2% compared to
$3.76 per mcf for the third quarter of 2009 and a decrease of 4%
from $3.85 per mcf for the prior quarter. The slight decrease in
realized natural gas prices from the comparative periods in 2009
was primarily related to weak benchmark prices due to lower demand
and high storage levels, and the impact of the stronger Canadian
dollar relative to the US dollar. The decrease in natural gas
prices from the prior quarter was primarily related to lower
benchmark prices due to high storage levels, partially offset by
higher demand resulting from the power and industrial sectors and
weather patterns in the Northeast part of the United States.
Comparisons of the prices received for the Company's North
America conventional production by product type were as
follows:
Sep 30 Jun 30 Sep 30
(Quarterly Average) 2010 2010 2009
----------------------------------------------------------------------------
Wellhead Price (1) (2)
Light/medium crude oil and NGLs ($/bbl) $ 62.40 $ 68.13 $ 59.24
Pelican Lake crude oil ($/bbl) $ 58.44 $ 60.38 $ 61.11
Primary heavy crude oil ($/bbl) $ 58.97 $ 60.26 $ 60.42
Thermal heavy crude oil ($/bbl) $ 57.60 $ 56.53 $ 59.52
Natural gas ($/mcf) $ 3.70 $ 3.85 $ 3.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 23% to average
$80.40 per bbl for the nine months ended September 30, 2010 from
$65.16 per bbl for the nine months ended September 30, 2009.
Realized crude oil prices increased 7% to average $81.47 per bbl
for the third quarter of 2010 from $75.91 per bbl for the third
quarter of 2009, and increased 3% from $79.30 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 27% to
average $78.34 per bbl for the nine months ended September 30, 2010
from $61.92 per bbl for the nine months ended September 30, 2009.
Realized crude oil prices increased 10% to average $77.32 per bbl
for the third quarter of 2010 from $70.05 per bbl for the third
quarter of 2009, and decreased 2% from $79.21 per bbl in the prior
quarter. The increase in realized crude oil prices in Offshore West
Africa from the comparable periods in 2009 was primarily the result
of increased Brent benchmark pricing, partially offset by the
impact of the stronger Canadian dollar. Realized crude oil prices
in Offshore West Africa were also impacted by quality differences
and the timing of liftings from each field.
ROYALTIES - CONVENTIONAL
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
North America $ 10.40 $ 10.42 $ 8.80 $ 10.96 $ 7.30
North Sea $ 0.13 $ 0.18 $ 0.16 $ 0.16 $ 0.13
Offshore West Africa $ 6.52 $ 4.29 $ 8.94 $ 4.95 $ 6.03
Company average $ 9.05 $ 8.95 $ 7.89 $ 9.34 $ 6.31
Natural gas ($/mcf) (1)
North America (2) $ 0.10 $ 0.25 $ 0.12 $ 0.25 $ 0.30
Offshore West Africa $ 0.85 $ 0.26 $ 0.74 $ 0.46 $ 0.64
Company average $ 0.11 $ 0.25 $ 0.13 $ 0.25 $ 0.31
Company average ($/boe)
(1) $ 5.83 $ 6.10 $ 4.85 $ 6.32 $ 4.43
Percentage of revenue (3)
Crude oil and NGLs 14% 14% 13% 14% 12%
Natural gas (2) 3% 6% 3% 6% 7%
Boe 12% 13% 11% 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 nine months ended September 30,
2010 compared to the nine months ended September 30, 2009 reflect
stronger benchmark commodity prices and the impact of the changes
under the Alberta Royalty Framework.
Crude oil and NGLs royalties averaged approximately 18% of
revenues for the third quarter of 2010, compared to 15% for the
third quarter in 2009 and 17% 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 3% of revenues for
the third quarter, comparable to the third quarter of 2009 and a
decrease from 6% for the prior quarter. The decrease in natural gas
royalty rates for the third quarter of 2010 compared to the prior
quarter was primarily due to lower benchmark pricing. Natural gas
royalties are anticipated to average 5% to 6% 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 9% for the third
quarter of 2010 compared to 13% for the third quarter of 2009 and
5% 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 Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
North America $ 12.41 $ 11.75 $ 15.19 $ 12.40 $ 15.01
North Sea $ 44.45 $ 21.35 $ 31.30 $ 29.61 $ 26.96
Offshore West Africa $ 13.66 $ 18.33 $ 13.35 $ 14.95 $ 11.76
Company average $ 15.37 $ 13.19 $ 16.71 $ 14.38 $ 16.08
Natural gas ($/mcf) (1)
North America $ 1.04 $ 1.03 $ 1.04 $ 1.08 $ 1.08
North Sea $ 2.42 $ 2.53 $ 1.57 $ 2.97 $ 1.69
Offshore West Africa $ 1.69 $ 1.64 $ 1.37 $ 1.65 $ 1.44
Company average $ 1.05 $ 1.05 $ 1.05 $ 1.10 $ 1.09
Company average ($/boe)
(1) $ 11.89 $ 10.55 $ 12.26 $ 11.37 $ 12.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 nine
months ended September 30, 2010 decreased 17% to $12.40 per bbl
from $15.01 per bbl for the nine months ended September 30, 2009.
Production expense for the third quarter of 2010 decreased 18% to
$12.41 per bbl from $15.19 per bbl for the third quarter of 2009
and increased 6% from $11.75 per bbl for the prior quarter. The
decrease in production expense per barrel from the comparable
periods in 2009 was a result of higher production volumes and the
lower cost of natural gas used for fuel. The increase in production
expense per barrel from the prior quarter was due to the timing of
thermal steam cycles. North America crude oil and NGLs production
expense is anticipated to average $12.00 to $13.00 per bbl for
2010.
North America natural gas production expense for the nine months
ended September 30, 2010 averaged $1.08 per mcf and was comparable
to the nine months ended September 30, 2009. Production expense for
the third quarter of 2010 averaged $1.04 per mcf and was comparable
to the third quarter of 2009 and the prior quarter. North America
natural gas production expense is anticipated to average $1.05 to
$1.10 per mcf for 2010.
North Sea
North Sea crude oil production expense for the nine months ended
September 30, 2010 increased 10% to $29.61 per bbl from $26.96 per
bbl for the nine months ended September 30, 2009. Production
expense for the third quarter of 2010 increased 42% to $44.45 per
bbl from $31.30 per bbl for the third quarter of 2009 and 108% from
$21.35 per bbl for the prior quarter. Production expense increased
on a per barrel basis from the comparable periods in 2009 due to
lower volumes on relatively fixed costs as a result of planned
facility maintenance shutdowns in the third quarter of 2010.
Production expense increased on a per barrel basis from the prior
quarter due to higher maintenance costs and lower production
volumes associated with the planned facility maintenance shutdowns,
and one-time third party cost recoveries in the prior quarter.
Production expense is anticipated to average $30.00 to $31.00 per
bbl for 2010.
Offshore West Africa
Offshore West Africa crude oil production expense increased 27%
to $14.95 per bbl from $11.76 per bbl for the nine months ended
September 30, 2009. Production expense for the third quarter of
2010 increased 2% to $13.66 per bbl from $13.35 per bbl for the
third quarter of 2009 and decreased 25% from $18.33 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 expenses than the
Espoir and Baobab fields. Production expense decreased from the
prior quarter due to a higher proportion of liftings from the
Espoir Field. Production expense is anticipated to average $14.50
to $15.50 per bbl for 2010.
DEPLETION, DEPRECIATION AND AMORTIZATION - CONVENTIONAL
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expense ($ millions) $ 763 $ 740 $ 610 $ 2,182 $ 1,902
$/boe (1) $ 15.22 $ 15.85 $ 12.64 $ 14.95 $ 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 increased liftings from the Olowi Field. The
increase in depletion, depreciation and amortization expense from
the prior quarter was primarily due to higher liftings in Offshore
West Africa.
ASSET RETIREMENT OBLIGATION ACCRETION - CONVENTIONAL
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expense ($ millions) $ 22 $ 21 $ 17 $ 63 $ 52
$/boe (1) $ 0.43 $ 0.45 $ 0.36 $ 0.43 $ 0.36
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($/bbl)(1) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
SCO sales price (2) $ 75.31 $ 75.97 $ 69.11 $ 76.66 $ 67.65
Bitumen value for
royalty purposes (3) $ 54.13 $ 52.67 $ 56.79 $ 56.04 $ 55.40
Bitumen royalties (4) $ 2.57 $ 2.69 $ 2.19 $ 2.70 $ 1.63
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 third quarter of 2010 compared to
the prior quarter was primarily due to weakening in WTI pricing.
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 Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash costs, excluding
natural gas costs $ 243 $ 262 $ 212 $ 804 $ 371
Natural gas costs 25 28 30 100 53
----------------------------------------------------------------------------
Total cash production
costs $ 268 $ 290 $ 242 $ 904 $ 424
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($/bbl) (1) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash costs, excluding
natural gas costs $ 31.20 $ 29.09 $ 32.36 $ 32.40 $ 34.24
Natural gas costs 3.15 3.18 4.49 4.03 4.89
----------------------------------------------------------------------------
Total cash production
costs $ 34.35 $ 32.27 $ 36.85 $ 36.43 $ 39.13
----------------------------------------------------------------------------
Sales (bbl/d) 84,836 98,645 71,578 90,896 39,736
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $36.43 per bbl for the nine
months ended September 30, 2010 compared to $39.13 per bbl for the
nine months ended September 30, 2009. Total cash production costs
averaged $34.35 per bbl in the third quarter of 2010 compared to
$36.85 per bbl for the third quarter of 2009, and $32.27 in the
prior quarter. The decrease in cash production costs from the
comparative periods in 2009 was primarily due to the Company's
ongoing focus on planned maintenance, operational optimization and
the stabilization of production volumes at levels approaching plant
capacity. The increase in cash production costs from the prior
quarter was primarily due to lower August production volumes
resulting from the plant-wide shutdown for unplanned maintenance to
repair localized pipe wall thinning. Annual production guidance
targets were revised to average between 90,000 and 93,000 bbl/d to
reflect the impact of this outage.
As production volumes continue to stabilize throughout the
remainder of 2010, cash production costs are expected to be between
$33.00 to $37.00 per bbl for 2010.
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Depletion, depreciation
and amortization $ 86 $ 94 $ 66 $ 270 $ 104
Asset retirement
obligation accretion 6 5 7 17 15
----------------------------------------------------------------------------
Total $ 92 $ 99 $ 73 $ 287 $ 119
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($/bbl) (1) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Depletion, depreciation
and amortization $ 10.96 $ 10.47 $ 9.99 $ 10.87 $ 9.61
Asset retirement
obligation accretion 0.71 0.62 0.95 0.67 1.35
----------------------------------------------------------------------------
Total $ 11.67 $ 11.09 $ 10.94 $ 11.54 $ 10.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, depreciation and amortization increased from the
comparable periods in 2009, primarily due to the impact of
depreciation determined on a straight-line basis.
MIDSTREAM
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue $ 19 $ 21 $ 18 $ 59 $ 54
Production expense 4 7 4 16 14
----------------------------------------------------------------------------
Midstream cash flow 15 14 14 43 40
Depreciation 2 2 2 6 6
----------------------------------------------------------------------------
Segment earnings before
taxes $ 13 $ 12 $ 12 $ 37 $ 34
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable periods.
ADMINISTRATION EXPENSE
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expense ($ millions) $ 43 $ 60 $ 38 $ 157 $ 132
$/boe (1) $ 0.73 $ 1.03 $ 0.72 $ 0.92 $ 0.85
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the nine and three months ended
September 30, 2010 increased from the comparative periods in 2009
due to higher staffing related costs. Administrative expense for
the third quarter of 2010 decreased compared to the prior quarter,
due to lower staffing costs and increased recoveries on a higher
capital program.
STOCK-BASED COMPENSATION EXPENSE
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expense (recovery) $ 18 $ (58) $ 172 $ (42) $ 268
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company recorded a $42 million ($42 million after-tax)
stock-based compensation recovery for the nine months ended
September 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 6%
decrease in the Company's share price (Company's share price as at:
September 30, 2010 - $35.59; June 30, 2010 - $35.33; December 31,
2009 - $38.00; September 30, 2009 - $36.15). For the nine months
ended September 30, 2010, the Company capitalized $3 million in
stock-based compensation to Oil Sands Mining and Upgrading
(September 30, 2009 - $2 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 September 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 nine months ended September 30, 2010, the Company paid
$39 million for stock options surrendered for cash settlement
(September 30, 2009 - $79 million).
INTEREST EXPENSE
Three Months Ended Nine Months Ended
($ millions, Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
except per boe amounts 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expense, gross $ 116 $ 114 $ 124 $ 348 $ 397
Less: capitalized
interest, Oil Sands
Mining and Upgrading 7 5 6 19 98
----------------------------------------------------------------------------
Expense, net $ 109 $ 109 $ 118 $ 329 $ 299
$/boe (1) $ 1.89 $ 1.88 $ 2.23 $ 1.93 $ 1.92
Average effective
interest rate 4.9% 4.8% 4.3% 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 Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments $ 5 $ 15 $ (235) $ 37 $ (1,182)
Natural gas financial
instruments (85) (78) - (181) (33)
Foreign currency
contracts and
interest rate swaps 10 (28) 35 22 84
----------------------------------------------------------------------------
Realized gain $ (70) $ (91) $ (200) $ (122) $ (1,131)
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments $ 8 $ (151) $ 208 $ (216) $ 1,711
Natural gas financial
instruments 56 94 (4) 20 (41)
Foreign currency
contracts and
interest rate swaps 28 (25) 70 (2) 13
----------------------------------------------------------------------------
Unrealized loss (gain) $ 92 $ (82) $ 274 $ (198) $ 1,683
----------------------------------------------------------------------------
Net loss (gain) $ 22 $ (173) $ 74 $ (320) $ 552
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Complete details related to outstanding derivative financial
instruments at September 30, 2010 are disclosed in note 11 to the
Company's unaudited interim consolidated financial statements. For
additional information on the Company's risk management activities,
refer to the audited consolidated financial statements and the
MD&A for the year ended December 31, 2009.
The Company recorded a net unrealized gain of $198 million ($147
million after-tax) on its risk management activities for the nine
months ended September 30, 2010, including a $92 million ($71
million after-tax) net unrealized loss for the third quarter of
2010 (June 30, 2010 - unrealized gain of $82 million, $64 million
after-tax; September 30, 2009 - unrealized loss of $274 million,
$217 million after-tax), primarily due to changes in crude oil and
natural gas forward pricing and the reversal of prior period
unrealized gains and losses.
FOREIGN EXCHANGE
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Net realized loss (gain) $ 11 $ (9) $ (33) $ (8) $ 26
Net unrealized (gain) loss
(1) (75) 165 (391) (60) (573)
----------------------------------------------------------------------------
Net (gain) loss $ (64) $ 156 $ (424) $ (68) $ (547)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net unrealized foreign exchange gain for the nine months
ended September 30, 2010 was primarily due to the strengthening of
the Canadian dollar with respect to US dollar debt, together with
the impact of the re-measurement of North Sea future income tax
liabilities denominated in UK pounds sterling. The net unrealized
gain for the respective periods also included the impact of cross
currency swaps (three months ended September 30, 2010 - unrealized
loss of $62 million, June 30, 2010 - unrealized gain of $91
million, September 30, 2009 - unrealized loss of $172 million; nine
months ended September 30, 2010 - unrealized loss of $30 million,
September 30, 2009 - unrealized loss of $290 million). The net
realized foreign exchange gain for the nine months ended September
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 third quarter at
US$0.9711 (June 30, 2010 - US$0.9429; December 31, 2009 -
US$0.9555; September 30, 2009 - US$0.9327).
TAXES
Three Months Ended Nine Months Ended
($ millions, Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
except income tax rates) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Current $ 10 $ 29 $ 10 $ 71 $ 66
Deferred 11 5 13 23 8
----------------------------------------------------------------------------
Taxes other than income
tax $ 21 $ 34 $ 23 $ 94 $ 74
----------------------------------------------------------------------------
North America (1) $ 115 $ 139 $ 7 $ 383 $ 17
North Sea 23 43 55 119 218
Offshore West Africa 25 9 28 40 59
----------------------------------------------------------------------------
Current income tax 163 191 90 542 294
Future income tax expense
(recovery) 40 71 83 306 (174)
----------------------------------------------------------------------------
203 262 173 848 120
Income tax rate and
other legislative changes (2) - - - (83) 19
----------------------------------------------------------------------------
$ 203 $ 262 $ 173 $ 765 $ 139
----------------------------------------------------------------------------
Effective income tax rate on
adjusted net earnings from
operations 25.9% 27.9% 25.7% 26.6% 22.9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 of $450 million to $500 million in Canada and $230 million
to $250 million in the North Sea and Offshore West Africa.
NET CAPITAL EXPENDITURES (1)
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Expenditures on property,
plant and equipment
Net property acquisitions
(dispositions) $ 51 $ 949 $ (30) $ 1,036 $ (5)
Land acquisition and
retention 27 37 18 102 49
Seismic evaluations 29 19 21 81 60
Well drilling, completion
and equipping 365 249 261 1,056 953
Production and related
facilities 253 176 235 811 755
----------------------------------------------------------------------------
Total net reserve replacement
expenditures 725 1,430 505 3,086 1,812
----------------------------------------------------------------------------
Oil Sands Mining and Upgrading:
Horizon Phase 1
construction costs - - - - 69
Horizon Phase 1 commissioning
and other costs - - - - 202
Horizon Phases 2/3
construction costs 92 56 21 219 62
Capitalized interest,
stock-based compensation
and other 10 39 11 58 86
Sustaining capital 35 27 23 80 27
----------------------------------------------------------------------------
Total Oil Sands Mining
and Upgrading (2) 137 122 55 357 446
----------------------------------------------------------------------------
Midstream 3 1 - 4 5
Abandonments (3) 45 15 12 99 31
Head office 4 5 2 13 9
----------------------------------------------------------------------------
Total net capital
expenditures $ 914 $ 1,573 $ 574 $ 3,559 $ 2,303
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 610 $ 1,350 $ 358 $ 2,769 $ 1,227
North Sea 59 29 38 111 120
Offshore West Africa 55 50 108 204 464
Other 1 1 1 2 1
Oil Sands Mining and
Upgrading 137 122 55 357 446
Midstream 3 1 - 4 5
Abandonments (3) 45 15 12 99 31
Head office 4 5 2 13 9
----------------------------------------------------------------------------
Total $ 914 $ 1,573 $ 574 $ 3,559 $ 2,303
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 nine months ended September 30,
2010 were $3,559 million compared to $2,303 million for the nine
months ended September 30, 2009. The increase in capital
expenditures from the comparable periods in 2009 was primarily the
result of the purchase of crude oil and natural gas producing
properties and undeveloped land in the Company's core regions in
Western Canada. Net capital expenditures for the third quarter of
2010 were $914 million compared to $574 million for the third
quarter of 2009 and $1,573 million in the prior quarter. The
decrease in capital expenditures in the current quarter was due to
reduced property acquisitions compared to the prior quarter.
Drilling Activity (number of wells)
Three Months Ended Nine Months Ended
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2010 2010 2009 2010 2009
----------------------------------------------------------------------------
Net successful natural
gas wells 19 10 17 74 81
Net successful crude oil
wells 281 92 262 616 449
Dry wells 9 2 10 25 29
Stratigraphic test /
service wells 14 9 6 320 249
----------------------------------------------------------------------------
Total 323 113 295 1,035 808
Success rate
(excluding stratigraphic
test / service wells) 97% 98% 97% 97% 95%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America
North America, excluding Oil Sands Mining and Upgrading,
accounted for approximately 81% of the total capital expenditures
for the nine months ended September 30, 2010 compared to
approximately 55% for the nine months ended September 30, 2009.
During the third quarter of 2010, the Company targeted 19 net
natural gas wells, including 4 wells in Northeast British Columbia,
12 wells in Northwest Alberta, 1 well in the Northern Plains region
and 2 wells in the Southern Plains region. The Company also
targeted 289 net crude oil wells. The majority of these wells were
concentrated in the Company's Northern Plains region where 209
heavy crude oil wells, 39 Pelican Lake crude oil wells, 6 thermal
crude oil wells and 3 light crude oil wells were drilled. Another
32 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 third quarter of 2010
averaged approximately 85,000 bbl/d, compared to approximately
52,000 bbl/d for the third quarter of 2009 and approximately 96,000
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 has received approval from regulators to commence
steaming on the next cycle.
The next planned phase of the Company's In Situ Oil Sands Assets
expansion is the Kirby Project. Currently the Company is proceeding
with the detailed engineering and design work. During the third
quarter of 2010, the Company received final regulatory approval for
Phase 1 of the Project. Subsequent to September 30, 2010 the
Company's Board of Directors sanctioned Kirby Phase 1. Construction
is targeted to commence in the fourth quarter of 2010, with first
steam targeted in 2013.
Development of new pads and tertiary recovery conversion
projects at Pelican Lake continued as expected throughout the third
quarter of 2010. Drilling included 39 horizontal wells in the third
quarter. The response from the water and polymer flood projects
continues to be positive. Pelican Lake production averaged
approximately 38,000 bbl/d for the third quarter of 2010, compared
to approximately 37,000 bbl/d for the third quarter of 2009 and the
prior quarter.
For the fourth quarter of 2010, the Company's overall planned
drilling activity in North America is expected to be comprised of
20 net natural gas wells and 351 net crude oil wells, excluding
stratigraphic and service wells.
Oil Sands Mining and Upgrading
Phase 2/3 spending during the third quarter continued to be
focused on construction of the third Ore Preparation Plant,
additional product tankage, hydro-transport, the butane treatment
unit and the sulphur recovery unit.
North Sea
In the third quarter of 2010, the Company continued drilling on
the Ninian South Platform, with 0.9 net injection wells drilled in
the quarter. The Company continues to focus on developing and high
grading its inventory of drilling locations for future
execution.
Offshore West Africa
During the third quarter of 2010, the final well on Platform B
at the Olowi Field was completed and drilling commenced on Platform
A. Drilling continued with 0.9 net crude oil wells completed during
the quarter. The Company achieved first crude oil production at
Platform A in the fourth quarter of 2010.
At Espoir the facilities upgrades were completed during the
second quarter. The associated production uplift from the upgrades
is now anticipated in the fourth quarter of 2010.
LIQUIDITY AND CAPITAL RESOURCES
Sep 30 Jun 30 Dec 31 Sep 30
($ millions, except ratios) 2010 2010 2009 2009
----------------------------------------------------------------------------
Working capital (deficit) (1) $ (515) $ (245) $ (514) $ (396)
Long-term debt (2) $ 8,490 $ 9,335 $ 9,658 $10,557
Share capital $ 3,015 $ 3,006 $ 2,834 $ 2,827
Retained earnings 18,502 18,066 16,696 16,299
Accumulated other comprehensive (loss)
income (97) (13) (104) (61)
----------------------------------------------------------------------------
Shareholders' equity $21,420 $21,059 $ 19,426 $19,065
Debt to book capitalization (2) (3) 28% 31% 33% 36%
Debt to market capitalization (2) (4) 18% 20% 19% 21%
After tax return on average common
shareholders' equity (5) 13% 13% 8% 16%
After tax return on average capital
employed (2) (6) 10% 10% 6% 10%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 September 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 September 30, 2010, the Company had $3,067 million of
available credit under its bank credit facilities.
Long-term debt was $8,490 million at September 30, 2010,
resulting in a debt to book capitalization ratio of 28% (June 30,
2010 - 31%; December 31, 2009 - 33%; September 30, 2009 - 36%).
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 and 2011 at prices that protect investment
returns to ensure ongoing balance sheet strength and the completion
of its capital expenditure programs. Further details related to the
Company's long-term debt at September 30, 2010 are discussed in
note 4 to the Company's unaudited interim consolidated financial
statements.
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 September 30,
2010, in accordance with the policy, approximately 32% of budgeted
crude oil volumes and approximately 18% of budgeted natural gas
volumes were hedged using collars for the remainder of 2010, and
approximately 5% of budgeted crude oil volumes were hedged using
collars for 2011. Subsequent to September 30, 2010, the Company
entered into 100,000 bbl/d of US$70 WTI put options for the period
January to December 2011 for a total cost of US$106 million, and
27,000 bbl/d of US$70 - US$102.14 WTI collars for the period
January to December 2011.
Further details related to the Company's commodity related
derivative financial instruments outstanding at September 30, 2010
are discussed in note 11 to the Company's unaudited interim
consolidated financial statements.
Share capital
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 with such subdivision
taking effect in May 2010. All common share, per common share, and
stock option amounts have been restated to reflect the share
split.
As at September 30, 2010, there were 1,087,651,000 common shares
outstanding and 58,034,000 stock options outstanding. As at
November 2, 2010, the Company had 1,088,133,000 common shares
outstanding and 57,207,000 stock options outstanding.
In March 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 November 2, 2010,
2,000,000 common shares had been purchased for cancellation at an
average price of $33.77 per common share, for a total cost of $68
million.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. As at September 30, 2010, no entities were
consolidated under the Canadian Institute of Chartered Accountants
("CICA") Handbook Accounting Guideline 15, "Consolidation of
Variable Interest Entities". The following table summarizes the
Company's commitments as at September 30, 2010:
Remaining
($ millions) 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 58 $ 220 $ 193 $ 167 $ 163 $ 1,085
Offshore equipment
operating leases $ 42 $ 135 $ 102 $ 100 $ 101 $ 258
Offshore drilling $ 11 $ 8 $ - $ - $ - $ -
Asset retirement
obligations (1) $ 4 $ 24 $ 21 $ 31 $ 39 $ 6,537
Long-term debt (2) $ 400 $ 412 $ 360 $ 812 $ 360 $ 5,344
Interest expense (3)$ 89 $ 442 $ 406 $ 364 $ 344 $ 4,691
Office leases $ 7 $ 27 $ 28 $ 29 $ 29 $ 391
Other $ 87 $ 74 $ 28 $ 18 $ 16 $ 38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $814 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 September 30, 2010.
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is defendant and plaintiff in a number of legal
actions arising from the Company's normal operations. 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
Canadian GAAP 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
September 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. As certain IFRS standards are
expected to change prior to adoption in 2011, the Company will
continue to update its IFRS conversion project to recognize new and
amended accounting standards.
The Company has identified, developed and tested systems and
accounting and reporting 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.
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 depleted 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 expected increase 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 expected increase 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 expected
increase 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 expected
increase 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 will 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 expected decrease in
the net 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.
IFRS Transitional Impacts
Giving effect to the above-noted transitional impacts, the
Company estimates that on adoption of IFRS, total Shareholders'
Equity as at January 1, 2010 will decrease by less than 4% compared
to the balance previously determined under Canadian GAAP, resulting
in a marginal increase in the Company's debt to book capitalization
to 34% from 33%. Further, on adoption of IFRS, the Company does not
anticipate any significant differences in cash flow from operations
as would have been previously reported. Readers are cautioned that
these estimates are subject to change, should underlying IFRS
standards be revised prior to the final release of the Company's
January 1, 2010 transitional balance sheet.
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 third 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
Cash flow flow from Net
from operations Net earnings
operations (per common earnings (per common
($ millions) share, basic) ($ millions) share, basic)
----------------------------------------------------------------------------
Price changes
Crude oil - WTI
US$1.00/bbl (1)
Excluding financial
derivatives $ 129 $ 0.12 $ 99 $ 0.09
Including financial
derivatives $ 125 $ 0.11 $ 96 $ 0.09
Natural gas -
AECO C$0.10/mcf (1)
Excluding financial
derivatives $ 35 $ 0.03 $ 26 $ 0.02
Including financial
derivatives $ 36 $ 0.03 $ 27 $ 0.02
Volume changes
Crude oil - 10,000
bbl/d $ 166 $ 0.15 $ 95 $ 0.09
Natural gas - 10 mmcf/d $ 9 $ 0.01 $ - $ -
Foreign currency rate
change
$0.01 change in US$ (1)
Including financial
derivatives $99 - 101 $ 0.09 $35 - 36 $ 0.03
Interest rate change
- 1% $ 5 $ 0.01 $ 5 $ 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
Sep 30 Dec 31
(millions of Canadian dollars, unaudited) 2010 2009
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 27 $ 13
Accounts receivable 1,246 1,148
Inventory, prepaids and other 582 584
Future income tax 5 146
----------------------------------------------------------------------------
1,860 1,891
Property, plant and equipment (note 13) 40,035 39,115
Other long-term assets (note 3) 30 18
----------------------------------------------------------------------------
$ 41,925 $ 41,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 274 $ 240
Accrued liabilities 1,891 1,522
Current portion of other long-term
liabilities (note 5) 210 643
----------------------------------------------------------------------------
2,375 2,405
Long-term debt (note 4) 8,490 9,658
Other long-term liabilities (note 5) 1,817 1,848
Future income tax 7,823 7,687
----------------------------------------------------------------------------
20,505 21,598
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 7) 3,015 2,834
Retained earnings 18,502 16,696
Accumulated other comprehensive loss (note 8) (97) (104)
----------------------------------------------------------------------------
21,420 19,426
----------------------------------------------------------------------------
$ 41,925 $ 41,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (note 12)
Consolidated Statements of Earnings
(millions of Canadian dollars, Three Months Ended Nine Months Ended
except per common Sep 30 Sep 30 Sep 30 Sep 30
share amounts, unaudited) 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue $ 3,341 $ 2,823 $ 10,535 $ 7,759
Less: royalties (313) (240) (990) (651)
----------------------------------------------------------------------------
Revenue, net of royalties 3,028 2,583 9,545 7,108
----------------------------------------------------------------------------
Expenses
Production 867 813 2,573 2,168
Transportation and blending 350 241 1,323 867
Depletion, depreciation and
amortization 851 673 2,458 1,983
Asset retirement obligation
accretion (note 5) 28 24 80 67
Administration 43 38 157 132
Stock-based compensation expense
(recovery) (note 5) 18 172 (42) 268
Interest, net 109 118 329 299
Risk management activities (note 11) 22 74 (320) 552
Foreign exchange gain (64) (424) (68) (547)
----------------------------------------------------------------------------
2,224 1,729 6,490 5,789
----------------------------------------------------------------------------
Earnings before taxes 804 854 3,055 1,319
Taxes other than income tax 21 23 94 74
Current income tax expense (note 6) 163 90 542 294
Future income tax expense (recovery)
(note 6) 40 83 306 (174)
----------------------------------------------------------------------------
Net earnings $ 580 $ 658 $ 2,113 $ 1,125
----------------------------------------------------------------------------
Net earnings per common share
(note 10)
Basic and diluted $ 0.53 $ 0.61 $ 1.94 $ 1.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Shareholders' Equity
Nine Months Ended
Sep 30 Sep 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 83 21
Previously recognized liability on stock
options exercised for common shares 104 38
Purchase of common shares under Normal Course
Issuer Bid (6) -
----------------------------------------------------------------------------
Balance - end of period 3,015 2,827
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period 16,696 15,344
Net earnings 2,113 1,125
Purchase of common shares under Normal Course
Issuer Bid (note 7) (62) -
Dividends on common shares (note 7) (245) (170)
----------------------------------------------------------------------------
Balance - end of period 18,502 16,299
----------------------------------------------------------------------------
Accumulated other comprehensive (loss) income
(note 8)
Balance - beginning of period (104) 262
Other comprehensive income (loss), net of taxes 7 (323)
----------------------------------------------------------------------------
Balance - end of period (97) (61)
----------------------------------------------------------------------------
Shareholders' equity $ 21,420 $ 19,065
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income
Three Months Ended Nine Months Ended
(millions of Canadian dollars, Sep 30 Sep 30 Sep 30 Sep 30
unaudited) 2010 2009 2010 2009
----------------------------------------------------------------------------
Net earnings $ 580 $ 658 $ 2,113 $ 1,125
----------------------------------------------------------------------------
Net change in derivative financial
instruments designated as cash flow
hedges
Unrealized (loss) gain during the
period, net of taxes of
$17 million (2009 - $nil)
- three months ended;
$5 million (2009 - $4 million)
- nine months ended (62) 6 22 (24)
Reclassification to net earnings,
net of taxes of $nil (2009 - $nil)
- three months ended;
$1 million (2009 - $1 million)
- nine months ended (1) (2) (4) (10)
----------------------------------------------------------------------------
(63) 4 18 (34)
Foreign currency translation
adjustment
Translation of net investment (21) (140) (11) (289)
----------------------------------------------------------------------------
Other comprehensive (loss) income,
net of taxes (84) (136) 7 (323)
----------------------------------------------------------------------------
Comprehensive income $ 496 $ 522 $ 2,120 $ 802
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months Ended Nine Months Ended
(millions of Canadian dollars, Sep 30 Sep 30 Sep 30 Sep 30
unaudited) 2010 2009 2010 2009
----------------------------------------------------------------------------
Operating activities
Net earnings $ 580 $ 658 $ 2,113 $ 1,125
Non-cash items
Depletion, depreciation and
amortization 851 673 2,458 1,983
Asset retirement obligation
accretion 28 24 80 67
Stock-based compensation expense
(recovery) 18 172 (42) 268
Unrealized risk management loss
(gain) 92 274 (198) 1,683
Unrealized foreign exchange gain (75) (391) (60) (573)
Deferred petroleum revenue tax
expense 11 13 23 8
Future income tax expense
(recovery) 40 83 306 (174)
Other 4 8 (12) 2
Abandonment expenditures (45) (12) (99) (31)
Net change in non-cash working
capital 117 58 212 (55)
----------------------------------------------------------------------------
1,621 1,560 4,781 4,303
----------------------------------------------------------------------------
Financing activities
Repayment of bank credit facilities,
net (651) (798) (1,094) (1,304)
Repayment of senior unsecured notes - - - (34)
Issue of common shares on exercise
of stock options 9 3 83 21
Purchase of common shares under
Normal Course Issuer Bid (68) - (68) -
Dividends on common shares (82) (57) (220) (168)
Net change in non-cash working
capital (37) (44) (36) (48)
----------------------------------------------------------------------------
(829) (896) (1,335) (1,533)
----------------------------------------------------------------------------
Investing activities
Expenditures on property, plant, and
equipment (869) (588) (3,463) (2,305)
Net proceeds on sale of property,
plant and equipment - 26 3 33
----------------------------------------------------------------------------
Net expenditures on property, plant
and equipment (869) (562) (3,460) (2,272)
Net change in non-cash working
capital 85 (113) 28 (511)
----------------------------------------------------------------------------
(784) (675) (3,432) (2,783)
----------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents 8 (11) 14 (13)
Cash and cash equivalents -
beginning of period 19 25 13 27
----------------------------------------------------------------------------
Cash and cash equivalents - end of
period $ 27 $ 14 $ 27 $ 14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 150 $ 157 $ 382 $ 433
Taxes paid
Taxes other than income tax $ 75 $ 34 $ 69 $ 34
Current income tax $ 33 $ 87 $ 45 $ 128
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 1601
carries forward existing guidance on the preparation of
consolidated financial statements, other than non-controlling
interests. Section 1602 provides guidance on the treatment of
non-controlling interests after acquisition.
3. OTHER LONG-TERM ASSETS
Sep 30 Dec 31
2010 2009
----------------------------------------------------------------------------
Other $ 30 $ 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. LONG-TERM DEBT
Sep 30 Dec 31
2010 2009
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities (bankers' acceptances) $ 814 $ 1,897
Medium-term notes 1,200 1,200
----------------------------------------------------------------------------
2,014 3,097
----------------------------------------------------------------------------
US dollar denominated debt
US dollar debt securities (2010 and 2009 - US$6,300
million) 6,488 6,594
Less: original issue discount on US dollar debt
securities (1) (21) (22)
----------------------------------------------------------------------------
6,467 6,572
Fair value of interest rate swaps on US dollar debt
securities (2) 54 38
----------------------------------------------------------------------------
6,521 6,610
----------------------------------------------------------------------------
Long-term debt before transaction costs 8,535 9,707
Less: transaction costs (1) (3) (45) (49)
----------------------------------------------------------------------------
$ 8,490 $ 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 $54 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 September 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 September 30, 2010 was 1.6% (December
31, 2009 - 0.8%), and on total long-term debt outstanding for the
three months ended September 30, 2010 was 4.9% (December 31, 2009 -
4.5%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $312 million, including $235
million related to Horizon, were outstanding at September 30, 2010.
Subsequent to September 30, 2010, the financial guarantee related
to Horizon was reduced to $205 million.
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
Sep 30 Dec 31
2010 2009
----------------------------------------------------------------------------
Asset retirement obligations $ 1,601 $ 1,610
Stock-based compensation 210 392
Risk management (note 11) 110 309
Other 106 180
----------------------------------------------------------------------------
2,027 2,491
Less: current portion 210 643
----------------------------------------------------------------------------
$ 1,817 $ 1,848
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset retirement obligations
At September 30, 2010, the Company's total estimated
undiscounted costs to settle its asset retirement obligations were
approximately $6,656 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:
Nine Months Year
Ended Ended
Sep 30, 2010 Dec 31, 2009
----------------------------------------------------------------------------
Balance - beginning of period $ 1,610 $ 1,064
Liabilities incurred (1) 9 299
Liabilities acquired 8 -
Liabilities settled (99) (48)
Asset retirement obligation accretion 80 90
Revision of estimates 4 276
Foreign exchange (11) (71)
----------------------------------------------------------------------------
Balance - end of period $ 1,601 $ 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.
Nine Months Year
Ended Ended
Sep 30, 2010 Dec 31, 2009
----------------------------------------------------------------------------
Balance - beginning of period $ 392 $ 171
Stock-based compensation (recovery) expense (42) 355
Cash payments for options surrendered (39) (94)
Transferred to common shares (104) (42)
Capitalized to Oil Sands Mining and Upgrading 3 2
----------------------------------------------------------------------------
Balance - end of period 210 392
Less: current portion 164 365
----------------------------------------------------------------------------
$ 46 $ 27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. INCOME TAXES
The provision for income taxes is as follows:
Three Months Ended Nine Months Ended
Sep 30 Sep 30 Sep 30 Sep 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Current income tax - North
America (1) $ 115 $ 7 $ 383 $ 17
Current income tax - North Sea 23 55 119 218
Current income tax - Offshore
West Africa 25 28 40 59
----------------------------------------------------------------------------
Current income tax expense 163 90 542 294
Future income tax expense (recovery) 40 83 306 (174)
----------------------------------------------------------------------------
Income tax expense $ 203 $ 173 $ 848 $ 120
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
Nine Months Ended Sep 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 5,011 83
Previously recognized liability on stock
options exercised for common shares - 104
Cancellation of common shares (14) -
Purchase of common shares under Normal
Course Issuer Bid (2,000) (6)
----------------------------------------------------------------------------
Balance - end of period 1,087,651 $ 3,015
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 September 30, 2010, the Company purchased
2,000,000 common shares at an average price of $33.77 per common
share, for a total cost of $68 million. Retained earnings was
reduced by $62 million, representing the excess of the purchase
price of the common shares over their average carrying value.
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 in May 2010. All common share,
per common share, and stock option amounts have been restated to
reflect the share split.
Nine Months Ended Sep 30, 2010
Weighted
average
Stock options exercise
Stock options (thousands) (1) price (1)
----------------------------------------------------------------------------
Outstanding - beginning of period 64,211 $ 29.27
Granted 3,340 $ 35.93
Surrendered for cash settlement (2,319) $ 19.48
Exercised for common shares (5,011) $ 16.58
Forfeited (2,187) $ 32.19
----------------------------------------------------------------------------
Outstanding - end of period 58,034 $ 31.03
----------------------------------------------------------------------------
Exercisable - end of period 19,189 $ 30.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Restated to reflect two-for-one common share split in May 2010.
8. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income (loss), net of
taxes, were as follows:
Sep 30 Sep 30
2010 2009
----------------------------------------------------------------------------
Derivative financial instruments designated as cash
flow hedges $ 94 $ 85
Foreign currency translation adjustment (191) (146)
----------------------------------------------------------------------------
$ (97) $ (61)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 28%.
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.
Sep 30 Dec 31
2010 2009
----------------------------------------------------------------------------
Long-term debt $ 8,490 $ 9,658
Total shareholders' equity $ 21,420 $ 19,426
Debt to book capitalization 28% 33%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. NET EARNINGS PER COMMON SHARE
Three Months Ended Nine Months Ended
Sep 30 Sep 30 Sep 30 Sep 30
2010 2009 (1) 2010 2009 (1)
----------------------------------------------------------------------------
Weighted average common shares
outstanding (thousands)
- basic and diluted 1,088,989 1,084,274 1,087,794 1,083,597
----------------------------------------------------------------------------
Net earnings - basic and
diluted $ 580 $ 658 $ 2,113 $ 1,125
----------------------------------------------------------------------------
Net earnings per common share
- basic and diluted $ 0.53 $ 0.61 $ 1.94 $ 1.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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:
Sep 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 $ - $ 27 $ -
Accounts receivable 1,246 - -
Other long-term assets - - -
Accounts payable - - (274)
Accrued liabilities - - (1,891)
Other long-term liabilities - (110) (95)
Long-term debt - - (8,490)
----------------------------------------------------------------------------
$ 1,246 $ (83) $ (10,750)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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:
Sep 30, 2010
----------------------------------------------------------------------------
Carrying Value Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term assets $ - $ - $ -
Other long-term liabilities (110) - (110)
Fixed-rate long-term debt(2)(3) (7,676) (8,675) -
----------------------------------------------------------------------------
$ (7,786) $ (8,675) $ (110)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $54 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:
Nine Months Ended Year Ended
Sep 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 198 (1,991)
- Interest expense 19 (25)
- Foreign exchange (30) (338)
- Other comprehensive income 12 (78)
- Settlement of interest rate swaps and other - 4
----------------------------------------------------------------------------
Balance - end of period (110) (309)
Less: current portion (18) (182)
----------------------------------------------------------------------------
$ (92) $ (127)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net (gains) losses from risk management activities were as follows:
Three Months Ended Nine Months Ended
Sep 30 Sep 30 Sep 30 Sep 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Net realized risk management gain $ (70) $ (200) $ (122) $ (1,131)
Net unrealized risk management
loss (gain) 92 274 (198) 1,683
----------------------------------------------------------------------------
$ 22 $ 74 $ (320) $ 552
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 September 30, 2010, the Company had the
following net derivative financial instruments outstanding:
i) Sales Contracts
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Crude oil (1)
Crude oil price
collars (2) Oct 2010-Dec 2010 50,000 bbl/d US$60.00-US$75.08 WTI
Oct 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
Jan 2011-Dec 2011 23,000 bbl/d US$70.00-US$102.33 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to September 30, 2010, the Company entered into 100,000 bbl/d
of US$70 WTI put options for the period January to December 2011 for a
total cost of US$106 million.
(2) Subsequent to September 30, 2010, the Company entered into an additional
27,000 bbl/d of US$70 - US$102.14 WTI collars for the period January to
December 2011.
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Natural gas
Natural gas price
collars Oct 2010-Dec 2010 220,000 GJ/d C$6.00 - C$8.00 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ii) Purchase Contracts
Weighted
average Floating
Remaining term Volume fixed rate 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 September 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 September 30,
2010, the Company had the following interest rate swap contracts
outstanding:
Remaining term Amount Fixed rate Floating rate
----------------------------------------------------------------------------
Interest rate
Swaps fixed to
floating (1) Oct 2010 - Dec 2014 US$350 4.90% LIBOR (2) + 0.38%
Swaps floating
to fixed Oct 2010 - Feb 2011 C$300 1.0680% 3 month CDOR (3)
Oct 2010 - Feb 2012 C$200 1.4475% 3 month CDOR (3)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to September 30, 2010, the Company unwound US$350 million of
4.9% interest rate swaps for proceeds of US$54 million.
(2) London Interbank Offered Rate
(3) Canadian Dealer Offered Rate
All fixed to floating interest rate related derivative financial
instruments designated as hedges at September 30, 2010 were
classified as fair value hedges.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated long-term
debt and working capital. The Company is also exposed to foreign
currency exchange rate risk on transactions conducted in other
currencies in its subsidiaries and in the carrying value of its
self-sustaining foreign subsidiaries. The Company periodically
enters into cross currency swap contracts and foreign currency
forward contracts to manage known currency exposure on US dollar
denominated long-term debt and working capital. The cross currency
swap contracts require the periodic exchange of payments with the
exchange at maturity of notional principal amounts on which the
payments are based. At September 30, 2010 the Company had the
following cross currency swap contracts outstanding:
Exchange Interest Interest
rate rate rate
Remaining term Amount (US$/C$) (US$) (C$)
----------------------------------------------------------------------------
Cross
currency
Swaps Oct 2010 - Jul 2011 US$100 0.999 6.70% 7.64%
Oct 2010 - Aug 2016 US$250 1.116 6.00% 5.40%
Oct 2010 - May 2017 US$1,100 1.170 5.70% 5.10%
Oct 2010 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency swap derivative financial instruments
designated as hedges at September 30, 2010 were classified as cash
flow hedges.
In addition to the cross currency swap contracts noted above, at
September 30, 2010 the Company had US$1,167 million of foreign
currency forward contracts outstanding, with terms of approximately
30 days or less.
Financial instrument sensitivities
The following table summarizes the annualized sensitivities of
the Company's net earnings and other comprehensive income to
changes in the fair value of financial instruments outstanding as
at September 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 $ (6) $ -
Decrease WTI US$1.00/bbl $ 6 $ -
Increase AECO C$0.10/mcf $ (1) $ 3
Decrease AECO C$0.10/mcf $ 1 $ (3)
Interest rate risk
Increase interest rate 1% $ (4) $ 9
Decrease interest rate 1% $ 4 $ (16)
Foreign currency exchange rate risk
Increase exchange rate by US$0.01 $ (28) $ -
Decrease exchange rate by US$0.01 $ 28 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) Credit risk
Credit risk is the risk that a party to a financial instrument
will cause a financial loss to the Company by failing to discharge
an obligation.
Counterparty credit risk management
The Company's accounts receivable are mainly with customers in
the crude oil and natural gas industry and are subject to normal
industry credit risks. The Company manages these risks by reviewing
its exposure to individual companies on a regular basis and where
appropriate, ensures that parental guarantees or letters of credit
are in place to minimize the impact in the event of default. At
September 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
September 30, 2010, the Company had net risk management assets of
$12 million with specific counterparties related to derivative
financial instruments (December 31, 2009 - $7 million).
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter
difficulty in meeting obligations associated with financial
liabilities.
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating
activities, available credit facilities, and access to debt capital
markets, to meet obligations as they become due. Due to
fluctuations in the timing of the receipt and/or disbursement of
operating cash flows, the Company believes it has adequate bank
credit facilities to provide liquidity.
The maturity dates for financial liabilities are as follows:
Less than 1 to less than 2 to less than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts
payable $ 274 $ - $ - $ -
Accrued
liabilities $ 1,891 $ - $ - $ -
Risk
management $ 18 $ 20 $ 30 $ 42
Other
long-term
liabilities $ 28 $ 23 $ 44 $ -
Long-term
debt (1) $ 812 $ - $ 1,932 $ 4,944
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $814 million of revolving
bank credit facilities due to the extendable nature of the facilities.
12. COMMITMENTS
As at September 30, 2010, the Company had committed to certain payments as
follows:
Remaining
2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Product
transportation
and pipeline $ 58 $ 220 $ 193 $ 167 $ 163 $ 1,085
Offshore equipment
operating leases $ 42 $ 135 $ 102 $ 100 $ 101 $ 258
Offshore drilling $ 11 $ 8 $ - $ - $ - $ -
Asset retirement
obligations (1) $ 4 $ 24 $ 21 $ 31 $ 39 $ 6,537
Office leases $ 7 $ 27 $ 28 $ 29 $ 29 $ 391
Other $ 87 $ 74 $ 28 $ 18 $ 16 $ 38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Months Nine Months Three Months Nine Months
(millions of Ended Ended Ended Ended
Canadian dollars, Sep 30 Sep 30 Sep 30 Sep 30
unaudited) 2010 2009 2010 2009 2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented revenue 2,221 1,906 7,197 5,753 224 220 755 666
Less: royalties (268) (196) (882) (581) - - (1) (1)
----------------------------------------------------------------------------
Segmented revenue,
net of royalties 1,953 1,710 6,315 5,172 224 220 754 665
----------------------------------------------------------------------------
Segmented expenses
Production 422 436 1,259 1,357 123 90 280 273
Transportation and
blending 344 237 1,305 867 2 1 7 6
Depletion,
depreciation and
amortization 585 512 1,728 1,573 70 53 222 196
Asset retirement
obligation
accretion 11 10 33 30 9 6 25 19
Realized risk
management
activities (70) (130) (122) (802) - (70) - (329)
----------------------------------------------------------------------------
Total segmented
expenses 1,292 1,065 4,203 3,025 204 80 534 165
----------------------------------------------------------------------------
Segmented earnings
before the
following 661 645 2,112 2,147 20 140 220 500
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Stock-based
compensation expense
(recovery)
Interest, net
Unrealized risk
management
activities
Foreign exchange
gain
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Taxes other than
income tax
Current income tax
expense
Future income tax
expense (recovery)
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Conventional Crude Oil and Natural Gas
Offshore West Africa Total Conventional
Three Months Nine Months Three Months Nine Months
(millions of Ended Ended Ended Ended
Canadian dollars, Sep 30 Sep 30 Sep 30 Sep 30
unaudited) 2010 2009 2010 2009 2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented revenue 290 223 623 606 2,735 2,349 8,575 7,025
Less: royalties (25) (29) (40) (59) (293) (225) (923) (641)
----------------------------------------------------------------------------
Segmented revenue,
net of royalties 265 194 583 547 2,442 2,124 7,652 6,384
----------------------------------------------------------------------------
Segmented expenses
Production 52 43 121 116 597 569 1,660 1,746
Transportation and
blending 1 1 1 1 347 239 1,313 874
Depletion,
depreciation and
amortization 108 45 232 133 763 610 2,182 1,902
Asset retirement
obligation
accretion 2 1 5 3 22 17 63 52
Realized risk
management
activities - - - - (70) (200) (122)(1,131)
----------------------------------------------------------------------------
Total segmented
expenses 163 90 359 253 1,659 1,235 5,096 3,443
----------------------------------------------------------------------------
Segmented earnings
before the
following 102 104 224 294 783 889 2,556 2,941
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Stock-based
compensation expense
(recovery)
Interest, net
Unrealized risk
management
activities
Foreign exchange
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 Months Nine Months Three Months Nine Months
(millions of Ended Ended Ended Ended
Canadian dollars, Sep 30 Sep 30 Sep 30 Sep 30
unaudited) 2010 2009 2010 2009 2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented revenue 604 469 1,949 761 19 18 59 54
Less: royalties (20) (15) (67) (18) - - - -
----------------------------------------------------------------------------
Segmented revenue,
net of royalties 584 454 1,882 743 19 18 59 54
----------------------------------------------------------------------------
Segmented expenses
Production 268 242 904 424 4 4 16 14
Transportation and
blending 15 13 46 27 - - - -
Depletion,
depreciation and
amortization 86 66 270 104 2 2 6 6
Asset retirement
obligation
accretion 6 7 17 15 - - - -
Realized risk
management
activities - - - - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 375 328 1,237 570 6 6 22 20
----------------------------------------------------------------------------
Segmented earnings
before the
following 209 126 645 173 13 12 37 34
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Stock-based
compensation
expense (recovery)
Interest, net
Unrealized risk
management
activities
Foreign exchange
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 Months Nine Months Three Months Nine Months
(millions of Ended Ended Ended Ended
Canadian dollars, Sep 30 Sep 30 Sep 30 Sep 30
unaudited) 2010 2009 2010 2009 2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented revenue (17) (13) (48) (81) 3,341 2,823 10,535 7,759
Less: royalties - - - 8 (313) (240) (990) (651)
----------------------------------------------------------------------------
Segmented revenue,
net of royalties (17) (13) (48) (73) 3,028 2,583 9,545 7,108
----------------------------------------------------------------------------
Segmented expenses
Production (2) (2) (7) (16) 867 813 2,573 2,168
Transportation and
blending (12) (11) (36) (34) 350 241 1,323 867
Depletion,
depreciation and
amortization - (5) - (29) 851 673 2,458 1,983
Asset retirement
obligation
accretion - - - - 28 24 80 67
Realized risk
management
activities - - - - (70) (200) (122)(1,131)
----------------------------------------------------------------------------
Total segmented
expenses (14) (18) (43) (79) 2,026 1,551 6,312 3,954
----------------------------------------------------------------------------
Segmented earnings
before the
following (3) 5 (5) 6 1,002 1,032 3,233 3,154
----------------------------------------------------------------------------
Non-segmented
expenses
Administration 43 38 157 132
Stock-based
compensation
expense (recovery) 18 172 (42) 268
Interest, net 109 118 329 299
Unrealized risk
management
activities 92 274 (198) 1,683
Foreign exchange
gain (64) (424) (68) (547)
----------------------------------------------------------------------------
Total non-segmented
expenses 198 178 178 1,835
----------------------------------------------------------------------------
Earnings before
taxes 804 854 3,055 1,319
Taxes other than
income tax 21 23 94 74
Current income tax
expense 163 90 542 294
Future income tax
expense (recovery) 40 83 306 (174)
----------------------------------------------------------------------------
Net earnings 580 658 2,113 1,125
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net additions to property, plant and equipment
Nine Months Ended
Sep 30, 2010
----------------------------------------------------------------------------
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 2,769 $ 17 $ 2,786
North Sea 111 4 115
Offshore West Africa 204 (2) 202
Other 2 - 2
Oil Sands Mining and Upgrading (2) 357 5 362
Midstream 4 - 4
Head office 13 - 13
----------------------------------------------------------------------------
$ 3,460 $ 24 $ 3,484
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine Months Ended
Sep 30, 2009
----------------------------------------------------------------------------
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 1,227 $ (4) $ 1,223
North Sea 120 - 120
Offshore West Africa 464 51 515
Other 1 - 1
Oil Sands Mining and Upgrading (2) 446 275 721
Midstream 5 - 5
Head office 9 - 9
----------------------------------------------------------------------------
$ 2,272 $ 322 $ 2,594
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
Sep 30 Dec 31 Sep 30 Dec 31
2010 2009 2010 2009
----------------------------------------------------------------------------
Segmented assets
North America $ 22,908 $ 21,834 $ 23,932 $ 22,994
North Sea 1,654 1,812 1,787 1,968
Offshore West Africa 1,795 1,883 1,985 2,033
Other 30 28 50 42
Oil Sands Mining and Upgrading 13,387 13,295 13,818 13,621
Midstream 201 203 293 306
Head office 60 60 60 60
----------------------------------------------------------------------------
$ 40,035 $ 39,115 $ 41,925 $ 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 nine months ended September 30,
2010, pre-tax interest of $19 million was capitalized to Oil Sands
Mining and Upgrading (September 30, 2009 - $98 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 September 30,
2010:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 8.6x
Cash flow from operations (2) 16.0x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, November 4, 2010. The North American
conference call number is 1-800-769-8320 and the outside North
American conference call number is 001-416-695-6616. Please call in
about 10 minutes before the starting time in order to be patched
into the call. The conference call will also be broadcast live on
the internet and may be accessed through the Canadian Natural
website at www.cnrl.com.
A taped rebroadcast will be available until 6:00 p.m. Mountain
Time, Thursday, November 11, 2010. To access the postview in North
America, dial 1-800-408-3053. Those outside of North America, dial
001-416-695-5800. The passcode to use is 3858142.
WEBCAST
This call is being webcast and can be accessed on Canadian
Natural's website at 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 Canada (403) 514-7777 ir@cnrl.com
www.cnrl.com
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