Canadian Natural Resources Limited Announces 2013 Second Quarter Results

Canadian Natural Resources Limited Announces 2013 Second Quarter Results 
CALGARY, ALBERTA -- (Marketwired) -- 08/08/13 -- Canadian Natural
Resources Limited (TSX:CNQ) (NYSE:CNQ) 
"Canadian Natural achieved in the second quarter of 2013 strong
quarterly production from our balanced and diverse asset base,"
commented Steve Laut, President of Canadian Natural. "On a per barrel
of oil equivalent basis, our overall Exploration and Production
operating costs decreased from last quarter resulting in excellent
overall netbacks. This, along with strong WTI benchmark pricing,
tighter WCS to WTI differentials and better natural gas pricing
helped the Company generate solid cash flow in the quarter. 
At Kirby South, we are in the final stages of commissioning. Steam
injection is expected to commence in late August or early September
2013, approximately three months ahead of the original schedule.
Project costs remain within 
our targeted budget. By the fourth quarter of 2014, thermal in situ
production at Kirby South is targeted to grow to 40,000 bbl/d. 
Horizon reliability continues to improve after the completion of our
first major maintenance turnaround of the plant in May 2013. We
continue to achieve safe, steady and reliable operations. In June and
July 2013, synthetic crude oil production was 101,000 bbl/d and
110,000 bbl/d, respectively. 
During the second quarter, our North America Exploration and
Production crude oil and NGL assets, excluding thermal in situ oil
sands, achieved record quarterly production of approximately 241,000
bbl/d. These volumes were driven by record quarterly production at
our primary heavy crude oil and Pelican Lake operations. This quarter
marks the tenth consecutive quarter that our heavy crude oil assets
have achieved record production and demonstrates the strong
performance ability of the Pelican Lake pool. 
As we move into the third quarter of 2013, we expect production
volumes to grow in the quarter. Higher production volumes from
thermal in situ operations, increased reliability at Horizon Oil
Sands Mining operations and continued strong production performance
from all other operating areas of the Company are anticipated. We
will continue to operate efficiently and effectively to ensure
industry competitive operating costs." 
Corey Bieber, Canadian Natural's Chief Financial Officer, stated, "We
are in an excellent position to realize strong cash flow metrics over
the last half of 2013. Midpoint guidance for crude oil production in
Q3/13 reflects an increase of approximately 19% over Q2/13 volumes.
Furthermore, heavy oil differentials have narrowed as expected. At
the same time, benchmark North American crude oil pricing has
increased and condensate premium costs have reduced. We target very
robust netbacks in the last half of 2013, which ultimately results in
debt levels reflective of 2012, making our balance sheet even
stronger, despite substantial capital investments of approximately
$2.075 billion in the calendar year of 2013 on the Horizon Project
Phase 2/3 expansion." 
QUARTERLY HIGHLIGHTS 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
($ Millions, except                                                         
 per common share         Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
 amounts)                   2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Net earnings          $      476 $      213 $      753 $      689 $    1,180
 Per common share                                                        
  - basic             $     0.44 $     0.19 $     0.68 $     0.63 $     1.07
  - diluted           $     0.44 $     0.19 $     0.68 $     0.63 $     1.07
Adjusted net earnings                                                       
 from operations (1)  $      462 $      401 $      606 $      863 $      906
 Per common share                                                         
  - basic             $     0.42 $     0.37 $     0.55 $     0.79 $     0.82
  - diluted           $     0.42 $     0.37 $     0.55 $     0.79 $     0.82
Cash flow from                                                              
 operations (2)       $    1,670 $    1,571 $    1,754 $    3,241 $    3,034
 Per common share                                                         
  - basic             $     1.53 $     1.44 $     1.60 $     2.97 $     2.76
  - diluted           $     1.53 $     1.44 $     1.59 $     2.97 $     2.75
Capital expenditures,                                                       
 net of dispositions  $    1,792 $    1,736 $    1,324 $    3,528 $    2,920
                                                                            
Daily production,                                                           
 before royalties                                                           
 Natural gas (MMcf/d)      1,122      1,150      1,255      1,136      1,277
 Crude oil and NGLs                                                         
  (bbl/d)                436,363    489,157    470,523    462,615    432,993
 Equivalent                                                                 
  production (BOE/d)                                                        
  (3)                    623,315    680,844    679,607    651,921    645,943
----------------------------------------------------------------------------
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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. 
- Canadian Natural generated cash flow from operations of
approximately $1.67 billion in Q2/13 compared to approximately $1.57
billion in Q1/13 and approximately $1.75 billion in Q2/12. The
increase from Q1/13 reflects higher crude oil and NGLs and natural
gas netbacks and higher realized synthetic crude oil ("SCO") pricing
partially offset by lower crude oil and SCO sales volumes in the
North America and Oil Sands Mining and Upgrading segments. The cash
flow variance from Q2/12 reflects higher crude oil and NGLs sales
volumes, higher natural gas netbacks, higher realized SCO pricing and
the impact of a weaker Canadian dollar offset by expected lower SCO
sales volumes in the Oil Sands Mining and Upgrading segment and
expected lower natural gas sales volumes.  
- Adjusted net earnings from operations in Q2/13 were $462 million
compared to $401 million in Q1/13 and $606 million in Q2/12. Changes
in adjusted net earnings primarily reflect the changes in cash flow
from operations. 
- Total production for Q2/13 averaged 623,315 BOE/d, within the
Company's previously announced corporate guidance, which ranged from
617,000 BOE/d to 646,000 BOE/d. As expected, production volumes
varied from Q2/12 and Q1/13 levels primarily as a result of expected
lower volumes in the Oil Sands Mining and Upgrading segment due to
the Company's first major maintenance turnaround at Horizon Oil Sands
("Horizon") and in the Thermal In Situ Oil Sands segment due to
production cycle timing.  
- In Q2/13, primary heavy crude oil operations achieved record
quarterly production of approximately 136,000 bbl/d, representing the
Company's tenth consecutive quarter of record primary heavy crude oil
production. Primary heavy crude oil production increased 2% and 11%
from Q1/13 and Q2/12, respectively. The Company expects continued
strong performance from its primary heavy crude oil assets during the
second half of 2013, which are targeted to deliver a 13% production
increase over 2012 levels.  
- In mid-May 2013, facility constraints at Pelican Lake were
alleviated with the completion of a new battery. Both Pelican Lake
and Woodenhouse production volumes ramped up soon afterward. In
Q2/13, Pelican Lake operations achieved record quarterly production
volumes of approximately 42,000 bbl/d, 10% higher than Q1/13 volumes.
In June and July 2013, monthly average production increased to
between 45,000 bbl/d and 46,000 bbl/d, demonstrating the reservoir's
continued strong performance. Further production volume increases are
expected through the second half of 2013, with targeted exit volumes
for 2013 of approximately 50,000 bbl/d. 
- Kirby South, the next step in the Company's well defined thermal
growth plan, is now in the final stages of commissioning, with first
steam-in expected in late August or early September 2013, three
months ahead of schedule. Production is targeted to ramp up to 40,000
bbl/d of bitumen by Q4/14. 
- During May 2013, the first major maintenance turnaround at Horizon
was completed with no major changes to the scope. The sequential
start-up of the operation was executed as planned. Q3/13 Horizon SCO
production is targeted to increase to between 110,000 bbl/d and
115,000 bbl/d as greater reliability and consistent production is
realized after the turnaround. Safe, steady, and reliable operations
continue to be a priority at Horizon.  Annual SCO production is
unchanged and is targeted to range from 100,000 bbl/d to 108,000
bbl/d in 2013.  
- At Septimus, the Company's liquids rich natural gas Montney play,
the plant expansion was completed and expanded production volumes
were achieved in July 2013. At the end of July, total production at
Septimus reached approximately 90 MMcf/d of natural gas and
approximately 8,600 bbl/d of liquids. During Q2/13, Canadian Natural
drilled 6 net wells at Septimus and targets to drill 7 additional net
wells in Q3/13. By early September 2013, production is targeted to
grow to plant expansion capacity of 125 MMcf/d of natural gas sales,
yielding approximately 12,200 bbl/d of liquids, through the plant and
deep cut facilities.  
- Subsequent to Q2/13, Canadian Natural announced the acquisition of
Barrick Energy Inc. The production and undeveloped land base is
complementary to Canadian Natural's existing assets and is
concentrated in light oil weighted assets with strong netbacks and a
long reserve life. This acquisition adds approximately 4,200 bbl/d of
light crude oil and NGLs and 4.4 MMcf/d of natural gas production.  
- Subsequent to Q2/13, TransCanada Corporation announced a successful
open season on its Energy East Pipeline project which is anticipated
to add 1.1 MMbbl/d of incremental pipeline capacity to the east coast
of Canada. Canadian Natural is a strong supporter of this project and
has made commitments of 80,000 bbl/d of crude oil. This commitment is
in addition to previously announced commitments of crude oil to
Keystone XL and Trans Mountain Expansion of 120,000 bbl/d and 75,000
bbl/d respectively. 


 
            ----------------------------------------------------------------
                                                                            
                                              SCO  Dated Brent   Condensate 
                   WTI    WCS Blend  Differential Differential Differential 
Benchmark      Pricing Differential      from WTI     from WTI     from WTI 
 Pricing     (US$/bbl) from WTI (%)     (US$/bbl)    (US$/bbl)    (US$/bbl) 
----------------------------------------------------------------------------
2013                                                                        
 April       $   92.07           25% $       6.14 $       9.85 $      10.00 
 May         $   94.80           15% $       8.33 $       7.69 $       6.92 
 June        $   95.80           21% $       0.02 $       7.11 $       4.91 
 July        $  104.70           14% $       5.98 $       3.25 $       1.60 
 August (i)  $  104.74           15% $       3.20 $       3.13 $      (2.78)
 September                                                                  
  (i)        $  103.84           20% $       2.27 $       3.21 $      (4.45)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(i) Based on current indicative pricing as at July 31, 2013. 
- As expected, heavy crude oil differentials narrowed during the
second quarter, resulting in more favorable price realizations for
the Company. The WCS heavy crude oil differential ("WCS
differential") as a percent of WTI averaged 20% in Q2/13 compared to
34% in Q1/13 and 24% in Q2/12. In July, August and September 2013,
the WCS differential, based on current indicative pricing, narrowed
to 14%, 15% and 20%, respectively.  
- The Company uses condensate as a blending diluent for heavy crude
oil pipeline shipments. During Q2/13, condensate price premiums to
WTI narrowed to US$7.27/bbl in Q2/13 compared to US$12.84/bbl in
Q1/13. Lower condensate price premiums are expected to continue in
the second half of 2013 resulting in higher netbacks for the
Company's heavy crude oil sales volumes.  
- As expected, the Dated Brent to WTI differential narrowed to
US$8.21/bbl in Q2/13 compared to US$18.09/bbl in Q1/13 and
US$14.71/bbl in Q2/12. Overall pricing relative to Dated Brent
pricing for Canadian Natural's North American crude oil production
continues to improve as a result of this narrowing.  
- SCO pricing improved in Q2/13 to US$99.10/bbl compared to
US$95.24/bbl in Q1/13 and US$89.54/bbl in Q2/12 resulting in more
favorable price realizations for the Company. 
- Q3/13 production volumes are expected to be strong and will be
driven by increased production volumes from Primrose, strong SCO
production due to improved Horizon reliability, and continued solid
performance from the Company's remaining operating areas. Combining
this strong production performance with favorable WTI pricing, narrow
heavy oil differentials, and strong SCO premiums should result in a
strong third quarter performance for the Company. 
- Year to date, Canadian Natural has purchased for cancellation
6,937,500 common shares at a weighted average price of $30.86 per
common share. 
- Canadian Natural declared a quarterly cash dividend on common
shares of C$0.125 per share payable on October 1, 2013. 
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 and
operating 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)                                                                     
                                           Six Months Ended Jun 30          
                                 -------------------------------------------
                                         2013                  2012         
                                      Gross       Net       Gross       Net 
----------------------------------------------------------------------------
Crude oil                               471       459         574       544 
Natural gas                              29        23          25        23 
Dry                                      10        10           8         8 
----------------------------------------------------------------------------
Subtotal                                510       492         607       575 
Stratigraphic test / service                                                
 wells                                  321       321         589       589 
----------------------------------------------------------------------------
Total                                   831       813       1,196     1,164 
----------------------------------------------------------------------------
  Success rate (excluding                                                   
   stratigraphic test / service                                             
   wells)                                          98%                   99%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
North America Exploration and Production 


 
Crude oil and NGLs - excluding Thermal In Situ Oil Sands                    
                             Three Months Ended          Six Months Ended   
                     -----------                      -----------           
                         Jun 30     Mar 31     Jun 30     Jun 30     Jun 30 
                           2013       2013       2012       2013       2012 
----------------------------------------------------------------------------
Crude oil and NGLs                                                          
 production (bbl/d)     241,402    236,600    222,127    239,014    223,707 
----------------------------------------------------------------------------
                                                                            
Net wells targeting                                                         
 crude oil                  136        271        231        407        472 
Net successful wells                                                        
 drilled                    131        267        229        398        464 
----------------------------------------------------------------------------
  Success rate               96%        99%        99%        98%        98%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- North America crude oil and NGLs operations achieved record
quarterly production of 241,402 bbl/d in Q2/13, an increase of 9% and
2% from Q2/12 and Q1/13 levels respectively.   
- Canadian Natural drilled 121 net primary heavy crude oil wells in
Q2/13. Canadian Natural's primary heavy crude oil continues to
provide strong netbacks and a high return on capital in the Company's
portfolio of diverse and balanced assets. In Q2/13 primary heavy
crude oil operations achieved record production volumes of
approximately 136,000 bbl/d, resulting in the tenth consecutive
quarter of record primary heavy crude oil production volumes,
contributing to the targeted 13% primary heavy crude oil production
growth in 2013. The Company is targeting to drill another 255 net
primary heavy crude oil wells in Q3/13.  
- Production volumes at Woodenhouse during Q2/13 averaged
approximately 13,500 bbl/d, representing an increase of 13% from
Q1/13 levels of approximately 12,000 bbl/d. Current production from
Woodenhouse is approximately 15,000 bbl/d.  
- During Q2/13, reservoir performance from Canadian Natural's
industry leading Pelican Lake polymer flood remained strong. Ten net
horizontal production wells were drilled during the quarter and 13
net horizontal production wells are targeted in Q3/13. Construction
of the new battery at Pelican Lake was successfully completed in
mid-May 2013. Facility constraints that began in Q4/12 have been
alleviated by the expansion and as a result, production volumes at
Pelican Lake and Woodenhouse have increased. Pelican Lake operations
achieved record quarterly crude oil production of approximately
42,000 bbl/d in Q2/13, representing a 10% increase from Q1/13 and a
12% increase from Q2/12. 
- North America light crude oil and NGLs Q2/13 production decreased
2% from Q1/13 due to downtime as a result of expansion activities at
Septimus and Wembley, spring break-up activities and planned
turnarounds. The Company drilled 5 net light crude oil wells in Q2/13
and targets to drill 29 additional net wells in Q3/13. Canadian
Natural's light crude oil drilling program will continue to utilize
and advance horizontal multi-frac well technology to access new
reserves in pools across the Company's land base.  
- Total planned drilling activity for Q3/13 includes 297 net crude
oil wells, excluding stratigraphic ("strat") and service wells. 


 
Thermal In Situ Oil Sands                                                   
                             Three Months Ended          Six Months Ended   
                     -----------                      -----------           
                         Jun 30     Mar 31     Jun 30     Jun 30     Jun 30 
                           2013       2013       2012       2013       2012 
----------------------------------------------------------------------------
Bitumen production                                                          
 (bbl/d)                 90,051    108,889     94,356     99,419     87,341 
----------------------------------------------------------------------------
                                                                            
Net wells targeting                                                         
 crude oil                   27         33         37         60         80 
Net successful wells                                                        
 drilled                     27         33         37         60         80 
----------------------------------------------------------------------------
  Success rate              100%       100%       100%       100%       100%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- Q2/13 thermal in situ oil sands ("thermal in situ") production
volumes averaged approximately 90,000 bbl/d due to the timing of
steaming and production cycles. 
- During the second quarter of 2013, bitumen emulsion was discovered
at surface at four separate locations in the Company's Primrose
development area. The bitumen emulsion seepage has been controlled to
specific containment areas totaling 13.5 hectares where it is
effectively recovered as it reaches the surface. The rate of bitumen
emulsion seepage in all four locations has declined as expected and
currently totals less than 20 bbl/d. Canadian Natural believes the
cause of the bitumen emulsion seepage is mechanical failures of
wellbores in the vicinity of the impacted locations. A complete
review is ongoing and Canadian Natural has a specialized team focused
on investigating wells in the impacted areas for potential required
remediation work. 
- The Company's near term steaming plan at Primrose has been
modified, with restrictions on steaming in some areas until the
investigation with the Alberta Energy Regulator is complete. 
Canadian Natural's July 2013 production was approximately 120,000
bbl/d with an additional 20,000 bbl/d of production capacity that was
restricted due to available plant capacity. The Company targets 2013
thermal in situ production to range from 100,000 bbl/d to 107,000
bbl/d. For 2014, even with these modified steaming strategies, the
Company anticipates thermal in situ production, excluding Kirby
South, to range from 100,000 bbl/d to 110,000 bbl/d, approximately
10,000 bbl/d less than originally targeted. The Company is of the
view that reserves recovered from the Primrose area over its life
cycle will be substantially unchanged. 
- Kirby South remains ahead of plan and on budget. Drilling was
successfully completed on the seventh and final pad in Q2/13.
Commissioning is nearing completion with first steam-in expected in
late August or early September 2013, ahead of the originally
scheduled steam-in date of November 2013. Production is targeted to
grow to 40,000 bbl/d by Q4/14. 
- Detailed engineering is progressing for Kirby North Phase 1. As of
June 30, 2013, the engineering portion was 64% complete. Construction
of the main access road has been completed and site preparation will
continue into Q3/13.  
- Kirby South and Kirby North Phase 1 will contribute to a targeted
staged expansion of production volumes from the greater Kirby area
over time to 140,000 bbl/d, with the overall thermal in situ
development plan targeted to increase to 510,000 bbl/d of production
capacity.  
- Planned drilling activity for Q3/13 includes 47 net thermal in situ
wells, excluding strat and service wells. 


 
Natural Gas                                                                 
                             Three Months Ended          Six Months Ended   
                     -----------                      -----------           
                         Jun 30     Mar 31     Jun 30     Jun 30     Jun 30 
                           2013       2013       2012       2013       2012 
----------------------------------------------------------------------------
Natural gas                                                                 
 production (MMcf/d)      1,092      1,125      1,230      1,108      1,255 
----------------------------------------------------------------------------
                                                                            
Net wells targeting                                                         
 natural gas                  8         16          4         24         23 
Net successful wells                                                        
 drilled                      8         15          4         23         23 
----------------------------------------------------------------------------
  Success rate              100%        94%       100%        96%       100%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- During Q2/13, North America natural gas production averaged 1,092
MMcf/d, representing a 11% decrease from Q2/12 levels and a 3%
decrease from Q1/13 levels. The decrease in production levels year
over year was due to expected production declines, reflecting
Canadian Natural's strategic decision to allocate capital to higher
return crude oil projects. Q3/13 production volumes are targeted to
increase to 1,135 MMcf/d to 1,155 MMcf/d.  
- At Septimus, the Company's liquids rich natural gas Montney play,
the plant expansion was completed and first production was achieved
in July 2013. At the end of July, total production at Septimus
reached approximately 90 MMcf/d of natural gas and approximately
8,600 bbl/d of liquids. During Q2/13, Canadian Natural drilled 6 net
wells at Septimus and targets to drill 7 additional net wells in
Q3/13. By early September 2013, production is targeted to grow to
plant expansion capacity of 125 MMcf/d of natural gas sales, yielding
12,200 bbl/d of liquids, through the plant and deep cut facilities. 
- Canadian Natural has a dominant Montney land position with over one
million high quality net acres, the largest in the industry. In
Q1/13, the Company commenced the process to monetize approximately
243,000 net acres (approximately 380 net sections) of its Montney
land base in the liquids rich fairway in the Graham Kobes area of
Northeast British Columbia. In Q2/13, the Information Memorandum was
completed. The Company targets to open the associated data room in
mid to late August 2013 and conduct presentations in September 2013. 
International Exploration and Production 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                         Jun 30      Mar 31     Jun 30    Jun 30      Jun 30
                           2013        2013       2012      2013        2012
----------------------------------------------------------------------------
Crude oil production                                                        
 (bbl/d)                                                                    
  North Sea              18,901      18,774     17,619    18,838      20,333
  Offshore Africa        18,055      16,112     20,598    17,089      20,655
----------------------------------------------------------------------------
Natural gas                                                                 
 production (MMcf/d)                                                        
  North Sea                   4           1          2         3           2
  Offshore Africa            26          24         23        25          20
----------------------------------------------------------------------------
Net wells targeting                                                         
 crude oil                  1.0           -          -       1.0           -
Net successful wells                                                        
 drilled                    1.0           -          -       1.0           -
----------------------------------------------------------------------------
  Success rate              100%          -          -       100%          -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- International crude oil production averaged 36,956 bbl/d during the
quarter. The 6% increase in production from Q1/13 was primarily due
to the stabilization of the midwater arch which resulted in a
reinstatement of production at the Olowi Field in Gabon in late
Q1/13. Crude oil production volumes declined 3% from Q2/12 as a
result of natural field declines and the cessation of North Sea
drilling activity following an increase in the Supplementary Charge
Tax Rate in 2011.  
- In Q2/13, the Company received a second Brownfield Allowance
("BFA") approval for its Ninian Field development plan which includes
four new production wells, four injectors and two well upgrades. The
Company received its first BFA approval in Q1/13 for its Tiffany
field development plan of a two well infill drilling program which
achieved first oil in May 2013. In September 2012, the UK government
announced the implementation of the BFA, which allows for a property
development allowance on qualifying preapproved field developments.
This allowance partially mitigates the impact of previous tax
increases. 
- The light crude oil infill drilling program at Espoir, Côte
d'Ivoire, originally targeted to commence in late Q2/13, has been
delayed as the Company is demobilizing the current drilling rig due
to ongoing operational and safety issues with the drilling
contractor. Canadian Natural is currently re-assessing its drilling
options at Espoir, where the Company expects to undertake an 8-well
drilling program. 
- During Q2/13, Canadian Natural acquired operatorship and a 60%
working interest of Block 12 in Côte d'Ivoire, located approximately
35 km west of the Company's current production at Espoir and Baobab.
The Company plans to commence new 3D seismic acquisition in Q4/13.
Potential exploration drilling is targeted for 2015 to evaluate
deepwater channel/fan structures similar to the Jubilee crude oil
discoveries in Ghana and plays elsewhere in offshore Africa. 
- Exploration work on Block 514 in Cote d'Ivoire, in which Canadian
Natural has a 36% working interest, is underway and a seismic program
has been completed. Drilling is targeted to commence in the first
half of 2014. The Company believes this block is also prospective for
deepwater channel/fan structures similar to Jubilee.  
- A partner has been selected to jointly conduct exploratory drilling
on Canadian Natural's prospective offshore South Africa property. The
Company will provide further details on the partnership terms upon
receipt of regulatory approval. Targeted drilling windows are from
Q4/13 to Q1/14 and from Q4/14 to Q1/15 and the necessary long-lead
equipment has been ordered.  
North America Oil Sands Mining and Upgrading - Horizon 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
                            2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Synthetic crude oil                                                         
 production (bbl/d)       67,954    108,782    115,823     88,255     80,957
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- During Q2/13, SCO production averaged 67,954 bbl/d at Horizon Oil
Sands.  Production volumes were lower than Q1/13 and Q2/12 levels due
to the completion of the Company's first major maintenance turnaround
in May 2013. Horizon SCO production averaged approximately 101,000
bbl/d in June 2013, approximately 110,000 bbl/d in July 2013 and
Q3/13 production guidance is targeted to range from 110,000 bbl/d to
115,000 bbl/d. 2013 annual guidance remains unchanged at 100,000
bbl/d to 108,000 bbl/d of SCO production. 
- Canadian Natural's staged expansion to 250,000 bbl/d of SCO
production capacity continues to progress on track. Capital
expenditures to date on Phase 2/3 expansion are at or below cost
estimates as the Company executes its cost focused strategy.
Expansion work at Horizon will ultimately add an additional 140,000
bbl/d of SCO production in a staged, disciplined manner. Horizon
provides high quality, long life SCO production without decline for
decades.  
- An update to the staged Phase 2/3 expansion on an Engineering,
Procurement and Construction basis at the end of Q2/13 is as follows: 
-- Overall Horizon Phase 2/3 expansion is 24% complete.  
-- Reliability - Tranche 2 is 90% complete. An additional 5,000 bbl/d
of production capacity is targeted to be added in 2014. 
-- Directive 74 includes technological investment and research into
tailings management. This project remains on track and is currently
18% complete.  
-- Phase 2A is a coker expansion. The expansion is 62% complete, and
is targeted to add 10,000 bbl/d of production capacity in 2015.  
-- Phase 2B is 15% complete. This phase includes lump sum contracts
for major components such as gas/oil hydrotreatment, froth treatment
and a hydrogen plant. This phase is targeted to add another 45,000
bbl/d of production capacity in 2016.  
-- Phase 3 is on track and engineering is underway. This phase is 15%
complete, and includes the addition of supplementary extraction
trains. This phase is targeted to increase production capacity by
80,000 bbl/d in 2017.  
-- The projects which are currently under construction continue to
trend at or below cost estimates.  
- Total capital budgeted for the Horizon Phase 2/3 expansion in 2013
is $2.075 billion. Canadian Natural continues to be disciplined and
cost driven in the Horizon Phase 2/3 expansion to ensure the
expansion continues effectively and efficiently.  
MARKETING 


 
                             Three Months Ended          Six Months Ended   
                     -----------                      -----------           
                         Jun 30     Mar 31     Jun 30     Jun 30     Jun 30 
                           2013       2013       2012       2013       2012 
----------------------------------------------------------------------------
Crude oil and NGLs                                                          
 pricing                                                                    
  WTI benchmark price                                                       
   (US$/bbl) (1)      $   94.23  $   94.34  $   93.50  $   94.28  $   98.22 
  WCS blend                                                                 
   differential from                                                        
   WTI (%) (2)               20%        34%        24%        27%        23%
  SCO price (US$/bbl) $   99.10  $   95.24  $   89.54  $   97.18  $   93.82 
  Condensate                                                                
   benchmark pricing                                                        
   (US$/bbl)          $  101.50  $  107.18  $   99.49  $  104.32  $  104.77 
  Average realized                                                          
   pricing before                                                           
   risk management                                                          
   (C$/bbl) (3)       $   75.10  $   60.87  $   72.12  $   67.94  $   77.14 
Natural gas pricing                                                         
  AECO benchmark                                                            
   price (C$/GJ)      $    3.41  $    2.92  $    1.74  $    3.16  $    2.06 
  Average realized                                                          
   pricing before                                                           
   risk management                                                          
   (C$/Mcf)           $    4.05  $    3.51  $    2.15  $    3.78  $    2.44 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) West Texas Intermediate ("WTI").  
(2) Western Canadian Select ("WCS").  
(3) Average crude oil and NGLs pricing excludes SCO. Pricing is net
of blending costs and excluding risk management activities.  


 
            ----------------------------------------------------------------
                                                                            
                                              SCO  Dated Brent   Condensate 
                   WTI    WCS Blend  Differential Differential Differential 
Benchmark      Pricing Differential      from WTI     from WTI     from WTI 
 Pricing     (US$/bbl) from WTI (%)     (US$/bbl)    (US$/bbl)    (US$/bbl) 
----------------------------------------------------------------------------
2013                                                                        
 April       $   92.07           25% $       6.14 $       9.85 $      10.00 
 May         $   94.80           15% $       8.33 $       7.69 $       6.92 
 June        $   95.80           21% $       0.02 $       7.11 $       4.91 
 July        $  104.70           14% $       5.98 $       3.25 $       1.60 
 August (i)  $  104.74           15% $       3.20 $       3.13 $      (2.78)
 September                                                                  
  (i)        $  103.84           20% $       2.27 $       3.21 $      (4.45)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(i) Based on current indicative pricing as at July 31, 2013.  
- As expected, heavy crude oil differentials narrowed during the
second quarter, resulting in more favorable price realizations for
the Company. The WCS differential averaged 20% in Q2/13 compared to
34% in Q1/13 and 24% in Q2/12. The differential narrowed during Q2/13
compared to Q1/13 due to increased seasonal demand for heavy crude
oil, increased pipeline capacity resulting from improved pipeline
reliability, and lower unplanned maintenance activity at refineries
accessible to Canadian heavy crude oil. In July, August and September
2013, the WCS differential, based on current indicative pricing,
narrowed to 14%, 15% and 20%, respectively. 
- Canadian Natural contributed over 172,000 bbl/d of its heavy crude
oil blends to the WCS blend in Q2/13. The Company remains the largest
contributor to the WCS blend, accounting for over 62% of the total
blend this quarter.  
- The Company uses condensate as a blending diluent for heavy crude
oil pipeline shipments. Condensate price premiums to WTI narrowed to
US$7.27/bbl in Q2/13 compared to US$12.84/bbl in Q1/13, reflecting
normal seasonality. Lower condensate price premiums are expected to
continue in the second half of 2013 resulting in higher netbacks for
the Company's heavy crude oil sales volumes. 
- As expected, the Dated Brent to WTI differential narrowed to
US$8.21/bbl in Q2/13 compared to US$18.09/bbl in Q1/13 and
US$14.71/bbl in Q2/12, reflecting continued debottlenecking of the
logistical constraints between Cushing and the Gulf Coast as
incremental pipeline capacity continued to grow. Overall pricing
relative to Dated Brent pricing for Canadian Natural's North American
crude oil production continues to improve as a result of this
narrowing.  
- SCO pricing averaged US$99.10/bbl during Q2/13, representing a 4%
and 11% increase from Q1/13 and Q2/12 pricing, respectively. Pricing
increases from Q1/13 and Q2/12 reflect planned and unplanned supply
disruptions in Northern Alberta and overall higher diesel demand and
result in more favorable price realizations for the Company.  
NORTH WEST REDWATER UPGRADING AND REFINING  
In Q2/13 work continued on the North West Redwater refinery and
completion is targeted for mid-2016. The North West Redwater refinery
asset strengthens the Company's position by providing a competitive
return on investment and by adding 50,000 bbl/d of bitumen conversion
capacity in Alberta which will help reduce volatility in pricing all
Western Canadian heavy crude oil.  
FINANCIAL REVIEW  
The Company continues to implement proven strategies and its
disciplined approach to capital allocation. As a result, the
financial position of Canadian Natural remains strong. 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
623,315 BOE/d for Q2/13 with approximately 96% of production located
in G8 countries. 
- Subsequent to Q2/13, the Company increased its forecasted 2013
capital spending as a result of the Cold Lake pipeline expansion, the
Barrick Energy Inc. acquisition and a minor increase in capital
allocated to Exploration and Production.  
- Canadian Natural has a strong balance sheet with debt to book
capitalization of 29% and debt to EBITDA of 1.4x at June 30, 2013. 
- During Q2/13, Canadian Natural's $3,000 million revolving
syndicated credit facility was extended to June 2017. Additionally,
the Company issued $500 million of 2.89% medium-term notes due August
2020.  Proceeds from the securities issued were used to repay bank
indebtedness and for general corporate purposes. 
- In Q2/13, the Company completed a full quarter of its US commercial
paper program. Borrowings of up to a maximum of US$1,500 million are
authorized. The program further diversifies the Company's borrowing
base and has been well received. 
- Canadian Natural maintains significant financial stability and
liquidity represented by approximately $2.4 billion of available
credit under its bank credit facilities, net of commercial paper
issued. 
- The Company's commodity hedging program protects investment
returns, ensures ongoing balance sheet strength and supports the
Company's cash flow for its capital expenditure programs.
Approximately 58% of forecasted 2013 crude oil volumes are currently
hedged using price collars and physical crude oil sales contracts
with fixed WCS differentials. Through the use of collars, the Company
has hedged approximately 300,000 bbl/d of crude oil volumes in the
second half of 2013, and approximately 150,000 bbl/d of crude oil
volumes in 2014. To partially mitigate its exposure to widening heavy
crude oil differentials, the Company has entered into physical crude
oil sales contracts with weighted average fixed WCS differentials as
follows: 


 
                 Term                     Volume      Weighted average price
----------------------------------------------------------------------------
Jul 2013  -  Sep 2013               20,000 bbl/d                US$21.27/bbl
Oct 2013  -  Dec 2013               17,000 bbl/d                US$21.49/bbl
Jan 2014  -  Mar 2014                8,000 bbl/d                US$21.89/bbl
Apr 2014  -  Jun 2014                9,000 bbl/d                US$21.93/bbl
Jul 2014  -  Sep 2014               10,000 bbl/d                US$20.81/bbl
Oct 2014  -  Dec 2014               10,000 bbl/d                US$20.81/bbl
----------------------------------------------------------------------------

 
Details of the Company's commodity hedging program can be found on
the Company's website at www.cnrl.com.  
- Year to date, Canadian Natural has purchased for cancellation
6,937,500 common shares at a weighted average price of $30.86 per
common share. 
- Canadian Natural declared a quarterly cash dividend on common
shares of C$0.125 per share payable on October 1, 2013.  
OUTLOOK  
The Company forecasts 2013 production levels before royalties to
average between 482,000 and 513,000 bbl/d of crude oil and NGLs and
between 1,085 and 1,145 MMcf/d of natural gas. Q3/13 production
guidance before royalties is forecast to average between 506,000 and
529,000 bbl/d of crude oil and NGLs and between 1,135 and 1,155
MMcf/d of natural gas. 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", "proposed" 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, 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 thermal projects, Pelican Lake water and
polymer flood project, the Kirby Thermal Oil Sands Project,
construction of the proposed Keystone XL Pipeline from Hardisty,
Alberta to the US Gulf Coast, construction of the proposed Energy
East pipeline to transport crude oil from Alberta to Quebec and New
Brunswick, the proposed Kinder Morgan Trans Mountain pipeline
expansion from Edmonton, Alberta to Vancouver, British Columbia, 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, natural gas and natural gas
liquids ("NGLs") 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 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 six months ended
June 30, 2013 and the MD&A and the audited consolidated financial
statements for the year ended December 31, 2012.  
All dollar amounts are referenced in millions of Canadian dollars,
except where noted otherwise. The Company's consolidated financial
statements for the period ended June 30, 2013 and this MD&A have been
prepared in accordance with International Financial Reporting
Standards ("IFRS") as issued by the International Accounting
Standards Board. 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 ("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. 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 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 six months ended June 30, 2013 in relation
to the comparable periods in 2012 and the first quarter of 2013. The
accompanying tables form an integral part of this MD&A. Additional
information relating to the Company, including its Annual Information
Form for the year ended December 31, 2012, is available on SEDAR at
www.sedar.com, and on EDGAR at www.sec.gov. This MD&A is dated August
7, 2013. 
FINANCIAL HIGHLIGHTS  


 
($ millions, except per common share amounts)                               
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
                            2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Product sales         $    4,230 $    4,101 $    4,187 $    8,331 $    8,158
Net earnings          $      476 $      213 $      753 $      689 $    1,180
  Per common share                                                        
    - basic           $     0.44 $     0.19 $     0.68 $     0.63 $     1.07
    - diluted         $     0.44 $     0.19 $     0.68 $     0.63 $     1.07
Adjusted net earnings                                                       
 from operations (1)  $      462 $      401 $      606 $      863 $      906
  Per common share                                                        
    - basic           $     0.42 $     0.37 $     0.55 $     0.79 $     0.82
    - diluted         $     0.42 $     0.37 $     0.55 $     0.79 $     0.82
Cash flow from                                                              
 operations (2)       $    1,670 $    1,571 $    1,754 $    3,241 $    3,034
  Per common share                                                        
    - basic           $     1.53 $     1.44 $     1.60 $     2.97 $     2.76
    - diluted         $     1.53 $     1.44 $     1.59 $     2.97 $     2.75
Capital expenditures,                                                       
 net of dispositions  $    1,792 $    1,736 $    1,324 $    3,528 $    2,920
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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" presents 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"
presents certain non-cash items that are included in the Company's
financial results. Cash flow from operations may not be comparable to
similar measures presented by other companies.  
Adjusted Net Earnings from Operations 


 
                             Three Months Ended          Six Months Ended   
                     -----------                      -----------           
                         Jun 30     Mar 31     Jun 30     Jun 30     Jun 30 
($ millions)               2013       2013       2012       2013       2012 
----------------------------------------------------------------------------
Net earnings as                                                             
 reported             $     476  $     213  $     753  $     689  $   1,180 
Share-based                                                                 
 compensation, net of                                                       
 tax (1)                    (49)        71       (115)        22       (222)
Unrealized risk                                                             
 management (gain)                                                          
 loss, net of tax (2)       (92)        51       (103)       (41)       (63)
Unrealized foreign                                                          
 exchange loss, net                                                         
 of tax (3)                 112         78         71        190         11 
Realized foreign                                                            
 exchange gain on                                                           
 repayment of US                                                            
 dollar debt                                                                
 securities (4)               -        (12)         -        (12)         - 
Effect of statutory                                                         
 tax rate and other                                                         
 legislative changes                                                        
 on deferred income                                                         
 tax liabilities (5)         15          -          -         15          - 
----------------------------------------------------------------------------
Adjusted net earnings                                                       
 from operations      $     462  $     401  $     606  $     863  $     906 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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 the 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 first quarter of 2013, the Company repaid US$400
million of 5.15% unsecured notes.  
(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
second quarter of 2013, the government of British Columbia
substantively enacted legislation to increase its provincial
corporate income tax rate effective April 1, 2013, resulting in an
increase in the Company's deferred income tax liability of $15
million.  
Cash Flow from Operations 


 
                             Three Months Ended          Six Months Ended   
                     -----------                      -----------           
                         Jun 30     Mar 31     Jun 30     Jun 30     Jun 30 
($ millions)               2013       2013       2012       2013       2012 
----------------------------------------------------------------------------
Net earnings          $     476  $     213  $     753  $     689  $   1,180 
Non-cash items:                                                             
  Depletion,                                                                
   depreciation and                                                         
   amortization           1,172      1,142      1,084      2,314      2,059 
  Share-based                                                               
   compensation             (49)        71       (115)        22       (222)
  Asset retirement                                                          
   obligation                                                               
   accretion                 42         42         38         84         75 
  Unrealized risk                                                           
   management (gain)                                                        
   loss                    (114)        62       (144)       (52)       (84)
  Unrealized foreign                                                        
   exchange loss            112         78         71        190         11 
  Realized foreign                                                          
   exchange gain on                                                         
   repayment of US                                                          
   dollar debt                                                              
   securities                 -        (12)         -        (12)         - 
  Equity loss from                                                          
   jointly controlled                                                       
   entity                     -          2          5          2          5 
  Deferred income tax                                                       
   expense (recovery)        31        (27)        62          4         10 
----------------------------------------------------------------------------
Cash flow from                                                              
 operations           $   1,670  $   1,571  $   1,754  $   3,241  $   3,034 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS  
Net earnings for the six months ended June 30, 2013 were $689 million
compared with $1,180 million for the six months ended June 30, 2012.
Net earnings for the six months ended June 30, 2013 included net
after-tax expenses of $174 million compared with net after-tax income
of $274 million for the six months ended June 30, 2012 related to the
effects of share-based compensation, risk management activities,
fluctuations in foreign exchange rates including 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 six months ended June 30, 2013 were
$863 million compared with $906 million for the six months ended June
30, 2012.  
Net earnings for the second quarter of 2013 were $476 million
compared with $753 million for the second quarter of 2012 and $213
million for the first quarter of 2013. Net earnings for the second
quarter of 2013 included net after-tax income of $14 million compared
with $147 million for the second quarter of 2012 and net after-tax
expenses of $188 million for the first quarter of 2013 related to the
effects of share-based compensation, risk management activities,
fluctuations in foreign exchange rates including 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 second quarter of 2013 were $462
million compared with $606 million for the second quarter of 2012 and
$401 million for the first quarter of 2013.  
The decrease in adjusted net earnings for the six months ended June
30, 2013 from the comparable period in 2012 was primarily due to: 
- lower crude oil and NGLs netbacks;  
- lower natural gas sales volumes; and  
- higher depletion, depreciation and amortization expense;  
partially offset by: 
- higher crude oil and synthetic crude oil ("SCO") sales volumes in
the North America and Oil Sands Mining and Upgrading segments;  
- higher realized natural gas netbacks;  
- higher realized SCO prices;  
- higher realized risk management gains; and  
- the impact of a weaker Canadian dollar.  
The decrease in adjusted net earnings for the second quarter of 2013
from the comparable period in 2012 was primarily due to: 
- lower SCO sales volumes in the Oil Sands Mining and Upgrading
segment due to the May 2013 turnaround;  
- lower natural gas sales volumes;  
- lower realized risk management gains; and  
- higher depletion, depreciation and amortization expense;  
partially offset by: 
- higher crude oil and NGLs sales volumes;  
- higher natural gas netbacks;  
- higher realized SCO prices; and  
- the impact of a weaker Canadian dollar.  
The increase in adjusted net earnings for the second quarter of 2013
from the first quarter of 2013 was primarily due to: 
- higher crude oil and NGLs and natural gas netbacks;  
- higher realized SCO prices; and  
- the impact of a weaker Canadian dollar;  
partially offset by: 
- lower crude oil and SCO sales volumes in the North America and Oil
Sands Mining and Upgrading segments; and  
- lower realized risk management gains.  
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 six months ended June 30, 2013 was
$3,241 million compared with $3,034 million for the six months ended
June 30, 2012. Cash flow from operations for the second quarter of
2013 was $1,670 million compared with $1,754 million for the second
quarter of 2012 and $1,571 million for the first quarter of 2013. The
fluctuations in cash flow from operations from the comparable periods
were primarily due to the factors noted above relating to the
fluctuations in adjusted net earnings, excluding depletion,
depreciation and amortization expense, as well as due to the impact
of cash taxes.  
Total production before royalties for the six months ended June 30,
2013 increased 1% to 651,921 BOE/d from 645,943 BOE/d for the six
months ended June 30, 2012. Total production before royalties for the
second quarter of 2013 decreased 8% to 623,315 BOE/d from 679,607
BOE/d for the second quarter of 2012 and 680,844 BOE/d for the first
quarter of 2013.  
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       Jun 30     Mar 31     Dec 31     Sep 30
 share amounts)                        2013       2013       2012       2012
----------------------------------------------------------------------------
Product sales                    $    4,230 $    4,101 $    4,059 $    3,978
Net earnings                     $      476 $      213 $      352 $      360
Net earnings per common share                                               
  - basic                        $     0.44 $     0.19 $     0.32 $     0.33
  - diluted                      $     0.44 $     0.19 $     0.32 $     0.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
($ millions, except per common       Jun 30     Mar 31     Dec 31     Sep 30
share amounts)                         2012       2012       2011       2011
----------------------------------------------------------------------------
Product sales                    $    4,187 $    3,971 $    4,788 $    3,690
Net earnings                     $      753 $      427 $      832 $      836
Net earnings per common share                                               
  - basic                        $     0.68 $     0.39 $     0.76 $     0.76
  - diluted                      $     0.68 $     0.39 $     0.76 $     0.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Volatility in the quarterly net earnings over the eight most recently
completed quarters was primarily due to: 
- Crude oil pricing - The impact of fluctuating demand, inventory
storage levels and geopolitical uncertainties on worldwide benchmark
pricing, the impact of the WCS Heavy Differential from West Texas
Intermediate reference location at Cushing, Oklahoma ("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 crude oil drilling program, and the impact of the
turnaround/suspension and subsequent 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.  
- 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, shut-in natural gas
production due to pricing 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 in 2011 that had higher operating costs per Mcf than the
Company's existing properties, and the turnaround/suspension and
subsequent recommencement of production at Horizon.  
- Depletion, depreciation and amortization - Fluctuations due to
changes in sales volumes, proved reserves, asset retirement
obligations, finding and development costs associated with crude oil
and natural gas exploration, estimated future costs to develop the
Company's proved undeveloped reserves, and the impact of the
turnaround/suspension and subsequent recommencement of production at
Horizon.  
- 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 also
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          Six Months Ended   
                     -----------                      -----------           
                         Jun 30     Mar 31     Jun 30     Jun 30     Jun 30 
                           2013       2013       2012       2013       2012 
----------------------------------------------------------------------------
WTI benchmark price                                                         
 (US$/bbl)            $   94.23  $   94.34  $   93.50  $   94.28  $   98.22 
Dated Brent benchmark                                                       
 price (US$/bbl)      $  102.44  $  112.43  $  108.21  $  107.41  $  113.34 
WCS blend                                                                   
 differential from                                                          
 WTI (US$/bbl)        $   19.10  $   31.79  $   22.83  $   25.41  $   22.15 
WCS blend                                                                   
 differential from                                                          
 WTI (%)                     20%        34%        24%        27%        23%
SCO price (US$/bbl)   $   99.10  $   95.24  $   89.54  $   97.18  $   93.82 
Condensate benchmark                                                        
 price (US$/bbl)      $  101.50  $  107.18  $   99.49  $  104.32  $  104.77 
NYMEX benchmark price                                                       
 (US$/MMBtu)          $    4.09  $    3.35  $    2.26  $    3.72  $    2.52 
AECO benchmark price                                                        
 (C$/GJ)              $    3.41  $    2.92  $    1.74  $    3.16  $    2.06 
US/Canadian dollar                                                          
 average exchange                                                           
 rate (US$)           $  0.9774  $  0.9917  $  0.9897  $  0.9844  $  0.9943 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Commodity Prices  
Crude oil sales contracts in the North America segment are typically
based on WTI benchmark pricing. WTI averaged US$94.28 per bbl for the
six months ended June 30, 2013, a decrease of 4% from US$98.22 per
bbl for the six months ended June 30, 2012. WTI averaged US$94.23 per
bbl for the second quarter of 2013 and was consistent with the
comparative periods.  
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$107.41 per bbl for the six
months ended June 30, 2013, a decrease of 5% from US$113.34 per bbl
for the six months ended June 30, 2012. Brent averaged US$102.44 per
bbl for the second quarter of 2013, a decrease of 5% from US$108.21
per bbl for the second quarter of 2012, and a decrease of 9% from
US$112.43 per bbl for the first quarter of 2013.  
The Brent differential from WTI tightened for the three and six
months ended June 30, 2013 from the comparable periods due to
incremental pipeline capacity reflecting a continued debottlenecking
of logistical constraints from Cushing to the US Gulf Coast.  
The WCS Heavy Differential averaged 27% for the six months ended June
30, 2013 compared with 23% for the six months ended June 30, 2012.
The WCS Heavy Differential averaged 20% for the second quarter of
2013 compared with 24% for the second quarter of 2012, and 34% for
the first quarter of 2013. The WCS Heavy Differential tightened in
the second quarter of 2013 from the comparable periods as a result of
increased seasonal heavy oil demand and increased pipeline capacity
as pipeline reliability in the second quarter of 2013 improved. The
WCS Heavy Differential per barrel tightened in July 2013 to average
US$14.20 per bbl and in August 2013 to average US$15.57 per bbl. To
partially mitigate its exposure to widening heavy crude oil
differentials, as at June 30, 2013, the Company has entered into
physical crude oil sales contracts with weighted average fixed WCS
differentials as follows: 20,000 bbl/d in the third quarter of 2013
at US$21.27 per bbl; 15,000 bbl/d in the fourth quarter of 2013 at
US$21.52 per bbl; 8,000 bbl/d in the first quarter of 2014 at
US$21.89 per bbl; 9,000 bbl/d in the second quarter of 2014 at
US$21.93 per bbl; and 10,000 bbl/d in the third and fourth quarters
of 2014 at US$20.81.  
The SCO price averaged US$97.18 per bbl for the six months ended June
30, 2013, an increase of 4% from US$93.82 per bbl for the six months
ended June 30, 2012. The SCO price averaged US$99.10 per bbl for the
second quarter of 2013, an increase of 11% from US$89.54 per bbl for
the second quarter of 2012, and an increase of 4% from US$95.24 per
bbl for the first quarter of 2013. The increase in SCO pricing for
the three and six months ended June 30, 2013 from the comparable
periods was due to planned and unplanned shutdowns of various
upgrading facilities in Northern Alberta.  
The Company uses condensate as a blending diluent for heavy crude oil
pipeline shipments. During the second quarter of 2013, condensate
price premiums to WTI narrowed, 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$3.72 per MMBtu for the six
months ended June 30, 2013, an increase of 48% from US$2.52 per MMBtu
for the six months ended June 30, 2012. NYMEX natural gas prices
averaged US$4.09 per MMBtu for the second quarter of 2013, an
increase of 81% from US$2.26 per MMBtu for the second quarter of
2012, and an increase of 22% from US$3.35 per MMBtu for the first
quarter of 2013.  
AECO natural gas prices for the six months ended June 30, 2013
averaged $3.16 per GJ, an increase of 53% from $2.06 per GJ for the
six months ended June 30, 2012. AECO natural gas prices for the
second quarter of 2013 averaged $3.41 per GJ, an increase of 96% from
$1.74 per GJ for the second quarter of 2012, and an increase of 17%
from $2.92 per GJ for the first quarter of 2013.  
During the second quarter of 2013, natural gas prices continued to
recover from the low pricing levels in 2012. A steady North America
production supply forecast and a return to normal winter weather in
North America in 2013 has allowed natural gas inventories to return
to seasonal levels.  
The Company continues to focus on its crude oil marketing strategy
including a blending strategy that expands markets within current
pipeline infrastructure, supporting pipeline projects that provide
crude oil transportation to new markets, and supporting incremental
heavy crude oil conversion capacity. Subsequent to June 30, 2013, the
Company entered into a 20 year transportation agreement to ship
80,000 bbl/d of crude oil on the proposed Energy East pipeline,
subject to regulatory approval.  
DAILY PRODUCTION, before royalties 


 
                             Three Months Ended          Six Months Ended   
                     -----------                      -----------           
                         Jun 30     Mar 31     Jun 30     Jun 30     Jun 30 
                           2013       2013       2012       2013       2012 
----------------------------------------------------------------------------
Crude oil and NGLs                                                          
 (bbl/d)                                                                    
North America -                                                             
 Exploration and                                                            
 Production             331,453    345,489    316,483    338,433    311,048 
North America - Oil                                                         
 Sands Mining and                                                           
 Upgrading               67,954    108,782    115,823     88,255     80,957 
North Sea                18,901     18,774     17,619     18,838     20,333 
Offshore Africa          18,055     16,112     20,598     17,089     20,655 
----------------------------------------------------------------------------
                        436,363    489,157    470,523    462,615    432,993 
----------------------------------------------------------------------------
Natural gas (MMcf/d)                                                        
North America             1,092      1,125      1,230      1,108      1,255 
North Sea                     4          1          2          3          2 
Offshore Africa              26         24         23         25         20 
----------------------------------------------------------------------------
                          1,122      1,150      1,255      1,136      1,277 
----------------------------------------------------------------------------
Total barrels of oil                                                        
 equivalent (BOE/d)     623,315    680,844    679,607    651,921    645,943 
----------------------------------------------------------------------------
Product mix                                                                 
Light and medium                                                            
 crude oil and NGLs          16%        15%        15%        15%        15%
Pelican Lake heavy                                                          
 crude oil                    7%         5%         5%         6%         6%
Primary heavy crude                                                         
 oil                         22%        20%        18%        21%        19%
Bitumen (thermal oil)        14%        16%        14%        15%        14%
Synthetic crude oil          11%        16%        17%        14%        13%
Natural gas                  30%        28%        31%        29%        33%
----------------------------------------------------------------------------
Percentage of product                                                       
 sales (1) (2)                                                              
 (excluding midstream                                                       
 revenue)                                                                   
Crude oil and NGLs           88%        89%        93%        89%        92%
Natural gas                  12%        11%         7%        11%         8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Net of blending costs and excluding risk management activities.  
(2) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.  
DAILY PRODUCTION, net of royalties 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
                            2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Crude oil and NGLs                                                          
 (bbl/d)                                                                    
North America -                                                             
 Exploration and                                                            
 Production              274,850    289,992    272,089    282,379    263,020
North America - Oil                                                         
 Sands Mining and                                                           
 Upgrading                65,077    104,203    109,569     84,532     76,584
North Sea                 18,839     18,706     17,578     18,773     20,282
Offshore Africa           14,974     13,603     15,051     14,292     16,274
----------------------------------------------------------------------------
                         373,740    426,504    414,287    399,976    376,160
----------------------------------------------------------------------------
Natural gas (MMcf/d)                                                        
North America              1,016      1,092      1,218      1,054      1,247
North Sea                      4          1          2          3          2
Offshore Africa               22         20         19         21         17
----------------------------------------------------------------------------
                           1,042      1,113      1,239      1,078      1,266
----------------------------------------------------------------------------
Total barrels of oil                                                        
 equivalent (BOE/d)      547,330    612,062    620,700    579,600    587,226
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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, primary heavy crude oil, Pelican Lake heavy crude oil,
bitumen (thermal oil) and SCO.  
Crude oil and NGLs production for the six months ended June 30, 2013
increased 7% to 462,615 bbl/d from 432,993 bbl/d for the six months
ended June 30, 2012. Crude oil and NGLs production for the second
quarter of 2013 decreased 7% to 436,363 bbl/d from 470,523 bbl/d for
the second quarter of 2012 and decreased 11% from 489,157 bbl/d for
the first quarter of 2013. The increase in production for the six
months ended June 30, 2013 from the comparable period in 2012 was
primarily due to the impact of a strong heavy crude oil drilling
program, and the increased production from the Company's cyclic
thermal operations and Horizon. The decrease in production for the
second quarter of 2013 from the comparable periods was primarily due
to the decrease in production volumes resulting from Horizon's
planned maintenance turnaround in May 2013 and from fluctuations in
the Company's cyclic thermal operations, partially offset by the
impact of a strong heavy crude oil drilling program. Crude oil and
NGLs production in the second quarter of 2013 was within the
Company's previously issued guidance of 435,000 to 461,000 bbl/d.  
Natural gas production for the six months ended June 30, 2013
decreased 11% to 1,136 MMcf/d from 1,277 MMcf/d for the six months
ended June 30, 2012. Natural gas production for the second quarter of
2013 decreased 11% to 1,122 MMcf/d from 1,255 MMcf/d for the second
quarter of 2012 and decreased 2% from 1,150 MMcf/d for the first
quarter of 2013. The decrease in natural gas production for the three
and six months ended June 30, 2013 from the comparable periods was
primarily a result of a strategic reduction of natural gas drilling
as the Company allocated capital to higher return crude oil projects,
as well as expected production declines. Natural gas production in
the second quarter of 2013 exceeded the Company's previously issued
guidance of 1,090 to 1,110 MMcf/d.  
For 2013, annual production guidance is targeted to average between
482,000 and 513,000 bbl/d of crude oil and NGLs and between 1,085 and
1,145 MMcf/d of natural gas. Third quarter 2013 production guidance
is targeted to average between 506,000 and 529,000 bbl/d of crude oil
and NGLs and between 1,135 and 1,155 MMcf/d of natural gas.  
North America - Exploration and Production  
North America crude oil and NGLs production for the six months ended
June 30, 2013 increased 9% to average 338,433 bbl/d from 311,048
bbl/d for the six months ended June 30, 2012. For the second quarter
of 2013, crude oil and NGLs production increased 5% to average
331,453 bbl/d compared with 316,483 bbl/d for the second quarter of
2012 and decreased 4% from 345,489 bbl/d for the first quarter of
2013. The increase in crude oil and NGLs production for the three and
six months ended June 30, 2013 from the comparable periods in 2012
was primarily due to the impact of a strong heavy crude oil drilling
program. The decrease for the second quarter of 2013 from the first
quarter of 2013 was primarily due to the decrease in production from
the Company's cyclic thermal operations. Second quarter 2013
production of crude oil and NGLs was within the Company's previously
issued guidance of 326,000 to 342,000 bbl/d. Third quarter 2013
production guidance is targeted to average between 365,000 and
380,000 bbl/d for crude oil and NGLs.  
Natural gas production for the six months ended June 30, 2013
decreased 12% to 1,108 MMcf/d compared with 1,255 MMcf/d for the six
months ended June 30, 2012. Natural gas production decreased 11% to
1,092 MMcf/d for the second quarter of 2013 compared with 1,230
MMcf/d in the second quarter of 2012 and decreased 3% from 1,125
MMcf/d for the first quarter of 2013. The decrease in natural gas
production for the three and six months ended June 30, 2013 from the
comparable periods was primarily a result of a strategic reduction of
natural gas drilling as the Company allocated capital to higher
return crude oil projects, as well as expected production declines.  
North America - Oil Sands Mining and Upgrading  
Production averaged 88,255 bbl/d for the six months ended June 30,
2013 compared with 80,957 bbl/d for the six months ended June 30,
2012. For the second quarter of 2013, SCO production averaged 67,954
bbl/d compared with 115,823 bbl/d for the second quarter of 2012 and
108,782 bbl/d for the first quarter of 2013. Production increased for
the six months ended June 30, 2013 from the comparable period due to
the unplanned maintenance completed during the first quarter of 2012.
Second quarter 2013 production reflected the impact of the planned
maintenance turnaround. Due to a 6 day extension of the planned
turnaround to 30 days from the 24 days originally forecasted, SCO
production was below the Company's previously issued guidance of
77,000 to 83,000 bbl/d for the second quarter of 2013. Third quarter
2013 production guidance is targeted to average between 110,000 and
115,000 bbl/d. Annual 2013 production guidance remains unchanged and
is targeted to average between 100,000 and 108,000 bbl/d.  
North Sea  
North Sea crude oil production for the six months ended June 30, 2013
decreased 7% to 18,838 bbl/d from 20,333 bbl/d for the six months
ended June 30, 2012. Second quarter 2013 North Sea crude oil
production increased 7% to 18,901 bbl/d compared with 17,619 bbl/d
for the second quarter of 2012, and was comparable with the first
quarter of 2013. The decrease in production for the six months ended
June 30, 2013 from the comparable period was primarily due to natural
field declines and a reduction in drilling activities as a result of
an increase in the UK corporate income tax rate in 2011. The increase
in production for the second quarter of 2013 from the second quarter
of 2012 was primarily due to higher production from both the Tiffany
and Ninian fields in 2013, as well as the temporary shut in of the
third-party operated pipeline to Sullom Voe for unplanned maintenance
for a portion of 2012, which caused all Ninian and associated fields
to be shut in.  
The Company received approval for the Brownfield Allowance for the
Tiffany field in January 2013 and as a result, during the second
quarter the Company drilled one injector well and one additional
production well, which came on at Tiffany with production of
approximately 1,500 bbl/d, exceeding original forecasted volumes.
During the second quarter of 2013, the Company also completed its
consolidation of a working interest in a satellite field at the
Ninian hub.  
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. The FPSO and associated
floating storage unit were subsequently removed from the field and
the FPSO is currently undergoing repairs and is targeted to be back
in the field in the first half of 2014. The associated repair costs,
net of insurance recoveries, are not expected to be significant.  
Offshore Africa  
Offshore Africa crude oil production decreased 17% to 17,089 bbl/d
for the six months ended June 30, 2013 from 20,655 bbl/d for the six
months ended June 30, 2012. Second quarter 2013 crude oil production
averaged 18,055 bbl/d, decreasing 12% from 20,598 bbl/d for the
second quarter of 2012 and increasing 12% from 16,112 bbl/d for the
first quarter of 2013. The decrease in production volumes for the
three and six months ended June 30, 2013 from the comparable periods
in 2012 was due to natural field declines and lower production from
Gabon. The increase in production volumes for the second quarter of
2013 from the first quarter of 2013 was due to the stabilization of
the midwater arch and the reinstatement of production at the Olowi
field in Gabon late in the first quarter of 2013. The final repairs
and assessment have been made and issues relating to the long-term
operability of the midwater arch have been resolved.  
International Guidance  
The Company's North Sea and Offshore Africa second quarter 2013 crude
oil and NGLs production exceeded the Company's previously issued
guidance of 32,000 to 36,000 bbl/d. Third quarter 2013 production
guidance is targeted to average between 31,000 and 34,000 bbl/d of
crude oil and NGLs.  
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 FPSOs, as follows: 


 
                                           -----------                      
                                                Jun 30     Mar 31     Dec 31
(bbl)                                             2013       2013       2012
----------------------------------------------------------------------------
North America - Exploration and Production     691,583    811,181    643,758
North America - Oil Sands Mining and                                        
 Upgrading (SCO)                             1,061,417  1,334,054    993,627
North Sea                                      583,227    409,333     77,018
Offshore Africa                                811,742    829,793  1,036,509
----------------------------------------------------------------------------
                                             3,147,969  3,384,361  2,750,912
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
                            2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Crude oil and NGLs                                                          
 ($/bbl) (1)                                                                
Sales price (2) (3)   $    75.10 $    60.87 $    72.12 $    67.94 $    77.14
Transportation              2.32       2.37       2.13       2.34       2.19
----------------------------------------------------------------------------
Realized sales price,                                                       
 net of                                                                     
 transportation            72.78      58.50      69.99      65.60      74.95
Royalties                  11.60       8.76       9.18      10.17      11.10
Production expense         16.51      17.56      16.66      17.04      16.72
----------------------------------------------------------------------------
Netback               $    44.67 $    32.18 $    44.15 $    38.39 $    47.13
----------------------------------------------------------------------------
Natural gas ($/Mcf)                                                         
 (1)                                                                        
Sales price (2) (3)   $     4.05 $     3.51 $     2.15 $     3.78 $     2.44
Transportation              0.29       0.29       0.25       0.29       0.25
----------------------------------------------------------------------------
Realized sales price,                                                       
 net of                                                                     
 transportation             3.76       3.22       1.90       3.49       2.19
Royalties                   0.28       0.12       0.05       0.20       0.05
Production expense          1.41       1.53       1.15       1.48       1.25
----------------------------------------------------------------------------
Netback               $     2.07 $     1.57 $     0.70 $     1.81 $     0.89
----------------------------------------------------------------------------
Barrels of oil                                                              
 equivalent ($/BOE)                                                         
 (1)                                                                        
Sales price (2) (3)   $    58.49 $    47.90 $    51.14 $    53.16 $    54.19
Transportation              2.18       2.21       1.97       2.20       2.01
----------------------------------------------------------------------------
Realized sales price,                                                       
 net of                                                                     
 transportation            56.31      45.69      49.17      50.96      52.18
Royalties                   8.29       6.05       5.93       7.16       7.08
Production expense         13.81      14.74      13.06      14.28      13.24
----------------------------------------------------------------------------
Netback               $    34.21 $    24.90 $    30.18 $    29.52 $    31.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
(2) Net of blending costs and excluding risk management activities.  
(3) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.  
PRODUCT PRICES - EXPLORATION AND PRODUCTION 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
                            2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Crude oil and NGLs                                                          
 ($/bbl) (1)(2) (3)                                                         
North America         $    71.81 $    55.68 $    67.44 $    63.66 $    71.99
North Sea             $   104.47 $   114.28 $   109.60 $   109.05 $   114.53
Offshore Africa       $   107.71 $   113.70 $   106.30 $   110.70 $   116.09
Company average       $    75.10 $    60.87 $    72.12 $    67.94 $    77.14
                                                                            
Natural gas ($/Mcf)                                                         
 (1)(2) (3)                                                                 
North America         $     3.90 $     3.37 $     1.99 $     3.63 $     2.32
North Sea             $     7.03 $     3.65 $     5.41 $     6.15 $     5.19
Offshore Africa       $    10.02 $    10.24 $    10.68 $    10.13 $    10.39
Company average       $     4.05 $     3.51 $     2.15 $     3.78 $     2.44
                                                                            
Company average                                                             
 ($/BOE) (1)(2) (3)   $    58.49 $    47.90 $    51.14 $    53.16 $    54.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
(2) Net of blending costs and excluding risk management activities.  
(3) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.  
North America  
North America realized crude oil prices decreased 12% to average
$63.66 per bbl for the six months ended June 30, 2013 from $71.99 per
bbl for the six months ended June 30, 2012. North America realized
crude oil prices averaged $71.81 per bbl for the second quarter of
2013, an increase of 6% compared with $67.44 per bbl for the second
quarter of 2012 and an increase of 29% compared with $55.68 per bbl
for the first quarter of 2013. The decrease in realized crude oil
prices for the six months ended June 30, 2013 from the comparable
period was due to the widening of the WCS Heavy Differential, lower
WTI benchmark pricing, and higher diluent blending costs, partially
offset by the impact of a weaker Canadian dollar relative to the US
dollar. The increase in realized crude oil prices for the second
quarter of 2013 from the comparable periods was due to the impact of
the tightening of the WCS Heavy Differential and the weaker Canadian
dollar relative to the US dollar. The Company continues to focus on
its crude oil blending marketing strategy and in the second quarter
of 2013 contributed approximately 172,000 bbl/d of heavy crude oil
blends to the WCS stream.  
North America realized natural gas prices increased 56% to average
$3.63 per Mcf for the six months ended June 30, 2013 from $2.32 per
Mcf for the six months ended June 30, 2012. North America realized
natural gas prices increased 96% to average $3.90 per Mcf for the
second quarter of 2013 compared with $1.99 per Mcf in the second
quarter of 2012, and increased 16% compared with $3.37 per Mcf for
the first quarter of 2013. The increase in realized natural gas
prices for the three and six months ended June 30, 2013 from the
comparable periods was primarily due to higher AECO benchmark pricing
related to the impact of a steady North America production supply
forecast and a return to normal winter weather in North America in
2013, that has allowed natural gas inventories to return to seasonal
levels. 
Comparisons of the prices received in North America Exploration and
Production by product type were as follows: 


 
                                           -----------                      
                                                Jun 30     Mar 31     Jun 30
(Quarterly Average)                               2013       2013       2012
----------------------------------------------------------------------------
Wellhead Price(1) (2) (3)                                                   
Light and medium crude oil and NGLs ($/bbl) $    78.15 $    73.77 $    71.56
Pelican Lake heavy crude oil ($/bbl)        $    75.17 $    54.41 $    66.13
Primary heavy crude oil ($/bbl)             $    71.75 $    51.45 $    66.15
Bitumen (thermal oil) ($/bbl)               $    65.99 $    50.42 $    66.88
Natural gas ($/Mcf)                         $     3.90 $     3.37 $     1.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
(2) Net of blending costs and excluding risk management activities.  
(3) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.  
North Sea  
North Sea realized crude oil prices decreased 5% to average $109.05
per bbl for the six months ended June 30, 2013 from $114.53 per bbl
for the six months ended June 30, 2012. Realized crude oil prices
decreased 5% to average $104.47 per bbl for the second quarter of
2013 from $109.60 per bbl for the second quarter of 2012, and
decreased 9% from $114.28 per bbl for the first quarter of 2013. The
fluctuations in realized crude oil prices for the three and six
months ended June 30, 2013 from the comparable periods reflected
movements in Brent benchmark pricing, the timing of liftings, and the
weakening of the Canadian dollar. 
Offshore Africa  
Offshore Africa realized crude oil prices decreased 5% to average
$110.70 per bbl for the six months ended June 30, 2013 from $116.09
per bbl for the six months ended June 30, 2012. Realized crude oil
prices increased 1% to average $107.71 per bbl for the second quarter
of 2013 from $106.30 per bbl for the second quarter of 2012, and
decreased 5% from $113.70 per bbl for the first quarter of 2013. The
fluctuations in realized crude oil prices for the three and six
months ended June 30, 2013 from the comparable periods reflected
movements in Brent benchmark pricing, the timing of liftings, and the
weakening of the Canadian dollar.  
ROYALTIES - EXPLORATION AND PRODUCTION 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
                            2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Crude oil and NGLs                                                          
 ($/bbl) (1)                                                                
North America         $    11.81 $     8.65 $     8.33 $    10.21 $    10.99
North Sea             $     0.34 $     0.41 $     0.26 $     0.37 $     0.28
Offshore Africa       $    18.38 $    17.71 $    28.63 $    18.05 $    24.90
Company average       $    11.60 $     8.76 $     9.18 $    10.17 $    11.10
                                                                            
Natural gas ($/Mcf)                                                         
 (1)                                                                        
North America         $     0.25 $     0.09 $     0.02 $     0.17 $     0.02
Offshore Africa       $     1.68 $     1.57 $     1.86 $     1.63 $     1.72
Company average       $     0.28 $     0.12 $     0.05 $     0.20 $     0.05
                                                                            
Company average                                                             
 ($/BOE) (1)          $     8.29 $     6.05 $     5.93 $     7.16 $     7.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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 six months
ended June 30, 2013 compared with the six months ended June 30, 2012
reflected movements in benchmark commodity prices and the
fluctuations of the WCS Heavy Differential.  
Crude oil and NGLs royalties averaged approximately 17% of product
sales for the second quarter of 2013 compared with 13% for the second
quarter of 2012 and 16% for the first quarter of 2013. The increase
in royalties from the second quarter of 2012 was primarily due to the
increase in realized crude oil and NGLs prices. Crude oil and NGLs
royalties per bbl are anticipated to average 16% to 18% of product
sales for 2013.  
Natural gas royalties averaged approximately 7% of product sales for
the second quarter of 2013 compared with 1% for the second quarter of
2012 and 3% for the first quarter of 2013. The increase in natural
gas royalty rates from the second quarter of 2012 was primarily the
result of the increase in realized natural gas prices. The increase
from the first quarter of 2013 was primarily the result of the
increase in realized natural gas prices, as well as gas cost
allowance adjustments in the first quarter of 2013. Natural gas
royalties are anticipated to average 4% to 6% of product sales for
2013.  
Offshore Africa  
Under the terms of the various Production Sharing Contracts, royalty
rates fluctuate based on realized commodity pricing, capital and
operating costs, the status of payouts, and the timing of liftings
from each field.  
Royalty rates as a percentage of product sales averaged approximately
17% for the second quarter of 2013 compared with 26% for the second
quarter of 2012 and 16% for the first quarter of 2013. The decrease
in royalties from the second quarter of 2012 was due to adjustments
to royalties on liftings during 2012.  
Offshore Africa royalty rates are anticipated to average 12% to 14%
of product sales for 2013. 
PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
                            2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Crude oil and NGLs                                                          
 ($/bbl) (1)                                                                
North America         $    14.83 $    14.61 $    13.10 $    14.72 $    14.23
North Sea             $    47.85 $    74.65 $    68.32 $    60.38 $    50.21
Offshore Africa       $    17.98 $    25.72 $    22.94 $    21.84 $    18.29
Company average       $    16.51 $    17.56 $    16.66 $    17.04 $    16.72
                                                                            
Natural gas ($/Mcf)                                                         
 (1)                                                                        
North America         $     1.38 $     1.52 $     1.13 $     1.45 $     1.24
North Sea             $     3.53 $     3.77 $     3.89 $     3.59 $     3.94
Offshore Africa       $     2.34 $     2.24 $     1.78 $     2.30 $     1.77
Company average       $     1.41 $     1.53 $     1.15 $     1.48 $     1.25
                                                                            
Company average                                                             
 ($/BOE) (1)          $    13.81 $    14.74 $    13.06 $    14.28 $    13.24
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
North America  
North America crude oil and NGLs production expense for the six
months ended June 30, 2013 increased 3% to $14.72 per bbl from $14.23
per bbl for the six months ended June 30, 2012. North America crude
oil and NGLs production expense for the second quarter of 2013
increased 13% to $14.83 per bbl from $13.10 per bbl for the second
quarter of 2012 and increased 2% from $14.61 per bbl for the first
quarter of 2013. The increase in production expense for the three and
six months ended June 30, 2013 from the comparable periods in 2012
was primarily the result of higher electricity costs, as well as
higher trucking costs related to extended seasonal conditions in
heavy oil production. The increase in production expense for the
second quarter of 2013 from the first quarter of 2013 was primarily a
result of higher electricity costs and extended spring season
conditions. North America crude oil and NGLs production expense
guidance remains unchanged from the previously issued guidance of
$12.00 to $14.00 per bbl for 2013.  
North America natural gas production expense for the six months ended
June 30, 2013 increased 17% to $1.45 per Mcf from $1.24 per Mcf for
the six months ended June 30, 2012. North America natural gas
production expense for the second quarter of 2013 increased 22% to
$1.38 per Mcf from $1.13 per Mcf for the second quarter of 2012 and
decreased 9% from $1.52 per Mcf for the first quarter of 2013.
Natural gas production expense increased for the three and six months
ended June 30, 2013 from the comparable periods in 2012 primarily due
to higher electricity costs along with lower production volumes
related to the reduction in natural gas activity. Natural gas
production expense decreased for the second quarter of 2013 from the
first quarter of 2013 due to normal seasonality. North America
natural gas production expense is anticipated to average $1.35 to
$1.40 per Mcf for 2013.  
North Sea  
North Sea crude oil production expense for the six months ended June
30, 2013 increased 20% to $60.38 per bbl from $50.21 per bbl for the
six months ended June 30, 2012. North Sea crude oil production
expense for the second quarter of 2013 decreased 30% to $47.85 per
bbl from $68.32 per bbl for the second quarter of 2012 and decreased
36% from $74.65 per bbl for the first quarter of 2013. Production
expense increased on a per barrel basis for the six months ended June
30, 2013 from the comparable period due to the impact of production
declines on relatively fixed costs as well as higher maintenance
activity and increased fuel costs. Production expense decreased for
the second quarter of 2013 from the comparable periods due to
increased production volumes on relatively fixed costs and the timing
of liftings from various fields, which have different cost
structures. North Sea crude oil production expense is anticipated to
average $62.00 to $66.00 per bbl for 2013 due to natural declines on
a relatively fixed cost structure.  
Offshore Africa  
Offshore Africa crude oil production expense for the six months ended
June 30, 2013 increased 19% to $21.84 per bbl from $18.29 per bbl for
the six months ended June 30, 2012. Offshore Africa crude oil
production expense for the second quarter of 2013 averaged $17.98 per
bbl, a decrease of 22% from $22.94 per bbl for the second quarter of
2012, and a decrease of 30% from $25.72 per bbl for the first quarter
of 2013. Production expense fluctuated for the three and six months
ended June 30, 2013 from the comparable periods as a result of the
timing of liftings from various fields, which have different cost
structures. Offshore Africa crude oil production expense is
anticipated to average $30.00 to $34.00 per bbl for 2013 due to
timing of liftings from various fields, which have different cost
structures.  
DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND PRODUCTION 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
                            2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Expense ($ millions)  $    1,009 $    1,023 $      936 $    2,032 $    1,846
  $/BOE (1)           $    19.97 $    19.99 $    18.13 $    19.98 $    17.93
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
Depletion, depreciation and amortization expense increased for the
three and six months ended June 30, 2013 compared with 2012 due to
higher sales volumes in North America associated with heavy oil
drilling and higher overall future development costs. The decrease in
depletion, depreciation and amortization expense for the second
quarter of 2013 from the first quarter of 2013 was primarily due to
lower sales volumes in North America.  
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND PRODUCTION 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
                            2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Expense ($ millions)  $       33 $       34 $       30 $       67 $       59
  $/BOE (1)           $     0.65 $     0.66 $     0.59 $     0.65 $     0.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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  
The Company continues to focus on efficient and effective operations
at Horizon and place emphasis on safe, steady, reliable operations.
In May 2013, the Company successfully completed a planned maintenance
turnaround. During the outage, all major scopes of work were
completed including the change out of the catalysts in the
hydro-treating units. Repairs to certain equipment extended slightly
beyond the original forecasted timeframe. The impact of the
turnaround has been reflected in the Company's 2013 production, cash
production cost and capital expenditure guidance.  
PRODUCT PRICES, ROYALTIES AND TRANSPORTATION - OIL SANDS MINING AND
UPGRADING 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
($/bbl) (1)                 2013       2013       2012       2013       2012
----------------------------------------------------------------------------
SCO sales price (2)   $    99.63 $    96.19 $    89.76 $    97.58 $    93.62
Bitumen value for                                                           
 royalty purposes (3) $    61.08 $    60.47 $    59.83 $    60.71 $    62.10
Bitumen royalties (4) $     4.41 $     3.81 $     5.20 $     4.05 $     5.19
Transportation        $     1.72 $     1.58 $     1.65 $     1.64 $     1.78
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes
excluding the period of turnaround/suspension of production.  
(2) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.  
(3) Calculated as the quarterly average of the 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 $97.58 per bbl for the six months
ended June 30, 2013, an increase of 4% compared with $93.62 per bbl
for six months ended June 30, 2012. Realized SCO sales prices
averaged $99.63 per bbl for the second quarter of 2013, an increase
of 11% compared with $89.76 per bbl for the second quarter of 2012
and an increase of 4% compared with $96.19 per bbl for the first
quarter of 2013, reflecting benchmark pricing and prevailing
differentials.  
CASH 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         Six Months Ended   
                      ----------------------------------------------------- 
                          Jun 30     Mar 31     Jun 30    Jun 30     Jun 30 
($ millions)                2013       2013       2012      2013       2012 
----------------------------------------------------------------------------
Cash production costs  $     394  $     377 $      388 $     771  $     734 
Less: costs incurred                                                        
 during the period of                                                       
 turnaround/suspension                                                      
 of production              (104)         -          -      (104)      (154)
----------------------------------------------------------------------------
Adjusted cash                                                               
 production costs      $     290  $     377 $      388 $     667  $     580 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Adjusted cash                                                               
 production costs,                                                          
 excluding natural gas                                                      
 costs                 $     268  $     349 $      362 $     617  $     539 
Adjusted natural gas                                                        
 costs                        22         28         26        50         41 
----------------------------------------------------------------------------
Adjusted cash                                                               
 production costs      $     290  $     377 $      388 $     667  $     580 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
($/bbl) (1)                 2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Adjusted cash                                                               
 production costs,                                                          
 excluding natural                                                          
 gas costs            $    41.53 $    36.95 $    34.45 $    38.81 $    36.79
Adjusted natural gas                                                        
 costs                      3.41       2.98       2.53       3.15       2.82
----------------------------------------------------------------------------
Adjusted cash                                                               
 production costs     $    44.94 $    39.93 $    36.98 $    41.96 $    39.61
----------------------------------------------------------------------------
Sales (bbl/d) (2)         70,950    105,000    115,552     87,881     80,646
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Adjusted cash production costs on a per unit basis were based on
sales volumes excluding the period of turnaround/suspension of
production.  
(2) Sales volumes include the period of turnaround/suspension of
production. 
Adjusted cash production costs averaged $41.96 per bbl for the six
months ended June 30, 2013, an increase of 6% compared with $39.61
per bbl for the six months ended June 30, 2012. Adjusted cash
production costs for the second quarter of 2013 averaged $44.94 per
bbl, an increase of 22% compared with $36.98 per bbl for the second
quarter of 2012 and an increase of 13% compared with $39.93 per bbl
for the first quarter of 2013 primarily due to lower production
volumes excluding the period of turnaround. Cash production costs are
anticipated to average $38.00 to $41.00 per bbl for 2013.  
DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND
UPGRADING 


 
                              Three Months Ended         Six Months Ended   
                      ----------------------------------------------------- 
                          Jun 30     Mar 31     Jun 30    Jun 30     Jun 30 
($ millions)                2013       2013       2012      2013       2012 
----------------------------------------------------------------------------
Depletion,                                                                  
 depreciation and                                                           
 amortization          $     161  $     117 $      146 $     278  $     209 
Less: depreciation                                                          
 incurred during the                                                        
 period of                                                                  
 turnaround/suspension                                                      
 of production               (79)         -          -       (79)        (6)
----------------------------------------------------------------------------
Adjusted depletion,                                                         
 depreciation and                                                           
 amortization          $      82  $     117 $      146 $     199  $     203 
----------------------------------------------------------------------------
  $/bbl (1)            $   12.70  $   12.35 $    13.84 $   12.49  $   13.83 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes
excluding the period of turnaround/suspension of production.  
Depletion, depreciation and amortization expense reflected the impact
of fluctuations in sales volumes.  
ASSET RETIREMENT OBLIGATION ACCRETION - OIL SANDS MINING AND
UPGRADING 


 
                             Three Months Ended           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
 ($ millions)               2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Expense               $        9 $        8 $        8 $       17 $       16
  $/bbl (1)           $     1.32 $     0.90 $     0.76 $     1.07 $     1.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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           Six Months Ended  
                     -----------                      -----------           
                          Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
($ millions)                2013       2013       2012       2013       2012
----------------------------------------------------------------------------
Revenue               $       29 $       27 $       22 $       56 $       43
Production expense             9          8          7         17         14
----------------------------------------------------------------------------
Midstream cash flow           20         19         15         39         29
Depreciation                   2          2          2          4          4
Equity loss from                                                            
 jointly controlled                                                         
 entity                        -          2          5          2          5
----------------------------------------------------------------------------
Segment earnings                                                            
 before taxes         $       18 $       15 $        8 $       33 $       20
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Midstream operating results were consistent with the comparable
periods.  
The Company has a 50% interest in the North West Redwater Partnership
("Redwater"). Redwater has entered into agreements to construct and
operate a 50,000 barrel per day bitumen upgrader and refinery (the
"Project") under processing agreements that target to process 12,500
barrels per day of bitumen feedstock for the Company and 37,500
barrels per day of bitumen feedstock for the Alberta Petroleum
Marketing Commission, an agent of the Government of Alberta, under a
30 year fee-for-service tolling agreement. During 2012, the Project
received board sanction from Redwater and its partners. 
ADMINISTRATION EXPENSE 


 
                         Three Months Ended             Six Months Ended    
                ------------                        ------------            
                      Jun 30      Mar 31      Jun 30      Jun 30      Jun 30
($ millions)            2013        2013        2012        2013        2012
----------------------------------------------------------------------------
Expense          $        81 $        79 $        77 $       160 $       142
 $/BOE (1)       $      1.43 $      1.30 $      1.24 $      1.36 $      1.20
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
Administration expense for the three and six months ended June 30,
2013 increased from the comparable periods primarily due to higher
staffing related costs and general corporate costs.  
SHARE-BASED COMPENSATION  


 
                       Three Months Ended              Six Months Ended     
             ------------                          ------------             
                   Jun 30       Mar 31      Jun 30       Jun 30      Jun 30 
($ millions)         2013         2013        2012         2013        2012 
----------------------------------------------------------------------------
(Recovery)                                                                  
 expense      $       (49) $        71 $      (115) $        22 $      (222)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 $22 million share-based compensation expense
for the six months ended June 30, 2013, primarily as a result of
remeasurement of the fair value of outstanding stock options at the
end of the period related to an increase in the Company's share
price, together with the impact of 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 six
months ended June 30, 2013, the Company capitalized $5 million in
respect of share-based compensation expense to Oil Sands Mining and
Upgrading (June 30, 2012 - $15 million recovery).  
For the six months ended June 30, 2013, the Company paid $1 million
for stock options surrendered for cash settlement (June 30, 2012 - $7
million). 
INTEREST AND OTHER FINANCING COSTS 


 
                         Three Months Ended             Six Months Ended    
                ------------            --          ------------            
($ millions,                                                                
 except per BOE      Jun 30      Mar 31      Jun 30      Jun 30      Jun 30 
 amounts)              2013        2013        2012        2013        2012 
----------------------------------------------------------------------------
Expense, gross   $      112  $      113  $      114  $      225  $      228 
Less:                                                                       
 capitalized                                                                
 interest                40          36          21          76          39 
----------------------------------------------------------------------------
Expense, net     $       72  $       77  $       93  $      149  $      189 
 $/BOE (1)       $     1.26  $     1.27  $     1.50  $     1.27  $     1.61 
Average                                                                     
 effective                                                                  
 interest rate          4.3%        4.5%        4.8%        4.4%        4.8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
Gross interest and other financing costs for the three and six months
ended June 30, 2013 were consistent with the comparable periods.
Capitalized interest of $76 million for the six months ended June 30,
2013 was related to the Horizon Phase 2/3 expansion and the Kirby
Thermal Oil Sands Project, which includes the Kirby South Project. 
The Company's average effective interest rate for the three and six
months ended June 30, 2013 decreased from the comparable periods in
2012 primarily due to the repayment of $400 million of 4.50%
medium-term notes and US$400 million of 5.15% unsecured notes during
the first quarter of 2013 and US$350 million of 5.45% unsecured notes
in the fourth quarter of 2012. This indebtedness was retired
utilizing cash flow from operations generated in excess of capital
expenditures and available bank credit facilities, while maintaining
the ongoing dividend program. The Company's average effective
interest rate for the second quarter of 2013 decreased from the first
quarter of 2013 primarily due to an increase in the utilization of
the US commercial paper program during the second quarter of 2013. 
RISK MANAGEMENT ACTIVITIES  
The Company utilizes various derivative financial instruments to
manage its commodity price, foreign currency and interest rate
exposures. These derivative financial instruments are not intended
for trading or speculative purposes. 


 
                         Three Months Ended             Six Months Ended    
                ------------                        ------------            
                     Jun 30      Mar 31      Jun 30      Jun 30      Jun 30 
($ millions)           2013        2013        2012        2013        2012 
----------------------------------------------------------------------------
Crude oil and                                                               
 NGLs financial                                                             
 instruments     $        -  $        -  $       19  $        -  $       28 
Foreign currency                                                            
 contracts              (19)        (83)        (80)       (102)          5 
----------------------------------------------------------------------------
Realized (gain)                                                             
 loss                   (19)        (83)        (61)       (102)         33 
----------------------------------------------------------------------------
                                                                            
Crude oil and                                                               
 NGLs financial                                                             
 instruments            (54)         24        (180)        (30)        (84)
Foreign currency                                                            
 contracts              (60)         38          36         (22)          - 
----------------------------------------------------------------------------
Unrealized                                                                  
 (gain) loss           (114)         62        (144)        (52)        (84)
----------------------------------------------------------------------------
Net gain         $     (133) $      (21) $     (205) $     (154) $      (51)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Complete details related to outstanding derivative financial
instruments at June 30, 2013 are disclosed in note 13 to the
Company's unaudited interim consolidated financial statements.  
The Company recorded a net unrealized gain of $52 million ($41
million after-tax) on its risk management activities for the six
months ended June 30, 2013, including an unrealized gain of $114
million ($92 million after-tax) for the second quarter of 2013 (March
31, 2013 - unrealized loss of $62 million; $51 million after-tax;
June 30, 2012 - unrealized gain of $144 million; $103 million
after-tax). 
FOREIGN EXCHANGE 


 
                         Three Months Ended             Six Months Ended    
                 -----------                        ------------            
                      Jun 30     Mar 31      Jun 30      Jun 30      Jun 30 
($ millions)            2013       2013        2012        2013        2012 
----------------------------------------------------------------------------
Net realized loss                                                           
 (gain)           $        1 $      (32) $       (9) $      (31) $       (3)
Net unrealized                                                              
 loss (1)                112         78          71         190          11 
----------------------------------------------------------------------------
Net loss          $      113 $       46  $       62  $      159  $        8 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts are reported net of the hedging effect of cross currency
swaps. 
The net realized foreign exchange gain for the six months ended June
30, 2013 was primarily due to foreign exchange rate fluctuations on
settlement of working capital items denominated in US dollars or UK
pounds sterling and the repayment of US$400 million of 5.15%
unsecured notes in the first quarter of 2013. The net unrealized
foreign exchange loss for the six months ended June 30, 2013 was
primarily related to the impact of the weakening of the Canadian
dollar with respect to remaining US dollar debt and the reversal of
the life-to-date unrealized foreign exchange gain on the repayment of
US$400 million of 5.15% unsecured notes in the first quarter of 2013.
The net unrealized (gain) loss for each of the periods presented
included the impact of cross currency swaps (three months ended June
30, 2013 - unrealized gain of $86 million, March 31, 2013 -
unrealized gain of $49 million, June 30, 2012 - unrealized gain of
$47 million; six months ended June 30, 2013 - unrealized gain of $135
million; June 30, 2012 - unrealized gain of $5 million). The
US/Canadian dollar exchange rate ended the second quarter of 2013 at
US$0.9513 (March 31, 2013 - US$0.9846; December 31, 2012 - US$1.0051;
June 30, 2012 - US$0.9813). 
INCOME TAXES 


 
                         Three Months Ended             Six Months Ended    
                ------------                        ------------            
($ millions,                                                                
 except income       Jun 30      Mar 31      Jun 30      Jun 30      Jun 30 
 tax rates)            2013        2013        2012        2013        2012 
----------------------------------------------------------------------------
North America                                                               
 (1)             $      111  $      122  $      124  $      233  $      237 
North Sea                25          (7)         19          18          64 
Offshore Africa          36          35          64          71         100 
PRT (recovery)                                                              
 expense - North                                                            
 Sea                    (33)        (13)          1         (46)         32 
Other taxes               6           4           5          10          11 
----------------------------------------------------------------------------
Current income                                                              
 tax expense            145         141         213         286         444 
----------------------------------------------------------------------------
Deferred income                                                             
 tax expense                                                                
 (recovery)              44          (4)         59          40          11 
Deferred PRT                                                                
 (recovery)                                                                 
 expense - North                                                            
 Sea                    (13)        (23)          3         (36)         (1)
----------------------------------------------------------------------------
Deferred income                                                             
 tax expense                                                                
 (recovery)              31         (27)         62           4          10 
----------------------------------------------------------------------------
                        176         114         275         290         454 
Income tax rate                                                             
 and other                                                                  
 legislative                                                                
 changes                (15)          -           -         (15)          - 
----------------------------------------------------------------------------
                 $      161  $      114  $      275  $      275  $      454 
----------------------------------------------------------------------------
Effective income                                                            
 tax rate on                                                                
 adjusted net                                                               
 earnings from                                                              
 operations (2)        27.9%       28.1%       27.1%       28.0%       30.1%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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. 
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.  
During the second quarter of 2013, the government of British Columbia
substantively enacted legislation to increase its provincial
corporate income tax rate effective April 1, 2013. As a result of the
income tax rate change, the Company's deferred income tax liability
was increased by $15 million.  
For 2013, based on budgeted prices and the current availability of
tax pools, the Company expects to incur current income tax expense of
$600 million to $700 million in Canada and $40 million to $100
million in the North Sea and Offshore Africa.  
NET CAPITAL EXPENDITURES (1) 


 
                     Three Months Ended              Six Months Ended  
                -----------                      -----------           
                     Jun 30     Mar 31     Jun 30     Jun 30     Jun 30
($ millions)           2013       2013       2012       2013       2012
-----------------------------------------------------------------------
Exploration and                                                        
 Evaluation                                                            
Net expenditures $       10 $       77 $       32 $       87 $      240
-----------------------------------------------------------------------
Property, Plant                                                        
 and Equipment                                                         
Net property                                                           
 acquisitions             -         11          7         11         45
Well drilling,                                                         
 completion and                                                        
 equipping              419        555        352        974        851
Production and                                                         
 related                                                               
 facilities             466        537        445      1,003        950
Capitalized                                                            
 interest and                                                          
 other (2)               29         28         30         57         60
-----------------------------------------------------------------------
Net expenditures        914      1,131        834      2,045      1,906
-----------------------------------------------------------------------
Total                                                                  
 Exploration and                                                       
 Production             924      1,208        866      2,132      2,146
-----------------------------------------------------------------------
Oil Sands Mining                                                       
 and Upgrading                                                         
Horizon Phases                                                         
 2/3                                                                   
 construction                                                          
 costs                  555        355        346        910        538
Sustaining                                                             
 capital                158         51         51        209         88
Turnaround costs         80         17          3         97          5
Capitalized                                                            
 interest and                                                          
 other (2)               22         38          5         60          8
-----------------------------------------------------------------------
Total Oil Sands                                                        
 Mining and                                                            
 Upgrading              815        461        405      1,276        639
-----------------------------------------------------------------------
Midstream                 4          5          4          9          5
Abandonments (3)         37         55         39         92        115
Head office              12          7         10         19         15
-----------------------------------------------------------------------
Total net                                                              
 capital                                                               
 expenditures    $    1,792 $    1,736 $    1,324 $    3,528 $    2,920
-----------------------------------------------------------------------
-----------------------------------------------------------------------
By segment                                                             
North America    $      826 $    1,093 $      788 $    1,919 $    2,011
North Sea                62         85         66        147        120
Offshore Africa          36         30         12         66         15
Oil Sands Mining                                                       
 and Upgrading          815        461        405      1,276        639
Midstream                 4          5          4          9          5
Abandonments (3)         37         55         39         92        115
Head office              12          7         10         19         15
-----------------------------------------------------------------------
Total            $    1,792 $    1,736 $    1,324 $    3,528 $    2,920
-----------------------------------------------------------------------
-----------------------------------------------------------------------

 
(1) 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) 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 six months ended June 30, 2013 were
$3,528 million compared with $2,920 million for the six months ended
June 30, 2012. Net capital expenditures for the second quarter of
2013 were $1,792 million compared with $1,324 million for the second
quarter of 2012 and $1,736 million for the first quarter of 2013.  
The increase in capital expenditures for the three and six months
ended June 30, 2013 from the comparable periods was primarily due to
the ramp up of Horizon site construction activity and the increase in
Horizon turnaround and sustaining capital costs resulting from the
planned maintenance turnaround in May 2013. 
Subsequent to June 30, 2013, the Company acquired all of the issued
and outstanding common shares of Barrick Energy Inc. ("BEI") for
total cash consideration of approximately $173 million. BEI's assets
include working interests in producing crude oil and natural gas
properties and undeveloped land. 
Drilling Activity (number of wells) 


 
                            Three Months Ended           Six Months Ended   
                     -----------                      -----------           
                         Jun 30     Mar 31     Jun 30     Jun 30     Jun 30 
                           2013       2013       2012       2013       2012 
----------------------------------------------------------------------------
Net successful                                                              
 natural gas wells            8         15          4         23         23 
Net successful crude                                                        
 oil wells (1)              159        300        266        459        544 
Dry wells                     5          5          2         10          8 
Stratigraphic test /                                                        
 service wells               16        305          5        321        589 
----------------------------------------------------------------------------
Total                       188        625        277        813      1,164 
Success rate                                                                
 (excluding                                                                 
 stratigraphic test /                                                       
 service wells)              97%        98%        99%        98%        99%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Includes bitumen wells. 
North America  
North America, excluding Oil Sands Mining and Upgrading, accounted
for approximately 57% of the total capital expenditures for the six
months ended June 30, 2013 compared with approximately 73% for the
six months ended June 30, 2012.  
During the second quarter of 2013, the Company targeted 8 net natural
gas wells, including 6 wells in Northeast British Columbia and 2
wells in Northwest Alberta. The Company also targeted 163 net crude
oil wells. The majority of these wells were concentrated in the
Company's Northern Plains region where 121 primary heavy crude oil
wells, 10 Pelican Lake heavy crude oil wells, and 27 bitumen (thermal
oil) wells were drilled. Another 5 wells targeting light crude oil
were drilled outside the Northern Plains region.  
Overall Primrose thermal production for the second quarter of 2013
averaged approximately 90,000 bbl/d compared with approximately
94,000 bbl/d for the second quarter of 2012 and approximately 109,000
bbl/d for the first quarter of 2013. 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 late 2013.  
In the second quarter of 2013, the Company discovered bitumen
emulsion at surface in areas of the Primrose field. The Company's
view is that the cause of the occurrence is mechanical in nature and
is working collaboratively with the regulators in the investigation
and remediation plans. To minimize the risk of any future occurrences
while the investigation is being conducted, adjustments were
immediately made to the current steaming strategy and monitoring
programs. The Company does not currently expect a change in thermal
in situ 2013 annual production guidance.  
The next planned phase of the Company's in situ Oil Sands assets
expansion is the Kirby South Project. As at June 30, 2013, the
overall project was 98% complete, drilling was complete on all seven
pads, and first steam is targeted for the third quarter of 2013. 
Development of the tertiary recovery conversion projects at Pelican
Lake continued and 10 horizontal wells were drilled during the second
quarter of 2013. Pelican Lake production averaged approximately
42,000 bbl/d for the second quarter of 2013 compared with 37,000
bbl/d for the second quarter of 2012 and 38,000 bbl/d for the first
quarter of 2013. The new 20,000 bbl/d battery was completed in
mid-May, alleviating the previous facility constraints at Pelican
Lake and Woodenhouse. Field production is currently being optimized
at both Woodenhouse and Pelican Lake. 
For the third quarter of 2013, the Company's overall planned drilling
activity in North America is expected to be 297 net crude oil wells,
47 net bitumen wells and 9 net natural gas wells, excluding
stratigraphic and service wells. 
Oil Sands Mining and Upgrading  
Phase 2/3 expansion activity in the second quarter of 2013 was
focused on field construction of the gas recovery unit, sulphur
recovery unit, butane treatment unit, coker expansion, tank farms,
tailings, hydrotransport and extraction trains 3 and 4, along with
engineering related to the froth treatment plants, hydrogen unit,
hydrotreater 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 and
the FPSO is currently undergoing repairs and is targeted to be back
in the field in the first half of 2014. The associated repair costs,
net of insurance recoveries, are not expected to be significant.  
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 received approval for the
Brownfield Allowance for the Tiffany field in January 2013 and as a
result, has commenced drilling additional production wells. During
the second quarter of 2013, the Company drilled one injector well and
one additional production well which came on at Tiffany, with
production of approximately 1,500 bbl/d, exceeding original
forecasted volumes. In May 2013, the Company received approval for
the Ninian field Brownfield Allowance and will commence drilling the
second platform in the third quarter of 2013.  
During the second quarter of 2013, the Company also completed its
consolidation of a working interest in a satellite field at the
Ninian hub.  
The Company currently plans to decommission the Murchison platform in
the North Sea commencing in 2014 and estimates the decommissioning
efforts will continue for approximately 5 years. 
Offshore Africa  
During the fourth quarter of 2011, the Company sanctioned an 8 well
drilling program at the Espoir field in Cote d'Ivoire. Due to ongoing
operational and safety issues with the drilling contractor, the
drilling rig currently on site is being de-mobilized and the Company
is assessing its drilling options at Espoir.  
The midwater arch at the Olowi field in Gabon was stabilized and
production was reinstated in late March 2013. The final repairs and
assessment have been made and issues relating to the long-term
operability of the midwater arch have been resolved. 
LIQUIDITY AND CAPITAL RESOURCES 


 
                        -------------                                       
($ millions, except           Jun 30       Mar 31       Dec 31       Jun 30 
 ratios)                        2013         2013         2012         2012 
----------------------------------------------------------------------------
Working capital deficit                                                     
 (1)                     $       948  $     1,178  $     1,264  $      (732)
Long-term debt (2) (3)   $    10,033  $     9,322  $     8,736  $     8,522 
                                                                            
Share capital            $     3,736  $     3,742  $     3,709  $     3,670 
Retained earnings             20,748       20,564       20,516       20,193 
Accumulated other                                                           
 comprehensive income             67           68           58           59 
----------------------------------------------------------------------------
Shareholders' equity     $    24,551  $    24,374  $    24,283  $    23,922 
                                                                            
Debt to book                                                                
 capitalization (3) (4)           29%          28%          26%          26%
Debt to market                                                              
 capitalization (3) (5)           24%          21%          22%          22%
After-tax return on                                                         
 average common                                                             
 shareholders' equity                                                       
 (6)                               6%           7%           8%          12%
After-tax return on                                                         
 average capital                                                            
 employed (3) (7)                  5%           6%           7%          10%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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' e
quity 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 June 30, 2013, 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, 2012 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.  
The Company established a US commercial paper program in the first
quarter of 2013. Borrowings of up to a maximum US$1,500 million are
authorized. The Company reserves capacity under its bank credit
facilities for amounts outstanding under this program.  
At June 30, 2013, the Company had $2,384 million of available credit
under its bank credit facilities, net of commercial paper issuances
of $263 million.  
During the first quarter of 2013, the Company repaid $400 million of
4.50% medium-term notes and US$400 million of 5.15% unsecured notes.
The Company retired this indebtedness utilizing cash flow from
operations generated in excess of capital expenditures and available
bank credit facilities, while maintaining the ongoing dividend
program.  
During the second quarter of 2013, the $3,000 million revolving
syndicated credit facility was extended to June 2017. Additionally,
the Company issued $500 million of 2.89% medium-term notes due August
2020. Proceeds from the securities issued were used to repay bank
indebtedness and for general corporate purposes. After issuing these
securities, the Company has $2,000 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.  
Long-term debt was $10,033 million at June 30, 2013, resulting in a
debt to book capitalization ratio of 29% (March 31, 2013 - 28%;
December 31, 2012 - 26%; June 30, 2012 - 26%). This ratio is within
the 25% 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 2013 and 2014 at
prices that protect investment returns to ensure ongoing balance
sheet strength and the completion of its capital expenditure
programs. Further details related to the Company's long-term debt at
June 30, 2013 are discussed in note 6 to the Company's unaudited
interim consolidated financial statements.  
The Company's commodity hedge policy reduces the risk of volatility
in commodity prices and supports the Company's cash flow for its
capital expenditure 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 August 7, 2013, approximately 58% of
currently forecasted 2013 crude oil volumes were hedged using price
collars and physical crude oil sales contracts with fixed WCS
differentials. Further details related to the Company's commodity
related derivative financial instruments outstanding at June 30, 2013
are discussed in note 13 to the Company's unaudited interim
consolidated financial statements.  
Share Capital  
As at June 30, 2013, there were 1,086,969,000 common shares
outstanding (June 30, 2012 - 1,096,497,000 common shares) and
67,463,000 stock options outstanding. As at August 6, 2013, the
Company had 1,087,477,000 common shares outstanding and 66,328,000
stock options outstanding. 
On March 6, 2013, the Company's Board of Directors approved an
increase in the annual dividend to be paid by the Company to $0.50
per common share for 2013. The increase represents an approximately
19% increase from 2012, recognizing the stability of the Company's
cash flow and providing a return to shareholders. The dividend policy
undergoes periodic review by the Board of Directors and is subject to
change.  
In April 2013, 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 2013 and ending April 2014, up to 54,635,116
common shares. The Company's Normal Course Issuer Bid announced in
2012 expired April 2013.  
For the six months ended June 30, 2013, the Company purchased
6,707,500 common shares at a weighted average price of $30.86 per
common share, for a total cost of $207 million. Retained earnings
were reduced by $184 million, representing the excess of the purchase
price of common shares over their average carrying value. Subsequent
to June 30, 2013, the Company purchased 230,000 common shares at a
weighted average price of $30.98 per common share for a total cost of
$7 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. The following table summarizes the Company's commitments
as at June 30, 2013: 


 
                   Remaining                                                
($ millions)            2013     2014     2015     2016     2017  Thereafter
----------------------------------------------------------------------------
Product                                                                     
 transportation                                                             
 and pipeline     $      117 $    225 $    209 $    138 $    118 $       795
Offshore                                                                    
 equipment                                                                  
 operating leases $       65 $    128 $    110 $     80 $     60 $        71
Long-term debt                                                              
 (1)              $      263 $    894 $    400 $    830 $  2,551 $     5,153
Interest and                                                                
 other financing                                                            
 costs (2)        $      226 $    452 $    417 $    400 $    328 $     4,026
Office leases     $       16 $     34 $     32 $     33 $     35 $       262
Other             $       97 $     99 $     86 $     15 $      2 $         6
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or
transaction costs. 
(2) Interest and other financing cost amounts represent the scheduled
fixed rate and variable rate cash interest payments related to
long-term debt. Interest on variable rate long-term debt was
estimated based upon prevailing interest rates and foreign exchange
rates as at June 30, 2013. 
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.  
CHANGES IN ACCOUNTING POLICIES  
For the impact of new accounting standards, refer to the unaudited
interim consolidated financial statements for the six months ended
June 30, 2013. 
CRITICAL ACCOUNTING ESTIMATES  
The preparation of financial statements requires the Company to make
estimates, assumptions and judgments 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 critical accounting estimates is contained in
the MD&A and the audited consolidated financial statements for the
year ended December 31, 2012. 
CONSOLIDATED BALANCE SHEETS 


 
                                                    ------------            
As at                                                     Jun 30      Dec 31
(millions of Canadian dollars, unaudited)       Note        2013        2012
----------------------------------------------------------------------------
ASSETS                                                                      
Current assets                                                              
 Cash and cash equivalents                           $        17 $        37
 Accounts receivable                                       1,614       1,197
 Inventory                                                   656         554
 Prepaids and other                                          213         126
 Current portion of other long-term assets         5          35           -
----------------------------------------------------------------------------
                                                           2,535       1,914
Exploration and evaluation assets                  3       2,655       2,611
Property, plant and equipment                      4      45,251      44,028
Other long-term assets                             5         369         427
----------------------------------------------------------------------------
                                                     $    50,810 $    48,980
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
LIABILITIES                                                                 
Current liabilities                                                         
 Accounts payable                                    $       667 $       465
 Accrued liabilities                                       2,451       2,273
 Current income tax liabilities                              212         285
 Current portion of long-term debt                 6         263         798
 Current portion of other long-term                                         
  liabilities                                      7         153         155
----------------------------------------------------------------------------
                                                           3,746       3,976
Long-term debt                                     6       9,770       7,938
Other long-term liabilities                        7       4,513       4,609
Deferred income tax liabilities                            8,230       8,174
----------------------------------------------------------------------------
                                                          26,259      24,697
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY                                                        
Share capital                                      9       3,736       3,709
Retained earnings                                         20,748      20,516
Accumulated other comprehensive income            10          67          58
----------------------------------------------------------------------------
                                                          24,551      24,283
----------------------------------------------------------------------------
                                                     $    50,810 $    48,980
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Commitments and contingencies (note 14).  
Approved by the Board of Directors on August 7, 2013 
CONSOLIDATED STATEMENTS OF EARNINGS 


 
                               Three Months Ended       Six Months Ended    
                            ------------            ------------            
(millions of                                                                
 Canadian dollars,                                                          
 except per common                                                          
 share amounts,                  Jun 30      Jun 30      Jun 30      Jun 30 
 unaudited)             Note       2013        2012        2013        2012 
----------------------------------------------------------------------------
Product sales                $    4,230  $    4,187  $    8,331  $    8,158 
Less: royalties                    (446)       (361)       (792)       (805)
----------------------------------------------------------------------------
Revenue                           3,784       3,826       7,539       7,353 
----------------------------------------------------------------------------
Expenses                                                                    
Production                        1,096       1,068       2,231       2,106 
Transportation and                                                          
 blending                           738         691       1,593       1,408 
Depletion,                                                                  
 depreciation and                                                           
 amortization              4      1,172       1,084       2,314       2,059 
Administration                       81          77         160         142 
Share-based                                                                 
 compensation              7        (49)       (115)         22        (222)
Asset retirement                                                            
 obligation                                                                 
 accretion                 7         42          38          84          75 
Interest and other         
                                                 
 financing costs                     72          93         149         189 
Risk management                                                             
 activities               13       (133)       (205)       (154)        (51)
Foreign exchange                                                            
 loss                               113          62         159           8 
Equity loss from                                                            
 jointly controlled                                                         
 entity                    5          -           5           2           5 
----------------------------------------------------------------------------
                                  3,132       2,798       6,560       5,719 
----------------------------------------------------------------------------
Earnings before                                                             
 taxes                              652       1,028         979       1,634 
Current income tax                                                          
 expense                   8        145         213         286         444 
Deferred income tax                                                         
 expense                   8         31          62           4          10 
----------------------------------------------------------------------------
Net earnings                 $      476  $      753  $      689  $    1,180 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per                                                            
 common share                                                               
 Basic                    12 $     0.44  $     0.68  $     0.63  $     1.07 
 Diluted                  12 $     0.44  $     0.68  $     0.63  $     1.07 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 


 
                            Three Months Ended         Six Months Ended     
                        ------------------------- ------------------------- 
(millions of Canadian         Jun 30       Jun 30       Jun 30       Jun 30 
 dollars, unaudited)            2013         2012         2013         2012 
----------------------------------------------------------------------------
Net earnings             $       476  $       753  $       689  $     1,180 
----------------------------------------------------------------------------
Items that may be                                                           
 reclassified                                                               
 subsequently to net                                                        
 earnings                                                                   
 Net change in                                                              
  derivative financial                                                      
  instruments designated                                                    
  as cash flow hedges                                                       
  Unrealized income                                                         
   during the period,                                                       
   net of taxes of                                                          
  $1 million (2012 - $1                                                     
   million) - three                                                         
   months ended;                                                            
  $3 million (2012 - $5                                                     
   million) - six months                                                    
   ended                           6           10           22           34 
  Reclassification to                                                       
   net earnings, net of                                                     
   taxes of                                                                 
  $nil (2012 - $nil) -                                                      
   three months ended;                                                      
  $nil (2012 - $nil) -                                                      
   six months ended               (1)          (2)          (2)          (1)
----------------------------------------------------------------------------
                                   5            8           20           33 
 Foreign currency                                                           
  translation adjustment                                                    
  Translation of net                                                        
   investment                     (6)          (8)         (11)           - 
----------------------------------------------------------------------------
Other comprehensive                                                         
 (loss) income, net of                                                      
 taxes                            (1)           -            9           33 
----------------------------------------------------------------------------
Comprehensive income     $       475  $       753  $       698  $     1,213 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY 


 
                                                       Six Months Ended     
                                                  -------------             
(millions of Canadian dollars,                          Jun 30       Jun 30 
 unaudited)                                   Note        2013         2012 
----------------------------------------------------------------------------
Share capital                                    9                          
Balance - beginning of period                      $     3,709  $     3,507 
Issued upon exercise of stock options                       39          140 
Previously recognized liability on stock                                    
 options exercised for common shares                        11           39 
Purchase of common shares under Normal                                      
 Course Issuer Bid                                         (23)         (16)
----------------------------------------------------------------------------
Balance - end of period                                  3,736        3,670 
----------------------------------------------------------------------------
Retained earnings                                                           
Balance - beginning of period                           20,516       19,365 
Net earnings                                               689        1,180 
Purchase of common shares under Normal                                      
 Course Issuer Bid                               9        (184)        (121)
Dividends on common shares                       9        (273)        (231)
----------------------------------------------------------------------------
Balance - end of period                                 20,748       20,193 
----------------------------------------------------------------------------
Accumulated other comprehensive income          10                          
Balance - beginning of period                               58           26 
Other comprehensive income, net of taxes                     9           33 
----------------------------------------------------------------------------
Balance - end of period                                     67           59 
----------------------------------------------------------------------------
Shareholders' equity                               $    24
,551  $    23,922 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
CONSOLIDATED STATEMENTS OF CASH FLOWS 


 
                          Three Months Ended            Six Months Ended    
                            ------------            ------------            
(millions of                                                                
 Canadian dollars,               Jun 30      Jun 30      Jun 30      Jun 30 
 unaudited)             Note       2013        2012        2013        2012 
----------------------------------------------------------------------------
Operating                                                                   
 activities                                                                 
Net earnings                 $      476  $      753  $      689  $    1,180 
Non-cash items                                                              
 Depletion,                                                                 
  depreciation and                                                          
  amortization                    1,172       1,084       2,314       2,059 
 Share-based                                                                
  compensation                      (49)       (115)         22        (222)
 Asset retirement                                                           
  obligation                                                                
  accretion                          42          38          84          75 
 Unrealized risk                                                            
  management gain                  (114)       (144)        (52)        (84)
 Unrealized foreign                                                         
  exchange loss                     112          71         190          11 
 Realized foreign                                                           
  exchange gain on                                                          
  repayment of US                                                           
  dollar debt                                                               
  securities                          -           -         (12)          - 
 Equity loss from                                                           
  jointly                                                                   
  controlled entity                   -           5           2           5 
 Deferred income                                                            
  tax expense                        31          62           4          10 
Other                                18          17          56          40 
Abandonment                                                                 
 expenditures                       (37)        (39)        (92)       (115)
Net change in non-                                                          
 cash working                                                               
 capital                             87        (117)       (302)        113 
----------------------------------------------------------------------------
                                  1,738       1,615       2,903       3,072 
----------------------------------------------------------------------------
Financing                                                                   
 activities                                                                 
(Repayment) issue                                                           
 of bank credit                                                             
 facilities and                                                             
 commercial paper,                                                          
 net                                 (5)       (352)      1,251        (559)
Issue of medium-                                                            
 term notes, net           6        498         498          98         498 
Repayment of US                                                             
 dollar debt                                                                
 securities                           -           -        (398)          - 
Issue of common                                                             
 shares on exercise                                                         
 of stock options                     9           9          39         140 
Purchase of common                                                          
 shares under                                                               
 Normal Course                                                              
 Issuer Bid                        (175)       (114)       (207)       (137)
Dividends on common                                                         
 shares                            (136)       (115)       (251)       (214)
Net change in non-                                                          
 cash working                                                               
 capital                             (5)        (13)        (11)        (16)
----------------------------------------------------------------------------
                                    186         (87)        521        (288)
----------------------------------------------------------------------------
Investing                                                                   
 activities                                                                 
Expenditures on                                                             
 exploration and                                                            
 evaluation assets                                                          
 and property,                                                              
 plant and                                                                  
 equipment                       (1,755)     (1,285)     (3,436)     (2,805)
Investment in other                                                         
 long-term assets                     -           2           -           2 
Net change in non-                                                          
 cash working                                                               
 capital                           (170)       (248)         (8)         (5)
----------------------------------------------------------------------------
                                 (1,925)     (1,531)     (3,444)     (2,808)
----------------------------------------------------------------------------
Decrease in cash                                                            
 and cash                                                                   
 equivalents                         (1)         (3)        (20)        (24)
Cash and cash                                                               
 equivalents -                                                              
 beginning of                                                               
 period                              18          13          37          34 
----------------------------------------------------------------------------
Cash and cash                                                               
 equivalents - end                                                          
 of period                   $       17  $       10  $       17  $       10 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid                $       97  $       93  $      239  $      226 
Income taxes paid            $       71  $      170  $      284  $      435 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
(tabular amounts in milli
ons 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, an electricity
co-generation system and an investment in the North West Redwater
Partnership ("Redwater").  
The Company was incorporated in Alberta, Canada. The address of its
registered office is 2500, 855-2 Street S.W., Calgary, Alberta,
Canada.  
These interim consolidated financial statements and the related notes
have been prepared in accordance with International Financial
Reporting Standards ("IFRS") as issued by the International
Accounting Standards Board ("IASB"), 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, 2012, except as
discussed in note 2. 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, 2012. 
2. CHANGES IN ACCOUNTING POLICIES  
Effective January 1, 2013, the Company adopted the following new
accounting standards issued by the IASB: 
(a) - IFRS 10 "Consolidated Financial Statements" replaced IAS 27
"Consolidated and Separate Financial Statements" (IAS 27 still
contains guidance for Separate Financial Statements) and Standing
Interpretations Committee ("SIC") 12 "Consolidation - Special Purpose
Entities". IFRS 10 establishes the principles for the presentation
and preparation of consolidated financial statements. The standard
defines the principle of control and establishes control as the basis
for consolidation, as well as providing guidance on applying the
control principle to determine whether an investor controls an
investee.  
- IFRS 11 "Joint Arrangements" replaced IAS 31 "Interests in Joint
Ventures" and SIC 13 "Jointly Controlled Entities - Non-Monetary
Contributions by Venturers". The new standard defines two types of
joint arrangements, joint operations and joint ventures. In a joint
operation, the parties with joint control have rights to the assets
and obligations for the liabilities of the joint arrangement and are
required to recognize their proportionate interest in the assets,
liabilities, revenues and expenses of the joint arrangement. In a
joint venture, the parties have an interest in the net assets of the
arrangement and are required to apply the equity method of
accounting.  
- IFRS 12 "Disclosure of Interests in Other Entities". The standard
includes disclosure requirements for investments in subsidiaries,
joint arrangements, associates and unconsolidated structured
entities.  
- The Company adopted these standards retrospectively.  
(b) IFRS 13 "Fair Value Measurement" provides guidance on applying
fair value where its use is already required or permitted by other
standards within IFRS. The standard includes a definition of fair
value and a single source of fair value measurement and disclosure
requirements for use across all IFRSs that require or permit the use
of fair value. IFRS 13 was adopted prospectively. As a result of
adoption of this standard, the Company has included its own credit
risk in measuring the carrying amount of a risk management liability. 
(c) Amendments to IAS 1 "Presentation of Financial Statements"
require items of other comprehensive income that may be reclassified
to net earnings to be grouped together. The amendments also require
that items in other comprehensive income and net earnings be
presented as either a single statement or two consecutive statements.
Adoption of this amended standard impacted presentation only.  
(d) IFRS Interpretation Committee ("IFRIC") 20 "Stripping Costs in
the Production Phase of a Surface Mine" requires overburden removal
costs during the production phase to be capitalized and depreciated
if the Company can demonstrate that probable future economic benefits
will be realized, the costs can be reliably measured, and the Company
can identify the component of the ore body for which access has been
improved.  
Adoption of these standards did not have a material impact on the
Company's consolidated financial statements. 
3. EXPLORATION AND EVALUATION ASSETS  


 
                                                    Oil Sands               
                                                    Mining and              
                    Exploration and Production       Upgrading     Total    
----------------------------------------------------------------------------
                     North                 Offshore                         
                   America    North Sea      Africa                         
----------------------------------------------------------------------------
Cost                                                                        
At December                                                                 
 31, 2012      $     2,564  $         - $        47 $         - $     2,611 
Additions               80            -           7           -          87 
Transfers to                                                                
 property,                                                                  
 plant and                                                                  
 equipment             (45)           -           -           -         (45)
Foreign                                                                     
 exchange                                                                   
 adjustments             -            -           2           -           2 
----------------------------------------------------------------------------
At June 30,                                                                 
 2013          $     2,599  $         - $        56 $         - $     2,655 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
4. PROPERTY, PLANT AND EQUIPMENT  


 
                                                                 Oil Sands  
                                                                Mining and  
                                Exploration and Production       Upgrading  
----------------------------------------------------------------------------
                                 North                 Offshore             
                               America    North Sea      Africa             
----------------------------------------------------------------------------
Cost                                                                        
At December 31, 2012       $    50,324  $     4,574 $     3,045 $    16,963 
Additions                        1,846          147          59       1,276 
Transfers from E&E assets           45            -           -           - 
Disposals/derecognitions          (100)           -           -        (317)
Foreign exchange                                                            
 adjustments and other               -          267         176           - 
----------------------------------------------------------------------------
At June 30, 2013           $    52,115  $     4,988 $     3,280 $    17,922 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and depreciation                                      
At December 31, 2012       $    24,991  $     2,709 $     2,273 $     1,202 
Expense                          1,718          224          80         278 
Disposals/derecognitions          (100)           -           -        (317)
Foreign exchange                                                            
 adjustments and other               -          173         134           - 
----------------------------------------------------------------------------
At June 30, 2013           $    26,609  $     3,106 $     2,487 $     1,163 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value- at June                                                     
 30, 2013                  $    25,506  $     1,882 $       793 $    16,759 
- at December 31, 2012     $    25,333  $     1,865 $       772 $    15,761 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                              Midstream      Head Office         Total      
----------------------------------------------------------------------------
                                                                            
----------------------------------------------------------------------------
Cost                                                                        
At December 31, 2012        $          312  $           270  $       75,488 
Additions                                9               19           3,356 
Transfers from E&E assets                -                -              45 
Disposals/derecognitions                 -                -            (417)
Foreign exchange                                                            
 adjustments and other                   -                -             443 
----------------------------------------------------------------------------
At June 30, 2013            $          321  $           289  $       78,915 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and                                                   
 depreciation                                                               
At December 31, 2012        $          103  $           182  $       31,460 
Expense                                  4               10           2,314 
Disposals/derecognitions                 -                -            (417)
Foreign exchange                                                            
 adjustments and other                   -                -             307 
----------------------------------------------------------------------------
At June 30, 2013            $          107  $           192  $       33,664 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value- at June                                                     
 30, 2013                   $          214  $            97  $       45,251 
- at December 31, 2012      $          209  $            88  $       44,028 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
                                                                            
Horizon project costs not subject to depletion                              
----------------------------------------------------------------------------
At June 30, 2013                                                 $     3,022
At December 31, 2012                                             $     2,066
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
In addition, the Company has capitalized costs to date of $1,320
million (December 31, 2012 - $1,021 million) related to the
development of the Kirby Thermal Oil Sands Project which are not
subject to depletion.  
The Company acquired a number of producing crude oil and natural gas
assets in the North American and North Sea Exploration and Production
segments for total cash consideration of $11 million during the six
months ended June 30, 2013 (year ended December 31, 2012 - $144
million), net of associated asset retirement obligations of $10
million (year ended December 31, 2012 - $12 million). Interests in
jointly controlled assets were acquired with full tax basis. No
working capital or debt obligations were assumed.  
Subsequent to June 30, 2013, the Company acquired all of the issued
and outstanding common shares of Barrick Energy Inc. ("BEI") for
total cash consideration of approximately $173 million. BEI's assets
include working interests in producing crude oil and natural gas
properties and undeveloped land. Due to the timing of the close of
the acquisition, the purchase accounting and related disclosures have
not been finalized. 
The Company capitalizes construction period interest for qualifying
assets based on costs incurred and the Company's cost of borrowing.
Interest capitalization to a qualifying asset ceases once
construction is substantially complete. For the six months ended June
30, 2013, pre-tax interest of $76 million (June 30, 2012 - $39
million) was capitalized to property, plant and equipment using a
capitalization rate of 4.4% (June 30, 2012 - 4.8%). 
5. OTHER LONG-TERM ASSETS 


 
                                                    ------------            
                                                       Jun 30      Dec 31   
                                                        2013         2012   
----------------------------------------------------------------------------
Investment in North West Redwater Partnership        $       308 $       310
Risk management (note 13)                                     35           -
Other                                                         61         117
----------------------------------------------------------------------------
                                                             404         427
Less: current portion                                         35           -
----------------------------------------------------------------------------
                                                     $       369 $       427
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Other long-term assets include an investment in the 50% owned
Redwater. The investment is accounted for using the equity method.
Redwater has entered into agreements to construct and operate a
50,000 barrel per day bitumen upgrader and refinery (the "Project")
under processing agreements that target to process 12,500 barrels per
day of bitumen feedstock for the Company and 37,500 barrels per day
of bitumen feedstock for the Alberta Petroleum Marketing Commission,
an agent of the Government of Alberta, under a 30 year
fee-for-service tolling agreement. During 2012, the Project received
board sanction from Redwater and its partners.  
As at June 30, 2013, Redwater had interim borrowings of $353 million
under credit facilit
ies totaling $600 million which mature no later
than December 2017. These facilities are secured by a floating charge
on the assets of Redwater with a mandatory repayment required from
future financing proceeds. At maturity, under its processing
agreement, the Company would be obligated to pay its 25% pro rate
share of any shortfall.  
Redwater has entered into various agreements related to the
engineering and procurement of the Project. These contracts can be
cancelled by Redwater upon notice without penalty, subject to the
costs incurred up to and in respect of the cancellation. 
6. LONG-TERM DEBT 


 
                                                  -------------             
                                                     Jun 30       Dec 31    
                                                      2013         2012     
----------------------------------------------------------------------------
Canadian dollar denominated debt                                            
Bank credit facilities                             $     1,963  $       971 
Medium-term notes                                        1,400        1,300 
----------------------------------------------------------------------------
                                                         3,363        2,271 
----------------------------------------------------------------------------
US dollar denominated debt                                                  
Commercial paper (June 30, 2013 - US$250 million;                           
 December 31, 2012 - US$nil)                               263            - 
US dollar debt securities (June 30, 2013 -                                  
 US$6,150 million; December 31, 2012 - US$6,550                             
 million)                                                6,465        6,517 
Less: original issue discount on US dollar debt                             
 securities (1)                                            (19)         (20)
----------------------------------------------------------------------------
                                                         6,709        6,497 
Fair value impact of interest rate swaps on US                              
 dollar debt securities (2)                                 14           19 
----------------------------------------------------------------------------
                                                         6,723        6,516 
----------------------------------------------------------------------------
Long-term debt before transaction costs                 10,086        8,787 
Less: transaction costs (1) (3)                            (53)         (51)
----------------------------------------------------------------------------
                                                        10,033        8,736 
Less: current portion of commercial paper                  263            - 
----------------------------------------------------------------------------
 current portion of other long-term debt (1)                 -          798 
                                                   $     9,770  $     7,938 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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 amount of US$350 million of 4.90% unsecured notes
due December 2014 was adjusted by $14 million (December 31, 2012 -
$19 million) to reflect the fair value impact of hedge accounting.  
(3) Transaction costs primarily represent underwriting commissions
charged as a percentage of the related debt offerings, as well as
legal, rating agency and other professional fees.  
Bank Credit Facilities and Commercial Paper  
As at June 30, 2013, 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 2017;  
- 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 2013, the $3,000 million revolving
syndicated credit facility was extended to June 2017. 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 established a US commercial paper program in the first
quarter of 2013. Borrowings of up to a maximum US$1,500 million are
authorized. The Company reserves capacity under its bank credit
facilities for amounts outstanding under this program.  
The Company's weighted average interest rate on bank credit
facilities and commercial paper outstanding as at June 30, 2013, was
2.1% (June 30, 2012 - 1.9%), and on long-term debt outstanding for
the six months ended June 30, 2013 was 4.4% (June 30, 2012 - 4.8%).  
In addition to the outstanding debt, letters of credit and financial
guarantees aggregating $560 million, including a $77 million
financial guarantee related to Horizon and $358 million of letters of
credit related to North Sea operations, were outstanding at June 30,
2013.  
Medium-Term Notes  
During the first quarter of 2013, the Company repaid $400 million of
4.50% medium-term notes.  
During the second quarter of 2013, the Company issued $500 million of
2.89% medium-term notes due August 2020. Proceeds from the securities
issued were used to repay bank indebtedness and for general corporate
purposes. After issuing these securities, the Company has $2,000
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  
During the first quarter of 2013, the Company repaid US$400 million
of 5.15% unsecured notes.  
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. 
7. OTHER LONG-TERM LIABILITIES 


 
                                                    ------------            
                                                          Jun 30      Dec 31
                                                            2013        2012
----------------------------------------------------------------------------
Asset retirement obligations                         $     4,340 $     4,266
Share-based compensation                                     169         154
Risk management (note 13)                                     80         257
Other                                                         77          87
----------------------------------------------------------------------------
                                                           4,666       4,764
Less: current portion                                        153         155
----------------------------------------------------------------------------
                                                     $     4,513 $     4,609
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 4.3%
(December 31, 2012 - 4.3%). A reconciliation of the discounted asset
retirement obligations is as follows:  


 
                                                    ------------            
                                                         Jun 30      Dec 31 
                                                           2013        2012 
----------------------------------------------------------------------------
Balance - beginning of period                        $    4,266  $    3,577 
 Liabilities incurred                                        27          51 
 Liabilities acquired                                        10          12 
 Liabilities settled                                        (92)       (204)
 Asset retirement obligation accretion                       84         151 
 Revision of estimates                                      (27)        384 
 Change in discount rate                                      -         315 
 Foreign exchange                                            72         (20)
----------------------------------------------------------------------------
Balance - end of period                              $    4,340  $    4,266 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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. 


 
                                                  -------------             
                                                        Jun 30       Dec 31 
                                                          2013         2012 
----------------------------------------------------------------------------
Balance - beginning of period                      $       154  $       432 
 Share-based compensation expense (recovery)                22         (214)
 Cash payment for stock options surrendered                 (1)          (7)
 Transferred to common shares                              (11)         (45)
 Capitalized to (recovered from) Oil Sands Mining                           
  and Upgrading                                              5          (12)
----------------------------------------------------------------------------
Balance - end of period                                    169          154 
Less: current portion                                      131          129 
----------------------------------------------------------------------------
                                                   $        38  $        25 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
8. INCOME TAXES  
The provision for income tax is as follows: 


 
                             Three Months Ended        Six Months Ended     
                         -------------            -------------             
                               Jun 30       Jun 30      Jun 30       Jun 30 
                                 2013         2012        2013         2012 
----------------------------------------------------------------------------
Current corporate income                                                    
 tax - North America      $       111  $       124 $       233  $       237 
Current corporate income                                                    
 tax - North Sea                   25           19          18           64 
Current corporate income                                                    
 tax - Offshore Africa             36           64          71          100 
Current PRT (1)                                                             
 (recovery) expense -                                                       
 North Sea                        (33)           1         (46)          32 
Other taxes                         6            5          10           11 
----------------------------------------------------------------------------
Current income tax                                                          
 expense                          145          213         286          444 
----------------------------------------------------------------------------
Deferred corporate income                                                   
 tax expense                       44           59          40           11 
Deferred PRT (1)                                                            
 (recovery) expense -                                                       
 North Sea                        (13)           3         (36)          (1)
----------------------------------------------------------------------------
Deferred income tax                                                         
 expense                           31           62           4           10 
----------------------------------------------------------------------------
Income tax expense        $       176  $       275 $       290  $       454 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Petroleum Revenue Tax. 
During the second quarter of 2013, the government of British Columbia
substantively enacted legislation to increase its provincial
corporate income tax rate effective April 1, 2013. As a result of the
income tax rate change, the Company's deferred income tax liability
was increased by $15 million. 
9. SHARE CAPITAL  
Authorized  
Preferred shares issuable in a series.  
Unlimited number of common shares without par value. 


 
                                          ----------------------------------
                                            Six Months Ended Jun 30, 2013   
                                              Number of shares              
Issued common shares                                (thousands)      Amount 
----------------------------------------------------------------------------
Balance - beginning of period                        1,092,072  $     3,709 
Issued upon exercise of stock options                    1,605           39 
Previously recognized liability on stock                                    
 options exercised for common shares                         -           11 
Purchase of common shares under Normal                                      
 Course Issuer Bid                                      (6,708)         (23)
-----------------------------
-----------------------------------------------
Balance - end of period                              1,086,969  $     3,736 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Dividend Policy  
The Company has paid regular quarterly dividends in January, April,
July, and October of each year since 2001. The dividend policy
undergoes periodic review by the Board of Directors and is subject to
change.  
On March 6, 2013, the Board of Directors set the regular quarterly
dividend at $0.125 per common share (2012 - $0.105 per common share). 
Normal Course Issuer Bid  
In April 2013, 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 2013 and ending April 2014, up to 54,635,116 common shares. The
Company's Normal Course Issuer Bid announced in 2012 expired April
2013.  
For the six months ended June 30, 2013, the Company purchased
6,707,500 common shares at a weighted average price of $30.86 per
common share, for a total cost of $207 million. Retained earnings
were reduced by $184 million, representing the excess of the purchase
price of common shares over their average carrying value. Subsequent
to June 30, 2013, the Company purchased 230,000 common shares at a
weighted average price of $30.98 per common share for a total cost of
$7 million. 
Stock Options  
The following table summarizes information relating to stock options
outstanding at June 30, 2013: 


 
                                                     -----------------------
                                                       Six Months Ended Jun 
                                                             30, 2013       
----------------------------------------------------------------------------
                                                                    Weighted
                                                          Stock      average
                                                        options     exercise
                                                     (thousands)       price
----------------------------------------------------------------------------
Outstanding - beginning of period                        73,747  $     34.13
Granted                                                   5,809  $     29.82
Surrendered for cash settlement                            (133) $     23.52
Exercised for common shares                              (1,605) $     24.86
Forfeited                                               (10,355) $     35.08
----------------------------------------------------------------------------
Outstanding - end of period                              67,463  $     33.84
----------------------------------------------------------------------------
Exercisable - end of period                              21,106  $     34.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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: 


 
                                                  -------------             
                                                        Jun 30       Jun 30 
                                                          2013         2012 
----------------------------------------------------------------------------
Derivative financial instruments designated as                              
 cash flow hedges                                  $       106  $        95 
Foreign currency translation adjustment                    (39)         (36)
----------------------------------------------------------------------------
                                                   $        67  $        59 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 25% to 45%. This range may be exceeded in
periods when a combination of capital projects, acquisitions, or
lower commodity prices occurs. The Company may be below the low end
of the targeted range when cash flow from operating activities is
greater than current investment activities. At June 30, 2013, the
ratio was within the target range at 29%.  
Readers are cautioned that the debt to book capitalization ratio is
not defined by IFRS and this financial measure may not be comparable
to similar measures presented by other companies. Further, there are
no assurances that the Company will continue to use this measure to
monitor capital or will not alter the method of calculation of this
measure in the future.  


 
                                                  -------------             
                                                        Jun 30       Dec 31 
                                                          2013         2012 
----------------------------------------------------------------------------
Long-term debt (1)                                 $    10,033  $     8,736 
Total shareholders' equity                         $    24,551  $    24,283 
Debt to book capitalization                                 29%          26%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Includes the current portion of long-term debt. 
12. NET EARNINGS PER COMMON SHARE 


 
                               Three Months Ended       Six Months Ended    
                            ------------            ------------            
                                  Jun 30      Jun 30      Jun 30      Jun 30
                                    2013        2012        2013        2012
----------------------------------------------------------------------------
Weighted average common                                                     
 shares outstanding - basic                                                 
 (thousands of shares)         1,089,302   1,099,046   1,090,858   1,099,600
Effect of dilutive stock                                                    
 options (thousands of                                                      
 shares)                           1,719       2,055       1,896       3,131
----------------------------------------------------------------------------
Weighted average common                                                     
 shares outstanding -                                                       
 diluted (thousands of                                                      
 shares)                       1,091,021   1,101,101   1,092,754   1,102,731
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings                 $       476 $       753 $       689 $     1,180
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common                                                     
 share - basic               $      0.44 $      0.68 $      0.63 $      1.07
  - diluted                  $      0.44 $      0.68 $      0.63 $      1.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
               -------------------------------------------------------------
                                       Jun 30, 2013                         
               -------------------------------------------------------------
                   Loans and      Fair                  Financial           
                 receivables     value                liabilities           
                          at   through  Derivatives            at           
Asset              amortized    profit     used for     amortized           
 (liability)            cost   or loss      hedging          cost     Total 
----------------------------------------------------------------------------
Accounts                                                                    
 receivable     $      1,614 $       - $          -  $          -  $  1,614 
Other long-term                                                             
 assets                    -        32            3             -        35 
Accounts                                                                    
 payable                   -         -            -          (667)     (667)
Accrued                                                                     
 liabilities               -         -            -        (2,451)   (2,451)
Other long-term                                                             
 liabilities               -        20         (100)          (68)     (148)
Long-term debt                                                              
 (1)                       -         -            -       (10,033)  (10,033)
----------------------------------------------------------------------------
                $      1,614 $      52 $        (97) $    (13,219) $(11,650)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                      Dec 31, 2012                          
----------------------------------------------------------------------------
                 Loans and                              Financial           
               receivables  Fair value                liabilities           
                        at     through  Derivatives            at           
Asset           amortized    profit or     used for    amortized            
 (liability)          cost        loss      hedging          cost     Total 
----------------------------------------------------------------------------
Accounts                                                                    
 receivable   $      1,197 $         - $          -  $          -  $  1,197 
Accounts                                                                    
 payable                 -           -            -          (465)     (465)
Accrued                                                                     
 liabilities             -           -            -        (2,273)   (2,273)
Other long-                                                                 
 term                                                                       
 liabilities             -           4         (261)          (79)     (336)
Long-term                                                                   
 debt (1)                -           -            -        (8,736)   (8,736)
----------------------------------------------------------------------------
              $      1,197 $         4 $       (261) $    (11,553) $(10,613)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Includes the current portion of long-term debt. 
The carrying amounts 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: 


 
                                     ---------------------------------------
                                                  Jun 30, 2013              
----------------------------------------------------------------------------
                                         Carrying                           
                                           amount                Fair value 
----------------------------------------------------------------------------
Asset (liability) (1)                                  Level 1      Level 2 
----------------------------------------------------------------------------
Other long-term assets                $        35  $         -  $        35 
Other long-term liabilities                   (80)           -          (80)
Fixed rate long-term debt (2) (3) (4)      (7,807)      (8,591)           - 
----------------------------------------------------------------------------
                                      $    (7,852) $    (8,591) $       (45)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                  Dec 31, 2012              
----------------------------------------------------------------------------
                                         Carrying                           
                                           amount                Fair value 
----------------------------------------------------------------------------
Asset (liability) (1)                                  Level 1      Level 2 
----------------------------------------------------------------------------
Other long-term liabilities           $      (257) $         -  $      (257)
Fixed rate long-term debt (2) (3) (4)      (7,765)      (9,118)           - 
----------------------------------------------------------------------------
                                      $    (8,022) $    (9,118) $      (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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 amount of US$350 million of 4.90% unsecured notes
due December 2014 was adjusted by $14 million (December 31, 2012 -
$19 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 fixed rate 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)                                 Jun 30, 2013 Dec 31, 2012 
----------------------------------------------------------------------------
Derivatives held for trading                                                
 Crude oil price collars                           $        14  $       (16)
 Foreign currency forward contracts                         38           20 
Cash flow hedges                                                            
 Foreign currency forward contracts                          2            - 
 Cross currency swaps                                      (99)        (261)
----------------------------------------------------------------------------
                                                   $       (45) $      (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Included within:                                                            
 Current portion of o
ther long-term assets                                  
  (liabilities)                                    $        35  $        (4)
 Other long-term liabilities                               (80)        (253)
----------------------------------------------------------------------------
                                                   $       (45) $      (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
For the six months ended June 30, 2013 the Company recognized a gain
of $3 million (December 31, 2012 - gain of $1 million) related to
ineffectiveness arising from cash flow hedges.  
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 the risk management asset (liability) were
recognized in the financial statements as follows: 


 
                                              ---------------               
                                                  Six Months                
                                                      Ended     Year Ended  
Asset (liability)                               Jun 30, 2013   Dec 31, 2012 
----------------------------------------------------------------------------
Balance - beginning of period                  $        (257) $        (274)
Net change in fair value of outstanding                                     
 derivative financial instruments attributable                              
 to:                                                                        
 Risk management activities                               52             42 
 Foreign exchange                                        137            (53)
 Other comprehensive income                               23             28 
----------------------------------------------------------------------------
Balance - end of period                                  (45)          (257)
Less: current portion                                     35             (4)
----------------------------------------------------------------------------
                                               $         (80) $        (253)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
                            Three Months Ended         Six Months Ended     
                        -------------             -------------             
                              Jun 30       Jun 30       Jun 30       Jun 30 
                                2013         2012         2013         2012 
----------------------------------------------------------------------------
Net realized risk                                                           
 management (gain) loss  $       (19) $       (61) $      (102) $        33 
Net unrealized risk                                                         
 management gain                (114)        (144)         (52)         (84)
----------------------------------------------------------------------------
                         $      (133) $      (205) $      (154) $       (51)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Financial Risk Factors 
a) Market risk 
Market risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in market
prices. The Company's market risk is comprised of commodity price
risk, interest rate risk, and foreign currency exchange risk. 
Commodity price risk management  
The Company periodically uses commodity derivative financial
instruments to manage its exposure to commodity price risk associated
with the sale of its future crude oil and natural gas production and
with natural gas purchases. At June 30, 2013, the Company had the
following derivative financial instruments outstanding to manage its
commodity price risk:  
Sales contracts 


 
                                                  Weighted average          
                     Remaining term    Volume                price     Index
----------------------------------------------------------------------------
Crude oil                                                                   
Price collars                          50,000                               
 (1)            Jul 2013 - Dec 2013     bbl/d US$80.00 - US$135.59     Brent
                                       50,000                               
                Jul 2013 - Dec 2013     bbl/d US$80.00 - US$132.18     Brent
                                       50,000                               
                Jan 2014 - Dec 2014     bbl/d US$75.00 - US$121.57     Brent
                                       50,000                               
                Jul 2013 - Dec 2013     bbl/d  US$80.00 - US$97.73       WTI
                                       50,000                               
                Jul 2013 - Dec 2013     bbl/d US$80.00 - US$110.34       WTI
                                       50,000                               
                Jul 2013 - Dec 2013     bbl/d US$80.00 - US$111.05       WTI
                                       50,000                               
                Jan 2014 - Dec 2014     bbl/d US$75.00 - US$105.54       WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Subsequent to June 30, 2013, the Company entered into an
additional 50,000 bbl/d of US$80.00 - US$118.26 WTI collars for the
period August to December 2013 and an additional 50,000 bbl/d of
US$80.00 - US$120.17 Brent collars for the period January to December
2014.  
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 June 30, 2013,
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,
commercial paper 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 debt,
commercial paper and working capital. The cross currency swap
contracts require the periodic exchange of payments with the exchange
at maturity of notional principal amounts on which the payments are
based. At June 30, 2013, 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         Jul 2013 - Aug 2016    US$250     1.116       6.00%      5.40%
              Jul 2013 - May 2017  US$1,100     1.170       5.70%      5.10%
              Jul 2013 - Nov 2021    US$500     1.022       3.45%      3.96%
              Jul 2013 - Mar 2038    US$550     1.170       6.25%      5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
All cross currency swap derivative financial instruments designated
as hedges at June 30, 2013, were classified as cash flow hedges.  
In addition to the cross currency swap contracts noted above, at June
30, 2013, the Company had US$2,643 million of foreign currency
forward contracts outstanding, with terms of approximately 30 days or
less, including US$250 million designated as cash flow hedges. 
b) Credit risk  
Credit risk is the risk that a party to a financial instrument will
cause a financial loss to the Company by failing to discharge an
obligation. 
Counterparty credit risk management  
The Company's accounts receivable are mainly with customers in the
crude oil and natural gas industry and are subject to normal industry
credit risks. The Company manages these risks by reviewing its
exposure to individual companies on a regular basis and where
appropriate, ensures that parental guarantees or letters of credit
are in place to minimize the impact in the event of default. At June
30, 2013, substantially all of the Company's accounts receivable were
due within normal trade terms.  
The Company is also exposed to possible losses in the event of
nonperformance by counterparties to derivative financial instruments;
however, the Company manages this credit risk by entering into
agreements with counterparties that are substantially all investment
grade financial institutions and other entities. At June 30, 2013,
the Company had net risk management assets of $29 million with
specific counterparties related to derivative financial instruments
(December 31, 2012 - $18 million). 
c) Liquidity risk 
Liquidity risk is the risk that the Company will encounter difficulty
in meeting obligations associated with financial liabilities.  
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating activities,
available credit facilities, commercial paper 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        than            
                                  1 year     2 years     5 years  Thereafter
----------------------------------------------------------------------------
Accounts payable             $       667 $         - $         - $         -
Accrued liabilities          $     2,451 $         - $         - $         -
Risk management              $         - $         9 $        53 $        18
Other long-term liabilities  $        22 $        46 $         - $         -
Long-term debt (1)           $       263 $     1,294 $     3,802 $     4,732
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Long-term debt represents principal repayments only and does not
reflect fair value adjustments, interest, original issue discounts or
transaction costs.  
14. COMMITMENTS AND CONTINGENCIES  
The Company has committed to certain payments as follows: 


 
                               Remaining                                    
                                    2013  2014  2015  2016  2017  Thereafter
----------------------------------------------------------------------------
Product transportation and                                                  
 pipeline                    $       117 $ 225 $ 209 $ 138 $ 118 $       795
Offshore equipment operating                                                
 leases                      $        65 $ 128 $ 110 $  80 $  60 $        71
Office leases                $        16 $  34 $  32 $  33 $  35 $       262
Other                        $        97 $  99 $  86 $  15 $   2 $         6
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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        
                                                                            
                               Three       Six          Three      Six
                               Months      Months       Months     Months
                               Ended       Ended        Ended      Ended
(millions of Canadian                                                       
 dollars, unaudited)           Jun 30      Jun 30      Jun 30      Jun 30   
----------------------------------------------------------------------------
                                                                            
                             2013  2012  2013  2012  2013   2012 2013  2012 
----------------------------------------------------------------------------
                                                                            
Segmented product sales     3,189 2,757 5,997 5,815   187    236  364   515 
                                                                            
Less: royalties              (384) (244) (660) (632)    -      -   (1)   (1)
----------------------------------------------------------------------------
                                                                            
Segmented revenue           2,805 2,513 5,337 5,183   187    236  363   514 
----------------------------------------------------------------------------
                                                                            
Segmented expenses                                                          
                                                                            
Production                    588   505 1,193 1,087    75    119  177   204 
                                                                            
Transportation and blending   735   683 1,590 1,398     1      3    3     6 
                                                                            
Depletion, depreciation and                                                 
 amortization                 855   811 1,726 1,609   114     75  226   159 
                                                                            
Asset retirement obligation                                                 
 accretion                     23    21    46    42     8      7   17    14 
                                                                            
Realized risk management                                                    
 activities                   (19)  (61) (102)   33     -      -    -     - 
                                                                            
Equity loss from jointly                                                    
 controlled entity              -     -     -     -     -      -    -     - 
----------------------------------------------------------------------------
                                                                            
Total segmented expenses    2,182 1,959 4,453 4,169   198    204  423   383 
----------------------------------------------------------------------------
                                                                            
Segmented earnings (loss)                                                   
 before the following         623   554   884 1,014   (11)    32  (60)  131 
----------------------------------------------------------------------------
Non-segmented expenses                                                      
                                                                            
Administration                                                              
                                                                            
Share-based compensation                                                    
                                                                            
Interest and other financing                                                
 costs                                                                      
                                                                            
Unrealized risk management                                                  
 activities                                                                 
                                                                            
Foreign exchange loss                                                       
----------------------------------------------------------------------------
                                                                            
Total non-segmented expenses                                                
----------------------------------------------------------------------------
                                                                            
Earnings before taxes                                                       
                                                                            
Current income tax expense                                                  
                                                                            
Deferred income tax expense                                                 
----------------------------------------------------------------------------
                                                                            
Net earnings                                                                
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
 
                                                     Total Exploration and  
                                Offshore Africa            Production       
                                                                            
                               Three       Six          Three      Six
                               Months      Months       Months     Months
                               Ended       Ended        Ended      Ended
(millions of Canadian                                                       
 dollars, unaudited)           Jun 30      Jun 30      Jun 30      Jun 30   
----------------------------------------------------------------------------
                                                                            
                             2013  2012  2013  2012  2013  2012  2013  2012 
----------------------------------------------------------------------------
                                                                            
Segmented product sales       206   240   414   457 3,582 3,233 6,775 6,787 
                                                                            
Less: royalties               (34)  (62)  (67)  (96) (418) (306) (728) (729)
----------------------------------------------------------------------------
                                                                            
Segmented revenue             172   178   347   361 3,164 2,927 6,047 6,058 
----------------------------------------------------------------------------
                                                                            
Segmented expenses                                                          
                                                                            
Production                     36    51    83    73   699   675 1,453 1,364 
                                                                            
Transportation and blending     1     1     1     1   737   687 1,594 1,405 
                                                                            
Depletion, depreciation and                                                 
 amortization                  40    50    80    78 1,009   936 2,032 1,846 
                                                                            
Asset retirement obligation                                                 
 accretion                      2     2     4     3    33    30    67    59 
                                                                            
Realized risk management                                                    
 activities                     -     -     -     -   (19)  (61) (102)   33 
                                                                            
Equity loss from jointly                                                    
 controlled entity              -     -     -     -     -     -     -     - 
----------------------------------------------------------------------------
                                                                            
Total segmented expenses       79   104   168   155 2,459 2,267 5,044 4,707 
----------------------------------------------------------------------------
                                                                            
Segmented earnings (loss)                                                   
 before the following          93    74   179   206   705   660 1,003 1,351 
----------------------------------------------------------------------------
Non-segmented expenses                                                      
                                                                            
Administration                                                              
                                                                            
Share-based compensation                                                    
                                                                            
Interest and other financing                                                
 costs                                                                      
                                                                            
Unrealized risk management                                                  
 activities                                                                 
                                                                            
Foreign exchange loss                                                       
----------------------------------------------------------------------------
                                                                            
Total non-segmented expenses                                                
----------------------------------------------------------------------------
                                                                            
Earnings before taxes                                                       
                                                                            
Current income tax expense                                                  
                                                                            
Deferred income tax expense                                                 
----------------------------------------------------------------------------
                                                                            
Net earnings                                                                
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 

 
                              Oil Sands Mining and                          
                                   Upgrading                Midstream       
                                                                            
                               Three       Six          Three      Six
                               Months      Months       Months     Months
                               Ended       Ended        Ended      Ended
(millions of Canadian                                                       
 dollars, unaudited)           Jun 30      Jun 30      Jun 30      Jun 30   
                            ------------------------------------------------
                                                                            
                             2013  2012  2013  2012   2013  2012  2013  2012
----------------------------------------------------------------------------
                                                                            
Segmented product sales       643   951 1,552 1,365     29    22    56    43
                                                                            
Less: royalties               (28)  (55)  (64)  (76)     -     -     -     -
----------------------------------------------------------------------------
                                                                            
Segmented revenue             615   896 1,488 1,289     29    22    56    43
----------------------------------------------------------------------------
                                                                            
Segmented expenses                                                          
                                                                            
Production                    394   388   771   734      9     7    17    14
                                                                            
Transportation and blending    18    18    33    30      -     -     -     -
                                                                            
Depletion, depreciation and                                                 
 amortization                 161   146   278   209      2     2     4     4
                                                                            
Asset retirement obligation                                                 
 accretion                      9     8    17    16      -     -     -     -
                                                                            
Realized risk management                                                    
 activities                     -     -     -     -      -     -     -     -
                                                                            
Equity loss from jointly                                                    
 controlled entity              -     -     -     -      -     5     2     5
----------------------------------------------------------------------------
                                                                            
Total segmented expenses      582   560 1,099   989     11    14    23    23
----------------------------------------------------------------------------
                                                                            
Segmented earnings (loss)                                                   
 before the following          33   336   389   300     18     8    33    20
----------------------------------------------------------------------------
                                                                            
Non-segmented expenses                                                      
                                                                            
Administration                                                              
                                                                            
Share-based compensation                                                    
                                                                            
Interest and other financing                                                
 costs                                                                      
                                                                            
Unrealized risk management                                                  
 activities                                                                 
                                                                            
Foreign exchange loss                                                       
----------------------------------------------------------------------------
                                                                            
Total non-segmented expenses                                                
----------------------------------------------------------------------------
                                                                            
Earnings before taxes                                                       
                                                                            
Current income tax expense                                                  
                                                                            
Deferred income tax expense                                                 
----------------------------------------------------------------------------
                                                                            
Net earnings                                                                
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                 Inter-segment                              
                             elimination and other           Total          
                                                                            
                               Three       Six          Three      Six
                               Months      Months       Months     Months
                               Ended       Ended        Ended      Ended
(millions of Canadian                                                       
 dollars, unaudited)           Jun 30      Jun 30      Jun 30      Jun 30   
                            ------------------------------------------------
                                                                            
                             2013  2012  2013  2012  2013  2012  2013  2012 
----------------------------------------------------------------------------
                                                                            
Segmented product sales       (24)  (19)  (52)  (37)4,230 4,187 8,331 8,158 
                                                                            
Less: royalties                 -     -     -     -  (446) (361) (792) (805)
----------------------------------------------------------------------------
                                                                            
Segmented revenue             (24)  (19)  (52)  (37)3,784 3,826 7,539 7,353 
----------------------------------------------------------------------------
                                                                            
Segmented expenses                                                          
                                                                            
Production                     (6)   (2)  (10)   (6)1,096 1,068 2,231 2,106 
                                                                            
Transportation and blending   (17)  (14)  (34)  (27)  738   691 1,593 1,408 
                                                                            
Depletion, depreciation and                                                 
 amortization                   -     -     -     - 1,172 1,084 2,314 2,059 
                                                                            
Asset retirement obligation                                                 
 accretion                      -     -     -     -    42    38    84    75 
                                                                            
Realized risk management                                                    
 activities                     -     -     -     -   (19)  (61) (102)   33 
                                                                            
Equity loss from jointly                                                    
 controlled entity              -     -     -     -     -     5     2     5 
----------------------------------------------------------------------------
                                                                            
Total segmented expenses      (23)  (16)  (44)  (33)3,029 2,825 6,122 5,686 
----------------------------------------------------------------------------
                                                                            
Segmented earnings (loss)                                                   
 before the following          (1)   (3)   (8)   (4)  755 1,001 1,417 1,667 
----------------------------------------------------------------------------
                                                                            
Non-segmented expenses                                                      
                                                                            
Administration                                         81    77   160   142 
                                                                            
Share-based compensation                              (49) (115)   22  (222)
                                                                            
Interest and other financing                                                
 costs                                                 72    93   149   189 
                                                                            
Unrealized risk management                                                  
 activities                                          (114) (144)  (52)  (84)
                                                                            
Foreign exchange loss                                 113    62   159     8 
----------------------------------------------------------------------------
                                                                            
Total non-segmented expenses                          103   (27)  438    33 
----------------------------------------------------------------------------
                                                                            
Earnings before taxes                                 652 1,028   979 1,634 
                                                                            
Current income tax expense                            145   213   286   444 
                                                                            
Deferred income tax expense                            31    62     4    10 
----------------------------------------------------------------------------
                                                                            
Net earnings                                          476   753   689 1,180 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Capital Expenditures (1)                                                    
                                                                            
                                               Six Months Ended             
                               ---------------------------------------------
                                                 Jun 30, 2013               
----------------------------------------------------------------------------
                                                    Non cash                
                                                    and fair                
                                           Net         value     Capitalized
                                  expenditures     changes(2)          costs
----------------------------------------------------------------------------
                                                                            
Exploration and evaluation                                                  
 assets                                                                     
Exploration and Production                                                  
  North America                  $          80  $        (45)  $          35
  North Sea                                  -             -               -
  Offshore Africa                            7             -               7
----------------------------------------------------------------------------
                                 $          87  $        (45)  $          42
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Property, plant and equipment                                               
Exploration and Production                                                  
  North America                  $       1,839  $        (48)  $       1,791
  North Sea                                147             -             147
  Offshore Africa                           59             -              59
----------------------------------------------------------------------------
                                         2,045           (48)          1,997
Oil Sands Mining and Upgrading                                              
 (3)                                     1,276          (317)            959
Midstream                                    9             -               9
Head office                                 19             -              19
----------------------------------------------------------------------------
                                 $       3,349  $       (365)  $       2,984
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                              Six Months Ended              
                               ---------------------------------------------
                                                 Jun 30, 2012               
----------------------------------------------------------------------------
                                                    Non cash                
                                                    and fair                
                                           Net         value     Capitalized
                                  expenditures    changes(2)           costs
----------------------------------------------------------------------------
                                                                            
Exploration and evaluation                                                  
 assets                                                                     
Exploration and Production                                                  
  North America                  $         239  $        (76)  $         163
  North Sea                                  -             -               -
  Offshore Africa                            1             -               1
----------------------------------------------------------------------------
                                 $         240  $        (76)  $         164
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Property, plant and equipment                                               
Exploration and Production                                                  
  North America                  $       1,772  $         59   $       1,831
  North Sea                                120           (36)             84
  Offshore Africa                           14            (6)              8
----------------------------------------------------------------------------
                                         1,906            17           1,923
Oil Sands Mining and Upgrading                                              
 (3)                                       639            35             674
Midstream                                    5             -               5
Head office                                 15             -              15
----------------------------------------------------------------------------
                                 $       2,565  $         52   $       2,617
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) This table provides a reconciliation of capitalized costs
including derecognitions and does not include the impact of foreign
exchange adjustments. 
(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. 
Segmented Assets  


 
                                                         Total Assets       
                                                --------------              
                                                        Jun 30       Dec 31 
                                                          2013          2012
----------------------------------------------------------------------------
Exploration and Production                                                  
  North America                                  $      29,515 $      29,012
  North Sea                                              2,094         1,993
  Offshore Africa                                        1,016           924
  Other                                                     29            36
Oil Sands Mining and Upgrading                          17,408        16,291
Midstream                                                  651           636
Head office                                                 97            88
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                                                 $      50,810 $      48,980
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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 June             
 30, 2013:                                                                  
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Interest coverage (times)                                                   
  Net earnings (1)                                                      5.1x
  Cash flow from operations (2)                                        15.6x
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(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, August 8, 2013. The North American
conference call number is 1-866-225-2055 and the outside North
American conference call number is 001-416-340-8410. 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, August 15, 2013. 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.
Contacts:
Steve W. Laut
President 
Douglas A. Proll
Executive Vice-President 
Corey B. Bieber
Chief Financial Officer & Senior Vice-President, Finance 
Canadian Natural Resources Limited
2500, 855 - 2nd Street S.W.
Calgary, Alberta, T2P 4J8 Canada
Phone: (403) 514-7777
(403) 514-7888 (FAX)
ir@cnrl.com
www.cnrl.com