Canadian Natural Resources Limited (TSX:CNQ) (NYSE:CNQ)
Commenting on second quarter results, Canadian Natural's Chairman, Allan Markin
stated, "Our skilled and experienced technical, operational and financial teams,
along with our balanced assets continue to deliver. We generated solid cash flow
results even while production at Horizon remained suspended in the second
quarter. We maintain a safe, responsible, efficient operating environment which
allows us to effectively execute on our plans. With the Horizon rebuild and
repairs now essentially complete and commissioning underway, we look forward to
additional cash flow generation for the remainder of 2011."
John Langille, Vice-Chairman of Canadian Natural continued, "We maintain
sufficient available liquidity which will sustain our operations in the short,
medium and long term. We continue to take advantage of our diverse asset base
through effective capital allocation to higher return projects. Our favorable
debt to book capital ratio of 29% supports our future growth strategy and our
ability to be flexible in our decision making and capital allocation."
Steve Laut, President of Canadian Natural stated, "Canadian Natural is
positioned to generate significant shareholder value going forward with
production at Horizon set to resume in the third quarter along with the solid
overall performance in the rest of the asset base so far in 2011. At Horizon,
we are committed to a disciplined execution strategy to achieve cost certainty
for expansions from the current 110,000 bbl/d of SCO capacity to 250,000 bbl/d
of SCO capacity. Our high quality, balanced asset base has allowed us to
allocate capital to the highest return projects and the business is set to
deliver significant free cash flow going forward."
QUARTERLY HIGHLIGHTS
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions, except as noted) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Net earnings $ 929 $ 46 $ 651 $ 975 $ 1,386
Per common share - basic $ 0.85 $ 0.04 $ 0.60 $ 0.89 $ 1.28
- diluted $ 0.84 $ 0.04 $ 0.60 $ 0.88 $ 1.27
Adjusted net earnings from
operations (1) $ 621 $ 228 $ 647 $ 849 $ 1,286
Per common share - basic $ 0.57 $ 0.21 $ 0.59 $ 0.78 $ 1.18
- diluted $ 0.56 $ 0.21 $ 0.59 $ 0.77 $ 1.17
Cash flow from operations (2) $ 1,548 $ 1,074 $ 1,629 $ 2,622 $ 3,136
Per common share - basic $ 1.41 $ 0.98 $ 1.50 $ 2.39 $ 2.89
- diluted $ 1.40 $ 0.97 $ 1.49 $ 2.37 $ 2.87
Capital expenditures, net of
dispositions $ 1,405 $ 1,694 $ 1,576 $ 3,099 $ 2,652
Daily production, before
royalties
Natural gas (MMcf/d) 1,240 1,256 1,237 1,248 1,231
Crude oil and NGLs (bbl/d) 349,915 356,988 443,045 353,433 424,757
Equivalent production (BOE/d) 556,539 566,231 649,195 561,359 629,982
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted net earnings from operations is a non-GAAP measure that the
Company utilizes to evaluate its performance. The derivation of this
measure is discussed in Management's Discussion and Analysis ("MD&A").
(2) Cash flow from operations is a non-GAAP measure that the Company
considers key as it demonstrates the Company's ability to fund capital
reinvestment and debt repayment. The derivation of this measure is
discussed in the MD&A.
-- In Q2/11 the Company's diverse assets continued to deliver while
Horizon repairs near completion. Production in all areas were within
previously issued guidance despite challenging conditions relating to
both forest fires and flooding in Western Canada. Solid cash flow
results continue to support the Company's strong financial position.
-- Total crude oil and NGLs production for Q2/11 was 349,915 bbl/d. Q2/11
crude oil production volumes decreased 21% from Q2/10 of 443,045 bbl/d
and 2% from Q1/11 of 356,988 bbl/d primarily due to the suspension of
production at Horizon, partially offset by the results of the impact of
a record primary heavy oil drilling program, continued pad additions at
Primrose, the cyclic nature of the Company's thermal in situ production
and acquisitions.
-- Crude oil and NGLs production in North America Exploration and
Production in Q2/11 was 295,715 bbl/d. Q2/11 crude oil and NGLs
production volumes increased 7% from Q2/10 levels of 275,584 bbl/d, and
increased 2% from Q1/11 levels of 290,130 bbl/d. The increase in volumes
in Q2/11 from Q2/10 was due to a record heavy oil drilling program,
continued pad additions at Primrose, the cyclic nature of the Company's
thermal in situ production and acquisitions.
-- Natural gas production for Q2/11 averaged 1,240 MMcf/d, comparable to
Q2/10 production of 1,237 MMcf/d and a 1% decrease from Q1/11 of 1,256
MMcf/d. Natural gas production in Q2/11 was comparable to Q2/10 as a
result of volumes from the Septimus Montney development in Northeast
British Columbia and from natural gas producing properties acquired in
2010 and 2011, offset by the strategic decision to allocate capital to
higher return crude oil projects.
-- Quarterly cash flow from operations was $1.55 billion compared to $1.63
billion for Q2/10 and $1.07 billion for Q1/11. The decrease in cash
flow from Q2/10 is primarily related to the suspension of production at
Horizon. The increase in Q2/11 cash flow from Q1/11 is primarily related
to higher crude oil and NGL netbacks, lower realized risk management
losses and lower net operating expenses at Horizon due to business
interruption insurance recoveries in Q2/11.
-- Adjusted net earnings from operations for Q2/11 was $621 million,
compared to adjusted net earnings of $647 million in Q2/10 and $228
million in Q1/11. The decrease in adjusted net earnings from Q2/10
primarily related to the suspension of production at Horizon. The
increase in adjusted net earnings in Q2/11 from Q1/11 was primarily due
to higher crude oil and NGL netbacks and lower realized risk management
losses.
-- A significant quarterly primary heavy crude oil drilling program, as
part of a targeted record drilling program in 2011, contributed to
record quarterly production in excess of 101,000 bbl/d in Q2/11. In
Q2/11, Canadian Natural drilled 134 net primary heavy crude oil wells.
The Company targets to drill a record 826 net primary heavy crude oil
wells in 2011 which will drive a targeted 13% annual production growth
in primary heavy crude oil. Primary heavy crude oil currently provides
the highest return on capital projects in the Company's portfolio.
-- International production in the North Sea slightly exceeded the
Company's previously issued guidance for Q2/11 due to strong performance
from the Ninian field. The North Sea and Offshore Africa provided cash
flow from operations in Q2/11 of approximately $235 million against
capital expenditures of $86 million. International operations provide
exposure to Brent oil pricing and the Company targets additional
significant free cash flow from the International operations in 2011.
-- Thermal in situ crude oil production exceeded 106,000 bbl/d in Q2/11 due
to the nature of the steaming and production cycles, continued pad
additions at Primrose and excellent well performance in the quarter.
Record monthly average production of 127,000 bbl/d in June 2011 in the
Company's thermal in situ assets contributed to the strong quarterly
production performance.
-- Construction at the Kirby South Phase 1 ("Kirby") 45,000 bbl/d capacity
Steam Assisted Gravity Drainage ("SAGD") project remains on cost and on
schedule. Kirby has targeted capital costs of $1.25 billion
and first steam-in is targeted for late 2013. As at Q2/11, the overall
project is 19% complete. All major equipment has been ordered and
drilling has commenced on schedule and on cost.
-- All necessary regulatory and operating approvals to recommence
operations at Horizon Oil Sands Mining and Upgrading have been received.
Fire rebuild and collateral damage repairs are essentially complete and
commissioning to commence operations started on August 2, 2011.
Commissioning is targeted to take between 2 and 3 weeks with ramp up to
full production design rates of 110,000 bbl/d of synthetic crude oil
("SCO") shortly thereafter.
-- Construction of the third Ore Preparation Plant ("OPP") at Horizon is
currently anticipated to be completed slightly below budget and on
schedule. Commissioning is currently targeted for early Q4/11 and is
expected to increase production reliability and result in higher plant
uptime at Horizon.
-- As part of Canadian Natural's disciplined execution strategy to achieve
cost certainty for a defined and stepped expansion at its Horizon
operation from the current 110,000 bbl/d to 250,000 bbl/d of SCO
capacity, the Company's Board of Directors has approved targeted
strategic expansion capital expenditures at Horizon for 2012 of
approximately $2 billion. It is expected that certain projects will be
advanced and contracts finalized in 2011 and 2012 such that the
execution of engineering, procurement and construction activities will
be undertaken in 2012 resulting in the above noted strategic expansion
capital expenditures.
-- The Company currently anticipates capital expenditures for 2012 will
range between $7 billion and $8 billion, including the targeted Horizon
strategic expansion capital expenditures.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its
activities in core regions where it can dominate the land base and
infrastructure. Land inventories are maintained to enable continuous
exploitation of play types and geological trends, greatly reducing overall
exploration risk. By dominating infrastructure, the Company is able to maximize
utilization of its production facilities, thereby increasing control over
production costs. Further, the Company maintains large project inventories and
production diversification among each of the commodities it produces; namely
natural gas, light/medium crude oil, primary heavy crude oil, Pelican Lake heavy
crude oil, bitumen (thermal oil), SCO and NGLs. A large diversified project
portfolio enables the effective allocation of capital to higher return
opportunities.
OPERATIONS REVIEW
Drilling activity (number of wells)
Six Months Ended Jun 30
2011 2010
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 471 456 356 335
Natural gas 39 35 63 55
Dry 22 21 17 16
----------------------------------------------------------------------------
Subtotal 532 512 436 406
Stratigraphic test / service wells 521 520 307 306
----------------------------------------------------------------------------
Total 1,053 1,032 743 712
----------------------------------------------------------------------------
Success rate (excluding stratigraphic test /
service wells) 96% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America Exploration and Production
North America natural gas
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Natural gas production (MMcf/d) 1,218 1,225 1,219 1,221 1,206
----------------------------------------------------------------------------
Net wells targeting natural gas 10 26 11 36 60
Net successful wells drilled 10 25 10 35 55
----------------------------------------------------------------------------
Success rate 100% 96% 91% 97% 92%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
-- Q2/11 North America natural gas production volumes were comparable to
Q2/10 and Q1/11 as a result of production from the Company's Septimus
Montney development in Northeast British Columbia and natural gas
volumes acquired in 2010 and 2011, offset by expected production
declines due to the allocation of capital to higher return crude oil
projects.
-- The Company's liquids rich Montney unconventional natural gas play at
Septimus continues to exceed expectations. During Q2/11 the Company
drilled 6 additional wells at Septimus as part of the planned 8 well
drilling program in 2011. Current production is approximately 60 MMcf/d
and 1,800 bbl/d of natural gas liquids. With additional infrastructure
liquid recovery is targeted to increase to approximately 50 bbl/MMcf or
3,000 bbl/d in Q4/11.
-- Planned drilling activity for Q3/11 includes 24 net natural gas wells.
North American crude oil and NGLs
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Crude oil and NGLs production
(bbl/d) 295,715 290,130 275,584 292,938 264,081
----------------------------------------------------------------------------
Net wells targeting crude oil 182 293 91 475 341
Net successful wells drilled 177 279 90 456 330
----------------------------------------------------------------------------
Success rate 97% 95% 99% 96% 97%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
-- Q2/11 North America crude oil and NGLs production increased 7% and 2%
from Q2/10 and Q1/11 levels respectively. The increase from the same
quarter last year reflects increases in growth in the Company's primary
heavy crude oil and thermal in situ operations.
-- The Company's focus on heavy and thermal in situ crude oil assets
resulted in record quarterly production in Q2/11. Heavy crude oil
differentials narrowed in Q2/11 compared to Q1/11, further increasing
already robust economics.
-- A significant quarterly primary heavy crude oil drilling program, as
part of a targeted record drilling program in 2011, contributed to
record quarterly production in excess of 101,000 bbl/d in Q2/11. In
Q2/11, Canadian Natural drilled 134 net primary heavy crude oil wells.
The Company targets to drill a record 826 net primary heavy crude oil
wells in 2011 which will drive a targeted 13% annual production growth
in primary heavy crude oil. Primary heavy crude oil currently provides
the highest return on capital projects in the Company's portfolio.
-- Pelican Lake production averaged approximately 35,000 bbl/d for Q2/11,
compared to approximately 37,000 bbl/d and 39,000 bbl/d for Q2/10 and
Q1/11 respectively. The decrease in production was a result of the
suspension of production due to forest fires which caused the Rainbow
pipeline system to be shut-in for several days. Polymer flood production
response is typically seen 9 to 24 months from injection of polymer and
production increases are expected in late 2011/early 2012. Production
response in the south portion of the crude oil pool is taking longer
than originally forecasted but is expected to ultimately result in
higher recovery rates. The planned 2011 expansion of the polymer flood
into new areas of the Pelican Lake pool will now occur later than
forecasted due to delays in receiving regulatory approvals. The Company
continues to work with regulators and anticipates all approvals to be
received in the Fall of 2011. These delays may impact production ramp up
timing in 2012. Canadian Natural targets to have close to 90% of the
field under polymer flood by 2015. Canadian Natural targets to have
close to 90% of the field under polymer flood by 2015.
-- Development of new pads at Primrose continue on track and contributed to
strong quarterly thermal in situ heavy crude oil production of over
106,000 bbl/d in Q2/11.
-- Production wells are currently being drilled at pads in Primrose East
and Primrose South as part of the Company's ongoing in situ development
program. The development costs for these pads is approximately $13,000
per flowing barrel of capacity.
-- Construction of Kirby continued in Q2/11 and targeted
timelines and capital expenditures remain on track. Drilling has
commenced on schedule and on cost. Fabrication of major equipment items
including the evaporators and steam generators is proceeding on
schedule. Significant construction milestones completed in Q2/11
included conclusion of the Utilities and Infrastructure stage and
initial occupancy of the 850 man workforce camp.
-- During Q2/11, drilling activity targeted 182 net crude oil wells
including 134 wells targeting primary heavy crude oil, 7 wells in
the Greater Pelican Lake area, 37 wells targeting bitumen (thermal oil)
and 4 wells targeting light crude oil.
-- Planned drilling activity for Q3/11 includes 326 net crude oil wells,
excluding stratigraphic test and service wells and 41 bitumen wells.
International Exploration and Production
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Crude oil production
(bbl/d)
North Sea 32,866 34,101 37,669 33,480 37,276
Offshore Africa 21,334 25,488 29,842 23,400 29,892
----------------------------------------------------------------------------
Natural gas production
(MMcf/d)
North Sea 7 9 9 8 12
Offshore Africa 15 22 9 19 13
----------------------------------------------------------------------------
Net wells targeting
crude oil 0.0 0.9 1.9 0.9 4.7
Net successful wells
drilled 0.0 0.0 1.9 0.0 4.7
----------------------------------------------------------------------------
Success rate 0% 0% 100% 0% 100%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
-- North Sea crude oil production was 32,866 bbl/d during Q2/11, slightly
above previously issued Corporate guidance due to strong performance
from the Ninian field. Q2/11 crude oil production decreased 13% from
Q2/10 and 4% from Q1/11 due to natural field declines.
-- In March 2011, the UK government substantively enacted an increase to
the corporate income tax rate charged on profits from UK North Sea
crude oil and natural gas production from 50% to 62%. As a result, the
Company's development activities in the North Sea have been reduced. The
Company is maintaining one drilling string in the North Sea, down from
the two originally planned. The planned drilling activity at Murchison
during 2011 has been cancelled and decommissioning plans for the
Murchison Platform are progressing as planned. The Company will continue
to high grade all North Sea prospects for potential future development
opportunities.
-- In Q2/11, Offshore Africa crude oil production averaged 21,334 bbl/d,
decreasing 29% from 29,842 bbl/d for Q2/10 and 16% from 25,488 bbl/d for
the prior quarter. The decrease in production volumes from Q2/10 and
Q1/11 was due to natural field declines, and the temporary suspension of
production at the Olowi Field due to a failure in the midwater arch.
Olowi production was reinstated at Platform C during Q2/11. The midwater
arch has been stabilized and work is ongoing with production from
Platforms A and B targeted for late Q3/11.
North America Oil Sands Mining and Upgrading - Horizon
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Synthetic crude oil
production (bbl/d) - 7,269 99,950 3,615 93,508
----------------------------------------------------------------------------
----------------------------------------------------------------------------
-- All necessary regulatory and operating approvals to recommence
operations at Horizon have been received. Fire rebuild and collateral
damage repairs are essentially complete and commissioning to commence
operations started on August 2, 2011. Commissioning is targeted to take
between 2 and 3 weeks with ramp up to full production design rates of
110,000 bbl/d of SCO shortly thereafter.
-- Construction of the third Ore Preparation Plant ("OPP") at Horizon is
currently anticipated to be completed slightly below budget and on
schedule. Commissioning is currently targeted for early Q4/11 and is
expected to increase production reliability and result in higher plant
uptime at Horizon.
-- Turnaround and opportune maintenance has been completed. Portions of the
turnaround originally scheduled for 2012 have been accelerated and
remaining portions of that turnaround are now expected to be deferred to
2013, resulting in higher targeted production levels of SCO for 2012
than originally forecast.
-- Fire repair/rebuild costs, including collateral damage, are currently
estimated at approximately $400 million to $450 million. Business
interruption insurance recoveries of $136 million were recognized in
Q2/11. Additional business interruption insurance recoveries related to
the second and third quarters will be recognized at such time as
additional interim payments are processed and as the final terms of the
insurance settlement are determined.
-- As part of Canadian Natural's disciplined execution strategy to achieve
cost certainty for a defined and stepped expansion at its Horizon
operation from the current 110,000 bbl/d to 250,000 bbl/d of SCO
capacity, the Company's Board of Directors has approved targeted
strategic expansion capital expenditures at Horizon for 2012 of
approximately $2 billion. It is expected that certain projects will be
advanced and contracts finalized in 2011 and 2012 such that the
execution of engineering, procurement and construction activities will
be undertaken in 2012 resulting in the above noted strategic expansion
capital expenditures. Decisions to proceed with individual projects, or
the next stage of the expansion, will be based on then market
conditions, the risk factors associated with the project, execution
performance to date and the overall strategy to deliver the expansion
phase of the project in a cost contained manner.
MARKETING
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Crude oil and NGLs
pricing
WTI(1) benchmark
price (US$/bbl) $ 102.55 $ 94.25 $ 77.99 $ 98.42 $ 78.39
Western Canadian
Select blend
differential from WTI (%) 17% 24% 18% 20% 15%
SCO price (US$/bbl) $ 115.65 $ 95.24 $ 76.44 $ 105.50 $ 77.90
Average realized
pricing before risk
management(2) (C$/bbl) $ 82.58 $ 67.96 $ 63.62 $ 75.25 $ 66.10
Natural gas pricing
AECO benchmark price
(C$/GJ) $ 3.54 $ 3.57 $ 3.66 $ 3.56 $ 4.36
Average realized
pricing before risk
management (C$/Mcf) $ 3.83 $ 3.83 $ 3.86 $ 3.83 $ 4.52
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
(2) Excludes SCO.
-- In Q2/11, WTI pricing increased by 31% from Q2/10, reflective of the
political instability in the Middle East and North Africa, continued
strong Asian demand and the relative weakness of the US dollar.
-- The Western Canadian Select ("WCS") heavy crude oil differential as a
percent of WTI averaged 17% in Q2/11 compared with 18% in Q2/10 and 24%
in Q1/11. The WCS heavy differential narrowed in Q2/11 from the prior
quarter primarily due to restored operations from Q1/11 outages at
upgrading facilities and planned refinery shutdowns in key markets for
WCS.
-- During Q2/11, the Company contributed approximately 155,000 bbl/d of its
heavy crude oil streams to the WCS blend. Canadian Natural is the
largest contributor accounting for 57% of the WCS blend.
REDWATER UPGRADING AND REFINING
-- In Q1/11 Canadian Natural announced that it has partnered with North
West Upgrading Inc. to move forward with detailed engineering regarding
the construction and operation of the bitumen refinery. The
partnership entered into an agreement to process bitumen supplied by the
Government of Alberta under its Bitumen Royalty In Kind ("BRIK")
initiative. The Project engineering is advancing and work towards
sanction level completion is ongoing. Sanction is currently targeted for
the latter part of 2011 or the first half of 2012.
FINANCIAL REVIEW
-- The financial position of Canadian Natural remains strong as the Company
continues to focus on capital allocation and the execution of
implemented strategies. Canadian Natural's credit facilities, its
diverse asset base and related capital expenditure programs, and
commodity hedging policy all support a flexible financial position and
provide the right liquid resources for the short, mid and long term.
Supporting this are:
-- A large and diverse asset base spread over various commodity types;
average production amounted to 561,359 BOE/d in the first half of
2011 and 95% of production was located in G8 countries.
-- Financial stability and liquidity; in Q2/11 the $2.2 billion
revolving syndicated credit facility was increased to $3.0 billion
and extended to June 2015. With cash flow from operations of over
$2.6 billion in the first half of 2011 and available unused bank
lines of $2.8 billion at June 30, 2011, the Company maintains
significant financial stability and liquidity.
-- A strong balance sheet with debt to book capitalization of 29%
and debt to EBITDA of 1.2 times; Canadian Natural's long term
debt at June 30, 2011 amounted to $8.6 billion compared with $8.5
billion at December 31, 2010.
OUTLOOK
The Company forecasts 2011 production levels before royalties to average between
1,250 and 1,275 MMcf/d of natural gas and between 371,000 and 406,000 bbl/d of
crude oil and NGLs. Q3/11 production guidance before royalties is forecast to
average between 1,230 and 1,255 MMcf/d of natural gas and between 373,000 and
414,000 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, forecast or anticipated 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 the Horizon Oil Sands resumption of production and future expansion, ability
to recover insurance proceeds, Primrose, Pelican Lake, Olowi Field (Offshore
Gabon), the Kirby Thermal Oil Sands Project, the Keystone Pipeline US Gulf Coast
expansion, and the construction and operation of the North West Redwater bitumen
refinery 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 and in mining, extracting or
upgrading the Company's bitumen products; 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, natural gas and natural gas
liquids ("NGLs") not currently classified as proved; actions by governmental
authorities; government regulations and the expenditures required to comply with
them (especially safety and environmental laws and regulations and the impact of
climate change initiatives on capital and operating costs); asset retirement
obligations; the adequacy of the Company's provision for taxes; and other
circumstances affecting revenues and expenses.
The Company's operations have been, and in the future may be, affected by
political developments and by federal, provincial and local laws and regulations
such as restrictions on production, changes in taxes, royalties and other
amounts payable to governments or governmental agencies, price or gathering rate
controls and environmental protection regulations. Should one or more of these
risks or uncertainties materialize, or should any of the Company's assumptions
prove incorrect, actual results may vary in material respects from those
projected in the forward-looking statements. The impact of any one factor on a
particular forward-looking statement is not determinable with certainty as such
factors are dependent upon other factors, and the Company's course of action
would depend upon its assessment of the future considering all information then
available.
Readers are cautioned that the foregoing list of factors is not exhaustive.
Unpredictable or unknown factors not discussed in this report could also have
material adverse effects on forward-looking statements. Although the Company
believes that the expectations conveyed by the forward-looking statements are
reasonable based on information available to it on the date such forward-looking
statements are made, no assurances can be given as to future results, levels of
activity and achievements. All subsequent forward-looking statements, whether
written or oral, attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by these cautionary statements. Except as
required by law, the Company assumes no obligation to update forward-looking
statements should circumstances or Management's estimates or opinions change.
Management's Discussion and Analysis
Management's Discussion and Analysis of the financial condition and results of
operations of the Company should be read in conjunction with the unaudited
interim consolidated financial statements for the six months ended June 30, 2011
and the MD&A and the audited consolidated financial statements for the year
ended December 31, 2010.
All dollar amounts are referenced in millions of Canadian dollars, except where
noted otherwise. Common share data and per common share amounts have been
restated to reflect the two-for-one share split in May 2010. The Company's
consolidated financial statements for the period ended June 30, 2011 and this
MD&A have been prepared in accordance with International Financial Reporting
Standards ("IFRS"), as issued by the International Accounting Standards Board
("IASB"). Unless otherwise stated, 2010 comparative figures have been restated
in accordance with IFRS issued as at August 3, 2011. Any subsequent changes to
IFRS that are given effect in the Company's annual consolidated financial
statements for the year ending December 31, 2011 could result in restatement of
the prior periods. 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 IFRS 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 IFRS, 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 IFRS, 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 conversion method primarily applicable at the
burner tip and does not represent the value equivalency at the wellhead.
Production volumes and per barrel statistics are presented throughout this MD&A
on a "before royalty" or "gross" basis, and realized prices are net of
transportation and blending costs and exclude the effect of risk management
activities. Production on an "after royalty" or "net" basis is also presented
for information purposes only.
The following discussion refers primarily to the Company's financial results for
the six and three months ended June 30, 2011 in relation to the comparable
periods in 2010 and the first quarter of 2011. The accompanying tables form an
integral part of this MD&A. This MD&A is dated August 3, 2011. Additional
information relating to the Company, including its Annual Information Form for
the year ended December 31, 2010, is available on SEDAR at www.sedar.com, and on
EDGAR at www.sec.gov.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Product sales $ 3,727 $ 3,302 $ 3,614 $ 7,029 $ 7,194
Net earnings $ 929 $ 46 $ 651 $ 975 $ 1,386
Per common share - basic $ 0.85 $ 0.04 $ 0.60 $ 0.89 $ 1.28
- diluted $ 0.84 $ 0.04 $ 0.60 $ 0.88 $ 1.27
Adjusted net earnings from
operations (1) $ 621 $ 228 $ 647 $ 849 $ 1,286
Per common share - basic $ 0.57 $ 0.21 $ 0.59 $ 0.78 $ 1.18
- diluted $ 0.56 $ 0.21 $ 0.59 $ 0.77 $ 1.17
Cash flow from operations
(2) $ 1,548 $ 1,074 $ 1,629 $ 2,622 $ 3,136
Per common share - basic $ 1.41 $ 0.98 $ 1.50 $ 2.39 $ 2.89
- diluted $ 1.40 $ 0.97 $ 1.49 $ 2.37 $ 2.87
Capital expenditures, net of
dispositions $ 1,405 $ 1,694 $ 1,576 $ 3,099 $ 2,652
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted net earnings from operations is a non-GAAP measure that
represents net earnings adjusted for certain items of a non-operational
nature. The Company evaluates its performance based on adjusted net
earnings from operations. The reconciliation "Adjusted Net Earnings from
Operations" presented below lists the after-tax effects of certain items
of a non-operational nature that are included in the Company's financial
results. Adjusted net earnings from operations may not be comparable to
similar measures presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that represents net
earnings adjusted for non-cash items before working capital adjustments.
The Company evaluates its performance based on cash flow from
operations. The Company considers cash flow from operations a key
measure as it demonstrates the Company's ability to generate the cash
flow necessary to fund future growth through capital investment and
to repay debt. The reconciliation "Cash Flow from Operations" presented
below lists certain non-cash items that are included in the Company's
financial results. Cash flow from operations may not be comparable to
similar measures presented by other companies.
Adjusted Net Earnings from Operations
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Net earnings as reported $ 929 $ 46 $ 651 $ 975 $ 1,386
Share-based compensation
(recovery) expense, net of tax
(a) (d) (188) 128 (87) (60) (58)
Unrealized risk management
(gain) loss, net of tax (b) (87) 39 (67) (48) (223)
Unrealized foreign exchange
(gain) loss, net of tax (c) (33) (89) 150 (122) 49
Effect of statutory tax rate
and other legislative changes
on deferred income
tax liabilities (d) - 104 - 104 132
----------------------------------------------------------------------------
Adjusted net earnings from
operations $ 621 $ 228 $ 647 $ 849 $ 1,286
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) The Company's employee stock option plan provides for a cash payment
option. Accordingly, the fair value of the outstanding vested options is
recorded as a liability on the Company's balance sheets and periodic
changes in the fair 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 sheets, 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 sheets in
determining deferred 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. During the
first quarter of 2011, the UK government substantively enacted an
increase to the corporate income tax rate charged on profits from UK
North Sea crude oil and natural gas production from 50% to 62%. The
Company's deferred income tax liability was increased by $104 million
with respect to this tax rate change. During 2010, changes in Canada to
the taxation of stock options surrendered by employees for cash payments
resulted in a $132 million charge to deferred income tax expense.
Cash Flow from Operations
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Net earnings $ 929 $ 46 $ 651 $ 975 $ 1,386
Non-cash items:
Depletion, depreciation and
amortization 870 849 879 1,719 1,676
Share-based compensation
(recovery) expense (188) 128 (87) (60) (58)
Asset retirement obligation
accretion 31 33 31 64 61
Unrealized risk management
(gain) loss (118) 54 (86) (64) (296)
Unrealized foreign exchange
(gain) loss (33) (89) 172 (122) 56
Deferred income tax expense 57 53 69 110 311
Horizon asset impairment
provision - 396 - 396 -
Insurance recovery - property
damage - (396) - (396) -
----------------------------------------------------------------------------
Cash flow from operations $ 1,548 $ 1,074 $ 1,629 $ 2,622 $ 3,136
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the six months ended June 30, 2011 were $975 million compared
to $1,386 million for the six months ended June 30, 2010. Net earnings for the
six months ended June 30, 2011 included net unrealized after-tax income of $126
million related to the effects of share-based compensation, risk management
activities, fluctuations in foreign exchange rates and the impact of statutory
tax rate and other legislative changes on deferred income tax liabilities,
compared to net unrealized after-tax income of $100 million for the six months
ended June 30, 2010. Excluding these items, adjusted net earnings from
operations for the six months ended June 30, 2011 were $849 million, compared to
$1,286 million for the six months ended June 30, 2010.
Net earnings for the second quarter of 2011 were $929 million compared to $651
million for the second quarter of 2010 and $46 million for the prior quarter.
Net earnings for the second quarter of 2011 included net unrealized after-tax
income of $308 million related to the effects of share-based compensation, risk
management activities, fluctuations in foreign exchange rates and the impact of
statutory tax rate and other legislative changes on deferred income tax
liabilities, compared to net unrealized after-tax income of $4 million for the
second quarter of 2010 and net unrealized after-tax expenses of $182 million for
the prior quarter. Excluding these items, adjusted net earnings from operations
for the second quarter of 2011 were $621 million compared to $647 million for
the second quarter of 2010 and $228 million for the prior quarter.
The decrease in adjusted net earnings for the six and three months ended June
30, 2011 from the comparable periods in 2010 was primarily due to lower
synthetic crude oil ("SCO") sales revenue and continuing production expenses
associated with the suspension of production at Horizon. On January 6, 2011, a
fire occurred at the Company's primary upgrading coking plant. As at August 3,
2011, all necessary regulatory and operating approvals to recommence operations
were received. Final mechanical, testing and commissioning activities are
ongoing and production is scheduled to commence in the third quarter of 2011.
Other factors contributing to the decrease in adjusted net earnings were:
-- realized risk management losses; and
-- the impact of the stronger Canadian dollar;
partially offset by:
-- higher North America crude oil and NGL sales volumes; and
-- higher crude oil and NGL netbacks.
The increase in adjusted net earnings from the prior quarter was due to:
-- higher crude oil and NGL netbacks;
-- lower realized risk management losses; and
-- lower continuing operating expenses associated with the suspension of
production at Horizon due to the effect of business interruption
insurance recoveries in the second quarter;
partially offset by:
-- lower SCO sales revenue; and
-- the impact of a stronger Canadian dollar.
The impacts of share-based compensation, unrealized risk management activities
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 six months ended June 30, 2011 was $2,622
million compared to $3,136 million for the six months ended June 30, 2010. Cash
flow from operations for the second quarter of 2011 was $1,548 million compared
to $1,629 million for the second quarter of 2010 and $1,074 million for the
prior quarter. The decrease in cash flow from operations from the comparable
periods in 2010 was primarily due to lower SCO sales revenue and continuing
production expenses associated with the suspension of production at Horizon.
Other factors contributing to the decrease were:
-- realized risk management losses; and
-- the impact of the stronger Canadian dollar;
partially offset by:
-- higher North America crude oil and NGL sales volumes; and
-- higher crude oil and NGL netbacks.
The increase in cash flow from operations from the prior quarter was primarily
due to:
-- higher crude oil and NGL netbacks;
-- lower realized risk management losses; and
-- lower continuing operating expenses associated with the suspension of
production at Horizon due to the effect of business interruption
insurance recoveries in the second quarter;
partially offset by:
-- lower SCO sales revenue;
-- the impact of a stronger Canadian dollar; and
-- higher cash taxes.
Total production before royalties for the six months ended June 30, 2011
decreased 11% to 561,359 BOE/d from 629,982 BOE/d for the six months ended June
30, 2010. Total production before royalties for the second quarter of 2011
decreased 14% to 556,539 BOE/d from 649,195 BOE/d for the second quarter of 2010
and 2% from 566,231 BOE/d for the prior quarter. Production for the second
quarter of 2011 was within the Company's previously issued guidance.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the eight most
recently completed quarters:
($ millions, except per
common share Jun 30 Mar 31 Dec 31 Sep 30
amounts) 2011 2011 2010 2010
----------------------------------------------------------------------------
Product sales $ 3,727 $ 3,302 $ 3,787 $ 3,341
Net earnings (loss) $ 929 $ 46 $ (309) $ 596
Net earnings (loss) per
common share
- Basic $ 0.85 $ 0.04 $ (0.28) $ 0.55
- Diluted $ 0.84 $ 0.04 $ (0.28) $ 0.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per
common share Jun 30 Mar 31 Dec 31 Sep 30
amounts) 2010 2010(1) 2009(1)(2) 2009(1)(2)
----------------------------------------------------------------------------
Product sales $ 3,614 $ 3,580 $ 3,319 $ 2,823
Net earnings $ 651 $ 735 $ 455 $ 658
Net earnings per common share
- Basic $ 0.60 $ 0.68 $ 0.42 $ 0.61
- Diluted $ 0.60 $ 0.67 $ 0.42 $ 0.61
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Per common share amounts have been restated to reflect a two-for-one
common share split in May 2010.
(2) 2009 quarterly results are reported in accordance with Canadian
generally accepted accounting principles as previously reported.
Volatility in the quarterly net earnings (loss) 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,
the impact of the WCS Heavy Differential ("WCS Differential") from WTI
in North America and the impact of the differential between WTI and
Dated Brent benchmark pricing in the North Sea and Offshore Africa.
-- 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 impact
of the suspension of production at Horizon due to the coker fire
incident. Sales volumes also reflected fluctuations due to timing of
liftings and maintenance activities in the North Sea and Offshore
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 ramp up and subsequent suspension of
production at both Horizon and the Olowi Field in Offshore Gabon.
-- Depletion, depreciation and amortization - Fluctuations due to changes
in sales volumes, proved reserves, finding and development costs
associated with crude oil and natural gas exploration, estimated future
costs to develop the Company's proved undeveloped reserves, the impact
of the ramp up and subsequent suspension of operations at Horizon and
the impact of the ramp up of production and ceiling test impairments at
the Olowi Field in Offshore Gabon.
-- Share-based compensation - Fluctuations due to the mark-to-market
movements of the Company's share-based compensation liability.
-- 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, partially offset by the impact of cross currency swap
hedges.
-- Income tax expense - Fluctuations in income tax expense (recovery)
include statutory tax rate and other legislative changes substantively
enacted or enacted in the various periods.
BUSINESS ENVIRONMENT
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
WTI benchmark price
(US$/bbl) (1) $ 102.55 $ 94.25 $ 77.99 $ 98.42 $ 78.39
Dated Brent benchmark price
(US$/bbl) $ 117.33 $ 105.01 $ 78.27 $ 111.20 $ 77.30
WCS blend differential from
WTI (US$/bbl) $ 17.62 $ 22.74 $ 14.12 $ 20.17 $ 11.60
WCS blend differential from
WTI (%) 17% 24% 18% 20% 15%
SCO price (US$/bbl) (2) $ 115.65 $ 95.24 $ 76.44 $ 105.50 $ 77.90
Condensate benchmark price
(US$/bbl) $ 112.48 $ 98.57 $ 82.81 $ 105.56 $ 83.81
NYMEX benchmark price
(US$/MMBtu) $ 4.36 $ 4.13 $ 4.08 $ 4.24 $ 4.72
AECO benchmark price
(C$/GJ) $ 3.54 $ 3.57 $ 3.66 $ 3.56 $ 4.36
US / Canadian dollar
average exchange
rate $ 1.0331 $ 1.0147 $ 0.9731 $ 1.0238 $ 0.9673
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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$98.42 per bbl for the six months ended
June 30, 2011, an increase of 26% from US$78.39 per bbl for the six months ended
June 30, 2010. WTI averaged US$102.55 per bbl for the second quarter of 2011, an
increase of 31% from US$77.99 per bbl for the second quarter of 2010, and an
increase of 9% from US$94.25 per bbl for the prior quarter. WTI pricing was
reflective of the political instability in the Middle East and North Africa,
continued strong Asian demand and the relative weakness of the US dollar.
Crude oil sales contracts for the Company's North Sea and Offshore Africa
segments are typically based on Dated Brent ("Brent") pricing, which is more
representative of international markets and overall world supply and demand.
Brent averaged US$111.20 per bbl for the six months ended June 30, 2011, an
increase of 44% compared to US$77.30 per bbl for the six months ended June 30,
2010. Brent averaged US$117.33 per bbl for the second quarter of 2011, an
increase of 50% compared to US$78.27 per bbl for the second quarter of 2010 and
an increase of 12% from US$105.01 per bbl for the prior quarter. The higher
Brent pricing relative to WTI was due to logistical constraints and high
inventory levels of crude oil at Cushing.
The Western Canadian Select ("WCS") Heavy Differential averaged 20% for the six
months ended June 30, 2011 compared to 15% for the six months ended June 30,
2010. The WCS Heavy Differential widened from the comparable period in 2010
partially due to the continuing effects of pipeline disruptions in the last half
of 2010 that forced the temporary shutdown and apportionment of major oil
pipelines to Midwest refineries in the United States. The WCS Heavy Differential
averaged 17% for the second quarter of 2011, compared to 18% for the second
quarter of 2010 and 24% for the prior quarter. The WCS Heavy Differential
narrowed in the second quarter of 2011, compared to the prior quarter, partially
due to a stronger diesel market, and the impact of unplanned outages at
upgrading facilities and planned refinery shutdowns in key markets for WCS that
occurred in the prior quarter.
The Company uses condensate as a blending diluent for heavy crude oil pipeline
shipments. During the second quarter of 2011, condensate prices continued to
trade at a premium to WTI, similar to the second quarter of 2010 and the prior
quarter, reflecting normal seasonality.
The Company anticipates continued volatility in crude oil pricing benchmarks due
to supply and demand factors, geopolitical events, and the timing and extent of
the continuing economic recovery. The WCS Heavy Differential is expected to
continue to reflect seasonal demand fluctuations, logistics and refinery
margins.
NYMEX natural gas prices averaged US$4.24 per MMbtu for the six months ended
June 30, 2011, a decrease of 10% from US$4.72 per MMbtu for the six months ended
June 30, 2010. NYMEX natural gas prices averaged US$4.36 per MMbtu for the
second quarter of 2011, an increase of 7% from US$4.08 per MMbtu for the second
quarter of 2010, and an increase of 6% from US$4.13 per MMbtu for the prior
quarter.
AECO natural gas prices for the six months ended June 30, 2011 averaged $3.56
per GJ, a decrease of 18% from $4.36 per GJ for the six months ended June 30,
2010. AECO natural gas prices for the second quarter of 2011 decreased 3% to
average $3.54 per GJ from $3.66 per GJ in the second quarter of 2010, and were
comparable to the prior quarter.
Weather in the United States in 2011 resulted in stronger natural gas prices and
reduced inventory levels which partially offset strong incremental production
from shale gas reservoirs. Overall gas prices continue to be weak in response to
the strong North America supply position, primarily from the highly productive
shale areas.
DAILY PRODUCTION, before royalties
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Crude oil and NGLs
(bbl/d)
North America -
Exploration
and Production 295,715 290,130 275,584 292,938 264,081
North America -
Oil Sands Mining and
Upgrading - 7,269 99,950 3,615 93,508
North Sea 32,866 34,101 37,669 33,480 37,276
Offshore Africa 21,334 25,488 29,842 23,400 29,892
----------------------------------------------------------------------------
349,915 356,988 443,045 353,433 424,757
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,218 1,225 1,219 1,221 1,206
North Sea 7 9 9 8 12
Offshore Africa 15 22 9 19 13
----------------------------------------------------------------------------
1,240 1,256 1,237 1,248 1,231
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 556,539 566,231 649,195 561,359 629,982
----------------------------------------------------------------------------
Product mix
Light and medium crude
oil and NGLs 20% 21% 18% 20% 18%
Pelican Lake heavy crude
oil 6% 7% 6% 6% 6%
Primary heavy crude oil 18% 17% 14% 18% 15%
Bitumen (thermal oil) 19% 17% 15% 18% 14%
Synthetic crude oil - 1% 15% 1% 15%
Natural gas 37% 37% 32% 37% 32%
----------------------------------------------------------------------------
Percentage of product
sales (1)
(excluding midstream
revenue)
Crude oil and NGLs 85% 84% 86% 84% 84%
Natural gas 15% 16% 14% 16% 16%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation and blending costs and excluding risk management
activities.
DAILY PRODUCTION, net of royalties
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America - Exploration
and Production 243,943 233,554 228,781 238,777 217,501
North America -
Oil Sands Mining and
Upgrading - 6,978 96,543 3,324 90,266
North Sea 32,793 34,008 37,581 33,397 37,194
Offshore Africa 21,196 23,213 28,225 22,199 28,574
----------------------------------------------------------------------------
297,932 297,753 391,130 297,697 373,535
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,146 1,197 1,149 1,171 1,125
North Sea 7 9 9 8 12
Offshore Africa 13 19 8 16 13
----------------------------------------------------------------------------
1,166 1,225 1,166 1,195 1,150
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 492,250 501,914 585,556 496,909 565,170
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 and medium crude oil and NGLs, Pelican Lake heavy crude oil,
primary heavy crude oil, bitumen (thermal oil), and SCO.
Crude oil and NGLs production for the six months ended June 30, 2011 decreased
17% to 353,433 bbl/d from 424,757 bbl/d for the six months ended June 30, 2010.
Crude oil and NGLs production for the second quarter of 2011 decreased 21% to
349,915 bbl/d from 443,045 bbl/d for the second quarter of 2010, and 2% from
356,988 bbl/d for the prior quarter. The decrease from the comparable periods in
2010 and the prior quarter was primarily related to the suspension of production
at Horizon, partially offset by the impact of a record heavy oil drilling
program and the cyclic nature of the Company's thermal operations. Crude oil and
NGLs production in the second quarter of 2011 was within the Company's
previously issued guidance of 345,000 to 376,000 bbl/d.
Natural gas production for the six months ended June 30, 2011 averaged 1,248
MMcf/d compared to 1,231 MMcf/d for the six months ended June 30, 2010. Natural
gas production for the second quarter of 2011 averaged 1,240 MMcf/d and was
comparable to the second quarter of 2010 and decreased 1% compared to 1,256
MMcf/d for the prior quarter. The increase in natural gas production from the
six months ended June 30, 2010 reflects the new production volumes from the
Septimus facility in North East British Columbia and from natural gas producing
properties acquired during 2010 and 2011. These increases were partially offset
by expected production declines due to the allocation of capital to higher
return crude oil projects, which resulted in a strategic reduction of natural
gas drilling activity. Natural gas production in the second quarter of 2011 was
within the Company's previously issued guidance of 1,219 to 1,244 MMcf/d.
For 2011, revised annual production guidance is targeted to average between
371,000 and 406,000 bbl/d of crude oil and NGLs and between 1,250 and 1,275
MMcf/d of natural gas. Third quarter 2011 production guidance is targeted to
average between 373,000 and 414,000 bbl/d of crude oil and NGLs and between
1,230 and 1,255 MMcf/d of natural gas.
North America - Exploration and Production
North America crude oil and NGLs production for the six months ended June 30,
2011 increased 11% to average 292,938 bbl/d from 264,081 bbl/d for the six
months ended June 30, 2010. For the second quarter of 2011, crude oil and NGLs
production increased 7% to average 295,715 bbl/d, compared to 275,584 bbl/d for
the second quarter of 2010, and increased 2% compared to 290,130 bbl/d for the
prior quarter. Increases in crude oil and NGLs production from comparable
periods were primarily due to the impact of a record heavy oil drilling program
and the cyclic nature of the Company's thermal operations. North America
production volumes were negatively impacted by forest fires in North Central
Alberta and flooding in South East Saskatchewan in the second quarter of 2011,
which caused temporary production curtailments of certain fields including
Pelican Lake. Accordingly, production of crude oil and NGLs was at the low end
of the Company's previously issued guidance of 295,000 bbl/d to 310,000 bbl/d
for the second quarter of 2011.
Natural gas production for the six months ended June 30, 2011 increased 1% to
1,221 MMcf/d compared to 1,206 MMcf/d for the six months ended June 30, 2010.
Natural gas production of 1,218 MMcf/d in the second quarter of 2011 was
comparable to the second quarter of 2010 and the prior quarter. The slight
increase in natural gas production for the six months ended June 30, 2011 from
the comparable period in 2010 reflected new production volumes from the Septimus
facility in North East British Columbia and from natural gas producing
properties acquired during 2010 and 2011. These increases were partially offset
by 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 with 10 natural gas wells drilled in the second quarter of
2011. Production of natural gas was within the Company's previously issued
guidance of 1,200 MMcf/d to 1,220 MMcf/d for the second quarter of 2011.
North America - Oil Sands Mining and Upgrading
Production averaged 3,615 bbl/d for the six months ended June 30, 2011,
decreasing by 96% from 93,508 bbl/d for the six months ended June 30, 2010.
There was no production for the second quarter of 2011, compared to 99,950 bbl/d
in the second quarter of 2010 and 7,269 bbl/d in the prior quarter. The decrease
in production for the six months ended June 30, 2011 reflected the suspension of
production of synthetic crude oil on January 6, 2011 following the occurrence of
a fire at Horizon's primary upgrading coking plant.
As at August 3, 2011, all necessary regulatory and operating approvals to
recommence operations were received. Final mechanical, testing and commissioning
activities are ongoing and production is scheduled for the third quarter of
2011.
North Sea
North Sea crude oil production for the six months ended June 30, 2011 decreased
10% to 33,480 bbl/d from 37,276 bbl/d for the six months ended June 30, 2010.
Second quarter 2011 North Sea crude oil production decreased 13% to 32,866 bbl/d
from 37,669 bbl/d for the second quarter of 2010, and decreased 4% from 34,101
bbl/d for the prior quarter. The decrease in production volumes from the
comparable periods in 2010 was due to natural field declines. Production in the
second quarter of 2011 exceeded the Company's previously issued guidance of
29,000 bbl/d to 32,000 bbl/d due to strong performance from the Olive Oyl well
brought online in December 2010 and strong base performance of the Ninian Field.
Offshore Africa
Offshore Africa crude oil production decreased 22% to 23,400 bbl/d for the six
months ended June 30, 2011 from 29,892 bbl/d for the six months ended June 30,
2010. Second quarter crude oil production averaged 21,334 bbl/d, decreasing 29%
from 29,842 bbl/d for the second quarter of 2010 and 16% from 25,488 bbl/d for
the prior quarter. The decrease in production volumes from the second quarter of
2010 was primarily due to the temporary suspension of production at the Olowi
Field, Gabon as a result of the failure in the supporting mechanism for
production and gas lift flowlines and the main power line. Olowi production was
reinstated at Platform C during the second quarter. The midwater arch was
re-secured in the second quarter and after a full evaluation and appropriate
testing, it was determined it can be used to restart production from Platforms A
and B in the third quarter of 2011. Production in the second quarter of 2011 was
at the low end of the Company's previously issued guidance of 21,000 bbl/d to
24,000 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 offloading vessels, as follows:
Jun 30 Mar 31 Dec 31
(bbl) 2011 2011 2010
----------------------------------------------------------------------------
North America - Exploration and Production - - 761,351
North America - Oil Sands Mining and
Upgrading (SCO) 787,517 802,575 1,172,200
North Sea 429,391 587,121 264,995
Offshore Africa 1,158,908 645,897 404,197
----------------------------------------------------------------------------
2,375,816 2,035,593 2,602,743
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
Sales price (2) $ 82.58 $ 67.96 $ 63.62 $ 75.25 $ 66.10
Royalties 11.62 10.43 8.95 11.03 9.50
Production expense 15.38 14.30 13.19 14.84 13.85
----------------------------------------------------------------------------
Netback $ 55.58 $ 43.23 $ 41.48 $ 49.38 $ 42.75
----------------------------------------------------------------------------
Natural gas ($/Mcf) (1)
Sales price (2) $ 3.83 $ 3.83 $ 3.86 $ 3.83 $ 4.52
Royalties 0.24 0.13 0.25 0.19 0.33
Production expense 1.11 1.17 1.05 1.14 1.12
----------------------------------------------------------------------------
Netback $ 2.48 $ 2.53 $ 2.56 $ 2.50 $ 3.07
----------------------------------------------------------------------------
Barrels of oil equivalent
($/BOE) (1)
Sales price (2) $ 60.77 $ 51.33 $ 47.97 $ 56.04 $ 50.86
Royalties 7.83 6.87 6.10 7.35 6.58
Production expense 12.12 11.59 10.55 11.85 11.09
----------------------------------------------------------------------------
Netback $ 40.82 $ 32.87 $ 31.32 $ 36.84 $ 33.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
PRODUCT PRICES - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) (2)
North America $ 77.62 $ 62.21 $ 60.35 $ 69.92 $ 63.15
North Sea $112.32 $102.51 $ 79.30 $107.75 $ 79.95
Offshore Africa $110.42 $ 97.09 $ 79.21 $102.56 $ 79.25
Company average $ 82.58 $ 67.96 $ 63.62 $ 75.25 $ 66.10
Natural gas ($/Mcf) (1) (2)
North America $ 3.76 $ 3.77 $ 3.85 $ 3.76 $ 4.51
North Sea $ 5.19 $ 3.56 $ 3.33 $ 4.29 $ 3.93
Offshore Africa $ 8.83 $ 7.34 $ 5.14 $ 7.94 $ 5.42
Company average $ 3.83 $ 3.83 $ 3.86 $ 3.83 $ 4.52
Company average ($/BOE) (1) (2) $ 60.77 $ 51.33 $ 47.97 $ 56.04 $ 50.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 11% to average $69.92 per bbl
for the six months ended June 30, 2011 from $63.15 per bbl for the six months
ended June 30, 2010. North America realized crude oil prices averaged $77.62 per
bbl for the second quarter of 2011, an increase of 29% compared to $60.35 per
bbl for the second quarter of 2010 and an increase of 25% compared to $62.21 per
bbl for the prior quarter. The increase in prices for the six months ended June
30, 2011 from the comparable period in 2010 was primarily a result of higher WTI
benchmark pricing, partially offset by the widening WCS Heavy Differential and
the impact of a stronger Canadian dollar relative to the US dollar. The increase
in prices for the three months ended June 30, 2011 was primarily a result of the
higher benchmark WTI pricing and narrowing WCS Heavy Differential, partially
offset by the impact of the stronger Canadian dollar relative to the US dollar.
The Company continues to focus on its crude oil blending marketing strategy, and
in the second quarter of 2011 contributed approximately 155,000 bbl/d of heavy
crude oil blends to the WCS stream.
In the first quarter of 2011, the Company announced that it had entered into a
partnership agreement with North West Upgrading Inc. to move forward with
detailed engineering regarding the construction and operation of a bitumen
refinery near Redwater, Alberta. In addition, the partnership has entered into
an agreement to process bitumen supplied by the Government of Alberta under the
Alberta Royalty Framework's Bitumen Royalty In Kind initiative. Project
development is dependent upon completion of detailed engineering and final
project sanction by the respective parties. Board sanction is currently targeted
for the latter half of 2011 or the first half of 2012.
North America realized natural gas prices decreased 17% to average $3.76 per Mcf
for the six months ended June 30, 2011 from $4.51 per Mcf for the six months
ended June 30, 2010. North America realized natural gas prices averaged $3.76
per Mcf for the second quarter of 2011, a decrease of 2% compared to $3.85 per
Mcf for the second quarter of 2010, and were comparable to the prior quarter.
The decrease in natural gas prices from the six months ended June 30, 2010 was
primarily related to the impact of strong supply from US shale projects and
continued weak demand from the industrial sector, together with the impact of a
stronger Canadian dollar.
Comparisons of the prices received in North America Exploration and Production
by product type were as follows:
Jun 30 Mar 31 Jun 30
(Quarterly Average) 2011 2011 2010
----------------------------------------------------------------------------
Wellhead Price(1) (2)
Light and medium crude oil and NGLs ($/bbl) $ 86.49 $ 76.57 $ 68.13
Pelican Lake heavy crude oil ($/bbl) $ 74.95 $ 62.78 $ 60.38
Primary heavy crude oil ($/bbl) $ 75.85 $ 59.62 $ 60.26
Bitumen (thermal oil) ($/bbl) $ 75.73 $ 56.79 $ 56.53
Natural gas ($/Mcf) $ 3.76 $ 3.77 $ 3.85
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 35% to average $107.75 per bbl for
the six months ended June 30, 2011 from $79.95 per bbl for the six months ended
June 30, 2010. Realized crude oil prices averaged $112.32 per bbl for the second
quarter of 2011, an increase of 42% from $79.30 per bbl for the second quarter
of 2010, and an increase of 10% from $102.51 per bbl for the prior quarter. The
increase in realized crude oil prices in the North Sea from the comparable
periods in 2010 was primarily the result of increased Brent benchmark pricing,
partially offset by the impact of the stronger Canadian dollar.
Offshore Africa
Offshore Africa realized crude oil prices increased 29% to average $102.56 per
bbl for the six months ended June 30, 2011 from $79.25 per bbl for the six
months ended June 30, 2010. Realized crude oil prices averaged $110.42 per bbl
for the second quarter of 2011, an increase of 39% from $79.21 per bbl for the
second quarter of 2010, and an increase of 14% from $97.09 per bbl in the prior
quarter. The increase in realized crude oil prices in Offshore Africa from the
comparable periods in 2010 was primarily the result of increased Brent benchmark
pricing, partially offset by the impact of the stronger Canadian dollar.
ROYALTIES - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
North America $13.53 $11.61 $10.42 $12.57 $11.24
North Sea $ 0.25 $ 0.28 $ 0.18 $ 0.26 $ 0.17
Offshore Africa $ 0.71 $ 8.66 $ 4.29 $ 5.40 $ 3.56
Company average $11.62 $10.43 $ 8.95 $11.03 $ 9.50
Natural gas ($/Mcf) (1)
North America $ 0.23 $ 0.12 $ 0.25 $ 0.18 $ 0.33
Offshore Africa $ 1.07 $ 0.97 $ 0.26 $ 1.01 $ 0.21
Company average $ 0.24 $ 0.13 $ 0.25 $ 0.19 $ 0.33
Company average ($/BOE) (1) $ 7.83 $ 6.87 $ 6.10 $ 7.35 $ 6.58
Percentage of product sales
(2)
Crude oil and NGLs 14% 15% 14% 15% 14%
Natural gas 6% 3% 6% 5% 7%
BOE 13% 13% 13% 13% 13%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North America
North America royalties for the six months ended June 30, 2011 compared to 2010
reflected benchmark commodity prices.
Crude oil and NGLs royalties averaged approximately 17% of product sales for the
second quarter of 2011 and 2010, compared to 19% for the prior quarter. The
decrease in royalties from the prior quarter was due to crude oil royalty
adjustments recorded in the prior quarter and an increase in capital
expenditures at Primrose. Crude oil and NGLs royalties per bbl are anticipated
to average 16% to 19% of product sales for 2011.
Natural gas royalties averaged approximately 6% of product sales for the second
quarter of 2011 and 2010, compared to 3% for the prior quarter. The increase in
natural gas royalty rates from the prior quarter was primarily due to gas cost
allowance adjustments recorded in the current quarter. Natural gas royalties are
anticipated to average 3% to 5% of product sales for 2011.
Offshore Africa
Under the terms of the various 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 product sales
averaged approximately 1% for the second quarter of 2011 compared to 5% for the
second quarter of 2010 and 9% for the prior quarter. The decrease in royalties
from the second quarter of 2010 and the prior quarter was due to crude oil
royalty adjustments related to the Baobab and Espoir Fields. Offshore Africa
royalty rates are anticipated to increase in 2011 to average 10% to 12% of
product sales, from 7% in 2010, as a result of payout of the Baobab Field during
the second quarter of 2011.
PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
North America $ 12.86 $ 12.28 $ 11.75 $ 12.57 $ 12.39
North Sea $ 34.20 $ 30.46 $ 21.35 $ 32.46 $ 23.35
Offshore Africa $ 21.36 $ 19.13 $ 18.33 $ 20.04 $ 16.11
Company average $ 15.38 $ 14.30 $ 13.19 $ 14.84 $ 13.85
Natural gas ($/Mcf)
(1)
North America $ 1.09 $ 1.16 $ 1.03 $ 1.12 $ 1.10
North Sea $ 2.61 $ 2.65 $ 2.53 $ 2.63 $ 3.15
Offshore Africa $ 2.35 $ 1.25 $ 1.64 $ 1.69 $ 1.63
Company average $ 1.11 $ 1.17 $ 1.05 $ 1.14 $ 1.12
Company average
($/BOE) (1) $ 12.12 $ 11.59 $ 10.55 $ 11.85 $ 11.09
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America
North America crude oil and NGLs production expense for the six months ended
June 30, 2011 was comparable to the six months ended June 30, 2010. North
America crude oil and NGLs production expense for the second quarter of 2011
increased 9% to $12.86 per bbl from $11.75 per bbl for the second quarter of
2010 and increased 5% from $12.28 per bbl for the prior quarter. The increase in
production expense per barrel from the second quarter of 2010 and the prior
quarter was a result of higher overall service costs relating to heavy crude oil
production and the impact of the forest fires in North Central Alberta and
flooding in South East Saskatchewan. The increase in production expense per
barrel from the prior quarter was also 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 2011.
North America natural gas production expense for the six months ended June 30,
2011 averaged $1.12 per Mcf and was comparable to the six months ended June 30,
2010. North America natural gas production expense for the second quarter of
2011 averaged $1.09 per Mcf and increased 6% compared to $1.03 per Mcf for the
second quarter of 2010. Natural gas production expense for the second quarter of
2011 increased from the comparable period in 2010 due to acquisitions of natural
gas producing properties that have higher operating costs per Mcf than the
Company's existing properties. These costs are expected to decline once the
acquisitions are fully integrated into the Company's operations. Natural gas
production expense decreased 6% from $1.16 per Mcf for the prior quarter, as the
prior quarter reflected normal seasonal costs associated with winter access and
colder weather. North America natural gas production expense is anticipated to
average $1.05 to $1.15 per Mcf for 2011.
North Sea
North Sea crude oil production expense for the six months ended June 30, 2011
increased 39% to $32.46 per bbl from $23.35 per bbl for the six months ended
June 30, 2010. North Sea crude oil production expense for the second quarter of
2011 increased 60% to $34.20 per bbl from $21.35 per bbl for the second quarter
of 2010 and increased 12% from $30.46 per bbl for the prior quarter. Production
expense increased on a per barrel basis from the comparable periods in 2010 and
the prior quarter due to lower volumes on relatively fixed costs and the
inclusion of one-time third party cost recoveries in the second quarter of 2010.
Production expense is anticipated to average $35.00 to $39.00 per bbl for 2011.
Offshore Africa
Offshore Africa crude oil production expense increased 24% to $20.04 per bbl
from $16.11 per bbl for the six months ended June 30, 2010. Offshore Africa
crude oil production expense for the second quarter of 2011 averaged $21.36 per
bbl, an increase of 17% compared to $18.33 per bbl for the second quarter of
2010 and an increase of 12% compared to $19.13 per bbl for the prior quarter.
Production expense increased on a per barrel basis from the comparable periods
due to the timing of liftings for each field, and due to lower volumes on
relatively fixed costs. Production expense for the second quarter of 2011 was
higher than the prior quarter due to the timing of liftings for each field.
Production expense is anticipated to average $20.00 to $23.00 per bbl for 2011.
DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Expense ($ millions) $ 835 $ 824 $ 775 $ 1,659 $ 1,473
$/BOE (1) $ 16.60 $ 16.33 $ 16.61 $ 16.46 $ 15.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, depreciation and amortization expense increased for the six months
ended June 30, 2011 compared to 2010 due to higher production in North America
and an increase in the estimated future costs to develop the Company's proved
and developed reserves. Depletion, depreciation and amortization expense for the
three months ended June 30, 2011 was comparable to the three months ended June
30, 2010 and the prior quarter on a per barrel basis.
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Expense ($ millions) $ 26 $ 28 $ 24 $ 54 $ 47
$/BOE (1) $ 0.52 $ 0.56 $ 0.51 $ 0.54 $ 0.48
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
OPERATIONS UPDATE
On January 6, 2011, the Company suspended SCO production at its Oil Sands Mining
and Upgrading operations due to a fire in the primary upgrading coking plant. As
at August 3, 2011, all necessary regulatory and operating approvals to
recommence operations were received. Final mechanical, testing and commissioning
activities are ongoing and production is scheduled for the third quarter of
2011.
PRODUCT PRICES AND ROYALTIES
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($/bbl) (1) 2011(5) 2011 2010 2011 2010
----------------------------------------------------------------------------
SCO sales price (2) $ - $ 82.93 $ 75.97 $ 82.93 $ 77.29
Bitumen value for royalty
purposes (3) $ 69.88 $ 51.13 $ 52.67 $ 60.50 $ 57.00
Bitumen royalties (4) $ - $ 4.14 $ 2.69 $ 4.14 $ 2.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes for the
period January 1 - 6, 2011.
(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.
(5) SCO sales price excludes incidental by-product sales and other
adjustments of $3 million.
Realized SCO sales prices averaged $82.93 per bbl for the six months ended June
30, 2011, an increase of 7% compared to $77.29 per bbl for the six months ended
June 30, 2010. Realized SCO sales prices for the six months ended June 30, 2011
reflected the prices reported in the first quarter of 2011 due to the impact of
suspension of production of synthetic crude oil in January 2011.
PRODUCTION COSTS
The following tables are reconciled to the Oil Sands Mining and Upgrading
production costs disclosed in note 17 to the Company's unaudited interim
consolidated financial statements.
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Cash costs $ 221 $ 256 $ 290 $ 477 $ 636
Less: costs incurred after
suspension of production (221) (209) - (430) -
----------------------------------------------------------------------------
Adjusted cash costs - 47 290 47 636
----------------------------------------------------------------------------
Cash costs, excluding
natural gas costs - 42 262 42 561
Natural gas costs - 5 28 5 75
----------------------------------------------------------------------------
Total cash production costs $ - $ 47 $ 290 $ 47 $ 636
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($/bbl) (1) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Cash costs, excluding natural
gas costs $ - $ 41.38 $ 29.09 $ 41.38 $ 32.96
Natural gas costs - 4.31 3.18 4.31 4.43
----------------------------------------------------------------------------
Total cash production costs $ - $ 45.69 $ 32.27 $ 45.69 $ 37.39
----------------------------------------------------------------------------
Sales (bbl/d) - 11,376 98,645 5,657 93,976
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes for the
period January 1 - 6, 2011.
Total cash production costs averaged $45.69 per bbl for the six months ended
June 30, 2011 compared to $37.39 per bbl for the six months ended June 30, 2010.
Cash production costs for the six months ended June 30, 2011 reflected the cash
production costs reported in the first quarter of 2011 due to the impact of the
suspension of production of synthetic crude oil in January 2011.
DEPLETION, DEPRECIATION AND AMORTIZATION
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Depletion, depreciation and
amortization $ 33 $ 23 $ 102 $ 56 $ 199
Less: depreciation incurred after
suspension of production (33) (10) - (43) -
----------------------------------------------------------------------------
Adjusted depletion, depreciation
and amortization - 13 102 13 199
----------------------------------------------------------------------------
$/bbl (1) $ - $ 12.37 $ 11.31 $ 12.37 $ 11.70
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes for the
period January 1 - 6, 2011.
Depletion, depreciation and amortization expense for the six months ended June
30, 2011 decreased from the six months ended June 30, 2010 primarily due to the
impact of the suspension of production of synthetic crude oil in January 2011.
ASSET RETIREMENT OBLIGATION ACCRETION
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Expense ($ millions) $ 5 $ 5 $ 7 $ 10 $ 14
$/bbl (1) $ - $ 4.84 $ 0.81 $ - $ 0.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes for the
period January 1 - 6, 2011.
Asset retirement obligation accretion expense represents the increase in the
carrying amount of the asset retirement obligation due to the passage of time.
MIDSTREAM
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Revenue $ 21 $ 22 $ 21 $ 43 $ 40
Production expense 5 7 7 12 12
----------------------------------------------------------------------------
Midstream cash flow 16 15 14 31 28
Depreciation 2 2 2 4 4
----------------------------------------------------------------------------
Segment earnings before taxes $ 14 $ 13 $ 12 $ 27 $ 24
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable periods.
ADMINISTRATION EXPENSE
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Expense ($ millions) $ 69 $ 54 $ 60 $ 123 $ 114
$/BOE (1) $ 1.38 $ 1.05 $ 1.03 $ 1.21 $ 1.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the six and three months ended June 30, 2011
increased from the comparable periods in 2010 and the prior quarter primarily
due to higher staffing related costs.
SHARE-BASED COMPENSATION EXPENSE
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Recovery (expense) $ (188) $ 128 $ (87) $ (60) $ (58)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
The Company recorded a $60 million share-based compensation recovery for the six
months ended June 30, 2011 primarily as a result of remeasurement of the fair
value of outstanding options at the end of the period, offset by normal course
graded vesting of options granted in prior periods and the impact of vested
options exercised or surrendered during the period. For the six months ended
June 30, 2011, the Company recovered $2 million in share-based compensation
previously capitalized to Oil Sands Mining and Upgrading (June 30, 2010 -
capitalized $8 million).
For the six months ended, June 30, 2011, the Company paid $11 million for stock
options surrendered for cash settlement (June 30, 2010 - $38 million).
INTEREST AND OTHER FINANCING COSTS
Three Months Ended Six Months Ended
($ millions, except per BOE Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
amounts) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Expense, gross $ 112 $ 105 $ 115 $ 217 $ 231
Less: capitalized interest 13 11 5 24 12
----------------------------------------------------------------------------
Expense, net $ 99 $ 94 $ 110 $ 193 $ 219
$/BOE (1) $ 1.97 $ 1.83 $ 1.89 $ 1.90 $ 1.94
Average effective interest
rate 4.7% 4.8% 4.8% 4.7% 4.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest and other financing costs for the three and six months ended June
30, 2011 decreased from the comparable period in 2010 due to the impact of a
stronger Canadian dollar on US dollar denominated debt, partially offset by
higher variable interest rates. Gross interest and other financing costs
increased compared to the prior quarter due to higher overall debt levels,
partially offset by the impact of a stronger Canadian dollar on US dollar
denominated debt.
The Company's average effective interest rates for the three and six months
ended June 30, 2011 were comparable to 2010 and the prior quarter.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures. These derivative
financial instruments are not intended for trading or speculative purposes.
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Crude oil and NGLs financial
instruments $ 37 $ 27 $ 15 $ 64 $ 32
Natural gas financial
instruments - - (78) - (96)
Foreign currency contracts and
interest rate swaps (3) 43 (28) 40 12
----------------------------------------------------------------------------
Realized loss (gain) $ 34 $ 70 $ (91) $ 104 $ (52)
----------------------------------------------------------------------------
Crude oil and NGLs financial
instruments $ (135) $ 67 $ (151) $ (68) $ (224)
Natural gas financial
instruments - - 94 - (36)
Foreign currency contracts and
interest rate swaps 17 (13) (29) 4 (36)
----------------------------------------------------------------------------
Unrealized (gain) loss $ (118) $ 54 $ (86) $ (64) $ (296)
----------------------------------------------------------------------------
Net (gain) loss $ (84) $ 124 $ (177) $ 40 $ (348)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Complete details related to outstanding derivative financial instruments at June
30, 2011 are disclosed in note 15 to the Company's unaudited interim
consolidated financial statements.
The Company recorded a net unrealized gain of $64 million ($48 million
after-tax) on its risk management activities for the six months ended June 30,
2011, including an unrealized gain of $118 million ($87 million after-tax) for
the second quarter of 2011 (March 31, 2011 - unrealized loss of $54 million, $39
million after-tax; June 30, 2010 - unrealized gain of $86 million, $67 million
after-tax), primarily due to changes in crude oil and natural gas forward
pricing and the reversal of prior period unrealized gains and losses.
FOREIGN EXCHANGE
Three Months Ended Six Months Ended
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Net realized (gain)loss $ (4) $ 22 $ (9) $ 18 $ (19)
Net unrealized
(gain) loss(1) (33) (89) 172 (122) 56
----------------------------------------------------------------------------
Net (gain) loss $ (37) $ (67) $ 163 $ (104) $ 37
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net unrealized foreign exchange gain for the six months ended June 30, 2011
was primarily due to the strengthening of the Canadian dollar with respect to US
dollar debt. The net unrealized gain for each of the periods presented included
the impact of cross currency swaps (six months ended June 30, 2011 - unrealized
loss of $64 million, March 31, 2011 - unrealized loss of $48 million, June 30,
2010 - unrealized gain of $32 million). The net realized foreign exchange loss
for the six months ended June 30, 2011 was primarily due to foreign exchange
rate fluctuations on settlement of working capital items denominated in US
dollars or UK pounds sterling. The Canadian dollar ended the second quarter at
US$1.0370 (March 31, 2011- US $1.0290; December 31, 2010 - US$1.0054; June 30,
2010 - US$0.9429).
INCOME TAXES
Three Months Ended Six Months Ended
($ millions, except income tax Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
rates) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
North America (1) $ 79 $ 91 $ 139 $ 170 $ 268
North Sea 70 46 43 116 96
Offshore Africa 24 20 9 44 15
PRT expense - North Sea 46 8 24 54 49
Other taxes 6 6 5 12 12
----------------------------------------------------------------------------
Current income tax 225 171 220 396 440
----------------------------------------------------------------------------
Deferred income tax expense 55 43 66 98 307
Deferred PRT expense - North
Sea 2 10 3 12 4
----------------------------------------------------------------------------
Deferred income tax 57 53 69 110 311
----------------------------------------------------------------------------
282 224 289 506 751
Income tax rate and other
legislative changes (2) - (104) - (104) (132)
----------------------------------------------------------------------------
$ 282 $ 120 $ 289 $ 402 $ 619
----------------------------------------------------------------------------
Effective income tax rate on
adjusted net earnings from
operations(3) 24.1% 32.7% 28.7% 26.6% 27.6%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Exploration and Production, Midstream, and Oil
Sands Mining and Upgrading segments.
(2) Deferred income tax expense in the first quarter of 2011 included a
charge of $104 million related to substantively enacted changes in the
UK to increase the corporate income tax rate charged on profits from UK
North Sea crude oil and natural gas production from 50% to 62%. Deferred
income tax expense in the first quarter of 2010 included a charge of
$132 million related to changes in Canada to the taxation of
stock options surrendered by employees for cash.
(3) Excludes the impact of current and deferred PRT expense and other
current income tax expense.
Taxable income from the Exploration and Production business in Canada is
primarily generated through partnerships, with the related income taxes payable
in periods subsequent to the current reporting period. North America current and
deferred 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.
In June 2011, the Canadian Federal government tabled a budget that proposed
several taxation changes that could impact the Company. These proposed changes
include:
-- A requirement that all partnership income be included in the taxable
income of its corporate partners based on the tax year of the partner,
previously the fiscal year of the partnership, beginning in 2012. The
budget proposed a transition reserve to amortize the impact of the
change over a five year period;
-- Classification of oil sands lease purchases as Canadian Oil and Gas
Property Expense (COGPE) rather than Canadian Development Expense (CDE);
and
-- Classification of certain pre-production expenses of oil sands mines as
CDE rather than Canadian Exploration Expense (CEE)
To date, no legislation related to the budget proposals has been released.
In March 2011, the UK government substantively enacted an increase to the
supplementary income tax rate charged on profits from UK North Sea crude oil and
natural gas production increasing the combined corporate and supplementary
income tax rate from 50% to 62%. This resulted in an increase to the overall
effective corporate tax rate applicable to net operating income from oil and gas
activities to 62% from 50% for non-PRT paying fields and 81% from 75% for PRT
paying fields, after allowing for deductions for capital and abandonment
expenditures. As a result of the income tax rate change, the Company's deferred
income tax liability was increased by $104 million as at March 31, 2011.
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 2011, based on budgeted prices and the current availability of tax pools,
the Company expects to incur current income tax expense of $300 million to $400
million in Canada and $460 million to $500 million in the North Sea and Offshore
Africa.
NET CAPITAL EXPENDITURES (1)
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Exploration and
Evaluation
Net expenditures $ 41 $ 74 $ 74 $ 115 $ 125
----------------------------------------------------------------------------
Property, Plant and
Equipment
Net property acquisitions 265 224 915 489 948
Land acquisition and
retention 10 10 6 20 18
Seismic evaluations 17 9 9 26 20
Well drilling, completion
and equipping 284 572 250 856 692
Production and related
facilities 382 417 176 799 558
----------------------------------------------------------------------------
Net expenditures 958 1,232 1,356 2,190 2,236
----------------------------------------------------------------------------
Total Exploration and
Production
expenditures 999 1,306 1,430 2,305 2,361
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading:
Horizon Phases 2/3
construction costs 115 90 56 205 127
Coker rebuild and
collateral
damage costs 183 126 - 309 -
Sustaining capital 50 24 27 74 45
Turnaround costs 24 55 - 79 -
Capitalized interest,
share-based
compensation and other (2) 20 42 18 55
----------------------------------------------------------------------------
Total Oil Sands Mining
and Upgrading (2) 370 315 125 685 227
----------------------------------------------------------------------------
Midstream 1 3 1 4 1
Abandonments (3) 29 64 15 93 54
Head office 6 6 5 12 9
----------------------------------------------------------------------------
Total net capital
expenditures $ 1,405 $ 1,694 $ 1,576 $ 3,099 $ 2,652
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 913 $ 1,232 $ 1,350 $ 2,145 $ 2,159
North Sea 69 41 29 110 52
Offshore Africa 17 33 50 50 149
Other - - 1 - 1
Oil Sands Mining and
Upgrading 370 315 125 685 227
Midstream 1 3 1 4 1
Abandonments (3) 29 64 15 93 54
Head office 6 6 5 12 9
----------------------------------------------------------------------------
Total $ 1,405 $ 1,694 $ 1,576 $ 3,099 $ 2,652
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The net capital expenditures exclude adjustments related to differences
between carrying amounts and tax values, and other fair value adjustments.
(2) Net expenditures for the Oil Sands Mining and Upgrading assets also
include the impact of intersegment eliminations.
(3) Abandonments represent expenditures to settle asset retirement
obligations and have been reflected as capital expenditures in this table.
The Company's strategy is focused on building a diversified asset base that is
balanced among various products. In order to facilitate efficient operations,
the Company concentrates its activities in core regions where it can dominate
the land base and infrastructure. The Company focuses on maintaining its land
inventories to enable the continuous exploitation of play types and geological
trends, greatly reducing overall exploration risk. By dominating infrastructure,
the Company is able to maximize utilization of its production facilities,
thereby increasing control over production costs.
Net capital expenditures for the six months ended June 30, 2011 were $3,099
million compared to $2,652 million for the six months ended June 30, 2010. Net
capital expenditures for the second quarter of 2011 were $1,405 million compared
to $1,576 million for the second quarter of 2010 and $1,694 million for the
prior quarter.
The increase in capital expenditures from the six months ended June 30, 2010 was
primarily due to an increase in well drilling and completion expenditures
related to the Company's heavy oil drilling program, an increase in the
Company's abandonment program and costs associated with the coker rebuild and
collateral damage resulting from the coker fire. The decrease in capital
expenditures in the second quarter of 2011 from the prior quarter was primarily
due to lower seasonal spending on drilling activities and related facilities,
partially offset by higher costs associated with the coker rebuild and
collateral damage.
Drilling Activity (number of wells)
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Net successful natural gas
wells 10 25 10 35 55
Net successful crude oil
wells (1) 177 279 92 456 335
Dry wells 5 16 2 21 16
Stratigraphic test / service
wells 19 501 9 520 306
----------------------------------------------------------------------------
Total 211 821 113 1,032 712
Success rate
(excluding stratigraphic
test / service wells) 97% 95% 98% 96% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes bitumen wells.
North America
North America, excluding Oil Sands Mining and Upgrading, accounted for
approximately 73% of the total capital expenditures for the six months ended
June 30, 2011 compared to approximately 84% for the six months ended June 30,
2010.
During the second quarter of 2011, the Company targeted 10 net natural gas
wells, including 6 wells in Northeast British Columbia and 4 wells in Northwest
Alberta. The Company also targeted 182 net crude oil wells. The majority of
these wells were concentrated in the Company's Northern Plains region where 134
primary heavy crude oil wells, 7 Pelican Lake heavy crude oil wells and 37
bitumen (thermal oil) wells were drilled. Another 4 wells targeting light crude
oil were drilled outside the Northern Plains region.
As part of the phased expansion of its In Situ Oil Sands Assets, the Company is
continuing to develop its Primrose thermal projects. Overall Primrose thermal
production for the second quarter of 2011 averaged approximately 106,000 bbl/d,
compared to approximately 96,000 bbl/d for the second quarter of 2010 and
approximately 98,000 bbl/d for the prior quarter.
The next planned phase of the Company's In Situ Oil Sands Assets expansion is
the Kirby South Phase 1 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. During
the fourth quarter of 2010, the Company's Board of Directors sanctioned Kirby
South Phase 1. Construction has commenced, with first steam targeted in 2013.
Development of the tertiary recovery conversion projects at Pelican Lake
continued in the second quarter of 2011. Drilling included 7 horizontal wells
during the quarter. Response from the polymer flood project continues to be
positive, but delayed from the original plan. Pelican Lake production averaged
approximately 35,000 bbl/d for the second quarter of 2011, compared to 37,000
bbl/d for the second quarter of 2010 and 39,000 bbl/d for the prior quarter, due
to the temporary impact of the forest fires in North Central Alberta.
For the third quarter of 2011, the Company's overall planned drilling activity
in North America is expected to be comprised of 24 net natural gas wells and 367
net crude oil wells excluding stratigraphic and service wells.
Oil Sands Mining and Upgrading
Phase 2/3 spending during the second quarter of 2011 continued to be focused on
construction of the third Ore Preparation Plant and associated hydro-transport,
additional product tankage, the butane treatment unit and the sulphur recovery
unit. Commissioning of the Ore Preparation Plant and associated hydro-transport
is currently targeted early in the fourth quarter of 2011.
On January 6, 2011, the Company suspended SCO production at its Oil Sands Mining
and Upgrading operations due to a fire in the primary upgrading coking plant. As
at August 3, 2011, all necessary regulatory and operating approvals to
recommence operations were received. Final mechanical, testing and commissioning
activities are ongoing and production is scheduled for the third quarter of
2011.
During the first quarter of 2011, the Company recognized a Horizon asset
impairment provision of $396 million, net of accumulated depletion and
depreciation, related to the property damage resulting from the fire in the
primary upgrading coking plant. As the Company believes that its insurance
coverage is adequate to mitigate all significant property damage related losses,
estimated insurance proceeds receivable of $396 million were also recognized
offsetting such property damage. The final Horizon asset impairment provision
and related insurance recoveries are subject to revision upon recommencement of
operations and the determination of final costs to restore plant operating
capacity. Accordingly, actual results may differ significantly from the amounts
currently recognized.
The Company also maintains business interruption insurance to reduce operating
losses related to its ongoing operations. During the second quarter of 2011, the
Company recognized business interruption insurance recoveries of $136 million,
based on interim payments and claims processed to date. Additional business
interruption insurance recoveries related to the second and third quarters will
be recognized at such time as additional interim payments are processed and as
the final terms of the insurance settlement are determined.
North Sea
During the second quarter of 2011, the Company continued workover and drilling
operations on the Ninian South Platform.
In March 2011, the UK government substantively enacted an increase to the
corporate income tax rate charged on profits from UK North Sea crude oil and
natural gas production from 50% to 62%. This resulted in an increase to the
overall corporate tax rate applicable to net operating income from oil and gas
activities to 62% for non-PRT paying fields and 81% for PRT paying fields, after
allowing for deductions for capital and abandonment expenditures.
As a result of the increase in the corporate income tax rate, the Company's
development activities in the North Sea will be reduced. The Company is now
maintaining only one drilling string in the North Sea, down from the two
originally planned. The planned drilling activity at Murchison during 2011 was
cancelled. The Company will continue to high grade all North Sea prospects for
potential future development opportunities.
Offshore Africa
During the second quarter of 2011, production at the Olowi Field was temporarily
suspended as a result of the failure of a midwater arch system that provides
support for production and gas lift flowlines and the main power line. All
necessary safety and environmental precautions were undertaken to temporarily
cease operations.
Olowi production was reinstated at Platform C during the second quarter. The
midwater arch was re-secured in the second quarter and after a full evaluation
and appropriate testing, it was determined it can be used to restart production
from Platforms A and B. However damage to the communication cable was not
repairable. As such, a new communication system is being procured with an
expected completion in the third quarter of 2011, at which time production from
the two platforms will be restarted.
LIQUIDITY AND CAPITAL RESOURCES
Jun 30 Mar 31 Dec 31 Jun 30
($ millions, except ratios) 2011 2011 2010 2010
----------------------------------------------------------------------------
Working capital (deficit) (1) $ (1,032) $ (1,657) $ (1,200) $ (430)
Long-term debt (2) (3) $ 8,624 $ 8,468 $ 8,485 $ 9,329
Share capital $ 3,425 $ 3,394 $ 3,147 $ 3,006
Retained earnings 17,989 17,158 17,212 17,150
Accumulated other comprehensive
loss 38 43 9 169
----------------------------------------------------------------------------
Shareholders' equity $ 21,452 $ 20,595 $ 20,368 $ 20,325
Debt to book capitalization
(3)(4) 29% 29% 29% 32%
Debt to market capitalization
(3)(5) 16% 14% 15% 20%
After-tax return on average
common
shareholders' equity (6) 6% 5% 8% -
After-tax return on average
capital employed (3) (7) 5% 5% 7% -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated as current assets less current liabilities, excluding the
current portion of long-term debt.
(2) Includes the current portion of long-term debt.
(3) Long-term debt is stated at its carrying value, net of fair value
adjustments, original issue discounts and transaction costs.
(4) Calculated as current and long-term debt; divided by the book value of
common shareholders' equity plus current and long-term debt.
(5) Calculated as current and long-term debt; divided by the market value of
common shareholders' equity plus current and long-term debt.
(6) Calculated as net earnings for the twelve month trailing period; as a
percentage of average common shareholders' equity for the period. The
ratio for the trailing period ended June 30, 2010 has not been presented
as the period would include 2009 amounts based on Canadian GAAP as
previously reported and therefore may not be comparable.
(7) Calculated as net earnings plus after-tax interest and other financing
costs for the twelve month trailing period; as a percentage of average
capital employed for the period. The ratio for the trailing period ended
June 30, 2010 has not been presented as the period would include 2009
amounts based on Canadian GAAP as previously reported and therefore may
not be comparable.
At June 30, 2011, the Company's capital resources consisted primarily of cash
flow from operations, available bank credit facilities and access to debt
capital markets. Cash flow from operations is dependent on factors discussed in
the "Risks and Uncertainties" section of the Company's December 31, 2010 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.
During the second quarter of 2011, the $2,230 million revolving syndicated
credit facility was increased to $3,000 million and extended to June 2015. Each
of the $3,000 million and $1,500 million facility is extendible annually for one
year periods at the mutual agreement of the Company and the lenders. At June 30,
2011, the Company had $2,800 million of available credit under its bank credit
facilities. Subsequent to June 30, 2011, US $400 million of US dollar
denominated debt securities bearing interest at 6.7% were repaid. During the
fourth quarter of 2010, the Company repaid $400 million of the medium-term notes
bearing interest at 5.50%.
The Company believes that its capital resources are sufficient to compensate for
any short-term cash flow reduction arising from Horizon, and accordingly, the
Company's targeted North America capital program has been increased for 2011.
Long-term debt was $8,624 million at June 30, 2011, resulting in a debt to book
capitalization ratio of 29% (March 31, 2011- 29%; December 31, 2010 - 29%; June
30, 2010 - 32%). 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, adequate available liquidity and flexible
capital structure. The Company has hedged a portion of its crude oil production
for 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 June 30, 2011 are discussed
in note 7 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 June 30, 2011, in
accordance with the policy, approximately 11% of budgeted crude oil volumes were
hedged using collars for 2011. Further details related to the Company's
commodity related derivative financial instruments outstanding at June 30, 2011
are discussed in note 15 to the Company's unaudited interim consolidated
financial statements.
Share capital
As at June 30, 2011, there were 1,097,078,000 common shares outstanding and
60,691,000 stock options outstanding. As at August 2, 2011, the Company had
1,097,205,000 common shares outstanding and 60,333,000 stock options
outstanding.
On March 1, 2011, the Company's Board of Directors approved an increase in the
annual dividend to be paid by the Company to $0.36 per common share for 2011.
The increase represents a 20% increase from 2010, recognizing the stability of
the Company's cash flow and providing a return to Shareholders. The dividend
policy undergoes a periodic review by the Board of Directors and is subject to
change.
On March 31, 2011, the Company announced a Normal Course Issuer Bid to purchase,
through the facilities of the TSX and the NYSE, during the 12 month period
commencing April 6, 2011 and ending April 5, 2012, up to 27,406,131 common
shares or 2.5% of the common shares of the Company outstanding at March 25,
2011. As at August 3, 2011, no common shares had been purchased under this
Normal Course Issuer Bid.
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. A total of 2,000,000 common
shares were purchased for cancellation under this Normal Course Issuer Bid at an
average price of $33.77 per common share, for a total cost of $68 million.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations. As at
June 30, 2011, no entities were consolidated under the Standing Interpretations
Committee 12, "Consolidation - Special Purpose Entities". The following table
summarizes the Company's commitments as at June 30, 2011:
($ millions) 2011 2012 2013 2014 2015 Thereafter
----------------------------------------------------------------------------
Product
transportation and
pipeline $ 119 $ 211 $ 186 $ 176 $ 164 $ 941
Offshore equipment
operating leases $ 80 $ 95 $ 94 $ 95 $ 78 $ 163
Long-term debt (1) $ 386 $ 337 $ 786 $ 337 $ 2,177 $ 4,629
Interest and other
financing costs (2) $ 226 $ 426 $ 389 $ 370 $ 320 $ 4,107
Office leases $ 14 $ 29 $ 33 $ 34 $ 32 $ 336
Other $ 79 $ 69 $ 22 $ 19 $ 25 $ 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does not reflect
fair value adjustments, original issue discounts or transaction costs.
(2) Interest and other financing cost amounts represent the scheduled fixed
rate and variable rate cash interest payments related to long-term debt.
Interest on variable rate long-term debt was estimated based upon
prevailing interest rates and foreign exchange rates as at June 30, 2011.
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is defendant and plaintiff in a number of legal actions arising in
the normal course of business. 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.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
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, including 2010 requirements to capture both Canadian
GAAP and IFRS data.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
In February 2008, the CICA's Accounting Standards Board confirmed that Canadian
publicly accountable enterprises would be required to adopt IFRS as issued by
the IASB in place of Canadian GAAP effective January 1, 2011.
The Company has completed its transition to IFRS. The 2011 fiscal year is the
first year in which the Company has prepared its consolidated financial
statements in accordance with IFRS as issued by the IASB. The interim
consolidated financial statements for the six months ended June 30, 2011 have
been prepared in accordance with IFRS applicable to the preparation of interim
financial statements, including International Accounting Standard ("IAS") 34,
"Interim Financial Reporting" and IFRS 1, "First-time Adoption of International
Financial Reporting Standards".
The accounting policies adopted by the Company under IFRS are set out in note 1
to the interim consolidated financial statements for the six months ended June
30, 2011. Note 18 to the interim consolidated financial statements discloses the
impact of the transition to IFRS on the Company's reported financial position,
earnings and cash flows, including the nature and effect of certain transition
elections and significant changes in accounting policies from those used in the
Company's Canadian GAAP consolidated financial statements for 2010.
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
The Company is required to adopt IFRS 9, "Financial Instruments", effective
January 1, 2013, with earlier adoption permitted. IFRS 9 replaces existing
requirements included in IAS 39, "Financial Instruments - Recognition and
Measurement". The new standard replaces the multiple classification and
measurement models for financial assets and liabilities with a new model that
has only two categories: amortized cost and fair value through profit and loss.
Under IFRS 9, fair value changes due to credit risk for liabilities designated
at fair value through profit and loss would generally be recorded in other
comprehensive income.
In May 2011, the IASB issued the following new accounting standards, which are
required to be adopted effective January 1, 2013:
-- IFRS 10 "Consolidated Financial Statements" replaces IAS 27
"Consolidated and Separate Financial Statements" (IAS 27 still contains
guidance for Separate Financial Statements) and Standing Interpretations
Committee 12 "Consolidation - Special Purpose Entities". IFRS 10
establishes the principles for the presentation and preparation of
consolidated financial statements. The standard defines the principle of
control and establishes control as the basis for consolidation, as well
as providing guidance on how to apply the control principle to determine
whether an investor controls an investee.
-- IFRS 11 "Joint Arrangements" replaces IAS 31 "Interests in Joint
Ventures" and Standing Interpretations Committee 13 "Jointly Controlled
Entities - Non-Monetary Contributions by Venturers". The new standard
defines two types of joint arrangements, joint operations and joint
ventures, and prescribes the accounting treatment for each type of joint
arrangement - proportionate consolidation and equity accounting,
respectively. There is no longer a choice of the accounting method.
-- IFRS 12 "Disclosure of Interests in Other Entities". The standard
includes disclosure requirements for investments in subsidiaries, joint
arrangements, associates and unconsolidated structured entities. This
standard does not impact the Company's accounting for investments in
other entities, but will impact the Company's disclosures.
-- IFRS 13 "Fair Value Measurement" provides guidance on how fair value
should be applied where its use is already required or permitted by
other standards within IFRS. The standard includes a definition of fair
value and a single source of fair value measurement and disclosure
requirements for use across all IFRSs that require or permit the use of
fair value.
In June 2011, the IASB issued amendments to IAS 1 "Presentation of Financial
Statements" that require items of other comprehensive income (OCI) that may be
reclassified to net earnings to be grouped together. The amendments also require
that items in OCI and net earnings be presented as either a single statement or
two consecutive statements. The standard is effective for fiscal years beginning
on or after July 1, 2012.
The Company is currently assessing the impact of these new and amended standards
on its consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING POLICIES
The preparation of financial statements requires the Company to make judgements,
assumptions and estimates in the application of IFRS that have a significant
impact on the financial results of the Company. Actual results could differ from
those estimates, and those differences may be material.
Critical accounting estimates are reviewed by the Company's Audit Committee
annually. The Company believes the following are the most critical accounting
estimates in preparing its consolidated financial statements.
Depletion, Depreciation and Amortization and Impairment
Property, plant and equipment is measured at cost less accumulated depletion and
depreciation and impairment losses. Crude oil and natural gas properties are
depleted using the unit-of-production method over proved reserves. The
unit-of-production rate takes into account expenditures incurred to date,
together with future development expenditures required to develop proved
reserves. Estimates of proved reserves have a significant impact on net
earnings, as they are a key input to the calculation of depletion expense.
Exploration and evaluation ("E&E") asset costs relating to activities to explore
and evaluate crude oil and natural gas properties are initially capitalized and
include costs associated with the acquisition of licenses, technical services
and studies, seismic acquisition, exploration drilling and testing, directly
attributable overhead and administration expenses, and estimated costs
associated with retiring the assets. Exploration and evaluation assets are
carried forward until technical feasibility and commercial viability of
extracting a mineral resource is determined. Technical feasibility and
commercial viability of extracting a mineral resource is considered to be
determined when proved reserves are determined to exist. The judgements
associated with the estimation of proved reserves are described below in "Crude
Oil and Natural Gas Reserves".
An alternative acceptable accounting method for E&E assets under IFRS 6
"Exploration for and Evaluation of Mineral Resources" is to charge exploratory
dry holes and geological and geophysical exploration costs incurred after having
obtained the legal rights to explore an area against net earnings in the period
incurred rather than capitalizing to E&E assets.
E&E assets are tested for impairment when facts and circumstances suggest that
the carrying amount of E&E assets may exceed their recoverable amount, by
comparing the relevant costs to the fair value of Cash Generating Units
("CGUs"), aggregated at the segment level. Indications of impairment include
leases approaching expiry, the existence of low benchmark commodity prices for
an extended period of time, significant downward revisions of estimated
reserves, increases in estimated future exploration expenditures, or significant
adverse changes in the legislative or regulatory frameworks. The determination
of the fair value of CGUs requires the use of assumptions and estimates
including quantities of recoverable reserves, production quantities, future
commodity prices and development and operating costs. Changes in any of these
assumptions, such as a downward revision in reserves, decrease in commodity
prices or increase in costs, could impact the fair value.
The Company assesses property, plant and equipment for impairment whenever
events or changes in circumstances indicate that the carrying value of an asset
or group of assets may not be recoverable. Indications of impairment include the
existence of low commodity prices for an extended period, significant downward
revisions of estimated reserves, increases in estimated future development
expenditures, or significant adverse changes in the legislative or regulatory
frameworks. If any such indication of impairment exists, the Company performs an
impairment test related to the specific assets. Individual assets are grouped
for impairment assessment purposes into CGU's, which are the lowest level at
which there are identifiable cash inflows that are largely independent of the
cash inflows of other groups of assets. The determination of fair value of CGUs
requires the use of assumptions and estimates including quantities of
recoverable reserves, production quantities, future commodity prices and
development and operating costs. Changes in any of these assumptions, such as a
downward revision in reserves, decrease in commodity prices or increase in
costs, could impact the fair value.
Crude Oil and Natural Gas Reserves
The estimation of reserves involves the exercise of judgement. Reserve estimates
are based on engineering data, estimated future prices, expected future rates of
production and the timing of future capital expenditures, all of which are
subject to many uncertainties and interpretations. The Company expects that,
over time, its reserve estimates will be revised either upward or downward based
on updated information such as the results of future drilling, testing and
production levels, and may be affected by changes in commodity prices. Reserve
estimates can have a significant impact on net earnings, as they are a key
component in the calculation of depletion, depreciation and amortization and for
determining potential asset impairment. For example, a revision to the proved
reserve estimates would result in a higher or lower depletion, depreciation and
amortization charge to net earnings. Downward revisions to reserve estimates may
also result in an impairment of crude oil and natural gas property, plant and
equipment carrying amounts.
Asset Retirement Obligations
The Company is required to recognize a liability for asset retirement
obligations ("ARO") associated with its property, plant and equipment. An ARO
liability associated with the retirement of a tangible long-lived asset is
recognized to the extent of a legal obligation resulting from an existing or
enacted law, statute, ordinance or written or oral contract, or by legal
construction of a contract under the doctrine of promissory estoppel. The ARO is
based on estimated costs, taking into account the anticipated method and extent
of restoration consistent with legal requirements, technological advances and
the possible use of the site. Since these estimates are specific to the sites
involved, there are many individual assumptions underlying the Company's total
ARO amount. These individual assumptions can be subject to change.
The estimated present values of ARO related to long-term assets are recognized
as a liability in the period in which they are incurred. The provision for the
ARO is estimated by discounting the expected future cash flows to settle the ARO
at the Company's average credit-adjusted risk-free interest rate, which is
currently 5.1%. Subsequent to initial measurement, the ARO is adjusted to
reflect the passage of time, changes in credit adjusted interest rates, and
changes in the estimated future cash flows underlying the obligation. The
increase in the provision due to the passage of time is recognized as asset
retirement obligation accretion expense whereas increases or decreases due to
changes in interest rates and estimated future cash flows are capitalized to
property, plant and equipment. Changes in estimates would impact accretion and
depletion expense in net earnings. In addition, differences between actual and
estimated costs to settle the ARO, timing of cash flows to settle the obligation
and future inflation rates may result in gains or losses on the final settlement
of the ARO.
Income Taxes
The Company follows the liability method of accounting for income taxes. Under
this method, deferred income tax assets and liabilities are recognized based on
the estimated tax effects of temporary differences between the carrying value of
assets and liabilities in the consolidated financial statements and their
respective tax bases, using income tax rates substantively enacted as at the
date of the balance sheet. Accounting for income taxes is a complex process that
requires the Company to interpret frequently changing laws and regulations,
including changing income tax rates, and make certain judgements with respect to
the application of tax law, estimating the timing of temporary difference
reversals, and estimating the realizability of tax assets. There are many
transactions and calculations for which the ultimate tax determination is
uncertain. The Company recognizes liabilities for potential tax audit issues
based on assessments of whether additional taxes will be due.
Risk Management Activities
The Company utilizes various 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.
Purchase Price Allocations
Purchase prices related to business combinations and asset acquisitions are
allocated to the underlying acquired assets and liabilities based on their
estimated fair value at the time of acquisition. The determination of fair value
requires the Company to make assumptions and estimates regarding future events.
The allocation process is inherently subjective and impacts the amounts assigned
to individually identifiable assets and liabilities. As a result, the purchase
price allocation impacts the Company's reported assets and liabilities and
future net earnings due to the impact on future depletion, depreciation and
amortization expense and impairment tests.
The Company has made various assumptions in determining the fair values of the
acquired assets and liabilities. The most significant assumptions and judgments
relate to the estimation of the fair value of the crude oil and natural gas
properties. To determine the fair value of these properties, the Company
estimates (a) crude oil and natural gas reserves, and (b) future prices of crude
oil and natural gas. Reserve estimates are based on the work performed by the
Company's internal engineers and outside consultants. The judgements associated
with these estimated reserves are described above in "Crude Oil and Natural Gas
Reserves". Estimates of future prices are based on prices derived from price
forecasts among industry analysts and internal assessments. The Company applies
estimated future prices to the estimated reserves quantities acquired, and
estimates future operating and development costs, to arrive at estimated future
net revenues for the properties acquired.
Share-based compensation
The Company has made various assumptions in estimating the fair values of the
common stock options granted including expected volatility, expected exercise
behavior and future forfeiture rates. At each period end, options outstanding
are remeasured for changes in the fair value of the liability.
Consolidated Balance Sheets
(millions of Canadian dollars, Jun 30 Dec 31 Jan 1
unaudited) Note 2011 2010 2010
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 6 $ 22 $ 13
Accounts receivable 1,859 1,481 1,148
Inventory 605 477 438
Prepaids and other 153 129 146
----------------------------------------------------------------------------
2,623 2,109 1,745
Exploration and evaluation assets 4 2,377 2,402 2,293
Property, plant and equipment 5 39,280 38,429 37,018
Other long-term assets 6 378 14 6
----------------------------------------------------------------------------
$ 44,658 $ 42,954 $ 41,062
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 557 $ 274 $ 240
Accrued liabilities 2,134 1,735 1,430
Current income tax liabilities 402 430 94
Current portion of long-term debt 7 386 397 400
Current portion of other long-term
liabilities 8 562 870 854
----------------------------------------------------------------------------
4,041 3,706 3,018
Long-term debt 7 8,238 8,088 9,259
Other long-term liabilities 8 3,057 3,004 2,485
Deferred income tax liabilities 7,870 7,788 7,462
----------------------------------------------------------------------------
23,206 22,586 22,224
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital 11 3,425 3,147 2,834
Retained earnings 17,989 17,212 15,927
Accumulated other comprehensive income 12 38 9 77
----------------------------------------------------------------------------
21,452 20,368 18,838
----------------------------------------------------------------------------
$ 44,658 $ 42,954 $ 41,062
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments and contingencies (Note 16)
Approved by the Board of Directors on August 3, 2011
Consolidated Statements of Earnings
Three Months Ended Six Months Ended
----------------------------------------------------------------------------
(millions of Canadian
dollars, except per
common share amounts, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) Note 2011 2010 2011 2010
----------------------------------------------------------------------------
Product sales $ 3,727 $ 3,614 $ 7,029 $ 7,194
Less: royalties (394) (324) (745) (677)
----------------------------------------------------------------------------
Revenue 3,333 3,290 6,284 6,517
----------------------------------------------------------------------------
Expenses
Production 833 812 1,678 1,706
Transportation and blending 665 559 1,286 973
Depletion, depreciation and
amortization 5 870 879 1,719 1,676
Administration 69 60 123 114
Share-based compensation 8 (188) (87) (60) (58)
Asset retirement obligation
accretion 8 31 31 64 61
Interest and other
financing costs 99 110 193 219
Risk management activities 15 (84) (177) 40 (348)
Foreign exchange (gain)
loss (37) 163 (104) 37
Horizon asset impairment
provision 9 - - 396 -
Insurance recovery -
property damage 9 - - (396) -
Insurance recovery -
business
interruption 9 (136) - (136) -
----------------------------------------------------------------------------
2,122 2,350 4,803 4,380
----------------------------------------------------------------------------
Earnings before taxes 1,211 940 1,481 2,137
Current income tax expense 10 225 220 396 440
Deferred income tax expense 10 57 69 110 311
----------------------------------------------------------------------------
Net earnings $ 929 $ 651 $ 975 $ 1,386
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
share
Basic 14 $ 0.85 $ 0.60 $ 0.89 $ 1.28
Diluted 14 $ 0.84 $ 0.60 $ 0.88 $ 1.27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income
Three Months Six Months
Ended Ended
----------------------------------------------------------------------------
(millions of Canadian dollars, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) 2011 2010 2011 2010
----------------------------------------------------------------------------
Net earnings $ 929 $ 651 $ 975 $ 1,386
----------------------------------------------------------------------------
Net change in derivative financial
instruments designated as cash
flow hedges
Unrealized (loss) income during
the period, net of taxes of
$ 4 million (2010 - $15 million)
- three months ended;
$ 1 million (2010 - $13 million)
- six months ended (20) 106 (2) 94
Reclassification to net earnings,
net of taxes of
$5 million (2010 - $1 million) -
three months ended;
$9 million (2010 - $1 million) -
six months ended 18 (3) 29 (3)
----------------------------------------------------------------------------
(2) 103 27 91
Foreign currency translation
adjustment
Translation of net investment (3) 33 2 1
----------------------------------------------------------------------------
Other comprehensive (loss) income,
net of taxes (5) 136 29 92
----------------------------------------------------------------------------
Comprehensive income $ 924 $ 787 $ 1,004 $ 1,478
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Changes in Equity
Six Months Ended
----------------------------------------------------------------------------
(millions of Canadian dollars, Jun 30 Jun 30
unaudited) Note 2011 2010
----------------------------------------------------------------------------
Share capital 11
Balance - beginning of period $ 3,147 $ 2,834
Issued upon exercise of stock options 181 74
Previously recognized liability on stock
options exercised for common shares 97 98
----------------------------------------------------------------------------
Balance - end of period 3,425 3,006
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period 17,212 15,927
Net earnings 975 1,386
Dividends on common shares 11 (198) (163)
----------------------------------------------------------------------------
Balance - end of period 17,989 17,150
----------------------------------------------------------------------------
Accumulated other comprehensive income 12
Balance - beginning of period 9 77
Other comprehensive income, net of taxes 29 92
----------------------------------------------------------------------------
Balance - end of period 38 169
----------------------------------------------------------------------------
Shareholders' equity $ 21,452 $ 20,325
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months Ended Six Months Ended
(millions of Canadian dollars, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) Note 2011 2010 2011 2010
----------------------------------------------------------------------------
Operating activities
Net earnings $ 929 $ 651 $ 975 $ 1,386
Non-cash items
Depletion, depreciation and
amortization 870 879 1,719 1,676
Share-based compensation (188) (87) (60) (58)
Asset retirement obligation
accretion 31 31 64 61
Unrealized risk management
gain (118) (86) (64) (296)
Unrealized foreign exchange
(gain) loss (33) 172 (122) 56
Deferred income tax expense 57 69 110 311
Horizon asset impairment
provision 9 - - 396 -
Insurance recovery - property
damage 9 - - (396) -
Other 11 11 (18) (16)
Abandonment expenditures (29) (15) (93) (54)
Net change in non-cash working
capital (98) 199 166 90
----------------------------------------------------------------------------
1,432 1,824 2,677 3,156
----------------------------------------------------------------------------
Financing activities
Issue (repayment) of
bank credit facilities, net 205 85 333 (443)
Issue of common shares on
exercise of stock options 19 34 181 74
Dividends on common shares (98) (81) (180) (138)
Net change in non-cash working
capital (5) - (5) (4)
----------------------------------------------------------------------------
121 38 329 (511)
----------------------------------------------------------------------------
Investing activities
Expenditures on exploration and
evaluation assets and
property, plant
and equipment (1,376) (1,561) (3,006) (2,598)
Investment in other long-term assets - - (346) -
Net change in non-cash working
capital (221) (303) 330 (41)
----------------------------------------------------------------------------
(1,597) (1,864) (3,022) (2,639)
----------------------------------------------------------------------------
(Decrease) increase in cash and
cash equivalents (44) (2) (16) 6
Cash and cash equivalents -
beginning of period 50 21 22 13
----------------------------------------------------------------------------
Cash and cash equivalents -
end of period $ 6 $ 19 $ 6 $ 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 78 $ 80 $ 225 $ 232
Income taxes paid (recovered) $ 93 $ (40) $ 375 $ 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes to the Consolidated Financial Statements
(tabular amounts in millions of Canadian dollars, unless otherwise stated,
unaudited)
1. ACCOUNTING POLICIES
Canadian Natural Resources Limited (the "Company") is a senior independent crude
oil and natural gas exploration, development and production company. The
Company's exploration and production operations are focused in North America,
largely in Western Canada; the United Kingdom ("UK") portion of the North Sea;
and Cote d'Ivoire, Gabon, and South Africa in Offshore Africa.
The Horizon Oil Sands Mining and Upgrading segment ("Horizon") produces
synthetic crude oil through bitumen mining and upgrading operations.
Also within Western Canada, the Company maintains certain midstream activities
that include pipeline operations and an electricity co-generation system.
The Company was incorporated in Alberta, Canada. The address of its registered
office is 2500, 855-2 Street S.W., Calgary, Alberta.
In 2010, the Canadian Institute of Chartered Accountants ("CICA") Handbook was
revised to incorporate International Financial Reporting Standards ("IFRS") and
require publicly accountable enterprises to apply IFRS effective for years
beginning on or after January 1, 2011. The 2011 fiscal year is the first year in
which the Company has prepared its consolidated financial statements in
accordance with IFRS as issued by the International Accounting Standards Board.
These interim consolidated financial statements have been prepared in accordance
with IFRS applicable to the preparation of interim financial statements,
including International Accounting Standard ("IAS") 34, "Interim Financial
Reporting" and IFRS 1, "First-time Adoption of International Financial Reporting
Standards". Certain disclosures that are normally required to be included in the
notes to the annual audited consolidated financial statements have been
condensed.
The accounting policies adopted by the Company under IFRS are set out below and
are based on IFRS issued and outstanding as at August 3, 2011. Subject to
certain transition elections disclosed in Note 18, the Company has consistently
applied the same accounting policies in its opening IFRS balance sheet at
January 1, 2010 and throughout all periods presented, as if these policies had
always been in effect. Any subsequent changes to IFRS that are given effect in
the Company's annual consolidated financial statements for the year ending
December 31, 2011 may result in restatement of these interim consolidated
financial statements, including the adjustments recognized on transition to
IFRS.
Comparative information for 2010 has been restated from Canadian Generally
Accepted Accounting Principles ("Canadian GAAP") to comply with IFRS. In these
consolidated financial statements, Canadian GAAP refers to Canadian GAAP before
the adoption of IFRS. Note 18 discloses the impact of the transition to IFRS on
the Company's reported financial position, earnings and cash flows, including
the nature and effect of significant changes in accounting policies from those
used in the Company's Canadian GAAP consolidated financial statements for the
year ended December 31, 2010.
(A) PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and
all of its subsidiary companies and partnerships. Certain of the Company's
activities are conducted through joint arrangements where the Company has a
direct ownership interest in jointly controlled assets. The revenue, expenses,
assets and liabilities related to the jointly controlled assets are included in
the consolidated financial statements in proportion to the Company's interest.
(B) CASH AND CASH EQUIVALENTS
Cash comprises cash on hand and demand deposits. Other investments (term
deposits and certificates of deposit) with an original term to maturity at
purchase of three months or less are reported as cash equivalents in the
consolidated balance sheets.
(C) INVENTORIES
Inventories are primarily comprised of product inventory and materials and
supplies. Product inventory includes crude oil held for sale, pipeline linefill
and crude oil stored in floating production, storage and offloading vessels.
Inventories are carried at the lower of cost and net realizable value. Cost
consists of purchase costs, direct production costs, direct overhead and
depletion, depreciation and amortization and is determined on a first-in,
first-out basis. Net realizable value is determined by reference to forward
prices as at the date of the consolidated balance sheets.
(D) EXPLORATION AND EVALUATION ASSETS
Exploration and evaluation ("E&E") assets consist of the Company's crude oil and
natural gas exploration projects that are pending the determination of proved
reserves. The Company accounts for E&E costs in accordance with the requirements
of IFRS 6 "Exploration for and Evaluation of Mineral Resources".
E&E costs relating to activities to explore and evaluate crude oil and natural
gas properties are initially capitalized and include costs associated with the
acquisition of licenses, technical services and studies, seismic acquisition,
exploration drilling and testing, directly attributable overhead and
administration expenses, and the estimated costs associated with retiring the
assets. E&E costs do not include general prospecting or evaluation costs
incurred prior to having obtained the legal rights to explore an area, which are
recognized immediately in net earnings.
Once the technical feasibility and commercial viability of E&E assets are
determined and a development decision is made by management, the E&E assets are
tested for impairment upon reclassification to property, plant and equipment.
The technical feasibility and commercial viability of extracting a mineral
resource is considered to be determined when proved reserves are determined to
exist.
E&E assets are also tested for impairment when facts and circumstances suggest
that the carrying amount of E&E assets may exceed their recoverable amount, by
comparing the relevant costs to the fair value of Cash Generating Units
("CGUs"), aggregated at the segment level. Indications of impairment include
leases approaching expiry, the existence of low benchmark commodity prices for
an extended period of time, significant downward revisions in estimated
reserves, significant increases in estimated future exploration or development
expenditures, or significant adverse changes in the applicable legislative or
regulatory frameworks.
(E) PROPERTY, PLANT AND EQUIPMENT
Exploration and Production
Property, plant and equipment is measured at cost less accumulated depletion and
depreciation and impairment provisions. When significant components of an item
of property, plant and equipment, including crude oil and natural gas interests,
have different useful lives, they are accounted for separately.
The cost of an asset comprises its acquisition, construction and development
costs, costs directly attributable to bringing the asset into operation, the
estimate of any asset retirement costs, and applicable borrowing costs. Property
acquisition costs are comprised of the aggregate amount paid and the fair value
of any other consideration given to acquire the asset. The capitalized value of
a finance lease is also included in property, plant and equipment.
The cost of property, plant and equipment at January 1, 2010, the date of
transition to IFRS, was determined as described in Note 18.
Crude oil and natural gas properties are depleted using the unit-of-production
method over proved reserves. The unit-of-production rate takes into account
expenditures incurred to date, together with future development expenditures
required to develop proved reserves.
Oil Sands Mining and Upgrading
Horizon is comprised of both mining and upgrading operations and accordingly,
capitalized costs are reported in a separate operating segment from the
Company's North America Exploration and Production segment. Capitalized mining
activity costs include property acquisition, construction and development costs,
the estimate of any asset retirement costs, and applicable borrowing costs.
Construction and development costs are capitalized separately to each phase of
Horizon. The construction and development of a particular phase of Horizon is
considered complete once the phase is available for its intended use.
Mine-related costs and costs of the upgrader and related infrastructure located
on the Horizon site are amortized on the unit-of-production method based on
Horizon proved reserves or productive capacity. Moveable mine-related equipment
is depreciated on a straight-line basis over its estimated useful life.
Midstream and head office
The Company capitalizes all costs that expand the capacity or extend the useful
life of the assets. Midstream assets are depreciated on a straight-line basis
over their estimated lives. Head office assets are amortized on a declining
balance basis.
Useful lives
The expected useful lives of property, plant and equipment are reviewed on an
annual basis, with changes in useful lives accounted for prospectively.
Derecognition
An item of property, plant and equipment is derecognized upon disposal or when
no future economic benefits are expected to arise from the continued use of the
asset. Any gain or loss arising on derecognition of the asset (calculated as the
difference between the net disposal proceeds and the carrying amount of the
item) is recognized in net earnings.
Major maintenance expenditures
Inspection costs associated with major maintenance turnarounds are capitalized
and amortized over the period to the next major maintenance turnaround. All
other maintenance costs are expensed as incurred.
Impairment
The Company assesses property, plant and equipment for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
or group of assets may not be recoverable. Indications of impairment include the
existence of low benchmark commodity prices for an extended period of time,
significant downward revisions of estimated reserves, significant increases in
estimated future development expenditures, or significant adverse changes in the
applicable legislative or regulatory frameworks. If any such indication of
impairment exists, the Company performs an impairment test related to the
assets. Individual assets are grouped for impairment assessment purposes into
CGU's, which are the lowest level at which there are identifiable cash inflows
that are largely independent of the cash inflows of other groups of assets. A
CGU's recoverable amount is the higher of its fair value less costs to sell and
its value in use. Where the carrying amount of a CGU exceeds its recoverable
amount, the CGU is considered impaired and is written down to its recoverable
amount.
In subsequent periods, an assessment is made at each reporting date to determine
whether there is any indication that previously recognized impairment losses may
no longer exist or may have decreased. If such indication exists, the
recoverable amount is re-estimated and the net carrying amount of the asset is
increased to its revised recoverable amount. The recoverable amount cannot
exceed the carrying amount that would have been determined, net of depletion,
had no impairment loss been recognized for the asset in prior periods. Such
reversal is recognized in net earnings. After a reversal, the depletion charge
is adjusted in future periods to allocate the asset's revised carrying amount
over its remaining useful life.
(F) OVERBURDEN REMOVAL COSTS
Overburden removal costs incurred during the initial development of a mine are
capitalized to property, plant and equipment. Overburden removal costs incurred
during the production of a mine are included in the cost of inventory, unless
the overburden removal activity has resulted in a probable inflow of future
economic benefits to the Company, in which case the costs are capitalized to
property, plant and equipment. Capitalized overburden removal costs are
amortized over the life of the mining reserves that directly benefit from the
overburden removal activity.
(G) CAPITALIZED BORROWING COSTS
Borrowing costs attributable to the acquisition, construction or production of
qualifying assets are capitalized to the cost of those assets until such time as
the assets are substantially available for their intended use. Qualifying assets
are comprised of those significant assets that require a period greater than one
year to be available for their intended use. All other borrowing costs are
recognized in net earnings.
(H) LEASES
Finance leases, which transfer substantially all of the risks and rewards
incidental to ownership of the leased item to the Company, are capitalized at
the commencement of the lease term at the fair value of the leased property or,
if lower, at the present value of the minimum lease payments. Capitalized leased
assets are depreciated over the shorter of the estimated useful life of the
asset or the lease term. Operating lease payments are recognized in production
expense in the statements of earnings over the lease term.
(I) ASSET RETIREMENT OBLIGATIONS
The Company provides for asset retirement obligations on all of its property,
plant and equipment based on current legislation and industry operating
practices. Provisions for asset retirement obligations related to property,
plant and equipment are recognized as a liability in the period in which they
are incurred. Provisions are measured at the present value of management's best
estimate of expenditures required to settle the present obligation at the date
of the balance sheet. Subsequent to the initial measurement, the obligation is
adjusted to reflect the passage of time, changes in credit adjusted interest
rates, and changes in the estimated future cash flows underlying the obligation.
The increase in the provision due to the passage of time is recognized as asset
retirement obligation accretion expense whereas increases/decreases due to
changes in interest rates and the estimated future cash flows are capitalized to
property, plant, and equipment. Actual costs incurred upon settlement of the
asset retirement obligation are charged against the provision.
(J) FOREIGN CURRENCY TRANSLATION
(i) Functional and presentation currency
Items included in the financial statements of the Company's subsidiary companies
and partnerships are measured using the currency of the primary economic
environment in which the subsidiary operates (the "functional currency"). The
consolidated financial statements are presented in Canadian dollars, which is
the Company's functional currency.
The assets and liabilities of subsidiaries that have a functional currency
different from that of the Company are translated into Canadian dollars at the
closing rate at the date of the balance sheet, and revenue and expenses are
translated at the average rate for the period. Cumulative foreign currency
translation adjustments are recognized in other comprehensive income.
When the Company disposes of its entire interest in a foreign operation, or
loses control, joint control, or significant influence over a foreign operation,
the foreign currency gains or losses accumulated in other comprehensive income
related to the foreign operation are recognized in net earnings.
(ii) Transactions and balances
Foreign currency transactions are translated into the functional currency using
the exchange rates prevailing at the dates of the transactions. Foreign exchange
gains and losses resulting from the settlement of foreign currency transactions
and from the translation at balance sheet date exchange rates of monetary assets
and liabilities denominated in currencies other than the functional currency of
the Company are recognized in net earnings.
(K) REVENUE RECOGNITION AND COSTS OF GOODS SOLD
Revenue from the sale of crude oil and natural gas is recognized when title
passes to the customer, delivery has taken place and collection is reasonably
assured. The Company assesses customer creditworthiness, both before entering
into contracts and throughout the revenue recognition process.
Revenue represents the Company's share net of royalty payments to governments
and other mineral interest owners. Related costs of goods sold are comprised of
production, transportation and blending, and depletion, depreciation and
amortization expenses. These amounts have been separately presented in the
consolidated statements of earnings.
(L) PRODUCTION SHARING CONTRACTS
Production generated from Offshore Africa is currently shared under the terms of
various Production Sharing Contracts ("PSCs"). Product sales are divided into
cost recovery oil and profit oil. Cost recovery oil allows the Company to
recover its capital and production costs and the costs carried by the Company on
behalf of the respective Government State Oil Companies (the "Governments").
Profit oil is allocated to the joint venture partners in accordance with their
respective equity interests, after a portion has been allocated to the
Governments. The Governments' share of profit oil attributable to the Company's
equity interest is allocated to royalty expense and current income tax expense
in accordance with the terms of the PSCs.
(M) INCOME TAX
The Company follows the liability method of accounting for income taxes. Under
this method, deferred income tax assets and liabilities are recognized based on
the estimated tax effects of temporary differences in the carrying amount of
assets and liabilities in the consolidated financial statements and their
respective tax bases.
Deferred income tax assets and liabilities are calculated using the
substantively enacted income tax rates that are expected to apply when the asset
or liability is recovered. Deferred income tax assets or liabilities are not
recognized when they arise on the initial recognition of an asset or liability
in a transaction (other than in a business combination) that, at the time of the
transaction, affects neither accounting nor taxable profit. Deferred income tax
assets or liabilities are also not recognized on possible future distributions
of retained earnings of subsidiaries where the timing of the distribution can be
controlled by the Company and it is probable that a distribution will not be
made in the foreseeable future, or when distributions can be made without
incurring income taxes.
Deferred income tax assets for deductible temporary differences and tax loss
carry forwards are recognized to the extent that it is probable that future
taxable profits will be available against which the temporary differences or tax
loss carry forwards can be utilized. The carrying amount of deferred income tax
assets is reviewed at each reporting date, and is reduced if it is no longer
probable that sufficient future taxable profits will be available against which
the temporary differences or tax loss carry forwards can be utilized.
Current income tax is calculated based on net earnings for the period, adjusted
for items that are non-taxable or taxed in different periods, using income tax
rates that are substantively enacted at each reporting date. Income taxes are
recognized in net earnings or other comprehensive income, consistent with the
items to which they relate.
Taxable income arising from the Exploration and Production business in Canada is
primarily generated through partnerships, with the related income taxes payable
in periods subsequent to the current reporting period. Accordingly, North
America current and deferred income taxes have been provided on the basis of
this corporate structure.
(N) SHARE-BASED COMPENSATION
The Company's Stock Option Plan (the "Option Plan") provides current employees
with the right to elect to receive common shares or a direct cash payment in
exchange for options surrendered. The liability for awards granted to employees
is initially measured based on the grant date fair value of the awards and the
number of awards expected to vest. The awards are re-measured for subsequent
changes in the fair value of the liability. Fair value is determined using the
Black-Scholes valuation model. Expected volatility is estimated based on
historic results. Re-measurements are recognized in each reporting period. When
stock options are surrendered for cash, the cash settlement paid reduces the
outstanding liability. When stock options are exercised for common shares under
the Option Plan, consideration paid by the employee and any previously
recognized liability associated with the stock options are recorded as share
capital.
(O) FINANCIAL INSTRUMENTS
The Company classifies its financial instruments into one of the following
categories: fair value through profit or loss; held-to-maturity investments;
loans and receivables; and financial liabilities measured at amortized cost. All
financial instruments are measured at fair value on initial recognition.
Measurement in subsequent periods is dependent on the classification of the
respective financial instrument.
Fair value through profit or loss financial instruments are subsequently
measured at fair value with changes in fair value recognized in net earnings.
All other categories of financial instruments are measured at amortized cost
using the effective interest method.
Cash, cash equivalents, and accounts receivable are classified as loans and
receivables. Accounts payable, accrued liabilities, certain other long-term
liabilities, and long-term debt are classified as other financial liabilities
measured at amortized cost. Risk management assets and liabilities are
classified as fair value through profit or loss.
Financial assets and liabilities are also categorized using a three-level
hierarchy that reflects the significance of the inputs used in making fair value
measurements for these assets and liabilities. The fair values of financial
assets and liabilities included in Level 1 are determined by reference to quoted
prices in active markets for identical assets and liabilities. Fair values of
financial assets and liabilities in Level 2 are based on inputs other than Level
1 quoted prices that are observable for the asset or liability either directly
(as prices) or indirectly (derived from prices). The fair values of Level 3
financial assets and liabilities are not based on observable market data. The
disclosure of the fair value hierarchy excludes financial assets and liabilities
where book value approximates fair value due to the liquid nature of the asset
or liability.
Transaction costs in respect of financial instruments at fair value through
profit or loss are recognized immediately in net earnings. Transaction costs in
respect of other financial instruments are included in the initial measurement
of the financial instrument.
Impairment of financial assets
At each reporting date, the Company assesses whether there is objective evidence
that a financial asset is impaired. If such evidence exists, an impairment loss
is recognized.
Impairment losses on financial assets carried at amortized cost including loans
and receivables are calculated as the difference between the amortized cost of
the loan or receivable and the present value of the estimated future cash flows,
discounted using the instrument's original effective interest rate. Impairment
losses on financial assets carried at amortized cost are reversed in subsequent
periods if the amount of the loss decreases and the decrease can be related
objectively to an event occurring after the impairment was recognized.
(P) RISK MANAGEMENT ACTIVITIES
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. All derivative financial instruments are recognized in the
consolidated balance sheets at their estimated fair value as determined based on
appropriate internal valuation methodologies and/or third party indications.
Fair values determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows and discount rates. The
Company's own credit risk is not included in the carrying amount of the risk
management liability.
The Company documents all derivative financial instruments that are formally
designated as hedging transactions at the inception of the hedging relationship,
in accordance with the Company's risk management policies. The effectiveness of
the hedging relationship is evaluated, both at inception of the hedge and on an
ongoing basis.
The Company periodically enters into commodity price contracts to manage
anticipated sales and purchases of crude oil and natural gas in order to protect
cash flow for capital expenditure programs. The effective portion of changes in
the fair value of derivative commodity price contracts formally designated as
cash flow hedges is initially recognized in other comprehensive income and is
reclassified to risk management activities in net earnings in the same period or
periods in which the commodity is sold or purchased. The ineffective portion of
changes in the fair value of these designated contracts is immediately
recognized in risk management activities in net earnings. All changes in the
fair value of non-designated crude oil and natural gas commodity price contracts
are included in risk management activities in net earnings.
The Company periodically enters into interest rate swap contracts to manage its
fixed to floating interest rate mix on certain of its 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.
Changes in the fair value of interest rate swap contracts designated as fair
value hedges and corresponding changes in the fair value of the hedged long-term
debt are included in interest expense in net earnings. Changes in the fair value
of non-designated interest rate swap contracts are included in risk management
activities in net earnings.
Cross currency swap contracts are periodically used to manage currency exposure
on US dollar denominated long-term debt. 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. Changes in the fair
value of the foreign exchange component of cross currency swap contracts
designated as cash flow hedges related to the notional principal amounts are
included in foreign exchange gains and losses in net earnings. The effective
portion of changes in the fair value of the interest rate component of cross
currency swap contracts designated as cash flow hedges is initially included in
other comprehensive income and is reclassified to interest expense when
realized, with the ineffective portion recognized in risk management activities
in net earnings. Changes in the fair value of non-designated cross currency swap
contracts are included in risk management activities in net earnings.
Realized gains or losses on the termination of financial instruments that have
been designated as cash flow hedges are deferred under accumulated other
comprehensive income on the consolidated balance sheets and amortized into net
earnings in the period in which the underlying hedged items are recognized. In
the event a designated hedged item is sold, extinguished or matures prior to the
termination of the related derivative instrument, any unrealized derivative gain
or loss is recognized immediately in net earnings. Realized gains or losses on
the termination of financial instruments that have not been designated as hedges
are recognized immediately in net earnings.
Upon termination of an interest rate swap designated as a fair value hedge, the
interest rate swap is derecognized on the consolidated balance sheets and the
related long-term debt hedged is no longer revalued for subsequent changes in
fair value. The fair value adjustment on the long-term debt at the date of
termination of the interest rate swap is amortized to interest expense over the
remaining term of the long-term debt.
Foreign currency forward contracts are periodically used to manage foreign
currency cash requirements. The foreign currency forward contracts involve the
purchase or sale of an agreed upon amount of US dollars at a specified future
date at forward exchange rates. Changes in the fair value of foreign currency
forward contracts designated as cash flow hedges are initially recorded in other
comprehensive income and are reclassified to foreign exchange gains and losses
when realized. Changes in the fair value of foreign currency forward contracts
not included as hedges are included in risk management activities and recognized
immediately in net earnings.
Embedded derivatives are derivatives that are included in a non-derivative host
contract. Embedded derivatives are recorded at fair value separately from the
host contract when their economic characteristics and risks are not clearly and
closely related to the host contract.
(Q) COMPREHENSIVE INCOME
Comprehensive income is comprised of the Company's net earnings and other
comprehensive income. Other comprehensive income includes the effective portion
of changes in the fair value of derivative financial instruments designated as
cash flow hedges and foreign currency translation gains and losses on the net
investment in self-sustaining foreign operations. Other comprehensive income is
shown net of related income taxes.
(R) PER COMMON SHARE AMOUNTS
The Company calculates basic earnings per share by dividing net earnings by the
weighted average number of common shares outstanding during the period. As the
Company's stock option plan allows for the settlement of stock options in either
cash or shares at the option of the holder, diluted earnings per share is
calculated using the more dilutive of cash settlement or share settlement under
the treasury stock method.
(S) SHARE CAPITAL
Common shares are classified as equity. Costs directly attributable to the issue
of new shares or options are shown in equity as a deduction, net of tax, from
proceeds. When common shares are repurchased, the amount of the consideration
paid, net of the excess of the purchase price of common shares over their
average carrying value, is recognized as a reduction of share capital. The
excess of the purchase price over the average carrying value is recognized as a
reduction of retained earnings. Repurchased shares are cancelled upon purchase.
(T) DIVIDENDS
Dividends on common shares are recognized in the Company's financial statements
in the period in which the dividends are approved by the Board of Directors.
2. ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
The Company is required to adopt IFRS 9, "Financial Instruments", effective
January 1, 2013, with earlier adoption permitted. IFRS 9 replaces existing
requirements included in IAS 39, "Financial Instruments - Recognition and
Measurement". The new standard replaces the multiple classification and
measurement models for financial assets and liabilities with a new model that
has only two categories: amortized cost and fair value through profit and loss.
Under IFRS 9, fair value changes due to credit risk for liabilities designated
at fair value through profit and loss would generally be recorded in other
comprehensive income.
In May 2011, the IASB issued the following new accounting standards, which are
required to be adopted effective January 1, 2013:
-- IFRS 10 "Consolidated Financial Statements" replaces IAS 27
"Consolidated and Separate Financial Statements" (IAS 27 still contains
guidance for Separate Financial Statements) and Standing Interpretations
Committee 12 "Consolidation - Special Purpose Entities". IFRS 10
establishes the principles for the presentation and preparation of
consolidated financial statements. The standard defines the principle of
control and establishes control as the basis for consolidation, as well
as providing guidance on how to apply the control principle to determine
whether an investor controls an investee.
-- IFRS 11 "Joint Arrangements" replaces IAS 31 "Interests in Joint
Ventures" and Standing Interpretations Committee 13 "Jointly Controlled
Entities - Non-Monetary Contributions by Venturers". The new standard
defines two types of joint arrangements, joint operations and joint
ventures, and prescribes the accounting treatment for each type of joint
arrangement - proportionate consolidation and equity accounting,
respectively. There is no longer a choice of the accounting method.
-- IFRS 12 "Disclosure of Interests in Other Entities". The standard
includes disclosure requirements for investments in subsidiaries, joint
arrangements, associates and unconsolidated structured entities. This
standard does not impact the Company's accounting for investments in
other entities, but will impact the Company's disclosures.
-- IFRS 13 "Fair Value Measurement" provides guidance on how fair value
should be applied where its use is already required or permitted by
other standards within IFRS. The standard includes a definition of fair
value and a single source of fair value measurement and disclosure
requirements for use across all IFRSs that require or permit the use of
fair value.
In June 2011, the IASB issued amendments to IAS 1 "Presentation of Financial
Statements" that require items of other comprehensive income ("OCI") that may be
reclassified to net earnings to be grouped together. The amendments also require
that items in OCI and net earnings be presented as either a single statement or
two consecutive statements. The standard is effective for fiscal years beginning
on or after July 1, 2012.
The Company is currently assessing the impact of these new and amended standards
on its consolidated financial statements.
3. CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS
The Company has made estimates and assumptions regarding certain assets,
liabilities, revenues and expenses in the preparation of the consolidated
financial statements. Such estimates primarily relate to unsettled transactions
and events as of the date of the consolidated financial statements. Accordingly,
actual results may differ from estimated amounts. The estimates and assumptions
that have a significant risk of causing a material adjustment to the carrying
amounts of assets and liabilities within the next financial year are addressed
below.
(a) Estimates of crude oil and natural gas reserves
Purchase price allocations, depletion, depreciation and amortization, and
amounts used in impairment calculations are based on estimates of crude oil and
natural gas reserves. Reserve estimates are based on engineering data, estimated
future prices, expected future rates of production and the timing of future
capital expenditures, all of which are subject to many uncertainties and
interpretations. The Company expects that, over time, its reserve estimates will
be revised upward or downward based on updated information such as the results
of future drilling, testing and production levels, and may be affected by
changes in commodity prices.
(b) Asset retirement obligations
The calculation of asset retirement obligations includes estimates of the future
costs and the timing of the cash flows to settle the liability, the discount
rate used in reflecting the passage of time, and future inflation rates.
(c) Income taxes
The Company is subject to income taxes in numerous jurisdictions. Accounting for
income taxes is a complex process that requires the Company to interpret
frequently changing laws and regulations, including changing income tax rates,
and make certain judgments with respect to the application of tax law,
estimating the timing of temporary difference reversals, and estimating the
realizability of tax assets. There are many transactions and calculations for
which the ultimate tax determination is uncertain. The Company recognizes
liabilities for potential tax audit issues based on assessments of whether
additional taxes will be due.
(d) Fair value of derivatives and other financial instruments
The fair value of financial instruments that are not traded in an active market
is determined using valuation techniques. The Company uses its judgement to
select a variety of methods and make assumptions that are primarily based on
market conditions existing at the end of each reporting period. The Company uses
directly and indirectly observable inputs in measuring the value of financial
instruments that are not traded in active markets, including quoted commodity
prices and volatility, interest rate yield curves and foreign exchange rates.
(e) Purchase price allocations
Purchase prices related to business combinations and asset acquisitions are
allocated to the underlying acquired assets and liabilities based on their
estimated fair value at the time of acquisition. The determination of fair value
requires the Company to make assumptions and estimates regarding future events.
The allocation process is inherently subjective and impacts the amounts assigned
to individually identifiable assets and liabilities, including the fair value of
crude oil and natural gas properties. As a result, the purchase price allocation
impacts the Company's reported assets and liabilities and future net earnings
due to the impact on future depletion, depreciation, and amortization expense
and impairment tests.
(f) Share-based compensation
The Company has made various assumptions in estimating the fair values of the
common stock options granted including expected volatility, expected exercise
behavior and future forfeiture rates. At each period end, options outstanding
are remeasured for changes in the fair value of the liability.
(g) Identification of cash generating units
Cash generating units are defined as the lowest grouping of integrated assets
that generate identifiable cash inflows that are largely independent of the cash
inflows of other assets or groups of assets. The classification of assets into
cash generating units requires significant judgment and interpretations with
respect to the integration between assets, the existence of active markets,
external users, shared infrastructures, and the way in which management monitors
the Company's operations.
4. EXPLORATION AND EVALUATION ASSETS
Oil Sands
Mining and
Exploration and Production Upgrading Total
----------------------------------------------------------------------------
North North Offshore
America Sea Africa
----------------------------------------------------------------------------
Cost
At January 1, 2010 $ 2,102 $ - $ 191 $ - $ 2,293
Additions 563 6 3 - 572
Transfer to property,
plant and equipment (299) - (154) - (453)
Foreign exchange
adjustments - (1) (9) - (10)
----------------------------------------------------------------------------
At December 31, 2010 2,366 5 31 - 2,402
Additions 114 - 1 - 115
Transfer to property,
plant and equipment (136) (4) - - (140)
Foreign exchange
adjustments - - - - -
----------------------------------------------------------------------------
At June 30, 2011 $ 2,344 $ 1 $ 32 $ - $ 2,377
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5. PROPERTY, PLANT AND EQUIPMENT
Oil Sands
Mining
and Head
Exploration and Production Upgrading Midstream Office Total
----------------------------------------------------------------------------
North North Offshore
America Sea Africa
----------------------------------------------------------------------------
Cost
At January 1,
2010 $36,159 $ 3,866 $ 2,666 $ 13,758 $ 284 $ 214 $ 56,947
Additions 4,403 190 254 411 7 18 5,283
Transfer from
E&E assets 299 - 154 - - - 453
Disposals/
derecognition - (5) - - - (11) (16)
Foreign
exchange
adjustments
and other - (238) (146) - - (5) (389)
----------------------------------------------------------------------------
At December
31, 2010 40,861 3,813 2,928 14,169 291 216 62,278
Additions 2,037 110 49 690 4 12 2,902
Transfer from
E&E assets 136 4 - - - - 140
Disposals/
derecognition
(1) - - (17) (411) - - (428)
Foreign
exchange
adjustments
and other - (117) (89) - - - (206)
----------------------------------------------------------------------------
At June 30,
2011 $ 43,034 $ 3,810 $ 2,871 $ 14,448 $ 295 $ 228 $ 64,686
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and
depreciation
At January 1,
2010 $16,427 $ 2,054 $ 1,008 $ 207 $ 81 $ 152 $ 19,929
Expense 2,473 295 298 396 8 13 3,483
Product
inventory
costing (5) (5) 21 4 - - 15
Impairment (2) - - 637 - - - 637
Disposals/
derecognition - (5) - - - (11) (16)
Foreign
exchange
adjustments
and other - (134) (60) - - (5) (199)
----------------------------------------------------------------------------
At December
31, 2010 18,895 2,205 1,904 607 89 149 23,849
Expense 1,392 133 126 56 4 8 1,719
Product
inventory
costing (9) 4 (16) 11 - - (10)
Impairment(1) - - - 396 - - 396
Disposals/
derecognition
(1) - - (17) (411) - - (428)
Foreign
exchange
adjustments
and other - (68) (52) - - - (120)
----------------------------------------------------------------------------
At June 30,
2011 $20,278 $ 2,274 $ 1,945 $ 659 $ 93 $ 157 $ 25,406
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book
value
- at June 30,
2011 $22,756 $ 1,536 $ 926 $ 13,789 $ 202 $ 71 $ 39,280
- at December
31, 2010 $21,966 $ 1,608 $ 1,024 $ 13,562 $ 202 $ 67 $ 38,429
- at January
1, 2010 $19,732 $ 1,812 $ 1,658 $ 13,551 $ 203 $ 62 $ 37,018
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) During the first quarter of 2011, the Company derecognized certain
property, plant and equipment related to the coker fire incident at
Horizon in the amount of $411 million, net of accumulated depletion and
depreciation of $15 million, resulting in an impairment charge of $396
million. For additional information, refer to Note 9.
(2) During 2010, the Company recognized a $637 million impairment relating
to Gabon, Offshore Africa which was included in depletion, depreciation
and amortization expense. The impairment was based on the difference
between the December 31, 2010 net book value of the assets and their
recoverable amounts. The recoverable amounts were determined using fair
value less costs to sell based on discounted future cash flows of proved
and probable reserves using forecast prices and costs.
Development projects not subject to depletion
----------------------------------------------------------------------------
At June 30, 2011 $ 1,486
At December 31, 2010 $ 934
At January 1, 2010 $ 1,270
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company acquired a number of producing crude oil and natural gas assets in
the Exploration and Production segments for total consideration of $489 million
during the six months ended June 30, 2011 (year ended December 31, 2010 - $1,482
million).
The Company capitalizes construction period interest for qualifying assets based
on costs incurred and the Company's cost of borrowing. Interest capitalization
to a qualifying asset ceases once construction is substantially complete. For
the six months ended June 30, 2011, pre-tax interest of $24 million was
capitalized to property, plant, and equipment (June 30, 2010 - $12 million)
using a capitalization rate of 4.7% (June 30, 2010 - 4.7%).
6. OTHER LONG-TERM ASSETS
Jun 30 Dec 31 Jan 1
2011 2010 2010
----------------------------------------------------------------------------
Investment in North West Redwater
Partnership $ 346 $ - $ -
Other 32 14 6
----------------------------------------------------------------------------
$ 378 $ 14 $ 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other long-term assets include a $346 million equity investment in the 50% owned
North West Redwater Partnership ("Redwater"). Redwater has entered into an
agreement to construct and operate a 50,000 bbl/d bitumen refinery, which
targets to process bitumen under a 30 year fee-for-service contract. Project
development is dependent upon completion of detailed engineering and final
project sanction by both Redwater and the Government of Alberta.
7. LONG-TERM DEBT
Jun 30 Dec 31 Jan 1
2011 2010 2010
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities (banker's
acceptances) $ 1,777 $ 1,436 $ 1,897
Medium-term notes 800 800 1,200
----------------------------------------------------------------------------
2,577 2,236 3,097
----------------------------------------------------------------------------
US dollar denominated debt
US dollar debt securities (US$6,300
million) 6,075 6,266 6,594
Less - original issue discount on US
dollar debt securities (1) (20) (20) (22)
----------------------------------------------------------------------------
6,055 6,246 6,572
Fair value impact of interest rate
swaps on US dollar debt securities
(2) 40 47 39
----------------------------------------------------------------------------
6,095 6,293 6,611
----------------------------------------------------------------------------
Long-term debt before transaction
costs 8,672 8,529 9,708
Less: transaction costs (1) (3) (48) (44) (49)
----------------------------------------------------------------------------
8,624 8,485 9,659
Less: current portion (1) (4) 386 397 400
----------------------------------------------------------------------------
$ 8,238 $ 8,088 $ 9,259
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has included unamortized original issue discounts and
directly attributable transaction costs in the carrying amount of the
outstanding debt.
(2) The carrying amounts of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 were adjusted by
$40 million (December 2010 - $47 million, January 2010 - $39 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.
(4) Subsequent to June 30, 2011, US $400 million of US dollar denominated
debt securities bearing interest at 6.7% were repaid.
Bank Credit Facilities
As at June 30, 2011, the Company had in place unsecured bank credit facilities
of $4,723 million, comprised of:
-- a $200 million demand credit facility;
-- a revolving syndicated credit facility of $3,000 million maturing June
2015;
-- a revolving syndicated credit facility of $1,500 million maturing June
2012; and
-- a GBP 15 million demand credit facility related to the Company's North
Sea operations.
During the second quarter of 2011, the $2,230 million revolving syndicated
credit facility was increased to $3,000 million and extended to June 2015. Each
of the $3,000 million and $1,500 million facilities is extendible annually for
one year periods at the mutual agreement of the Company and the lenders. If the
facilities are not extended, the full amount of the outstanding principal would
be repayable on the maturity date. Borrowings under these facilities can be made
by way of Canadian dollar and US dollar bankers' acceptances, and LIBOR, US base
rate and Canadian prime loans.
The Company's weighted average interest rate on bank credit facilities
outstanding as at June 30, 2011, was 2.8% (June 30, 2010 - 1.1%), and on
long-term debt outstanding for the six months ended June 30, 2011 was 4.7% (June
30, 2010 - 4.7%).
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $482 million, including $163 million related to Horizon and $171
million related to North Sea operations, were outstanding at June 30, 2011.
Medium-Term Notes
During 2009, the Company filed a base shelf prospectus that allows for the issue
of up to $3,000 million of medium-term notes in Canada until November 2011. If
issued, these securities will bear interest as determined at the date of
issuance.
US Dollar Debt Securities
During 2009, the Company filed a base shelf prospectus that allows for the issue
of up to US$3,000 million of debt securities in the United States until November
2011. If issued, these securities will bear interest as determined at the date
of issuance.
8. OTHER LONG-TERM LIABILITIES
Jun 30 Dec 31 Jan 1
2011 2010 2010
----------------------------------------------------------------------------
Asset retirement obligations $ 2,580 $ 2,624 $ 2,214
Share-based compensation 493 663 622
Risk management (Note 15) 451 485 325
Other 95 102 178
----------------------------------------------------------------------------
3,619 3,874 3,339
Less: current portion 562 870 854
----------------------------------------------------------------------------
$ 3,057 $ 3,004 $ 2,485
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset retirement obligations
The Company's asset retirement obligations will be settled on an ongoing basis
over a period of approximately 60 years and have been discounted using a
weighted average discount rate of 5.1% (December 31, 2010 - 5.1%; January 1,
2010 - 5.8%). A reconciliation of the discounted asset retirement obligations is
as follows:
Jun 30 Dec 31
2011 2010
----------------------------------------------------------------------------
Balance - beginning of period $2,624 $ 2,214
Liabilities incurred 6 12
Liabilities acquired 3 22
Liabilities settled (93) (179)
Asset retirement obligation accretion 64 123
Revision of estimates - 474
Foreign exchange (24) (42)
----------------------------------------------------------------------------
Balance - end of period $2,580 $ 2,624
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Share-based Compensation
As the Company's Option Plan provides current employees with the right to elect
to receive common shares or a direct cash payment in exchange for options
surrendered, a liability for potential cash settlements is recognized. 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.
Jun 30 Dec 31
2011 2010
----------------------------------------------------------------------------
Balance - beginning of period $ 663 $ 622
Share-based compensation (recovery) expense (60) 203
Cash payment for options surrendered (11) (45)
Transferred to common shares (97) (149)
Capitalized (recovered) to Oil Sands Mining and Upgrading (2) 32
----------------------------------------------------------------------------
Balance - end of period 493 663
Less: current portion 384 623
----------------------------------------------------------------------------
$ 109 $ 40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. HORIZON ASSET IMPAIRMENT PROVISION AND INSURANCE RECOVERY
On January 6, 2011, the Company suspended synthetic crude oil production at its
Oil Sands Mining and Upgrading operations due to a fire in the primary upgrading
coking plant. As at August 3, 2011, all necessary regulatory and operating
approvals to recommence operations were received. Final mechanical, testing and
commissioning activities are ongoing and production is scheduled for the third
quarter of 2011.
During the first quarter of 2011, the Company recognized a Horizon asset
impairment provision of $396 million, net of accumulated depletion and
depreciation, related to the property damage resulting from the fire in the
primary upgrading coking plant. As the Company believes that its insurance
coverage is adequate to mitigate all significant property damage related losses,
estimated insurance proceeds receivable of $396 million were also recognized
offsetting such property damage. The final Horizon asset impairment provision
and related insurance recoveries are subject to revision upon recommencement of
operations and the determination of final costs to restore plant operating
capacity. Accordingly, actual results may differ significantly from the amounts
currently recognized.
The Company also maintains business interruption insurance to reduce operating
losses related to its ongoing operations. During the second quarter of 2011, the
Company recognized business interruption insurance recoveries of $136 million,
based on interim payments and claims processed to date. Additional business
interruption insurance recoveries related to the second and third quarters will
be recognized at such time as additional interim payments are processed and as
the final terms of the insurance settlement are determined.
10. INCOME TAXES
The provision for income tax is as follows:
Three Months Ended Six Months Ended
Jun 30 Jun 30 Jun 30 Jun 30
2011 2010 2011 2010
----------------------------------------------------------------------------
Current corporate income tax - North
America $ 79 $ 139 $ 170 $ 268
Current corporate income tax - North
Sea 70 43 116 96
Current corporate income tax -
Offshore Africa 24 9 44 15
Current PRT(1) expense - North Sea 46 24 54 49
Other taxes 6 5 12 12
----------------------------------------------------------------------------
Current income tax expense 225 220 396 440
----------------------------------------------------------------------------
Deferred corporate income tax expense 55 66 98 307
Deferred PRT expense - North Sea 2 3 12 4
----------------------------------------------------------------------------
Deferred income tax expense 57 69 110 311
----------------------------------------------------------------------------
Income tax expense $ 282 $ 289 $ 506 $ 751
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Petroleum Revenue Tax
Taxable income from the Exploration and Production business in Canada is
primarily generated through partnerships, with the related income taxes payable
in periods subsequent to the current reporting period. North America current and
deferred income taxes have been provided on the basis of this corporate
structure. In addition, current income taxes in each operating segment will vary
depending upon available income tax deductions related to the nature, timing and
amount of capital expenditures incurred in any particular year.
Deferred income tax expense in the first quarter of 2010 included a charge of
$132 million related to changes in Canada to the taxation of stock options
surrendered by employees for cash.
During the first quarter of 2011, the UK government substantively enacted an
increase to the supplementary income tax rate charged on profits from UK North
Sea crude oil and natural gas production, increasing the combined corporate and
supplementary income tax rate from 50% to 62%. As a result of the income tax
rate change, the Company's deferred income tax liability was increased by $104
million as at March 31, 2011.
11. SHARE CAPITAL
Authorized
200,000 Class 1 preferred shares with a stated value of $10.00 each.
Unlimited number of common shares without par value.
------------------------------
Six Months Ended Jun 30, 2011
----------------------------------------------------------------------------
Number of shares
Issued common shares (thousands) Amount
----------------------------------------------------------------------------
Balance - beginning of period 1,090,848 $ 3,147
Issued upon exercise of stock options 6,230 181
Previously recognized liability on stock
options exercised for common shares - 97
----------------------------------------------------------------------------
Balance - end of period 1,097,078 $ 3,425
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dividend Policy
On March 1, 2011, the Board of Directors set the regular quarterly dividend at
$0.09 per common share (2010 - $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 2011, 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 twelve month period commencing April 6, 2011 and ending April 5,
2012, up to 27,406,131 common shares or 2.5% of the common shares of the Company
outstanding at March 25, 2011. In April 2011, the previous Normal Course Issuer
Bid expired. As at June 30, 2011, no common shares had been repurchased for
cancellation during 2011.
Stock Options
The following table summarizes information relating to stock options outstanding
at June 30, 2011:
Six months ended Jun 30, 2011
----------------------------------------------------------------------------
Weighted
average
Stock options exercise
(thousands) price
----------------------------------------------------------------------------
Outstanding - beginning of period 66,844 $ 33.31
Granted 2,538 $ 43.73
Surrendered for cash settlement (798) $ 29.76
Exercised for common shares (6,230) $ 29.14
Forfeited (1,663) $ 35.10
----------------------------------------------------------------------------
Outstanding - end of period 60,691 $ 34.17
----------------------------------------------------------------------------
Exercisable - end of period 18,853 $ 31.36
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Option Plan is a "rolling 9%" plan, whereby the aggregate number of common
shares that may be reserved for issuance under the plan shall not exceed 9% of
the common shares outstanding from time to time.
12. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of accumulated other comprehensive income, net of taxes, were as
follows:
Jun 30 Jun 30
2011 2010
----------------------------------------------------------------------------
Derivative financial instruments designated as cash flow
hedges $ 60 $ 168
Foreign currency translation adjustment (22) 1
----------------------------------------------------------------------------
$ 38 $ 169
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the next twelve months, $22 million is expected to be reclassified to net
earnings from accumulated other comprehensive income, reducing net earnings.
13. 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
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, or 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. At June 30, 2011, the ratio was
below the target range at 29%.
Readers are cautioned that the debt to book capitalization ratio is not defined
by IFRS 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.
Jun 30 Dec 31 Jan 1
2011 2010 2010
----------------------------------------------------------------------------
Long-term debt (1) $ 8,624 $ 8,485 $ 9,659
Total shareholders' equity $21,452 $20,368 $18,838
Debt to book capitalization 29% 29% 34%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
14. NET EARNINGS PER COMMON SHARE
Three Months Ended Six Months Ended
Jun 30 2011 Jun 30 2010 Jun 30 2011 Jun 30 2010
----------------------------------------------------------------------------
Weighted average common
shares outstanding -
basic (thousands of
shares) 1,096,784 1,088,751 1,095,243 1,087,179
Effect of dilutive stock
options 8,521 7,399 10,261 7,990
----------------------------------------------------------------------------
Weighted average common
shares outstanding -
diluted (thousands of
shares) 1,105,305 1,096,150 1,105,504 1,095,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 929 $ 651 $ 975 $ 1,386
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
share - basic $ 0.85 $ 0.60 $ 0.89 $ 1.28
- diluted $ 0.84 $ 0.60 $ 0.88 $ 1.27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
15. FINANCIAL INSTRUMENTS
The carrying amounts of the Company's financial instruments by category were
as follows:
---------------------------------------------------------------
Jun 30, 2011
----------------------------------------------------------------------------
Loans and Financial
receivables Fair value liabilities
at through Derivatives at
Asset amortized profit or used for amortized
(liability) cost loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 1,859 $ - $ - $ - $ 1,859
Accounts
payable - - - (557) (557)
Accrued
liabilities - - - (2,134) (2,134)
Other long-
term
liabilities - (104) (347) (85) (536)
Long-term
debt (1) - - - (8,624) (8,624)
----------------------------------------------------------------------------
$ 1,859 $ (104) $ (347) $ (11,400) $ (9,992)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2010
----------------------------------------------------------------------------
Loans and Financial
receivables Fair value liabilities
at through Derivatives at
Asset amortized profit or used for amortized
(liability) cost loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 1,481 $ - $ - $ - $ 1,481
Accounts
payable - - - (274) (274)
Accrued
liabilities - - - (1,735) (1,735)
Other long-
term
liabilities - (167) (318) (91) (576)
Long-term
debt (1) - - - (8,485) (8,485)
----------------------------------------------------------------------------
$ 1,481 $ (167) $ (318) $ (10,585) $ (9,589)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Jan 1, 2010
----------------------------------------------------------------------------
Loans and Financial
receivables Fair value liabilities
at through Derivatives at
Asset amortized profit or used for amortized
(liability) cost loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 1,148 $ - $ - $ - $ 1,148
Accounts
payable - - - (240) (240)
Accrued
liabilities - - - (1,430) (1,430)
Other long-
term
liabilities - (182) (143) (167) (492)
Long-term
debt (1) - - - (9,659) (9,659)
----------------------------------------------------------------------------
$ 1,148 $ (182) $ (143) $ (11,496) $ (10,673)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
The carrying amount of the Company's financial instruments approximates their
fair value, except for fixed-rate long-term debt as noted below. The fair values
of the Company's financial assets and liabilities are outlined below:
-------------------------------------
Jun 30, 2011
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term liabilities $ (451) $ - $ (451)
Fixed-rate long-term debt (2) (3) (4) (6,847) (7,549) -
----------------------------------------------------------------------------
$ (7,298) $ (7,549) $ (451)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2010
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term liabilities $ (485) $ - $ (485)
Fixed-rate long-term debt (2) (3) (4) (7,049) (7,835) -
----------------------------------------------------------------------------
$ (7,534) $ (7,835) $ (485)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Jan 1, 2010
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term liabilities $ (325) $ - $ (325)
Fixed-rate long-term debt (2) (3) (4) (7,762) (8,212) -
----------------------------------------------------------------------------
$ (8,087) $ (8,212) $ (325)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes financial assets and liabilities where the carrying amount
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 amounts 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 $40 million (December 31, 2010 - $47 million, January 1, 2010 - $39
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.
(4) Includes the current portion of long-term debt.
The following provides a summary of the carrying amounts of derivative contracts
held and a reconciliation to the Company's consolidated balance sheets.
Jun 30, Dec 31, Jan 1,
Asset (liability) 2011 2010 2010
----------------------------------------------------------------------------
Derivatives held for trading
Crude oil price collars $ (29) $ (64) $ (256)
Crude oil put options (50) (83) -
Natural gas price collars - - 72
Interest rate swaps - - 11
Foreign currency forward contracts (25) (20) (9)
Cash flow hedges
Natural gas swaps (27) (49) -
Cross currency swaps (320) (269) (158)
Fair value hedges
Interest rate swaps - - 15
----------------------------------------------------------------------------
$ (451) $ (485) $ (325)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Included within:
Current portion of other long-term
liabilities $ (146) $ (222) $ (182)
Other long-term liabilities (305) (263) (143)
----------------------------------------------------------------------------
$ (451) $ (485) $ (325)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Ineffectiveness arising from cash flow hedges recognized in the consolidated
statements of earnings for the six months ended June 30, 2011 resulted in a loss
of $1 million (December 31, 2010 - loss of $1 million).
Risk Management
The Company uses derivative financial instruments to manage its commodity price,
foreign currency and interest rate exposures. These financial instruments are
entered into solely for hedging purposes and are not used for speculative
purposes.
The estimated fair value of derivative financial instruments has been determined
based on appropriate internal valuation methodologies. Fair values determined
using valuation models require the use of assumptions concerning the amount and
timing of future cash flows and discount rates. In determining these
assumptions, the Company primarily relied on external, readily-observable market
inputs including quoted commodity prices and volatility, interest rate yield
curves, and foreign exchange rates. The resulting fair value estimates may not
necessarily be indicative of the amounts that could be realized or settled in a
current market transaction and these differences may be material.
The changes in estimated fair values of derivative financial instruments
included in the risk management asset (liability) were recognized in the
financial statements as follows:
Six Months Year Ended
Ended Jun Dec 31,
30, 2011 2010
----------------------------------------------------------------------------
Risk Risk
management management
mark-to- mark-to-
Asset (liability) market market
----------------------------------------------------------------------------
Balance - beginning of period $ (485) $ (325)
Net cost of outstanding put options 52 106
Net change in fair value of outstanding derivative
financial instruments attributable to:
Risk management activities 64 38
Interest expense - 16
Foreign exchange (64) (101)
Other comprehensive income 34 (58)
Settlement of interest rate swaps and other - (55)
----------------------------------------------------------------------------
(399) (379)
Add: put premium financing obligations (1) (52) (106)
----------------------------------------------------------------------------
Balance - end of period (451) (485)
Less: current portion (146) (222)
----------------------------------------------------------------------------
$ (305) $ (263)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has negotiated payment of put option premiums with various
counterparties at the time of actual settlement of the respective options.
These obligations were reflected in the net risk management asset
(liability).
Net losses (gains) from risk management activities were as follows:
Three Months Ended Six Months Ended
Jun 30 Jun 30 Jun 30 Jun 30
2011 2010 2011 2010
----------------------------------------------------------------------------
Net realized risk management loss
(gain) $ 34 $ (91) $ 104 $ (52)
Net unrealized risk management gain (118) (86) (64) (296)
----------------------------------------------------------------------------
$ (84) $ (177) $ 40 $ (348)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 periodically uses commodity derivative financial instruments to
manage its exposure to commodity price risk associated with the sale of its
future crude oil and natural gas production and with natural gas purchases. At
June 30, 2011, the Company had the following derivative financial instruments
outstanding to manage its commodity price risks:
i) Sales contracts
Weighted
Remaining average
term Volume price Index
----------------------------------------------------------------------------
Crude oil
Crude oil Jul 2011 - 50,000 US$70.00 -
price collars Dec2011 bbl/d US $102.23 WTI
Crude oil Jul 2011 - 100,000
puts Dec 2011 bbl/d US$70.00 WTI
The cost of outstanding put options and their respective periods of
settlement are as follows:
Q3 2011 Q4 2011
----------------------------------------------------------------------------
Cost ($ millions) US$27 US$27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ii) Purchase contracts
Weighted
average
Remaining fixed
term Volume rate Index
----------------------------------------------------------------------------
Natural gas
Swaps-floating Jul 2011 - 125,000
to fixed Dec 2011 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.
The natural gas derivative financial instruments designated as hedges at June
30, 2011 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 periodically enters into interest rate swap contracts to manage its
fixed to floating interest rate mix on long-term debt. The interest rate swap
contracts require the periodic exchange of payments without the exchange of the
notional principal amounts on which the payments are based. At June 30, 2011 the
Company had the following interest rate swap contracts outstanding:
Remaining Fixed Floating
term Amount rate rate
----------------------------------------------------------------------------
Interest rate
Swaps-floating Jul 2011 - 3 month
to fixed Feb 2012 C$200 1.4475% CDOR(1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1)Canadian Dealer Offered Rate
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in Canada
primarily related to its US dollar denominated long-term debt and working
capital. The Company is also exposed to foreign currency exchange rate risk on
transactions conducted in other currencies in its subsidiaries and in the
carrying value of its foreign subsidiaries. The Company periodically enters into
cross currency swap contracts and foreign currency forward contracts to manage
known currency exposure on US dollar denominated long-term debt and working
capital. The cross currency swap contracts require the periodic exchange of
payments with the exchange at maturity of notional principal amounts on which
the payments are based. At June 30, 2011, the Company had the following cross
currency swap contracts outstanding:
Exchange Interest Interest
Remaining rate rate rate
term Amount (US$/C$) (US$) (C$)
----------------------------------------------------------------------------
Cross currency
Swaps (1) Jul 2011 - Jul 2011 US$200 0.998 6.70% 7.74%
Jul 2011 - Aug 2016 US$250 1.116 6.00% 5.40%
Jul 2011 - May 2017 US$1,100 1.170 5.70% 5.10%
Jul 2011 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to June 30, 2011, the cross currency swaps that had been
designated as cash flow hedges of US $400 million of 6.7% debt securities
were settled, resulting in a realized loss of $9 million.
All cross currency swap derivative financial instruments designated as hedges at
June 30, 2011 were classified as cash flow hedges.
In addition to the cross currency swap contracts noted above, at June 30, 2011,
the Company had US$1,479 million of foreign currency forward contracts
outstanding, with terms of approximately 30 days or less.
b) Credit Risk
Credit risk is the risk that a party to a financial instrument will cause a
financial loss to the Company by failing to discharge an obligation.
Counterparty credit risk management
The Company's accounts receivable are mainly with customers in the crude oil and
natural gas industry and are subject to normal industry credit risks. The
Company manages these risks by reviewing its exposure to individual companies on
a regular basis and where appropriate, ensures that parental guarantees or
letters of credit are in place to minimize the impact in the event of default.
At June 30, 2011, substantially all of the Company's accounts receivable were
due within normal trade terms.
The Company is also exposed to possible losses in the event of nonperformance by
counterparties to derivative financial instruments; however, the Company manages
this credit risk by entering into agreements with counterparties that are
substantially all investment grade financial institutions and other entities. At
June 30, 2011, the Company had no net risk management assets with specific
counterparties related to derivative financial instruments (December 31, 2010 -
$nil, January 1, 2010 - $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. The Company
believes it has adequate bank credit facilities to provide liquidity to manage
fluctuations in the timing of the receipt and/or disbursement of operating cash
flows.
The maturity dates for financial liabilities are as follows:
1 to 2 to
Less than less than less than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 557 $ - $ - $ -
Accrued liabilities $ 2,134 $ - $ - $ -
Current income tax liabilities $ 402 $ - $ - $ -
Risk management $ 146 $ 48 $ 144 $ 113
Other long-term liabilities $ 32 $ 15 $ 38 $ -
Long-term debt (1) $ 386 $ 1,123 $ 2,514 $ 4,629
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does not reflect
fair value adjustments, original issue discounts or transaction costs.
16. COMMITMENTS AND CONTINGENCIES
The Company has committed to certain payments as follows:
Remaining
2011 2012 2013 2014 2015 Thereafter
----------------------------------------------------------------------------
Product
transportation and
pipeline $ 119 $ 211 $ 186 $ 176 $ 164 $ 941
Offshore equipment
operating leases $ 80 $ 95 $ 94 $ 95 $ 78 $ 163
Office leases $ 14 $ 29 $ 33 $ 34 $ 32 $ 336
Other $ 79 $ 69 $ 22 $ 19 $ 25 $ 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company is defendant and plaintiff in a number of legal actions arising in
the normal course of business. 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.
17. SEGMENTED INFORMATION
Exploration and Production
North America North Sea
(millions of
Canadian Three Months Six Months Three Months Six Months
dollars, Ended Ended Ended Ended
unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2011 2010 2011 2010 2011 2010 2011 2010
----------------------------------------------------------------------------
Segmented
product sales 3,207 2,490 5,913 4,976 342 245 631 531
Less:
royalties (391) (290) (717) (614) (1) - (2) (1)
----------------------------------------------------------------------------
Segmented
revenue 2,816 2,200 5,196 4,362 341 245 629 530
----------------------------------------------------------------------------
Segmented
expenses
Production 466 410 924 837 109 67 195 157
Transportation
and blending 660 554 1,272 961 3 2 7 5
Depletion,
depreciation
and
amortization 697 620 1,400 1,203 65 72 133 148
Asset
retirement
obligation
accretion 17 13 35 26 8 9 16 18
Realized risk
management
activities 34 (91) 104 (52) - - - -
Horizon Asset
Impairment
Provision - - - - - - - -
Insurance
recovery -
property
damage (Note 9) - - - - - - - -
Insurance
recovery -
business
interruption
(Note 9) - - - - - - - -
----------------------------------------------------------------------------
Total
segmented
expenses 1,874 1,506 3,735 2,975 185 150 351 328
----------------------------------------------------------------------------
Segmented
earnings
(loss) before
the following 942 694 1,461 1,387 156 95 278 202
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and
other
financing
costs
Unrealized
risk
management
activities
Foreign
exchange
(gain) loss
----------------------------------------------------------------------------
Total
non-segmented
expenses
Earnings
before taxes
Current income
tax expense
Deferred
income tax
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Exploration
Offshore Africa and Production
(millions of
Canadian Three Months Six Months Three Months Six Months
dollars, Ended Ended Ended Ended
unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2011 2010 2011 2010 2011 2010 2011 2010
----------------------------------------------------------------------------
Segmented product
sales 173 177 388 333 3,722 2,912 6,932 5,840
Less: royalties (2) (10) (22) (15) (394) (300) (741) (630)
----------------------------------------------------------------------------
Segmented revenue 171 167 366 318 3,328 2,612 6,191 5,210
----------------------------------------------------------------------------
Segmented expenses
Production 33 41 75 69 608 518 1,194 1,063
Transportation and
blending (1) - - - 662 556 1,279 966
Depletion,
depreciation and
amortization 73 83 126 122 835 775 1,659 1,473
Asset retirement
obligation accretion 1 2 3 3 26 24 54 47
Realized risk
management
activities - - - - 34 (91) 104 (52)
Horizon Asset
Impairment Provision - - - - - - - -
Insurance recovery -
property
damage (Note 9) - - - - - - - -
Insurance recovery -
business
interruption
(Note 9) - - - - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 106 126 204 194 2,165 1,782 4,290 3,497
----------------------------------------------------------------------------
Segmented earnings
(loss) before
the following 65 41 162 124 1,163 830 1,901 1,713
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
(gain) loss
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income tax
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil Sands Mining and Upgrading Midstream
(millions of
Canadian Three Months Six Months Three Months Six Months
dollars, Ended Ended Ended Ended
unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2011 2010 2011 2010 2011 2010 2011 2010
----------------------------------------------------------------------------
Segmented product
sales 3 698 89 1,345 21 21 43 40
Less: royalties - (24) (4) (47) - - - -
----------------------------------------------------------------------------
Segmented revenue 3 674 85 1,298 21 21 43 40
----------------------------------------------------------------------------
Segmented expenses
Production 221 290 477 636 5 7 12 12
Transportation and
blending 15 16 31 31 - - - -
Depletion,
depreciation and
amortization 33 102 56 199 2 2 4 4
Asset retirement
obligation
accretion 5 7 10 14 - - - -
Realized risk
management
activities - - - - - - - -
Horizon Asset
Impairment
Provision - - 396 - - - - -
Insurance Recovery
- property
damage (Note 9) - - (396) - - - - -
Insurance Recovery
- business
interruption
(Note 9) (136) - (136) - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 138 415 438 880 7 9 16 16
----------------------------------------------------------------------------
Segmented earnings
(loss) before
the following (135) 259 (353) 418 14 12 27 24
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
(gain) loss
----------------------------------------------------------------------------
Total
non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income
tax expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment
elimination and other Total
(millions of
Canadian Three Months Six Months Three Months Six Months
dollars, Ended Ended Ended Ended
unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2011 2010 2011 2010 2011 2010 2011 2010
----------------------------------------------------------------------------
Segmented product
sales (19) (17) (35) (31) 3,727 3,614 7,029 7,194
Less: royalties - - - - (394) (324) (745) (677)
----------------------------------------------------------------------------
Segmented revenue (19) (17) (35) (31) 3,333 3,290 6,284 6,517
----------------------------------------------------------------------------
Segmented expenses
Production (1) (3) (5) (5) 833 812 1,678 1,706
Transportation
and blending (12) (13) (24) (24) 665 559 1,286 973
Depletion,
depreciation and
amortization - - - - 870 879 1,719 1,676
Asset retirement
obligation
accretion - - - - 31 31 64 61
Realized risk
management
activities - - - - 34 (91) 104 (52)
Horizon Asset
Impairment
Provision - - - - - - 396 -
Insurance
Recovery -
property
damage (Note 9) - - - - - - (396) -
Insurance
Recovery -
business
interruption
(Note 9) - - - - (136) - (136) -
----------------------------------------------------------------------------
Total segmented
expenses (13) (16) (29) (29) 2,297 2,190 4,715 4,364
----------------------------------------------------------------------------
Segmented
earnings (loss)
before
the following (6) (1) (6) (2) 1,036 1,100 1,569 2,153
----------------------------------------------------------------------------
Non-segmented
expenses
Administration 69 60 123 114
Share-based
compensation (188) (87) (60) (58)
Interest and
other financing
costs 99 110 193 219
Unrealized risk
management
activities (118) (86) (64) (296)
Foreign exchange
(gain) loss (37) 163 (104) 37
----------------------------------------------------------------------------
Total
non-segmented
expenses (175) 160 88 16
----------------------------------------------------------------------------
Earnings before
taxes 1,211 940 1,481 2,137
Current income
tax expense 225 220 396 440
Deferred income
tax expense 57 69 110 311
----------------------------------------------------------------------------
Net earnings 929 651 975 1,386
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital Expenditures (1)
Six Months Ended
--------------------------------------------
Jun 30, 2011
Non cash and
Net fair value Capitalized
expenditures changes(2) costs
----------------------------------------------------------------------------
Exploration and evaluation
Exploration and Production
North America $ 114 $ (136) $ (22)
North Sea - (4) (4)
Offshore Africa 1 - 1
----------------------------------------------------------------------------
$ 115 $ (140) $ (25)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Property, plant and equipment
Exploration and Production
North America $ 2,031 $ 142 $ 2,173
North Sea 110 4 114
Offshore Africa 49 (17) 32
----------------------------------------------------------------------------
2,190 129 2,319
Oil Sands Mining and
Upgrading(3)(4) 685 (406) 279
Midstream 4 - 4
Head office 12 - 12
----------------------------------------------------------------------------
$ 2,891 $ (277) $ 2,614
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six Months Ended
--------------------------------------------
Jun 30, 2010
Non cash and
Net fair value Capitalized
expenditures changes(2) costs
----------------------------------------------------------------------------
Exploration and evaluation
Exploration and Production
North America $ 119 $ (132) $ (13)
North Sea 5 - 5
Offshore Africa 1 - 1
----------------------------------------------------------------------------
$ 125 $ (132) $ (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Property, plant and equipment
Exploration and Production
North America $ 2,040 $ 146 $ 2,186
North Sea 47 - 47
Offshore Africa 149 - 149
----------------------------------------------------------------------------
2,236 146 2,382
Oil Sands Mining and
Upgrading(3)(4) 227 6 233
Midstream 1 - 1
Head office 9 (11) (2)
----------------------------------------------------------------------------
$ 2,473 $ 141 $ 2,614
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) This table provides a reconciliation of capitalized costs and does not
include the impact of accumulated depletion and depreciation.
(2) Asset retirement obligations, deferred income tax adjustments related to
differences between carrying amounts and tax values, transfers of
exploration and evaluation assets, and other fair value adjustments.
(3) Net expenditures for Oil Sands Mining and Upgrading also include
capitalized interest, share-based compensation, and the impact of
intersegment eliminations.
(4) During the first quarter of 2011 the Company derecognized certain
property, plant and equipment related to the coker fire incident at
Horizon in the amount of $411 million. This amount has been included in
non-cash and fair value changes.
Segmented Assets
Total assets
-----------------------------
Jun 30 Dec 31
2011 2010
----------------------------------------------------------------------------
Exploration and Production
North America $ 26,792 $ 25,486
North Sea 1,717 1,759
Offshore Africa 1,083 1,263
Other 10 15
Oil Sands Mining and Upgrading 14,640 14,026
Midstream 345 338
Head office 71 67
----------------------------------------------------------------------------
$ 44,658 $ 42,954
----------------------------------------------------------------------------
----------------------------------------------------------------------------
18. TRANSITION TO IFRS
The effect of the Company's transition to IFRS, described in Note 1, is
summarized below:
(i) Transition elections
The Company has applied the following transition exceptions and exemptions to
full retrospective application of IFRS as described below:
Note
Deemed cost of property, plant and equipment (a)
Leases (b)
Share-based compensation (c)
Borrowing costs (d)
Asset retirement obligations (e)
Cumulative translation adjustment (f)
Business combinations (g)
(ii) Transition adjustments
The Company has recorded the following transition adjustments upon adoption of IFRS:
Note
Risk management (h)
Petroleum Revenue Tax (i)
UK deferred income tax liabilities (j)
Reclassification of current portion of deferred income tax (k)
Horizon major maintenance costs (l)
Long-term debt (m)
Reconciliations of the Consolidated Balance Sheets
(millions of Canadian
dollars,
unaudited) Dec 31, 2010 Jun 30, 2010
----------------------------------------------------------------------------
Canadian Canadian
GAAP Adj IFRS GAAP Adj IFRS
Note $ $ $ $ $ $
ASSETS
Current
assets
Cash and
cash
equivalents 22 - 22 19 - 19
Accounts
receivable 1,481 - 1,481 1,363 - 1,363
Inventory (a) 481 (4) 477 461 (9) 452
Prepaids
and other 129 - 129 149 - 149
Deferred
income tax
assets (k) 59 (59) - - - -
Current
portion of
other
long-term
assets - - - 108 - 108
----------------------------------------------------------------------------
2,172 (63) 2,109 2,100 (9) 2,091
Exploration
and
evaluation
assets (a) - 2,402 2,402 - 2,288 2,288
Property,
plant and
equipment (a)(c)(e)(l) 40,472 (2,043) 38,429 40,107 (2,152) 37,955
Other
long-term
assets 25 (11) 14 48 (14) 34
----------------------------------------------------------------------------
42,669 285 42,954 42,255 113 42,368
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current
liabilities
Accounts
payable 274 - 274 295 - 295
Accrued
liabilities 1,733 2 1,735 1,478 2 1,480
Current
income tax
liabilities 430 - 430 364 - 364
Deferred
income tax
liabilities (k) - - - 22 (22) -
Current
portion of
long-term
debt (m) - 397 397 - 400 400
Current
portion of
other
long-term
liabilities (c) 719 151 870 186 196 382
----------------------------------------------------------------------------
3,156 550 3,706 2,345 576 2,921
Long-term
debt (h)(m) 8,499 (411) 8,088 9,335 (406) 8,929
Other
long-term
liabilities (c)(e)(h) 2,130 874 3,004 1,753 656 2,409
Deferred
income tax
liabilities (i)(j)(k) 7,899 (111) 7,788 7,763 21 7,784
----------------------------------------------------------------------------
21,684 902 22,586 21,196 847 22,043
----------------------------------------------------------------------------
SHAREHOLDERS'
EQUITY
Share
capital 3,147 - 3,147 3,006 - 3,006
Retained
earnings 18,005 (793) 17,212 18,066 (916) 17,150
Accumulated
other
comprehensive
(loss)
income (f)(h) (167) 176 9 (13) 182 169
----------------------------------------------------------------------------
20,985 (617) 20,368 21,059 (734) 20,325
----------------------------------------------------------------------------
42,669 285 42,954 42,255 113 42,368
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(millions of Canadian
dollars, unaudited) Jan 1, 2010
----------------------------------------------------------------------------
Canadian
GAAP Adj IFRS
Note $ $ $
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents 13 - 13
Accounts receivable 1,148 - 1,148
Inventory 438 - 438
Prepaids and other 146 - 146
Deferred income tax assets (k) 146 (146) -
Current portion of other long-term
assets - - -
----------------------------------------------------------------------------
1,891 (146) 1,745
Exploration and evaluation assets (a) - 2,293 2,293
Property, plant and equipment (a)(c)(e)(l) 39,115 (2,097) 37,018
Other long-term assets 18 (12) 6
----------------------------------------------------------------------------
41,024 38 41,062
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable 240 - 240
Accrued liabilities 1,428 2 1,430
Current income tax liabilities 94 - 94
Deferred income tax liabilities (k) - - -
Current portion of long-term debt (m) - 400 400
Current portion of other long-term
liabilities (c) 643 211 854
----------------------------------------------------------------------------
2,405 613 3,018
Long-term debt (h)(m) 9,658 (399) 9,259
Other long-term liabilities (c)(e)(h) 1,848 637 2,485
Deferred income tax liabilities (i)(j)(k) 7,687 (225) 7,462
----------------------------------------------------------------------------
21,598 626 22,224
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital 2,834 - 2,834
Retained earnings 16,696 (769) 15,927
Accumulated other comprehensive
(loss) income (f)(h) (104) 181 77
----------------------------------------------------------------------------
19,426 (588) 18,838
----------------------------------------------------------------------------
41,024 38 41,062
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliations of the Consolidated Statements of Earnings
(millions of Canadian dollars,
except per common share Year ended Three months ended
amounts, unaudited) Dec 31, 2010 Jun 30, 2010
----------------------------------------------------------------------------
Canadian Canadian
GAAP Adj IFRS GAAP Adj IFRS
Note $ $ $ $ $ $
----------------------------------------------------------------------------
Product sales 14,322 - 14,322 3,614 - 3,614
Less: royalties (1,421) - (1,421) (324) - (324)
----------------------------------------------------------------------------
Revenue 12,901 - 12,901 3,290 - 3,290
----------------------------------------------------------------------------
Expenses
Production (a) 3,447 2 3,449 812 - 812
Transportation and
blending 1,783 - 1,783 559 - 559
Depletion, depreciation
and amortization (a)(e)(l) 4,036 84 4,120 836 43 879
Administration (a) 210 1 211 60 - 60
Share-based
compensation (c) 294 (91) 203 (58) (29) (87)
Asset retirement
obligation accretion (e) 107 16 123 26 5 31
Interest and other
financing costs (h) 449 (1) 448 109 1 110
Risk management
activities (h) (121) (13) (134) (173) (4) (177)
Foreign exchange
(gain) loss (j) (182) 19 (163) 156 7 163
----------------------------------------------------------------------------
10,023 17 10,040 2,327 23 2,350
----------------------------------------------------------------------------
Earnings before taxes 2,878 (17) 2,861 963 (23) 940
Taxes other than
income tax 119 (119) - 34 (34) -
Current income tax
expense 698 91 789 191 29 220
Deferred income tax
expense 364 35 399 71 (2) 69
----------------------------------------------------------------------------
Net earnings 1,697 (24) 1,673 667 (16) 651
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per
common share
Basic 1.56 (0.02) 1.54 0.61 (0.01) 0.60
Diluted 1.56 (0.03) 1.53 0.61 (0.01) 0.60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliations of the Consolidated Statements of Earnings
(millions of Canadian dollars,
except per common share Six months ended
amounts, unaudited) Jun 30, 2010
----------------------------------------------------------------------------
Canadian
GAAP Adj IFRS
Note $ $ $
----------------------------------------------------------------------------
Product sales 7,194 - 7,194
Less: royalties (677) - (677)
----------------------------------------------------------------------------
Revenue 6,517 - 6,517
----------------------------------------------------------------------------
Expenses
Production (a) 1,706 - 1,706
Transportation and
blending 973 - 973
Depletion, depreciation
and amortization (a)(e)(l) 1,607 69 1,676
Administration (a) 114 - 114
Share-based
compensation (c) (60) 2 (58)
Asset retirement
obligation accretion (e) 52 9 61
Interest and other
financing costs (h) 220 (1) 219
Risk management
activities (h) (342) (6) (348)
Foreign exchange
(gain) loss (j) (4) 41 37
----------------------------------------------------------------------------
4,266 114 4,380
----------------------------------------------------------------------------
Earnings before taxes 2,251 (114) 2,137
Taxes other than
income tax 73 (73) -
Current income tax
expense 379 61 440
Deferred income tax
expense 266 45 311
----------------------------------------------------------------------------
Net earnings 1,533 (147) 1,386
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per
common share
Basic 1.41 (0.13) 1.28
Diluted 1.41 (0.14) 1.27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliations of the Consolidated Statements of Comprehensive Income
(millions of
Canadian dollars, Year ended Three months ended
unaudited) Dec 31, 2010 Jun 30, 2010
----------------------------------------------------------------------------
Canadian Canadian
GAAP Adj IFRS GAAP Adj IFRS
Note $ $ $ $ $ $
----------------------------------------------------------------------------
Net earnings 1,697 (24) 1,673 667 (16) 651
----------------------------------------------------------------------------
Net change in
derivative financial
instruments
designated as cash
flow hedges
Unrealized(loss)
income during
the period (h) (35) (18) (53) 102 19 121
Income tax 11 2 13 (13) (2) (15)
----------------------------------------------------------------------------
Unrealized(loss)
Income during
the period,
net of tax (24) (16) (40) 89 17 106
----------------------------------------------------------------------------
Reclassification to net
earnings (5) - (5) (4) - (4)
Income tax 1 - 1 1 - 1
----------------------------------------------------------------------------
Reclassification to net
earnings, net of taxes (4) - (4) (3) - (3)
----------------------------------------------------------------------------
(28) (16) (44) 86 17 103
Foreign currency
translation
adjustment
Translation of net
investment (35) 11 (24) 53 (20) 33
----------------------------------------------------------------------------
Other comprehensive
(loss) income, net
of taxes (63) (5) (68) 139 (3) 136
----------------------------------------------------------------------------
Comprehensive
income 1,634 (29) 1,605 806 (19) 787
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliations of the Consolidated Statements of Comprehensive Income
(millions of Canadian Six months ended
dollars, unaudited) Jun 30, 2010
----------------------------------------------------------------------------
Canadian
GAAP Adj IFRS
Note $ $ $
----------------------------------------------------------------------------
Net earnings 1,533 (147) 1,386
----------------------------------------------------------------------------
Net change in
derivative financial
instruments
designated as cash
flow hedges
Unrealized gain (loss)
during the period (h) 96 11 107
Income tax (12) (1) (13)
----------------------------------------------------------------------------
Unrealized gain (loss)
during the period,
net of tax 84 10 94
----------------------------------------------------------------------------
Reclassification to net
earnings (4) - (4)
Income tax 1 - 1
----------------------------------------------------------------------------
Reclassification to net
earnings, net of taxes (3) - (3)
----------------------------------------------------------------------------
81 10 91
Foreign currency
translation
adjustment
Translation of net
investment 10 (9) 1
----------------------------------------------------------------------------
Other comprehensive
gain (loss) income, net
of taxes 91 1 92
----------------------------------------------------------------------------
Comprehensive
income 1,624 (146) 1,478
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes:
(a) Deemed cost of property, plant and equipment
In accordance with IFRS transitional provisions, the Company elected to use the
deemed cost of property, plant and equipment for its exploration and production
assets, which allowed the Company to measure its exploration and evaluation
assets at the amounts capitalized under Canadian GAAP at the date of transition
to IFRS. Additionally, under the transitional provision, the Company elected to
allocate the carrying amount of property, plant and equipment in the development
or production phases under Canadian GAAP to IFRS applicable assets pro rata
using reserve values as at January 1, 2010, subject to impairment tests. The
impairment tests compared the carrying amount of the assets to their recoverable
amounts. The recoverable amount is the higher of fair value less costs to sell
or value in use. The impairment tests conducted by the Company resulted in a
reduction to the carrying amounts of Offshore Africa property, plant and
equipment at the date of transition of $62 million. At January 1, 2010, retained
earnings were reduced by $53 million, net of income taxes of $9 million.
For the year ended December 31, 2010, net earnings decreased by $119 million,
net of taxes of $27 million, to reflect the impact of higher depletion charges,
partially offset by $78 million, net of taxes of $11 million, to reflect the
impact of a lower impairment charge on the Gabon CGU. For the six months ended
June 30, 2010, net earnings decreased by $46 million, net of taxes of $8
million, to reflect the impact of higher depletion charges.
(b) Leases
The Company elected under IFRS 1 not to reassess whether an arrangement contains
a lease under IFRIC 4 for contracts that were assessed under Canadian GAAP.
Arrangements entered into before the effective date of Canadian GAAP EIC 150
that have not subsequently been assessed under EIC 150, were assessed under
IFRIC 4, and no additional leases were identified.
(c) Share-based compensation
The Company has granted share-based compensation that may be settled in either
cash or shares at the holder's option to all employees. The Company accounted
for these share-based payment arrangements by reference to their intrinsic value
under Canadian GAAP. Under IFRS the related liability has been adjusted to
reflect the fair value of the outstanding share-based compensation. The Company
elected to use the IFRS 1 exemption to not retrospectively restate share-based
payment transactions that were settled before the date of transition to IFRS.
This adjustment increased the share-based compensation liability by $230 million
(December 31, 2010 - $147 million; June 30, 2010 - $239 million). Included in
this amount was $11 million (December 31, 2010 - $19 million; June 30, 2010 -
$18 million) capitalized to Oil Sands Mining and Upgrading. At January 1, 2010,
retained earnings were reduced by $170 million, net of income taxes of $49
million.
For the year ended December 31, 2010, net earnings increased by $91 million and
for the six months ended June 30, 2010, net earnings decreased by $2 million to
reflect differences in share-based compensation expense. In addition, during the
six months ended June 30, 2010, deferred income tax expense included an
additional charge of $49 million related to the change to the taxation of stock
options surrendered by employees for cash.
(d) Borrowing costs
Under Canadian GAAP the Company was not required to capitalize all borrowing
costs in respect of constructed assets. At the date of transition, the Company
elected to capitalize borrowing costs in respect of all qualifying assets
effective January 1, 2010.
(e) Asset retirement obligations
In accordance with IFRS transitional provisions for assets described in (a)
above, the Company remeasured the liability associated with asset retirement
obligation activities for the North America, North Sea and Offshore Africa
Exploration and Production segments at the date of transition, resulting in an
increase in asset retirement obligations of $338 million. At January 1, 2010,
retained earnings were reduced by $210 million, net of income taxes of $128
million.
In addition, the Company remeasured the liability related to asset retirement
obligation activities in the Oil Sands Mining and Upgrading segment at the date
of transition. These assets were not subject to the election in (a) above and
accordingly, the difference in the liability between Canadian GAAP and IFRS of
$266 million was recognized in property, plant and equipment in accordance with
IFRS transitional provisions. Additional accumulated depletion of $2 million was
recognized in retained earnings.
The difference between Canadian GAAP and IFRS asset retirement obligations
related primarily to discount rates.
As at December 31, 2010, an additional liability of $234 million was recognized
in property, plant and equipment. For the year ended December 31, 2010, net
earnings decreased by $15 million, net of taxes of $6 million, and for the six
months ended June 30, 2010, net earnings decreased by $8 million, net of taxes
of $3 million, to reflect the impact of higher depletion and accretion charges.
(f) Cumulative translation adjustment
In accordance with IFRS transitional provisions, the Company elected to reset
the cumulative translation adjustment account, which includes gains and losses
arising from the translation of foreign operations, to $nil at the date of
transition to IFRS. Accordingly, accumulated other comprehensive income
increased by $180 million and retained earnings were reduced by $180 million.
(g) Business combinations
In accordance with IFRS transitional provisions, the Company elected to apply
IFRS relating to business combinations prospectively from January 1, 2010. As
such, Canadian GAAP balances relating to business combinations entered into
before that date have been carried forward without adjustment.
(h) Risk management
Under Canadian GAAP, the Company was required to adjust the carrying amount of
the liability for risk management derivative financial instruments by the
Company's own credit risk. Under IFRS, this adjustment is not required. The
reversal of the credit risk adjustment for IFRS on January 1, 2010 resulted in
an increase in the carrying amount of the risk management liability of $16
million (December 31, 2010 - increase of $34 million; June 30, 2010 - decrease
in risk management asset of $2 million) and an increase in accumulated
comprehensive income of $1 million (December 31, 2010 - decrease of $15 million;
June 30, 2010 - increase of $11 million). At January 1, 2010, retained earnings
were reduced by $13 million, net of income taxes of $5 million. Further,
differences in applying fair value hedge accounting between Canadian GAAP and
IFRS resulted in an increase to the carrying value of hedged long-term debt by
$1 million (December 31, 2010 - decrease of $14 million; June 30, 2010 -
decrease of $6 million).
For the year ended December 31, 2010, net earnings increased by $10 million, net
of income taxes of $4 million and other comprehensive income decreased by $16
million, net of income taxes of $2 million. For the six months ended June 30,
2010, net earnings increased by $4 million, net of income taxes of $3, and other
comprehensive income increased by $10 million, net of income taxes of $1
million.
(i) Petroleum Revenue Tax
Under Canadian GAAP, the Company calculated its deferred PRT liability using the
life-of-field method. Under IFRS, the Company calculates its deferred PRT
liability based on temporary differences arising between the tax base of assets
and liabilities of PRT paying fields and their carrying amounts in the
consolidated balance sheets. As a result of this adjustment, the deferred income
tax liability was increased by $116 million ($58 million after-tax) at January
1, 2010 (December 31, 2010 - $80 million, $40 million after-tax; June 30, 2010 -
$106 million, $53 million after-tax). At January 1, 2010, retained earnings were
reduced by $58 million.
For the year ended December 31, 2010, net earnings increased by $18 million, net
of taxes of $18 million and for the six months ended June 30, 2010, net earnings
increased by $5 million, net of taxes of $5 million, to reflect the impact of
lower PRT charges.
(j) UK deferred income tax liabilities
Under Canadian GAAP, the Company calculated the future income tax liabilities of
its UK subsidiaries in UK pounds sterling, and converted the resultant liability
to its US dollar functional currency. Under IFRS, the Company calculates its
UK-based deferred income tax liabilities directly in the functional US dollar
currency. This adjustment resulted in an increase in the deferred income tax
liability of $61 million at January 1, 2010 (December 31, 2010 - $80 million;
June 30, 2010 - $102 million). At January 1, 2010, retained earnings were
reduced by $61 million.
For the year ended December 31, 2010, net earnings decreased by $19 million, and
for the six months ended June 30, 2010, net earnings decreased by $41 million.
(k) Reclassification of current portion of deferred income tax
Under Canadian GAAP, deferred income tax relating to current assets or current
liabilities must be classified as current. Under IFRS, deferred income tax
balances are classified as long-term, irrespective of the classification of the
assets or liabilities to which the deferred income tax relates or the expected
timing of reversal. Accordingly, current deferred income tax assets reported
under Canadian GAAP of $146 million at January 1, 2010 (December 31, 2010 -
current deferred income tax assets of $59 million; June 30, 2010 - current
deferred income tax liabilities of $22 million) have been reclassified as
non-current under IFRS.
(l) Horizon major maintenance costs
Under Canadian GAAP, the Company would have deferred and amortized major
maintenance turnaround costs on a straight-line basis over the period to the
next scheduled major maintenance turnaround. Under IFRS, the Company has
identified capitalized components of the original cost of an asset, which have a
shorter useful life, and has amortized the costs of these components over the
period to the next turnaround. At January 1, 2010, retained earnings decreased
by $14 million, net of taxes of $5 million.
For the year ended December 31, 2010, net earnings decreased by $19 million, net
of taxes of $6 million, and for the six months ended June 30, 2010, net earnings
decreased by $10 million, net of taxes of $3 million, to reflect the impact of
higher depletion charges.
(m) Long-term debt
Under Canadian GAAP, debt maturities within one year of the date of the balance
sheet were classified as non-current on the basis that the Company had the
intent and ability to refinance these obligations with its existing long-term
credit facilities. Under IFRS, as the long-term debt maturing within one year
was not payable to the same counterparty lenders as the long-term debt facility,
$400 million was reclassified to current at January 1, 2010 (December 31, 2010 -
$397 million; June 30, 2010 - $400 million).
Deferred income tax liabilities have been adjusted to give effect to adjustments
as follows:
Dec 31 Jun 30 Jan 1
Note 2010 2010 2010
----------------------------------------------------------------------------
Deferred income tax assets as reported
under Canadian GAAP $ 59 $ - $ 146
Deferred income tax liabilities as
reported under Canadian GAAP (7,899) (7,785) (7,687)
----------------------------------------------------------------------------
Deferred income tax, net (7,840) (7,785) (7,541)
IFRS adjustments
Deemed cost of property, plant and
equipment (a) 25 17 9
Share-based compensation (c) - - 49
Asset retirement obligations (e) 134 131 128
Risk management (h) 3 1 5
PRT (i) (40) (53) (58)
UK deferred income tax liabilities (j) (80) (102) (61)
Horizon maintenance costs (l) 11 8 5
Foreign exchange and other (1) (1) 2
----------------------------------------------------------------------------
Deferred income tax liabilities as
reported under IFRS $ (7,788) $ (7,784) $ (7,462)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following is a summary of transition adjustments, net of tax, to the
Company's accumulated other comprehensive income from Canadian GAAP to IFRS:
Dec 31 Jun 30 Jan 1
Note 2010 2010 2010
----------------------------------------------------------------------------
Accumulated other comprehensive income
as reported under Canadian GAAP $ (167) $ (13) $ (104)
IFRS adjustments
Cumulative translation adjustment on
transition (f) 180 180 180
Risk management (h) (15) 11 1
Translation of net investment 11 (9) -
----------------------------------------------------------------------------
Accumulated other comprehensive income
as reported under IFRS $ 9 $ 169 $ 77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following is a summary of transition adjustments, net of tax, to the
Company's retained earnings from Canadian GAAP to IFRS:
Dec 31 Jun 30 Jan 1
Note 2010 2010 2010
----------------------------------------------------------------------------
Retained earnings as reported under
Canadian GAAP $ 18,005 $ 18,066 $ 16,696
IFRS adjustments
Deemed cost of property, plant and
equipment (a) (94) (99) (53)
Share-based compensation (c) (128) (221) (170)
Asset retirement obligations (e) (227) (220) (212)
Cumulative translation adjustment (f) (180) (180) (180)
Risk management (h) (3) (9) (13)
PRT (i) (40) (53) (58)
UK deferred income tax liabilities (j) (80) (102) (61)
Horizon maintenance costs (l) (33) (24) (14)
Other (8) (8) (8)
----------------------------------------------------------------------------
Retained earnings as reported under IFRS $ 17,212 $ 17,150 $ 15,927
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Adjustments to the statements of cash flows
The transition from Canadian GAAP to IFRS had no significant impact on cash
flows generated by the Company.
SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with the Company's
continuous offering of medium-term notes pursuant to the short form prospectus
dated October 2009. These ratios are based on the Company's interim consolidated
financial statements that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended
June 30, 2011:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 5.5x
Cash flow from operations (2) 14.9x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net earnings plus income taxes and interest expense excluding current
and deferred PRT expense; divided by the sum of interest expense and
capitalized interest.
(2) Cash flow from operations plus current income taxes and interest expense
excluding current PRT 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 Daylight Time, 11:00 a.m.
Eastern Daylight Time on Thursday, August 4, 2011. The North American conference
call number is 1-800-952-6845 and the outside North American conference call
number is 001-416-695-7848. 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 Daylight Time,
Friday, August 12, 2011. To access the postview in North America, dial
1-800-408-3053. Those outside of North America, dial 001-905-694-9451. The
passcode to use is 6866018.
WEBCAST
This call is being webcast and can be accessed on Canadian Natural's website at
www.cnrl.com.
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