Canadian Natural Resources Limited Announces 2012 Third

Canadian Natural Resources Limited Announces 2012 Third Quarter
Results 
CALGARY, ALBERTA -- (Marketwire) -- 11/08/12 -- Canadian Natural
Resources Limited (TSX:CNQ) (NYSE:CNQ)  
Commenting on third quarter results, Canadian Natural's Vice-Chairman
John Langille stated, "During the first nine months of 2012 we
effectively executed a balanced capital budget.  Our large proved
plus probable reserve base (7.5 billion barrels of oil equivalent)
delivered $4.5 billion of cash flow ensuring we maintain a strong
balance sheet with debt to book capitalization at 26% and debt to
EBITDA of 1.1 times. This strong financial position supports our
ability to drive effective capital allocation, efficiently control
costs and continue implementing our successful strategy. 
As part of our successful strategy we have sanctioned the North West
Redwater refinery project. This project strengthens our position by
not only providing a competitive return on investment but also by
adding 50,000 bbl/d of heavy crude oil conversion capacity in Alberta
which will help reduce volatility in pricing all Western Canadian
heavy crude oil." 
Steve Laut, President of Canadian Natural continued, "We had a solid
operating quarter and we met or exceeded production guidance in all
areas of the business. The Company achieved strong production
volumes, up 9% from the third quarter of last year, due to our
successful heavy and light crude oil drilling programs and our oil
sands operations, both thermal in situ and Horizon mining. This is
impressive considering the Company deferred an additional $230
million of capital this quarter, over and above the $680 million that
was previously deferred, totalling $910 million of reduced capital
expenditures since mid-2012. 
During the third quarter, we made substantial progress in driving our
mid and long term potential assets forward.  The Horizon expansion is
making solid progress and tracking below cost estimates. At Pelican
Lake, we continue to roll out our leading edge polymer flood and are
seeing strong production response. We achieved 67% construction
completion at Kirby South Phase 1 and target first steam in late
2013. 
Additionally the Company has added 31,570 net acres of thermal in
situ lands contiguous to our Kirby land holdings.  The additional
lands contain significant SAGD resource potential within the McMurray
reservoir creating long term value for the Company.  It is expected
that these lands will increase overall production capacity at our
thermal in situ operations that currently is targeted to add 500,000
barrels per day of bitumen over the next fifteen years. 
Canadian Natural is in an excellent position. We have a proven
strategy that works, and are focused on effective and efficient
operations in all areas. Our vast resource base, strong technical
expertise, and financial resources will facilitate our ability to
significantly grow cash flow and maximize returns for our
shareholders." 
QUARTERLY HIGHLIGHTS 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
 
($ Millions, except per       Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
 common share amounts)          2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Net earnings               $     360 $     753 $     836 $   1,540 $   1,811
  Per common share - basic $    0.33 $    0.68 $    0.76 $    1.40 $    1.65
  - diluted                $    0.33 $    0.68 $    0.76 $    1.40 $    1.64
Adjusted net earnings from
 operations (1)            $     353 $     606 $     719 $   1,259 $   1,568
  Per common share - basic $    0.33 $    0.55 $    0.65 $    1.15 $    1.43
  - diluted                $    0.32 $    0.55 $    0.65 $    1.14 $    1.42
Cash flow from operations
 (2)                       $   1,431 $   1,754 $   1,767 $   4,465 $   4,389
  Per common share - basic $    1.31 $    1.60 $    1.62 $    4.07 $    4.01
  - diluted                $    1.30 $    1.59 $    1.60 $    4.06 $    3.98
Capital expenditures, net
 of dispositions           $   1,621 $   1,324 $   1,406 $   4,541 $   4,505
 
Daily production, before
 royalties
  Natural gas (MMcf/d)         1,191     1,255     1,252     1,248     1,249
  Crude oil and NGLs
   (bbl/d)                   469,168   470,523   403,900   445,140   370,439
  Equivalent production
   (BOE/d) (3)               667,616   679,607   612,575   653,220   578,618
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(1) Adjusted net earnings from operations is a non-GAAP measure that the
    Company utilizes to evaluate its performance. The derivation of this
    measure is discussed in the Management's Discussion and Analysis
    ("MD&A").
(2) Cash flow from operations is a non-GAAP measure that the Company
    considers key as it demonstrates the Company's ability to fund capital
    reinvestment and debt repayment. The derivation of this measure is
    discussed in the MD&A.
(3) A barrel of oil equivalent ("BOE") is derived by converting six thousand
    cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6
    Mcf:1 bbl). This conversion may be misleading, particularly if 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 a value equivalency at the wellhead. In comparing the value
    ratio using current crude oil prices relative to natural gas prices, the
    6 Mcf:1 bbl conversion ratio may be misleading as an indication of
    value.

 
- During Q3/12, the Company achieved quarterly production of 667,616
BOE/d, representing an increase of 9% over Q3/11, and met or exceeded
production guidance in all areas of the business. 
- The Company's total crude oil and NGLs production during Q3/12 was
469,168 bbl/d, representing an increase of 16% over Q3/11 and
comparable to Q2/12. The increase from Q3/11 was primarily due to a
strong primary heavy crude oil drilling program, the timing of
production cycles in bitumen ("thermal in situ"), and safe, steady
and reliable operations at Horizon. Q3/12 production volumes remained
consistent with Q2/12 volumes and were primarily driven by increased
heavy crude oil production, increased Pelican Lake crude oil
production and increased thermal in situ production offset by lower
synthetic crude oil ("SCO") production. 
- During Q3/12, total natural gas production for the Company was
1,191 MMcf/d representing a decrease of 5% from both Q3/11 and Q2/12
levels. The decrease in production from Q3/11 and Q2/12 was primarily
a result of natural declines and 40 MMcf/d of cumulative shut-in
natural gas volumes reflecting the Company's strategic decision to
allocate capital to higher return crude oil projects due to low
natural gas prices. 
- Canadian Natural generated quarterly cash flow of $1.43 billion,
compared to $1.77 billion in Q3/11 and $1.75 billion in Q2/12. Cash
flow decreased from Q3/11 primarily resulting from lower crude oil
and NGLs and natural gas netbacks and lower SCO pricing partially
offset by higher crude oil and SCO sales volumes. The decrease in
cash flow from Q2/12 was primarily due to lower SCO sales volumes and
lower crude oil and NGLs netbacks. These factors, along with the
impact of a stronger Canadian dollar and non-operational realized
risk management losses were partially offset by higher crude oil
sales volumes in North America and higher natural gas prices. 
- Adjusted net earnings from operations for the quarter were $353
million, compared with adjusted net earnings of $719 million in Q3/11
and $606 million in Q2/12. Changes in adjusted net earnings reflect
the changes in cash flow from operations. 
- The Company reduced targeted 2012 capital spending by an additional
$230 million in the quarter, resulting in total capital spending
reductions of $910 million or 12%, compared to the updated capital
budget announced in May 2012. At the same time, the mid-point of
total BOE production volume guidance has decreased only 1% for 2012.
This illustrates the strength of the Company's asset base and ability
to maintain capital flexibility while allocating capital to the
highest return projects. 
- Operating highlights for Q3/12 include the following with further
details included in the Operations Review sections. 
-- Primary heavy crude oil operations achieved production volumes
that totaled over 128,000 bbl/d, resulting in the seventh consecutive
quarter of record production. Production increased by 26% compared
with Q3/11. 
-- North America light crude oil and NGLs quarterly production
increased 15% from Q3/11. 
-- Reservoir performance at Pelican Lake continues to be positive as
production volumes of approximately 41,000 bbl/d in Q3/12 were
achieved, an increase of 8% over Q3/11 volumes. 
-- In Q3/12, thermal in situ production grew 8% from the previous
quarter to approximately 102,000 bbl/d. 
-- Kirby South Phase 1 is progressing ahead of plan. All major
equipment and modules have been delivered and installed on site with
overall construction progress ahead of schedule. 
-- In Q3/12, solid production volumes were achieved at Horizon Oil
Sands ("Horizon"), exceeding 99,200 bbl/d. 
-- Canadian Natural's staged expansion to 250,000 bbl/d of SCO
production capacity at Horizon continues to progress on track. 
- Subsequent to Q3/12, North West Redwater Partnership and its owners
(50% Canadian Natural) completed the sanctioning process for the
construction of a 50,000 bbl/d bitumen refinery. Simultaneously, the
feedstock providers (Canadian Natural for 12,500 bbl/d and Alberta
Petroleum Marketing Commission for 37,500 bbl/d) approved the target
toll amounts and have now committed to the 30 year tolling agreement. 
- To date in 2012, Canadian Natural has purchased 7,825,200 common
shares for cancellation at a weighted average price of $29.22 per
common share. 
- Declared a quarterly cash dividend on common shares of $0.105 per
common share payable January 1, 2013. 
- Canadian Natural will release its 2013 budget details on Tuesday,
December 4, 2012.  The Company will provide forward looking
information on its 2013 operating year. 
OPERATIONS REVIEW AND CAPITAL ALLOCATION 
In order to facilitate efficient operations, Canadian Natural focuses
its activities in core regions where it can own a substantial land
base and associated infrastructure. Land inventories are maintained
to enable continuous exploitation of play types and geological
trends, greatly reducing overall exploration risk. By owning
associated 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; light and medium crude oil, primary heavy
crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein
collectively referred to as "crude oil"), natural gas and NGLs. A
large diversified project portfolio enables the effective allocation
of capital to higher return opportunities. 
OPERATIONS REVIEW 
Drilling activity (number of wells) 


 
                                             Nine Months Ended Sep 30
                                      --------------------------------------
                                             2012               2011
                                          Gross      Net     Gross      Net
----------------------------------------------------------------------------
Crude oil                                   952      909       816      773
Natural gas                                  37       32        68       56
Dry                                          14       14        32       31
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Subtotal                                  1,003      955       916      860
Stratigraphic test / service wells          612      611       547      545
----------------------------------------------------------------------------
Total                                     1,615    1,566     1,463    1,405
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Success rate (excluding stratigraphic
 test / service wells)                                99%                96%
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North America Exploration and Production 
North America crude oil and NGLs 


 
                                   Three Months Ended     Nine Months Ended
                               ---------------------------------------------
                                 Sep 30   Jun 30   Sep 30   Sep 30   Sep 30
                                   2012     2012     2011     2012     2011
----------------------------------------------------------------------------
Crude oil and NGLs production
 (bbl/d)                        332,895  316,483  304,671  318,384  296,892
----------------------------------------------------------------------------
 
Net wells targeting crude oil       371      268      327      923      802
Net successful wells drilled        365      266      317      909      773
----------------------------------------------------------------------------
  Success rate                       98%      99%      97%      98%      96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- Production averaged 332,895 bbl/d in Q3/12 representing an increase
of 9% from Q3/11 and an increase of 5% from Q2/12. The increase in
production from Q3/11 was a result of a successful primary heavy
crude oil drilling program and the timing of thermal in situ
production cycles. The increase in production from Q2/12 was a result
of strong heavy crude oil production, increased Pelican Lake volumes
and the continuing ramp up of thermal in situ production as pads
re-entered the production cycle. 
- Primary heavy crude oil currently provides the highest return on
capital projects in Canadian Natural's portfolio.  Primary heavy
crude oil operations achieved production volumes that totaled over
128,000 bbl/d, resulting in the seventh consecutive quarter of record
production. Production increased by 26% and 5% compared with Q3/11
and Q2/12 levels respectively, primarily due to a successful drilling
program and strong production results from Woodenhouse, a new
non-traditional primary heavy crude oil area located 75 kilometers
north of Pelican Lake. 
-- The production profiles at Woodenhouse have been better than
anticipated.  In October 2012, production averaged 9,300 bbl/d and
exit rate production for 2012 is targeted at approximately 12,600
bbl/d.  In 2012, 71 wells have been drilled at Woodenhouse and the
Company targets to drill 15 additional wells by year-end. 
-- Canadian Natural targets to drill 241 net primary heavy crude oil
wells (including Woodenhouse) in Q4/12 for a targeted record of 901
total net wells in 2012, 93 more net wells than the original budget.
The Company has further increased its targeted annual production
guidance by 5% to an increase of 22% over 2011 production volumes. 
-- Canadian Natural continues to demonstrate efficient and effective
operations in primary heavy crude oil. Low quarterly operating costs
of $14.27/bbl were achieved in Q3/12 and continue to result in high
netbacks and high value production contributing to the Company's
significant cash flow. 
- North America light crude oil and NGLs quarterly production
increased 15% from Q3/11 as a result of a successful light oil
drilling program and increased production from Septimus. North
America light crude oil and NGLs is a significant part of Canadian
Natural's balanced portfolio, averaging approximately 62,600 bbl/d in
the quarter. 
- Reservoir performance at Pelican Lake continues to be positive as
production volumes of approximately 41,000 bbl/d in Q3/12 were
achieved, an increase of 8% over Q3/11 volumes. 
-- The Company achieved over 37,000 bbl/d in Q2/12, approximately
41,000 bbl/d in Q3/12 and exit rates for 2012 are targeted to be
approximately 43,000 bbl/d, a 16% increase from Q2/12 production
volumes. 
-- Construction of the 25,000 bbl/d battery expansion is targeted to
be on stream by Q2/13 and will support production growth to over
60,000 bbl/d targeted by 2015/16. 
-- Pelican Lake continues to achieve low quarterly operating costs at
$10.69/bbl in Q3/12, which result in high netbacks and high value
production contributing to the Company's significant cash flow. 
-- Ultimate recovery from this world class pool is targeted to be 561
million barrels (363 million barrels of proved plus probable reserves
and 198 million barrels of best estimate contingent resources) of
additional crude oil through a disciplined multi-year expansion plan. 
- Canadian Natural's robust portfolio of thermal in situ projects is
a significant part of the Company's defined plan to transition to a
longer-life, more sustainable asset base with the ability to generate
significant shareholder value for decades to come. The Company
targets to grow thermal in situ production to approximately 500,000
bbl/d of capacity by delivering projects that will add 40,000 bbl/d
of production every two to three years. 
-- In Q3/12, thermal in situ production grew 8% from the previous
quarter to approximately 102,000 bbl/d. 
--- The Company achieved over 94,000 bbl/d in Q2/12, approximately
102,000 bbl/d in Q3/12 and exit rates for 2012 are targeted to be
approximately 119,500 bbl/d, a 27% increase from Q2/12 production
volumes. 
--- Total quarterly operating costs, including energy costs, for the
quarter were $8.84/bbl in Q3/12, which is industry leading for
thermal in situ and demonstrates the Company's commitment to
operational excellence. As a result, the Company achieves high
netbacks and high volume production contributing to the Company's
significant cash flow. 
-- Kirby South Phase 1 is progressing ahead of plan. All major
equipment and modules have been delivered and installed on site with
overall construction progress ahead of schedule. An update to the
project at the end of Q3/12 is as follows: 
--- Overall project is 67% complete. 
--- Module assembly is 96% complete. 
--- Overall construction is 58% complete. 
--- Drilling is 73% complete. Drilling on the fourth of seven pads
was completed in Q3/12 and the fifth pad was rig released in early
Q4/12. 
--- First steam-in is targeted for late 2013 and production is
targeted to ramp up to 40,000 bbl/d in 2014. 
-- Over the past twelve months and through 3 separate transactions,
31,570 net acres of additional leases adjacent to Canadian Natural's
Kirby In Situ Oil Sands Expansion Project ("Kirby Project") were
acquired, adding best estimate contingent resources of 340 million
barrels of bitumen. The Company is in the early stages of integrating
the acquired lands into the development plan and is expecting to
increase production capacity for future phases in Kirby North and
Kirby South beyond current estimates. The Company expects to gain
significant capital and operating synergies within the Kirby Project,
which will create the potential to drive exploitation opportunities
similar to those seen at Primrose over the last decade. 
-- On Kirby North Phase 1, engineering design specifications are
complete and the transition to detailed engineering is now in
progress. Critical long lead items have been ordered and the central
plant site has been cleared. First steam-in is targeted for early
2016. 
-- At Grouse, engineering is on track. The design basis memorandum
engineering is complete and the transition to engineering design
specifications is now in progress. First steam-in is targeted for
late 2017. 
- For Q4/12, the Company plans to drill 42 net thermal in situ wells
and 302 net crude oil wells, excluding strat test and service wells. 
- North America crude oil and NGLs quarterly operating costs
decreased to $12.52/bbl in Q3/12 from $13.10/bbl in Q2/12. The
decrease was primarily due to reduced primary heavy crude oil
operating costs as a result of strategic capital investments made
during the first half of 2012 and the timing of thermal in situ
production cycles. 
North America natural gas 


 
                                Three Months Ended       Nine Months Ended
                          --------------------------------------------------
                             Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                               2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Natural gas production
 (MMcf/d)                     1,169     1,230     1,226     1,226     1,223
----------------------------------------------------------------------------
 
Net wells targeting
 natural gas                      9         4        21        32        57
Net successful wells
 drilled                          9         4        21        32        56
----------------------------------------------------------------------------
  Success rate                  100%      100%      100%      100%       98%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- North America natural gas production for the quarter averaged 1,169
MMcf/d representing a decrease of 5% from both Q3/11 and Q2/12
production levels. The decrease in production levels was a result of
natural declines and 40 MMcf/d of cumulative shut-in natural gas
volumes reflecting the Company's strategic decision to allocate
capital to higher return crude oil projects. 
- The Company reduced capital spending on natural gas by an
additional $45 million in the quarter, resulting in total capital
spending reductions of $345 million or 42% for 2012 compared to the
original capital budget while the mid-point of production volume
guidance decreased 6% in 2012 compared to the original capital
budget. This illustrates the strength of the Company's asset base and
ability to maintain capital flexibility and allocate capital to the
highest return projects. 
- North America natural gas quarterly operating costs increased to
$1.28/Mcf in Q3/12 from $1.13/Mcf in Q2/12 as a result of reduced
volumes, seasonal maintenance activity, increased property taxes and
lease rentals. 
- Canadian Natural is the second largest natural gas producer in
Canada and has an extensive land base where it demonstrates efficient
and effective operations. The Company's vast land base of both
conventional and unconventional natural gas assets and ownership of
infrastructure favorably positions the Company to increase drilling
activity and production volumes once gas prices strengthen. Canadian
Natural's significant unconventional assets include approximately
1,044,000 net acres in the Montney and approximately 500,000 net
acres in the Duvernay. 
International Exploration and Production 


 
                               Three Months Ended        Nine Months Ended
                         --------------------------------------------------
                             Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                               2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Crude oil production
 (bbl/d)
  North Sea                  19,502    17,619    26,350    20,054    31,077
  Offshore Africa            17,566    20,598    22,525    19,618    23,105
----------------------------------------------------------------------------
Natural gas production
 (MMcf/d)
  North Sea                       2         2         5         2         7
  Offshore Africa                20        23        21        20        19
----------------------------------------------------------------------------
Net wells targeting crude
 oil                              -         -         -         -       0.9
Net successful wells
 drilled                          -         -         -         -       0.9
----------------------------------------------------------------------------
  Success rate                    -         -         -         -       100%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- North Sea crude oil production averaged 19,502 bbl/d during Q3/12
representing a decrease of 26% compared with Q3/11 and an increase of
11% compared with Q2/12. The decrease from Q3/11 was primarily due to
suspended operations at Banff/Kyle, planned maintenance on a
third-party operated pipeline, and planned maintenance turnarounds at
the Ninian platforms that commenced late in Q3/12. The increase from
Q2/12 was primarily due to partial recovery of production volumes
following the unplanned shutdown of the Ninian platforms in Q2/12 as
a result of a third-party pipeline outage. 
- Production in Offshore Africa averaged 17,566 bbl/d during Q3/12
representing a decrease of 22% compared with Q3/11 and a decrease of
15% compared with Q2/12. The decrease from Q3/11 and Q2/12 production
volumes was primarily due to natural declines and a planned 9 day
turnaround at Baobab. A planned 15 day turnaround at Espoir is
scheduled in Q4/12. 
- Canadian Natural's eight well infill drilling program at the Espoir
Field is progressing. The drilling rig has arrived in Cote d'Ivoire
and preparations are currently being undertaken to commence drilling.
The Company targets first oil in Q2/13 ramping up to production of
6,500 BOE/d at the completion of the Espoir drilling program,
offsetting natural declines. The cost of this program is targeted at
$24,000 per flowing BOE. 
- Conversion of the license of the Company's 100% working interest
block in South Africa has been completed and all regulatory
requirements to drill a well are complete. Targeted drilling windows
are from Q4/13 to Q1/14 and from Q4/14 to Q1/15. 
North America Oil Sands Mining and Upgrading - Horizon 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                                2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Synthetic crude oil
 production (bbl/d)           99,205   115,823    50,354    87,084    19,365
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- Horizon continued to demonstrate solid operational performance in
the quarter. Production averaged 99,205 bbl/d, representing a 97%
increase from Q3/11 and a 14% decrease from Q2/12. The increase from
Q3/11 was due to improved steady operations at Horizon, and the
decrease from Q2/12 resulted from the Company's decision to operate
at restricted rates for a portion of Q3/12 to ensure safe, steady and
reliable operations in anticipation of the proactive planned
maintenance that was completed in Q4/12. 
- Previously planned maintenance at Horizon originally scheduled to
occur in late Q3/12 was shifted into Q4/12 (October) to optimize the
benefit of the outage and address potential risks associated with the
winter season. The planned outage, scheduled for twelve days in the
month of October, was completed on schedule and on cost. Production
was returned to 115,000 bbl/d and then temporarily reduced to
proactively allow tank volumes and overall performance to reach
optimal levels not yet achieved following the ramp up. The decision
to temporarily reduce production reflects the Company's commitment to
increasing overall reliability going forward. Horizon production
guidance for 2012 has been reduced to range from 87,000 bbl/d to
89,000 bbl/d. However, overall long term production volumes are
expected to increase because of these proactive actions. 
- The Company's focus on operational discipline and proactive
maintenance activities will, over time, deliver increasing levels of
reliability resulting in more effective and efficient operations, and
lower operating costs at the plant.  In Q3/12 quarterly operating
costs averaged $42.69/bbl, which were primarily a result of lower
production volumes and one-time costs. 
- Canadian Natural's staged expansion to 250,000 bbl/d of SCO
production capacity continues to progress on track. An update to the
expansion at the end of Q3/12 is as follows: 
-- Overall Horizon expansion is 15% complete. 
-- Reliability - Tranche 2 is 84% complete. 
-- Directive 74 and Technology are 14% complete. 
-- Phase 2A is 39% complete. 
-- Phase 2B is 6% complete. 
-- Phase 3 is 6% complete. 
-- Thus far, four lump sum contracts have been awarded and projects
currently under construction are trending at or below cost estimates. 
MARKETING 


 
                                Three Months Ended       Nine Months Ended
                          --------------------------------------------------
                             Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                               2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Crude oil and NGLs pricing
  WTI benchmark price
   (US$/bbl) (1)           $  92.19  $  93.50  $  89.81  $  96.20  $  95.52
  WCS blend differential
   from WTI (%) (2)              24%       24%       20%       23%       20%
  SCO price (US$/bbl)      $  90.84  $  89.54  $ 100.64  $  92.82  $ 103.86
  Average realized pricing
   before risk management
   (C$/bbl) (3)            $  67.59  $  69.99  $  73.80  $  72.43  $  74.77
Natural gas pricing
  AECO benchmark price
   (C$/GJ)                 $   2.08  $   1.74  $   3.53  $   2.07  $   3.55
  Average realized pricing
   before risk management
   (C$/Mcf)                $   2.28  $   1.90  $   3.76  $   2.22  $   3.81
----------------------------------------------------------------------------
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(1) West Texas Intermediate ("WTI").
(2) Western Canadian Select ("WCS").
(3) Excludes SCO.

 
- The WCS heavy crude oil differential as a percent of WTI was
seasonally normal, averaging 24% in Q3/12, and in line with the
Company's long term expectations and well below historical averages.
The WCS heavy differential remained unchanged from Q2/12. The Company
anticipates continued volatility in the differential in Q4/12 and
narrowing of the differential thereafter as additional conversion and
pipeline capacity come on stream.
- For December 2012, heavy crude oil currently trades at a US$6.00
premium (7% premium) to WTI on the US Gulf Coast ("USGC") and at a
US$30.00 discount (35% discount) at Hardisty reflecting the
logistical constraints at Cushing, which are currently being
debottlenecked. 
-- Canadian Natural ships approximately 20,000 bbl/d of heavy crude
oil via a combination of pipelines to USGC markets and receives Mayan
based pricing for these barrels. 
-- Approximately 10,000 bbl/d of heavy crude oil is railed to USGC
markets and receives significantly higher netbacks than the
traditional heavy crude oil markets. 
-- This highlights the strong demand for Gulf Coast refiners to use
heavy crude oil blends as feedstock, and the value to Canadian
producers reaching the Gulf Coast. 
- During Q3/12, Canadian Natural contributed 155,000 bbl/d of its
heavy crude oil stream to the WCS blend. The Company is the largest
contributor of the WCS blend, accounting for 55%. 
- Natural gas pricing remains weak as compared to previous year
pricing.  In response, Canadian production has declined while US
production remains steady through 2012.  AECO benchmark natural gas
prices strengthened in Q3/12 compared with Q2/12 due to increased
demand from the power generation sector and increased seasonal
demand. 
NORTH WEST REDWATER UPGRADING AND REFINING 
Subsequent to Q3/12, North West Redwater Partnership and its owners
(50% Canadian Natural) completed the sanctioning process for the
construction of a 50,000 bbl/d bitumen refinery.  Simultaneously, the
feedstock providers (Canadian Natural for 12,500 bbl/d and Alberta
Petroleum Marketing Commission for 37,500 bbl/d) approved the target
toll amounts and have now committed to the 30 year tolling agreement.
Canadian Natural will earn a return on the project of 10% on its
equity investment, and additional margin on any excess capacity
available over design capacity. Based on sanction capital for the
project, the majority of equity has already been contributed to the
partnership. Target commencement of deliveries is mid-2016. 
The North West Redwater refinery project strengthens the Company's
position by not only providing a competitive return on investment but
by also adding 50,000 bbl/d of bitumen conversion capacity in Alberta
which will help reduce volatility in pricing all Western Canadian
heavy crude oil. There is potential to further expand the downstream
capacity of the North West Redwater refinery project from its 50,000
bbl/d of bitumen facility capacity in Phase 1 to 150,000 bbl/d of
bitumen facility capacity. 
FINANCIAL REVIEW 
The financial position of Canadian Natural remains strong as the
Company continues to implement proven strategies and focuses on
disciplined capital allocation. Canadian Natural's cash flow
generation, credit facilities, diverse asset base and related capital
expenditure programs, and commodity hedging policy all support a
flexible financial position and provide the right financial resources
for the near, mid and long term. 
- The Company's strategy is to maintain a diverse portfolio balanced
across various commodity types. The Company achieved production of
667,616 BOE/d for the quarter with over 97% of production located in
G8 countries. 
- Canadian Natural has a strong balance sheet with debt to book
capitalization of 26% and debt to EBITDA of 1.1x. At September 30,
2012, long-term debt amounted to $8.4 billion compared with $8.6
billion at December 31, 2011. 
- Canadian Natural maintains significant financial stability and
liquidity represented by approximately $4.26 billion in available
unused bank lines at the end of the quarter. 
- The Company's commodity hedging program protects investment
returns, ensures ongoing balance sheet strength and supports the
Company's cash flow for its capital expenditures programs. The
Company has hedged approximately 60% of the remaining crude oil
volumes forecasted for 2012, 150,000 bbl/d of crude oil volumes for
the first half of 2013, and 100,000 bbl/d of crude oil volumes for
the second half of 2013 through a combination of puts and collars. 
- To date in 2012, Canadian Natural has purchased 7,825,200 common
shares for cancellation at a weighted average price of $29.22 per
common share. 
- Declared a quarterly cash dividend on common shares of $0.105 per
common share payable January 1, 2013. 
OUTLOOK 
The Company forecasts 2012 production levels before royalties to
average between 1,222 and 1,229 MMcf/d of natural gas and between
452,000 and 460,000 bbl/d of crude oil and NGLs. Q4/12 production
guidance before royalties is forecast to average between 1,145 and
1,165 MMcf/d of natural gas and between 467,000 and 495,000 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 operations and
future expansions, Primrose, Pelican Lake, the Kirby Thermal Oil
Sands Project, and the construction and future operations of the
North West Redwater bitumen upgrader and 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
and proved plus probable 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
disruptions or delays in the resumption of the mining, extracting or
upgrading of 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, whether as a result of new information, future events or
other factors, or the foregoing factors affecting this information,
should circumstances or Management's estimates or opinions change. 
Management's Discussion and Analysis 
This MD&A of the financial condition and results of operations of the
Company should be read in conjunction with the unaudited interim
consolidated financial statements for the three and nine months ended
September 30, 2012 and the MD&A and the audited consolidated
financial statements for the year ended December 31, 2011. 
All dollar amounts are referenced in millions of Canadian dollars,
except where noted otherwise. The Company's consolidated financial
statements for the period ended September 30, 2012 and this MD&A have
been prepared in accordance with International Financial Reporting
Standards ("IFRS"), as issued by the International Accounting
Standards Board. Unless otherwise stated, 2010 comparative figures
have been restated in accordance with IFRS issued as at December 31,
2011. 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. 
A Barrel of Oil Equivalent ("BOE") is derived by converting six
thousand cubic feet of natural gas to one barrel of crude oil (6
Mcf:1 bbl). This conversion may be misleading, particularly if 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 a value equivalency at the wellhead. In
comparing the value ratio using current crude oil prices relative to
natural gas prices, the 6 Mcf:1 bbl conversion ratio may be
misleading as an indication of value. In addition, for the purposes
of this MD&A, crude oil is defined to include the following
commodities: light and medium crude oil, primary heavy crude oil,
Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic
crude oil. 
Production volumes and per unit statistics are presented throughout
this MD&A on a "before royalty" or "gross" basis, and realized prices
are net of transportation and blending costs and exclude the effect
of risk management activities. Production on an "after royalty" or
"net" basis is also presented for information purposes only. 
The following discussion refers primarily to the Company's financial
results for the three and nine months ended September 30, 2012 in
relation to the comparable periods in 2011 and the second quarter of
2012. The accompanying tables form an integral part of this MD&A.
This MD&A is dated November 6, 2012. Additional information relating
to the Company, including its Annual Information Form for the year
ended December 31, 2011, is available on SEDAR at www.sedar.com, and
on EDGAR at www.sec.gov. 
FINANCIAL HIGHLIGHTS 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
($ millions, except per       Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
 common share amounts)          2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Product sales              $   3,978 $   4,187 $   3,690 $  12,136 $  10,719
Net earnings               $     360 $     753 $     836 $   1,540 $   1,811
 Per common share
 - basic                   $    0.33 $    0.68 $    0.76 $    1.40 $    1.65
 - diluted                 $    0.33 $    0.68 $    0.76 $    1.40 $    1.64
Adjusted net earnings from
 operations (1)            $     353 $     606 $     719 $   1,259 $   1,568
 Per common share
  - basic                  $    0.33 $    0.55 $    0.65 $    1.15 $    1.43
  - diluted                $    0.32 $    0.55 $    0.65 $    1.14 $    1.42
Cash flow from operations
 (2)                       $   1,431 $   1,754 $   1,767 $   4,465 $   4,389
 Per common share
 - basic                   $    1.31 $    1.60 $    1.62 $    4.07 $    4.01
 - diluted                 $    1.30 $    1.59 $    1.60 $    4.06 $    3.98
Capital expenditures, net
 of dispositions           $   1,621 $   1,324 $   1,406 $   4,541 $   4,505
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
    lists certain non-cash items that are included in the Company's
    financial results. Cash flow from operations may not be comparable to
    similar measures presented by other companies.

 
Adjusted Net Earnings from Operations 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
                             Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
($ millions)                   2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Net earnings as reported   $    360  $    753  $    836  $  1,540  $  1,811
Share-based compensation,
 net of tax (1)                  49      (115)     (249)     (173)     (309)
Unrealized risk management
 loss (gain), net of tax
 (2)                             22      (103)      (97)      (41)     (145)
Unrealized foreign
 exchange (gain) loss, net
 of tax (3)                    (136)       71       454      (125)      332
 Realized foreign exchange
  gain on repayment of US
  dollar debt securities
  (4)                             -         -      (225)        -      (225)
 Effect of statutory tax
  rate and other
  legislative changes on
  deferred income
  tax liabilities (5)             58         -         -        58       104
----------------------------------------------------------------------------
Adjusted net earnings from
 operations                $    353  $    606  $    719  $  1,259  $  1,568
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) 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.
(2) 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.
(3) Unrealized foreign exchange gains and losses result primarily from the
    translation of US dollar denominated long-term debt to period-end
    exchange rates, partially offset by the impact of cross currency swaps,
    and are recognized in net earnings.
(4) During the third quarter of 2011, the Company repaid US$400 million of
    US dollar debt securities bearing interest at 6.7%.
(5) All substantively enacted adjustments in applicable income tax rates and
    other legislative changes are applied to underlying assets and
    liabilities on the Company's 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 third quarter of
    2012, the UK government enacted legislation to restrict the combined
    corporate and supplementary income tax rate relief on decommissioning
    expenditures to 50%, resulting in an increase in the Company's deferred
    income tax liability of $58 million. During the first quarter of 2011,
    the UK government 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.

 
Cash Flow from Operations 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
                             Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
($ millions)                   2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Net earnings               $    360  $    753  $    836  $  1,540  $  1,811
Non-cash items:
 Depletion, depreciation
  and amortization            1,056     1,084       887     3,115     2,606
 Share-based compensation        49      (115)     (249)     (173)     (309)
 Asset retirement
  obligation accretion           38        38        33       113        97
 Unrealized risk
  management loss (gain)         34      (144)     (122)      (50)     (186)
 Unrealized foreign
  exchange (gain) loss         (136)       71       454      (125)      332
 Realized foreign exchange
  gain on repayment of US
  dollar debt securities          -         -      (225)        -      (225)
 Equity loss from jointly
  controlled entity               1         5         -         6         -
 Deferred income tax
  expense                        29        62       153        39       263
 Horizon asset impairment
  provision                       -         -         -         -       396
Insurance recovery -
 property damage                  -         -         -         -      (396)
----------------------------------------------------------------------------
Cash flow from operations  $  1,431  $  1,754  $  1,767  $  4,465  $  4,389
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS 
Net earnings for the nine months ended September 30, 2012 amounted to
$1,540 million compared with $1,811 million for the nine months ended
September 30, 2011. Net earnings for the nine months ended September
30, 2012 included net after-tax income of $281 million compared with
net after-tax income of $243 million for the nine months ended
September 30, 2011 related to the effects of share-based
compensation, risk management activities, fluctuations in foreign
exchange rates, the impact of a realized foreign exchange gain on
repayment of long-term debt and the impact of statutory tax rate and
other legislative changes on deferred income tax liabilities.
Excluding these items, adjusted net earnings from operations for the
nine months ended September 30, 2012 were $1,259 million compared
with $1,568 million for the nine months ended September 30, 2011. 
Net earnings for the third quarter of 2012 were $360 million compared
with $836 million for the third quarter of 2011 and $753 million for
the second quarter of 2012. Net earnings for the third quarter of
2012 included net after-tax income of $7 million compared with $117
million for the third quarter of 2011 and $147 million for the second
quarter of 2012 related to the effects of share-based compensation,
risk management activities, fluctuations in foreign exchange rates,
the impact of a realized foreign exchange gain on repayment of
long-term debt and the impact of statutory tax rate and other
legislative changes on deferred income tax liabilities. Excluding
these items, adjusted net earnings from operations for the third
quarter of 2012 were $353 million compared with $719 million for the
third quarter of 2011 and $606 million for the second quarter of
2012. 
The decrease in adjusted net earnings for the three and nine months
ended September 30, 2012 from the comparable periods in 2011 was
primarily due to: 
- lower crude oil and NGLs and natural gas netbacks; 
- lower realized synthetic crude oil ("SCO") prices; 
- higher depletion, depreciation and amortization expense; and 
- realized risk management losses;  
partially offset by: 
- higher crude oil and SCO sales volumes in the North America and Oil
Sands Mining and Upgrading segments; and 
- the impact of a weaker Canadian dollar. 
The decrease in adjusted net earnings for the third quarter of 2012
from the second quarter of 2012 was primarily due to: 
- lower SCO sales volumes in the Oil Sands Mining and Upgrading
segment; 
- lower crude oil and NGLs netbacks; 
- the impact of a stronger Canadian dollar; and 
- realized risk management losses; 
partially offset by: 
- higher crude oil sales volumes in the North America segment; and 
- lower depletion, depreciation and amortization expense. 
The impacts of share-based compensation, 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 nine months ended September 30,
2012 was $4,465 million compared with $4,389 million for the nine
months ended September 30, 2011. Cash flow from operations for the
third quarter of 2012 was $1,431 million compared with $1,767 million
for the third quarter of 2011 and $1,754 million for the second
quarter of 2012. The fluctuations in cash flow from operations from
the comparable periods was primarily due to the factors noted above
relating to the decrease in adjusted net earnings, excluding
depletion, depreciation and amortization expense. 
Total production before royalties for the nine months ended September
30, 2012 increased 13% to 653,220 BOE/d from 578,618 BOE/d for the
nine months ended September 30, 2011. Total production before
royalties for the third quarter of 2012 increased 9% to 667,616 BOE/d
from 612,575 BOE/d for the third quarter of 2011, and decreased 2%
from 679,607 BOE/d for the second quarter of 2012. Production for the
third quarter of 2012 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    Sep 30    Jun 30    Mar 31   Dec 31
 amounts)                                 2012      2012      2012     2011
----------------------------------------------------------------------------
Product sales                        $   3,978 $   4,187 $   3,971 $  4,788
Net earnings (loss)                  $     360 $     753 $     427 $    832
Net earnings (loss) per common share
 - basic                             $    0.33 $    0.68 $    0.39 $   0.76
 - diluted                           $    0.33 $    0.68 $    0.39 $   0.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
($ millions, except per common share    Sep 30    Jun 30    Mar 31   Dec 31
 amounts)                                 2011      2011      2011     2010
----------------------------------------------------------------------------
Product sales                        $   3,690 $   3,727 $   3,302 $  3,787
Net earnings (loss)                  $     836 $     929 $      46 $   (309)
Net earnings (loss) per common share
 - basic                             $    0.76 $    0.85 $    0.04 $  (0.28)
 - diluted                           $    0.76 $    0.84 $    0.04 $  (0.28)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 from West Texas
Intermediate ("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 fluctuations in both the demand
for natural gas and inventory storage levels, and the impact of
increased shale gas production in 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, the
record heavy oil drilling program, and the impact of the suspension
and recommencement of production at Horizon. Sales volumes also
reflected fluctuations due to timing of liftings and maintenance
activities in the North Sea and Offshore Africa, and payout of the
Baobab field in May 2011. 
- 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 and
timing 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, acquisitions of natural gas producing
properties that had higher operating costs per Mcf than the Company's
existing properties, and the suspension and recommencement of
production at Horizon. 
- 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 suspension and recommencement of
production at Horizon and the impact of impairments at the Olowi
field in offshore Gabon. 
- Share-based compensation - Fluctuations due to the determination of
fair market value based on the Black-Scholes valuation model 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 that 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
realized and 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 include
statutory tax rate and other legislative changes substantively
enacted in the various periods. 
BUSINESS ENVIRONMENT 


 
                                Three Months Ended       Nine Months Ended
                          --------------------------------------------------
                             Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                               2012      2012      2011      2012      2011
----------------------------------------------------------------------------
WTI benchmark price
 (US$/bbl)                 $  92.19  $  93.50  $  89.81  $  96.20  $  95.52
Dated Brent benchmark
 price (US$/bbl)           $ 109.57  $ 108.21  $ 113.46  $ 112.07  $ 111.96
WCS blend differential
 from WTI (US$/bbl)        $  21.78  $  22.83  $  17.66  $  22.03  $  19.32
WCS blend differential
 from WTI (%)                    24%       24%       20%       23%       20%
SCO price (US$/bbl)        $  90.84  $  89.54  $ 100.64  $  92.82  $ 103.86
Condensate benchmark price
 (US$/bbl)                 $  96.09  $  99.49  $ 101.73  $ 101.85  $ 104.27
NYMEX benchmark price
 (US$/MMBtu)               $   2.82  $   2.26  $   4.19  $   2.62  $   4.23
AECO benchmark price
 (C$/GJ)                   $   2.08  $   1.74  $   3.53  $   2.07  $   3.55
US/Canadian dollar average
 exchange rate (US$)       $ 1.0047  $ 0.9897  $ 1.0197  $ 0.9977  $ 1.0224
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Commodity Prices 
Crude oil sales contracts in the North America segment are typically
based on WTI benchmark pricing. WTI averaged US$96.20 per bbl for the
nine months ended September 30, 2012 and was comparable with the nine
months ended September 30, 2011. WTI averaged US$92.19 per bbl for
the third quarter of 2012, an increase of 3% from US$89.81 per bbl
for the third quarter of 2011 and was comparable with the second
quarter of 2012. WTI pricing was reflective of the political
instability in the Middle East with growing tensions between Israel
and Iran creating instability in the crude price; partially offset by
declining optimism in the United States economy, the European debt
crisis, and lower than expected growth in Asian demand. 
Crude oil sales contracts for the Company's North Sea and Offshore
Africa segments are typically based on Dated Brent ("Brent") pricing,
which is representative of international markets and overall world
supply and demand. Brent averaged US$112.07 per bbl for the nine
months ended September 30, 2012 and was comparable with the nine
months ended September 30, 2011. Brent averaged US$109.57 per bbl for
the third quarter of 2012, a decrease of 3% compared with US$113.46
per bbl for the third quarter of 2011 and was comparable with the
second quarter of 2012. The higher Brent pricing relative to WTI was
due to logistical constraints and high inventory levels of crude oil
at Cushing. The differential is expected to narrow with the expansion
of the Seaway pipeline in the first quarter of 2013. 
The WCS Heavy Differential averaged 23% for the nine months ended
September 30, 2012 compared with 20% for the nine months ended
September 30, 2011. The WCS Heavy Differential averaged 24% for the
second and third quarters of 2012 compared with 20% in the third
quarter of 2011. The WCS Heavy Differential widened from the
comparable periods in 2011 as a result of planned and unplanned
maintenance at key refineries accessible by Canadian crude oil. 
The Company uses condensate as a blending diluent for heavy crude oil
pipeline shipments. During the third quarter of 2012, condensate
prices continued to trade at a premium to WTI, similar to prior
periods, 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 economic recovery. The WCS Heavy
Differential is expected to continue to reflect seasonal demand
fluctuations, changes in transportation logistics, and refinery
utilization and shutdowns. 
NYMEX natural gas prices averaged US$2.62 per MMBtu for the nine
months ended September 30, 2012, a decrease of 38% from US$4.23 per
MMBtu for the nine months ended September 30, 2011. NYMEX natural gas
prices averaged US$2.82 per MMBtu for the third quarter of 2012, a
decrease of 33% from US$4.19 per MMBtu for the third quarter of 2011,
and an increase of 25% from US$2.26 per MMBtu for the second quarter
of 2012. 
AECO natural gas prices for the nine months ended September 30, 2012
averaged $2.07 per GJ, a decrease of 42% from $3.55 per GJ for the
nine months ended September 30, 2011. AECO natural gas prices for the
third quarter of 2012 averaged $2.08 per GJ, a decrease of 41% from
$3.53 per GJ for the third quarter of 2011, and an increase of 20%
from $1.74 per GJ for the second quarter of 2012. 
During the third quarter of 2012, natural gas prices continued to be
weak. While Canadian production has declined in response to low
prices, US production has held steady during 2012. The AECO natural
gas price has increased from the second quarter of 2012 as a result
of a shift to higher utilization of gas fired electric generators
supported by the low natural gas prices, and higher weather related
gas demand resulting from warmer than normal summer temperatures. 
DAILY PRODUCTION, before royalties 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
                             Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                               2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
 Exploration and
 Production                 332,895   316,483   304,671   318,384   296,892
North America - Oil Sands
 Mining and Upgrading        99,205   115,823    50,354    87,084    19,365
North Sea                    19,502    17,619    26,350    20,054    31,077
Offshore Africa              17,566    20,598    22,525    19,618    23,105
----------------------------------------------------------------------------
                            469,168   470,523   403,900   445,140   370,439
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America                 1,169     1,230     1,226     1,226     1,223
North Sea                         2         2         5         2         7
Offshore Africa                  20        23        21        20        19
----------------------------------------------------------------------------
                              1,191     1,255     1,252     1,248     1,249
----------------------------------------------------------------------------
Total barrels of oil
 equivalent (BOE/d)         667,616   679,607   612,575   653,220   578,618
----------------------------------------------------------------------------
Product mix
Light and medium crude oil
 and NGLs                        15%       15%       17%       16%       19%
Pelican Lake heavy crude
 oil                              6%        5%        6%        6%        6%
Primary heavy crude oil          19%       18%       17%       19%       18%
Bitumen (thermal oil)            15%       14%       18%       14%       18%
Synthetic crude oil              15%       17%        8%       13%        3%
Natural gas                      30%       31%       34%       32%       36%
----------------------------------------------------------------------------
Percentage of product
 sales (1) (excluding
 midstream revenue)
Crude oil and NGLs               92%       93%       85%       92%       85%
Natural gas                       8%        7%       15%        8%       15%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation and blending costs and excluding risk management
    activities.

 
DAILY PRODUCTION, net of royalties 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                                2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
 Exploration and
 Production                  261,655   272,089   251,909   262,561   243,202
North America - Oil Sands
 Mining and Upgrading         95,704   109,569    48,509    83,004    18,648
North Sea                     19,441    17,578    26,284    20,000    31,000
Offshore Africa               11,662    15,051    18,452    14,726    20,936
----------------------------------------------------------------------------
                             388,462   414,287   345,154   380,291   313,786
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America                  1,159     1,218     1,189     1,218     1,177
North Sea                          2         2         5         2         7
Offshore Africa                   16        19        17        17        16
----------------------------------------------------------------------------
                               1,177     1,239     1,211     1,237     1,200
----------------------------------------------------------------------------
Total barrels of oil
 equivalent (BOE/d)          584,577   620,700   546,861   586,337   513,839
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 nine months ended September 30,
2012 increased 20% to 445,140 bbl/d from 370,439 bbl/d for the nine
months ended September 30, 2011. Crude oil and NGLs production for
the third quarter of 2012 increased 16% to 469,168 bbl/d from 403,900
bbl/d for the third quarter of 2011 and was comparable with the
second quarter of 2012. The increase in production from the
comparable periods in 2011 was primarily related to increased
production at Horizon, the impact of a strong heavy crude oil
drilling program, and the cyclic nature of the Company's thermal
operations. Crude oil and NGLs production in the third quarter of
2012 was within the Company's previously issued guidance of 451,000
to 480,000 bbl/d. 
Natural gas production for the nine months ended September 30, 2012
averaged 1,248 MMcf/d and was comparable with the nine months ended
September 30, 2011. Natural gas production for the third quarter of
2012 decreased by 5% to 1,191 MMcf/d from 1,252 MMcf/d from the third
quarter of 2011 and decreased by 5% from 1,255 MMcf/d for the second
quarter of 2012. The decrease in natural gas production for the third
quarter of 2012 from the comparable periods was primarily a result of
expected production declines due to the allocation of capital to
higher return crude oil projects, which continue to result in a
strategic reduction of natural gas drilling activity. The Company
shut in approximately 20 MMcf/d of natural gas production in 2012 and
overall has shut in approximately 40 MMcf/d due to the decrease in
natural gas prices. Natural gas production in the third quarter of
2012 slightly exceeded the Company's previously issued guidance of
1,170 to 1,190 MMcf/d. 
For 2012, annual production guidance is targeted to average between
452,000 and 460,000 bbl/d of crude oil and NGLs and between 1,222 and
1,229 MMcf/d of natural gas. Fourth quarter 2012 production guidance
is targeted to average between 467,000 and 495,000 bbl/d of crude oil
and NGLs and between 1,145 and 1,165 MMcf/d of natural gas.
North America - Exploration and Production 
North America crude oil and NGLs production for the nine months ended
September 30, 2012 increased 7% to average 318,384 bbl/d from 296,892
bbl/d for the nine months ended September 30, 2011. For the third
quarter of 2012, crude oil and NGLs production increased 9% to
average 332,895 bbl/d compared with 304,671 bbl/d for the third
quarter of 2011 and increased 5% from 316,483 bbl/d for the second
quarter of 2012. Increases in crude oil and NGLs production from
comparable periods were primarily due to the impact of a strong heavy
crude oil drilling program and the cyclic nature of the Company's
thermal operations. Production of crude oil and NGLs was at the upper
end of the Company's previously issued guidance of 322,000 bbl/d to
335,000 bbl/d for the third quarter of 2012. Fourth quarter 2012
production guidance is targeted to average between 350,000 and
365,000 bbl/d of crude oil and NGLs. 
Natural gas production for the nine months ended September 30, 2012
averaged 1,226 MMcf/d and was comparable with the nine months ended
September 30, 2011. Natural gas production decreased 5% to 1,169
MMcf/d for the third quarter of 2012 compared with 1,226 MMcf/d in
the third quarter of 2011 and 1,230 MMcf/d in the second quarter of
2012. Natural gas production for the third quarter of 2012 decreased
from the comparable periods primarily as a result of expected
production declines due to the allocation of capital to higher return
crude oil projects, which continue to result in a strategic reduction
of natural gas drilling activity. The Company has reduced its
drilling activities and shut in approximately 40 MMcf/d of natural
gas production due to the decline in natural gas prices. 
North America - Oil Sands Mining and Upgrading 
Production averaged 87,084 bbl/d for the nine months ended September
30, 2012 compared with 19,365 bbl/d for the nine months ended
September 30, 2011. For the third quarter of 2012, SCO production
averaged 99,205 bbl/d compared with 50,354 bbl/d for the third
quarter of 2011 and 115,823 bbl/d for the second quarter of 2012.
Production for the three and nine months ended September 30, 2012
increased from the comparable periods in 2011 as production volumes
in 2011 reflected the suspension of production due to the coker fire
incident. Third quarter production in 2012 decreased from the second
quarter as the Company operated at restricted rates for a portion of
the third quarter to ensure safe, steady, reliable operations in
anticipation of the proactive planned 12 day outage in the fourth
quarter. Production of SCO remained within the Company's previously
issued guidance of 95,000 to 105,000 bbl/d for the third quarter of
2012. 
Subsequent to September 30, 2012 the Company completed the 12 day
planned maintenance outage followed by a return to full production.
Full year production guidance for 2012 has been revised to 87,000
bbl/d to 89,000 bbl/d. 
North Sea 
North Sea crude oil production for the nine months ended September
30, 2012 decreased 35% to 20,054 bbl/d from 31,077 bbl/d for the nine
months ended September 30, 2011. For the third quarter of 2012, North
Sea crude oil production decreased 26% to 19,502 bbl/d from 26,350
bbl/d for the third quarter of 2011, and increased 11% from 17,619
bbl/d for the second quarter of 2012. The decrease in production
volumes for the three and nine months ended September 30, 2012 from
the comparable periods in 2011 was primarily due to temporary shut
ins of the third-party operated pipeline to Sullom Voe for unplanned
maintenance, which caused all Ninian and associated fields to be shut
in, planned turnaround activity, the suspension of production at
Banff/Kyle, and natural field declines due to curtailment of
development activities in the North Sea as a result of corporate tax
increases that were enacted in 2011. The increase in production
volumes for the third quarter of 2012 from the second quarter of 2012
was due to the temporary reinstatement of the third-party operated
pipeline to Sullom Voe, which was subsequently shut in again in late
September 2012, and the timing of planned turnaround activity. In
December 2011, the Banff Floating Production, Storage and Offloading
Vessel ("FPSO") and subsea infrastructure suffered storm damage.
Operations at Banff/Kyle, with combined net production of
approximately 3,500 bbl/d, were suspended and appropriate shut-down
procedures were activated. The FPSO and associated floating storage
unit have subsequently been removed from the field. The extent of the
damage, including associated costs and related property damage, are
not expected to be significant. The timing of returning to the field
is currently being assessed. 
Offshore Africa 
Offshore Africa crude oil production decreased 15% to 19,618 bbl/d
for the nine months ended September 30, 2012 from 23,105 bbl/d for
the nine months ended September 30, 2011. Third quarter crude oil
production averaged 17,566 bbl/d, decreasing 22% from 22,525 bbl/d
for the third quarter of 2011 and decreasing 15% from 20,598 bbl/d in
the second quarter of 2012. The decrease in production volumes from
the comparable periods was due to natural field declines and the shut
in of approximately 1,500 bbl/d of production at the Olowi field,
Gabon as a result of a second failure in the midwater arch. The
Company is currently assessing the operability of the midwater arch. 
International Guidance 
The Company's North Sea and Offshore Africa third quarter 2012 crude
oil and NGLs production was within the Company's previously issued
guidance of 34,000 to 40,000 bbl/d. Fourth quarter 2012 production
guidance is targeted to average between 32,000 and 38,000 bbl/d of
crude oil. 
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: 


 
                               ---------------------------------------------
                                        Sep 30         Jun 30         Dec 31
(bbl)                                     2012           2012           2011
----------------------------------------------------------------------------
North America - Exploration and
 Production                            656,340        587,765        557,475
North America - Oil Sands
 Mining and Upgrading (SCO)            888,442      1,077,734      1,021,236
North Sea                              150,269              -        286,633
Offshore Africa                      1,058,992        678,540        527,312
----------------------------------------------------------------------------
                                     2,754,043      2,344,039      2,392,656
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                                2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
 (1)
Sales price (2)            $   67.59 $   69.99 $   73.80 $   72.43 $   74.77
Royalties                      12.08      9.18     11.52     11.44     11.19
Production expense             15.79     16.66     16.42     16.40     15.37
----------------------------------------------------------------------------
Netback                    $   39.72 $   44.15 $   45.86 $   44.59 $   48.21
----------------------------------------------------------------------------
Natural gas ($/Mcf) (1)
Sales price (2)            $    2.28 $    1.90 $    3.76 $    2.22 $    3.81
Royalties                       0.05      0.05      0.17      0.05      0.18
Production expense              1.30      1.15      1.15      1.27      1.15
----------------------------------------------------------------------------
Netback                    $    0.93 $    0.70 $    2.44 $    0.90 $    2.48
----------------------------------------------------------------------------
Barrels of oil equivalent
 ($/BOE) (1)
Sales price (2)            $   49.08 $   49.17 $   55.19 $   51.15 $   55.76
Royalties                       7.94      5.93      7.59      7.37      7.43
Production expense             12.97     13.06     12.83     13.15     12.18
----------------------------------------------------------------------------
Netback                    $   28.17 $   30.18 $   34.77 $   30.63 $   36.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                                2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
 (1)(2)
North America              $   63.73 $   65.10 $   67.81 $   67.54 $   69.21
North Sea                  $  106.68 $  108.22 $  109.28 $  111.38 $  108.18
Offshore Africa            $  112.59 $  106.30 $  114.44 $  115.19 $  106.93
Company average            $   67.59 $   69.99 $   73.80 $   72.43 $   74.77
 
Natural gas ($/Mcf) (1)(2)
North America              $    2.15 $    1.73 $    3.67 $    2.09 $    3.73
North Sea                  $    3.65 $    3.98 $    3.26 $    3.93 $    4.05
Offshore Africa            $    9.95 $   10.54 $    9.38 $   10.15 $    8.46
Company average            $    2.28 $    1.90 $    3.76 $    2.22 $    3.81
 
Company average ($/BOE)
 (1)(2)                    $   49.08 $   49.17 $   55.19 $   51.15 $   55.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
    activities.

 
North America 
North America realized crude oil prices decreased 2% to average
$67.54 per bbl for the nine months ended September 30, 2012 from
$69.21 per bbl for the nine months ended September 30, 2011. North
America realized crude oil prices averaged $63.73 per bbl for the
third quarter of 2012, a decrease of 6% compared with $67.81 per bbl
for the third quarter of 2011 and a decrease of 2% compared with
$65.10 per bbl for the second quarter of 2012. The decrease in prices
for the three and nine months ended September 30, 2012 from the
comparable periods in 2011 was primarily a result of the widening of
the WCS Heavy Differential; partially offset by the fluctuations in
the Canadian dollar relative to the US dollar. The Company continues
to focus on its crude oil blending marketing strategy, and in the
third quarter of 2012 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 upgrader and refinery ("the Project") near
Redwater, Alberta. In addition, the partnership has entered into
processing agreements that target to process bitumen for the Company
and the Government of Alberta under a 30 year fee-for-service tolling
agreement under the Bitumen Royalty In Kind initiative. Subsequent to
September 30, 2012, the Project was sanctioned by the Board of
Directors of each partner of the North West Redwater Partnership
("Redwater"), and the associated target toll amounts were agreed to
by Redwater, the Company and the Government of Alberta. 
North America realized natural gas prices decreased 44% to average
$2.09 per Mcf for the nine months ended September 30, 2012 from $3.73
per Mcf for the nine months ended September 30, 2011. North America
realized natural gas prices decreased 41% to average $2.15 per Mcf
for the third quarter of 2012 compared with $3.67 per Mcf in the
third quarter of 2011, and increased 24% compared with $1.73 per Mcf
for the second quarter of 2012. The decrease in natural gas prices
for the three and nine months ended September 30, 2012 from the
comparable periods  in 2011 was primarily due to lower NYMEX and AECO
benchmark pricing related to the impact of strong supply from US
shale projects. The increase in natural gas prices for the third
quarter of 2012 from the second quarter of 2012 was primarily due to
higher NYMEX and AECO benchmark pricing related to a shift to higher
utilization of gas fired electric generators and higher weather
related gas demand resulting from warmer than normal summer
temperatures. 
Comparisons of the prices received in North America Exploration and
Production by product type were as follows: 


 
                               ---------------------------------------------
                                        Sep 30         Jun 30         Sep 30
(Quarterly Average)                       2012           2012           2011
----------------------------------------------------------------------------
Wellhead Price(1) (2)
Light and medium crude oil and
 NGLs ($/bbl)                      $     67.33    $     69.75    $     78.54
Pelican Lake heavy crude oil
 ($/bbl)                           $     63.03    $     63.07    $     66.33
Primary heavy crude oil ($/bbl)    $     61.54    $     63.69    $     65.08
Bitumen (thermal oil) ($/bbl)      $     64.56    $     64.65    $     65.31
Natural gas ($/Mcf)                $      2.15    $      1.73    $      3.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 3% to average $111.38
per bbl for the nine months ended September 30, 2012 from $108.18 per
bbl for the nine months ended September 30, 2011. Realized crude oil
prices averaged $106.68 per bbl for the third quarter of 2012, a
decrease of 2% from $109.28 per bbl for the third quarter of 2011,
and a decrease 1% from $108.22 per bbl for the second quarter of
2012. The fluctuations in realized crude oil prices in the North Sea
from the comparable periods were primarily the result of fluctuations
in Brent benchmark pricing and the Canadian dollar, and the timing of
liftings. 
Offshore Africa 
Offshore Africa realized crude oil prices increased 8% to average
$115.19 per bbl for the nine months ended September 30, 2012 from
$106.93 per bbl for the nine months ended September 30, 2011.
Realized crude oil prices decreased 2% to average $112.59 per bbl for
the third quarter of 2012 from $114.44 per bbl for the third quarter
of 2011, and increased 6% from $106.30 per bbl for the second quarter
of 2012. The fluctuations in realized crude oil prices in Offshore
Africa from the comparable periods were primarily the result of
fluctuations in Brent benchmark pricing and the Canadian dollar, and
the timing of liftings. 
ROYALTIES - EXPLORATION AND PRODUCTION 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                                2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
 (1)
North America              $   11.65 $    8.33 $   11.78 $   11.22 $   12.31
North Sea                  $    0.33 $    0.26 $    0.27 $    0.30 $    0.27
Offshore Africa            $   37.84 $   28.63 $   20.69 $   28.20 $   11.02
Company average            $   12.08 $    9.18 $   11.52 $   11.44 $   11.19
 
Natural gas ($/Mcf) (1)
North America              $    0.02 $    0.02 $    0.15 $    0.02 $    0.17
Offshore Africa            $    1.89 $    1.86 $    1.90 $    1.78 $    1.33
Company average            $    0.05 $    0.05 $    0.17 $    0.05 $    0.18
 
Company average ($/BOE)
 (1)                       $    7.94 $    5.93 $    7.59 $    7.37 $    7.43
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.

 
North America 
North America crude oil and natural gas royalties for the nine months
ended September 30, 2012 compared with the nine months ended
September 30, 2011 reflected benchmark commodity prices. 
Crude oil and NGLs royalties averaged approximately 18% of product
sales for the third quarter of 2012 compared with 17% for the third
quarter of 2011 and 13% for the second quarter of 2012. The increase
in royalties from the second quarter of 2012 was the result of
fluctuating pricing related to production from Oil Sands Royalty
projects. Crude oil and NGLs royalties per bbl are anticipated to
average 16% to 18% of product sales for 2012. 
Natural gas royalties averaged approximately 1% of product sales for
the second and third quarters of 2012 compared with 4% for the third
quarter of 2011. The decrease in natural gas royalty rates from the
third quarter of 2011 was due to lower realized natural gas prices.
Natural gas royalties are anticipated to average 1% to 2% of product
sales for 2012. 
Offshore Africa 
Under the terms of the various Production Sharing Contracts, royalty
rates fluctuate based on realized commodity pricing, capital costs,
the status of payouts, and the timing of liftings from each field. 
Royalty rates as a percentage of product sales averaged approximately
32% for the third quarter of 2012 compared with 18% for the third
quarter of 2011 and 26% for the second quarter of 2012. The increase
in royalty rates from the comparable periods was due to higher crude
oil prices during the year, adjustments to royalties on liftings, and
the payout of the Baobab field in May 2011. 
Offshore Africa royalty rates are anticipated to average 23% to 28%
of product sales for 2012. 
PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                                2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
 (1)
North America              $   12.52 $   13.10 $   13.38 $   13.63 $   12.84
North Sea                  $   60.94 $   68.32 $   49.72 $   53.25 $   37.26
Offshore Africa            $   38.34 $   22.94 $   19.91 $   23.40 $   19.99
Company average            $   15.79 $   16.66 $   16.42 $   16.40 $   15.37
 
Natural gas ($/Mcf) (1)
North America              $    1.28 $    1.13 $    1.13 $    1.25 $    1.13
North Sea                  $    3.44 $    3.89 $    2.68 $    3.78 $    2.64
Offshore Africa            $    2.37 $    1.78 $    2.16 $    1.97 $    1.86
Company average            $    1.30 $    1.15 $    1.15 $    1.27 $    1.15
 
Company average ($/BOE)
 (1)                       $   12.97 $   13.06 $   12.83 $   13.15 $   12.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.

 
North America 
North America crude oil and NGLs production expense for the nine
months ended September 30, 2012 increased 6% to $13.63 per bbl from
$12.84 per bbl for the nine months ended September 30, 2011. North
America crude oil and NGLs production expense for the third quarter
of 2012 decreased 6% to $12.52 per bbl from $13.38 per bbl for the
third quarter of 2011 and decreased 4% from $13.10 per bbl for the
second quarter of 2012. The increase in production expense for the
nine months ended September 30, 2012 from the comparable period in
2011 was a result of higher overall service costs relating to heavy
crude oil production. The decrease in production expense for the
three months ended September 30, 2012 from the comparable period in
2011 was a result of the timing of thermal steam cycles and lower
servicing costs in Pelican and light oil areas. The decrease in
production expense from the second quarter of 2012 was a result of
lower primary heavy oil costs and the timing of thermal steam cycles.
North America crude oil and NGLs production expense is anticipated to
average $12.75 to $13.25 per bbl for 2012. 
North America natural gas production expense for the nine months
ended September 30, 2012 increased 11% to $1.25 per Mcf from $1.13
per Mcf for the nine months ended September 30, 2011. North America
natural gas production expense for the third quarter of 2012
increased 13% to $1.28 per Mcf from $1.13 per Mcf for the comparable
periods. Natural gas production expense for the three and nine months
ended September 30, 2012 increased from the comparable periods in
2011 due to the impact of shut-in production and lower production
volumes related to the curtailment of capital expenditures related to
gas activity. Natural gas production expense increased in the third
quarter of 2012 compared to the second quarter of 2012 due to
seasonal maintenance activity. North America natural gas production
expense is anticipated to average $1.22 to $1.26 per Mcf for 2012. 
North Sea 
North Sea crude oil production expense for the nine months ended
September 30, 2012 increased 43% to $53.25 per bbl from $37.26 per
bbl for the nine months ended September 30, 2011. North Sea crude oil
production expense for the third quarter of 2012 increased 23% to
$60.94 per bbl from $49.72 per bbl for the third quarter of 2011, and
decreased 11% from $68.32 per bbl for the second quarter of 2012.
Production expense increased on a per barrel basis for the three and
nine months ended September 30, 2012 from the comparable periods in
2011 due to the impact of production declines on relatively fixed
costs, temporary shut ins of the third-party operated pipeline to
Sullom Voe, and higher maintenance costs related to turnaround
activity completed during the quarter. Production expense decreased
for the third quarter of 2012 from the second quarter of 2012 due to
higher production volumes on relatively fixed costs. North Sea crude
oil production expense is anticipated to average $52.00 to $53.00 per
bbl for 2012. 
Offshore Africa 
Offshore Africa crude oil production expense increased 17% to $23.40
per bbl from $19.99 per bbl for the nine months ended September 30,
2012. Offshore Africa crude oil production expense for the third
quarter of 2012 averaged $38.34 per bbl, an increase of 93% compared
with $19.91 per bbl for the third quarter of 2011 and an increase of
67% compared with $22.94 per bbl for the second quarter of 2012.
Production expense for the three and nine months ended September 30,
2012 fluctuated from the comparable periods as a result of the timing
of liftings from various fields, which have different cost
structures. Annual Offshore Africa crude oil production expense is
anticipated to average $24.50 to $25.50 per bbl for 2012. 
DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND PRODUCTION 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                                2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Expense ($ millions)       $     931 $     936 $     809 $   2,777 $   2,468
  $/BOE (1)                $   18.00 $   18.13 $   15.96 $   17.96 $   16.29
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.

 
Depletion, depreciation and amortization expense increased for the
nine months ended September 30, 2012 compared with 2011 due to higher
production volumes in North America associated with heavy oil
drilling and the impact of higher future development costs. 
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND PRODUCTION 


 
                              Three Months Ended           Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                                2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Expense ($ millions)       $      30 $      30 $      28 $      89 $      82
  $/BOE (1)                $    0.59 $    0.59 $    0.54 $    0.58 $    0.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 March 13, 2012 the Company successfully and safely completed the
unplanned maintenance on the fractionating unit in the primary
upgrading facility. The positive impact of the third ore preparation
plant ("OPP") and continued emphasis on safe, steady and reliable
operations resulted in production of 99,205 bbl/d of SCO in the third
quarter of 2012, within the Company's previously issued guidance of
95,000 to 105,000 bbl/d of SCO. 
PRODUCT PRICES AND ROYALTIES - OIL SANDS MINING AND UPGRADING 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
($/bbl) (1)                     2012      2012      2011      2012      2011
----------------------------------------------------------------------------
SCO sales price (2)        $   87.40 $   88.11 $   96.19 $   89.39 $   92.45
Bitumen value for royalty
 purposes (3)              $   57.40 $   59.83 $   56.54 $   60.53 $   59.18
Bitumen royalties (4)      $    3.45 $    5.20 $    3.48 $    4.52 $    3.60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes
    excluding the period during suspension of production.
(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.

 
Realized SCO sales prices averaged $89.39 per bbl for the nine months
ended September 30, 2012, a decrease of 3% compared to $92.45 per bbl
for the nine months ended September 30, 2011. Realized SCO sales
prices averaged $87.40 per bbl for the third quarter of 2012, a
decrease of 9% compared with $96.19 per bbl for the third quarter of
2011 and a decrease of 1% compared with $88.11 per bbl for the second
quarter of 2012, reflecting benchmark pricing. 
PRODUCTION COSTS - OIL SANDS MINING AND UPGRADING 
The following tables are reconciled to the Oil Sands Mining and
Upgrading production costs disclosed in the Company's unaudited
interim consolidated financial statements. 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30   Sep 30    Sep 30    Sep 30
($ millions)                    2012      2012     2011      2012      2011
----------------------------------------------------------------------------
Cash production costs      $     398 $     388 $    306  $  1,132  $    783
Less: costs incurred
 during the period of
 suspension of production          -         -     (151)     (154)     (581)
----------------------------------------------------------------------------
Adjusted cash production
 costs                     $     398 $     388 $    155  $    978  $    202
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Adjusted cash production
 costs, excluding natural
 gas costs                 $     373 $     362 $    144  $    912  $    186
Adjusted natural gas costs        25        26       11        66        16
----------------------------------------------------------------------------
Adjusted cash production
 costs                     $     398 $     388 $    155  $    978  $    202
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
($/bbl) (1)                     2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Adjusted cash production
 costs, excluding natural
 gas costs                 $   40.03 $   34.45 $   33.13 $   38.05 $   34.70
Adjusted natural gas costs      2.66      2.53      2.72      2.75      3.02
----------------------------------------------------------------------------
Adjusted cash production
 costs                     $   42.69 $   36.98 $   35.85 $   40.80 $   37.72
----------------------------------------------------------------------------
Sales (bbl/d)                101,263   115,552    47,218    87,569    19,663
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes
    excluding the period during suspension of production.

 
Adjusted cash production costs averaged $40.80 per bbl for the nine
months ended September 30, 2012, an increase of 8% compared with
$37.72 per bbl for the nine months ended September 30, 2011. Adjusted
cash production costs for the third quarter of 2012 averaged $42.69
per bbl, an increase of 15% compared with $36.98 per bbl for the
second quarter of 2012, primarily due to reduced production levels.
Horizon operated at restricted rates for a portion of the third
quarter of 2012 to ensure safe, steady, reliable operations in
anticipation of the 12 day proactive planned maintenance outage in
the fourth quarter of 2012. 
DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND
UPGRADING 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30   Sep 30    Sep 30    Sep 30
($ millions)                    2012      2012     2011      2012      2011
----------------------------------------------------------------------------
Depletion, depreciation
 and amortization          $     124 $     146 $     77  $    333  $    133
Less: depreciation
 incurred during the
 period of suspension of
 production                        -         -      (21)       (6)      (64)
----------------------------------------------------------------------------
Adjusted depletion,
 depreciation and
 amortization              $     124 $     146 $     56  $    327  $     69
----------------------------------------------------------------------------
  $/bbl (1)                $   13.31 $   13.84 $  13.00  $  13.63  $  12.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes
    excluding the period during suspension of production.

 
Depletion, depreciation and amortization expense for the three and
nine months ended September 30, 2012 increased from the comparable
periods in 2011 primarily due to higher sales volumes. 
ASSET RETIREMENT OBLIGATION ACCRETION - OIL SANDS MINING AND
UPGRADING 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
 ($ millions)                   2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Expense                    $       8 $       8 $       5 $      24 $      15
  $/bbl (1)                $    0.85 $    0.76 $    1.14 $    0.99 $    2.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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. 
MIDSTREAM 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
($ millions)                    2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Revenue                    $      24 $      22 $      23 $      67 $      66
Production expense                 7         7         7        21        19
----------------------------------------------------------------------------
Midstream cash flow               17        15        16        46        47
Depreciation                       1         2         1         5         5
----------------------------------------------------------------------------
Segment earnings before
 taxes                     $      16 $      13 $      15 $      41 $      42
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Midstream operating results were consistent with the comparable
periods. 
ADMINISTRATION EXPENSE 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
($ millions)                    2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Expense                    $      64 $      77 $      65 $     206 $     188
  $/BOE (1)                $    1.05 $    1.24 $    1.17 $    1.15 $    1.20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.

 
Administration expense for the nine months ended September 30, 2012
increased from the comparable period primarily due to higher staffing
related costs and general corporate costs. Administration expense for
the third quarter of 2012 decreased from the second quarter of 2012
due to increased overhead recoveries associated with the capital
programs. 
SHARE-BASED COMPENSATION 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
                              Sep 30   Jun 30    Sep 30    Sep 30    Sep 30
($ millions)                    2012     2012      2011      2012      2011
----------------------------------------------------------------------------
Expense (recovery)         $      49 $   (115) $   (249) $   (173) $   (309)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
The Company's stock option plan provides current employees with the
right to receive common shares or a direct cash payment in exchange
for stock options surrendered. 
The Company recorded a $173 million share-based compensation recovery
for the nine months ended September 30, 2012, primarily as a result
of remeasurement of the fair value of outstanding stock options at
the end of the period related to a decrease in the Company's share
price, offset by normal course graded vesting of stock options
granted in prior periods and the impact of vested stock options
exercised or surrendered during the period. For the nine months ended
September 30, 2012, a $9 million recovery was recognized in respect
of capitalized share-based compensation to Oil Sands Mining and
Upgrading (September 30, 2011 - $19 million recovery). 
For the nine months ended September 30, 2012, the Company paid $7
million for stock options surrendered for cash settlement (September
30, 2011 - $12 million). 
INTEREST AND OTHER FINANCING COSTS 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
($ millions, except per      Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
 BOE amounts)                  2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Expense, gross             $    119  $    114  $    113  $    347  $    330
Less: capitalized interest       27        21        16        66        40
----------------------------------------------------------------------------
Expense, net               $     92  $     93  $     97  $    281  $    290
  $/BOE (1)                $   1.51  $   1.50  $   1.75  $   1.57  $   1.85
Average effective interest
 rate                           4.9%      4.8%      4.6%      4.8%      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 nine
months ended September 30, 2012 increased compared with 2011 due to
higher average US dollar debt levels, higher variable interest rates,
and the impact of a weaker Canadian dollar on US dollar denominated
debt; partially offset by lower Canadian dollar denominated debt
levels. Gross interest and other financing costs for the third
quarter of 2012 increased from the second quarter of 2012 due to
higher variable interest rates; partially offset by the impact of a
stronger Canadian dollar on US dollar denominated debt. Capitalized
interest of $66 million for the nine months ended September 30, 2012
related to Horizon Phase 2/3 expansions and the Kirby Project. 
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        Nine Months Ended
                          --------------------------------------------------
                             Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
($ millions)                   2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Crude oil and NGLs
 financial instruments     $     18  $     19  $     26  $     46  $     90
Foreign currency contracts
 and interest rate swaps        119       (80)      (49)      124        (9)
----------------------------------------------------------------------------
Realized loss (gain)       $    137  $    (61) $    (23) $    170  $     81
----------------------------------------------------------------------------
 
Crude oil and NGLs
 financial instruments     $     58  $   (180) $    (71) $    (26) $   (139)
Foreign currency contracts
 and interest rate swaps        (24)       36       (51)      (24)      (47)
----------------------------------------------------------------------------
Unrealized loss (gain)     $     34  $   (144) $   (122) $    (50) $   (186)
----------------------------------------------------------------------------
Net loss (gain)            $    171  $   (205) $   (145) $    120  $   (105)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Complete details related to outstanding derivative financial
instruments at September 30, 2012 are disclosed in note 13 to the
Company's unaudited interim consolidated financial statements. 
The Company recorded a net unrealized gain of $50 million ($41
million after-tax) on its risk management activities for the nine
months ended September 30, 2012, including an unrealized loss of $34
million ($22 million after-tax) for the third quarter of 2012 (June
30, 2012 - unrealized gain of $144 million; $103 million after-tax;
September 30, 2011 - unrealized gain of $122 million; $97 million
after-tax), primarily due to changes in crude oil forward pricing and
the fluctuations of unrealized gains and losses related to crude oil
and foreign currency contracts. 
FOREIGN EXCHANGE 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
                             Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
($ millions)                   2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Net realized loss (gain)   $     21  $     (9) $   (243) $     18  $   (225)
Net unrealized (gain) loss
 (1)                           (136)       71       454      (125)      332
----------------------------------------------------------------------------
Net (gain) loss            $   (115) $     62  $    211  $   (107) $    107
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps.

 
The net realized foreign exchange loss for the nine months ended
September 30, 2012 was primarily due to foreign exchange rate
fluctuations on settlement of working capital items denominated in US
dollars or UK pounds sterling. The net unrealized foreign exchange
gain for the nine months ended September 30, 2012 was primarily
related to the strengthening of the Canadian dollar with respect to
US dollar debt. The net unrealized loss (gain) for each of the
periods presented included the impact of cross currency swaps (three
months ended September 30, 2012 - unrealized loss of $85 million;
June 30, 2012 - unrealized gain of $47 million; September 30, 2011 -
unrealized gain of $150 million; nine months ended September 30, 2012
- unrealized loss of $80 million; September 30, 2011 - unrealized
gain of $84 million). The Canadian dollar ended the third quarter at
US$1.0166 (June 30, 2012 - US$0.9813; September 30, 2011 -
US$0.9626). 
INCOME TAXES 


 
                                Three Months Ended        Nine Months Ended
                           -------------------------------------------------
($ millions, except income    Sep 30    Jun 30   Sep 30    Sep 30    Sep 30
 tax rates)                     2012      2012     2011      2012      2011
----------------------------------------------------------------------------
North America (1)           $     61  $    124 $     26  $    298  $    196
North Sea                         22        19       45        86       161
Offshore Africa                   50        64       46       150        90
PRT (recovery) expense -
 North Sea                       (19)        1       42        13        96
Other taxes                        -         5        6        11        18
----------------------------------------------------------------------------
Current income tax               114       213      165       558       561
----------------------------------------------------------------------------
Deferred income tax expense       23        59      157        34       255
Deferred PRT expense
 (recovery) - North Sea            6         3       (4)        5         8
----------------------------------------------------------------------------
Deferred income tax expense       29        62      153        39       263
----------------------------------------------------------------------------
                                 143       275      318       597       824
Income tax rate and other
 legislative changes             (58)        -        -       (58)     (104)
----------------------------------------------------------------------------
                            $     85  $    275 $    318  $    539  $    720
----------------------------------------------------------------------------
Effective income tax rate
 on adjusted net earnings
 from operations (2)            23.8%    27.1%     25.7%     28.5%     26.2%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Exploration and Production, Midstream, and Oil
    Sands Mining and Upgrading segments.
(2) Excludes the impact of current and deferred PRT expense and other
    current income tax expense.

 
During 2011, the Canadian federal government enacted legislation to
implement several taxation changes. These changes include a
requirement that, beginning in 2012, partnership income must be
included in the taxable income of each corporate partner based on the
tax year of the partner, rather than the fiscal year of the
partnership. The legislation includes a five-year transition
provision and has no impact on net earnings. 
During the first quarter of 2011, the UK government 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. 
During the third quarter of 2012, the UK government enacted
legislation to restrict the combined corporate and supplementary
income tax relief on decommissioning expenditures to 50%. As a result
of the income tax rate change, the Company's deferred income tax
liability was increased by $58 million. 
The Company files income tax returns in the various jurisdictions in
which it operates. These tax returns are subject to periodic
examinations in the normal course by the applicable tax authorities.
The tax returns as prepared may include filing positions that could
be subject to differing interpretations of applicable tax laws and
regulations, which may take several years to resolve. The Company
does not believe the ultimate resolution of these matters will have a
material impact upon the Company's results of operations, financial
position or liquidity. 
For 2012, based on budgeted prices and the current availability of
tax pools, the Company expects to incur current income tax expense of
$440 million to $480 million in Canada and $300 million to $350
million in the North Sea and Offshore Africa. 
NET CAPITAL EXPENDITURES (1) 


 
                                Three Months Ended         Nine Months Ended
                          --------------------------------------------------
                              Sep 30    Jun 30   Sep 30     Sep 30    Sep 30
($ millions)                    2012      2012     2011       2012      2011
----------------------------------------------------------------------------
Exploration and Evaluation
Net expenditures           $      59 $      32 $     85  $     299 $     200
----------------------------------------------------------------------------
Property, Plant and
 Equipment
Net property acquisitions         23         7      127         68       616
Well drilling, completion
 and equipping                   485       352      437      1,336     1,293
Production and related
 facilities                      533       445      415      1,483     1,210
Capitalized interest and
 other (2)                        28        30       28         88        78
----------------------------------------------------------------------------
Net expenditures               1,069       834    1,007      2,975     3,197
----------------------------------------------------------------------------
Total Exploration and
 Production                    1,128       866    1,092      3,274     3,397
----------------------------------------------------------------------------
Oil Sands Mining and
 Upgrading
Horizon Phases 2/3
 construction costs              354       346      126        892       331
Sustaining capital                41        51       52        129       126
Turnaround costs                  11         3        -         16        79
Capitalized interest and
 other (2)                        24         5       (3)        32        15
----------------------------------------------------------------------------
Total Oil Sands Mining and
 Upgrading                       430       405      175      1,069       551
----------------------------------------------------------------------------
Horizon coker rebuild and
 collateral damage costs
 (3)                               -         -       80          -       389
Midstream                          5         4        1         10         5
Abandonments (4)                  48        39       54        163       147
Head office                       10        10        4         25        16
----------------------------------------------------------------------------
Total net capital
 expenditures              $   1,621 $   1,324 $  1,406  $   4,541 $   4,505
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America              $   1,029 $     788 $  1,045  $   3,040 $   3,190
North Sea                         79        66       46        199       156
Offshore Africa                   20        12        1         35        51
Oil Sands Mining and
 Upgrading                       430       405      255      1,069       940
Midstream                          5         4        1         10         5
Abandonments (4)                  48        39       54        163       147
Head office                       10        10        4         25        16
----------------------------------------------------------------------------
Total                      $   1,621 $   1,324 $  1,406  $   4,541 $   4,505
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The net capital expenditures exclude adjustments related to differences
    between carrying amounts and tax values, and other fair value
    adjustments.
(2) Capitalized interest and other includes expenditures related to land
    acquisition and retention, seismic, and other adjustments.
(3) During 2011, the Company recognized $393 million of property damage
    insurance recoveries (see note 7 to the interim consolidated financial
    statements), offsetting the costs incurred related to the coker rebuild
    and collateral damage costs.
(4) 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
areas. 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 owning
associated infrastructure, the Company is able to maximize
utilization of its production facilities, thereby increasing control
over production costs. 
Net capital expenditures for the nine months ended September 30, 2012
were $4,541 million, comparable with $4,505 million for the nine
months ended September 30, 2011. Net capital expenditures for the
third quarter of 2012 were $1,621 million compared with $1,406
million for the third quarter of 2011 and $1,324 million for the
second quarter of 2012. 
Excluding the Horizon coker rebuild and collateral damage costs
incurred in 2011, the increase in capital expenditures for the three
and nine months ended September 30, 2012 from 2011 was primarily due
to the ramp up of Horizon field construction activity, partially
offset by lower net property acquisition costs. The increase in
capital expenditures for the three months ended September 30, 2012
from the second quarter of 2012 was primarily due to an increase in
well drilling and completion activities related to the primary heavy
oil drilling program. 
Drilling Activity (number of wells) 


 
                                Three Months Ended        Nine Months Ended
                          --------------------------------------------------
                             Sep 30    Jun 30    Sep 30    Sep 30    Sep 30
                               2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Net successful natural gas
 wells                            9         4        21        32        56
Net successful crude oil
 wells (1)                      365       266       317       909       773
Dry wells                         6         2        10        14        31
Stratigraphic test /
 service wells                   22         5        25       611       545
----------------------------------------------------------------------------
Total                           402       277       373     1,566     1,405
Success rate (excluding
 stratigraphic test /
 service wells)                  99%       99%       97%       99%       96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes bitumen wells.

 
North America 
North America, excluding Oil Sands Mining and Upgrading, accounted
for approximately 71% of the total capital expenditures for the nine
months ended September 30, 2012 compared with approximately 74% for
the nine months ended September 30, 2011. 
During the third quarter of 2012, the Company targeted 9 net natural
gas wells, including 2 wells in Northeast British Columbia and 7
wells in Northwest Alberta. The Company also targeted 371 net crude
oil wells. The majority of these wells were concentrated in the
Company's Northern Plains region where 267 primary heavy crude oil
wells, 20 Pelican Lake heavy crude oil wells, 1 light crude oil well
and 43 bitumen (thermal oil) wells were drilled. Another 40 wells
targeting light crude oil were drilled outside the Northern Plains
region. 
Overall Primrose thermal production for the third quarter of 2012
averaged approximately 102,000 bbl/d compared with approximately
110,000 bbl/d for the third quarter of 2011 and approximately 94,000
bbl/d for the second quarter of 2012. Production volumes were in line
with expectations due to the cyclic nature of thermal production at
Primrose. As part of the phased expansion of its in situ Oil Sands
assets, the Company is continuing to develop its Primrose thermal
projects. Additional pad drilling was completed and drilled on
budget, with these wells coming on production in 2013. 
The next planned phase of the Company's in situ Oil Sands assets
expansion is the Kirby South Phase 1 Project. As at September 30,
2012, the overall project was 67% complete, drilling was completed on
the fourth of seven pads and first steam is targeted for 2013. The
Company has acquired approximately 49 sections (12,630 hectares) of
additional Oil Sands rights immediately adjacent to the Kirby in situ
Oil Sands expansion project. 
Development of the tertiary recovery conversion projects at Pelican
Lake continued and 20 horizontal wells were drilled during the
quarter. Pelican Lake production averaged approximately 41,000 bbl/d
for the third quarter of 2012 compared with 38,000 bbl/d for the
third quarter of 2011 and 37,000 bbl/d for the second quarter of
2012. 
For the fourth quarter of 2012, the Company's overall planned
drilling activity in North America is expected to be 302 net crude
oil wells, 42 net bitumen wells and 3 net natural gas wells,
excluding stratigraphic and service wells. 
Oil Sands Mining and Upgrading 
Phase 2/3 expansion activity in the third quarter of 2012 was focused
on the field construction of the gas recovery unit, sulphur recovery
unit, butane treatment unit, coker expansion, and extraction trains 3
and 4, along with engineering related to the hydrogen unit, vacuum
distillation unit and distillation recovery unit. 
North Sea 
In December 2011, the Banff FPSO and subsea infrastructure suffered
storm damage. Operations at Banff/Kyle, with combined net production
of approximately 3,500 bbl/d, were suspended. The FPSO and associated
floating storage unit were subsequently removed from the field. All
personnel on board the FPSO were safe and accounted for. The extent
of the damage, including associated costs and related property
damage, are not expected to be significant. The timing of returning
to the field is currently being assessed. 
In March 2011, the UK government 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 of the increase
in the corporate income tax rate, the Company's development
activities in the North Sea were reduced. The Company is continuing
to high grade all North Sea prospects for potential development
opportunities in 2012 and future years. 
In September 2012, the UK government announced the implementation of
the Brownfield Allowance which allows for an agreed allowance related
to property development for certain pre-approved qualifying field
developments. This allowance partially mitigates the impact of
previous tax increases. The Company is currently assessing the impact
of this initiative on its future capital programs. 
Offshore Africa 
During the fourth quarter of 2011, the Company sanctioned an 8 well
drilling program at the Espoir field in Cote d'Ivoire. Preparations
are ongoing, targeting commencement of drilling operations in the
fourth quarter of 2012. At the Olowi field in Gabon, approximately
1,500 bbl/d of production was shut in due to a second failure in the
midwater arch. The Company is currently assessing the operability of
the midwater arch. 
LIQUIDITY AND CAPITAL RESOURCES 


 
                                    ----------------------------------------
                                       Sep 30    Jun 30    Dec 31    Sep 30
($ millions, except ratios)              2012      2012      2011      2011
----------------------------------------------------------------------------
Working capital (deficit) (1)        $ (1,002) $   (732) $   (894) $   (213)
Long-term debt (2) (3)               $  8,416  $  8,522  $  8,571  $  9,327
 
Share capital                        $  3,691  $  3,670  $  3,507  $  3,431
Retained earnings                      20,383    20,193    19,365    18,642
Accumulated other comprehensive
 income                                    46        59        26        71
----------------------------------------------------------------------------
Shareholders' equity                 $ 24,120  $ 23,922  $ 22,898  $ 22,144
 
Debt to book capitalization (3) (4)        26%       26%       27%       30%
Debt to market capitalization (3)
 (5)                                       20%       22%       17%       22%
After-tax return on average common
 shareholders' equity (6)                  10%       12%       12%        7%
After-tax return on average capital
 employed (3) (7)                           8%       10%       10%        6%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
(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.

 
At September 30, 2012, 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 and the Company's ability to renew existing bank credit
facilities and raise new debt is dependent on factors discussed in
the "Risks and Uncertainties" section of the Company's December 31,
2011 annual MD&A. In addition, the Company's ability to renew
existing bank credit facilities and raise new debt is also dependent
upon 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 ongoing hedge policy, the flexibility of its
capital expenditure programs supported by its multi-year financial
plans, its existing bank credit facilities, and its ability to raise
new debt on commercially acceptable terms will provide sufficient
liquidity to sustain its operations in the short, medium and long
term and support its growth strategy. At September 30, 2012, the
Company had $4,261 million of available credit under its bank credit
facilities. 
Over the next 12 months, the Company has maturities of long-term debt
aggregating $1,138 million (US$350 million due October 2012, $400
million due January 2013 and US$400 million due February 2013). It is
the Company's intention to retire this indebtedness utilizing cash
flow from operations generated in excess of capital expenditures and
available bank credit facilities as necessary, while maintaining the
ongoing dividend program. On a pro forma basis, reflecting the
retirement of this indebtedness, the available credit under its bank
credit facilities at September 30, 2012 would amount to $3,123
million. 
During the second quarter of 2012, the $1,500 million revolving
syndicated credit facility was extended to June 2016. Additionally,
the Company issued $500 million of 3.05% medium-term notes due June
2019. Proceeds from the securities issued were used to repay bank
indebtedness and for general corporate purposes. After issuing these
securities, the Company has $2,500 million remaining on its
outstanding $3,000 million base shelf prospectus that allows for the
issue of medium-term notes in Canada, which expires in November 2013.
If issued, these securities will bear interest as determined at the
date of issuance. 
The Company has US$2,000 million remaining on its outstanding
US$3,000 million base shelf prospectus that allows for the issue of
US dollar debt securities in the United States, which expires in
November 2013. If issued, these securities will bear interest as
determined at the date of issuance. Subsequent to September 30, 2012,
US$350 million of US dollar denominated debt securities bearing
interest at 5.45% were repaid. 
Long-term debt was $8,416 million at September 30, 2012, resulting in
a debt to book capitalization ratio of 26% (June 30, 2012 - 26%;
September 30, 2011 - 30%). 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, 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. The Company remains
committed to maintaining a strong balance sheet, adequate available
liquidity and a flexible capital structure. The Company has hedged a
portion of its crude oil production for 2012 and 2013 at prices that
protect investment returns to ensure ongoing balance sheet strength
and the completion of its capital expenditure programs. Further
details related to the Company's long-term debt at September 30, 2012
are discussed in note 5 to the Company's unaudited interim
consolidated financial statements. 
The Company's commodity hedging policy reduces the risk of volatility
in commodity prices and supports the Company's cash flow for its
capital expenditures programs. This policy 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 policy, the purchase of put options is in addition to
the above parameters. As at November 6, 2012, approximately 60% of
currently forecasted fourth quarter 2012 crude oil volumes were
hedged using collars and puts. Further details related to the
Company's commodity related derivative financial instruments
outstanding at September 30, 2012 are discussed in note 13 to the
Company's unaudited interim consolidated financial statements. 
Share Capital 
As at September 30, 2012, there were 1,095,134,000 common shares
outstanding and 66,029,000 stock options outstanding. As at November
5, 2012, the Company had 1,094,484,000 common shares outstanding and
65,435,000 stock options outstanding. 
During the second quarter of 2012, the Company amended its Articles
by special resolution of the Shareholders, changing the designation
of its Class 1 preferred shares to "Preferred Shares" which may be
issuable in series. If issued, the number of shares in each series,
and the designation, rights, privileges, restrictions and conditions
attached to the shares will be determined by the Board of Directors
of the Company. 
On March 6, 2012, the Company's Board of Directors approved an
increase in the annual dividend to be paid by the Company to $0.42
per common share for 2012. The increase represents an approximately
17% increase from 2011, 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. 
In April 2012, 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 twelve
month period commencing April 9, 2012 and ending April 8, 2013, up to
55,027,447 common shares. 
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 twelve month period commencing April 6, 2011 and ending April 5,
2012, up to 27,406,131 common shares of the Company. 
As at September 30, 2012, 6,876,200 common shares (June 30, 2012 -
4,621,600 common shares; March 31, 2012 - 692,200 common shares) had
been purchased for cancellation at a weighted average price of $29.10
per common share (June 30, 2012 - $29.63 per common share; March 31,
2012 - $33.11 per common share), for a total cost of $200 million
(June 30, 2012 - $137 million; March 31, 2012 - $23 million).
Subsequent to September 30, 2012, the Company purchased 949,000
common shares at a weighted average price of $30.18 per common share
for a total cost of $29 million. 
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS 
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's future
operations. As at September 30, 2012, no entities were consolidated
under the Standing Interpretations Committee ("SIC") 12,
"Consolidation - Special Purpose Entities". The following table
summarizes the Company's commitments as at September 30, 2012: 


 
                        Remaining
($ millions)                 2012    2013    2014    2015    2016 Thereafter
----------------------------------------------------------------------------
Product transportation
 and pipeline            $     58 $   213 $   204 $   192 $   126  $     889
Offshore equipment
 operating leases and
 offshore drilling       $     43 $   153 $   120 $   103 $    75  $     121
Long-term debt (1)       $    344 $   794 $   836 $   437 $   589  $   5,468
Interest and other
 financing costs (2)     $    103 $   397 $   377 $   343 $   329  $   3,997
Office leases            $      8 $    32 $    35 $    33 $    34  $     309
Other                    $     76 $   169 $    95 $    42 $    10  $       8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 September 30,
    2012.

 
In addition to the commitments disclosed above, the Company has
entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These
contracts can be cancelled by the Company upon notice without
penalty, subject to the costs incurred up to and in respect of the
cancellation. 
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES 
The Company is a 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. 
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED 
For the impact of new accounting standards, refer to the MD&A and the
audited consolidated financial statements for the year ended December
31, 2011. 
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING POLICIES 
The preparation of financial statements requires the Company to make
estimates, assumptions and judgements in the application of IFRS that
have a significant impact on the financial results of the Company.
Actual results could differ from estimated amounts, and those
differences may be material. A comprehensive discussion of the
Company's significant accounting policies is contained in the MD&A
and the audited consolidated financial statements for the year ended
December 31, 2011. 
Consolidated Balance Sheets 


 
                                              ------------------------------
As at
(millions of Canadian dollars,                         Sep 30        Dec 31
 unaudited)                               Note           2012           2011
----------------------------------------------------------------------------
ASSETS
Current assets
 Cash and cash equivalents                        $        21    $        34
 Accounts receivable                                    1,365          2,077
 Inventory                                                570            550
 Prepaids and other                                       191            120
----------------------------------------------------------------------------
                                                        2,147          2,781
Exploration and evaluation assets            2          2,660          2,475
Property, plant and equipment                3         42,724         41,631
Other long-term assets                       4            338            391
----------------------------------------------------------------------------
                                                  $    47,869    $    47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
LIABILITIES
Current liabilities
 Accounts payable                                 $       525    $       526
 Accrued liabilities                                    2,218          2,347
 Current income tax liabilities                           232            347
 Current portion of long-term debt           5          1,138            359
 Current portion of other long-term
  liabilities                                6            174            455
----------------------------------------------------------------------------
                                                        4,287          4,034
Long-term debt                               5          7,278          8,212
Other long-term liabilities                  6          3,954          3,913
Deferred income tax liabilities                         8,230          8,221
----------------------------------------------------------------------------
                                                       23,749         24,380
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital                                9          3,691          3,507
Retained earnings                                      20,383         19,365
Accumulated other comprehensive income      10             46             26
----------------------------------------------------------------------------
                                                       24,120         22,898
----------------------------------------------------------------------------
                                                  $    47,869    $    47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments and contingencies (note 14).

 
Approved by the Board of Directors on November 6, 2012 
Consolidated Statements of Earnings 


 
                                     Three Months Ended    Nine Months Ended
                                    ----------------------------------------
(millions of Canadian dollars,
 except per common share               Sep 30    Sep 30    Sep 30    Sep 30
 amounts, unaudited)            Note     2012      2011      2012      2011
----------------------------------------------------------------------------
Product sales                        $  3,978  $  3,690  $ 12,136  $ 10,719
Less: royalties                          (442)     (400)   (1,247)   (1,145)
----------------------------------------------------------------------------
Revenue                                 3,536     3,290    10,889     9,574
----------------------------------------------------------------------------
Expenses
Production                              1,071       959     3,177     2,637
Transportation and blending               606       459     2,014     1,745
Depletion, depreciation and
 amortization                      3    1,056       887     3,115     2,606
Administration                             64        65       206       188
Share-based compensation           6       49      (249)     (173)     (309)
Asset retirement obligation
 accretion                         6       38        33       113        97
Interest and other financing
 costs                                     92        97       281       290
Risk management activities        13      171      (145)      120      (105)
Foreign exchange (gain) loss             (115)      211      (107)      107
Horizon asset impairment
 provision                         7        -         -         -       396
Insurance recovery - property
 damage                            7        -         -         -      (396)
Insurance recovery - business
 interruption                      7        -      (181)        -      (317)
Equity loss from jointly
 controlled entity                 4        1         -         6         -
----------------------------------------------------------------------------
                                        3,033     2,136     8,752     6,939
----------------------------------------------------------------------------
Earnings before taxes                     503     1,154     2,137     2,635
Current income tax expense         8      114       165       558       561
Deferred income tax expense        8       29       153        39       263
----------------------------------------------------------------------------
Net earnings                         $    360  $    836  $  1,540  $  1,811
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common share
  Basic                           12 $   0.33  $   0.76  $   1.40  $   1.65
  Diluted                         12 $   0.33  $   0.76  $   1.40  $   1.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Consolidated Statements of Comprehensive Income 


 
                                     Three Months Ended   Nine Months Ended
                                    ----------------------------------------
(millions of Canadian dollars,         Sep 30    Sep 30    Sep 30    Sep 30
 unaudited)                              2012      2011      2012      2011
----------------------------------------------------------------------------
Net earnings                         $    360  $    836  $  1,540  $  1,811
----------------------------------------------------------------------------
Net change in derivative financial
 instruments designated as cash flow
 hedges
Unrealized (loss) income during the
 period, net of taxes of
  $3 million (2011 - $6 million) -
   three months ended;
  $2 million (2011 - $5 million) -
   nine months ended                      (20)       46        14        44
Reclassification to net earnings,
 net of taxes of
  $nil (2011 - $4 million) - three
   months ended;
  $nil (2011 - $13 million) - nine
   months ended                            (3)       12        (4)       41
----------------------------------------------------------------------------
                                          (23)       58        10        85
Foreign currency translation
 adjustment
Translation of net investment              10       (25)       10       (23)
----------------------------------------------------------------------------
Other comprehensive (loss) income,
 net of taxes                             (13)       33        20        62
----------------------------------------------------------------------------
Comprehensive income                 $    347  $    869  $  1,560  $  1,873
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Consolidated Statements of Changes in Equity 


 
                                                   Nine Months Ended
                                            --------------------------------
(millions of Canadian dollars,                       Sep 30          Sep 30
 unaudited)                             Note           2012            2011
----------------------------------------------------------------------------
Share capital                              9
Balance - beginning of period                   $     3,507     $     3,147
Issued upon exercise of stock options                   164             192
Previously recognized liability on stock
 options exercised for common shares                     43             100
Purchase of common shares under Normal
 Course Issuer Bid                                      (23)             (8)
----------------------------------------------------------------------------
Balance - end of period                               3,691           3,431
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period                        19,365          17,212
Net earnings                                          1,540           1,811
Purchase of common shares under Normal
 Course Issuer Bid                         9           (177)            (84)
Dividends on common shares                 9           (345)           (297)
----------------------------------------------------------------------------
Balance - end of period                              20,383          18,642
----------------------------------------------------------------------------
Accumulated other comprehensive income    10
Balance - beginning of period                            26               9
Other comprehensive income, net of taxes                 20              62
----------------------------------------------------------------------------
Balance - end of period                                  46              71
----------------------------------------------------------------------------
Shareholders' equity                            $    24,120     $    22,144
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Consolidated Statements of Cash Flows 


 
                                     Three Months Ended   Nine Months Ended
                                    ----------------------------------------
(millions of Canadian dollars,         Sep 30    Sep 30    Sep 30    Sep 30
 unaudited)                     Note     2012      2011      2012      2011
----------------------------------------------------------------------------
Operating activities
Net earnings                         $    360  $    836  $  1,540  $  1,811
Non-cash items
 Depletion, depreciation and
  amortization                          1,056       887     3,115     2,606
 Share-based compensation                  49      (249)     (173)     (309)
 Asset retirement obligation
  accretion                                38        33       113        97
 Unrealized risk management loss
  (gain)                                   34      (122)      (50)     (186)
 Unrealized foreign exchange
  (gain) loss                            (136)      454      (125)      332
 Realized foreign exchange gain
  on repayment of US dollar debt
  securities                                -      (225)        -      (225)
 Equity loss from jointly
  controlled entity                4        1         -         6         -
 Deferred income tax expense               29       153        39       263
 Horizon asset impairment
  provision                        7        -         -         -       396
Insurance recovery - property
 damage                            7        -         -         -      (396)
Other                                       7         9        47        (9)
Abandonment expenditures                  (48)      (54)     (163)     (147)
Net change in non-cash working
 capital                                  132      (469)      245      (303)
----------------------------------------------------------------------------
                                        1,522     1,253     4,594     3,930
----------------------------------------------------------------------------
Financing activities
Issue (repayment) of bank credit
 facilities, net                          139       652      (420)      985
Repayment of US dollar debt
 securities                                 -      (390)        -      (390)
Issue of medium-term notes, net             -         -       498         -
Issue of common shares on
 exercise of stock options                 24        11       164       192
Purchase of common shares under
 Normal Course Issuer Bid                 (63)      (92)     (200)      (92)
Dividends on common shares               (115)      (99)     (329)     (279)
Net change in non-cash working
 capital                                  (13)       (5)      (29)      (10)
----------------------------------------------------------------------------
                                          (28)       77      (316)      406
----------------------------------------------------------------------------
Investing activities
Expenditures on exploration and
 evaluation assets and property,
 plant and equipment                   (1,573)   (1,352)   (4,378)   (4,358)
Investment in other long-term
 assets                                     -         -         2      (346)
Net change in non-cash working
 capital                                   90        34        85       364
----------------------------------------------------------------------------
                                       (1,483)   (1,318)   (4,291)   (4,340)
----------------------------------------------------------------------------
Increase (decrease) in cash and
 cash equivalents                          11        12       (13)       (4)
Cash and cash equivalents -
 beginning of period                       10         6        34        22
----------------------------------------------------------------------------
Cash and cash equivalents - end
 of period                           $     21  $     18  $     21  $     18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid                        $    134  $    151  $    360  $    376
Income taxes paid                    $     99  $    141  $    534  $    516
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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. 
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. 
These interim consolidated financial statements have been prepared in
accordance with International Financial Reporting Standards ("IFRS")
as issued by the International Accounting Standards Board, applicable
to the preparation of interim financial statements, including
International Accounting Standard ("IAS") 34, "Interim Financial
Reporting", following the same accounting policies as the audited
consolidated financial statements of the Company as at December 31,
2011. These interim consolidated financial statements contain
disclosures that are supplemental to the Company's annual audited
consolidated financial statements. Certain disclosures that are
normally required to be included in the notes to the annual audited
consolidated financial statements have been condensed. These interim
consolidated financial statements should be read in conjunction with
the Company's audited consolidated financial statements and notes
thereto for the year ended December 31, 2011. 
2. EXPLORATION AND EVALUATION ASSETS 


 
                                                         Oil Sands
                                                            Mining
                                                               and
                             Exploration and Production  Upgrading    Total
----------------------------------------------------------------------------
                             North             Offshore
                           America  North Sea    Africa
----------------------------------------------------------------------------
Cost
At December 31, 2011      $  2,442   $      -  $     33   $      - $  2,475
Additions                      294          -         5          -      299
Transfers to property,
 plant and equipment          (114)         -         -          -     (114)
----------------------------------------------------------------------------
At September 30, 2012     $  2,622   $      -  $     38   $      - $  2,660
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
3. PROPERTY, PLANT AND EQUIPMENT 


 
                                                                  Oil Sands
                                                                     Mining
                                                                        and
                                      Exploration and Production  Upgrading
----------------------------------------------------------------------------
                                     North              Offshore
                                   America  North Sea     Africa
----------------------------------------------------------------------------
Cost
At December 31, 2011              $ 46,120   $  4,147   $  3,044   $ 15,211
Additions                            2,787        205         32      1,108
Transfers from E&E assets              114          -          -          -
Disposals/ derecognitions              (84)       (39)        (8)        (5)
Foreign exchange adjustments and
 other                                   -       (139)      (101)         -
----------------------------------------------------------------------------
At September 30, 2012             $ 48,937   $  4,174   $  2,967   $ 16,314
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and depreciation
At December 31, 2011              $ 21,721   $  2,512   $  2,152   $    776
Expense                              2,438        220        107        333
Disposals/ derecognitions              (84)       (39)        (6)        (5)
Foreign exchange adjustments and
 other                                   -        (86)       (62)       (21)
----------------------------------------------------------------------------
At September 30, 2012             $ 24,075   $  2,607   $  2,191   $  1,083
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value
- at September 30, 2012           $ 24,862   $  1,567   $    776   $ 15,231
- at December 31, 2011            $ 24,399   $  1,635   $    892   $ 14,435
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                     Midstream    Head Office         Total
----------------------------------------------------------------------------
 
----------------------------------------------------------------------------
Cost
At December 31, 2011               $       298    $       234    $   69,054
Additions                                   10             25         4,167
Transfers from E&E assets                    -              -           114
Disposals/ derecognitions                    -              -          (136)
Foreign exchange adjustments and
 other                                       -              -          (240)
----------------------------------------------------------------------------
At September 30, 2012              $       308    $       259    $   72,959
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and
 depreciation
At December 31, 2011               $        96    $       166    $   27,423
Expense                                      5             12         3,115
Disposals/ derecognitions                    -              -          (134)
Foreign exchange adjustments and
 other                                       -              -          (169)
----------------------------------------------------------------------------
At September 30, 2012              $       101    $       178    $   30,235
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value
- at September 30, 2012            $       207    $        81    $   42,724
- at December 31, 2011             $       202    $        68    $   41,631
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Development projects not subject to depletion
----------------------------------------------------------------------------
At September 30, 2012                                            $     1,669
At December 31, 2011                                             $     1,443
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
The Company acquired a number of producing crude oil and natural gas
assets in the North America Exploration and Production segment for
total cash consideration of $67 million during the nine months ended
September 30, 2012 (year ended December 31, 2011 - $1,012 million),
net of associated asset retirement obligations of $4 million (year
ended December 31, 2011 - $79 million). Interests in jointly
controlled assets were acquired with full tax basis. No working
capital or debt obligations were assumed. 
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 nine months ended
September 30, 2012, pre-tax interest of $66 million was capitalized
to property, plant and equipment (September 30, 2011 - $40 million)
using a capitalization rate of 4.8% (September 30, 2011 - 4.7%). 
4. OTHER LONG-TERM ASSETS 


 
                                              ------------------------------
                                                       Sep 30         Dec 31
                                                         2012           2011
----------------------------------------------------------------------------
Investment in North West Redwater Partnership     $       313    $       321
Other                                                      25             70
----------------------------------------------------------------------------
                                                  $       338    $       391
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Other long-term assets include an investment in the 50% owned North
West Redwater Partnership ("Redwater"). The investment is accounted
for using the equity method. Redwater has committed to construct and
operate a bitumen upgrader and refinery (the "Project") under
processing agreements that target to process bitumen for the Company
and the Government of Alberta under a 30 year fee-for-service tolling
agreement. Subsequent to September 30, 2012, the Project was
sanctioned by the Board of Directors of each partner of Redwater, and
the associated target toll amounts were agreed to by Redwater, the
Company and the Government of Alberta. 
5. LONG-TERM DEBT 


 
                                              ------------------------------
                                                      Sep 30         Dec 31
                                                        2012           2011
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities                            $      380     $      796
Medium-term notes                                      1,300            800
----------------------------------------------------------------------------
                                                       1,680          1,596
----------------------------------------------------------------------------
US dollar denominated debt
US dollar debt securities (US$6,900 million)           6,788          7,017
Less: original issue discount on US dollar
 debt securities (1)                                     (21)           (21)
----------------------------------------------------------------------------
                                                       6,767          6,996
Fair value impact of interest rate swaps on US
 dollar debt securities (2)                               21             31
----------------------------------------------------------------------------
                                                       6,788          7,027
----------------------------------------------------------------------------
Long-term debt before transaction costs                8,468          8,623
Less: transaction costs (1) (3)                          (52)           (52)
----------------------------------------------------------------------------
                                                       8,416          8,571
Less: current portion (1) (2) (4)                      1,138            359
----------------------------------------------------------------------------
                                                  $    7,278     $    8,212
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $21
    million (December 31, 2011 - $31 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 September 30, 2012, US$350 million of US dollar
    denominated debt securities bearing interest at 5.45% were repaid.

 
Bank Credit Facilities 
As at September 30, 2012, the Company had in place unsecured bank
credit facilities of $4,724 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 2016; and 
- a GBP 15 million demand credit facility related to the Company's
North Sea operations. 
During the second quarter of 2012, the $1,500 million revolving
syndicated credit facility was extended to June 2016. 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 may be made by way of pricing
referenced to Canadian dollar or US dollar bankers' acceptances, or
LIBOR, US base rate or Canadian prime loans. 
The Company's weighted average interest rate on bank credit
facilities outstanding as at September 30, 2012, was 2.0% (September
30, 2011 - 2.3%), and on long-term debt outstanding for the nine
months ended September 30, 2012 was 4.8% (September 30, 2011 - 4.7%). 
In addition to the outstanding debt, letters of credit and financial
guarantees aggregating $561 million, including $95 million related to
Horizon and $271 million related to North Sea operations, were
outstanding at September 30, 2012. During the third quarter of 2012,
the Company issued a financial guarantee for $100 million supporting
a revolving credit facility in the 50% owned North West Redwater
Partnership. 
Subsequent to September 30, 2012, the financial guarantee related to
Horizon was reduced to $87 million and the financial guarantee
related to Redwater was increased by $25 million to $125 million. 
Medium-Term Notes 
During the second quarter of 2012, the Company issued $500 million of
3.05% medium-term unsecured notes due June 2019. After issuing these
securities, the Company has $2,500 million remaining on its
outstanding $3,000 million base shelf prospectus that allows for the
issue of medium-term notes in Canada, which expires in November 2013.
If issued, these securities will bear interest as determined at the
date of issuance. 
US Dollar Debt Securities 
The Company has US$2,000 million remaining on its outstanding
US$3,000 million base shelf prospectus that allows for the issue of
US dollar debt securities in the United States, which expires in
November 2013. If issued, these securities will bear interest as
determined at the date of issuance. 
6. OTHER LONG-TERM LIABILITIES 


 
                                              ------------------------------
                                                       Sep 30         Dec 31
                                                         2012           2011
----------------------------------------------------------------------------
Asset retirement obligations                      $     3,544    $     3,577
Share-based compensation                                  200            432
Risk management (note 13)                                 292            274
Other                                                      92             85
----------------------------------------------------------------------------
                                                        4,128          4,368
Less: current portion                                     174            455
----------------------------------------------------------------------------
                                                  $     3,954    $     3,913
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Asset retirement obligations 
The Company's asset retirement obligations are expected to be settled
on an ongoing basis over a period of approximately 60 years and have
been discounted using a weighted average discount rate of 4.6%
(December 31, 2011 - 4.6%). A reconciliation of the discounted asset
retirement obligations is as follows: 


 
                                              ------------------------------
                                                      Sep 30         Dec 31
                                                        2012           2011
----------------------------------------------------------------------------
Balance - beginning of period                     $    3,577     $    2,624
 Liabilities incurred                                     37             12
 Liabilities acquired                                      4             79
 Liabilities settled                                    (163)          (213)
 Asset retirement obligation accretion                   113            130
 Revision of estimates                                     5            924
 Foreign exchange                                        (29)            21
----------------------------------------------------------------------------
Balance - end of period                           $    3,544     $    3,577
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Share-based compensation 
As the Company's Option Plan provides current employees with the
right to elect to receive common shares or a cash payment in exchange
for stock 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 stock options are surrendered for cash settlement. 


 
                                              ------------------------------
                                                      Sep 30         Dec 31
                                                        2012           2011
----------------------------------------------------------------------------
Balance - beginning of period                     $      432     $      663
 Share-based compensation recovery                      (173)          (102)
 Cash payment for stock options surrendered               (7)           (14)
 Transferred to common shares                            (43)          (115)
 Capitalized to (recovered from) Oil Sands
  Mining and Upgrading                                    (9)             -
----------------------------------------------------------------------------
Balance - end of period                                  200            432
Less: current portion                                    143            384
----------------------------------------------------------------------------
                                                  $       57     $       48
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
7. HORIZON ASSET IMPAIRMENT PROVISION AND INSURANCE RECOVERY 
In 2011, the Company recognized an asset impairment provision in the
Oil Sands Mining and Upgrading segment of $396 million, net of
accumulated depletion and amortization, related to the property
damage resulting from a fire in the Horizon primary upgrading coking
plant. The Company also recorded final property damage insurance
recoveries of $393 million and business interruption insurance
recoveries of $333 million in 2011. In the first quarter of 2012,
upon final settlement of its insurance claims, all outstanding
insurance proceeds were collected. 
8. INCOME TAXES 
The provision for income tax is as follows: 


 
                                     Three Months Ended    Nine Months Ended
                                    ----------------------------------------
                                       Sep 30    Sep 30     Sep 30    Sep 30
                                         2012      2011       2012      2011
----------------------------------------------------------------------------
Current corporate income tax - North
 America                             $     61  $     26  $     298 $     196
Current corporate income tax - North
 Sea                                       22        45         86       161
Current corporate income tax -
 Offshore Africa                           50        46        150        90
Current PRT (1) (recovery) expense -
 North Sea                                (19)       42         13        96
Other taxes                                 -         6         11        18
----------------------------------------------------------------------------
Current income tax expense                114       165        558       561
----------------------------------------------------------------------------
Deferred corporate income tax
 expense                                   23       157         34       255
Deferred PRT (1) expense (recovery)
 - North Sea                                6        (4)         5         8
----------------------------------------------------------------------------
Deferred income tax expense                29       153         39       263
----------------------------------------------------------------------------
Income tax expense                   $    143  $    318  $     597 $     824
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Petroleum Revenue Tax.

 
During 2011, the Canadian federal government enacted legislation to
implement several taxation changes. These changes include a
requirement that, beginning in 2012, partnership income must be
included in the taxable income of each corporate partner based on the
tax year of the partner, rather than the fiscal year of the
partnership. The legislation includes a five-year transition
provision and has no impact on net earnings. 
During the first quarter of 2011, the UK government 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. 
During the third quarter of 2012, the UK government enacted
legislation to restrict the combined corporate and supplementary
income tax relief on decommissioning expenditures to 50%. As a result
of the income tax rate change, the Company's deferred income tax
liability was increased by $58 million. 
9. SHARE CAPITAL 
Authorized 
Preferred shares issuable in a series. 
Unlimited number of common shares without par value. 


 
                                             -------------------------------
                                             Nine Months Ended Sep 30, 2012
                                                   Number of
                                                      shares
Issued common shares                              (thousands)        Amount
----------------------------------------------------------------------------
Balance - beginning of period                      1,096,460     $    3,507
Issued upon exercise of stock options                  5,550            164
Previously recognized liability on stock
 options exercised for common shares                       -             43
Purchase of common shares under Normal Course
 Issuer Bid                                           (6,876)           (23)
----------------------------------------------------------------------------
Balance - end of period                            1,095,134     $    3,691
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Preferred Shares 
During the second quarter of 2012, the Company amended its Articles
by special resolution of the Shareholders, changing the designation
of its Class 1 preferred shares to "Preferred Shares" which may be
issuable in series. If issued, the number of shares in each series,
and the designation, rights, privileges, restrictions and conditions
attached to the shares will be determined by the Board of Directors
of the Company. 
Dividend Policy 
On March 6, 2012, the Board of Directors set the regular quarterly
dividend at $0.105 per common share (2011 - $0.09 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 
The Company's Normal Course Issuer Bid announced in 2011 expired
April 5, 2012. In April 2012, 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 9, 2012 and ending April 8, 2013, up to
55,027,447 common shares. 
For the nine months ended September 30, 2012, the Company purchased
6,876,200 common shares at a weighted average price of $29.10 per
common share, for a total cost of $200 million. Retained earnings
were reduced by $177 million, representing the excess of the purchase
price of common shares over their average carrying value. Subsequent
to September 30, 2012, the Company purchased 949,000 common shares at
a weighted average price of $30.18 per common share for a total cost
of $29 million. 
Stock Options 
The following table summarizes information relating to stock options
outstanding at September 30, 2012: 


 
                                            --------------------------------
                                              Nine Months Ended Sep 30, 2012
----------------------------------------------------------------------------
                                                                    Weighted
                                              Stock options          average
                                                 (thousands)  exercise price
----------------------------------------------------------------------------
Outstanding - beginning of period                    73,486      $     34.85
Granted                                               4,949      $     31.80
Surrendered for cash settlement                        (853)     $     30.17
Exercised for common shares                          (5,550)     $     29.52
Forfeited                                            (6,003)     $     36.92
----------------------------------------------------------------------------
Outstanding - end of period                          66,029      $     34.94
----------------------------------------------------------------------------
Exercisable - end of period                          21,090      $     32.93
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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. 
10. ACCUMULATED OTHER COMPREHENSIVE INCOME 
The components of accumulated other comprehensive income, net of
taxes, were as follows: 


 
                                              ------------------------------
                                                      Sep 30         Sep 30
                                                        2012           2011
----------------------------------------------------------------------------
Derivative financial instruments designated as
 cash flow hedges                                 $       72     $      118
Foreign currency translation adjustment                  (26)           (47)
----------------------------------------------------------------------------
                                                  $       46     $       71
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
11. 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 at 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 September 30, 2012,
the ratio was below the target range at 26%. 
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. 


 
                                            --------------------------------
                                                     Sep 30          Dec 31
                                                       2012            2011
----------------------------------------------------------------------------
Long-term debt (1)                              $     8,416     $     8,571
Total shareholders' equity                      $    24,120     $    22,898
Debt to book capitalization                              26%             27%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.

 
12. NET EARNINGS PER COMMON SHARE 


 
                                  Three Months Ended       Nine Months Ended
                            ------------------------------------------------
                                  Sep 30      Sep 30      Sep 30      Sep 30
                                    2012        2011        2012        2011
----------------------------------------------------------------------------
Weighted average common
 shares outstanding - basic
 (thousands of shares)         1,095,267   1,096,750   1,098,145   1,095,753
Effect of dilutive stock
 options (thousands of
 shares)                           1,856       4,673       2,725       8,103
----------------------------------------------------------------------------
Weighted average common
 shares outstanding -
 diluted (thousands of
 shares)                       1,097,123   1,101,423   1,100,870   1,103,856
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings                 $       360 $       836 $     1,540 $     1,811
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
 share
 - basic                     $      0.33 $      0.76 $      1.40 $      1.65
 - diluted                   $      0.33 $      0.76 $      1.40 $      1.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
13. FINANCIAL INSTRUMENTS 
The carrying amounts of the Company's financial instruments by
category were as follows: 


 
                  ----------------------------------------------------------
                                         Sep 30, 2012
----------------------------------------------------------------------------
                                    Fair
                     Loans and     value                 Financial
                   receivables   through  Derivatives  liabilities
                  at amortized profit or     used for at amortized
Asset (liability)         cost      loss      hedging         cost    Total
----------------------------------------------------------------------------
Accounts
 receivable        $     1,365 $       - $         -  $         -  $  1,365
Accounts payable             -         -           -         (525)     (525)
Accrued
 liabilities                 -         -           -       (2,218)   (2,218)
Other long-term
 liabilities                 -        12        (304)         (85)     (377)
Long-term debt (1)           -         -           -       (8,416)   (8,416)
----------------------------------------------------------------------------
                   $     1,365 $      12 $      (304) $   (11,244) $(10,171)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                         Dec 31, 2011
----------------------------------------------------------------------------
 
                                    Fair
                     Loans and     value                 Financial
                   receivables   through  Derivatives  liabilities
                  at amortized profit or     used for at amortized
Asset (liability)         cost      loss      hedging         cost    Total
----------------------------------------------------------------------------
Accounts
 receivable        $     2,077 $       -  $         -  $        -  $  2,077
Accounts payable             -         -            -        (526)     (526)
Accrued
 liabilities                 -         -            -      (2,347)   (2,347)
Other long-term
 liabilities                 -       (38)        (236)        (75)     (349)
Long-term debt (1)           -         -            -      (8,571)   (8,571)
----------------------------------------------------------------------------
                   $     2,077 $     (38) $      (236) $  (11,519) $ (9,716)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 other long-term
liabilities and fixed rate long-term debt are outlined below: 


 
                         ---------------------------------------------------
                                            Sep 30, 2012
----------------------------------------------------------------------------
                                 Carrying
                                   amount              Fair value
----------------------------------------------------------------------------
Asset (liability) (1)                              Level 1          Level 2
----------------------------------------------------------------------------
Other long-term
 liabilities              $          (292) $             -  $          (292)
Fixed rate long-term debt
 (2) (3) (4)                       (8,036)          (9,466)               -
----------------------------------------------------------------------------
                          $        (8,328) $        (9,466) $          (292)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                            Dec 31, 2011
----------------------------------------------------------------------------
                                 Carrying
                                   amount              Fair value
----------------------------------------------------------------------------
Asset (liability) (1)                              Level 1          Level 2
----------------------------------------------------------------------------
Other long-term
 liabilities              $          (274) $             -  $          (274)
Fixed rate long-term debt
 (2) (3) (4)                       (7,775)          (9,120)               -
----------------------------------------------------------------------------
                          $        (8,049) $        (9,120) $          (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $21 million (December 31, 2011 - $31 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. 


 
                                          ----------------------------------
Asset (liability)                             Sep 30, 2012     Dec 31, 2011
----------------------------------------------------------------------------
Derivatives held for trading
  Crude oil price collars                  $            26  $           (13)
  Crude oil put options, net of put
   premium financing obligations                       (13)               -
  Foreign currency forward contracts                    (1)             (25)
Cash flow hedges
  Cross currency swaps                                (304)            (236)
----------------------------------------------------------------------------
                                           $          (292) $          (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Included within:
  Current portion of other long-term
   liabilities                             $            (7) $           (43)
  Other long-term liabilities                         (285)            (231)
----------------------------------------------------------------------------
                                           $          (292) $          (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Ineffectiveness arising from cash flow hedges recognized in net
earnings for the nine months ended September 30, 2012 resulted in no
gain or loss (December 31, 2011 - loss of $2 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
and/or third party indications. Fair values determined using
valuation models require the use of assumptions concerning the amount
and timing of future cash flows and discount rates. In determining
these assumptions, the Company 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 risk management assets (liabilities) were
recognized in the financial statements as follows: 


 
                                          ----------------------------------
                                               Nine Months
                                                     Ended       Year Ended
Asset (liability)                             Sep 30, 2012     Dec 31, 2011
----------------------------------------------------------------------------
Balance - beginning of period              $          (274) $          (485)
Net cost of outstanding put options                     18                -
Net change in fair value of outstanding
 derivative financial instruments
 attributable to:
  Risk management activities                            50              128
  Foreign exchange                                     (80)              42
  Other comprehensive income                            12               41
----------------------------------------------------------------------------
                                                      (274)            (274)
Add: put premium financing obligations (1)             (18)               -
----------------------------------------------------------------------------
Balance - end of period                               (292)            (274)
Less: current portion                                   (7)             (43)
----------------------------------------------------------------------------
                                           $          (285) $          (231)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 are reflected in the net risk management
    asset (liability).

 
Net losses (gains) from risk management activities were as follows: 


 
                                  Three Months Ended    Nine Months Ended
                                 -------------------------------------------
                                     Sep 30    Sep 30     Sep 30     Sep 30
                                       2012      2011       2012       2011
----------------------------------------------------------------------------
Net realized risk management loss
 (gain)                           $     137 $     (23) $     170  $      81
Net unrealized risk management
 loss (gain)                             34      (122)       (50)      (186)
----------------------------------------------------------------------------
                                  $     171 $    (145) $     120  $    (105)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 September 30, 2012, the Company had
the following derivative financial instruments outstanding to manage
its commodity price risks: 
Sales contracts 


 
                                                   Weighted average
                           Remaining term  Volume       price          Index
----------------------------------------------------------------------------
Crude oil
Crude oil price collars                    50,000
                        Oct 2012-Dec 2012   bbl/d US$80.00-US$134.87   Brent
                                           50,000
                        Oct 2012-Dec 2012   bbl/d US$80.00-US$136.06   Brent
                                           50,000
                        Oct 2012-Dec 2012   bbl/d US$80.00-US$113.62     WTI
                                           50,000
                        Oct 2012-Jun 2013   bbl/d US$80.00-US$145.07   Brent
                                           50,000
                        Jan 2013-Dec 2013   bbl/d US$80.00-US$110.34     WTI
                                           50,000
                        Jan 2013-Dec 2013   bbl/d US$80.00-US$135.59   Brent
 
Crude oil puts                            100,000
                        Oct 2012-Dec 2012   bbl/d           US$80.00     WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
During the fourth quarter of 2012, US$19 million of put option costs
will be settled. 
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. 
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 September 30,
2012, the Company had no interest rate swap contracts outstanding. 
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 September 30,
2012, the Company had the following cross currency swap contracts
outstanding: 


 
                                              Exchange
                                                  rate   Interest  Interest
                  Remaining term      Amount  (US$/C$) rate (US$) rate (C$)
----------------------------------------------------------------------------
Cross currency
Swaps          Oct 2012 - Aug 2016    US$250     1.116       6.00%     5.40%
               Oct 2012 - May 2017  US$1,100     1.170       5.70%     5.10%
               Oct 2012 - Nov 2021    US$500     1.022       3.45%     3.96%
               Oct 2012 - Mar 2038    US$550     1.170       6.25%     5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
All cross currency swap derivative financial instruments designated
as hedges at September 30, 2012, were classified as cash flow hedges. 
In addition to the cross currency swap contracts noted above, at
September 30, 2012, the Company had US$2,881 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
September 30, 2012, 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 September 30,
2012, the Company had net risk management assets of $10 million with
specific counterparties related to derivative financial instruments
(December 31, 2011 - $nil). 
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 less   2 to less
                               Less than      than 2        than
                                  1 year       years     5 years  Thereafter
----------------------------------------------------------------------------
Accounts payable             $       525 $         - $         - $         -
Accrued liabilities          $     2,218 $         - $         - $         -
Risk management              $         7 $        45 $       142 $        98
Other long-term liabilities  $        24 $        23 $        38 $         -
Long-term debt (1)           $     1,138 $         - $     2,944 $     4,386
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does not reflect
    fair value adjustments, original issue discounts or transaction costs.

 
14. COMMITMENTS AND CONTINGENCIES 
The Company has committed to certain payments as follows: 


 
                    Remaining
                         2012     2013     2014     2015     2016 Thereafter
----------------------------------------------------------------------------
Product
 transportation and
 pipeline           $      58 $    213 $    204 $    192 $    126 $      889
Offshore equipment
 operating leases
 and offshore
 drilling           $      43 $    153 $    120 $    103 $     75 $      121
Office leases       $       8 $     32 $     35 $     33 $     34 $      309
Other               $      76 $    169 $     95 $     42 $     10 $        8
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
In addition to the commitments disclosed above, the Company has
entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These
contracts can be cancelled by the Company upon notice without
penalty, subject to the costs incurred up to and in respect of the
cancellation. 
The Company is a 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. 
15. SEGMENTED INFORMATION 


 
                                   Exploration and Production
                           North America                 North Sea
(millions of        Three Months   Nine Months   Three Months  Nine Months
 Canadian dollars,     Ended          Ended          Ended        Ended
 unaudited)            Sep 30        Sep 30         Sep 30        Sep 30
                   ---------------------------------------------------------
                     2012   2011   2012    2011   2012    2011  2012   2011
----------------------------------------------------------------------------
Segmented product
 sales              2,786  2,730  8,601   8,643    198     276   713    907
Less: royalties      (359)  (339)  (991) (1,056)    (1)      -    (2)    (2)
----------------------------------------------------------------------------
Segmented revenue   2,427  2,391  7,610   7,587    197     276   711    905
----------------------------------------------------------------------------
Segmented expenses
Production            521    493  1,608   1,417     98     114   302    309
Transportation and
 blending             602    454  2,000   1,726      2       3     8     10
Depletion,
 depreciation and
 amortization         839    714  2,448   2,114     63      51   222    184
Asset retirement
 obligation
 accretion             22     18     64      53      6       8    20     24
Realized risk
 management
 activities           137    (23)   170      81      -       -     -      -
Horizon asset
 impairment
 provision              -      -      -       -      -       -     -      -
Insurance recovery
 - property damage
 (note 7)               -      -      -       -      -       -     -      -
Insurance recovery
 - business
 interruption (note
 7)                     -      -      -       -      -       -     -      -
Equity loss from
 jointly controlled
 entity                 1      -      6       -      -       -     -      -
----------------------------------------------------------------------------
Total segmented
 expenses           2,122  1,656  6,296   5,391    169     176   552    527
----------------------------------------------------------------------------
Segmented earnings
 (loss) before the
 following            305    735  1,314   2,196     28     100   159    378
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                  Exploration and Production
                                                   Total Exploration and
                          Offshore Africa                Production
(millions of        Three Months   Nine Months   Three Months  Nine Months
 Canadian dollars,     Ended          Ended         Ended         Ended
 unaudited)            Sep 30        Sep 30         Sep 30        Sep 30
                   ---------------------------------------------------------
                     2012   2011   2012    2011   2012   2011   2012   2011
----------------------------------------------------------------------------
Segmented product
 sales                158    250    615     638  3,142  3,256  9,929 10,188
Less: royalties       (50)   (46)  (146)    (68)  (410)  (385)(1,139)(1,126)
----------------------------------------------------------------------------
Segmented revenue     108    204    469     570  2,732  2,871  8,790  9,062
----------------------------------------------------------------------------
Segmented expenses
Production             51     45    124     120    670    652  2,034  1,846
Transportation and
 blending               -      1      1       1    604    458  2,009  1,737
Depletion,
 depreciation and
 amortization          29     44    107     170    931    809  2,777  2,468
Asset retirement
 obligation
 accretion              2      2      5       5     30     28     89     82
Realized risk
 management
 activities             -      -      -       -    137    (23)   170     81
Horizon asset
 impairment
 provision              -      -      -       -      -      -      -      -
Insurance recovery
 - property damage
 (note 7)               -      -      -       -      -      -      -      -
Insurance recovery
 - business
 interruption (note
 7)                     -      -      -       -      -      -      -      -
Equity loss from
 jointly controlled
 entity                 -      -      -       -      1      -      6      -
----------------------------------------------------------------------------
Total segmented
 expenses              82     92    237     296  2,373  1,924  7,085  6,214
----------------------------------------------------------------------------
Segmented earnings
 (loss) before the
 following             26    112    232     274    359    947  1,705  2,848
----------------------------------------------------------------------------
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        Three Months   Nine Months   Three Months   Nine Months
 Canadian dollars,     Ended          Ended          Ended         Ended
 unaudited)            Sep 30        Sep 30         Sep 30        Sep 30
                   ---------------------------------------------------------
                     2012   2011   2012    2011    2012   2011   2012   2011
----------------------------------------------------------------------------
Segmented product
 sales                831    427  2,196     516      24     23     67     66
Less: royalties       (32)   (15)  (108)    (19)      -      -      -      -
----------------------------------------------------------------------------
Segmented revenue     799    412  2,088     497      24     23     67     66
----------------------------------------------------------------------------
Segmented expenses
Production            398    306  1,132     783       7      7     21     19
Transportation and
 blending              16     15     46      46       -      -      -      -
Depletion,
 depreciation and
 amortization         124     77    333     133       1      1      5      5
Asset retirement
 obligation
 accretion              8      5     24      15       -      -      -      -
Realized risk
 management
 activities             -      -      -       -       -      -      -      -
Horizon asset
 impairment
 provision              -      -      -     396       -      -      -      -
Insurance recovery
 - property damage
 (note 7)               -      -      -    (396)      -      -      -      -
Insurance recovery
 - business
 interruption (note
 7)                     -   (181)     -    (317)      -      -      -      -
Equity loss from
 jointly controlled
 entity                 -      -      -       -       -      -      -      -
----------------------------------------------------------------------------
Total segmented
 expenses             546    222  1,535     660       8      8     26     24
----------------------------------------------------------------------------
Segmented earnings
 (loss) before the
 following            253    190    553    (163)     16     15     41     42
----------------------------------------------------------------------------
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       Three Months  Nine Months   Three Months   Nine Months
 Canadian dollars,     Ended        Ended         Ended          Ended
 unaudited)           Sep 30        Sep 30        Sep 30         Sep 30
                   ---------------------------------------------------------
                    2012   2011   2012   2011   2012   2011    2012    2011
----------------------------------------------------------------------------
Segmented product
 sales               (19)   (16)   (56)   (51) 3,978  3,690  12,136  10,719
Less: royalties        -      -      -      -   (442)  (400) (1,247) (1,145)
----------------------------------------------------------------------------
Segmented revenue    (19)   (16)   (56)   (51) 3,536  3,290  10,889   9,574
----------------------------------------------------------------------------
Segmented expenses
Production            (4)    (6)   (10)   (11) 1,071    959   3,177   2,637
Transportation and
 blending            (14)   (14)   (41)   (38)   606    459   2,014   1,745
Depletion,
 depreciation and
 amortization          -      -      -      -  1,056    887   3,115   2,606
Asset retirement
 obligation
 accretion             -      -      -      -     38     33     113      97
Realized risk
 management
 activities            -      -      -      -    137    (23)    170      81
Horizon asset
 impairment
 provision             -      -      -      -      -      -       -     396
Insurance recovery
 - property damage
 (note 7)              -      -      -      -      -      -       -    (396)
Insurance recovery
 - business
 interruption (note
 7)                    -      -      -      -      -   (181)      -    (317)
Equity loss from
 jointly controlled
 entity                -      -      -      -      1      -       6       -
----------------------------------------------------------------------------
Total segmented
 expenses            (18)   (20)   (51)   (49) 2,909  2,134   8,595   6,849
----------------------------------------------------------------------------
Segmented earnings
 (loss) before the
 following            (1)     4     (5)    (2)   627  1,156   2,294   2,725
----------------------------------------------------------------------------
Non-segmented
 expenses
Administration                                    64     65     206     188
Share-based
 compensation                                     49   (249)   (173)   (309)
Interest and other
 financing costs                                  92     97     281     290
Unrealized risk
 management
 activities                                       34   (122)    (50)   (186)
Foreign exchange
 (gain) loss                                    (115)   211    (107)    107
----------------------------------------------------------------------------
Total non-segmented
 expenses                                        124      2     157      90
----------------------------------------------------------------------------
Earnings before
 taxes                                           503  1,154   2,137   2,635
Current income tax
 expense                                         114    165     558     561
Deferred income tax
 expense                                          29    153      39     263
----------------------------------------------------------------------------
Net earnings                                     360    836   1,540   1,811
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Capital Expenditures (1) 


 
                                           Nine Months Ended
                          -------------------------------------------------
                                             Sep 30, 2012
---------------------------------------------------------------------------
                                                 Non cash
                                            and fair value      Capitalized
                          Net expenditures      changes(2)            costs
---------------------------------------------------------------------------
 
Exploration and evaluation
 assets
Exploration and Production
 North America             $           294 $          (114) $           180
 North Sea                               -               -                -
 Offshore Africa                         5               -                5
---------------------------------------------------------------------------
                           $           299 $          (114) $           185
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
Property, plant and
 equipment
Exploration and Production
 North America             $         2,746 $            71  $         2,817
 North Sea                             199             (33)             166
 Offshore Africa                        30              (6)              24
---------------------------------------------------------------------------
                                     2,975              32            3,007
Oil Sands Mining and
 Upgrading (3) (4)                   1,069              34            1,103
Midstream                               10               -               10
Head office                             25               -               25
---------------------------------------------------------------------------
                           $         4,079 $            66  $         4,145
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
                                           Nine Months Ended
                          --------------------------------------------------
                                             Sep 30, 2011
----------------------------------------------------------------------------
                                              Non cash and
                                                fair value      Capitalized
                          Net expenditures     changes(2)             costs
----------------------------------------------------------------------------
 
Exploration and evaluation
 assets
Exploration and Production
 North America             $           199 $          (225) $           (26)
 North Sea                               -              (4)              (4)
 Offshore Africa                         1               -                1
----------------------------------------------------------------------------
                           $           200 $          (229) $           (29)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Property, plant and
 equipment
Exploration and Production
 North America             $         2,991 $           255  $         3,246
 North Sea                             156               4              160
 Offshore Africa                        50             (29)              21
----------------------------------------------------------------------------
                                     3,197             230            3,427
Oil Sands Mining and
 Upgrading (3) (4)                     940            (406)             534
Midstream                                5               -                5
Head office                             16               -               16
----------------------------------------------------------------------------
                           $         4,158 $          (176) $         3,982
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) This table provides a reconciliation of capitalized costs and does not
    include the impact of foreign exchange adjustments and 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 and share-based compensation.
(4) During the first quarter of 2011, the Company derecognized certain
    property, plant and equipment related to the coker fire at Horizon in
    the amount of $411 million. This amount was included in non cash and
    fair value changes.

 
Segmented Assets 


 
                                                     Total Assets
                                          ----------------------------------
                                                     Sep 30           Dec 31
                                                       2012             2011
----------------------------------------------------------------------------
Exploration and Production
  North America                            $         29,028 $         28,554
  North Sea                                           1,652            1,809
  Offshore Africa                                       898            1,070
  Other                                                  44               23
Oil Sands Mining and Upgrading                       15,825           15,433
Midstream                                               341              321
Head office                                              81               68
----------------------------------------------------------------------------
                                           $         47,869 $         47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 2011. These ratios are based on
the Company's interim consolidated financial statements that are
prepared in accordance with accounting principles generally accepted
in Canada. 


 
Interest coverage ratios for the twelve month period ended
 September 30, 2012:
----------------------------------------------------------------------------
Interest coverage (times)
  Net earnings (1)                                                      8.3x
  Cash flow from operations (2)                                        17.3x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net earnings plus income taxes and interest expense excluding current
    and deferred PRT expense and other taxes; 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 and other taxes; divided by the sum of
    interest expense and capitalized interest.

 
CONFERENCE CALL 
A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m.
Eastern Time on Thursday, November 8, 2012. 
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. 
A taped rebroadcast will be available until 6:00 p.m. Mountain Time,
Thursday, November 15, 2012. To access the rebroadcast in North
America, dial 1-800-408-3053. Those outside of North America, dial
001-905-694-9451. The pass code to use is 6854115. 
WEBCAST 
The conference call will also be broadcast live on the internet and
may be accessed through the Canadian Natural website at www.cnrl.com. 
2013 BUDGET DETAILS 
Canadian Natural will release its 2013 budget details on Tuesday,
December 4, 2012. The news release will provide forward looking
information on the Company's 2013 operating year. 
A conference call and webcast, which will include presentation
slides, will be held on the same day at 9:00 am MT (11:00 am ET).
Presentation slides will be available shortly before the conference
call. Conference call information and presentation can be accessed on
the homepage of Canadian Natural's website at: www.cnrl.com under
Upcoming Events and News. 
Contacts:
John G. Langille
Vice-Chairman 
Steve W. Laut
President 
Corey B. Bieber
Vice-President, Finance & Investor Relations 
Canadian Natural Resources Limited
2500, 855 2nd Street S.W.
Calgary, Alberta, T2P 4J8 Canada
Phone: (403) 514-7777
ir@cnrl.com
www.cnrl.com